We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, vendors or derivativeother counterparties could reducereduces our revenues increaseand increases our expenses, and otherwiseany significant level of nonpayment and nonperformance could have a negative impact on our ability to conduct our business, operating results, cash flows and our ability to service our debt obligations and make distributions to our unitholders.
Our facilities operate under a number of federal, state and local permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. These limits and standards require a significant amount of monitoring, recordkeeping and reporting in order to demonstrate compliance with the underlying permit, license or approval. Noncompliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. In addition, public protest, political activism and responsive government intervention have recently made it more difficult for some energy companies to acquire the permits required to complete planned infrastructure projects. A decision by a government agency to deny or delay issuing a new or renewed permit, license or approval, or to revoke or substantially modify an existing permit, license or approval, could have a material adverse effect on our ability to continue or expand our operations and on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.
require costly future remediation. If a significant release or event occurred in the past, the liability for which was not retained by the seller, or for which indemnification by the seller is not available, it could adversely affect our financial position and results of operations. Conversely, if future releases or other liabilities arise from assets we have sold, we could incur costs related to those liabilities if the buyer possesses valid indemnification rights against us with respect to those assets.
The FERC regulates the tariff rates and terms and conditions of service for interstate oil movements on our common carrier pipelines. FERC regulations requirerequires that these rates must be just and reasonable and that the pipeline not engage in undue discrimination or undue preference with respect to any shipper. Under the ICA, theThe FERC or shippers may challenge ourrequired pipeline tariff filings, including rates and terms and conditions of service. Further, other than for rates set under market-based rate authority, if a new rate is challenged by protest and investigated by the FERC, the FERC may suspend collection of such new rate for uprequire the pipeline owner to seven months. If such new rate is found to be unjust and unreasonable, the FERC may order refunds ofrefund amounts collected in excess of amounts generated by the deemed just and reasonable rate determined by the FERC. A successful rate challenge could result in a common carrier paying refunds together with interest for the period that the rate was in effect.rate. In
addition, shippers may challenge by complaint tariff rates and terms and conditions of service even after the ratesthey take effect, and terms and conditions of service are in effect. If the FERC, in response to such a complaint or on its own initiative, initiates an investigation of rates that are already in effect, the FERC may order a carrier to change its rates prospectively. If existing rates are challenged and are determined by the FERCprospectively to be in excess of a just and reasonable level, anylevel. A complaining shipper also may obtain reparations for damages sustained during the two years prior to the date of the shipper filed a complaint.
We are able to use various FERC-authorized rate change methodologies for our interstate pipelines, including indexed rates, cost-of-service rates, market-based rates and settlementnegotiated rates. Typically, we adjust our rates annually in accordance with the FERC indexing methodology, which currently allows a pipeline to change its rates within prescribed ceiling levels that are tied to an inflation index. For the five-year period beginning July 1, 2011,It is possible that the index was measured by the year-over-year changemay result in the Bureau of Labor’s producer price index for finished goods, plus 2.65%. For the five-year period beginning July 1, 2016, the current index is measured by the year-over-year change in the Bureau of Labor’s producer price index for finished goods, plus 1.23%. Further, some of our newer projects that involved an open season include negotiated indexation rate caps.
Power costs constitute a significant portion of our operating expenses. For the year ended December 31, 2017,2022, our power costs equaled approximately $46.0$51.6 million, or 10.2%14% of our operating expenses for the year. We use mainly electric power at our pipeline pump stations and terminals, and such electric power is furnished by various utility companies that primarilycompanies. Requirements for utilities to use natural gasless carbon intensive power or to generate electricity. Accordingly, our power costs typically fluctuate with natural gas prices, and increases in natural gas prices mayadd pollution control devices also could cause our power costs to increase further. If natural gas prices increase,and our cash flows may be adversely affected, which could adversely affect our ability to make distributions to our unitholders.
Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our common unitholders of all available cash, after taking into account reserves for commitments and contingencies, including growth and other capital expenditures and operating costs, and debt service requirements. As a result, we do not accumulate equity in the form of retained earnings in a manner typical of many other forms of organizations, including most traditional public corporations.requirements and payments with respect to our preferred units. We are therefore more likely than those organizations to require issuances of additional capitaldebt and equity securities to finance our growth plans, meet unforeseen cash requirements and service our debt.debt and other obligations.
NuStar GP Holdings may currently have and, if the Merger is not consummated, may continue to have conflicts of interest and limited fiduciary responsibilities, which may permit it to favor its own interests to the detriment of our unitholders.
NuStar GP Holdings currently indirectly owns our general partner, our incentive distribution rights and, as of December 31, 2017, an aggregate 11.0% of our outstanding common units. Conflicts of interest may arise between NuStar GP Holdings and its affiliates, including our general partner, on the one hand, and us and our limited partners, on the other hand. As a result of these conflicts, the general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:
our general partner is allowed to take into account the interests of parties other than us, such as NuStar GP Holdings, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;
our general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to unitholders. As a result of purchasing our units, unitholders have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;
our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings and issuances of additional limited partner interests and reserves, each of which can affect the amount of cash that is paid to our unitholders;
our general partner determines in its sole discretion which costs incurred by NuStar GP Holdings and its affiliates are reimbursable by us;
our general partner may cause us to pay the general partner or its affiliates for any services rendered on terms that are fair and reasonable to us or enter into additional contractual arrangements with any of these entities on our behalf;
our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and
in some instances, our general partner may cause us to borrow funds in order to permit the payment of distributions.
Our partnership agreement gives the general partner broad discretion in establishing financial reserves for the proper conduct of our business, including interest payments. These reserves also affect the amount of cash available for distribution.
If the Merger is not consummated, the general partner interest, the control of our general partner and the incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.
If the merger is not consummated, our general partner may transfer its general partner interest and/or its incentive distribution rights to a third party without the consent of our unitholders. Any new owner of our general partner would be in a position to replace the officers of the general partner with its own choices and to control the decisions made by such officers. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights.
Unitholders have limited voting rights, and our partnership agreement further restricts the voting rights of certain unitholders owning 20% or more of any class of our units.
Unlike 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’ voting rights are further restricted by a provision in our partnership agreement providing that units held by certain persons that own 20% or more of any class of units then outstanding other than our general partner or its affiliates, cannot vote on any matter without the prior approval of our general partner.
We may issue an unlimited number of additional units,equity securities, including unitsequity securities that are senior to theour common units, and pari passu withwhich would dilute our 8.50% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units, 7.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units and 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (collectively, the Preferred Units); issuing new units dilutesunitholders’ existing unitholders and may increase the aggregate distribution we are required to pay each quarter under the terms of our partnership agreement.ownership interests.
Our partnership agreement allows us to issue an unlimited number of additional units and certain other equity securities on the terms and conditions established by our general partner and without the approval of other unitholders. There is no limit onunitholders as long as the total number of units and othernewly issued equity securities we may issue. If we issue additional unitsare not senior to, or other equity securities,equally ranked with, our preferred units. With the proportionate partnership interest of our existing common unitholders and the relative voting strength of eachconsent of the previously outstanding commonholders of a majority of the Series D preferred units, will decrease. Any additional issuance may increase the risk that we will be unable to maintain or increase our per common unit distribution level.
In addition, we may issue an unlimited number of units that are senior to theour common units and equally ranked with our preferred units. However, in right of distribution, liquidation and voting, including additional Preferred Units and any securities in parity withcertain circumstances, we may be required to obtain the Preferred Units without any voteapproval of the holders of the Preferred Units (except where the cumulative distributions on the Preferred Units or any parity securities are in arrears and in certain other circumstances) and without the approvala majority of each class of our common unitholders. preferred units before we could issue equity securities that are equally ranked with our preferred units.
Our issuance of additional units or other equity interests 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 amount of cash available for redemption of, or payment of the liquidation preference on, each preferred unit may decrease;
•the ratio of taxable income to distributions may increase;
•the relative voting strength of each previously outstanding unit may be diminished; and
•the market price of our common units and Preferred Unitspreferred units may decline.
Additionally, althoughHolders of our Series D preferred units generally have the same voting rights as holders of our common units and generally vote on an as-converted basis with the Preferred Units are entitled to limitedholders of our common units as a single class. Although holders of our other preferred units also have voting rights, with respectsuch rights are limited to certain matters the Preferred Units generallyand require that such holders vote separately as a separate class along with all other series of our parityequally ranked securities that we may issue upon which likebe issued and possess similar voting rights have been conferred and are exercisable.rights. As a result, the voting rights of holders of Preferred Unitsour preferred units may be significantly diluted, and the holders of such other seriesfuture securities of parity securities that we may issueequal rank may be able to control or significantly influence the outcome of any vote with respect to which the holders of the Preferred Unitsour preferred units are entitled to vote. The issuance of additional units on parity with or senior to the Preferred Units (including additional Preferred Units of the same series) would dilute the interests of the holders of the Preferred Units, and any issuance of equity securities of any class or series that ranks on parity with the Preferred Units as to the payment of distributions and amounts payable upon a liquidation event (including additional Preferred Units of the same series) or equity securities with terms expressly made senior to the Preferred Units as to the payment of distributions and amounts payable upon a liquidation event or additional indebtedness could affect our ability to pay distributions on, redeem or pay the liquidation preference on the Preferred Units. Our partnership agreement contains limited protections for the holders of the Preferred Unitsour preferred units (other than Series D preferred units) in the event of a highly leveraged or other
transaction, including a merger, or the sale, lease or conveyance of all or substantially all of our assets or business, which might adversely affect the holders of the Preferred Units.our preferred units.
Future issuances and sales of parity securities that rank equally with our preferred units, or the perception that such issuances and sales could occur, may cause prevailing market prices for the Preferred Unitsour preferred units and our common units to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us.
Furthermore, the payment of distributions on any additional units may increase the risk that we will not be able to make distributions at our prior per unit distribution levels. To the extent new units are senior to our common units, their issuance will increase the uncertainty of the payment of distributions on our common units.
If we do not pay distributions on our Preferred Unitspreferred units in any fiscal quarter,distribution period, we willwould be unable to declare or pay distributions on our common units until all unpaid Preferred Unit distributionspreferred unit distribution obligations have been paid, and our common unitholders are not entitled to receive distributions for such prior period.
The Preferred UnitsOur preferred units rank senior to our common units with respect to distribution rights and rights upon liquidation. If we do not pay the required distributions on our Preferred Units,preferred units, we will be unable to declare or pay distributions on our common units. Additionally, because distributions to our Preferred Unitholderspreferred unitholders are cumulative, we will have to pay all unpaid accumulated preferred distributions before we can declare or pay any distributions to our common unitholders. Also, because distributions to our common unitholders are not cumulative, if we do not pay distributions on our common units with respect to any quarter, our common unitholders will not be entitled to receive distributions covering any prior periods. In addition, if we do not pay the required distributions on our Series D preferred units for three consecutive distribution periods, the holders of our Series D preferred units have certain additional rights until such distributions are paid, including the right to convert the Series D preferred units into common units, the right to appoint one director to our board of directors and the right to approve certain subsequent indebtedness, acquisitions or asset sales. The preferences and privileges of the Preferred Unitsour preferred units could adversely affect the market price for our common units, or could make it more difficult for us to sell our common units in the future.
Unitholders may not have limited liability ifIf a court findswere to determine that a unitholder action constitutesconstituted control of our business, or that we have not complied with applicable statutes, whichthe unitholders may have an impact on the cash we have availablelose their legal protection from liability and be required to make distributions.repay distributions wrongfully distributed to them.
Under Delaware law, if a court were to determine that actions of a unitholder constituted participation in the “control” of our business, unitholders couldwould be held liable for our obligations to the same extent as a general partner if a court determined that actionspartner. In addition, under
Under Delaware law, the general partner generally has unlimited liability for the obligations of the partnership, such as its debts and environmental liabilities, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. In addition, Section 17-607 of the
Furthermore, under Delaware Revised Uniform Limited Partnership Act (the Delaware Act) provides that, under some circumstances, a limited partner may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.
Under certain circumstances, unitholders may have liability to repay distributions wrongfully distributed to them.
Under Section 17-607 of the Delaware Act,law, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are nonrecourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Delaware law provides that, for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to us for the repayment of the distribution amount. Likewise, upon the winding up of our partnership, in the event that (a) we do not distribute assets in the following order: (1) to creditors in satisfaction of our debts; (2) to partners and former partners in satisfaction of liabilities for distributions owed under our partnership agreement; (3) to partners for the return of their contributions; and finally (4) to the partners in the proportions in which the partners share in distributions and (b) a limited partner knows at the time that the distribution violated the Delaware Act,law, then such limited partner will be liable to repay the distribution for a period of three years from the impermissible distribution under Section 17-804 of theapplicable Delaware Act.law.
A purchaser of our common or Preferred Unitspreferred units becomes a limited partner and is liable for the obligations of the transferring limited partner to make contributions to us that are known to such purchaser of common or Preferred Unitspreferred units at the time it became a limited partner and, for unknown obligations, if the liabilities could be determined from our partnership agreement.
Unitholders may be required to sell their units to our general partner at an undesirable time or price.
If at any time less than 20% of the outstanding units of any class are held by persons other than the general partner and its affiliates, the general partner will have the right to acquire all, but not less than all, of those units at a price no less than their then-current market price. As a consequence, a unitholder may be required to sell his common units at an undesirable time or price. The general partner may assign this purchase right to any of its affiliates or to us.
The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.
We currently list our common units on the NYSE under the symbol “NS” and certain of our Preferred Unitspreferred units on the NYSE under the symbols “NSprA,” “NSprB” and “NSprC,” respectively. Although our general partner has maintained a majority of independent directors on its board and all members of its board’s audit committee, compensation committee and nominating/governance & conflicts committee are independent directors, because we are a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to have a compensation committee or a nominating committee consisting of independent directors. Additionally, any future issuance of additional common or Preferred Unitspreferred units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules that apply to a corporation. Accordingly, the NYSE does not mandate the same protections for our unitholders as are required for certain corporations that are subject to all of the NYSE corporate governance requirements. See “Director Independence” under Item 13 of this annual report on Form 10-K for additional information regarding the independence of our general partner’s directors and the committees of our general partner’s board.
TAX RISKS TO OUR UNITHOLDERSPROPERTIES
IfOur principal properties are described above under the caption “Segments and Results of Operations” above, and that information is incorporated herein by reference. We believe that we have satisfactory title to all of our properties. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, liens for current taxes and other burdens and easements, and restrictions or other encumbrances, including those related to environmental liabilities associated with historical operations, to which the underlying properties were treatedsubject at the time of acquisition by us or our predecessors, we believe that none of these burdens will materially detract from the value of these properties or from our interest in these properties or will materially interfere with their use in the operation of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this report. We perform scheduled maintenance on all of our pipelines, terminals, crude oil tanks and related equipment and make repairs and replacements when necessary or appropriate. We believe that our pipelines, terminals, crude oil tanks and related equipment have been constructed and are maintained in all material respects in accordance with applicable federal, state and local laws and the regulations and standards prescribed by the American Petroleum Institute, the DOT and accepted industry practice.
RATE REGULATION
Several of our crude oil and refined products pipelines are interstate common carrier pipelines, which are subject to regulation by the FERC under the Interstate Commerce Act (ICA) and the Energy Policy Act of 1992 (the EP Act). The ICA and its implementing regulations give the FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate liquids pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates a corporationcommon carrier pipeline charges for providing transportation services on its interstate common carrier liquids pipelines, as well as the rules and regulations governing these services, to be maintained on file with the FERC and posted publicly. The EP Act deemed certain rates in effect prior to its passage to be just and reasonable and limited the circumstances under which a complaint can be made against such “grandfathered” rates. The EP Act and its implementing regulations also allow interstate common carrier liquids pipelines to annually index their rates up to a prescribed ceiling level and generally require that such pipelines index their rates down to the prescribed ceiling level if the index is negative. In addition, the FERC retains cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach.
Our ammonia pipeline is subject to regulation by the STB pursuant to the ICA applicable to such pipelines (which differs from the ICA applicable to interstate liquids pipelines). Under that regulation, the ammonia pipeline’s rates, classifications, rules and practices related to the interstate transportation of anhydrous ammonia must be reasonable and, in providing interstate transportation, the ammonia pipeline may not subject a person, place, port or type of traffic to unreasonable discrimination.Similar to the crude and refined products pipelines, the rates for transportation services on the ammonia pipeline are required to be in a tariff which is posted publicly on our website, however, that tariff is not required to be on file with the STB. The STB does not prescribe an indexing approach similar to the EP Act but rates under the STB must be reasonable and the pipeline may not subject a person, place, port or type of traffic to unreasonable discrimination.
In addition to federal regulatory body oversight, various states, including Colorado, Kansas, Louisiana, North Dakota and Texas, maintain commissions focused on the rates and practices of common carrier pipelines offering services within their borders. Although the applicable state statutes and regulations vary, they generally require that intrastate pipelines publish tariffs setting forth all rates, rules and regulations applying to intrastate service, and generally require that pipeline rates and practices be just, reasonable and nondiscriminatory.
Shippers may challenge tariff rates, rules and regulations on our pipelines. In most instances, state commissions have not initiated investigations of the rates or practices of pipelines in the absence of shipper complaints. There are no pending challenges or complaints regarding our tariffs or tariff rates.
ENVIRONMENTAL, HEALTH, SAFETY AND SECURITY REGULATION
Our operations are subject to extensive international, federal, state and local environmental laws and regulations, in the U.S. and in Mexico, including those relating to the discharge of materials into the environment, waste management, remediation, the characteristics and composition of fuels, climate change and greenhouse gases. In 2022, our capital expenditures attributable to compliance with environmental regulations were $5.9 million, and we currently project environmental regulatory compliance spending of approximately $6.3 million in 2023.
Our operations are also subject to extensive health, safety and security laws and regulations, including those relating to worker and pipeline safety, pipeline and storage tank integrity and operations security. The principal environmental, health, safety and security risks associated with our operations relate to unauthorized emissions into the air, releases into soil, surface water or groundwater, personal injury and property damage. We have adopted policies, practices, systems and procedures designed to comply with the laws and regulations, and to help minimize and mitigate these risks, limit the liability that could result from such events, prevent material environmental or other damage, ensure the safety of our employees and the public and secure our pipelines, terminals and operations. Compliance with environmental, health, safety and security laws, regulations and related permits increases our capital expenditures and operating expenses, and violation of these laws, regulations or permits could result in significant civil and criminal liabilities, injunctions or other penalties. Future governmental actions could result in more restrictive laws and regulations, which could increase required capital expenditures and operating expenses. At this time, we are unable to estimate either the impact, if any, of potential future regulation and/or legislation on our financial condition or results of operations, or the amount and timing of such possible future expenditures or expenses. The risk of additional compliance expenditures, expenses and liabilities are inherent to government-regulated industries, including midstream energy. As a result, there can be no assurances that significant expenditures, expenses and liabilities will not be incurred in the future. However, while compliance may affect our capital expenditures and operating expenses, we believe that the cost of such compliance will not have a material impact on our competitive position, financial condition or results of operations. Further, we do not believe that our cost of compliance is proportionately greater than the cost to other companies operating in our industry.
Discussed below are the primary U.S. environmental, health, safety and security laws applicable to our operations. Compliance with or violations of any of these laws and related regulations could result in significant expenditures, expenses and liabilities.
Occupational, Safety and Health
We are subject to the Occupational Safety and Health Act, as amended, and analogous or more stringent international, state and local laws and regulations for the protection of worker safety and health. In addition, we have operations subject to the Occupational Safety and Health Administration’s Process Safety Management regulations. These regulations apply to processes that involve certain chemicals at or above specified thresholds.
Fuel Standards and Renewable Energy
International, federal, state and local laws and regulations regulate the fuels we transport and store for our customers. Changes in these laws or regulations could affect our earnings, including by reducing our throughput volumes, or require capital expenditures and expenses to segregate and separately store fuels. In addition, several federal and state programs require,
subsidize or encourage the purchase and use of competing fuels or energy, renewable energy, electric battery-powered motor vehicle engines and renewable fuels and blending additives, like ethanol, biodiesel and renewable diesel. These programs may over time offset projected increases or reduce the demand for refined products, particularly gasoline, in certain markets. However, the increased production and use of renewable fuels may also create opportunities for pipeline transportation and fuel blending. Other legislative changes in the future may similarly alter the expected demand and supply projections for refined products in ways that cannot be predicted.
Hazardous Substances and Hazardous Waste
The Federal Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA or “Superfund,” and analogous or more stringent international, state and local laws and regulations, impose restrictions and liability related to the release, threatened release, disposal and remediation of hazardous substances. This liability can be joint and several strict liability, without regard to fault or the legality of the original release or disposal. Current operators of a facility, past owners or operators of a facility and parties who arranged for the disposal of a hazardous substance can be held liable under these laws and regulations.
We currently own, lease, and operate on, and have in the past owned, leased and operated on, properties and at facilities that handled, transported and stored hazardous substances. Despite our compliance with applicable requirements and industry standards, hazardous substances may have been released on or under our facilities and properties, or on or under locations where these substances were taken for disposal. We are currently remediating subsurface contamination at several facilities, and, based on currently available information, we believe the costs related to these remedial activities should not materially affect our financial condition or results of operations. However, the aggregate total cost of remediation projects can be difficult to estimate, and there are no assurances that the cost of future remedial activities will not become material. Further, applicable laws or regulation, including those dictating the degree of remediation required, may be revised to be more restrictive in the future. As a result, we are unable to estimate the effect of future regulation on our financial condition or results of operations or the amount and timing of future expenditures required to comply with such possible regulatory changes.
The Federal Resource Conservation and Recovery Act, as amended, and analogous or more stringent international, state and local laws and regulations impose restrictions and strict controls regarding the handling and disposal of wastes, including hazardous wastes. We generate hazardous wastes and it is possible that additional wastes, which could include wastes currently generated during operations, will be designated as hazardous wastes in the future. Hazardous wastes are subject to more rigorous requirements than are non-hazardous wastes.
Air
The Federal Clean Air Act, as amended, and various applicable international, state and local laws and regulations impose restrictions and strict controls regarding emission into the air, including greenhouse gas emissions. These laws and regulations generally require permits issued by applicable federal, state or local authorities for emissions, and impose monitoring and reporting requirements. Such laws and regulations can also require pre-approval for the construction or modification of certain operations or facilities expected to produce or increase air emissions.
Water
The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, the federal Spill Prevention, Control, and Countermeasure and Facility Response Plan Rules and analogous or more stringent international, state and local laws and regulations impose restrictions and strict controls regarding the discharge of pollutants into state waters or waters of the United States. The discharge of pollutants into waters is generally prohibited, except in accordance with a permit issued by applicable federal or state income tax purposes or we were otherwiseauthorities. The Oil Pollution Act further regulates the discharge of oil, and the response to and liability for oil spills, and the Rivers and Harbors Act regulates pipelines crossing navigable waters.
Pipeline and Other Asset Integrity, Safety and Security
Our pipeline, storage tank and other operations are subject to extensive international, federal, state and local laws and regulations governing integrity, safety and security, including those in Title 49 of the U.S. Code and its implementing regulations. These laws and regulations include the Pipeline and Hazardous Materials Safety Administration’s requirements for safe pipeline design, construction, operation, maintenance, inspection, testing and corrosion control, control rooms and qualification programs for operating personnel. In addition, we have marine terminal operations subject to Coast Guard safety, integrity and security regulations and standards. We also have operations subject to the Department of Homeland Security Chemical Facility Anti-Terrorism Standards and security guidelines and directives issued by the Transportation Security Administration.
Although we take proactive steps to protect our company, systems and data from cyberattacks, such as implementing multiple layers of security, segregated systems and user access, antivirus tools, vulnerability scanning, monitoring and patch
management, regular employee training, phishing tests, penetration tests, internal risk assessments, independent third-party assessments, tabletop exercises to test our incident response plan, enhanced cyber diligence of vendors and physical security measures, all companies are at risk of a cyberattack. Due to the continued acceleration of cyberattacks, generally and against our industry, regulatory actions by federal, state and local governmental agencies in the U.S. and in Mexico have increased. Although we believe that we have robust cybersecurity procedures and other safeguards in place, we cannot guarantee their effectiveness, and a significant failure, compromise, breach or interruption in our systems or those of our customers or vendors could have a material effect on our operations and the operations of our customers and vendors.
CRITICAL ACCOUNTING POLICIES
The preparation of financial statements in accordance with U.S. generally accepted accounting principles requires management to select accounting policies and to make estimates and assumptions related thereto that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The accounting policies below are considered critical due to judgments made by management and the sensitivity of these estimates to deviations of actual results from management’s assumptions. The critical accounting policies should be read in conjunction with Note 2 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data,” which summarizes our significant accounting policies.
Impairment of Long-Lived Assets
We test long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount of entity-level taxation,the asset may not be recoverable. We evaluate recoverability using undiscounted estimated net cash flows generated by the related asset or asset group. If the results of that evaluation indicate that the undiscounted cash flows are less than the carrying amount of the asset (i.e., the asset is not recoverable) we perform an impairment analysis. If our intent is to hold the asset for continued use, we determine the amount of impairment as the amount by which the net carrying value exceeds its fair value. If our intent is to sell the asset, and the criteria required to classify an asset as held for sale are met, we determine the amount of impairment as the amount by which the net carrying amount exceeds its fair value less costs to sell.
In determining the existence of an impairment of the carrying value of an asset, we make a number of subjective assumptions as to:
•whether there is an event or circumstance that may indicate that the carrying amount of an asset may not be recoverable;
•the grouping of assets;
•the intention of holding, abandoning or selling an asset;
•the forecast of undiscounted expected future cash flows with respect to an asset or asset group; and
•if an impairment exists, the fair value of the asset or asset group.
Our estimates of undiscounted future cash flows include: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) estimates of useful lives of the assets. The identification of impairment indicators and the estimates of future undiscounted cash flows are highly subjective and are based on numerous assumptions about future operations and market conditions, which we believe to be reasonable but are inherently uncertain. The uncertainties underlying our assumptions and estimates could differ significantly from actual results and could cause a different conclusion about the recoverability of our assets. If we determined one or more assets was impaired, the amount of impairment could be material to our results of operations.
We recorded long-lived asset impairment charges of $154.9 million in 2021. Please refer to Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data,” for discussion of the impairment charges.
Impairment of Goodwill
We perform an assessment of goodwill annually or more frequently if events or changes in circumstances warrant. We have the option to first perform a qualitative annual assessment to determine whether it is necessary to perform a quantitative goodwill impairment test. A qualitative assessment includes, among other things, industry and market considerations, overall financial performance, other entity-specific events and events affecting individual reporting units. If after assessing the totality of events or circumstances for each reporting unit, we determine that it is more likely than not that the carrying value exceeds its fair value, then we would perform a quantitative impairment test for that reporting unit.
We recognize an impairment of goodwill if the carrying value of a reporting unit that contains goodwill exceeds its estimated fair value. In order to estimate the fair value of the reporting unit, including goodwill, management must make certain estimates and assumptions that affect the total fair value of the reporting unit including, among other things, an assessment of market conditions, projected cash flows, discount rates and growth rates. Management’s estimates of projected cash flows related to the
reporting unit include, but are not limited to, future earnings of the reporting unit, assumptions about the use or disposition of assets included in the reporting unit, estimated remaining lives of those assets, and future expenditures necessary to maintain the assets’ existing service potential.
We calculate the estimated fair value of each of our reporting units using a weighted-average of values calculated using an income approach and a market approach. The income approach involves estimating the fair value of each reporting unit by discounting its estimated future cash flows using a discount rate, consistent with a market participant’s assumption. The market approach bases the fair value measurement on information obtained from observed stock prices of public companies and recent merger and acquisition transaction data of comparable entities. Our fair value estimates are sensitive to typical valuation assumptions, particularly our estimates for the weighted-average cost of capital used for the income approach and the guideline public company and guideline transaction multiples used for the market approach.
We recorded a goodwill impairment charge of $34.1 million for the year ended December 31, 2021. Please refer to Notes 4 and 10 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data,” for additional information.
NEW ACCOUNTING PRONOUNCEMENTS
Please refer to Note 3 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of new accounting pronouncements.
AVAILABLE INFORMATION
Our internet website address is www.nustarenergy.com. Information contained on our website is not part of this report. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and any amendments thereto, filed with (or furnished to) the SEC are available on our website, free of charge, as soon as reasonably practicable after we file or furnish such material (select the “Investors” link, then the “SEC Filings” link). We also post our corporate governance guidelines, code of business conduct and ethics, code of ethics for senior financial officers and the charters of our board’s committees on our website free of charge (select the “Investors” link, then the “Corporate Governance” link).
Our governance documents are available in print to any unitholder that makes a written request to Corporate Secretary, NuStar Energy L.P., 19003 IH-10 West, San Antonio, Texas 78257 or corporatesecretary@nustarenergy.com.
ITEM 1A. RISK FACTORS
RISKS RELATED TO OUR BUSINESS
Changes in price levels could negatively impact our revenue, our expenses, or both, which could adversely affect our business.
The operation of our assets and the execution of capital projects require significant expenditures for labor, materials, property, equipment and services. As a result, such costs may increase during periods of high inflation, including as a result of rising commodity prices, supply chain disruptions and tight labor markets. Recent inflationary pressures affecting the general economy and the energy industry have increased our expenses and capital costs, and those costs may continue to increase. While we expect our pipeline systems to benefit from the positive revenue impact of our tariff indexation increases, we may not be able to pass all of these increased costs to our customers in the form of higher fees for our services, and, if so, our revenues and operating margins would be reduced. Prior to adjustments to applicable rates, material cost increases may affect our operating margins, even if margins in subsequent periods may be normalized following applicable rate adjustments. Accordingly, increased costs during periods of high inflation that are not passed through to customers or offset by other factors may have a material adverse effect on our financial position, results of operations and cash flows.
We may not be able to generate sufficient cash from operations to enable us to pay quarterly distributions to our unitholders.
The amount of cash that we can distribute to our unitholders each quarter principally depends upon the amount of cash we generate from our operations, based on, among other things:
•prevailing macroeconomic conditions as well as economic conditions in and specific to our primary markets;
•demand for and supply of crude oil, refined products, renewable fuels and anhydrous ammonia;
•volumes transported in our pipelines and stored in our terminals and storage facilities;
•the financial stability and strength of our customers;
•tariff and/or contractually determined rates and fees we charge and the revenue we realize for our services;
•domestic and foreign governmental laws, regulations, sanctions, embargoes and taxes;
•the effect of energy conservation, efficiency and other evolving priorities;
•the effect of weather events on our operations and demand for our services; and
•the results of our marketing, trading and hedging activities, which fluctuate depending upon the relationship between refined product prices and prices of crude oil and other feedstocks.
Furthermore, the amount of cash that we will have available for distribution depends on a number of other factors, including:
•our debt service requirements and restrictions on distributions contained in our current or future financing agreements;
•our capital expenditures;
•our operating costs;
•the costs to comply with environmental, health, safety and security laws and regulations;
•fluctuations in our working capital needs;
•adjustments in cash reserves made by our board of directors, in its discretion;
•availability of and access to equity capital and debt markets; and
•the sources of cash used to fund our acquisitions, if any.
Moreover, the total amount of cash that we have available for distribution to common unitholders wouldis further reduced by the required distributions with respect to our preferred units.
It is possible that one or more of the factors listed above, which may be substantially reduced.
The anticipated after-tax benefitfurther impacted by the lingering impact of the COVID-19 pandemic or other public health crises, as well as the actions of oil-producing nations, may reduce our available cash to such an investment in our units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service (the IRS) on this matter.
Despite the factextent that we are unable to pay distributions at the current level or at all in a given quarter. Cash distributions to our unitholders depend primarily upon our cash flows, including cash flows from reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items; in other words, we may be able to make cash distributions during periods in which we record net losses and may not be able to make cash distributions during periods in which we record net income.
An extended period of reduced demand for or supply of crude oil and refined products could have an adverse impact on our results of operations, cash flows and ability to make distributions to our unitholders.
Our business is ultimately dependent upon the demand for and supply of the crude oil and refined products we transport in our pipelines and store in our terminals. Market prices for crude oil and refined products, including fuel oil, are subject to wide fluctuation in response to changes in global and regional supply that are beyond our control. Increases in the price of crude oil may result in a lower demand for refined products that we transport, store and market, including fuel oil, while sustained low prices may lead to reduced production in the markets served by our pipelines and storage terminals.
Any sustained decrease in demand for refined products in the markets our pipelines and terminals serve that extends beyond the expiration of our existing throughput and deficiency agreements could result in a significant reduction in throughputs in our pipelines and storage in our terminals, which would reduce our cash flows and impair our ability to make distributions to our unitholders. Factors that tend to decrease market demand include:
•a recession, inflation or other adverse economic conditions that result in lower spending by consumers on gasoline, diesel and travel;
•events that negatively impact global economic activity, travel and demand generally, such as occurred in response to the COVID-19 pandemic;
•higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline;
•an increase in aggregate automotive engine fuel economy;
•new government and regulatory actions or court decisions requiring the phase out or reduced use of gasoline-fueled vehicles;
•the increased use of and public demand for use of alternative fuel sources or electric vehicles;
•an increase in the market price of crude oil that increases refined product prices, which may reduce demand for refined products and increase demand for alternative products; and
•a decrease in corn acres planted for ethanol, which may reduce demand for anhydrous ammonia.
Similarly, any sustained decrease in the supply of crude oil and refined products in markets we serve could result in a significant reduction in throughputs in our pipelines and storage in our terminals, which would reduce our cash flows and undermine our ability to make distributions to our unitholders. Factors that tend to decrease supply and, by extension, utilization of our pipelines and terminals include:
•prolonged periods of low prices for crude oil and refined products that result in decreased exploration and development activity and reduced production in markets served by our pipelines and storage terminals;
•macroeconomic forces affecting, or actions taken by, oil and gas producing nations that impact supply of and prices for crude oil and refined products;
•a lack of drilling services, equipment or skilled personnel available to producers to accommodate production needs;
•changes in laws, regulations, sanctions or taxation that directly or indirectly delay supply or production or increase the cost of production of refined products; and
•political unrest or hostilities, activist interference and the resulting governmental response thereto.
Failure to retain or replace current customers and renew existing contracts on comparable terms to maintain utilization of our pipeline and storage assets at current or more favorable rates could reduce our revenue and cash flows to levels that adversely affect our ability to make quarterly distributions to our unitholders.
Our revenue and cash flows are generated primarily from our customers’ payments of fees under throughput contracts and storage agreements. Failure to renew or enter into new contracts or a material reduction in utilization under existing contracts results from many factors, including:
•sustained low crude oil prices;
•a material decrease in the supply or price of crude oil;
•a material decrease in demand for refined products in the markets served by our pipelines and terminals;
•political, social or economic instability in the United States or another country that has a detrimental impact on customers based there and our ability to conduct our operations;
•competition for customers from companies with comparable assets and capabilities;
•scheduled turnarounds or unscheduled maintenance at customers we serve;
•operational problems or catastrophic events affecting our assets or customers we serve;
•environmental or regulatory proceedings or other litigation that compel the cessation of all or a portion of the operations of our assets or those of the customers we serve;
•increasingly stringent environmental, health, safety and security regulations;
•a decision by our current customers to redirect products transported in our pipelines to markets not served by our pipelines or to transport crude oil or refined products by means other than our pipelines; and
•a decision by our current customers to shut down, limit operations of or sell one or more of the refineries we serve to a purchaser that elects not to use our pipelines and terminals.
Depending on conditions in the credit and capital markets at a given time, we may not be able to obtain funding on acceptable terms or at all, which may hinder or prevent us from meeting our future capital needs, satisfying our debt obligations, or making quarterly distributions to our unitholders.
From time to time, the domestic and global financial markets and economic conditions are volatile and disrupted by a variety of factors, including low consumer confidence, high unemployment, geoeconomic and geopolitical issues, weak economic conditions, uncertainty in the market and negative sentiment toward fossil fuel energy-related companies generally, or master limited partnerships specifically. For example, during the COVID-19 pandemic, global financial markets have experienced significant volatility, which is expected to continue during the pendency of the pandemic. In addition, there are fewer investors and lenders for master limited partnership debt and equity capital market issuances than there are for corporate issuances, and negative public sentiment toward the fossil fuel energy industry has led some investors and lenders to reduce or cease investing in and lending to fossil fuel energy companies. As a result, the cost of raising capital has increased, the availability of funds has diminished and certain lenders have, and others may, refuse to refinance existing debt on similar terms or at all and reduce, or in some cases cease to provide, funding to borrowers such as us.
In general, if we do not generate sufficient cash from operations to finance our expenditures and funding from external sources is not available when needed, or is available only on unfavorable terms, we may be unable to execute our growth strategy, complete future acquisitions or construction projects or take advantage of other business opportunities and may be required to reduce investments or capital expenditures or sell assets, which could have a material adverse effect on our revenues and results of operations, and we may not be able to satisfy our debt obligations or pay distributions to our unitholders.
Our future financial and operating flexibility may be adversely affected by our significant leverage, any future downgrades of our credit ratings, restrictions in our debt agreements and conditions in the financial markets.
As of December 31, 2022, our consolidated debt was $3.3 billion, and we have the ability to incur more debt. In addition to any potential direct financial impact of our debt, a material increase to our debt or other adverse financial factors would likely be viewed negatively by credit rating agencies, which could result in ratings downgrades, increased costs or inability for us to access the capital markets and an increase in interest rates on amounts borrowed under Delaware law,our revolving credit agreement and an increase in certain fees on our accounts receivable securitization program.
Our revolving credit agreement contains restrictive covenants, such as limitations on indebtedness, liens, mergers, asset transfers and certain investing activities. In addition, that agreement limits us to a consolidated debt coverage ratio (consolidated debt to consolidated EBITDA, each as defined in the agreement) not to exceed 5.00-to-1.00 and requires us to maintain a minimum consolidated interest coverage ratio (as defined in the agreement) of at least 1.75-to-1.00. Failure to comply with any of the restrictive covenants or the maximum consolidated debt coverage ratio or minimum consolidated interest coverage ratio requirements would constitute an event of default and could result in acceleration of our obligations under our revolving credit agreement and possibly other agreements. Our accounts receivable securitization program, senior
notes and other debt obligations also contain various customary affirmative and negative covenants and default, indemnification and termination provisions, and provide for acceleration of amounts owed upon the occurrence of certain specified events. Future financing agreements we may enter into may contain similar or more restrictive covenants and ratio requirements than those we have negotiated for our current financing agreements.
Our debt service obligations, restrictive covenants, ratio requirements and maturities may adversely affect our ability to finance future operations, pursue acquisitions, fund our capital needs and pay cash distributions to our unitholders. In addition, this leverage may make our results of operations more susceptible to adverse economic or operating conditions, limit our flexibility in planning for, or reacting to, changes in our business and industry and place us at a competitive disadvantage compared to competitors with proportionately less indebtedness. For example, during an event of default under certain of our debt agreements, we would be prohibited from making cash distributions to our unitholders.
Our ability to service our debt will depend on, among other things, our future financial and operating performance and our ability to access the capital markets, which will be treatedaffected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our indebtedness and we are unable to access the capital markets or otherwise refinance our indebtedness, we may be required to reduce our distributions, reduce or delay our business activities, investments or capital expenditures, sell assets or issue additional equity, which could materially and adversely affect our financial condition, results of operations, cash flows and ability to make distributions to unitholders, as well as the trading price of our units.
Changes in interest rates could adversely affect our business and the trading price of our units.
We have significant exposure to increases in interest rates through variable rate provisions in certain of our debt instruments and our Series A, Series B and Series C preferred units. At December 31, 2022, we had approximately $3.3 billion of consolidated debt, of which $2.6 billion was at fixed interest rates and $0.7 billion was at variable interest rates. In addition, the distribution rates on our Series A, Series B and Series C preferred units converted from a corporationfixed rate to a floating rate in December 2021, June 2022 and December 2022, respectively. Our results of operations, cash flows and financial position could be materially adversely affected by significant changes in interest rates and uncertainty regarding the floating rates referenced in our variable rate debt instruments and preferred units could adversely affect the value of those financing arrangements. Please see “Quantitative and Qualitative Disclosures about Market Risk” for federal income taxdiscussion of our market risk related to interest rates.
Furthermore, although we have positioned ourselves to self-fund all of our expenses, distribution requirements and capital expenditures for 2023 using internally generated cash flows as we did for the full-year 2022 and 2021, we funded our strategic capital expenditures and any acquisitions prior to 2021 primarily from borrowings under our revolving credit agreement, funds raised through debt or equity offerings and/or sales of non-strategic assets. An increase in interest rates may also have a negative impact on our ability to access the capital markets at economically attractive rates.
Moreover, the market price of master limited partnership units, like other yield-oriented securities, may be affected by, among other factors, implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, increases or decreases in interest rates may affect whether or not certain investors decide to invest in master limited partnership units, including ours, and a rising interest rate environment could have an adverse impact on our unit price and impair our ability to issue additional equity or incur debt to fund growth or for other purposes, unless we satisfyincluding distributions.
Our inability to develop, fund and execute growth projects and acquire new assets could limit our ability to maintain and grow quarterly distributions to our unitholders.
Our ability to maintain and grow our distributions to unitholders depends on the growth of our existing businesses and strategic acquisitions. Decisions regarding new growth projects rely on numerous estimates, including, among other factors, the ability to secure a “qualifying income” requirement. Based uponcommitment from a customer that sufficiently exceeds our current operations, we believe we satisfycost of capital to justify the qualifying income requirement. Failing to meetproject cost, predictions of future demand for our services, future supply shifts, crude oil production estimates, commodity price environments, economic conditions, both domestic and foreign, and potential changes in the qualifying income requirement or a change in current lawfinancial condition of our customers. Our predictions of such factors could cause us to be treated as a corporation for federal income tax purposesforego certain investments and to lose opportunities to competitors who make investments based on different predictions or otherwise subjecthave greater access to financial resources. In addition, volatile market conditions have caused us to taxation as an entity.
reevaluate the estimates underlying certain planned projects and delay the timing of certain projects until conditions improve. If we were treated asare unable to develop and execute expansion projects, implement business development opportunities, acquire new assets and finance such activities on economically acceptable terms, our future growth will be limited, which could have a corporation for federal income tax purposes, we would pay federal income taxsignificant adverse impact on our taxable income atresults of operations and cash flows and, accordingly, result in reduced distributions over time.
Failure to complete capital projects as planned adversely affects our financial condition, results of operations and cash flows.
While we incur financing costs during the corporate tax rateplanning and would likely pay state and local income tax at varying rates. Distributions to unitholders who are treated as holders of corporate stock would generally be taxed again as corporate dividends (to the extentconstruction phases of our currentprojects, a project does not generate expected operating cash flows until it is at least substantially completed, if at all. Additionally, our forecasted operating results from capital spending projects are based on future market fundamentals that are not within our control, including changes in
general economic conditions, the supply and accumulated earningsdemand of crude oil, refined products and profits), and no income, gains, losses, deductions or credits would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our distributable cash flow would be substantially reduced.
Moreover, changes in current state law may subject us to entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes or an increase in the existing tax rates would substantially reduce the cash available for distributionrenewable fuels, availability to our unitholders. Therefore, if we were treated ascustomers of attractively priced alternative solutions for storage, transportation or supplies of crude oil, refined products and renewable fuels and overall customer demand. As a corporation for federal income tax purposesresult of these uncertainties, the anticipated benefits associated with our capital projects may not be achieved or otherwise subjected tocould be delayed. In turn, this could have a material amountnegative impact on our results of entity-level taxation, there would be a material reduction in the anticipatedoperations and cash flow and after-tax returnour ability to make cash distributions to our unitholders, likely causing a substantial reduction in the valueunitholders.
Although we evaluate and monitor each capital spending project and try to anticipate difficulties that may arise, delays or cost increases related to capital spending programs involving construction of new facilities (or improvements and repairs to our units.
The tax treatment of publicly traded partnerships or an investment in our 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 units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Further, final Treasury regulations under Section 7704(d)(1)(E) of the Code published in the Federal Register interpret the scope of qualifying income requirements for publicly traded partnerships by providing industry-specific guidance. We do not believe the final Treasury regulationsfacilities) adversely affect our ability to be treatedachieve forecasted operating results. Delays or cost increases arise as a partnershipresult of many factors that are beyond our control, including:
•adverse economic conditions;
•market-related increases in a project’s debt or equity financing costs;
•severe adverse weather conditions, natural disasters or other events (such as hurricanes, equipment malfunctions, explosions, fires, spills or public health events) affecting our facilities or employees, or those of vendors and suppliers;
•non-performance or delay by, or disputes with, counterparties, vendors, suppliers, contractors or sub-contractors involved with a project;
•denial or delay in issuing requisite regulatory approvals and/or permits;
•delay or increased costs to obtain right-of-way or other property rights;
•delays or failures by third parties to complete related projects;
•protests and other activist interference with planned or in-process projects;
•unplanned increases in the cost of construction materials or labor;
•shortages or disruptions in transportation of modular components and/or construction materials; or
•shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages.
Competing midstream service providers, including certain major energy and chemical companies, possess, or have greater financial resources to acquire, assets better suited to meet customer demand, which could undermine our ability to obtain and retain customers or reduce utilization of our assets, which could reduce our revenues and cash flows, thereby reducing our ability to make our quarterly distributions to unitholders.
We face competition in all aspects of our business and can give no assurances that we will be able to compete effectively against our competitors. Our competitors include major energy and chemical companies, some of which have greater financial resources, more pipelines or storage terminals, greater capacity pipelines or storage terminals and greater access to supply than we do. Certain of our competitors also have advantages in competing for U.S.acquisitions or other new business opportunities because of their financial resources and synergies in operations. As a consequence of increased competition in the industry or market conditions, some customers are and others may be in the future reluctant to renew or enter into long-term contracts or contracts that provide for minimum throughput amounts. Our inability to renew or replace a significant portion of our current contracts as they expire, to enter into contracts for newly acquired, constructed or expanded assets and to respond appropriately to changing market conditions would have a negative effect on our revenue, cash flows and ability to make quarterly distributions to our unitholders.
Our operations are subject to operational hazards and interruptions, and we cannot insure against or predict all potential losses and liabilities that might result therefrom.
Our operations and those of our customers and suppliers are subject to operational hazards and unforeseen interruptions due to natural disasters, adverse weather conditions (such as hurricanes, tornadoes, storms, floods and earthquakes), accidents, fires, explosions, hazardous materials releases, mechanical failures, cyberattacks, acts of terrorism and other events beyond our control. These events have, and may in the future, result in a loss of life or equipment, injury or extensive property or environmental damage, as well as an interruption in our operations or those of our customers or suppliers. In the event any of our facilities, or those of our customers or suppliers, suffer significant damage or are forced to shut down for a significant period of time, it may have a material adverse effect on our results of operations and our financial condition as a whole. Additionally, our pipelines, terminals and storage assets are generally long-lived assets, and some have been in service for many years. The age and condition of our assets could result in increased maintenance or repair expenditures in the future.
As a result of market conditions and losses experienced by us and other companies, the premiums and deductibles for our insurance policies have increased and could continue to increase substantially; therefore, it has become increasingly difficult to, and we may not be able to, maintain or obtain insurance of the type and amount we desire at reasonable rates. In addition, certain insurance coverage is subject to broad exclusions, and may become subject to further exclusions, become unavailable altogether or become available only for reduced amounts of coverage and at higher rates. We are not fully insured against all hazards and risks to our business, and the insurance we carry requires us to meet deductibles before we collect for losses we sustain. If we incur a significant liability for which we are uninsured or not fully insured, or if there is a significant delay in payment of a major insurance claim, such a liability could have a material adverse effect on our financial position.
We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, vendors or other counterparties reduces our revenues and increases our expenses, and any significant level of nonpayment and nonperformance could have a negative impact on our ability to conduct our business, operating results, cash flows and our ability to service our debt obligations and make distributions to our unitholders.
Weak and volatile economic conditions and widespread financial stress reduce the liquidity of our customers, vendors or other counterparties, making it more difficult for them to meet their obligations to us. We are therefore subject to risks of loss resulting from nonpayment or nonperformance by our customers to whom we extend credit. Financial problems encountered by our customers limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements. In addition, nonperformance by vendors or their subcontractors, who have committed to provide us with critical products or services, increases our costs and could result in significant disruptions or interfere with our ability to successfully conduct our business. Although we attempt to mitigate our risk through warehouseman’s liens and other security protections, we are not always able to enforce such liens and protections due to competing claims from other parties. Any substantial increase in the nonpayment and nonperformance by our customers, vendors or other counterparties or our inability to enforce our warehouseman’s liens and other security protections could have a material adverse effect on our results of operations, cash flows and ability to make distributions to our unitholders.
We rely on our information technology and operational technology systems to conduct our business. Any significant cybersecurity breach or other significant disruption to those systems would cause our business, financial results and reputation to suffer, increase our costs and expose us to liability, and could adversely affect our ability to make distributions to our unitholders.
We rely on our information technology systems and our operational technology systems to process, transmit and store information, such as employee, customer and vendor data, and to conduct almost all aspects of our business, including safely operating our pipelines and storage facilities, recording and reporting commercial and financial transactions and receiving and making payments. We also rely on systems hosted by third parties, with respect to which we have limited visibility and control, and that have access to or store certain of our employee, customer and vendor data. The security of these networks and systems is critical to our operations and business strategy.
Although we take proactive steps to protect us, our systems and our data from cyberattacks, such as implementing multiple layers of security, segregated systems and user access, antivirus tools, vulnerability scanning, monitoring and patch management, regular employee training, phishing tests, penetration tests, internal risk assessments, independent third-party assessments, tabletop exercises to test our incident response plan, enhanced cyber diligence of vendors and physical security measures, all companies are at risk of a cyberattack. The number and sophistication of reported cyberattacks by both state-sponsored and criminal organizations continue to increase, across industries and around the world, including attacks on operators of critical infrastructure assets, such as pipelines, as well as the third parties that provide technology services for critical infrastructure, in some cases with considerable negative impact on targeted companies’ ability to conduct business.
Like other companies, we recognize that, despite our security measures, we remain subject to cybersecurity incidents due to attacks from a variety of external threat actors, internal employee error or malfeasance and cybersecurity incidents suffered by our service providers, vendors or customers. In addition, in connection with precautions during the COVID-19 pandemic, many of our employees and those of our service providers, vendors and customers began working, and some have continued to work, from home or other remote-work locations, where cybersecurity protections may be less robust and cybersecurity procedures and safeguards may be less effective. Moreover, certain attacker techniques and goals, such as surveillance, intelligence gathering or extended reconnaissance, may remain undetected for an extended period of time, which can increase the breadth and negative impact of an incident. A significant failure, compromise, breach or interruption in our systems or those of third parties critical to our operations could result in a disruption of our operations; physical damage to our assets or the environment; physical, financial, or other harm to employees or others; safety incidents; damage to our reputation; loss of customers or revenues; increased costs for remedial actions; and potential litigation or regulatory fines. Failures, interruptions and similar events that result in the loss or improper disclosure of information maintained in our systems and networks or those of our vendors, including personnel, customer and vendor information, have in the past and may in the future require reporting under relevant contractual obligations and laws and regulations protecting personal data and privacy and could also subject us to litigation or other liability under relevant contractual obligations, laws and regulations. Our financial results could also be adversely affected if our systems are breached or an employee, vendor or customer causes our systems to fail, either as a result of inadvertent error or deliberate tampering with or manipulation of our systems.
Due to the continued acceleration of cyberattacks, generally and against our industry, regulatory actions by federal, income tax purposes.state and local governmental agencies in the United States and in Mexico have increased. Evolving laws and regulations governing cybersecurity and data privacy and protection pose increasingly complex compliance challenges. Although we believe that we have robust cybersecurity procedures and other safeguards in place, we cannot guarantee their effectiveness, and a significant failure, compromise, breach or interruption in our systems or those of our customers or vendors could have a material effect on our operations and the operations of our customers and vendors. As threats continue to evolve and cybersecurity and data privacy and protection laws and regulations continue to develop, we have spent and expect to continue spending additional resources to continue to enhance our cybersecurity, data protection, business continuity and incident response measures, to investigate and remediate any vulnerabilities to, or consequences of, cyber incidents, as well as on regulatory compliance.
Disputes regarding a failure to maintain product quality specifications or other claims related to the operation of our assets and the services we provide to our customers result in unforeseen expenses and could result in the loss of customers.
Certain of the products we store and transport are produced to precise customer specifications. If the quality and purity of the products we receive are not maintained or a product fails to perform in a manner consistent with the quality specifications required by our customers, customers have sought, and could in the future seek, replacement of the product or damages for costs incurred as a result of the product failing to perform as guaranteed. We also have faced, and could in the future face, other claims by our customers if our assets do not operate as expected by our customers or our services otherwise do not meet our customers’ expectations. Successful claims or a series of claims against us result in unforeseen expenditures and could result in the loss of one or more customers.
Climate change and fuels legislation and other regulatory initiatives restricting emissions of “greenhouse gases” may decrease demand for some of the products we store, transport and sell, increase our operating costs or reduce our ability to expand our facilities.
Federal and state legislative and regulatory initiatives in the United States, as well as international efforts, have attempted to and will continue to address climate change and control or limit emissions of greenhouse gases. For example, the United States is now a party to the Paris Agreement and has established an economy-wide target of reducing its net greenhouse gas emissions by 50-52 percent below 2005 levels in 2030 and achieving net zero greenhouse gas emissions economy-wide by no later than 2050. The United States has also established a goal to reach 100 percent carbon emissions-free electricity by 2035. Furthermore, many state and local leaders have stated their intent to increase efforts to control or limit emissions of greenhouse gases. To this end, climate change laws or regulations enacted by the United States and other political bodies that increase costs, reduce demand or otherwise impede our operations, could, directly or indirectly, have an adverse effect on our business. Specifically, certain regulatory changes have restricted, and future changes could restrict, our ability to expand our operations and have increased, and in the future could increase, our costs to operate and maintain our existing facilities by requiring that we measure and report our emissions, install new emission controls on our facilities, acquire allowances to authorize our emissions, pay taxes related to our emissions or administer and manage an emissions program, among other things. The passage of climate change legislation and interpretation and action of federal and state regulatory bodies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to greenhouse gases, or restrictions on their use, may reduce volumes available to us for transportation and storage. These developments could have adverse effects on our business, financial position, results of operations and prospects.
In addition, certain of our blending operations subject us to potential requirements to purchase renewable fuels credits. Even though we attempt to mitigate such lost revenues or increased costs through the Tax Cutscontracts we sign with our customers, we sometimes are not able to recover those revenues or mitigate the increased costs, and Jobs Act enacted December 22, 2017, makesany such recovery depends on events beyond our control, including the outcome of future rate proceedings before the Federal Energy Regulatory Commission (FERC) or other regulators and the provisions of any final legislation or regulations. Reductions in our revenues or increases in our expenses as a result of climate change legislation or other regulatory initiatives could have adverse effects on our business, financial position, results of operations and prospects.
Finally, increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. Such events have had and may in the future have an adverse effect on our assets and operations, especially those located in coastal regions.
Public sentiment towards climate change, fossil fuels and sustainability could adversely affect our business, operations and ability to attract capital.
Our business plans are based upon the assumption that public sentiment and the regulatory environment will continue to enable the future development, transportation and use of carbon-based fuels. Negative public perception of the industry in which we operate and the influence of environmental activists and initiatives aimed at limiting climate change could interfere with our business activities, operations and access to capital. Activists concerned about the potential effects of climate change have directed their attention towards sources of funding for fossil fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital reducing or ceasing lending to or investing in companies in the fossil fuel energy industry, such as us. Such negative sentiment regarding our industry could influence consumer preference and decrease demand for the products we transport and store and result in increased regulatory scrutiny, which could then result in additional laws, regulations, guidelines and enforcement interpretations, at the federal, state or local level. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation.
Members of the investment community are also increasing their focus on sustainability practices, including practices related to greenhouse gas emissions and climate change, in the energy industry. Additionally, some members of the investment community screen companies such as ours for sustainability performance before investing in our units. In response to the increasing pressure regarding sustainability disclosures and practices, we and other companies in our industries publish sustainability reports that are made available to investors. Such reports are used by some investors to inform their investment and voting decisions, and we may continue to face increasing pressure regarding sustainability practices and disclosures. Unfavorable sustainability ratings by organizations that provide such information to investors may lead to increased negative
investor sentiment toward us or our customers and to the diversion of investment to other industries, which would have a negative impact on our unit price and/or our access to and costs of capital.
Our operations are subject to federal, state and local laws and regulations, in the U.S. and in Mexico, relating to environmental, health, safety and security that require us to make substantial expenditures.
Our operations are subject to increasingly stringent international, federal, state and local environmental, health, safety and security laws and regulations. Transporting, storing and distributing hazardous materials, including petroleum products, entails the risk of releasing these products into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies including for damages to natural resources, personal injury or property damages to private parties and significant business interruption. Further, our pipeline facilities are subject to the pipeline integrity and safety regulations of various federal and state regulatory agencies, as well as cybersecurity directives. In recent years, increased regulatory focus on pipeline integrity, safety and security has resulted in various proposed or adopted regulations. The implementation of these regulations has required, and the adoption of future regulations could require, us to make additional capital or other expenditures, including to install new or modified safety or security measures, or to conduct new or more extensive inspection and maintenance programs.
Legislative action and regulatory initiatives have resulted in, and could in the future result in, changes to operating permits, material changes in operations, increased capital expenditures and operating costs, increased costs of the U.S. federal income tax rules applicablegoods we transport and/or decreased demand for products we handle. Future impacts cannot be assessed with certainty at this time. Required expenditures to both individualsmodify operations or install pollution control equipment or release prevention and entities, including changes to the tax rate on a unitholder’s allocable share of income from the publicly traded partnership. The Tax Cutscontainment systems or other environmental, health, safety or security measures could materially and Jobs Act is complex and lacks administrative guidance. Thus, the impact of certain aspects of its provisions on us or an investment in our units is currently unclear. Unitholders should consult their tax advisor regarding the Tax Cuts and Jobs Act and its effect on us or an investment in our units.
Any changes to the federal income tax laws and interpretations thereof (including administrative guidance relating to the Tax Cuts and Jobs Act) may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for federal income tax purposes or otherwise adversely affect our business, financial condition, results of operations and liquidity if these expenditures, as with all costs, are not ultimately reflected in the tariffs and other fees we receive for our services.
We own or lease a number of properties that were used to transport, store or distribute products for many years before we acquired them; therefore, such properties were operated by third parties whose handling, disposal or release of products and wastes was not under our control. Environmental laws and regulations could impose obligations to conduct assessment or remediation efforts at our facilities, third-party sites where we take wastes for disposal, or where wastes have migrated. Environmental laws and regulations also impose joint and several liability on us for the conduct of third parties or for actions that complied with applicable requirements when taken, regardless of negligence or fault. If we were to incur a significant liability pursuant to environmental, health, safety or security laws or regulations, such a liability could have a material adverse effect on our financial position.
We operate assets outside of the United States, which exposes us to different legal and regulatory requirements and additional risk.
A portion of our revenues are generated from our assets located in northern Mexico. Our operations are subject to various risks unique to Mexico that could have a material adverse effect on our business, results of operations and financial condition, including political and economic instability from civil unrest; labor strikes; war and other armed conflict; inflation; currency fluctuations, devaluation and conversion restrictions or other factors. Any deterioration of social, political, labor or economic conditions, including the increasing threat of terrorist organizations and drug cartels in Mexico, or affecting a customer with whom we do business, as well as difficulties in staffing, obtaining necessary equipment and supplies and managing foreign operations, may adversely affect our operations or financial results. We are also exposed to the risk of foreign and domestic governmental actions that may: impose additional costs on us; delay permits or otherwise impede our operations; limit or disrupt markets for our operations, restrict payments or limit the movement of funds; impose sanctions on or otherwise restrict our ability to conduct business with certain customers or persons or in certain countries; or result in the deprivation of contract rights. Our operations outside the United States may also be affected by changes in trade protection laws, policies and measures, and other regulatory requirements affecting trade and investment, including the Foreign Corrupt Practices Act and foreign laws prohibiting corrupt payments, as well as travel restrictions and import and export regulations.
We may be unable to obtain or renew permits necessary for our current or proposed operations, which could inhibit our ability to conduct or expand our business.
Our facilities operate under a number of federal, state and local permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. These limits and standards require a significant amount of monitoring, recordkeeping and reporting in order to demonstrate compliance with the underlying permit, license or approval. Noncompliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. In addition, public protest, political activism and responsive government intervention have made it more difficult for energy companies to acquire the permits required to complete planned infrastructure projects. A decision by a government agency to deny or delay issuing a new or renewed permit, license or approval, or to revoke or substantially modify an existing permit, license or approval, could have a material adverse effect on our ability to continue or expand our operations and on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.
We could be subject to liabilities from our assets that predate our acquisition of those assets, but that are not covered by indemnification rights we have against the sellers of the assets.
We have acquired assets and businesses and we are not always indemnified by the seller for liabilities that precede our ownership. In addition, in some cases, we have indemnified the previous owners and operators of acquired assets or businesses. Some of our assets have been used for many years to transport and store crude oil and refined products, and past releases could require costly future remediation. If a significant release or event occurred in the past, the liability for which was not retained by the seller, or for which indemnification by the seller is not available, it could adversely affect our financial position and results of operations. Conversely, if liabilities arise from assets we have sold, we could incur costs related to those liabilities if the buyer possesses valid indemnification rights against us with respect to those assets.
Our interstate common carrier pipelines are subject to regulation by the FERC, which could have an adverse impact on our ability to recover the full cost of operating our pipelines and the revenue we are able to receive from those operations.
The FERC regulates the tariff rates and terms and conditions of service for interstate oil movements on common carrier pipelines. FERC requires that these rates be just and reasonable and that the pipeline not engage in undue discrimination with respect to any shipper. The FERC or shippers may challenge required pipeline tariff filings, including rates and terms and conditions of service. Further, other than for rates set under market-based rate authority, if a new rate is challenged by protest and investigated by the FERC, the FERC may require the pipeline owner to refund amounts collected in excess of the deemed just and reasonable rate. In addition, shippers may challenge by complaint tariff rates and terms and conditions of service even after they take effect, and the FERC may order a carrier to change its rates prospectively to a just and reasonable level. A complaining shipper also may obtain reparations for damages sustained during the two years prior to the date of the complaint.
We are unableable to predict whether any additionaluse various FERC-authorized rate change methodologies for our interstate pipelines, including indexed rates, cost-of-service rates, market-based rates and negotiated rates. Typically, we adjust our rates annually in accordance with the FERC indexing methodology, which currently allows a pipeline to change its rates within prescribed ceiling levels that are tied to an inflation index. It is possible that the index may result in negative rate adjustments in some years, or that changes in the index might not be large enough to fully reflect actual increases in our costs. The FERC’s indexing methodology is subject to review and revision every five years, with the most recent five-year review occurring in 2020. On December 17, 2020, the FERC established the index level for the five-year period commencing July 1, 2021, which will end on June 30, 2026, at the Bureau of Labor’s producer price index for finished goods (PPI-FG) plus 0.78%. On January 20, 2022, the FERC granted rehearing of certain aspects of the final rule and revised the index level to PPI-FG minus 0.21%, effective March 1, 2022 through June 30, 2026. FERC ordered pipelines with filed rates that exceed their index ceiling levels based on PPI-FG minus 0.21% to file rate reductions effective March 1, 2022. Pending appellate review could result in a further change to the index.
FERC has granted us authority to charge market-based rates on some of our pipelines, which are not subject to cost-of-service or indexing constraints. If we were to lose market-based rate authority, however, we could be required to establish rates on some other basis, such as cost-of-service, which could reduce our revenues and cash flows. Additionally, because competition constrains our rates in various markets, we may from time to time be forced to reduce some of our rates to remain competitive.
We do not own all of the land on which our pipelines and facilities are located, and we are therefore subject to the possibility of increased costs or the inability to retain necessary land use.
Like other pipeline and storage logistics services providers, certain of our pipelines, storage terminals and other facilities are located on land owned by third parties and governmental agencies that we have obtained the right to utilize for these purposes through contract (rather than through outright purchase). Many of our rights-of-way or other proposals will ultimately be enacted. Anyproperty rights are perpetual in duration, but others are for a specific period of time. In addition, some of our facilities are located on leased premises. A potential loss of property rights through our inability to renew right-of-way contracts or leases or otherwise retain property rights on acceptable terms or the increased costs to renew such changesrights could negatively impact the valueadversely affect our financial condition, results of an investment in our units.
A successful IRS contest of the federal income tax positions we take may adversely impact the market for our units,operations and the costs of any contest will reduce cash flows available for distribution to our unitholders.
Increases in power prices could adversely affect our operating expenses and our ability to make distributions to our unitholders.
Power costs constitute a significant portion of our operating expenses. For the year ended December 31, 2022, our power costs equaled approximately $51.6 million, or 14% of our operating expenses for the year. We use mainly electric power at our pipeline pump stations and terminals, and such electric power is furnished by various utility companies. Requirements for utilities to use less carbon intensive power or to add pollution control devices also could cause our power costs to increase and our cash flows may be adversely affected, which could adversely affect our ability to make distributions to our unitholders.
We may be adversely affected by changes in the method of determining the London Interbank Offering Rate (LIBOR) or the replacement of LIBOR with an alternative reference rate, such as the Secured Overnight Financing Rate (SOFR).
The IRS may adopt positionspublication of non-U.S. dollar LIBOR rates ceased after publication on December 31, 2021 and the publication of U.S. dollar LIBOR rates for the most common tenors (overnight and one, three, six and twelve months) is expected to cease after publication on June 30, 2023. Regulators have emphasized that, differ fromdespite any continued publication of U.S. dollar LIBOR rates through June 30, 2023, no new contracts using U.S. dollar LIBOR rates should be entered into after December 31, 2021.
Further, there is no assurance that LIBOR, or any particular currency and tenor, will continue to be published until any particular date.
In addition, in March 2022, the positions we take, even positions takenAdjustable Interest Rate (LIBOR) Act (the “LIBOR Act”) was signed into law. This law provides a statutory fallback mechanism to replace LIBOR with a benchmark rate that is selected by the Federal Reserve Board and based on SOFR for certain contracts that reference LIBOR without adequate fallback provisions providing for a clearly defined replacement benchmark. On December 16, 2022, the Federal Reserve Board adopted a final rule to implement the LIBOR Act and established benchmark rates based on SOFR to replace LIBOR contracts governed by U.S. law that reference certain tenors of U.S. dollar LIBOR after June 30, 2023. The regulations include provisions that (i) provide a mechanism for the automatic replacement of LIBOR with the advicebenchmark rate selected by the Federal Reserve Board; (ii) clarify who may contractually select a benchmark replacement for LIBOR; and (iii) ensure that contracts transitioning to the replacement benchmark rate selected by the Federal Reserve Board will not be interrupted or terminated following the replacement of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or allLIBOR.
Following the amendment and restatement of the positions we take. A court may not agree with all of the positions we take. Any contest with the IRS may affect adversely the taxable income reported to our unitholdersrevolving credit agreement and the income taxes they are requiredamendment of our accounts receivable securitization program on January 28, 2022, to pay. Asreplace LIBOR with SOFR as the benchmark rate, we had approximately $0.4 billion of variable-rate indebtedness using LIBOR as a result, any such contest withbenchmark for establishing the IRS may materially and adversely impact the market for our units and the prices at which they trade.interest rate. In addition, the costsdistribution rates on our Series A, Series B and Series C preferred units converted from a fixed rate to a floating rate based on LIBOR in December 2021, June 2022 and December 2022, respectively. Although our variable rate indebtedness and Series A, Series B and Series C preferred units contain certain alternative calculation measures if LIBOR is no longer published, we are unable to unilaterally change the LIBOR-based rates on our variable rate indebtedness and Series A and Series B preferred units to a replacement benchmark rate without the consent of any contest between usthe holders of the variable rate indebtedness, the holders of 66-2/3% of each of the Series A and the IRS will be borne indirectly by our unitholdersSeries B preferred units, and our general partner because such 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 we may electnot be able to either paydo so on terms favorable to us. We do not anticipate seeking or obtaining consent of holders of the taxes directly toSeries A and Series B preferred units. In accordance with the IRS or to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes. IfLIBOR Act, we bear such payment our cash available for distribution to our unitholders might be substantially reduced.
Pursuant toexpect that 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. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised Schedule K-1 to each unitholderfloating rate based on LIBOR with respect to an auditedthe Series A and adjusted return. Although our general partner may electSeries B preferred units will be replaced with the 3-month SOFR plus a credit spread adjustment. The calculation agent for the Series C preferred units is able to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance thatselect a replacement benchmark for LIBOR, however, such election willmay not be practical, permissiblemade in a manner favorable to us. Furthermore, given SOFR’s limited history and potential volatility as compared to other benchmark or effective in all circumstances. As a result, our current unitholders may bear some or allmarket rates, the future performance of SOFR cannot be predicted based on historical performance. The consequences of the tax liability resultingtransition away from such audit adjustment, even if such unitholders did not own commonLIBOR and the use of SOFR cannot be entirely predicted but could include an increase in the cost of our variable-rate indebtedness, our Series A, Series B and Series C preferred units inand other commercial arrangements tied to LIBOR.
An impairment of goodwill or long-lived assets could reduce our earnings.
As of December 31, 2022, we had $0.7 billion of goodwill and $3.9 billion of long-lived assets, including property, plant and equipment, net and intangible assets, net. U.S. generally accepted accounting principles requires us during the tax year under audit. If, as a result of any such audit adjustment, we make payments of taxes, penaltiesto test both goodwill and interest, our cash availablelong-lived assets for distribution to our unitholdersimpairment when events or circumstances occur indicating that either goodwill or long-lived assets might be substantially reduced.
Even if unitholders do not receive any cash distributions from us, they will be required to pay taxes on their respective share of our taxable income.
Unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their respective share of our taxable income, whether or not the unitholders receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their respective share of our taxable income or even equal to the actual tax liability that results from their respective share of our taxable income.
Tax gain or loss on the disposition of our units could be different than expected.
If a unitholder sells units, the selling unitholder will recognize a gain or loss equal to the difference between the amount realized and the unitholder’s tax basis in those units. Prior distributions to the selling unitholder in excess of the total net taxable income the unitholder was allocated for a unit, which decreased the unitholder’s tax basis in that unit, will, in effect, become taxable income to the selling unitholder if the unit is sold at a price greater than the unitholder’s tax basis in that unit, even if the price the unitholder receives is less than the unit’s original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to the selling unitholder.
Unitholders may be subject to limitations on their ability to deduct interest expense incurred by us.
In general, we are 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, a deduction for “business interest” is limited to the sum of our business interest income plus 30% of our “adjusted taxable income.” This limitation is applied at the entity level for partnerships. For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income,impaired and, in the case of taxable years beginning before January 1, 2022, any deduction allowablegoodwill, at least annually. Charges to impair our goodwill or our long-lived assets reduce earnings and partners’ capital. Any event that causes a reduction in demand for depreciation, amortization, or depletion. Any interest disallowed at the partnership level may be carried forward and deductedour services could result in future years by a unitholder from his sharereduction of our “excess taxable income,”estimates of future cash flows and growth rates in our business, which is generally equalcould cause us to record an impairment charge to reduce the excessvalue of 30%goodwill. Similarly, any event or change in circumstances that causes the carrying value of our adjusted taxable income over the amount of our deduction for business interest for such future taxable year, subjectlong-lived assets to certain restrictions.
Tax-exempt entities face unique tax issues from owning our units thatno longer be recoverable may result in adverse tax consequences to them.
Investment in our 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 that is engaged in one or more unrelated trades or businesses) 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 inrequire us 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 units.
Non-U.S. unitholders will be subjectrecord an impairment charge to U.S. taxes and withholding with respect to their income and gain from owning our units.
Non-U.S. unitholders are subject to U.S. federal income tax on income effectively connected with a U.S. trade or business (“effectively connected income”). A unitholder’s share of our income, gain, loss and deduction, and any gain from the sale or disposition of our units will generally be considered to be “effectively connected” with a U.S. trade or business and subject to U.S. federal income tax. Additionally, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate.
The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a non-U.S. unitholder’s sale or disposition of units. The IRS has temporarily suspended the application of the withholding requirements on sales of publicly traded interests, including our units, pending promulgation of regulations or other guidance. It is not clear if or when such regulations or other guidances will be issued. Non-U.S. unitholders should consult a tax advisor before investing in our units.
We will treat each purchaser of our common units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affectreduce the value of our common units.long-lived assets.
Because
If we cannot match transferorsdetermine that either our goodwill or our long-lived assets are impaired, the resulting charge will reduce earnings and transfereespartners’ capital.
RISKS INHERENT IN AN INVESTMENT IN US
As a master limited partnership, we do not have the same flexibility that corporations and other types of organizations may have to accumulate cash and prevent illiquidity in the future, which may also limit our growth.
Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our common unitholders of all available cash, after taking into account reserves for commitments and contingencies, including growth and other capital expenditures and operating costs, debt service requirements and payments with respect to our preferred units. We are therefore more likely than those organizations to require issuances of additional debt and equity securities to finance our growth plans, meet unforeseen cash requirements and service our debt and other obligations.
In addition, to the extent we issue additional units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional units may increase the risk that we will adopt depreciationbe unable to maintain our current per unit distribution level and amortization positions that may not conform with all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of our common units or resultand other limited partner interests may decrease in audit adjustmentscorrelation with any reduction in our cash distributions per unit. Accordingly, if we experience a liquidity shortage in the future, we may not be able to the unitholder’s tax returns.issue more equity to recapitalize.
Unitholders will likely be subject to statehave limited voting rights, and local taxes and return filing requirements as a resultour partnership agreement restricts the voting rights of investing incertain unitholders owning 20% or more of any class of our units.
In additionUnlike holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to federal income taxes, unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritanceinfluence management’s decisions regarding our business. Unitholders’ voting rights are further restricted by a provision in our partnership agreement providing that units held by certain persons that own 20% or intangible taxesmore of any class of units then outstanding cannot vote on any matter without the prior approval of our general partner.
We may issue additional equity securities, including equity securities that are imposed by the various jurisdictions in which we do business or own property. Unitholders will likely be requiredsenior to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We may own property or conduct business in other states or foreign countries in the future. It is each unitholder’s responsibility to file all federal, state and local tax returns.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units, each month based uponwhich would dilute our unitholders’ existing ownership interests.
Our partnership agreement allows us to issue an unlimited number of additional equity securities without the ownershipapproval of other unitholders as long as the newly issued equity securities are not senior to, or equally ranked with, our preferred units. With the consent of the holders of a majority of the Series D preferred units, we may issue an unlimited number of units that are senior to our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction amongequally ranked with our common unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The U.S. Treasury Department and the IRS issued final regulations pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis and the regulations do not specifically authorize all aspects of the proration method we have currently adopted. If the IRS were to challenge our proration method,preferred units. However, in certain circumstances, we may be required to changeobtain the allocationapproval of itemsthe holders of a majority of each class of our preferred units before we could issue equity securities that are equally ranked with our preferred units.
Our issuance of additional units or other equity interests 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 amount of cash available for redemption of, or payment of the liquidation preference on, each preferred unit may decrease;
•the ratio of taxable income gain, lossto distributions may increase;
•the relative voting strength of each previously outstanding unit may be diminished; and deduction among our common unitholders.
We have adopted certain valuation methodologies in determining a common unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methods or •the resulting allocations and such a challenge could adversely affect the valuemarket price of our common units.units and preferred units may decline.
In determining
Holders of our Series D preferred units generally have the itemssame voting rights as holders of income, gain, loss and deduction allocable to our common unitholders, we must routinely determineunits and generally vote on an as-converted basis with the fair market value of our respective assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make fair market value estimates using a methodology based on the market valueholders of our common units as a means to measure the fair market valuesingle class. Although holders of our respective assets. The IRSother preferred units also have voting rights, such rights are limited to certain matters and require that such holders vote as a separate class with all other series of our equally ranked securities that may challenge these valuation methodsbe issued and possess similar voting rights. As a result, the voting rights of holders of our preferred units may be significantly diluted, and the resulting allocationsholders of income, gain, losssuch future securities of equal rank may be able to control or significantly influence the outcome of any vote with respect to which the holders of our preferred units are entitled to vote. Our partnership agreement contains limited protections for the holders of our preferred units (other than Series D preferred units) in the event of a transaction, including a merger, sale, lease or conveyance of all or substantially all of our assets or business, which might adversely affect the holders of our preferred units.
Future issuances and deduction.sales of securities that rank equally with our preferred units, or the perception that such issuances and sales could occur, may cause prevailing market prices for our preferred units and our common units to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us. Furthermore, the payment of distributions on any additional units may increase the risk that we will not be able to make distributions at our prior per unit distribution levels. To the extent new units are senior to our common units, their issuance will increase the uncertainty of the payment of distributions on our common units.
A successful IRS challengeIf we do not pay distributions on our preferred units in any distribution period, we would be unable to these methodsdeclare or allocationspay distributions on our common units until all unpaid preferred unit distribution obligations have been paid, and our common unitholders are not entitled to receive distributions for such prior period.
Our preferred units rank senior to our common units with respect to distribution rights and rights upon liquidation. If we do not pay the required distributions on our preferred units, we will be unable to declare or pay distributions on our common units. Additionally, because distributions to our preferred unitholders are cumulative, we will have to pay all unpaid accumulated preferred distributions before we can declare or pay any distributions to our common unitholders. Also, because distributions to our common unitholders are not cumulative, if we do not pay distributions on our common units with respect to any quarter, our common unitholders will not be entitled to receive distributions covering any prior periods. In addition, if we do not pay the required distributions on our Series D preferred units for three consecutive distribution periods, the holders of our Series D preferred units have certain additional rights until such distributions are paid, including the right to convert the Series D preferred units into common units, the right to appoint one director to our board of directors and the right to approve certain subsequent indebtedness, acquisitions or asset sales. The preferences and privileges of our preferred units could adversely affect the amount, character and timing of taxable income or loss being allocated tomarket price for our common unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units, or resultcould make it more difficult for us to sell our common units in audit adjustmentsthe future.
If a court were to determine that a unitholder action constituted control of our business, the unitholders may lose their legal protection from liability and be required to repay distributions wrongfully distributed to them.
Under Delaware law, if a court were to determine that actions of a unitholder constituted participation in the “control” of our business, unitholders would be held liable for our obligations to the same extent as a general partner. In addition, under
Delaware law, the general partner generally has unlimited liability for the obligations of the partnership, such as its debts and environmental liabilities, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner.
Furthermore, under Delaware law, we may not make a distribution to our common unitholders’ tax returns withoutunitholders if the benefitdistribution would cause our liabilities to exceed the fair value of additional deductions.our assets. Liabilities to partners on account of their partnership interests and liabilities that are nonrecourse to the partnership are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that, for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to us for the repayment of the distribution amount. Likewise, upon the winding up of our partnership, in the event that (a) we do not distribute assets in the following order: (1) to creditors in satisfaction of our debts; (2) to partners and former partners in satisfaction of liabilities for distributions owed under our partnership agreement; (3) to partners for the return of their contributions; and finally (4) to the partners in the proportions in which the partners share in distributions and (b) a limited partner knows at the time that the distribution violated Delaware law, then such limited partner will be liable to repay the distribution for a period of three years from the impermissible distribution under applicable Delaware law.
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, the unitholder 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 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, the 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 loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
Treatment of distributions on our Preferred Units as guaranteed payments for the use of capital creates a different tax treatment for the holders of Preferred Units than the holderspurchaser of our common or preferred units becomes a limited partner and such distributions may not be eligibleis liable for the 20% deductionobligations of the transferring limited partner to make contributions to us that are known to such purchaser of common or preferred units at the time it became a limited partner and, for qualified publicly tradedunknown obligations, if the liabilities could be determined from our partnership income.agreement.
The tax treatment of distributions on our Preferred Units is uncertain. We will treat the holders of Preferred Units as partners for tax purposes and will treat distributions on the Preferred Units as guaranteed payments for the use of capital that will generally be taxable to the holders of Preferred Units as ordinary income. Although a holder of Preferred Units could recognize taxable income from the accrual of such a guaranteed payment even in the absence of a contemporaneous distribution, we anticipate accruing and making the guaranteed payment distributions quarterly. Otherwise, the holders of Preferred Units are generallyNYSE does not anticipated to share in our items of income, gain, loss or deduction, nor will we allocate any share of our nonrecourse liabilities to the holders of Preferred Units. If the Preferred Units were treated as indebtedness for tax purposes, rather than as guaranteed payments for the use of capital, distributions likely would be treated as payments of interest by us to the holders of Preferred Units.
The Tax Cuts and Jobs Act allows individuals and other non-corporate owners of interests inrequire a publicly traded limited partnership like us to takecomply with certain of its corporate governance requirements.
We currently list our common units on the NYSE under the symbol “NS” and certain of our preferred units on the NYSE under the symbols “NSprA,” “NSprB” and “NSprC,” respectively. Although our general partner has maintained a deduction equal to 20%majority of their allocable shareindependent directors on its board and all members of “qualifiedits board’s audit committee, compensation committee and nominating/governance & conflicts committee are independent directors, because we are a publicly traded limited partnership, income.” Although we expect that muchthe NYSE does not require us to have a majority of the income we earn is generally eligible for the 20% deduction for qualified publicly traded partnership income, it is uncertain whetherindependent directors on our general partner’s board of directors or to have a guaranteed payment for the usecompensation committee or a nominating committee consisting of capital may constitute an allocableindependent directors. Additionally, any future issuance of additional common or distributive share of such income. As a result, the guaranteed payment for use of capital received by the holders of our Preferred Units maypreferred units or other securities, including to affiliates, will not be eligible for the 20% deduction for qualified publicly traded partnership income.
A holder of Preferred Units will be required to recognize gain or loss on a sale of Preferred Units equal to the difference between the amount realized by such holder and tax basis in the Preferred Units sold. The amount realized generally will equal the sum of the cash and the fair market value of other property such holder receives in exchange for such Preferred Units. Subject to general rules requiring a blended basis among multiple partnership interests, the tax basis of a Preferred Unit will generally be equal to the sum of the cash and the fair market value of other property paid by the holder of Preferred Units to acquire such Preferred Unit. Gain or loss recognized by a holder of Preferred Units on the sale or exchange of a Preferred Unit held for more than one year generally will be taxable as long-term capital gain or loss. Because holders of Preferred Units will generally not be allocated a share of our items of depreciation, depletion or amortization, it is not anticipated that such holders would be required to recharacterize any portion of their gain as ordinary income as a result of the recapture rules.
Investment in the Preferred Units by tax-exempt investors, such as employee benefit plans and IRAs, and non-U.S. persons raises issues unique to them. A non-U.S. holder’s income from guaranteed payments and any gain from the sale or disposition
of our units will generally be considered to be effectively connected income and subject to U.S. federal income tax. Distributions to non-U.S. holders of Preferred Units will be subject to withholding taxes. If the amount of withholding exceedsNYSE’s shareholder approval rules that apply to a corporation. Accordingly, the amount of U.S. federal income tax actually due, non-U.S. holders of Preferred Units may beNYSE does not mandate the same protections for our unitholders as are required for certain corporations that are subject to file U.S. federal income tax returns in order to seek a refund of such excess. The Tax Cuts and Jobs Act imposes a withholding obligation of 10%all of the amount realized upon a non-U.S. unitholder’s sale or disposition of Preferred Units. The IRS has temporarily suspended the application of the withholding requirements on sales of publicly traded interests, including our Preferred Units, pending promulgation of regulations or other guidance. It is not clear if or when such regulations or other guidance will be issued. Additionally, the treatment of guaranteed payments for the use of capital to tax exempt investors is not certain and such payments may be treated as unrelated business taxable income for federal income tax purposes.NYSE corporate governance requirements.
All holders of our Preferred Units are urged to consult a tax advisor with respect to the consequences of owning our Preferred Units.
PROPERTIESResults of Operations
Houston Pipeline Impairment. In the third quarter of 2021, we recorded a non-cash asset impairment charge of $59.2 million related to the southern section of our Houston refined product pipeline. Please refer to Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion.
The following table presents operating highlights for the pipeline segment:
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | |
| | 2022 | | 2021 | | Change |
| (Thousands of Dollars, Except Barrel Data) |
| Pipeline Segment: | | | | | |
| Crude oil pipelines throughput (barrels/day) | 1,319,360 | | | 1,281,568 | | | 37,792 | |
| Refined products and ammonia pipelines throughput (barrels/day) | 579,240 | | | 585,189 | | | (5,949) | |
| Total throughput (barrels/day) | 1,898,600 | | | 1,866,757 | | | 31,843 | |
| | | | | |
| Throughput and other revenues | $ | 828,191 | | | $ | 762,238 | | | $ | 65,953 | |
| Operating expenses | 210,719 | | | 202,481 | | | 8,238 | |
| Depreciation and amortization expense | 178,802 | | | 179,088 | | | (286) | |
| | | | | |
| Impairment loss | — | | | 59,197 | | | (59,197) | |
| Segment operating income | $ | 438,670 | | | $ | 321,472 | | | $ | 117,198 | |
Pipeline segment revenues increased $66.0 million and throughputs increased 31,843 barrels per day for the year ended December 31, 2022, compared to the year ended December 31, 2021. Results for the first quarter of 2021 were negatively affected by Winter Storm Uri, which brought snow and damaging ice and caused widespread power outages in Texas and surrounding states in February 2021, as well as the lingering effects of COVID-19 restrictions. However, by the second quarter of 2021, demand had largely recovered to pre-pandemic levels. Revenues primarily increased due to the following:
•an increase in revenues of $61.6 million and an increase in throughputs of 82,596 barrels per day on our Permian Crude System, mainly due to increased customer production supplying this system and the completion of pipeline expansion projects, as well as the negative impacts on the first quarter of 2021 described above. The increase in revenues included an increase of $14.5 million due to higher commodity prices on PLA volumes sold and a $4.4 million adjustment to deferred revenue in the second quarter of 2022 resulting from higher expected tariff revenue on certain incentive pricing contracts;
•an increase in revenues of $5.7 million and an increase in throughputs of 7,768 barrels per day on our Three Rivers System, mainly due to an increase in demand in the markets served by our Nuevo Laredo and San Antonio pipelines in 2022 and the negative impacts on the first quarter of 2021 described above;
•an increase in revenues of $3.4 million and an increase in throughputs of 2,545 barrels per day on our Valley Pipeline, mainly due to higher demand in the markets served by this pipeline in 2022;
•an increase in revenues of $3.0 million on our Corpus Christi Crude Pipeline System, mainly due to increased volumes on certain of our pipelines in this system, despite lower overall throughputs of 37,808 barrels per day, mainly due to unfavorable market conditions on other pipelines in this system; and
•an increase in revenues of $1.3 million and an increase in throughputs of 1,526 barrels per day on our Houston Pipeline due to a new contract with a customer that began at the end of March 2021.
However, these increases were partially offset by the following:
•a decrease in revenues of $4.1 million and a decrease in throughputs of 4,322 barrels per day on our Ammonia Pipeline, due to scheduled maintenance on our pipeline in the third quarter of 2022 and unfavorable market conditions in 2022;
•a decrease in revenues of $2.6 million on the Ardmore System, mainly due to the expiration of a customer contract at the end of the first quarter of 2021; although throughputs on this system increased 7,055 barrels per day in 2022 due to the negative impacts in the first quarter of 2021 described above, these higher throughputs did not offset the decrease in revenues as more barrels were moved at lower average tariffs in 2022;
•a decrease in revenues of $1.3 million and a decrease in throughputs of 4,471 barrels per day on our East Pipeline, mainly due to the current backwardated market, which led to a decline in PLA volumes sold and the expiration of customer contracts; and
•a decrease in revenues of $0.7 million and a decrease in throughputs of 20,590 barrels per day on our McKee System pipelines, mainly due to operational issues at a customer’s refinery in 2022, including a planned turnaround in the third quarter of 2022, which had an even greater negative impact than the first quarter of 2021 impacts described above.
Operating expenses increased $8.2 million for the year ended December 31, 2022, compared to the year ended December 31, 2021, mainly due to an increase in power costs of $5.7 million, primarily on our Permian Crude System and various refined product pipelines, and an increase in maintenance and regulatory expenses of $1.6 million across various pipelines.
STORAGE SEGMENT
Our principal propertiesstorage segment is comprised of our facilities that provide storage, handling and other services for refined products, crude oil, specialty chemicals, renewable fuels and other liquids. As of December 31, 2022, we owned and operated 29 terminal and storage facilities in the United States and one terminal in Nuevo Laredo, Mexico, with an aggregate storage capacity of 36.4 million barrels. The following table sets forth information about our terminal and storage facilities as of December 31, 2022:
| | | | | | | | | | |
| Facility | | Tank Capacity | | |
| | (Barrels) | | |
| Colorado Springs, CO | | 327,000 | | | |
| Denver, CO | | 110,000 | | | |
| Albuquerque, NM | | 250,000 | | | |
| Rosario, NM | | 167,000 | | | |
| Catoosa, OK | | 359,000 | | | |
| Abernathy, TX | | 161,000 | | | |
| Amarillo, TX | | 269,000 | | | |
| Corpus Christi, TX | | 410,000 | | | |
| Corpus Christi, TX (North Beach) | | 3,962,000 | | | |
| Edinburg, TX | | 345,000 | | | |
| El Paso, TX (a) | | 415,000 | | | |
| Harlingen, TX | | 286,000 | | | |
| Laredo, TX | | 218,000 | | | |
| San Antonio, TX (b) | | 379,000 | | | |
| Southlake, TX | | 569,000 | | | |
| Nuevo Laredo, Mexico | | 268,000 | | | |
| Central West Terminals | | 8,495,000 | | | |
| | | | |
| St. James, LA | | 9,906,000 | | | |
| Houston, TX | | 87,000 | | | |
| Gulf Coast Terminals | | 9,993,000 | | | |
| | | | |
| Los Angeles, CA | | 606,000 | | | |
| Pittsburg, CA | | 398,000 | | | |
| Selby, CA | | 2,672,000 | | | |
| Stockton, CA | | 818,000 | | | |
| Portland, OR | | 1,348,000 | | | |
| Tacoma, WA | | 391,000 | | | |
| Vancouver, WA (b) | | 775,000 | | | |
| West Coast Terminals | | 7,008,000 | | | |
| | | | |
| Benicia, CA | | 3,683,000 | | | |
| Corpus Christi, TX | | 4,030,000 | | | |
| Texas City, TX | | 3,141,000 | | | |
| Refinery Storage Tanks | | 10,854,000 | | | |
| | | | |
| Total | | 36,350,000 | | | |
(a)We own a 67% undivided interest in the El Paso refined product terminal. The tank capacity represents the proportionate share of capacity attributable to our ownership interest.
(b)Location includes two terminal facilities.
Description of Terminal and Storage Facilities
Central West Terminals. Our Central West Terminals include terminals located in Texas, Oklahoma, New Mexico and Colorado, as well as one terminal located in Nuevo Laredo, Mexico, with an aggregate storage capacity of 8.5 million barrels. Most of these terminals are described aboveconnected to our Central West Refined Product Pipelines. Our Corpus Christi North Beach terminal, located at the Port of Corpus Christi in Texas, has 4.0 million barrels of crude oil storage and supports our Corpus Christi Crude Pipeline System that transports crude oil from the Eagle Ford and Permian Basin regions to Corpus Christi for export or refineries owned by third parties. This facility also provides our customers with the flexibility to segregate and deliver crude oil and processed condensate and has access to four docks, including two private docks. We can accommodate Suezmax-class vessels and load crude oil onto marine vessels simultaneously on all four docks.
We refer to our pipelines that transport crude oil from the Eagle Ford and Permian Basin regions to Corpus Christi, together with our Corpus Christi North Beach terminal, as the Corpus Christi Crude System.
Gulf Coast Terminals. Our Gulf Coast Terminals have an aggregate storage capacity of 10.0 million barrels and include our St. James terminal, which is located on the Mississippi River near St. James, Louisiana, and one terminal located in Houston, Texas. Our St. James terminal has a total storage capacity of 9.9 million barrels and is located on almost 900 acres of land, some of which is undeveloped. The majority of the storage tanks and infrastructure are suited for light to medium crude oil, with certain tanks capable of fuel oil or heated crude oil storage. Additionally, the facility has one barge dock and two ship docks, and can accommodate exports up to Aframax-class vessels. Our St. James terminal is connected to (i) offshore pipelines in the Gulf of Mexico, (ii) long-haul pipelines that can receive crude oil from the Eagle Ford, Permian Basin, other domestic shale plays and Canada, and (iii) pipelines connecting to refineries in the Gulf Coast. The St. James terminal also has two unit train rail facilities that are served by the Union Pacific Railroad. Each facility has the capacity to simultaneously off-load 120 railcars, at a minimum, in a 24-hour period.
West Coast Terminals. Our West Coast Terminals include terminals located in California, Oregon and Washington, with an aggregate storage capacity of 7.0 million barrels. The largest of these terminals is our Selby, California terminal, with a total storage capacity of 2.7 million barrels. We have completed several renewable fuel storage projects at our West Coast Terminals over the last several years, and are able to receive and distribute renewable fuels across the West Coast, including renewable diesel, sustainable aviation fuel, ethanol, biodiesel and renewable feedstock. Our West Coast Terminals are connected to supply from various domestic and foreign sources.
Refinery Storage Tanks. We own crude oil storage tanks with an aggregate storage capacity of 10.9 million barrels that are physically integrated with and serve refineries owned by Valero Energy at Corpus Christi and Texas City, Texas and Benicia, California. We lease our refinery storage tanks to Valero Energy in exchange for a fixed fee.
Storage Operations
We generate storage segment revenues through fees for tank storage agreements, under which a customer agrees to pay for a certain amount of storage in a tank over a period of time (storage terminal revenues), and throughput agreements, under which a customer pays a fee per barrel for volumes moved through our terminals (throughput terminal revenues). Our terminals also provide blending, additive injections, handling and filtering services for which we charge additional fees.
Demand for Storage Services
The operations of our refined product terminals depend in large part on the caption “Segments,level of demand for products stored in our terminals in the markets served by those assets. Demand for our terminalling services will generally increase or decrease with demand for refined products, and demand for refined products tends to increase or decrease with the relative strength of the economy. In addition, the forward pricing curve can have an impact on demand. For example, crude oil traders focus less on the current market commodity price than on whether that price is higher or lower than expected future market prices: if the future price for a product is believed to be higher than the current market price, or a “contango market,” traders are more likely to purchase and that informationstore products to sell in the future at the higher price. On the other hand, when the current price of crude oil nears or exceeds the expected future market price, or “backwardation,” traders are no longer incentivized to purchase and store product for future sale. Our storage terminal revenues are somewhat insulated from demand volatility due to contracted rates for storage and minimum volume commitments.
Crude oil delivered to our St. James and Corpus Christi North Beach terminals will generally increase or decrease with crude oil production rates in western Canada and the Bakken, Permian and Eagle Ford shale plays. In addition, the market price relationship between various grades of crude oil impacts the demand for our unit train facilities at our St. James terminal. Prior to the COVID-19 pandemic, North American shale play production had increased exports of crude oil from Texas Gulf Coast ports, including our Corpus Christi North Beach facility, to destinations as close as the U.S. East Coast and as far away as Europe and Asia. Although the negative impact of COVID-19 has been partially mitigated by the low break-even point in the
Permian and Eagle Ford shale plays, our Corpus Christi exports have not returned to pre-pandemic levels due to lower global demand for refined products and crude oil and increased competition in crude oil export markets out of the U.S. Overall, refinery production rates, drilling activity and overall consumer demand in the U.S. rebounded in 2021, bringing demand for most of our terminal and storage facilities back to pre-pandemic levels. However, the detrimental impact of the pandemic, amplified by the Russia-Ukraine conflict, has continued to affect current global demand, resulting in a decline in crude oil exports from our Corpus Christi North Beach facility, and the current volatile and backwardated market has led to customers not renewing expiring contracts, mainly at our St. James terminal.
Demand for renewable diesel, renewable jet fuel, ethanol and other renewable fuels continues to grow in markets served by our West Coast terminals due to new regulations with aggressive carbon emissions reduction goals. As this demand growth is incorporated herein by reference. We believe thatexpected to continue, we have satisfactory titlecompleted, and continue to develop, renewable fuel storage projects at our West Coast terminals to meet this demand.
Customers
We provide storage and terminalling services for crude oil, refined products and other products to many of the world’s largest producers of crude oil, integrated oil companies, chemical companies, oil traders and refiners. In addition, our blending capabilities in our storage assets have attracted customers who have leased capacity primarily for blending purposes. The two largest customers of our storage segment accounted for approximately 33% and 14%, respectively, of the total revenues of the segment for the year ended December 31, 2022. No other customer accounted for a significant portion of the total revenues of the storage segment.
Competition and Other Business Considerations
Many major energy and chemical companies own extensive terminal storage facilities. Although such terminals often have the same capabilities as terminals owned by independent operators, they generally do not provide terminalling services to third parties. In many instances, even major energy and chemical companies that have storage and terminalling facilities are also significant customers of independent terminal operators, especially terminals located in cost-effective locations near key transportation links, such as deep-water ports. Major energy and chemical companies also need independent terminal storage when their proprietary storage facilities are inadequate, due to size constraints, the nature of the stored material or specialized handling requirements.
Independent terminal owners generally compete on the basis of the location and versatility of terminals, service and price. A favorably located terminal will have access to various cost-effective transportation modes both to and from the terminal. Transportation modes typically include waterways, railroads, roadways and pipelines.
Terminal versatility is a function of the operator’s ability to offer complex handling requirements for diverse products. The services typically provided by the terminal include, among other things, the safe storage of the product at specified temperature, moisture and other conditions, as well as receipt at and delivery from the terminal, all of our properties. Although titlewhich must comply with applicable environmental regulations. A terminal operator’s ability to these propertiesobtain attractive pricing is subjectoften dependent on the quality, versatility and reputation of the facilities owned by the operator. Operators with versatile storage capabilities typically require less modification prior to encumbrancesusage, ultimately making the storage cost to the customer more attractive. On the West Coast, regulatory priorities continue to increase demand for renewable fuels in some cases, such as customary interests generally retained in connection with the acquisition of real property, liens for current taxes and other burdens and easements, and restrictions or other encumbrances, including those related to environmental liabilities associated with historical operations, to which the underlying properties were subjectregion, while at the same time, of acquisitionobtaining permits for greenfield projects remains difficult, which both add more value to our existing assets.
Our crude oil refinery storage tanks are physically integrated with and serve refineries owned by us or our predecessors,Valero Energy, and we believe that nonehave entered into various agreements with Valero Energy governing the use of these burdens will materially detract from the value of these properties or from our interest in these properties or will materially interfere with their use in the operation of our business. In addition,tanks. As a result, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private partieswill not face significant competition for usour services provided to operate our business in all material respects as described in this report. We perform scheduled maintenance on allthose refineries.
Results of our pipelines, terminals, crude oil tanks andOperations
Dispositions. In the first quarter of 2022, we recognized a non-cash pre-tax impairment loss of $46.1 million related equipment and make repairs and replacements when necessary or appropriate. We believe that our pipelines, terminals, crude oil tanks and related equipment have been constructed and are maintained in all material respects in accordance with applicable federal, state and local laws and the regulations and standards prescribed by the American Petroleum Institute, the DOT and accepted industry practice.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
We are named as a defendant in litigation and are a party to other claims and legal proceedings relating to our normalPoint Tupper terminal facility, which was sold on April 29, 2022 (the Point Tupper Terminal Disposition). In the third quarter of 2021, we recorded non-cash asset and goodwill impairment losses of $95.7 million and $34.1 million, respectively, related to our Eastern U.S. Terminal Operations, which were sold on October 8, 2021 (the Eastern U.S. Terminals Disposition). Please refer to Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of these dispositions.
Selby Terminal Fire. We recognized a gain from business operations, including regulatoryinterruption insurance of $4.0 million for the year ended December 31, 2021, which is included in “Operating expenses” in the consolidated statements of income (loss) and environmental matters. Duerelates to the inherent uncertaintya fire in October 2019 at our terminal facility in Selby, California.
We are insured against various business risks to the extent we believe is prudent; however, we cannot assure you that the nature and amount of such insurance will be adequate, in every case, to protect us against liabilities arising from future legal proceedings as a result of our ordinary business activity.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
| |
ITEM 5. | MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
Common Unit Distributions
Our common units are listed and traded on the New York Stock Exchange under the symbol “NS.” At the close of business on February 8, 2018, we had 464 holders of record of our common units. The following table presents operating highlights for the highstorage segment:
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | |
| | 2022 | | 2021 | | Change |
| (Thousands of Dollars, Except Barrel Data) |
| Storage Segment: | | | | | |
| Throughput (barrels/day) (a) | 480,129 | | | 516,094 | | | (35,965) | |
| | | | | |
| Throughput terminal revenues | $ | 110,591 | | | $ | 122,331 | | | $ | (11,740) | |
| Storage terminal revenues | 223,958 | | | 305,337 | | | (81,379) | |
| Total revenues | 334,549 | | | 427,668 | | | (93,119) | |
| Operating expenses | 154,270 | | | 185,597 | | | (31,327) | |
| Depreciation and amortization expense | 73,076 | | | 87,500 | | | (14,424) | |
| Goodwill impairment loss | — | | | 34,060 | | | (34,060) | |
| Other impairment losses | 46,122 | | | 95,711 | | | (49,589) | |
| Segment operating income | $ | 61,081 | | | $ | 24,800 | | | $ | 36,281 | |
(a)Prior period throughputs for our Corpus Christi North Beach terminal were restated consistent with current period presentation.
Throughput terminal revenues decreased $11.7 million and lowthroughputs decreased 35,965 barrels per day for the year ended December 31, 2022, compared to the year ended December 31, 2021, mainly at our Corpus Christi North Beach terminal due to a decline in export demand and changes to a customer contract.
Storage terminal revenues decreased $81.4 million for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily due to:
•an aggregate decrease in revenues of $73.6 million due to the Eastern U.S. Terminals Disposition in October 2021 and the Point Tupper Terminal Disposition in April 2022; and
•a decrease in revenues of $21.1 million at our St. James terminal due to customers not renewing expiring contracts in the current backwardated market.
These decreases were partially offset by the following:
•an increase in revenues of $10.1 million at our West Coast Terminals, mainly at our Portland and Stockton terminals, primarily due to new contracts and higher throughput and handling fees;
•an increase in revenues of $1.6 million due to rate escalations on our refinery storage tanks; and
•an increase in revenues of $1.4 million at our Central West Terminals, mainly due to rate escalations and higher throughput and handling fees.
Operating expenses decreased $31.3 million for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily due to an aggregate decrease in operating expenses of $46.6 million due to the Eastern U.S. Terminals Disposition in October 2021 and the Point Tupper Terminal Disposition in April 2022. This decrease was partially offset by the following:
•increases in reimbursable expenses of $4.1 million, mainly at our St. James terminal;
•a $4.0 million recovery in the first quarter of 2021 for business interruption insurance related to the 2019 Selby terminal fire; and
•increases in compensation expense of $1.7 million, ad valorem taxes of $1.2 million, additive and chemical expenses of $1.1 million and maintenance and regulatory expenses of $1.0 million, across various terminals.
Depreciation and amortization expense decreased $14.4 million for the year ended December 31, 2022, compared to the year ended December 31, 2021, mainly due to the Eastern U.S. Terminals Disposition in October 2021 and the Point Tupper Terminal Disposition in April 2022.
FUELS MARKETING SEGMENT
The fuels marketing segment mainly includes our bunkering operations in the Gulf Coast, as well as certain of our blending operations associated with our Central East System. The results of operations for the fuels marketing segment depend largely on the margin between our costs and the sales prices of the products we market. Therefore, the results of operations for this segment are more sensitive to changes in commodity prices compared to the operations of the pipeline and storage segments. We enter into derivative contracts to attempt to mitigate the effects of commodity price fluctuations. The financial impacts of the derivative financial instruments associated with commodity price risk were not material for any periods presented. Fluctuations in global demand for crude oil, which was caused by many economic factors outside of our control, has caused volatility in commodity prices and volumes in 2022 and 2021, for our common units duringblending operations and bunker fuel sales.
Customers for bunker fuel sales are mainly ship owners, including cruise line companies, marketers and traders. In the periods presented (composite transactions as reported bysale of bunker fuel, we compete with ports offering bunker fuels that are along the New York Stock Exchange) and the amount, record date and payment dateroute of travel of the quarterlyvessel. One of our customers, a marketer of petroleum products, was the largest customer of our fuels marketing segment and accounted for approximately 16% of the total segment revenues for the year ended December 31, 2022. No other customer accounted for a significant portion of the total revenues of the fuels marketing segment for the year ended December 31, 2022.
Results of Operations
The following table presents operating highlights for the fuels marketing segment:
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | |
| | 2022 | | 2021 | | Change |
| (Thousands of Dollars) |
| Fuels Marketing Segment: | | | | | |
| Product sales | $ | 520,486 | | | $ | 428,608 | | | $ | 91,878 | |
| Cost of goods | 484,477 | | | 417,000 | | | 67,477 | |
| Gross margin | 36,009 | | | 11,608 | | | 24,401 | |
| Operating expenses | 2,473 | | | 427 | | | 2,046 | |
| | | | | |
| | | | | |
| Segment operating income | $ | 33,536 | | | $ | 11,181 | | | $ | 22,355 | |
| | | | | |
Segment operating income increased $22.4 million for the year ended December 31, 2022, compared to the year ended December 31, 2021, mainly due to an increase of $12.4 million in gross margins from our bunkering operations and an increase of $11.4 million in gross margins from our blending and other product sales, both driven by higher fuel prices on product sales.
Operating expenses increased $2.0 million for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily due to a settlement of $1.7 million we received in the first quarter of 2021 for a credit loss that was previously written off.
LIQUIDITY AND CAPITAL RESOURCES
The following sections are included in Liquidity and Capital Resources:
•Overview
•Cash Flows
•Sources of Liquidity
•Material Cash Requirements
OVERVIEW
Our primary cash requirements are for distributions onto our common units with respect to such periods:
|
| | | | | | | | | | | | | | | |
| | Price Range per Common Unit | | Cash Distributions |
| | High | | Low | | Amount Per Common Unit | | Record Date | | Payment Date |
| Year 2017 | | | | | | | | | |
| 4th Quarter (a) | $ | 41.00 |
| | $ | 26.21 |
| | $ | 1.095 |
| | February 8, 2018 | | February 13, 2018 |
| 3rd Quarter | $ | 47.99 |
| | $ | 37.30 |
| | $ | 1.095 |
| | November 9, 2017 | | November 14, 2017 |
| 2nd Quarter | $ | 52.68 |
| | $ | 42.40 |
| | $ | 1.095 |
| | August 7, 2017 | | August 11, 2017 |
| 1st Quarter | $ | 55.64 |
| | $ | 49.09 |
| | $ | 1.095 |
| | May 8, 2017 | | May 12, 2017 |
| Year 2016 | | | | | | | | | |
| 4th Quarter | $ | 50.87 |
| | $ | 43.41 |
| | $ | 1.095 |
| | February 8, 2017 | | February 13, 2017 |
| 3rd Quarter | $ | 50.72 |
| | $ | 43.91 |
| | $ | 1.095 |
| | November 8, 2016 | | November 14, 2016 |
| 2nd Quarter | $ | 53.47 |
| | $ | 37.90 |
| | $ | 1.095 |
| | August 9, 2016 | | August 12, 2016 |
| 1st Quarter | $ | 42.87 |
| | $ | 25.65 |
| | $ | 1.095 |
| | May 9, 2016 | | May 13, 2016 |
| |
(a) | The distribution was announced on January 29, 2018. |
partners, debt service, capital expenditures and operating expenses. Our partnership agreement requires that we distribute all “Available Cash” to our common limited partners and general partner each quarter, and this termquarter. “Available Cash” is defined in the partnership agreement generally as cash on hand at the end of the quarter, plus certain permitted borrowings made subsequent to the end of the quarter, less cash reserves determined by our board of directors. See Itemdirectors, subject to requirements for distributions for our preferred units. We may maintain our distribution level with other sources of Available Cash, as provided in our partnership agreement, including borrowings under our revolving credit agreement and proceeds from the sales of assets.
The following chart shows our sources and uses of cash for 2022 and 2021:
In 2022 and 2021, we were able to fund all of our expenses, distribution requirements and capital expenditures using internally generated cash flows. We reduced our leverage to position ourselves to repurchase 6,900,000 of our Series D Cumulative Convertible Preferred Units in November 2022, representing approximately one-third of the outstanding units, using borrowings under our $1.0 billion unsecured revolving credit agreement.
For the full-year 2023, we expect to fund all of our expenses, distribution requirements and capital expenditures using internally generated cash flows.
Our Series D Cumulative Convertible Preferred Units (Series D Preferred Units) become redeemable, at our option, beginning in 2023, which coincides with an increase in the distribution rate of those units. Beginning in 2028, the holders of the Series D Preferred Units have the option to require us to redeem their units, and we have taken steps to position ourselves to repurchase or redeem the Series D Preferred Units in advance of the possible mandatory redemption. We plan to redeem the remaining 16,346,650 of Series D Preferred Units outstanding in 2023 and 2024, which is several years ahead of the holders’ redemption option in 2028. We will also continue to evaluate other sources of liquidity to facilitate the planned redemption of the remaining Series D Preferred Units in 2023 and 2024.
We have no long-term debt maturities until 2025, and we expect to be able to access debt capital markets to refinance those maturities.
A discussion of our cash flows and other changes in financial position for 2020 can be found in Items 1., 2. and 7. “Management’s“Business, Properties and Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report on Form 10-K for further information regardingthe year ended December 31, 2021 filed with the SEC on February 24, 2022.
CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2022 AND 2021
The following table summarizes our distributions.cash flows from operating, investing and financing activities (please refer to our Consolidated Statements of Cash Flows in Item 8. “Financial Statements and Supplementary Data”).
| | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2022 | | 2021 | | |
| (Thousands of Dollars) |
| Net cash provided by (used in): | | | | | |
| Operating activities | $ | 527,549 | | | $ | 501,478 | | | |
| Investing activities | (84,365) | | | 75,978 | | | |
| Financing activities | (434,953) | | | (725,579) | | | |
| Effect of foreign exchange rate changes on cash | 707 | | | 136 | | | |
| Net increase (decrease) in cash, cash equivalents and restricted cash | $ | 8,938 | | | $ | (147,987) | | | |
For the years ended December 31, 2022 and 2021, net cash provided by operating activities exceeded our distributions to unitholders, reliability capital expenditures and strategic capital expenditures.
Net cash provided by operating activities increased by $26.1 million for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily due to higher net income and changes in working capital. Generally, working capital requirements are affected by our accounts receivable, accounts payable and accrued interest payable balances, which vary depending on the timing of payments. Our working capital decreased by $0.7 million for the year ended December 31, 2022, compared to an increase of $14.1 million for the year ended December 31, 2021, mainly due to changes in the timing of payments related to accrued interest payable due to the repayment of senior notes in February and November 2021. Cash flows from operating activities for the years ended December 31, 2022 and 2021 include $1.3 million and $19.1 million, respectively, of insurance proceeds related to cleanup costs and business interruption from the 2019 Selby terminal fire.
For the year ended December 31, 2022, we recorded net cash used in investing activities of $84.4 million, compared to net cash provided by investing activities of $76.0 million for the year ended December 31, 2021, primarily due to lower proceeds from asset sales of $187.2 million, partially offset by a decrease in capital expenditures of $40.5 million. Cash flows from investing activities also include insurance proceeds related to the 2019 Selby terminal fire of $9.8 million for the year ended December 31, 2022, compared to $9.4 million for the year ended December 31, 2021.
Net cash used in financing activities decreased by $290.6 million for the year ended December 31, 2022, compared to the year ended December 31, 2021, mainly due to net debt borrowings of $106.6 million for the year ended December 31, 2022, compared to net debt repayments of $412.7 million for the year ended December 31, 2021, mainly due to the timing of asset sales as proceeds were used to repay debt borrowings, and the repurchase of 6,900,000 of our Series D Preferred Units in November 2022.
SOURCES OF LIQUIDITY
Revolving Credit Agreement
As of December 31, 2022, NuStar Logistics’ $1.0 billion unsecured revolving credit agreement (the Revolving Credit Agreement) had $775.3 million available for borrowing and $220.0 million of borrowings outstanding. Letters of credit issued under the Revolving Credit Agreement totaled $4.7 million as of December 31, 2022. Letters of credit limit the amount we can borrow under the Revolving Credit Agreement. Obligations under the Revolving Credit Agreement are guaranteed by NuStar Energy and NuPOP.
The Revolving Credit Agreement is subject to maximum consolidated debt coverage ratio and minimum consolidated interest coverage ratio requirements, which may limit the amount we can borrow to an amount less than the total amount available for borrowing. For the rolling period of four quarters ending December 31, 2022, the maximum allowed consolidated debt coverage ratio (as defined in the Revolving Credit Agreement) could not exceed 5.00-to-1.00 and the minimum consolidated interest coverage ratio (as defined in the Revolving Credit Agreement) must not be less than 1.75-to-1.00. The Revolving Credit Agreement also contains customary restrictive covenants, such as limitations on indebtedness, liens, mergers, asset transfers and
certain investing activities. As of December 31, 2022, our consolidated debt coverage ratio was 3.98x and our consolidated interest coverage ratio was 2.17x.
On February 7, 2018, January 28, 2022, we amended and restated the Revolving Credit Agreement primarily to: (i) extend the maturity date from October 27, 2023 to April 27, 2025; (ii) increase the maximum amount of letters of credit capable of being issued from $400.0 million to $500.0 million; (iii) replace London Interbank Offering Rate, or LIBOR, benchmark provisions with customary secured overnight financing rate, or SOFR, benchmark provisions; (iv) remove the 0.50x increase permitted in our consolidated debt coverage ratio for certain rolling periods in which an acquisition for aggregate net consideration of at least $50.0 million occurs; and (v) add baskets and exceptions to certain negative covenants. Following the amendment, borrowings under the Revolving Credit Agreement bear interest, at our option, at an alternate base rate or a SOFR rate, each as defined in the Revolving Credit Agreement.
The interest rate on the Revolving Credit Agreement and certain fees under the Receivables Financing Agreement, defined below, are the only debt arrangements that are subject to adjustment if our debt rating is downgraded (or upgraded) by certain credit rating agencies. The following table reflects the current ratings and outlook that have been assigned to our debt:
| | | | | | | | | | | | | | | | | |
| Fitch Ratings | | Moody’s Investor Service Inc. | | S&P Global Ratings |
| Ratings | BB- | | Ba3 | | BB- |
| Outlook | Stable | | Stable | | Stable |
Receivables Financing Agreement
NuStar Energy Riverwalk Logistics, L.P., NuStar GP, LLC, Merger Sub, Riverwalk Holdings, LLC and NuStar GP Holdings entered into the Merger Agreement pursuant to which Merger Sub will merge withFinance LLC (NuStar Finance), a special purpose entity and into NuStar GP Holdings with NuStar GP Holdings being the surviving entity, such thatwholly owned subsidiary of NuStar Energy, will be the sole memberare parties to a $100.0 million receivables financing agreement with a third-party lender (the Receivables Financing Agreement) and agreements with certain of NuStar GP Holdings followingEnergy’s wholly owned subsidiaries (together with the Merger. Additionally,Receivables Financing Agreement, the Securitization Program). The amount available for borrowing under the Receivables Financing Agreement is based on February 8, 2018, we announced thatthe availability of eligible receivables and other customary factors and conditions. The Securitization Program contains various customary affirmative and negative covenants and default, indemnification and termination provisions, and the Receivables Financing Agreement provides for acceleration of amounts owed upon the occurrence of certain specified events.
On January 28, 2022, the Receivables Financing Agreement was amended primarily to: (i) extend the scheduled termination date from September 20, 2023 to January 31, 2025; (ii) reduce the floor rate in the calculation of our management anticipates recommendingborrowing rates; and (iii) replace provisions related to the boardLIBOR rate of directorsinterest with references to SOFR rates of interest. Following the amendment, borrowings under the Receivables Financing Agreement bear interest, at NuStar GP, LLC, andFinance’s option, at a base rate or a SOFR rate, each as defined in the board of directors expects to adopt, a reset of our quarterly distribution per common unit to $0.60 ($2.40 on an annualized basis), starting with the first-quarter distribution payable in May 2018. Receivables Financing Agreement.
Please refer to Note 2812 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for furthera discussion of our debt agreements.
Asset Sales
We utilized the Merger.proceeds from the Point Tupper Terminal Disposition in 2022 and the Eastern U.S. Terminals Disposition in 2021 to reduce debt and improve our debt metrics.
General Partner DistributionsMATERIAL CASH REQUIREMENTS
Capital Expenditures
Our general partner is entitledoperations require significant investments to distributionsmaintain, upgrade or enhance the operating capacity of our existing assets. Our capital expenditures consist of:
•strategic capital expenditures, such as shown below:those to expand or upgrade the operating capacity, increase efficiency or increase the earnings potential of existing assets, whether through construction or acquisition, as well as certain capital expenditures related to support functions; and
•reliability capital expenditures, such as those required to maintain the current operating capacity of existing assets or extend their useful lives, as well as those required to maintain equipment reliability and safety.
|
| | | | |
| | | Percentage of Distribution |
| Quarterly Distribution Amount per Common Unit | | Common Unitholders | | General Partner Including Incentive Distributions |
| Up to $0.60 | | 98% | | 2% |
| Above $0.60 up to $0.66 | | 90% | | 10% |
| Above $0.66 | | 75% | | 25% |
| | | | | | | | | | | | | | | | | |
| Strategic Capital Expenditures | | Reliability Capital Expenditures | | Total |
| (Thousands of Dollars) |
| For the year ended December 31: | | | | | |
| 2022 | $ | 107,855 | | | $ | 32,775 | | | $ | 140,630 | |
| 2021 | $ | 140,867 | | | $ | 40,266 | | | $ | 181,133 | |
| | | | | |
| Expected for the year ended December 31, 2023 | $ 130,000 - 150,000 | | $ 25,000 - 35,000 | | |
Our general partner’s incentive distributions totaled $45.7 million and $43.4 million
Strategic capital expenditures for the years ended December 31, 20172022 and 2016, respectively. The general partner’s shareDecember 31, 2021 mainly consisted of expansion projects on our distributionsPermian Crude System and Central West Refined Products Pipelines, as well as biofuel and other terminal projects at our West Coast Terminals. Reliability capital expenditures primarily related to maintenance upgrade projects at our terminals.
We expect our strategic capital expenditures for the yearsyear ended December 31, 20172023 to include spending of approximately $60.0 million on expansion projects to accommodate production growth in the Permian Basin and 2016 was 11.9%approximately $25.0 million on projects to expand our renewable fuels network on the West Coast. We continue to evaluate our capital budget and 13.0%, respectively, due to the impact of the incentive distributions. In the second quarter of 2017,internal growth projects can be accelerated or scaled back depending on market conditions or customer demand. Therefore, our general partner amended and restated our partnership agreement in connection with the issuance of the Series B Preferred Units described below and our acquisition of Navigator Energy Services, LLC to waive up to an aggregate $22.0 million of the quarterly incentive distributions to our general partneractual capital expenditures for any NS common units issued2023 may increase or decrease from the date of the acquisition agreement (other than those attributable to NS common units issued under any equity compensation plan) for ten consecutive quarters, starting with the distributions for the second quarter of 2017.expected amounts noted above.
Pursuant to the Merger Agreement and at the effective time of the Merger, our partnership agreement will be amended and restated to, among other things, cancel the incentive distribution rights held by our general partner and convert the 2% general partner interest in NuStar Energy held by our general partner into a non-economic management interest. As a result, after the Merger, our general partner will no longer receive incentive distributions or quarterly cash distributions related to its ownership interest, from us. Please refer to Note 28 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the Merger.
Preferred Unit Distributions
The following table provides the terms related to distributions for our Series A, Series B and Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (collectively, the Preferred Units):
|
| | | | | | | | | | |
| Units | | Fixed Distribution Rate per Annum (as a Percentage of the $25.00 Liquidation Preference per Unit) | | Fixed Distribution Rate per Unit per Annum | | Optional Redemption Date/Date at Which Distribution Rate Becomes Floating | | Floating Annual Rate (as a Percentage of the $25.00 Liquidation Preference per Unit) |
| Series A Preferred Units | | 8.50% | | $ | 2.125 |
| | December 15, 2021 | | Three-month LIBOR plus 6.766% |
| Series B Preferred Units | | 7.625% | | $ | 1.90625 |
| | June 15, 2022 | | Three-month LIBOR plus 5.643% |
| Series C Preferred Units | | 9.00% | | $ | 2.25 |
| | December 15, 2022 | | Three-month LIBOR plus 6.88% |
Units. Distributions on the Preferred Unitsour preferred units are payable out of any legally available funds, accrue and are cumulative from the original issuance dates, and are payable on the 15th day (or the next business day) of each of March, June, September and December of each year to holders of record on the first business day of each payment month. The Preferred Units rank equalPlease see Notes 17 and 18 of the Notes to each other and senior to all of our other classes of equity securities with respect to distribution rights and rights upon liquidation.
The following table summarizes information related to our quarterly cash distributions on our Preferred Units: |
| | | | | | | | |
| Period | | Cash Distributions Per Unit | | Record Date | | Payment Date |
| | | | | | | |
| Series A Preferred Units: | | | | | | |
| December 15, 2017 - March 14, 2018 (a) | | $ | 0.53125 |
| | March 1, 2018 | | March 15, 2018 |
| September 15, 2017 - December 14, 2017 | | $ | 0.53125 |
| | December 1, 2017 | | December 15, 2017 |
| June 15, 2017 - September 14, 2017 | | $ | 0.53125 |
| | September 1, 2017 | | September 15, 2017 |
| March 15, 2017 - June 14, 2017 | | $ | 0.53125 |
| | June 1, 2017 | | June 15, 2017 |
| November 25, 2016 - March 14, 2017 | | $ | 0.64930556 |
| | March 1, 2017 | | March 15, 2017 |
| | | | | | | |
| Series B Preferred Units: | | | | | | |
| December 15, 2017 - March 14, 2018 (a) | | $ | 0.47657 |
| | March 1, 2018 | | March 15, 2018 |
| September 15, 2017 - December 14, 2017 | | $ | 0.47657 |
| | December 1, 2017 | | December 15, 2017 |
| April 28, 2017 - September 14, 2017 | | $ | 0.725434028 |
| | September 1, 2017 | | September 15, 2017 |
| | | | | | | |
| Series C Preferred Units: | | | | | | |
| November 30, 2017 - March 14, 2018 (a) | | $ | 0.65625 |
| | March 1, 2018 | | March 15, 2018 |
| |
(a) | The distribution was announced on January 29, 2018. |
ITEM 6. SELECTED FINANCIAL DATA
The following table contains selected financial data derived from our audited financial statements:
|
| | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | | 2014 | | 2013 (a) |
| | (Thousands of Dollars, Except Per Unit Data) |
| Statement of Income Data: | | | | | | | | | |
| Revenues (b) | $ | 1,814,019 |
| | $ | 1,756,682 |
| | $ | 2,084,040 |
| | $ | 3,075,118 |
| | $ | 3,463,732 |
|
| Operating income (loss) | $ | 336,278 |
| | $ | 359,109 |
| | $ | 390,704 |
| | $ | 346,901 |
| | $ | (19,121 | ) |
| Income (loss) from continuing operations (c) | $ | 147,964 |
| | $ | 150,003 |
| | $ | 305,946 |
| | $ | 214,169 |
| | $ | (185,509 | ) |
Income (loss) from continuing operations per common unit (c) | $ | 0.64 |
| | $ | 1.27 |
| | $ | 3.29 |
| | $ | 2.14 |
| | $ | (2.89 | ) |
Cash distributions per unit applicable to common limited partners | $ | 4.38 |
| | $ | 4.38 |
| | $ | 4.38 |
| | $ | 4.38 |
| | $ | 4.38 |
|
| | | | | | | | | | |
| | December 31, |
| | 2017 (d) | | 2016 | | 2015 | | 2014 | | 2013 |
| | (Thousands of Dollars) |
| Balance Sheet Data: | | | | | | | | | |
| Property, plant and equipment, net | $ | 4,300,933 |
| | $ | 3,722,283 |
| | $ | 3,683,571 |
| | $ | 3,460,732 |
| | $ | 3,310,653 |
|
| Total assets | $ | 6,535,233 |
| | $ | 5,030,545 |
| | $ | 5,125,525 |
| | $ | 4,918,796 |
| | $ | 5,032,186 |
|
| Long-term debt, less current portion | $ | 3,263,069 |
| | $ | 3,014,364 |
| | $ | 3,055,612 |
| | $ | 2,749,452 |
| | $ | 2,655,553 |
|
| Total partners’ equity | $ | 2,480,089 |
| | $ | 1,611,617 |
| | $ | 1,609,844 |
| | $ | 1,716,210 |
| | $ | 1,903,794 |
|
| |
(a) | The losses for the year ended December 31, 2013 are mainly due to goodwill impairment charges. |
| |
(b) | DeclinesConsolidated Financial Statements in revenues from 2013 through 2017 are mainly from a reduction in marketing activity and lower commodity prices. We ceased marketing crude oil in the second quarter of 2017 and exited our heavy fuels trading operations in the third quarter of 2017. |
| |
(c) | Includes the impact of a $58.7 million non-cash impairment charge on the Axeon term loan in 2016 and a $56.3 million non-cash gain associated with the Linden terminal acquisition in 2015. |
| |
(d) | The significant increases in balance sheet data are primarily due to our acquisition of Navigator Energy Services, LLC for approximately $1.5 billion in May 2017.
|
| |
ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
The following review of our results of operations and financial condition should be read in conjunction with “Cautionary Statement Regarding Forward-Looking Information,” Items 1., 1A. and 2. “Business, Risk Factors and Properties” and Item 8. “Financial Statements and Supplementary Data” for additional information.
The distribution rates on the outstanding Series D Preferred Units are as follows: (i) 9.75% per annum ($0.619 per unit per distribution period) for the first two years (beginning with the September 17, 2018 distribution); (ii) 10.75% per annum ($0.682 per unit per distribution period) for years three through five; and (iii) the greater of 13.75% per annum ($0.872 per unit per distribution period) or the distribution per common unit thereafter. The number of Series D Preferred Units outstanding as of December 31, 2022 and 2021 totaled 16,346,650 and 23,246,650, respectively, as we repurchased an aggregate 6,900,000 of our Series D Preferred Units in November 2022. While the Series D Preferred Units are outstanding, the Partnership will be prohibited from paying distributions on any junior securities, including the common units, unless full cumulative distributions on the Series D Preferred Units (and any parity securities) have been, or contemporaneously are being, paid or set aside for payment through the most recent Series D Preferred Unit distribution payment date. Any Series D Preferred Unit distributions in excess of $0.635 may be paid, in the Partnership’s sole discretion, in additional Series D Preferred Units, with the remainder paid in cash. If we fail to pay in full any Series D Preferred Unit distribution amount, then, until we pay such distributions in full, the applicable distribution rate for those distribution periods shall be increased by $0.048 per Series D Preferred Unit. We would also be subject to other requirements.
Distribution information on our Series D Preferred Units is as follows:
| | | | | | | | | | | | | | |
| Distribution Period | | Distribution Rate per Unit | | Total Distribution |
| | | | (Thousands of Dollars) |
| December 15, 2022 - March 14, 2023 | | $ | 0.682 | | | $ | 11,148 | |
| September 15, 2022 - December 14, 2022 | | $ | 0.682 | | | $ | 14,337 | |
| June 15, 2022 - September 14, 2022 | | $ | 0.682 | | | $ | 15,854 | |
| March 15, 2022 - June 14, 2022 | | $ | 0.682 | | | $ | 15,854 | |
| December 15, 2021 - March 14, 2022 | | $ | 0.682 | | | $ | 15,854 | |
Information on our 8.50% Series A, 7.625% Series B and 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (collectively, the Series A, B and C Preferred Units) is shown below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Units | | | | | | | | | | Units Issued and Outstanding as of December 31, 2022 | | Optional Redemption Date/Date When Distribution Rate Became Floating | | Floating Annual Rate (as a Percentage of the $25.00 Liquidation Preference Per Unit) |
| Series A Preferred Units | | | | | | | | | | 9,060,000 | | December 15, 2021 | | Three-month LIBOR plus 6.766% |
| Series B Preferred Units | | | | | | | | | | 15,400,000 | | June 15, 2022 | | Three-month LIBOR plus 5.643% |
| Series C Preferred Units | | | | | | | | | | 6,900,000 | | December 15, 2022 | | Three-month LIBOR plus 6.88% |
Distribution information on our Series A, B and C Preferred Units is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Series A Preferred Units | | Series B Preferred Units | | Series C Preferred Units |
| Distribution Period | | Distribution Rate per Unit | | Total Distribution | | Distribution Rate per Unit | | Total Distribution | | Distribution Rate per Unit | | Total Distribution |
| | | | (Thousands of Dollars) | | | | (Thousands of Dollars) | | | | (Thousands of Dollars) |
| December 15, 2022 - March 14, 2023 | | $ | 0.71889 | | | $ | 6,513 | | | $ | 0.64871 | | | $ | 9,990 | | | $ | 0.72602 | | | $ | 5,010 | |
| September 15, 2022 - December 14, 2022 | | $ | 0.64059 | | | $ | 5,804 | | | $ | 0.57040 | | | $ | 8,784 | | | $ | 0.56250 | | | $ | 3,881 | |
| June 15, 2022 - September 14, 2022 | | $ | 0.54808 | | | $ | 4,966 | | | $ | 0.47789 | | | $ | 7,360 | | | $ | 0.56250 | | | $ | 3,881 | |
| March 15, 2022 - June 14, 2022 | | $ | 0.47817 | | | $ | 4,332 | | | $ | 0.47657 | | | $ | 7,339 | | | $ | 0.56250 | | | $ | 3,881 | |
| December 15, 2021 - March 14, 2022 | | $ | 0.43606 | | | $ | 3,951 | | | $ | 0.47657 | | | $ | 7,339 | | | $ | 0.56250 | | | $ | 3,881 | |
In January 2023, our board of directors declared quarterly distributions with respect to the Series A, B and C Preferred Units and the Series D Preferred Units to be paid on March 15, 2023.
Common Units. Distribution payments are made to our common limited partners within 45 days after the end of each quarter as of a record date that is set after the end of each quarter. The following table summarizes information about cash distributions to our common limited partners applicable to the period in which the distributions were earned:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Cash Distributions
Per Unit | | Total Cash Distributions | | Record Date | | Payment Date |
| | | | (Thousands of Dollars) | | | | |
| Quarter ended: | | | | | | | | |
| December 31, 2022 | | $ | 0.40 | | | $ | 44,328 | | | February 8, 2023 | | February 14, 2023 |
| September 30, 2022 | | 0.40 | | | 44,125 | | | November 7, 2022 | | November 14, 2022 |
| June 30, 2022 | | 0.40 | | | 44,128 | | | August 8, 2022 | | August 12, 2022 |
| March 31, 2022 | | 0.40 | | | 44,165 | | | May 9, 2022 | | May 13, 2022 |
| Year ended December 31, 2022 | | $ | 1.60 | | | $ | 176,746 | | | | | |
| | | | | | | | |
| Year ended December 31, 2021 | | $ | 1.60 | | | $ | 175,470 | | | | | |
Debt Obligations
The following table summarizes our debt obligations: | | | | | | | | | | | | | | | | | |
| | Maturity | | Outstanding Obligations as of December 31, 2022 |
| | | | | | (Thousands of Dollars) |
| Receivables Financing Agreement, 6.0% as of December 31, 2022 | January 31, 2025 | | $ | 80,900 | |
| Revolving Credit Agreement, 6.9% as of December 31, 2022 | April 27, 2025 | | $ | 220,000 | |
| 5.75% senior notes | October 1, 2025 | | $ | 600,000 | |
| 6.00% senior notes | June 1, 2026 | | $ | 500,000 | |
| 5.625% senior notes | April 28, 2027 | | $ | 550,000 | |
| 6.375% senior notes | October 1, 2030 | | $ | 600,000 | |
| GoZone Bonds, 5.85% - 6.35% | 2038 | thru | 2041 | | $ | 322,140 | |
| Subordinated notes, 10.8% as of December 31, 2022 | January 15, 2043 | | $ | 402,500 | |
As reflected in the table below, certain series of GoZone Bonds in principal amounts totaling $75.0 million and $103.8 million contain a requirement for the bondholders to tender their bonds in exchange for 100% of the principal plus accrued and unpaid interest on June 1, 2025 and on June 1, 2030, respectively, after which these bonds will potentially be remarketed with a new interest rate established. The following table summarizes the GoZone Bonds outstanding as of December 31, 2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Series | | Date Issued | | Amount
Outstanding | | | | | | | |
Interest Rate | | Mandatory
Purchase Date | | Maturity Date |
| | | | (Thousands of Dollars) | | | | | | |
| Series 2008 | | June 26, 2008 | | $ | 55,440 | | | | | | | | | 6.10 | % | | June 1, 2030 | | June 1, 2038 |
| Series 2010 | | July 15, 2010 | | 100,000 | | | | | | | | | 6.35 | % | | n/a | | July 1, 2040 |
| Series 2010A | | October 7, 2010 | | 43,300 | | | | | | | | | 6.35 | % | | n/a | | October 1, 2040 |
| Series 2010B | | December 29, 2010 | | 48,400 | | | | | | | | | 6.10 | % | | June 1, 2030 | | December 1, 2040 |
| Series 2011 | | August 9, 2011 | | 75,000 | | | | | | | | | 5.85 | % | | June 1, 2025 | | August 1, 2041 |
| | Total | | $ | 322,140 | | | | | | | | | | | | | |
We believe that, as of December 31, 2022, we are in compliance with the ratios and covenants applicable to our debt obligations. A default under certain of our debt agreements would be considered an event of default under other of our debt obligations.
Guarantor Summarized Financial Information. NuStar Energy has no operations, and its assets consist mainly of its 100% ownership interest in its indirectly owned subsidiaries, NuStar Logistics and NuPOP. The senior and subordinated notes issued by NuStar Logistics are fully and unconditionally guaranteed by NuStar Energy and NuPOP. Each guarantee of the senior notes by NuStar Energy and NuPOP ranks equally in right of payment with all other existing and future unsecured senior indebtedness of that guarantor, is structurally subordinated to all existing and any future indebtedness and obligations of any subsidiaries of that guarantor that do not guarantee the notes and rank senior to its guarantee of our subordinated indebtedness. Each guarantee of the subordinated notes by NuStar Energy and NuPOP ranks equal in right of payment with all other existing and future subordinated indebtedness of that guarantor and subordinated in right of payment and upon liquidation to the prior payment in full of all other existing and future senior indebtedness of that guarantor. NuPOP will be released from its guarantee when it no longer guarantees any obligations of NuStar Energy or any of its subsidiaries, including NuStar Logistics, under any bank credit facility or public debt instrument. The rights of holders of our senior and subordinated notes may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Please refer to Note 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of our debt agreements.
The following tables present summarized combined balance sheet and income statement information for NuStar Energy, NuStar Logistics and NuPOP (collectively, the Guarantor Issuer Group). Intercompany items among the Guarantor Issuer Group have been eliminated in the summarized combined financial information below, as well as intercompany balances and activity for the Guarantor Issuer Group with non-guarantor subsidiaries, including the Guarantor Issuer Group’s investment balances in non-guarantor subsidiaries. | | | | | |
| December 31, 2022 |
| (Thousands of Dollars) |
| Summarized Combined Balance Sheet Information: | |
| Current assets | $ | 44,328 | |
| Long-term assets | $ | 3,210,483 | |
| Current liabilities (a) | $ | 120,633 | |
| Long-term liabilities, including long-term debt | $ | 3,279,200 | |
| Series D preferred limited partners interests | $ | 446,970 | |
(a)Excluding $1,694.4 million of net intercompany payables due to the non-guarantor subsidiaries from the Guarantor Issuer Group. |
Long-term assets for the non-guarantor subsidiaries totaled $1,559.3 million as of December 31, 2022.
| | | | | |
| Year Ended December 31, 2022 |
| (Thousands of Dollars) |
| Summarized Combined Income Statement Information: | |
| Revenues | $ | 824,398 | |
| Operating income | $ | 277,142 | |
| Interest expense, net | $ | (208,479) | |
| Net income | $ | 72,456 | |
Revenues and net income for the non-guarantor subsidiaries totaled $858.8 million and $150.3 million, respectively, for the year ended December 31, 2022.
Contractual Obligations
The following table presents our contractual obligations and commitments as of December 31, 2022:
| | | | | | | | | | | |
| | Current | | Long-Term |
| | (Thousands of Dollars) |
| Long-term debt maturities | $ | — | | | $ | 3,275,540 | |
| Interest payments | 224,970 | | | 1,631,462 | |
| Operating leases | 7,535 | | | 79,649 | |
| Finance leases | 6,366 | | | 68,380 | |
| Purchase obligations | 7,643 | | | 19,762 | |
| Total | $ | 246,514 | | | $ | 5,074,793 | |
The interest payments calculated for our variable-rate, long-term debt are based on interest rates and the outstanding borrowings as of December 31, 2022. The interest payments on our fixed-rate debt are based on the stated interest rates and the outstanding borrowings as of December 31, 2022. Please see Note 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.
Our operating leases consist primarily of land and dock leases at various terminal facilities. Our finance leases consist primarily of a dock lease at our Corpus Christi North Beach terminal with a remaining term of approximately three years and three additional five-year renewal periods that also includes a commitment for minimum dockage and wharfage throughput volumes. Please see Note 15 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on our operating and finance leases.
A purchase obligation is an enforceable and legally binding agreement to purchase goods or services that specifies significant terms, including (i) fixed or minimum quantities to be purchased, (ii) fixed, minimum or variable price provisions and (iii) the approximate timing of the transaction. Please see Note 14 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on our purchase obligations.
Series D Preferred Units Repurchase and Redemption Features
In November 2022, we repurchased an aggregate 6,900,000 of our Series D Preferred Units at a price per unit of $32.73 for an aggregate purchase price of $225.8 million, including approximately $3.4 million related to accrued distributions. We may redeem all or any portion of the remaining 16,346,650 Series D Preferred Units outstanding, in an amount not less than $50.0 million for cash at a redemption price equal to, as applicable: (i) $31.73 per Series D Preferred Unit, or up to $518.7 million, at any time on or after June 29, 2023 but prior to June 29, 2024; (ii) $30.46 per Series D Preferred Unit, or up to $497.9 million, at any time on or after June 29, 2024 but prior to June 29, 2025; (iii) $29.19 per Series D Preferred Unit, or up to $477.2 million, at any time on or after June 29, 2025; plus, in each case, the sum of any unpaid distributions on the applicable Series D Preferred Unit plus the distributions prorated for the number of days elapsed (not to exceed 90) in the period of redemption (Series D Partial Period Distributions). The holders have the option to convert the units prior to such redemption as discussed in Note 17 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”
Additionally, at any time on or after June 29, 2028, each holder of Series D Preferred Units will have the right to require us to redeem all of the Series D Preferred Units held by such holder at a redemption price equal to $29.19 per Series D Preferred Unit, plus any unpaid Series D distributions plus the Series D Partial Period Distributions. If a holder of Series D Preferred Units exercises its redemption right, we may elect to pay up to 50% of such amount in common units (which shall be valued at 93% of a volume-weighted average trading price of the common units); provided, that the common units to be issued do not, in the aggregate, exceed 15% of NuStar Energy’s common equity market capitalization at the time.
Pension and Other Postretirement Benefit Plan Contributions
During 2022, we contributed $5.0 million and $0.5 million to our pension and postretirement benefit plans, respectively. In 2023, we expect to contribute approximately $10.1 million to our pension and postretirement benefit plans and will monitor our funding status to determine if any contributions are required by regulations or laws, or with respect to unfunded plans, necessary to fund current benefits. Pension and postretirement benefit plans funding beyond 2023 is uncertain as the funding varies from year to year based upon changes in the fair value of the plan assets and actuarial assumptions.
A change of 0.25% in the specified assumptions would have the following effects to our pension and postretirement benefit obligations and costs: | | | | | | | | | | | |
| Pension
Benefits | | Other Postretirement Benefits |
| (Thousands of Dollars) |
| Increase in benefit obligation as of December 31, 2022 resulting from: | | | |
| Discount rate decrease | $ | 3,300 | | | $ | 400 | |
| Compensation rate increase | $ | 500 | | | n/a |
| | | |
(Decrease) increase in net periodic benefit cost for the year ending December 31, 2023 resulting from: | | | |
| Discount rate decrease | $ | (100) | | | $ | — | |
| Expected long-term rate of returns on plan assets decrease | $ | 400 | | | n/a |
| Compensation rate increase | $ | 100 | | | n/a |
Please see Notes 2 and 21 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.
Environmental, Health and Safety
As described below under “Environmental, Health, Safety and Security Regulation,” our operations in the U.S. and Mexico are subject to extensive international, federal, state and local environmental laws and regulations, including those relating to the discharge of materials into the environment, waste management, remediation, the characteristics and composition of fuels, climate change and greenhouse gases. Our operations are also subject to extensive health, safety and security laws and regulations, including those relating to worker and pipeline safety, pipeline and storage tank integrity and operations security.
Because more stringent environmental and safety laws and regulations are continuously being enacted or proposed, the level of expenditures required for environmental, health and safety matters is expected to increase in the future.
The balance of and changes in our accruals for environmental matters as of and for the years ended December 31, 2022 and 2021 are included in this report.Note 13 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.” We believe that we have adequately accrued for our environmental exposures.
OVERVIEW
HUMAN CAPITAL
We strive to make NuStar Energy L.P. (NYSE: NS) is engageda safe, positive, inclusive and rewarding workplace, with competitive compensation, benefits and health and wellness programs and opportunities for our employees to grow and develop in their careers.
Our Employees
As of December 31, 2022, we had 1,167 employees, of which 1,156 are based in the United States and 11 are based in Mexico. Only 1.1 percent of our 1,167 employees are represented under collective bargaining agreements. In the United States, 477 of our employees work at our headquarters in San Antonio, Texas, with the remaining 679 employees working at other locations.
We believe that having a workforce composed of diverse employees with wide-ranging backgrounds, experiences and ideas makes our company stronger. As of December 31, 2022:
•19.4% of all of our employees and 29.8% of our employees at senior manager level and above are female; and
•33.2% of our U.S. employees and 23.8% of our U.S. employees at senior manager level and above are minorities (as defined by the U.S. Equal Opportunity Employment Commission).
Employee Benefits and NuStar’s Culture
We provide opportunities for our employees to develop and enhance their skills through defined career paths, professional training, educational reimbursement and leadership and development programs, as well as regular training regarding safety, operations, ethics (including our Code of Business Conduct and Ethics), human resources topics and cybersecurity. In addition, we support our employees by providing competitive compensation and benefits.
We benchmark our compensation programs through market surveys to help offer competitive packages to attract and retain high-performing employees. Our compensation department also evaluates company-wide racial and gender equity by job-profile each time an employee is hired or recommended for a promotion — this helps to ensure that compensation levels are equitable for all employees regardless of race or gender.
Our benefits and health and wellness programs include life and health insurance (medical, dental and vision), prescription drug benefits, flexible spending accounts, paid sick leave, vacation, short-term and long-term disability, mental and behavioral health resources, retirement benefits (including 401(k) and pension benefits), educational reimbursement, a disaster relief fund that provides cash grants (that do not have to be repaid) to employees undergoing difficult circumstances, an employee assistance program and employee recognition programs. We also are committed to supporting the communities in which we operate, and we organize opportunities for our employees to participate in and enrich our communities through a variety of initiatives, such as fundraising activities, community clean-up projects and educational programs.
Our culture is driven by our nine guiding principles: safety; integrity; commitment; make a difference; teamwork; respect; communication; excellence; and pride. We believe that these principles are the building blocks for our success and have helped us to recruit and retain our employees and make NuStar a great place to work. We have been recognized on FORTUNE’S “100 Best Companies to Work For” list 12 times, FORTUNE’S “Best Workplaces for Millennials” list five times, the “Best Places For Working Parents” list three times, and Latino Leader Magazine’s “Best Companies for Latinos to Work” list three times. We also were recognized as a top employer by regional and local publications, including being recognized as a top employer in Texas by FORTUNE. Many of these awards are based on confidential surveys of our employees. In addition, we monitor our ability to retain our employees through our voluntary turnover rate (the percentage of our total employees who voluntarily leave our company, other than through retirement). As of December 31, 2022, our voluntary turnover rate over the last five years has averaged 3.7%, and 224 of our employees have been employed by NuStar or predecessor entities for at least 20 years.
Safety
Safety is our first priority. In managing our business, we focus on the safety of our employees and contractors, as well as the communities in which we operate. We have implemented safety programs and management practices to promote a culture of safety, including required training for field and office employees and contractors, as well as specific qualifications and certifications for field employees and contractors. To further emphasize the importance of safety at NuStar, our Board of Directors receives a comprehensive annual report and monthly updates regarding our health, safety and environmental
performance. The Compensation Committee of our Board of Directors also evaluates our overall environmental, social and governance (ESG) performance and our health, safety and environmental performance together annually as one of the metrics used to determine the annual incentive bonus for all of our employees, including our executive officers, which we believe reinforces the importance of maintaining safe, responsible operations and focusing on ESG excellence.
We are proud of NuStar’s safety performance. Our safety statistics have been substantially better than those reported by the U.S. Bureau of Labor Statistics (BLS) for our industries. Our 2022 total recordable incident rate (TRIR) of 0.23 was 17.4 times better than the 4.0 average most recently reported by BLS for the bulk terminals industry and 2.6 times better than the 0.60 average most recently reported by BLS for the pipeline transportation industry. Our 2022 days away, restricted or transferred rate (DART) of petroleum products0.23 was 13.9 times better than the 3.20 average most recently reported by BLS for the bulk terminals industry and anhydrous ammonia,1.7 times better than the 0.4 average most recently reported by BLS for the pipeline transportation industry. NuStar also participates in the Occupational Safety and Health Administration’s (OSHA) Voluntary Protection Program (VPP), which promotes effective worksite health and safety. Achieving VPP Star status requires rigorous OSHA review and audit, and requires recertification every three to five years. As of December 31, 2022, approximately 91% of our eligible U.S. terminals have attained VPP Star status. NuStar also has received the International Liquids Terminals Association’s Safety Excellence Award 12 times. Throughout the COVID-19 pandemic, we continued to focus on safety and have taken measures to protect our employees and maintain safe, reliable operations.
Sustainability Report
We publish a Sustainability Report, which covers topics similar to those described above, including our guiding principles; operations and economic impact; environmental and safety programs; sustainability; renewable fuels-related services; policies and statistics (including greenhouse gas emissions disclosures); employee engagement, development and training; diversity and inclusion; community involvement and development; recent awards; human rights and landowner relations; risk management; cybersecurity; and governance. Our Sustainability Report can be viewed at https://sustainability.nustarenergy.com. Our Sustainability Report and the terminalling, storageinformation contained on our website are not part of this Annual Report on Form 10-K, are not “soliciting materials,” are not deemed filed with the SEC and marketingare not to be incorporated by reference into any of petroleum products. Unless otherwise indicated,NuStar Energy’s filings under the terms “NuStar Energy,” “NS,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to NuStar Energy L.P., to oneSecurities Act of 1933 or morethe Securities Act of our consolidated subsidiaries or to all of them taken1934, as a whole. NuStar GP Holdings, LLC (NuStar GP Holdings or NSH) (NYSE: NSH) owns our general partner, Riverwalk Logistics, L.P., and owns an approximate 11% common limited partner interest in us as of December 31, 2017. Our Management’s Discussion and Analysis of Financial Condition and Results of Operations is presented in seven sections:amended, respectively.
Overview
Results of Operations
Trends and Outlook
Liquidity and Capital Resources
Related Party Transactions
Critical Accounting Policies
New Accounting Pronouncements
Recent Developments
Merger. On February 7, 2018, NuStar Energy, Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, a wholly owned subsidiary of NuStar Energy (Merger Sub), Riverwalk Holdings, LLC and NuStar GP Holdings, LLC (NuStar GP Holdings) entered into an Agreement and Plan of Merger (the Merger Agreement) pursuant to which Merger Sub will merge with and into NuStar GP Holdings with NuStar GP Holdings being the surviving entity (the Merger), such that NuStar Energy will be the sole member of NuStar GP Holdings following the Merger. Pursuant to the Merger Agreement and at the effective time of the Merger, our partnership agreement will be amended and restated to, among other things, (i) cancel the incentive distribution rights held by our general partner, (ii) convert the 2% general partner interest in NuStar Energy held by our general partner into a non-economic management interest and (iii) provide the holders of our common units with voting rights in the election of the members of the board of directors of NuStar GP, LLC at an annual meeting, beginning in 2019. The Merger is subject to the satisfaction or waiver of certain conditions, including approval of the Merger Agreement by NuStar GP Holdings unitholders. Please refer to Note 28 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the Merger.
Hurricane Activity.Houston Pipeline Impairment. In the third quarter of 2017, parts of the Caribbean and Gulf of Mexico experienced three major hurricanes. Several of our facilities were affected by the hurricanes, but our St. Eustatius terminal experienced the most damage and was temporarily shut down. We incurred approximately $2.6 million of operating expenses to repair minor property damage at several of our domestic terminals. Additionally,2021, we recorded a $5.0non-cash asset impairment charge of $59.2 million loss in “Other (expense) income, net” inrelated to the consolidated statements of income in the third quarter of 2017 for property damage at our St. Eustatius terminal, which represents the amountsouthern section of our property deductible under our insurance policy. The hurricane impacts lowered revenues for our bunker fuel operations in our fuels marketing segment and lowered throughput and associated handling fees in our storage segment in the third and fourth quarters of 2017. We received insurance proceeds of $12.5 million in 2017 for damages at our St. Eustatius terminal, of which $3.8 million was for business interruption and the remainder was used for repairs and cleanup. Proceeds from business interruption insurance are included in “Operating expenses” in the consolidated statements of income and in “Cash flows from operating activities” in the consolidated statements of cash flows. In January 2018, we received $87.5 million of insurance proceeds in settlement of our property damage claim for our St. Eustatius terminal. We expect that the costs to repair the property damage at the terminal will not exceed the value of insurance proceeds received.
Navigator Acquisition and Financing Transactions. On May 4, 2017, we completed the acquisition of Navigator Energy Services, LLC for approximately $1.5 billion (the Navigator Acquisition). In order to fund the purchase price, we issued 14,375,000 common units for net proceeds of $657.5 million, issued $550.0 million of 5.625% senior notes for net proceeds of $543.3 million and issued 15,400,000 of our 7.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (Series B Preferred Units) for net proceeds of $371.8 million. We collectively refer to the acquired assets as our
Permian Crude System. Please refer to Notes 4, 12 and 19 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion.
Axeon Term Loan. On February 22, 2017, we settled and terminated the $190.0 million term loan to Axeon Specialty Products, LLC (the Axeon Term Loan), pursuant to which we also provided credit support, such as guarantees, letters of credit and cash collateral, as applicable, of up to $125.0 million to Axeon Specialty Products, LLC (Axeon). We received $110.0 million in settlement of the Axeon Term Loan, and our obligation to provide ongoing credit support to Axeon ceased. In 2016, we recognized an impairment charge on the Axeon Term Loan of $58.7 million which is included in “Other (expense) income, net” in the consolidated statements of income. Please refer to Notes 7 and 15 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on the Axeon Term Loan and related credit support.
Other Events
Martin Terminal Acquisition. On December 21, 2016, we acquired crude oil andHouston refined product storage assets in Corpus Christi, TX for $95.7 million, including $2.1 million of capital expenditure reimbursements, from Martin Operating Partnership L.P. (the Martin Terminal Acquisition). The assets acquired are in our storage segment and include 900,000 barrels of crude oil storage capacity, 250,000 barrels of refined product storage capacity and exclusive use of the Port of Corpus Christi’s new crude oil dock.The acquired assets, which are adjacent to our existing Corpus Christi North Beach terminal, increased our storage capacity in the Corpus Christi region and have direct connectivity to Eagle Ford crude oil production.
Employee Transfer from NuStar GP, LLC. On March 1, 2016, NuStar GP, LLC, the general partner of our general partner and a wholly owned subsidiary of NuStar GP Holdings, transferred and assigned to NuStar Services Company LLC (NuStar Services Co), a wholly owned subsidiary of NuStar Energy, all of NuStar GP, LLC’s employees and related benefit plans, programs, contracts and policies (the Employee Transfer). As a result of the Employee Transfer, we pay employee costs directly and sponsor the long-term incentive plan and other employee benefit plans. Please refer to the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for the following: Note 17 for further discussion of the Employee Transfer and our related party agreements, Note 22 for a discussion of our employee benefit plans and Note 23 for a discussion of our long-term incentive plan.
Linden Acquisition. On January 2, 2015, we acquired full ownership of ST Linden Terminal, LLC (Linden), which owns a refined products terminal in Linden, NJ with 4.3 million barrels of storage capacity, for $142.5 million (the Linden Acquisition). Prior to the Linden Acquisition, Linden operated as a joint venture between Linden Holding Corp. and us, with each party owning 50%. On the acquisition date, we remeasured our existing 50% equity investment in Linden to its fair value of $128.0 million and we recognized a gain of $56.3 million in “Other (expense) income, net” in the consolidated statements of income for the year ended December 31, 2015.pipeline. Please refer to Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussiondiscussion.
The following table presents operating highlights for the pipeline segment:
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | |
| | 2022 | | 2021 | | Change |
| (Thousands of Dollars, Except Barrel Data) |
| Pipeline Segment: | | | | | |
| Crude oil pipelines throughput (barrels/day) | 1,319,360 | | | 1,281,568 | | | 37,792 | |
| Refined products and ammonia pipelines throughput (barrels/day) | 579,240 | | | 585,189 | | | (5,949) | |
| Total throughput (barrels/day) | 1,898,600 | | | 1,866,757 | | | 31,843 | |
| | | | | |
| Throughput and other revenues | $ | 828,191 | | | $ | 762,238 | | | $ | 65,953 | |
| Operating expenses | 210,719 | | | 202,481 | | | 8,238 | |
| Depreciation and amortization expense | 178,802 | | | 179,088 | | | (286) | |
| | | | | |
| Impairment loss | — | | | 59,197 | | | (59,197) | |
| Segment operating income | $ | 438,670 | | | $ | 321,472 | | | $ | 117,198 | |
Pipeline segment revenues increased $66.0 million and throughputs increased 31,843 barrels per day for the year ended December 31, 2022, compared to the year ended December 31, 2021. Results for the first quarter of 2021 were negatively affected by Winter Storm Uri, which brought snow and damaging ice and caused widespread power outages in Texas and surrounding states in February 2021, as well as the lingering effects of COVID-19 restrictions. However, by the second quarter of 2021, demand had largely recovered to pre-pandemic levels. Revenues primarily increased due to the following:
•an increase in revenues of $61.6 million and an increase in throughputs of 82,596 barrels per day on our Permian Crude System, mainly due to increased customer production supplying this system and the completion of pipeline expansion projects, as well as the negative impacts on the first quarter of 2021 described above. The increase in revenues included an increase of $14.5 million due to higher commodity prices on PLA volumes sold and a $4.4 million adjustment to deferred revenue in the second quarter of 2022 resulting from higher expected tariff revenue on certain incentive pricing contracts;
•an increase in revenues of $5.7 million and an increase in throughputs of 7,768 barrels per day on our Three Rivers System, mainly due to an increase in demand in the markets served by our Nuevo Laredo and San Antonio pipelines in 2022 and the negative impacts on the first quarter of 2021 described above;
•an increase in revenues of $3.4 million and an increase in throughputs of 2,545 barrels per day on our Valley Pipeline, mainly due to higher demand in the markets served by this pipeline in 2022;
•an increase in revenues of $3.0 million on our Corpus Christi Crude Pipeline System, mainly due to increased volumes on certain of our pipelines in this system, despite lower overall throughputs of 37,808 barrels per day, mainly due to unfavorable market conditions on other pipelines in this system; and
•an increase in revenues of $1.3 million and an increase in throughputs of 1,526 barrels per day on our Houston Pipeline due to a new contract with a customer that began at the end of March 2021.
However, these increases were partially offset by the following:
•a decrease in revenues of $4.1 million and a decrease in throughputs of 4,322 barrels per day on our Ammonia Pipeline, due to scheduled maintenance on our pipeline in the third quarter of 2022 and unfavorable market conditions in 2022;
•a decrease in revenues of $2.6 million on the Ardmore System, mainly due to the expiration of a customer contract at the end of the Linden Acquisition.first quarter of 2021; although throughputs on this system increased 7,055 barrels per day in 2022 due to the negative impacts in the first quarter of 2021 described above, these higher throughputs did not offset the decrease in revenues as more barrels were moved at lower average tariffs in 2022;
•a decrease in revenues of $1.3 million and a decrease in throughputs of 4,471 barrels per day on our East Pipeline, mainly due to the current backwardated market, which led to a decline in PLA volumes sold and the expiration of customer contracts; and
Operations•a decrease in revenues of $0.7 million and a decrease in throughputs of 20,590 barrels per day on our McKee System pipelines, mainly due to operational issues at a customer’s refinery in 2022, including a planned turnaround in the third quarter of 2022, which had an even greater negative impact than the first quarter of 2021 impacts described above.
We conduct
Operating expenses increased $8.2 million for the year ended December 31, 2022, compared to the year ended December 31, 2021, mainly due to an increase in power costs of $5.7 million, primarily on our operations through our subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics)Permian Crude System and NuStar Pipeline Operating Partnership L.P. (NuPOP). Our operations are divided into three reportable business segments: pipeline, storage and fuels marketing. For a more detailed description of our segments, please refer to “Segments” under Item 1. “Business.”
Pipeline. We own 3,130 miles ofvarious refined product pipelines, and 1,930 milesan increase in maintenance and regulatory expenses of $1.6 million across various pipelines.
STORAGE SEGMENT
Our storage segment is comprised of our facilities that provide storage, handling and other services for refined products, crude oil, pipelines, as well as approximately 5.0 million barrelsspecialty chemicals, renewable fuels and other liquids. As of storage capacity, which comprise our Central West System. In addition,December 31, 2022, we own 2,370 miles of refined product pipelines, consisting of the Eastowned and North Pipelines, and a 2,000-mile ammonia pipeline (the Ammonia Pipeline), which comprise our Central East System. The East and North Pipelines have storage capacity of approximately 6.8 million barrels.
Storage. We own terminalsoperated 29 terminal and storage facilities in the United States Canada,and one terminal in Nuevo Laredo, Mexico, the Netherlands, including St. Eustatiuswith an aggregate storage capacity of 36.4 million barrels. The following table sets forth information about our terminal and storage facilities as of December 31, 2022:
| | | | | | | | | | |
| Facility | | Tank Capacity | | |
| | (Barrels) | | |
| Colorado Springs, CO | | 327,000 | | | |
| Denver, CO | | 110,000 | | | |
| Albuquerque, NM | | 250,000 | | | |
| Rosario, NM | | 167,000 | | | |
| Catoosa, OK | | 359,000 | | | |
| Abernathy, TX | | 161,000 | | | |
| Amarillo, TX | | 269,000 | | | |
| Corpus Christi, TX | | 410,000 | | | |
| Corpus Christi, TX (North Beach) | | 3,962,000 | | | |
| Edinburg, TX | | 345,000 | | | |
| El Paso, TX (a) | | 415,000 | | | |
| Harlingen, TX | | 286,000 | | | |
| Laredo, TX | | 218,000 | | | |
| San Antonio, TX (b) | | 379,000 | | | |
| Southlake, TX | | 569,000 | | | |
| Nuevo Laredo, Mexico | | 268,000 | | | |
| Central West Terminals | | 8,495,000 | | | |
| | | | |
| St. James, LA | | 9,906,000 | | | |
| Houston, TX | | 87,000 | | | |
| Gulf Coast Terminals | | 9,993,000 | | | |
| | | | |
| Los Angeles, CA | | 606,000 | | | |
| Pittsburg, CA | | 398,000 | | | |
| Selby, CA | | 2,672,000 | | | |
| Stockton, CA | | 818,000 | | | |
| Portland, OR | | 1,348,000 | | | |
| Tacoma, WA | | 391,000 | | | |
| Vancouver, WA (b) | | 775,000 | | | |
| West Coast Terminals | | 7,008,000 | | | |
| | | | |
| Benicia, CA | | 3,683,000 | | | |
| Corpus Christi, TX | | 4,030,000 | | | |
| Texas City, TX | | 3,141,000 | | | |
| Refinery Storage Tanks | | 10,854,000 | | | |
| | | | |
| Total | | 36,350,000 | | | |
(a)We own a 67% undivided interest in the Caribbean,El Paso refined product terminal. The tank capacity represents the proportionate share of capacity attributable to our ownership interest.
(b)Location includes two terminal facilities.
Description of Terminal and Storage Facilities
Central West Terminals. Our Central West Terminals include terminals located in Texas, Oklahoma, New Mexico and Colorado, as well as one terminal located in Nuevo Laredo, Mexico, with an aggregate storage capacity of 8.5 million barrels. Most of these terminals are connected to our Central West Refined Product Pipelines. Our Corpus Christi North Beach terminal, located at the United Kingdom (UK), with approximately 84.8Port of Corpus Christi in Texas, has 4.0 million barrels of crude oil storage capacity.and supports our Corpus Christi Crude Pipeline System that transports crude oil from the Eagle Ford and Permian Basin regions to Corpus Christi for export or refineries owned by third parties. This facility also provides our customers with the flexibility to segregate and deliver crude oil and processed condensate and has access to four docks, including two private docks. We can accommodate Suezmax-class vessels and load crude oil onto marine vessels simultaneously on all four docks.
Fuels Marketing. WithinWe refer to our fuels marketing operations, we purchase petroleum products for resale. The resultspipelines that transport crude oil from the Eagle Ford and Permian Basin regions to Corpus Christi, together with our Corpus Christi North Beach terminal, as the Corpus Christi Crude System.
Gulf Coast Terminals. Our Gulf Coast Terminals have an aggregate storage capacity of operations for the fuels marketing segment depend largely10.0 million barrels and include our St. James terminal, which is located on the margin between our costsMississippi River near St. James, Louisiana, and the sales pricesone terminal located in Houston, Texas. Our St. James terminal has a total storage capacity of 9.9 million barrels and is located on almost 900 acres of land, some of which is undeveloped. The majority of the products we market. Therefore, the results of operationsstorage tanks and infrastructure are suited for this segment are more sensitivelight to changes in commodity prices compared to the operations of the pipeline and storage segments. We enter into derivative contracts to attempt to mitigate the effects of commodity price fluctuations. The derivative instruments we use consist primarily of commodity futures and swap contracts. Not all of our derivative instruments qualify for hedge accounting treatment under U.S. generally accepted accounting principles. In such cases, our earnings for a period may include the gain or loss related to derivative instruments without including the offsetting effect of the hedged item, which could result in greater earnings volatility.
We ceased marketingmedium crude oil, with certain tanks capable of fuel oil or heated crude oil storage. Additionally, the facility has one barge dock and two ship docks, and can accommodate exports up to Aframax-class vessels. Our St. James terminal is connected to (i) offshore pipelines in the second quarterGulf of 2017Mexico, (ii) long-haul pipelines that can receive crude oil from the Eagle Ford, Permian Basin, other domestic shale plays and exited our heavy fuels trading operationsCanada, and (iii) pipelines connecting to refineries in the third quarterGulf Coast. The St. James terminal also has two unit train rail facilities that are served by the Union Pacific Railroad. Each facility has the capacity to simultaneously off-load 120 railcars, at a minimum, in a 24-hour period.
West Coast Terminals. Our West Coast Terminals include terminals located in California, Oregon and Washington, with an aggregate storage capacity of 2017. These actions are in line7.0 million barrels. The largest of these terminals is our Selby, California terminal, with our goala total storage capacity of reducing our exposure to commodity margins, and instead focusing on our core, fee-based pipeline and2.7 million barrels. We have completed several renewable fuel storage segments. The only operations remaining in our fuels marketing segment are our bunkering operationsprojects at our St. EustatiusWest Coast Terminals over the last several years, and are able to receive and distribute renewable fuels across the West Coast, including renewable diesel, sustainable aviation fuel, ethanol, biodiesel and renewable feedstock. Our West Coast Terminals are connected to supply from various domestic and foreign sources.
Refinery Storage Tanks. We own crude oil storage tanks with an aggregate storage capacity of 10.9 million barrels that are physically integrated with and serve refineries owned by Valero Energy at Corpus Christi and Texas City, Texas and Benicia, California. We lease our refinery storage tanks to Valero Energy in exchange for a fixed fee.
Storage Operations
We generate storage segment revenues through fees for tank storage agreements, under which a customer agrees to pay for a certain amount of storage in a tank over a period of time (storage terminal revenues), and throughput agreements, under which a customer pays a fee per barrel for volumes moved through our terminals as well as certain(throughput terminal revenues). Our terminals also provide blending, additive injections, handling and filtering services for which we charge additional fees.
Demand for Storage Services
The operations of our blending operations.
Factors That Affect Resultsrefined product terminals depend in large part on the level of Operations
The following factors affect the results of our operations:
company-specific factors, such as facility integrity issues and maintenance requirements that impact the throughput rates of our assets;
seasonal factors that affect the demand for products transported by and/or stored in our assets andterminals in the markets served by those assets. Demand for our terminalling services will generally increase or decrease with demand for refined products, we sell;
industry factors, such as changes in the prices of petroleum products that affect demand and operations of our competitors;
economic factors, such as commodity price volatility that impact our fuels marketing segment; and
factors that impact the operations served by our pipeline and storage assets, such as utilization rates and maintenance turnaround schedules of our refining company customers and drilling activity by our crude oil production customers.
Current Market Conditions
The price of crude oil has recovered somewhat since its sharp initial decline in 2014 and subsequent historic lows during 2015 and 2016. In 2017, global supply and demand moved into balance, which seemsfor refined products tends to increase or decrease with the relative strength of the economy. In addition, the forward pricing curve can have reduced crude price volatility, but crude prices remain stalled at approximately 50% of their 2014 levels. Most energy industry experts now project a modest price recovery in 2018, but the duration and degree of price improvements will dependan impact on among other things, changes in global supply and demand.
Increases or decreases in the price of crude oil affect sectors across the energy industry, including our customers in crude oil production, refining and trading, in different ways at different points in any given price cycle. For example, U.S. crude oil producers reduced their capital spending relatively early in this sustained low price cycle, which reduced drilling activity and lowered production, particularly in shale play regions with higher relative drilling costs. As this cycle has continued, producers focused their trimmed-back spending on the most capital-efficient regions, such as, notably, the Permian Basin. Refiners, on the other hand, have benefitted from lower crude oil prices, to the extent they have been able to take advantage of lower feedstock prices, especially those positioned for healthy regional demand for their refined products; however, as refined product inventories increase, refiners are incentivized to reduce their production levels, which in turn may reduce their ability to benefit from low crude prices. Crude oil traders focus less on the current market commodity price than on whether that price is higher or lower than expected future market prices: if the future price for a product is believed to be higher than the current market price, or a “contango market,” traders are more likely to purchase and store products to sell in the future at the higher price. On the other hand, when the current price of crude oil nears or exceeds the expected future market price, or “backwardation,” as is currently the case, traders are no longer incentivized to purchase and store product for future sale. Our storage terminal revenues are somewhat insulated from demand volatility due to contracted rates for storage and minimum volume commitments.
RESULTS OF OPERATIONS
Year Ended December 31, 2017 ComparedCrude oil delivered to Year Ended December 31, 2016
Financial Highlights
(Thousandsour St. James and Corpus Christi North Beach terminals will generally increase or decrease with crude oil production rates in western Canada and the Bakken, Permian and Eagle Ford shale plays. In addition, the market price relationship between various grades of Dollars, Except Unitcrude oil impacts the demand for our unit train facilities at our St. James terminal. Prior to the COVID-19 pandemic, North American shale play production had increased exports of crude oil from Texas Gulf Coast ports, including our Corpus Christi North Beach facility, to destinations as close as the U.S. East Coast and Per Unit Data)as far away as Europe and Asia. Although the negative impact of COVID-19 has been partially mitigated by the low break-even point in the
|
| | | | | | | | | | | |
| | Year Ended December 31, | | |
| | 2017 | | 2016 | | Change |
| Statement of Income Data: | | | |
| Revenues: | | | | | |
| Service revenues | $ | 1,128,726 |
| | $ | 1,083,165 |
| | $ | 45,561 |
|
| Product sales | 685,293 |
| | 673,517 |
| | 11,776 |
|
| Total revenues | 1,814,019 |
| | 1,756,682 |
| | 57,337 |
|
| | | | | | |
| Costs and expenses: | | | | | |
| Cost of product sales | 651,599 |
| | 633,653 |
| | 17,946 |
|
| Operating expenses | 449,670 |
| | 448,367 |
| | 1,303 |
|
| General and administrative expenses | 112,240 |
| | 98,817 |
| | 13,423 |
|
| Depreciation and amortization expense | 264,232 |
| | 216,736 |
| | 47,496 |
|
| Total costs and expenses | 1,477,741 |
| | 1,397,573 |
| | 80,168 |
|
| | | | | | |
| Operating income | 336,278 |
| | 359,109 |
| | (22,831 | ) |
| Interest expense, net | (173,083 | ) | | (138,350 | ) | | (34,733 | ) |
| Other expense, net | (5,294 | ) | | (58,783 | ) | | 53,489 |
|
| Income before income tax expense | 157,901 |
| | 161,976 |
| | (4,075 | ) |
| Income tax expense | 9,937 |
| | 11,973 |
| | (2,036 | ) |
| Net income | $ | 147,964 |
| | $ | 150,003 |
| | $ | (2,039 | ) |
| Basic and diluted net income per common unit | $ | 0.64 |
| | $ | 1.27 |
| | $ | (0.63 | ) |
| Basic weighted-average common units outstanding | 88,825,964 |
| | 78,080,484 |
| | 10,745,480 |
|
Annual Overview
Net income slightly decreasedDemand for renewable diesel, renewable jet fuel, ethanol and other renewable fuels continues to grow in markets served by our West Coast terminals due to new regulations with aggressive carbon emissions reduction goals. As this demand growth is expected to continue, we have completed, and continue to develop, renewable fuel storage projects at our West Coast terminals to meet this demand.
Customers
We provide storage and terminalling services for crude oil, refined products and other products to many of the world’s largest producers of crude oil, integrated oil companies, chemical companies, oil traders and refiners. In addition, our blending capabilities in our storage assets have attracted customers who have leased capacity primarily for blending purposes. The two largest customers of our storage segment accounted for approximately 33% and 14%, respectively, of the total revenues of the segment for the year ended December 31, 2017, compared to the year ended December 31, 2016. The decrease in2022. No other expense, net, mainly resulting fromcustomer accounted for a $58.7 million impairment charge on the Axeon Term Loan in 2016, was offset by increased interest expense, increased general and administrative expenses and decreased segment operating income.
Segment Operating Highlights
(Thousands of Dollars, Except Barrel/Day Information)
|
| | | | | | | | | | | |
| | Year Ended December 31, | | |
| | 2017 | | 2016 | | Change |
| Pipeline: | | | | | |
| Refined products pipelines throughput (barrels/day) | 516,736 |
| | 535,946 |
| | (19,210 | ) |
| Crude oil pipelines throughput (barrels/day) | 583,323 |
| | 392,181 |
| | 191,142 |
|
| Total throughput (barrels/day) | 1,100,059 |
| | 928,127 |
| | 171,932 |
|
| Throughput revenues | $ | 516,288 |
| | $ | 485,650 |
| | $ | 30,638 |
|
| Operating expenses | 156,432 |
| | 147,858 |
| | 8,574 |
|
| Depreciation and amortization expense | 128,061 |
| | 89,554 |
| | 38,507 |
|
| Segment operating income | $ | 231,795 |
| | $ | 248,238 |
| | $ | (16,443 | ) |
| | | | | | |
| Storage: | | | | | |
| Throughput (barrels/day) | 325,194 |
| | 789,065 |
| | (463,871 | ) |
| Throughput terminal revenues | $ | 85,927 |
| | $ | 117,586 |
| | $ | (31,659 | ) |
| Storage terminal revenues | 531,026 |
| | 492,456 |
| | 38,570 |
|
| Total revenues | 616,953 |
| | 610,042 |
| | 6,911 |
|
| Operating expenses | 270,041 |
| | 276,578 |
| | (6,537 | ) |
| Depreciation and amortization expense | 127,473 |
| | 118,663 |
| | 8,810 |
|
| Segment operating income | $ | 219,439 |
| | $ | 214,801 |
| | $ | 4,638 |
|
| | | | | | |
| Fuels Marketing: | | | | | |
| Product sales and other revenue | $ | 692,884 |
| | $ | 681,934 |
| | $ | 10,950 |
|
| Cost of product sales | 660,844 |
| | 645,355 |
| | 15,489 |
|
| Gross margin | 32,040 |
| | 36,579 |
| | (4,539 | ) |
| Operating expenses | 26,057 |
| | 33,173 |
| | (7,116 | ) |
| Segment operating income | $ | 5,983 |
| | $ | 3,406 |
| | $ | 2,577 |
|
| | | | | | |
| Consolidation and Intersegment Eliminations: | | | | | |
| Revenues | $ | (12,106 | ) | | $ | (20,944 | ) | | $ | 8,838 |
|
| Cost of product sales | (9,245 | ) | | (11,702 | ) | | 2,457 |
|
| Operating expenses | (2,860 | ) | | (9,242 | ) | | 6,382 |
|
| Total | $ | (1 | ) | | $ | — |
| | $ | (1 | ) |
| | | | | | |
| Consolidated Information: | | | | | |
| Revenues | $ | 1,814,019 |
| | $ | 1,756,682 |
| | $ | 57,337 |
|
| Cost of product sales | 651,599 |
| | 633,653 |
| | 17,946 |
|
| Operating expenses | 449,670 |
| | 448,367 |
| | 1,303 |
|
| Depreciation and amortization expense | 255,534 |
| | 208,217 |
| | 47,317 |
|
| Segment operating income | 457,216 |
| | 466,445 |
| | (9,229 | ) |
| General and administrative expenses | 112,240 |
| | 98,817 |
| | 13,423 |
|
| Other depreciation and amortization expense | 8,698 |
| | 8,519 |
| | 179 |
|
| Consolidated operating income | $ | 336,278 |
| | $ | 359,109 |
| | $ | (22,831 | ) |
Pipeline
Total revenues increased $30.6 million and total throughputs increased 171,932 barrels per day for the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to:
an increase in revenues of $42.6 million and an increase in throughputs of 192,958 barrels per day from our Permian Crude System acquired in May 2017;
an increase in revenues of $5.5 million and an increase in throughputs of 2,929 barrels per day due to maintenance downtime in 2016 on asignificant portion of the Ammonia Pipeline,total revenues of the storage segment.
Competition and Other Business Considerations
Many major energy and chemical companies own extensive terminal storage facilities. Although such terminals often have the same capabilities as terminals owned by independent operators, they generally do not provide terminalling services to third parties. In many instances, even major energy and chemical companies that have storage and terminalling facilities are also significant customers of independent terminal operators, especially terminals located in cost-effective locations near key transportation links, such as deep-water ports. Major energy and chemical companies also need independent terminal storage when their proprietary storage facilities are inadequate, due to size constraints, the nature of the stored material or specialized handling requirements.
Independent terminal owners generally compete on the basis of the location and versatility of terminals, service and price. A favorably located terminal will have access to various cost-effective transportation modes both to and from the terminal. Transportation modes typically include waterways, railroads, roadways and pipelines.
Terminal versatility is a function of the operator’s ability to offer complex handling requirements for diverse products. The services typically provided by the terminal include, among other things, the safe storage of the product at specified temperature, moisture and other conditions, as well as operational issues in 2016receipt at certain plants servedand delivery from the terminal, all of which must comply with applicable environmental regulations. A terminal operator’s ability to obtain attractive pricing is often dependent on the quality, versatility and reputation of the facilities owned by the pipeline; and
an increase in revenues of $3.4 million, despite a decrease in throughputs of 4,129 barrels per day, on our East Pipeline dueoperator. Operators with versatile storage capabilities typically require less modification prior to usage, ultimately making the storage cost to the completion of various storage projects alongcustomer more attractive. On the pipeline, as well as anWest Coast, regulatory priorities continue to increase demand for renewable fuels in long-haul deliveries resulting in higher average tariffs. A turnaround and operational issuesthe region, while at the same time, obtaining permits for greenfield projects remains difficult, which both add more value to our existing assets.
Our crude oil refinery storage tanks are physically integrated with and serve refineries servedowned by Valero Energy, and we have entered into various agreements with Valero Energy governing the East Pipeline in 2017 contributeduse of these tanks. As a result, we believe that we will not face significant competition for our services provided to those refineries.
Results of Operations
Dispositions. In the decrease in throughputs.
These increases in revenues and throughputs were partially offset by:
a decrease in revenues of $10.4 million and a decrease in throughputs of 16,839 barrels per day due to a turnaround in the fourthfirst quarter of 2017 at the refinery served by2022, we recognized a non-cash pre-tax impairment loss of $46.1 million related to our McKee System pipelines;
a decrease in revenues of $6.8 million and a decrease in throughputs of 15,561 barrels per day on our Eagle Ford System, mainly due to reduced production in this sustained low crude oil price environment; and
a decrease in revenues of $4.8 million and a decrease in throughputs of 6,905 barrels per day due to a turnaround in the second quarter of 2017 at the refinery served by the North Pipeline.
Operating expenses increased $8.6 million for the year ended December 31, 2017, compared to the year ended December 31, 2016. Operating expenses increased $9.9 million as a result of our acquisition of the Permian Crude System,Point Tupper terminal facility, which was partially offset by a decrease of $2.1 million from product imbalancessold on the East Pipeline.
Depreciation and amortization expense increased $38.5 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, due to our acquisition of the Permian Crude System and the completion of various pipeline projects.
Storage
Beginning January 1, 2017, our agreements for our refinery crude storage tanks at Corpus Christi, TX, Texas City, TX and Benicia, CA changed from throughput-based to storage-based. Excluding the effect of the change to these agreements, throughput terminal revenues would have increased $9.5 million and throughputs would have increased 14,360 barrels per day for the year ended December 31, 2017, compared to the year ended December 31, 2016. Throughput terminal revenues increased at our Corpus Christi North Beach terminal by $15.1 million due to an increase in throughputs of 26,359 barrels per day, mainly resulting from the MartinApril 29, 2022 (the Point Tupper Terminal Acquisition. The benefit of the Martin Terminal Acquisition was partially offset by lower revenues and throughputs resulting from a decrease in Eagle Ford Shale crude oil being shipped to Corpus Christi due to reduced production in this sustained low crude oil price environment. Throughputs increased 16,309 barrels per day, despite only a slight increase in revenues of $0.3 million, at our Central West Terminals, mainly due to a new customer contract and increased marine activity, mostly offset by decreased revenues from ancillary services. These increases in revenues and throughputs were partially offset by decreased revenues of $5.8 million and decreased throughputs of 28,308 barrels per day at our Paulsboro, NJ terminal as a customer diverted barrels to other terminals.
Storage terminal revenues would have decreased $0.6 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, excluding the effect of the change to the refinery storage tank agreements described above. Revenues at our Gulf Coast Terminals decreased $19.2 million, mainly at our St. James, LA terminal due to reduced unit train activity and at our Texas City, TX terminal as a result of the exit from our heavy fuels trading operations. These decreases were partially offset by increases in revenues of $8.2 million at our North East Terminals and $4.5 million at our West Coast Terminals, mainly due to new customer contracts and rate escalations.
Storage terminal revenues also increased $5.5 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, at our International Terminals. Revenues increased $10.2 million at our St. Eustatius terminal, mainly due to new customer contracts and rate escalations, partially offset by lower throughput and associated handling fees as a result of the temporary shutdown of the terminal and damage caused by hurricane activity inDisposition). In the third quarter of 2017. This increase was partially offset by a decrease in revenues of $4.2 million at our Point Tupper terminal, mainly resulting from a decrease in customer base, tanks out of service2021, we recorded non-cash asset and lower reimbursable revenues.
Operating expenses decreased $6.5 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to:
a decrease of $8.7 million in maintenance and regulatory expenses, primarily at our St. Eustatius, North East and Point Tupper terminals; and
a decrease of $6.1 million in reimbursable expenses, mainly at our Texas City, TX and Point Tupper terminals, consistent with the decrease in reimbursable revenues;
These decreases were partially offset by increased operating expenses of $8.5 million as a result of the Martin Terminal Acquisition.
Depreciation and amortization expense increased $8.8 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, due to the Martin Terminal Acquisition and other various projects.
Fuels Marketing
Segment operating income increased $2.6 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to a reduction ingoodwill impairment losses of $9.1$95.7 million from our heavy fuels trading operations following our exit of that business in 2017. Segment operating income from our bunker fuel operations at our St. Eustatius terminal decreased $6.4and $34.1 million, resulting from lower gross margins and the temporary shutdown of the terminal caused by hurricane activity in the third quarter of 2017.
Consolidation and Intersegment Eliminations
Revenue and operating expense eliminations primarily relate to storage fees charged to the fuels marketing segment by the storage segment. Cost of product sales eliminations represent expenses charged to the fuels marketing segment for costs associated with inventory that are expensed once the inventory is sold.
General
General and administrative expenses increased $13.4 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to transaction costsrespectively, related to the Navigator Acquisition.
Interest expense, net increased $34.7 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, mainly due to the issuance of $550.0 million of 5.625% senior notes in April 2017 and as a result of fees for a bridge loan commitment to potentially assist with the financing of the Navigator Acquisition. We did not enter into or borrow under the bridge loan. Interest expense, net also increased as a result of lower interest income due to the termination of the Axeon Term Loan in February 2017.our Eastern U.S. Terminal Operations, which were sold on October 8, 2021 (the Eastern U.S. Terminals Disposition). Please refer to Note 74 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for afurther discussion of the Axeon Term Loan and related credit support.these dispositions.
For the year ended December 31, 2017, we recorded other expense, net
Selby Terminal Fire. We recognized a gain from business interruption insurance of $5.3 million, mainly due to property damage of $5.0 million at our St. Eustatius terminal resulting from hurricane activity in the third quarter of 2017. For the year ended December 31, 2016, we recorded other expense, net of $58.8 million, mainly due to an impairment charge of $58.7 million recognized on the Axeon Term Loan.
Income tax expense decreased $2.0$4.0 million for the year ended December 31, 2017, compared2021, which is included in “Operating expenses” in the consolidated statements of income (loss) and relates to the year ended December 31, 2016, primarily due to reductionsa fire in withholding taxes related to certainOctober 2019 at our terminal facility in Selby, California.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
Financial Highlights
(Thousands of Dollars, Except Unit and Per Unit Data)Contents
|
| | | | | | | | | | | |
| | Year Ended December 31, | | |
| | 2016 | | 2015 | | Change |
| Statement of Income Data: | |
| Revenues: | | | | | |
| Service revenues | $ | 1,083,165 |
| | $ | 1,114,153 |
| | $ | (30,988 | ) |
| Product sales | 673,517 |
| | 969,887 |
| | (296,370 | ) |
| Total revenues | 1,756,682 |
| | 2,084,040 |
| | (327,358 | ) |
| | | | | | |
| Costs and expenses: | | | | | |
| Cost of product sales | 633,653 |
| | 907,574 |
| | (273,921 | ) |
| Operating expenses | 448,367 |
| | 473,031 |
| | (24,664 | ) |
| General and administrative expenses | 98,817 |
| | 102,521 |
| | (3,704 | ) |
| Depreciation and amortization expense | 216,736 |
| | 210,210 |
| | 6,526 |
|
| Total costs and expenses | 1,397,573 |
| | 1,693,336 |
| | (295,763 | ) |
| | | | | | |
| Operating income | 359,109 |
| | 390,704 |
| | (31,595 | ) |
| Interest expense, net | (138,350 | ) | | (131,868 | ) | | (6,482 | ) |
| Other (expense) income, net | (58,783 | ) | | 61,822 |
| | (120,605 | ) |
| Income from continuing operations before income tax expense | 161,976 |
| | 320,658 |
| | (158,682 | ) |
| Income tax expense | 11,973 |
| | 14,712 |
| | (2,739 | ) |
| Income from continuing operations | 150,003 |
| | 305,946 |
| | (155,943 | ) |
| Income from discontinued operations, net of tax | — |
| | 774 |
| | (774 | ) |
| Net income | $ | 150,003 |
| | $ | 306,720 |
| | $ | (156,717 | ) |
| Basic and diluted net income per common unit: | | | | |
|
|
| Continuing operations | $ | 1.27 |
| | $ | 3.29 |
| | $ | (2.02 | ) |
| Discontinued operations | — |
| | 0.01 |
| | (0.01 | ) |
| Total | $ | 1.27 |
| | $ | 3.30 |
| | $ | (2.03 | ) |
| Basic weighted-average common units outstanding | 78,080,484 |
| | 77,886,078 |
| | 194,406 |
|
Annual Overview
Net income decreased $156.7 millionThe following table presents operating highlights for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to a $58.7 million impairment charge on the Axeon Term Loan in 2016 and a $56.3 million gain associatedstorage segment:
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | |
| | 2022 | | 2021 | | Change |
| (Thousands of Dollars, Except Barrel Data) |
| Storage Segment: | | | | | |
| Throughput (barrels/day) (a) | 480,129 | | | 516,094 | | | (35,965) | |
| | | | | |
| Throughput terminal revenues | $ | 110,591 | | | $ | 122,331 | | | $ | (11,740) | |
| Storage terminal revenues | 223,958 | | | 305,337 | | | (81,379) | |
| Total revenues | 334,549 | | | 427,668 | | | (93,119) | |
| Operating expenses | 154,270 | | | 185,597 | | | (31,327) | |
| Depreciation and amortization expense | 73,076 | | | 87,500 | | | (14,424) | |
| Goodwill impairment loss | — | | | 34,060 | | | (34,060) | |
| Other impairment losses | 46,122 | | | 95,711 | | | (49,589) | |
| Segment operating income | $ | 61,081 | | | $ | 24,800 | | | $ | 36,281 | |
(a)Prior period throughputs for our Corpus Christi North Beach terminal were restated consistent with the Linden Acquisition in 2015. In addition, segment operating income decreased $35.3 million, resulting mainly from reductions in operating income for the pipeline and fuels marketing segments.current period presentation.
Segment Operating Highlights
(Thousands of Dollars, Except Barrel/Day Information)
|
| | | | | | | | | | | |
| | Year Ended December 31, | | |
| | 2016 | | 2015 | | Change |
| Pipeline: | | | | | |
| Refined products pipelines throughput (barrels/day) | 535,946 |
| | 522,146 |
| | 13,800 |
|
| Crude oil pipelines throughput (barrels/day) | 392,181 |
| | 471,632 |
| | (79,451 | ) |
| Total throughput (barrels/day) | 928,127 |
| | 993,778 |
| | (65,651 | ) |
| Throughput revenues | $ | 485,650 |
| | $ | 508,522 |
| | $ | (22,872 | ) |
| Operating expenses | 147,858 |
| | 153,222 |
| | (5,364 | ) |
| Depreciation and amortization expense | 89,554 |
| | 84,951 |
| | 4,603 |
|
| Segment operating income | $ | 248,238 |
| | $ | 270,349 |
| | $ | (22,111 | ) |
| | | | | | |
| Storage: | | | | | |
| Throughput (barrels/day) | 789,065 |
| | 899,606 |
| | (110,541 | ) |
| Throughput terminal revenues | $ | 117,586 |
| | $ | 130,127 |
| | $ | (12,541 | ) |
| Storage terminal revenues | 492,456 |
| | 494,781 |
| | (2,325 | ) |
| Total revenues | 610,042 |
| | 624,908 |
| | (14,866 | ) |
| Operating expenses | 276,578 |
| | 290,322 |
| | (13,744 | ) |
| Depreciation and amortization expense | 118,663 |
| | 116,768 |
| | 1,895 |
|
| Segment operating income | $ | 214,801 |
| | $ | 217,818 |
| | $ | (3,017 | ) |
| �� | | | | | |
| Fuels Marketing: | | | | | |
| Product sales and other revenue | $ | 681,934 |
| | $ | 976,216 |
| | $ | (294,282 | ) |
| Cost of product sales | 645,355 |
| | 922,906 |
| | (277,551 | ) |
| Gross margin | 36,579 |
| | 53,310 |
| | (16,731 | ) |
| Operating expenses | 33,173 |
| | 39,803 |
| | (6,630 | ) |
| Segment operating income | $ | 3,406 |
| | $ | 13,507 |
| | $ | (10,101 | ) |
| | | | | | |
| Consolidation and Intersegment Eliminations: | | | | | |
| Revenues | $ | (20,944 | ) | | $ | (25,606 | ) | | $ | 4,662 |
|
| Cost of product sales | (11,702 | ) | | (15,332 | ) | | 3,630 |
|
| Operating expenses | (9,242 | ) | | (10,316 | ) | | 1,074 |
|
| Total | $ | — |
| | $ | 42 |
| | $ | (42 | ) |
| | | | | | |
| Consolidated Information: | | | | | |
| Revenues | $ | 1,756,682 |
| | $ | 2,084,040 |
| | $ | (327,358 | ) |
| Cost of product sales | 633,653 |
| | 907,574 |
| | (273,921 | ) |
| Operating expenses | 448,367 |
| | 473,031 |
| | (24,664 | ) |
| Depreciation and amortization expense | 208,217 |
| | 201,719 |
| | 6,498 |
|
| Segment operating income | 466,445 |
| | 501,716 |
| | (35,271 | ) |
| General and administrative expenses | 98,817 |
| | 102,521 |
| | (3,704 | ) |
| Other depreciation and amortization expense | 8,519 |
| | 8,491 |
| | 28 |
|
| Consolidated operating income | $ | 359,109 |
| | $ | 390,704 |
| | $ | (31,595 | ) |
Pipeline
TotalThroughput terminal revenues decreased $22.9$11.7 million and total throughputs decreased 65,65135,965 barrels per day for the year ended December 31, 2016,2022, compared to the year ended December 31, 2015, primarily due to:
a decrease in revenues of $36.3 million and a decrease in throughputs of 81,779 barrels per day on our Eagle Ford System due to reduced production resulting from a sustained low crude oil price environment;
a decrease in revenues of $7.1 million and a decrease in throughputs of 6,586 barrels per day on our Ammonia Pipeline partly due to a shipper’s facility reconfiguration, resulting in fewer barrels available for transportation, and maintenance downtime on a portion of the pipeline; and
a decrease in revenues of $3.9 million and a decrease in throughputs of 1,551 barrels per day on our Ardmore System due to operational issues and a turnaround at our customer’s Ardmore refinery in 2016, as well as increased short-haul deliveries resulting in lower average tariffs.
Those decreases in pipeline revenues and throughputs were partially offset by:
an increase in revenues of $12.1 million and an increase in throughputs of 14,803 barrels per day on our McKee and Three Rivers System pipelines due to higher demand in those markets, increased production at our customer’s McKee refinery and increased volumes on pipelines with higher average tariffs;
an increase in revenues of $9.6 million and an increase in throughputs of 11,441 barrels per day on our East Pipeline,2021, mainly due to the completion of various expansion projects beginning in the fourth quarter of 2015, unfavorable pricing differentials in 2015 in markets served by the East Pipeline and lower throughputs in 2015 due to maintenance downtime on a portion of the pipeline; and
an increase in revenues of $3.4 million and an increase in throughputs of 1,392 barrels per day on our North Pipeline due to increased refinery production shipped via pipeline and increased long-haul deliveries resulting in higher average tariffs.
Operating expenses decreased $5.4 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to lower operating expenses of $8.7 million on our Eagle Ford System, consistent with the decrease in throughputs. The decrease in pipeline operating expenses was partially offset by higher maintenance and regulatory expenses of $3.2 million, mainly on our Central West Refined Products Pipelines.
Depreciation and amortization expense increased $4.6 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, mainly due to the completion of pipeline projects.
Storage
Throughput terminal revenues decreased $12.5 million and throughputs decreased 110,541 barrels per day for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to:
a decrease in revenues of $10.9 million and a decrease in throughputs of 82,177 barrels per day at our Corpus Christi North Beach terminal due to (i) a decreasedecline in Eagle Ford Shale crude oil being shippedexport demand and changes to Corpus Christi, consistent with the decrease in pipeline throughputs and (ii) the completion of a pipeline expansion project in the first quarter of 2016, in which we transport volumes from North Beach to our customer’s refineries, thus reducing volumes moved over our docks; andcustomer contract.
a decrease in revenues of $3.3 million and a decrease in throughputs of 35,497 barrels per day due to turnarounds at the refineries served by our Benicia and Corpus Christi crude oil storage tank facilities, as well as operational issues at a customer’s Corpus Christi refinery in 2016.
The decreases were partially offset by an increase in revenue of $3.0 million and an increase in throughputs of 9,044 barrels per day at our McKee and Three Rivers System terminals due to higher demand in those markets, as well as increased production at our customer’s McKee refinery.
Storage terminal revenues decreased $2.3$81.4 million for the year ended December 31, 2016,2022, compared to the year ended December 31, 2015. Revenues from our International Terminals decreased $17.7 million,2021, primarily due to ato:
•an aggregate decrease in revenues at our St. Eustatius terminal of $8.3$73.6 million resulting mainly from lower throughputdue to the Eastern U.S. Terminals Disposition in October 2021 and related handling fees, as well as the Point Tupper Terminal Disposition in April 2022; and
•a decrease in revenues of $5.9$21.1 million at our UK Terminals, mainlySt. James terminal due to fluctuationscustomers not renewing expiring contracts in foreign exchange rates. the current backwardated market.
These decreases were partially offset by the following:
•an increase of $15.3 million in domestic revenues. Domestic revenues increasedof $10.1 million fromat our West Coast Terminals, mainly at our Portland and Stockton terminals, primarily due to new contracts and higher throughput and handling fees;
•an increase in revenues of $1.6 million due to rate escalations on our refinery storage tanks; and
•an increase in revenues of $1.4 million at our Central West Terminals, mainly due to rate escalations and new customer contracts mainly at our Selby, CA, Linden, NJ, Blue Island, ILhigher throughput and Piney Point, MD terminals. In addition, revenues at our St. James, LA terminal increased $3.1 million due to completed terminal expansion projects.handling fees.
Operating expenses decreased $13.7$31.3 million for the year ended December 31, 2016,2022, compared to the year ended December 31, 2015,2021, primarily due to:
ato an aggregate decrease of $11.8 million in operating expenses at our Internationalof $46.6 million due to the Eastern U.S. Terminals Disposition in October 2021 and the Point Tupper Terminal Disposition in April 2022. This decrease was partially offset by the following:
•increases in reimbursable expenses of $4.1 million, mainly at our St. EustatiusJames terminal;
•a $4.0 million recovery in the first quarter of 2021 for business interruption insurance related to the 2019 Selby terminal facility due to higher propertyfire; and
•increases in compensation expense of $1.7 million, ad valorem taxes in 2015,of $1.2 million, additive and lower employee related costs and reimbursablechemical expenses in 2016;
a decrease of $3.1$1.1 million resulting from an insurance settlement for environmental remediation expenses incurred on a previously sold terminal; and
a decrease of $2.0 million resulting from lower wharfage and dockage costs at our Corpus Christi North Beach terminal.
The decreases in storage operating expenses were partially offset by a $3.9 million increase in regulatory and maintenance and regulatory expenses mainly at our Central West terminal facilitiesof $1.0 million, across various terminals.
Depreciation and $1.6 million in cancelled capital project costs.
Fuels Marketing
Segment operating incomeamortization expense decreased $10.1$14.4 million for the year ended December 31, 2016,2022, compared to the year ended December 31, 2015, primarily2021, mainly due to a decreasethe Eastern U.S. Terminals Disposition in gross marginOctober 2021 and the Point Tupper Terminal Disposition in April 2022.
FUELS MARKETING SEGMENT
The fuels marketing segment mainly includes our fuel oil trading and bunker fuelbunkering operations respectively.in the Gulf Coast, as well as certain of our blending operations associated with our Central East System. The lower gross margins were partially offset by a reduction in operating expensesresults of $6.6 million mainly from our bunker fuel operations due to lower bad debt expense and decreased product inspection and marine vessel costs.
Consolidation and Intersegment Eliminations
Revenue and operating expense eliminations primarily relate to storage fees charged tofor the fuels marketing segment depend largely on the margin between our costs and the sales prices of the products we market. Therefore, the results of operations for this segment are more sensitive to changes in commodity prices compared to the operations of the pipeline and storage segments. We enter into derivative contracts to attempt to mitigate the effects of commodity price fluctuations. The financial impacts of the derivative financial instruments associated with commodity price risk were not material for any periods presented. Fluctuations in global demand for crude oil, which was caused by many economic factors outside of our control, has caused volatility in commodity prices and volumes in 2022 and 2021, for our blending operations and bunker fuel sales.
Customers for bunker fuel sales are mainly ship owners, including cruise line companies, marketers and traders. In the storage segment. Costsale of product sales eliminations represent expenses charged tobunker fuel, we compete with ports offering bunker fuels that are along the route of travel of the vessel. One of our customers, a marketer of petroleum products, was the largest customer of our fuels marketing segment and accounted for approximately 16% of the total segment revenues for the year ended December 31, 2022. No other customer accounted for a significant portion of the total revenues of the fuels marketing segment for costs associated with inventory that are expensed once the inventory is sold.year ended December 31, 2022.
Results of Operations
GeneralThe following table presents operating highlights for the fuels marketing segment:
General and administrative expenses decreased $3.7 | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | |
| | 2022 | | 2021 | | Change |
| (Thousands of Dollars) |
| Fuels Marketing Segment: | | | | | |
| Product sales | $ | 520,486 | | | $ | 428,608 | | | $ | 91,878 | |
| Cost of goods | 484,477 | | | 417,000 | | | 67,477 | |
| Gross margin | 36,009 | | | 11,608 | | | 24,401 | |
| Operating expenses | 2,473 | | | 427 | | | 2,046 | |
| | | | | |
| | | | | |
| Segment operating income | $ | 33,536 | | | $ | 11,181 | | | $ | 22,355 | |
| | | | | |
Segment operating income increased $22.4 million for the year ended December 31, 2016,2022, compared to the year ended December 31, 2015, primarily2021, mainly due to a decreasean increase of $12.4 million in employee benefit costs which was partially offsetgross margins from our bunkering operations and an increase of $11.4 million in gross margins from our blending and other product sales, both driven by higher fuel prices on product sales.
Operating expenses increased compensation expense associated with our long-term incentive plan.
Interest expense, net increased $6.5$2.0 million for the year ended December 31, 2016,2022, compared to the year ended December 31, 2015,2021, primarily due to increased interest costs associated with higher borrowings under our revolving credit agreement, as well as lower capitalized interest resulting from fewer capital projects.
For the year ended December 31, 2016,a settlement of $1.7 million we recorded other expense, net of $58.8 million, mainly due to an impairment charge of $58.7 million recognized on the Axeon Term Loan. For the year ended December 31, 2015, we recorded other income, net of $61.8 million, mainly due to the $56.3 million gain associated with the Linden Acquisition.
Income tax expense decreased $2.7 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to lower margin taxreceived in Texas, a decrease in the UK tax rate and a reduction in our St. Eustatius and Canada withholding tax. Please refer to Note 24 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion on income taxes.
TRENDS AND OUTLOOK
As discussed in more detail in Note 28 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data,” we and NuStar GP Holdings entered into the Merger Agreement to simplify our corporate structure. At the closing of the Merger, which is subject to, among other things, approval of the NSH unitholders: (i) NuStar Energy will issue 0.55 of an NS common unit for each outstanding NSH unit; (ii) NSH’s economic rights in the 2% general partner interest, the incentive distribution rights (the IDRs) in NS and the NS common units held by NSH will be cancelled; and (iii) NS will pay off and cancel NSH’s obligations under its revolving credit agreement.
We believe simplifying our corporate structure and eliminating the IDRs will lower our cost of capital and create a more efficient and transparent structure. In addition, management anticipates recommending, and the NuStar Energy board of directors indicated it intends to approve, resetting NuStar Energy’s quarterly distribution from $1.095 per common unit to $0.60 per common unit, effective with the first quarter 2018 distribution. We expectof 2021 for a credit loss that resetting our distribution will improve our ability to fund cash requirements immediately, and, in the longer-term, will also serve to improve our leverage metrics and reduce our future need to access the capital markets.was previously written off.
Historically, master limited partnerships (MLPs), like NuStar Energy, have typically funded strategic capital expenditures and acquisitions from external sources, primarily through borrowings under revolving credit agreements and issuance of equity and debt securities. In the past few years, the total number of, and aggregate amount raised by, MLP common equity issuances has dropped dramatically, and MLPs with low coverage and high leverage have found it increasingly difficult to issue common equity. Through the combination of the simplification and distribution reset discussed above, we expect to be able to fund a larger proportion of our capital projects with the cash generated by our operations, which should, over time, reduce our need to access capital markets to finance future growth opportunities.
During 2017, our legacy pipeline systems and storage assets, other than our Permian Crude System, faced several unanticipated challenges, on top of the continuing burden of the third year of sustained low crude prices. In September, hurricanes caused damage in the Gulf of Mexico and significant destruction in the Caribbean. Hurricane Harvey’s heavy rainfall caused only minimal damage to our six affected Gulf Coast facilities, but Hurricane Irma passed almost directly over our facility at St. Eustatius, causing a temporary shutdown and inflicting substantial damage. We received hurricane insurance proceeds of $12.5 million in the fourth quarter of 2017 and $87.5 million in January 2018. We expect to recognize a gain in our first quarter 2018 results equal to the amount by which the insurance proceeds received exceed our actual expense incurred during the period, or approximately $85 million. At this time, we expect that costs incurred, over and above our deductible amount, will be covered by the insurance proceeds we have already received. We expect these repairs to continue through next year and into 2020.
Due to that fact that some of our current committed shippers’ contracts on our South Texas Crude System expire in the second half of 2018, as well as our assessment of the current market conditions in the Eagle Ford, our 2018 forecast reflects our expectation that some of those customers will decline to renew their commitments and demand rates lower than previously contracted rates. As a result, we are projecting lower throughput and rates for the South Texas Crude System in the second half of 2018, which we expect to result in lower revenues for that system during 2018 as compared to 2017.
Since we agree with the many energy experts who currently predict that backwardation, which tends to decrease demand for storage capacity, will continue through 2018, our 2018 forecast reflects lower storage rates and contract renewals at certain of our facilities, which we expect to result in lower revenues for those facilities during 2018 as compared to 2017.
In January 2018, as a result of the widely reported economic strife in Venezuela and the mounting financial and operational challenges facing our St. Eustatius anchor tenant, Petróleos de Venezuela, S.A. (PDVSA), we reduced our expectations for their utilization of the terminal during 2018 to reflect a more conservative outlook. In 2017 and this year so far, news outlets around the world have reported the dramatic deterioration of economic conditions in Venezuela, and during 2017, we saw PDVSA’s activity at the terminal decrease to levels well below their historical levels. In addition, in August 2017, the United States imposed sanctions against Venezuela intended to limit PDVSA’s access to credit, and the Trump Administration has announced it may also ban imports of Venezuelan crude into the U.S. and export of U.S. refined products to Venezuela. If implemented, these additional sanctions, together with the current sanctions, could have a significant negative impact on Venezuela and on PDVSA.
Largely due to the impact we believe those negative factors may have on PDVSA and their utilization of our facility, our current forecast reflects our expectation that our 2018 results of operations of our storage segment will be lower than 2017 and that it properly reflects our conservative assessment of significant uncertainty and risk surrounding PDVSA’s ability to perform this year. That being said, since early January PDVSA’s activity at the terminal has increased, and, if they are able to continue this trend through all or a portion of the year, all other factors remaining constant, we could see improvement in our revenue generated for St. Eustatius, in comparison with our current forecast for 2018, as the year progresses. While we are hopeful that
PDVSA will maintain its current activity and we continue to work to retain them as an important customer, we also continue to closely monitor PDVSA’s activity and financial well-being and are working to diversify our St. Eustatius facility customer base.
While our outlook for 2018 reflects all the challenges we have described, we believe that the consummation of the Merger and our board of director’s approval of our recommended reset to our distribution will immediately increase our cash available to pay for capital expenditures, and, over time, will improve our leverage metrics. We expect these steps to strengthen our balance sheet in 2018 and beyond. We also project that the Permian Crude System will continue to grow, and we expect its positive contributions to our pipeline segment’s overall results to grow accordingly.
Our outlook for the partnership, both overall and for any of our segments, may change, as we base our expectations on our continuing evaluation of a number of factors, many of which are outside our control. These factors include, but are not limited to, the state of the economy and the capital markets, changes to our customers’ refinery maintenance schedules and unplanned refinery downtime, crude oil prices, the supply of and demand for crude oil, refined products and anhydrous ammonia, demand for our transportation and storage services and changes in laws or regulations affecting our assets.
LIQUIDITY AND CAPITAL RESOURCES
The following sections are included in Liquidity and Capital Resources:
•Overview
•Cash Flows
•Sources of Liquidity
•Material Cash Requirements
OVERVIEW
Our primary cash requirements are for distributions to our partners, debt service, capital expenditures acquisitions and operating expenses.
Our partnership agreement requires that we distribute all “Available Cash” to our common limited partners and general partner each quarter, and this termquarter. “Available Cash” is defined in the partnership agreement generally as cash on hand at the end of the quarter, plus certain permitted borrowings made subsequent to the end of the quarter, less cash reserves determined by our board of directors. After the Merger,directors, subject to requirements for distributions for our general partner will no longer receive incentive distributions or quarterly cash distributions, related to its ownership interest, from us. Additionally, on February 8, 2018, we announced that our management anticipates recommending to the board of directors of NuStar GP, LLC, and the board of directors expects to adopt, a reset of our quarterly distribution per common unit to $0.60 ($2.40 on an annualized basis), starting with the first-quarter distribution payable in May 2018. Please refer to Note 28 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the Merger.
Each year, our objective is to fund our reliability capital expenditures and distribution requirements with our net cash provided by operating activities during that year. If we do not generate sufficient cash from operations to meet that objective, we utilize cash on hand or other sources of cash flow, which in the past have primarily included borrowings under our revolving credit agreement, sales of non-strategic assets and, to the extent necessary, funds raised through equity or debt offerings under our shelf registration statements.preferred units. We have typically funded our strategic capital expenditures and acquisitions from external sources, primarily borrowings under our revolving credit agreement or funds raised through equity or debt offerings. However, our ability to raise funds by issuing debt or equity depends on many factors beyond our control. Our risk factors in Item 1A. “Risk Factors” describe the risks inherent to these sources of funding and the availability thereof.
During periods when our cash flow from operations is less than our distribution and reliability capital requirements, we may maintain our distribution level because we can usewith other sources of Available Cash, as provided in our partnership agreement, including borrowings under our revolving credit agreement and proceeds from the sales of assets.
The following chart shows our sources and uses of cash for 2022 and 2021:
In 2022 and 2021, we were able to fund all of our expenses, distribution requirements and capital expenditures using internally generated cash flows. We reduced our leverage to position ourselves to repurchase 6,900,000 of our Series D Cumulative Convertible Preferred Units in November 2022, representing approximately one-third of the outstanding units, using borrowings under our $1.0 billion unsecured revolving credit agreement.
For the full-year 2023, we expect to fund all of our expenses, distribution requirements and capital expenditures using internally generated cash flows.
Our risk factorsSeries D Cumulative Convertible Preferred Units (Series D Preferred Units) become redeemable, at our option, beginning in Item 1A. “Risk Factors” describe2023, which coincides with an increase in the risks inherentdistribution rate of those units. Beginning in 2028, the holders of the Series D Preferred Units have the option to require us to redeem their units, and we have taken steps to position ourselves to repurchase or redeem the Series D Preferred Units in advance of the possible mandatory redemption. We plan to redeem the remaining 16,346,650 of Series D Preferred Units outstanding in 2023 and 2024, which is several years ahead of the holders’ redemption option in 2028. We will also continue to evaluate other sources of liquidity to facilitate the planned redemption of the remaining Series D Preferred Units in 2023 and 2024.
We have no long-term debt maturities until 2025, and we expect to be able to access debt capital markets to refinance those maturities.
A discussion of our cash flows and other changes in financial position for 2020 can be found in Items 1., 2. and 7. “Business, Properties and Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our ability to maintain or grow our distribution.
ForAnnual Report on Form 10-K for the year ended December 31, 2017, our cash flow from operations did not exceed our distributions to our partners and our reliability capital expenditures. See below for discussion. For 2018, we expect to generate sufficient cash from operations to exceed our distribution and reliability capital requirements. Although we expect higher interest costs due to our issuances of debt and equity securities in 2017, we expect a decrease in distributions as a result of2021 filed with the distribution reset and the Merger discussed above. See below for additional discussion of our 2017 equity and debt issuances.SEC on February 24, 2022.
Cash Flows for the Years Ended DecemberCASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2017, 2016 and 20152022 AND 2021
The following table summarizes our cash flows from operating, investing and financing activities (please refer to our Consolidated Statements of Cash Flows in Item 8. “Financial Statements and Supplementary Data”):.
| | | | Year Ended December 31, | | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | | 2022 | | 2021 | |
| | (Thousands of Dollars) | | (Thousands of Dollars) |
| Net cash provided by (used in): | | | | | | Net cash provided by (used in): | | |
| Operating activities | $ | 406,799 |
| | $ | 436,761 |
| | $ | 524,937 |
| Operating activities | $ | 527,549 | | | $ | 501,478 | | |
| Investing activities | (1,696,441 | ) | | (311,078 | ) | | (452,029 | ) | Investing activities | (84,365) | | | 75,978 | | |
| Financing activities | 1,276,272 |
| | (211,324 | ) | | (29,229 | ) | Financing activities | (434,953) | | | (725,579) | | |
| Effect of foreign exchange rate changes on cash | 1,720 |
| | 2,721 |
| | (12,729 | ) | Effect of foreign exchange rate changes on cash | 707 | | | 136 | | |
| Net (decrease) increase in cash and cash equivalents | $ | (11,650 | ) | | $ | (82,920 | ) | | $ | 30,950 |
| |
| Net increase (decrease) in cash, cash equivalents and restricted cash | | Net increase (decrease) in cash, cash equivalents and restricted cash | $ | 8,938 | | | $ | (147,987) | | |
For the years ended December 31, 2022 and 2021, net cash provided by operating activities exceeded our distributions to unitholders, reliability capital expenditures and strategic capital expenditures.
Net cash provided by operating activities for the year ended December 31, 2017 was $406.8 million, compared to $436.8increased by $26.1 million for the year ended December 31, 2016,2022, compared to the year ended December 31, 2021, primarily due to higher net income and changes in working capital. Generally, working capital requirements are affected by our accounts receivable, accounts payable and accrued interest payable balances, which vary depending on the timing of payments. Our working capital increaseddecreased by $26.5$0.7 million for the year ended December 31, 2017,2022, compared to a decreasean increase of $3.7$14.1 million for the year ended December 31, 2016. Please refer2021, mainly due to changes in the timing of payments related to accrued interest payable due to the “Working Capital Requirements” section belowrepayment of senior notes in February and November 2021. Cash flows from operating activities for a discussionthe years ended December 31, 2022 and 2021 include $1.3 million and $19.1 million, respectively, of insurance proceeds related to cleanup costs and business interruption from the changes in working capital.2019 Selby terminal fire.
For the year ended December 31, 2017,2022, we recorded net cash used in investing activities of $84.4 million, compared to net cash provided by operatinginvesting activities the proceeds from the termination of the Axeon Term Loan of $110.0$76.0 million and cash on hand were used to fund our distributions to unitholders and our general partner in the aggregate amount of $485.1 million and reliability capital expenditures of $57.5 million. Proceeds from our debt and
equity issuances of approximately $1.5 billion were used to fund the purchase price of the Navigator Acquisition. The proceeds from debt borrowings, net of repayments, remaining proceeds from our equity issuances and cash on hand were used to fund our other strategic capital expenditures.
Forfor the year ended December 31, 2016, net cash provided2021, primarily due to lower proceeds from asset sales of $187.2 million, partially offset by operating activities primarily was used to fund our distributions to
unitholders and our general partnera decrease in the aggregate amount of $393.0 million and reliability capital expenditures of $38.2
$40.5 million. ProceedsCash flows from investing activities also include insurance proceeds related to the issuance2019 Selby terminal fire of common and preferred units and cash on hand were used to fund our strategic capital expenditures, including the Martin Terminal Acquisition.
For$9.8 million for the year ended December 31, 2015,2022, compared to $9.4 million for the majority ofyear ended December 31, 2021.
Net cash used in financing activities decreased by $290.6 million for the year ended December 31, 2022, compared to the year ended December 31, 2021, mainly due to net cash provided by operating activities was used to fund our distributions to unitholders and our general partner in the aggregate amount of $392.2 million and to fund $40.0 million of reliability capital expenditures. The proceeds from debt borrowings of $106.6 million for the year ended December 31, 2022, compared to net debt repayments of repayments, combined with a portion$412.7 million for the year ended December 31, 2021, mainly due to the timing of net cash provided by operating activities,asset sales as proceeds were used to fundrepay debt borrowings, and the repurchase of 6,900,000 of our strategic capital expenditures, including the Linden Acquisition.Series D Preferred Units in November 2022.
Debt Sources of Liquidity
SOURCES OF LIQUIDITY
Revolving Credit Agreement.On August 22, 2017,Agreement
As of December 31, 2022, NuStar Logistics amended itsLogistics’ $1.0 billion unsecured revolving credit agreement (the Revolving Credit Agreement), mainly to extend had $775.3 million available for borrowing and $220.0 million of borrowings outstanding. Letters of credit issued under the maturity date from October 29, 2019 to October 29, 2020, and to increase the borrowing capacity from $1.50 billion to $1.75 billion. The Revolving Credit Agreement includestotaled $4.7 million as of December 31, 2022. Letters of credit limit the ability toamount we can borrow up tounder the equivalent of $250.0 million in Euros and up to the equivalent of $250.0 million in British Pounds Sterling.Revolving Credit Agreement. Obligations under the Revolving Credit Agreement are guaranteed by NuStar Energy and NuPOP.
The Revolving Credit Agreement was also amendedis subject to increasemaximum consolidated debt coverage ratio and minimum consolidated interest coverage ratio requirements, which may limit the amount we can borrow to an amount less than the total amount available for borrowing. For the rolling period of four quarters ending December 31, 2022, the maximum allowed consolidated debt coverage ratio (as defined in the Revolving Credit Agreement) from 5.00-to-1.00 to 5.50-to-1.00 through the rolling period ending March 31, 2018. Subsequently, the maximum allowed consolidated debt coverage ratio maycould not exceed 5.00-to-1.00 for any rolling period ending on or after June 30, 2018. If we complete one or more acquisitions for aggregate net consideration of at least $50.0 million, our maximumand the minimum consolidated debtinterest coverage ratio will increase to 5.50-to-1.00 for two rolling periods. On November 22, 2017,(as defined in the Revolving Credit Agreement was amended to continue to exclude our $402.5 million fixed-to-floating rate subordinated notes from the definition of consolidated debt for purposes of calculating our consolidated debt coverage ratio through December 31, 2018.Agreement) must not be less than 1.75-to-1.00. The Revolving Credit Agreement also contains customary restrictive covenants, such as limitations on indebtedness, liens, mergers, asset transfers and
certain investing activities.
The requirement not to exceed a maximum consolidated debt coverage ratio may limit the amount we can borrow under the Revolving Credit Agreement to an amount less than the total amount available for borrowing. As of December 31, 2017,2022, our consolidated debt coverage ratio was 4.9x3.98x and our consolidated interest coverage ratio was 2.17x.
On January 28, 2022, we had $853.0 million available for borrowing.
Lettersamended and restated the Revolving Credit Agreement primarily to: (i) extend the maturity date from October 27, 2023 to April 27, 2025; (ii) increase the maximum amount of letters of credit capable of being issued from $400.0 million to $500.0 million; (iii) replace London Interbank Offering Rate, or LIBOR, benchmark provisions with customary secured overnight financing rate, or SOFR, benchmark provisions; (iv) remove the 0.50x increase permitted in our consolidated debt coverage ratio for certain rolling periods in which an acquisition for aggregate net consideration of at least $50.0 million occurs; and (v) add baskets and exceptions to certain negative covenants. Following the amendment, borrowings under the Revolving Credit Agreement totaled $3.7 millionbear interest, at our option, at an alternate base rate or a SOFR rate, each as of December 31, 2017. Letters of credit are limited to $400.0 million (including up to the equivalent of $25.0 milliondefined in Euros and up to the equivalent of $25.0 million in British Pounds Sterling) and also may restrict the amount we can borrow under the Revolving Credit Agreement.
The interest rate on the Revolving Credit Agreement and certain fees under the Receivables Financing Agreement. Agreement, defined below, are the only debt arrangements that are subject to adjustment if our debt rating is downgraded (or upgraded) by certain credit rating agencies. The following table reflects the current ratings and outlook that have been assigned to our debt:
| | | | | | | | | | | | | | | | | |
| Fitch Ratings | | Moody’s Investor Service Inc. | | S&P Global Ratings |
| Ratings | BB- | | Ba3 | | BB- |
| Outlook | Stable | | Stable | | Stable |
Receivables Financing Agreement
NuStar Energy and NuStar Finance LLC (NuStar Finance), a special purpose entity and wholly owned subsidiary of NuStar Energy, are parties to a $125.0$100.0 million receivables financing agreement with a third-party lenderslender (the Receivables Financing Agreement) and agreements with certain of NuStar Energy’s wholly owned subsidiaries (collectively(together with the Receivables Financing Agreement, the Securitization Program). On September 20, 2017, the Securitization Program was amended to add certain of NuStar Energy’s wholly owned subsidiaries resulting from the Navigator Acquisition and to extend the Securitization Program’s scheduled termination date from June 15, 2018 to September 20, 2020, with the option to renew for additional 364-day periods thereafter. The amount available for borrowing under the Receivables Financing Agreement is based on the availability of eligible receivables and other customary factors and conditions. The Securitization Program contains various customary affirmative and negative covenants and default, indemnification and termination provisions, and the Receivables Financing Agreement provides for acceleration of amounts owed upon the occurrence of certain specified events.
IssuanceOn January 28, 2022, the Receivables Financing Agreement was amended primarily to: (i) extend the scheduled termination date from September 20, 2023 to January 31, 2025; (ii) reduce the floor rate in the calculation of 5.625% Senior Notes. On April 28, 2017, NuStar Logistics issued $550.0 million of 5.625% senior notes due April 28, 2027. We used the net proceeds of $543.3 million from the offering to fund a portion of the purchase price for the Navigator Acquisitionour borrowing rates; and to pay(iii) replace provisions related fees and expenses. Interest on the 5.625% senior notes is payable semi-annually in arrears on April 28 and October 28 of each year beginning on October 28, 2017. The 5.625% senior notes do not have sinking fund requirements. These notes rank equally with existing senior unsecured indebtedness and senior to existing subordinated indebtedness of NuStar Logistics. The 5.625% senior notes contain restrictions on NuStar Logistics’ ability to incur secured indebtedness unless the same security is also provided for the benefit of holders of the senior notes. In addition, the senior notes
limit NuStar Logistics’ ability to incur indebtedness secured by certain liens, engage in certain sale-leaseback transactions and engage in certain consolidations, mergers or asset sales.
Other Debt Sources of Liquidity. Other sources of liquidity consist of the following:
$365.4 million in revenue bonds pursuant to the Gulf Opportunity Zone ActLIBOR rate of 2005 (the GoZone Bonds),interest with $42.5 million remainingreferences to SOFR rates of interest. Following the amendment, borrowings under the Receivables Financing Agreement bear interest, at NuStar Finance’s option, at a base rate or a SOFR rate, each as defined in trust as of December 31, 2017, supported by $370.2 million in letters of credit; andthe Receivables Financing Agreement.
two short-term line of credit agreements with an aggregate uncommitted borrowing capacity of up to $85.0 million, with $35.0 million of borrowings outstanding as of December 31, 2017.
Please refer to Note 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of our debt agreements.
LOC Agreement
NuStar Logistics is a party to a $100.0 million uncommitted letter of credit agreement, which provides for standby letters of credit or guarantees with a term of up to one year (LOC Agreement). Any letters of credit issued under the LOC Agreement do not reduce availability under the Revolving Credit Agreement. As of December 31, 2017, we had no letters of credit issued under the LOC Agreement.
RepatriationAsset Sales
We may repatriate a portion of undistributed foreign earnings in order to provide greater flexibility to meet cash flow needs. Duringutilized the years ended December 31, 2017 and 2016, we repatriated $9.5 million and $110.8 million, respectively, of cash from our foreign subsidiaries. We will continue to evaluate our cash flow needs and may repatriate funds from our foreign subsidiaries as a source of liquidity.
Issuances of Units
In the fourth quarter of 2017, we issued 6,900,000 of our 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (Series C Preferred Units) representing limited partner interests at a price of $25.00 per unit. We used the net proceeds of $166.7 million from the issuance ofPoint Tupper Terminal Disposition in 2022 and the Series C Preferred Units for general partnership purposes, including the funding of capital expendituresEastern U.S. Terminals Disposition in 2021 to reduce debt and repayments of outstanding borrowings under the Revolving Credit Agreement.improve our debt metrics.
OnApril 28, 2017, we issued 15,400,000 of our Series B Preferred Units representing limited partner interests at a price of $25.00 per unit. We used the net proceeds of $371.8 million from the issuance of the Series B Preferred Units to fund a portion of the purchase price for the Navigator Acquisition and to pay related fees and expenses.
On April 18, 2017, we issued 14,375,000 common units representing limited partner interests at a price of $46.35 per unit. We used the net proceeds from this offering of $657.5 million, including a contribution of $13.6 million from our general partner to maintain its 2% general partner interest, to fund a portion of the purchase price for the Navigator Acquisition. Beginning with the distribution earned for the second quarter of 2017, our general partner will not receive incentive distributions with respect to these common units. Our general partner amended and restated our partnership agreement to waive up to an aggregate $22.0 million of the quarterly incentive distributions to our general partner for any NS common units issued from the date of the Navigator Acquisition agreement (other than those attributable to NS common units issued under any equity compensation plan) for ten consecutive quarters.
In the fourth quarter of 2016, we issued 9,060,000 of our 8.50% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (Series A Preferred Units) representing limited partner interests at a price of $25.00 per unit. We used the net proceeds of $218.4 million from this issuance for general partnership purposes, including the funding of capital expenditures and repayments of outstanding borrowings under the Revolving Credit Agreement.
During the year ended December 31, 2016, we issued 595,050 common units representing limited partner interests at an average price of $47.39 per unit for proceeds of $28.3 million, net of $0.5 million of issuance costs. We used these proceeds, which include a contribution of $0.6 million from our general partner to maintain its 2% general partner interest, for general partnership purposes, including repayments of outstanding borrowings under the Revolving Credit Agreement.
Please refer to Note 19 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on these issuances.
MATERIAL CASH REQUIREMENTS
Capital RequirementsExpenditures
Our operations require significant investments to maintain, upgrade or enhance the operating capacity of our existing assets. Our capital expenditures consist of:
•strategic capital expenditures, such as those to expand or upgrade the operating capacity, increase efficiency or increase the earnings potential of existing assets, whether through construction or acquisition, as well as certain capital expenditures related to support functions; and
•reliability capital expenditures, such as those required to maintain the existingcurrent operating capacity of existing assets or extend their useful lives, as well as those required to maintain equipment reliability and safety.
The following table summarizes our capital expenditures:
| | | | | | | | | | | | | | | | | |
| Strategic Capital Expenditures | | Reliability Capital Expenditures | | Total |
| (Thousands of Dollars) |
| For the year ended December 31: | | | | | |
| 2022 | $ | 107,855 | | | $ | 32,775 | | | $ | 140,630 | |
| 2021 | $ | 140,867 | | | $ | 40,266 | | | $ | 181,133 | |
| | | | | |
| Expected for the year ended December 31, 2023 | $ 130,000 - 150,000 | | $ 25,000 - 35,000 | | |
Strategic capital expenditures for the years ended December 31, 2022 and the amount weDecember 31, 2021 mainly consisted of expansion projects on our Permian Crude System and Central West Refined Products Pipelines, as well as biofuel and other terminal projects at our West Coast Terminals. Reliability capital expenditures primarily related to maintenance upgrade projects at our terminals.
We expect to spendour strategic capital expenditures for 2018:
|
| | | | | | | | | | | | | | | |
| | Strategic | | | | |
| | Acquisitions and Investments in Other Long-Term Assets | | Capital Expenditures (a) | | Reliability Capital Expenditures (b) | | Total |
| | (Thousands of Dollars) |
| For the year ended December 31: | | | | | | | |
| 2017 | $ | 1,461,719 |
| | $ | 327,141 |
| | $ | 57,497 |
| | $ | 1,846,357 |
|
| 2016 | $ | 95,657 |
| | $ | 166,203 |
| | $ | 38,155 |
| | $ | 300,015 |
|
| 2015 | $ | 146,064 |
| | $ | 284,806 |
| | $ | 40,002 |
| | $ | 470,872 |
|
| | | | | | | | |
| Expected for the year ended December 31, 2018 | | | $ 360,000 - 390,000 |
| | $ 80,000 - 100,000 |
| | $ 440,000 - 490,000 |
|
| |
(a) | Strategic capital for 2015, 2016 and 2017 mainly consists of terminal expansions. In addition, strategic capital in 2015 includes the reactivation and conversion of our 200-mile pipeline between Mont Belvieu and Corpus Christi, Texas and strategic capital in 2017 includes pipeline expansions on our Permian Crude System. |
| |
(b) | Reliability capital expenditures primarily relate to maintenance upgrade projects at our terminals. |
For the year ended December 31, 2018, we expect a significant portion2023 to include spending of approximately $60.0 million on expansion projects to accommodate production growth in the Permian Basin and approximately $25.0 million on projects to expand our strategic capital spending to relate to our Permian Crude System and a significant portion of reliability capital spending to relate to hurricane damage repairs at our St. Eustatius facility.renewable fuels network on the West Coast. We continue to evaluate our capital budget and make changes as economic conditions warrant, and our actual capital expenditures for 2018 may increase or decrease from the budgeted amounts. We believe cash on hand, combined with the sources of liquidity previously described, will be sufficient to fund our capital expenditures in 2018, and our internal growth projects can be accelerated or scaled back depending on market conditions or customer demand. Therefore, our actual capital expenditures for 2023 may increase or decrease from the expected amounts noted above.
Working Capital Requirements
Working capital requirements, particularly in our fuels marketing segment, may vary with the seasonality of demand and the volatility of commodity prices for the products we market. This seasonality in demand and the volatility of commodity prices affect our accounts receivable and accounts payable balances, which vary depending on timing of payments.
During the year ended December 31, 2017, accounts payable decreased $30.4 million and inventories decreased $11.9 million, primarily due to our exit from our heavy fuels trading and crude oil marketing operations in 2017.
During the year ended December 31, 2016, accounts receivable increased $23.2 million and accounts payable increased $14.1 million, primarily due to the timing of payments related to our bunker fuel operations and crude oil trading activity.
During the year ended December 31, 2015, inventories decreased $16.8 million, mainly due to the continued decline in crude oil prices. In addition, inventory volumes decreased in 2015 primarily due to decreased bunker fuel operations activity. During the year ended December 31, 2015, accounts receivable decreased $67.3 million and accounts payable decreased $32.2 million, primarily due to decreased bunker fuel operations and crude oil trading activity.
Axeon Term Loan and Credit Support
On February 22, 2017, we settled and terminated the $190.0 million Axeon Term Loan, pursuant to which we also provided credit support, such as guarantees, letters of credit and cash collateral, as applicable, of up to $125.0 million to Axeon. We received $110.0 million in settlement of the Axeon Term Loan, and our obligation to provide ongoing credit support to Axeon ceased. In 2016, we recognized an impairment charge on the Axeon Term Loan of $58.7 million which is included in “Other (expense) income, net” in the consolidated statements of income. Please refer to Notes 7 and 15 of the Notes to Consolidated
Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on the Axeon Term Loan and related credit support.
Defined Benefit Plans Funding
During 2017, we contributed $11.2 million to our pension and postretirement benefit plans. We expect to contribute approximately $11.6 million to our pension and postretirement benefit plans in 2018, which principally represents contributions either required by regulations or laws or, with respect to unfunded plans, necessary to fund current benefits. Pension and postretirement benefit plans funding beyond 2018 is uncertain as the funding varies from year to year based upon changes in the fair value of the plan assets and actuarial assumptions.
Distributions
General Partner and Common Limited Partners. NuStar Energy’s partnership agreement determines the amount and priority of cash distributions that our unitholders and general partner may receive. The general partner receives a 2% distribution with respect to its general partner interest. The general partner is also entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds $0.60 per unit. For a detailed discussion of the incentive distribution targets, please read Item 5. “Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities.”
The following table reflects the allocation of total cash distributions to the general partner and common limited partners applicable to the period in which the distributions were earned:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (Thousands of Dollars, Except Per Unit Data) |
| General partner interest | $ | 9,252 |
| | $ | 7,877 |
| | $ | 7,844 |
|
| General partner incentive distribution | 45,669 |
| | 43,407 |
| | 43,220 |
|
| Total general partner distribution | 54,921 |
| | 51,284 |
| | 51,064 |
|
| Common limited partners’ distribution | 407,681 |
| | 342,598 |
| | 341,140 |
|
| Total cash distributions | $ | 462,602 |
| | $ | 393,882 |
| | $ | 392,204 |
|
| | | | | | |
| Cash distributions per unit applicable to common limited partners | $ | 4.38 |
| | $ | 4.38 |
| | $ | 4.38 |
|
Distribution payments to our general partner and common limited partners are made within 45 days after the end of each quarter as of a record date that is set after the end of each quarter. The following table summarizes information related to our quarterly cash distributions to our general partner and common limited partners:
|
| | | | | | | | | | | | |
| Quarter Ended | | Cash Distributions Per Unit | | Total Cash Distributions | | Record Date | | Payment Date |
| | | | | (Thousands of Dollars) | | | | |
| December 31, 2017 (a) | | $ | 1.095 |
| | $ | 115,267 |
| | February 8, 2018 | | February 13, 2018 |
| September 30, 2017 | | $ | 1.095 |
| | $ | 115,084 |
| | November 9, 2017 | | November 14, 2017 |
| June 30, 2017 | | $ | 1.095 |
| | $ | 115,083 |
| | August 7, 2017 | | August 11, 2017 |
| March 31, 2017 | | $ | 1.095 |
| | $ | 117,168 |
| | May 8, 2017 | | May 12, 2017 |
| |
(a) | The distribution was announced on January 29, 2018. |
Pursuant to the Merger Agreement and at the effective time of the Merger, our partnership agreement will be amended and restated to, among other things, cancel the incentive distribution rights held by our general partner and convert the 2% general partner interest in NuStar Energy held by our general partner into a non-economic management interest. As a result, after the Merger, our general partner will no longer receive incentive distributions or quarterly cash distributions related to its ownership interest from us. Please refer to Note 28 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the Merger.
Preferred Units. The following table provides the terms related to distributions for our Series A, Series B and Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (collectively, the Preferred Units):
|
| | | | | | | | | | |
| Units | | Fixed Distribution Rate per Annum (as a Percentage of the $25.00 Liquidation Preference per Unit) | | Fixed Distribution Rate per Unit per Annum | | Optional Redemption Date/Date at Which Distribution Rate Becomes Floating | | Floating Annual Rate (as a Percentage of the $25.00 Liquidation Preference per Unit) |
| Series A Preferred Units | | 8.50% | | $ | 2.125 |
| | December 15, 2021 | | Three-month LIBOR plus 6.766% |
| Series B Preferred Units | | 7.625% | | $ | 1.90625 |
| | June 15, 2022 | | Three-month LIBOR plus 5.643% |
| Series C Preferred Units | | 9.00% | | $ | 2.25 |
| | December 15, 2022 | | Three-month LIBOR plus 6.88% |
Distributions on the Preferred Unitsour preferred units are payable out of any legally available funds, accrue and are cumulative from the original issuance dates, and are payable on the 15th day (or next business day) of each of March, June, September and December of each year to holders of record on the first business day of each payment month. Please see Notes 17 and 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.
The distribution rates on the outstanding Series D Preferred Units are as follows: (i) 9.75% per annum ($0.619 per unit per distribution period) for the first two years (beginning with the September 17, 2018 distribution); (ii) 10.75% per annum ($0.682 per unit per distribution period) for years three through five; and (iii) the greater of 13.75% per annum ($0.872 per unit per distribution period) or the distribution per common unit thereafter. The number of Series D Preferred Units outstanding as of December 31, 2022 and 2021 totaled 16,346,650 and 23,246,650, respectively, as we repurchased an aggregate 6,900,000 of our Series D Preferred Units in November 2022. While the Series D Preferred Units are outstanding, the Partnership will be prohibited from paying distributions on any junior securities, including the common units, unless full cumulative distributions on the Series D Preferred Units (and any parity securities) have been, or contemporaneously are being, paid or set aside for payment through the most recent Series D Preferred Unit distribution payment date. Any Series D Preferred Unit distributions in excess of $0.635 may be paid, in the Partnership’s sole discretion, in additional Series D Preferred Units, with the remainder paid in cash. If we fail to pay in full any Series D Preferred Unit distribution amount, then, until we pay such distributions in full, the applicable distribution rate for those distribution periods shall be increased by $0.048 per Series D Preferred Unit. We would also be subject to other requirements.
Distribution information on our Series D Preferred Units is as follows:
| | | | | | | | | | | | | | |
| Distribution Period | | Distribution Rate per Unit | | Total Distribution |
| | | | (Thousands of Dollars) |
| December 15, 2022 - March 14, 2023 | | $ | 0.682 | | | $ | 11,148 | |
| September 15, 2022 - December 14, 2022 | | $ | 0.682 | | | $ | 14,337 | |
| June 15, 2022 - September 14, 2022 | | $ | 0.682 | | | $ | 15,854 | |
| March 15, 2022 - June 14, 2022 | | $ | 0.682 | | | $ | 15,854 | |
| December 15, 2021 - March 14, 2022 | | $ | 0.682 | | | $ | 15,854 | |
Information on our 8.50% Series A, 7.625% Series B and 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (collectively, the Series A, B and C Preferred Units) is shown below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Units | | | | | | | | | | Units Issued and Outstanding as of December 31, 2022 | | Optional Redemption Date/Date When Distribution Rate Became Floating | | Floating Annual Rate (as a Percentage of the $25.00 Liquidation Preference Per Unit) |
| Series A Preferred Units | | | | | | | | | | 9,060,000 | | December 15, 2021 | | Three-month LIBOR plus 6.766% |
| Series B Preferred Units | | | | | | | | | | 15,400,000 | | June 15, 2022 | | Three-month LIBOR plus 5.643% |
| Series C Preferred Units | | | | | | | | | | 6,900,000 | | December 15, 2022 | | Three-month LIBOR plus 6.88% |
Distribution information on our Series A, B and C Preferred Units is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Series A Preferred Units | | Series B Preferred Units | | Series C Preferred Units |
| Distribution Period | | Distribution Rate per Unit | | Total Distribution | | Distribution Rate per Unit | | Total Distribution | | Distribution Rate per Unit | | Total Distribution |
| | | | (Thousands of Dollars) | | | | (Thousands of Dollars) | | | | (Thousands of Dollars) |
| December 15, 2022 - March 14, 2023 | | $ | 0.71889 | | | $ | 6,513 | | | $ | 0.64871 | | | $ | 9,990 | | | $ | 0.72602 | | | $ | 5,010 | |
| September 15, 2022 - December 14, 2022 | | $ | 0.64059 | | | $ | 5,804 | | | $ | 0.57040 | | | $ | 8,784 | | | $ | 0.56250 | | | $ | 3,881 | |
| June 15, 2022 - September 14, 2022 | | $ | 0.54808 | | | $ | 4,966 | | | $ | 0.47789 | | | $ | 7,360 | | | $ | 0.56250 | | | $ | 3,881 | |
| March 15, 2022 - June 14, 2022 | | $ | 0.47817 | | | $ | 4,332 | | | $ | 0.47657 | | | $ | 7,339 | | | $ | 0.56250 | | | $ | 3,881 | |
| December 15, 2021 - March 14, 2022 | | $ | 0.43606 | | | $ | 3,951 | | | $ | 0.47657 | | | $ | 7,339 | | | $ | 0.56250 | | | $ | 3,881 | |
In January 2023, our board of directors declared quarterly distributions with respect to the Series A, B and C Preferred Units and the Series D Preferred Units to be paid on March 15, 2023.
Common Units. Distribution payments are made to our common limited partners within 45 days after the end of each quarter as of a record date that is set after the end of each quarter. The following table summarizes information relatedabout cash distributions to our quarterly cashcommon limited partners applicable to the period in which the distributions on our Preferred Units:were earned:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Cash Distributions
Per Unit | | Total Cash Distributions | | Record Date | | Payment Date |
| | | | (Thousands of Dollars) | | | | |
| Quarter ended: | | | | | | | | |
| December 31, 2022 | | $ | 0.40 | | | $ | 44,328 | | | February 8, 2023 | | February 14, 2023 |
| September 30, 2022 | | 0.40 | | | 44,125 | | | November 7, 2022 | | November 14, 2022 |
| June 30, 2022 | | 0.40 | | | 44,128 | | | August 8, 2022 | | August 12, 2022 |
| March 31, 2022 | | 0.40 | | | 44,165 | | | May 9, 2022 | | May 13, 2022 |
| Year ended December 31, 2022 | | $ | 1.60 | | | $ | 176,746 | | | | | |
| | | | | | | | |
| Year ended December 31, 2021 | | $ | 1.60 | | | $ | 175,470 | | | | | |
|
| | | | | | | | | | | | |
| Period | | Cash Distributions Per Unit | | Total Cash Distributions | | Record Date | | Payment Date |
| | | | | (Thousands of Dollars) | | | | |
| Series A Preferred Units: | | | | | | | | |
| December 15, 2017 - March 14, 2018 (a) | | $ | 0.53125 |
| | $ | 4,813 |
| | March 1, 2018 | | March 15, 2018 |
| September 15, 2017 - December 14, 2017 | | $ | 0.53125 |
| | $ | 4,813 |
| | December 1, 2017 | | December 15, 2017 |
| June 15, 2017 - September 14, 2017 | | $ | 0.53125 |
| | $ | 4,813 |
| | September 1, 2017 | | September 15, 2017 |
| March 15, 2017 - June 14, 2017 | | $ | 0.53125 |
| | $ | 4,813 |
| | June 1, 2017 | | June 15, 2017 |
| November 25, 2016 - March 14, 2017 | | $ | 0.64930556 |
| | $ | 5,883 |
| | March 1, 2017 | | March 15, 2017 |
| | | | | | | | | |
| Series B Preferred Units: | | | | | | | | |
| December 15, 2017 - March 14, 2018 (a) | | $ | 0.47657 |
| | $ | 7,339 |
| | March 1, 2018 | | March 15, 2018 |
| September 15, 2017 - December 14, 2017 | | $ | 0.47657 |
| | $ | 7,339 |
| | December 1, 2017 | | December 15, 2017 |
| April 28, 2017 - September 14, 2017 | | $ | 0.725434028 |
| | $ | 11,172 |
| | September 1, 2017 | | September 15, 2017 |
| | | | | | | | | |
| Series C Preferred Units: | | | | | | | | |
| November 30, 2017 - March 14, 2018 (a) | | $ | 0.65625 |
| | $ | 4,528 |
| | March 1, 2018 | | March 15, 2018 |
| |
(a) | The distribution was announced on January 29, 2018. |
Debt Obligations
The following table summarizes our debt obligations: | | | | | | | | | | | | | | | | | |
| | Maturity | | Outstanding Obligations as of December 31, 2022 |
| | | | | | (Thousands of Dollars) |
| Receivables Financing Agreement, 6.0% as of December 31, 2022 | January 31, 2025 | | $ | 80,900 | |
| Revolving Credit Agreement, 6.9% as of December 31, 2022 | April 27, 2025 | | $ | 220,000 | |
| 5.75% senior notes | October 1, 2025 | | $ | 600,000 | |
| 6.00% senior notes | June 1, 2026 | | $ | 500,000 | |
| 5.625% senior notes | April 28, 2027 | | $ | 550,000 | |
| 6.375% senior notes | October 1, 2030 | | $ | 600,000 | |
| GoZone Bonds, 5.85% - 6.35% | 2038 | thru | 2041 | | $ | 322,140 | |
| Subordinated notes, 10.8% as of December 31, 2022 | January 15, 2043 | | $ | 402,500 | |
As reflected in the table below, certain series of December 31, 2017, we wereGoZone Bonds in principal amounts totaling $75.0 million and $103.8 million contain a partyrequirement for the bondholders to tender their bonds in exchange for 100% of the following debt agreements:
Revolving Credit Agreement due October 29, 2020, with $893.3 million of borrowings outstanding as of December 31, 2017;
7.65% senior notes due April 15, 2018principal plus accrued and unpaid interest on June 1, 2025 and on June 1, 2030, respectively, after which these bonds will potentially be remarketed with a face value of $350.0 million; 4.80% senior notes due September 1, 2020 with a face value of $450.0 million; 6.75% senior notes due February 1, 2021 with a face value of $300.0 million; 4.75% senior notes due February 1, 2022 with a face value of $250.0 million; 5.625% senior notes due April 28, 2027 with a face value of $550.0 million; and 7.625% fixed-to-floating subordinated notes due January 15, 2043 with a face value of $402.5 million;
$365.4 million innew interest rate established. The following table summarizes the GoZone Bonds due from 2038 to 2041;
Line of credit agreements with $35.0 million of borrowings outstanding as of December 31, 2017; and2022:
Receivables Financing Agreement due September 20, 2020, with $62.3 million of borrowings outstanding as of December 31, 2017. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Series | | Date Issued | | Amount
Outstanding | | | | | | | |
Interest Rate | | Mandatory
Purchase Date | | Maturity Date |
| | | | (Thousands of Dollars) | | | | | | |
| Series 2008 | | June 26, 2008 | | $ | 55,440 | | | | | | | | | 6.10 | % | | June 1, 2030 | | June 1, 2038 |
| Series 2010 | | July 15, 2010 | | 100,000 | | | | | | | | | 6.35 | % | | n/a | | July 1, 2040 |
| Series 2010A | | October 7, 2010 | | 43,300 | | | | | | | | | 6.35 | % | | n/a | | October 1, 2040 |
| Series 2010B | | December 29, 2010 | | 48,400 | | | | | | | | | 6.10 | % | | June 1, 2030 | | December 1, 2040 |
| Series 2011 | | August 9, 2011 | | 75,000 | | | | | | | | | 5.85 | % | | June 1, 2025 | | August 1, 2041 |
| | Total | | $ | 322,140 | | | | | | | | | | | | | |
Management believesWe believe that, as of December 31, 2017,2022, we are in compliance with the ratios and covenants contained inapplicable to our debt instruments.obligations. A default under certain of our debt agreements would be considered an event of default under other of our debt instruments.obligations.
Guarantor Summarized Financial Information. NuStar Energy has no operations, and its assets consist mainly of its 100% ownership interest in its indirectly owned subsidiaries, NuStar Logistics and NuPOP. The senior and subordinated notes issued by NuStar Logistics are fully and unconditionally guaranteed by NuStar Energy and NuPOP. Each guarantee of the senior notes by NuStar Energy and NuPOP ranks equally in right of payment with all other existing and future unsecured senior indebtedness of that guarantor, is structurally subordinated to all existing and any future indebtedness and obligations of any subsidiaries of that guarantor that do not guarantee the notes and rank senior to its guarantee of our subordinated indebtedness. Each guarantee of the subordinated notes by NuStar Energy and NuPOP ranks equal in right of payment with all other existing and future subordinated indebtedness of that guarantor and subordinated in right of payment and upon liquidation to the prior payment in full of all other existing and future senior indebtedness of that guarantor. NuPOP will be released from its guarantee when it no longer guarantees any obligations of NuStar Energy or any of its subsidiaries, including NuStar Logistics, under any bank credit facility or public debt instrument. The rights of holders of our senior and subordinated notes may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Please refer to Note 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of our debt agreements.
Credit Ratings
The following table reflectstables present summarized combined balance sheet and income statement information for NuStar Energy, NuStar Logistics and NuPOP (collectively, the current outlook and ratings thatGuarantor Issuer Group). Intercompany items among the Guarantor Issuer Group have been assigned to our debteliminated in the summarized combined financial information below, as of December 31, 2017:
well as intercompany balances and activity for the Guarantor Issuer Group with non-guarantor subsidiaries, including the Guarantor Issuer Group’s investment balances in non-guarantor subsidiaries. |
| | | | | |
| Standard & Poor’s
Ratings Services
| | Moody’s Investor
Service Inc.
| | Fitch, Inc.December 31, 2022 |
| | | | | (Thousands of Dollars) |
RatingsSummarized Combined Balance Sheet Information: | BB | | Ba1 | | BB |
OutlookCurrent assets | Negative$ | 44,328 | Negative |
| Long-term assets | $ | Stable3,210,483 | |
| Current liabilities (a) | $ | 120,633 | |
| Long-term liabilities, including long-term debt | $ | 3,279,200 | |
| Series D preferred limited partners interests | $ | 446,970 | |
(a)Excluding $1,694.4 million of net intercompany payables due to the non-guarantor subsidiaries from the Guarantor Issuer Group. |
Long-term assets for the non-guarantor subsidiaries totaled $1,559.3 million as of December 31, 2022.
| | | | | |
| Year Ended December 31, 2022 |
| (Thousands of Dollars) |
| Summarized Combined Income Statement Information: | |
| Revenues | $ | 824,398 | |
| Operating income | $ | 277,142 | |
| Interest expense, net | $ | (208,479) | |
| Net income | $ | 72,456 | |
Revenues and net income for the non-guarantor subsidiaries totaled $858.8 million and $150.3 million, respectively, for the year ended December 31, 2022.
Contractual Obligations
The following table presents our contractual obligations and commitments as of December 31, 2022:
| | | | | | | | | | | |
| | Current | | Long-Term |
| | (Thousands of Dollars) |
| Long-term debt maturities | $ | — | | | $ | 3,275,540 | |
| Interest payments | 224,970 | | | 1,631,462 | |
| Operating leases | 7,535 | | | 79,649 | |
| Finance leases | 6,366 | | | 68,380 | |
| Purchase obligations | 7,643 | | | 19,762 | |
| Total | $ | 246,514 | | | $ | 5,074,793 | |
The interest rates payablepayments calculated for our variable-rate, long-term debt are based on the $350.0 million of 7.65% senior notes due 2018 (the 7.65% Senior Notes)interest rates and the Revolving Credit Agreement are subject to adjustment if our debt rating is downgraded (or upgraded) by certain credit rating agencies. In November 2017, Standard & Poor’s Rating Services lowered our credit rating from BB+ to BB, and the outlook was changed from stable to negative. The rating downgrade caused the interest rate on the 7.65% Senior Notes to increase from 8.15% to 8.4% and had no impact on the interest rate payable on our Revolving Credit Agreement. In February 2018, Moody’s Investor Service Inc. (Moody’s) lowered our credit rating from Ba1 to Ba2, which caused the interest rate on the 7.65% Senior Notes to also increase by 0.25%, resulting in an interest rate of 8.65% applicable to the interest payment due April 15, 2018. This Moody’s downgrade also caused the interest rate on our Revolving Credit Agreement to increase by 0.25%.
Interest Rate Swaps
Asoutstanding borrowings as of December 31, 20172022. The interest payments on our fixed-rate debt are based on the stated interest rates and 2016, we were a party to forward-starting interest rate swap agreements for the purpose of hedging interest rate risk. Asoutstanding borrowings as of December 31, 2017 and 2016, the aggregate notional amount of these forward-starting interest rate swaps was $600.0 million.2022. Please refer to Notes 2 and 16see Note 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.
Our operating leases consist primarily of land and dock leases at various terminal facilities. Our finance leases consist primarily of a dock lease at our Corpus Christi North Beach terminal with a remaining term of approximately three years and three additional five-year renewal periods that also includes a commitment for minimum dockage and wharfage throughput volumes. Please see Note 15 of the Notes to Consolidated Financial Statements in Item 7A. “Quantitative8. “Financial Statements and Qualitative Disclosures about Market Risk”Supplementary Data” for a more detailed discussion of our interest rate swaps.
Long-Term Contractual Obligations
The following table presents our long-term contractual obligations and commitments and the related payments due, in total and by period, as of December 31, 2017:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Payments Due by Period | | | | |
| | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | Thereafter | | Total |
| | (Thousands of Dollars) |
| Long-term debt maturities | $ | 350,000 |
| | $ | — |
| | $ | 1,405,611 |
| | $ | 300,000 |
| | $ | 250,000 |
| | $ | 1,317,940 |
| | $ | 3,623,551 |
|
| Interest payments (a) | 174,937 |
| | 169,162 |
| | 165,124 |
| | 102,586 |
| | 86,715 |
| | 1,150,198 |
| | 1,848,722 |
|
| Operating leases (b) | 39,236 |
| | 34,203 |
| | 19,541 |
| | 13,324 |
| | 7,295 |
| | 68,386 |
| | 181,985 |
|
| Purchase obligations (c) | 6,963 |
| | 6,133 |
| | 4,686 |
| | 4,690 |
| | 4,480 |
| | 300 |
| | 27,252 |
|
| Total | $ | 571,136 |
| | $ | 209,498 |
| | $ | 1,594,962 |
| | $ | 420,600 |
| | $ | 348,490 |
| | $ | 2,536,824 |
| | $ | 5,681,510 |
|
| |
(a) | The interest payments calculated for our variable-rate debt are based on forward LIBOR interest rates and the outstanding borrowings as of December 31, 2017. The interest payments on our fixed-rate debt are based on the stated interest rates and the outstanding borrowings as of December 31, 2017. |
| |
(b) | Our operating leases consist primarily of leases for tugs and barges utilized at our St. Eustatius facility and land leases at various terminal facilities. |
| |
(c) | A purchase obligation is an enforceable and legally binding agreement to purchase goods or services that specifies significant terms, including (i) fixed or minimum quantities to be purchased, (ii) fixed, minimum or variable price provisions and (iii) the approximate timing of the transaction. |
We also have pension and other postretirement benefit obligations recorded in “Other long-term liabilities” on our consolidated balance sheets which have been excluded from the contractual obligations table above due to the uncertainty in timing as to the future cash flows related to these obligations. For additional information on our pensionoperating and other postretirement benefit obligationsfinance leases.
A purchase obligation is an enforceable and legally binding agreement to purchase goods or services that specifies significant terms, including (i) fixed or minimum quantities to be purchased, (ii) fixed, minimum or variable price provisions and (iii) the approximate timing of the transaction. Please see Note 2214 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on our purchase obligations.
Series D Preferred Units Repurchase and Redemption Features
In November 2022, we repurchased an aggregate 6,900,000 of our Series D Preferred Units at a price per unit of $32.73 for an aggregate purchase price of $225.8 million, including approximately $3.4 million related to accrued distributions. We may redeem all or any portion of the remaining 16,346,650 Series D Preferred Units outstanding, in an amount not less than $50.0 million for cash at a redemption price equal to, as applicable: (i) $31.73 per Series D Preferred Unit, or up to $518.7 million, at any time on or after June 29, 2023 but prior to June 29, 2024; (ii) $30.46 per Series D Preferred Unit, or up to $497.9 million, at any time on or after June 29, 2024 but prior to June 29, 2025; (iii) $29.19 per Series D Preferred Unit, or up to $477.2 million, at any time on or after June 29, 2025; plus, in each case, the sum of any unpaid distributions on the applicable Series D Preferred Unit plus the distributions prorated for the number of days elapsed (not to exceed 90) in the period of redemption (Series D Partial Period Distributions). The holders have the option to convert the units prior to such redemption as discussed in Note 17 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”
Additionally, at any time on or after June 29, 2028, each holder of Series D Preferred Units will have the right to require us to redeem all of the Series D Preferred Units held by such holder at a redemption price equal to $29.19 per Series D Preferred Unit, plus any unpaid Series D distributions plus the Series D Partial Period Distributions. If a holder of Series D Preferred Units exercises its redemption right, we may elect to pay up to 50% of such amount in common units (which shall be valued at 93% of a volume-weighted average trading price of the common units); provided, that the common units to be issued do not, in the aggregate, exceed 15% of NuStar Energy’s common equity market capitalization at the time.
Pension and Other Postretirement Benefit Plan Contributions
During 2022, we contributed $5.0 million and $0.5 million to our pension and postretirement benefit plans, respectively. In 2023, we expect to contribute approximately $10.1 million to our pension and postretirement benefit plans and will monitor our funding status to determine if any contributions are required by regulations or laws, or with respect to unfunded plans, necessary to fund current benefits. Pension and postretirement benefit plans funding beyond 2023 is uncertain as the funding varies from year to year based upon changes in the fair value of the plan assets and actuarial assumptions.
A change of 0.25% in the specified assumptions would have the following effects to our pension and postretirement benefit obligations and costs: | | | | | | | | | | | |
| Pension
Benefits | | Other Postretirement Benefits |
| (Thousands of Dollars) |
| Increase in benefit obligation as of December 31, 2022 resulting from: | | | |
| Discount rate decrease | $ | 3,300 | | | $ | 400 | |
| Compensation rate increase | $ | 500 | | | n/a |
| | | |
(Decrease) increase in net periodic benefit cost for the year ending December 31, 2023 resulting from: | | | |
| Discount rate decrease | $ | (100) | | | $ | — | |
| Expected long-term rate of returns on plan assets decrease | $ | 400 | | | n/a |
| Compensation rate increase | $ | 100 | | | n/a |
Please see Notes 2 and 21 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.
Environmental, Health and Safety
OurAs described below under “Environmental, Health, Safety and Security Regulation,” our operations in the U.S. and Mexico are subject to extensive international, federal, state and local environmental laws and regulations, in the U.S. and in the other countries in which we operate, including those relating to the discharge of materials into the environment, waste management, remediation, the characteristics and composition of fuels, climate change and greenhouse gases. Our operations are also subject to extensive health, safety and security laws and regulations, including those relating to worker and pipeline safety, pipeline and storage tank integrity and operations security.
Because more stringent environmental and safety laws and regulations are continuously being enacted or proposed, the level of expenditures required for environmental, health and safety matters is expected to increase in the future.
The balance of and changes in our accruals for environmental matters as of and for the years ended December 31, 20172022 and 20162021 are included in Note 13 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.” We believe that we have adequately accrued for our environmental exposures.
Contingencies
HUMAN CAPITAL
We strive to make NuStar a safe, positive, inclusive and rewarding workplace, with competitive compensation, benefits and health and wellness programs and opportunities for our employees to grow and develop in their careers.
Our Employees
As of December 31, 2022, we had 1,167 employees, of which 1,156 are based in the United States and 11 are based in Mexico. Only 1.1 percent of our 1,167 employees are represented under collective bargaining agreements. In the United States, 477 of our employees work at our headquarters in San Antonio, Texas, with the remaining 679 employees working at other locations.
We believe that having a workforce composed of diverse employees with wide-ranging backgrounds, experiences and ideas makes our company stronger. As of December 31, 2022:
•19.4% of all of our employees and 29.8% of our employees at senior manager level and above are female; and
•33.2% of our U.S. employees and 23.8% of our U.S. employees at senior manager level and above are minorities (as defined by the U.S. Equal Opportunity Employment Commission).
Employee Benefits and NuStar’s Culture
We provide opportunities for our employees to develop and enhance their skills through defined career paths, professional training, educational reimbursement and leadership and development programs, as well as regular training regarding safety, operations, ethics (including our Code of Business Conduct and Ethics), human resources topics and cybersecurity. In addition, we support our employees by providing competitive compensation and benefits.
We benchmark our compensation programs through market surveys to help offer competitive packages to attract and retain high-performing employees. Our compensation department also evaluates company-wide racial and gender equity by job-profile each time an employee is hired or recommended for a promotion — this helps to ensure that compensation levels are equitable for all employees regardless of race or gender.
Our benefits and health and wellness programs include life and health insurance (medical, dental and vision), prescription drug benefits, flexible spending accounts, paid sick leave, vacation, short-term and long-term disability, mental and behavioral health resources, retirement benefits (including 401(k) and pension benefits), educational reimbursement, a disaster relief fund that provides cash grants (that do not have to be repaid) to employees undergoing difficult circumstances, an employee assistance program and employee recognition programs. We also are committed to supporting the communities in which we operate, and we organize opportunities for our employees to participate in and enrich our communities through a variety of initiatives, such as fundraising activities, community clean-up projects and educational programs.
Our culture is driven by our nine guiding principles: safety; integrity; commitment; make a difference; teamwork; respect; communication; excellence; and pride. We believe that these principles are the building blocks for our success and have helped us to recruit and retain our employees and make NuStar a great place to work. We have been recognized on FORTUNE’S “100 Best Companies to Work For” list 12 times, FORTUNE’S “Best Workplaces for Millennials” list five times, the “Best Places For Working Parents” list three times, and Latino Leader Magazine’s “Best Companies for Latinos to Work” list three times. We also were recognized as a top employer by regional and local publications, including being recognized as a top employer in Texas by FORTUNE. Many of these awards are based on confidential surveys of our employees. In addition, we monitor our ability to retain our employees through our voluntary turnover rate (the percentage of our total employees who voluntarily leave our company, other than through retirement). As of December 31, 2022, our voluntary turnover rate over the last five years has averaged 3.7%, and 224 of our employees have been employed by NuStar or predecessor entities for at least 20 years.
Safety
Safety is our first priority. In managing our business, we focus on the safety of our employees and contractors, as well as the communities in which we operate. We have implemented safety programs and management practices to promote a culture of safety, including required training for field and office employees and contractors, as well as specific qualifications and certifications for field employees and contractors. To further emphasize the importance of safety at NuStar, our Board of Directors receives a comprehensive annual report and monthly updates regarding our health, safety and environmental
performance. The Compensation Committee of our Board of Directors also evaluates our overall environmental, social and governance (ESG) performance and our health, safety and environmental performance together annually as one of the metrics used to determine the annual incentive bonus for all of our employees, including our executive officers, which we believe reinforces the importance of maintaining safe, responsible operations and focusing on ESG excellence.
We are proud of NuStar’s safety performance. Our safety statistics have been substantially better than those reported by the U.S. Bureau of Labor Statistics (BLS) for our industries. Our 2022 total recordable incident rate (TRIR) of 0.23 was 17.4 times better than the 4.0 average most recently reported by BLS for the bulk terminals industry and 2.6 times better than the 0.60 average most recently reported by BLS for the pipeline transportation industry. Our 2022 days away, restricted or transferred rate (DART) of 0.23 was 13.9 times better than the 3.20 average most recently reported by BLS for the bulk terminals industry and 1.7 times better than the 0.4 average most recently reported by BLS for the pipeline transportation industry. NuStar also participates in the Occupational Safety and Health Administration’s (OSHA) Voluntary Protection Program (VPP), which promotes effective worksite health and safety. Achieving VPP Star status requires rigorous OSHA review and audit, and requires recertification every three to five years. As of December 31, 2022, approximately 91% of our eligible U.S. terminals have attained VPP Star status. NuStar also has received the International Liquids Terminals Association’s Safety Excellence Award 12 times. Throughout the COVID-19 pandemic, we continued to focus on safety and have taken measures to protect our employees and maintain safe, reliable operations.
Sustainability Report
We publish a Sustainability Report, which covers topics similar to those described above, including our guiding principles; operations and economic impact; environmental and safety programs; sustainability; renewable fuels-related services; policies and statistics (including greenhouse gas emissions disclosures); employee engagement, development and training; diversity and inclusion; community involvement and development; recent awards; human rights and landowner relations; risk management; cybersecurity; and governance. Our Sustainability Report can be viewed at https://sustainability.nustarenergy.com. Our Sustainability Report and the information contained on our website are not part of this Annual Report on Form 10-K, are not “soliciting materials,” are not deemed filed with the SEC and are not to be incorporated by reference into any of NuStar Energy’s filings under the Securities Act of 1933 or the Securities Act of 1934, as amended, respectively.
PROPERTIES
Our principal properties are described above under the caption “Segments and Results of Operations” above, and that information is incorporated herein by reference. We believe that we have satisfactory title to all of our properties. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, liens for current taxes and other burdens and easements, and restrictions or other encumbrances, including those related to environmental liabilities associated with historical operations, to which the underlying properties were subject at the time of acquisition by us or our predecessors, we believe that none of these burdens will materially detract from the value of these properties or from our interest in these properties or will materially interfere with their use in the operation of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this report. We perform scheduled maintenance on all of our pipelines, terminals, crude oil tanks and related equipment and make repairs and replacements when necessary or appropriate. We believe that our pipelines, terminals, crude oil tanks and related equipment have been constructed and are maintained in all material respects in accordance with applicable federal, state and local laws and the regulations and standards prescribed by the American Petroleum Institute, the DOT and accepted industry practice.
RATE REGULATION
Several of our crude oil and refined products pipelines are interstate common carrier pipelines, which are subject to regulation by the FERC under the Interstate Commerce Act (ICA) and the Energy Policy Act of 1992 (the EP Act). The ICA and its implementing regulations give the FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate liquids pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates a common carrier pipeline charges for providing transportation services on its interstate common carrier liquids pipelines, as well as the rules and regulations governing these services, to be maintained on file with the FERC and posted publicly. The EP Act deemed certain rates in effect prior to its passage to be just and reasonable and limited the circumstances under which a complaint can be made against such “grandfathered” rates. The EP Act and its implementing regulations also allow interstate common carrier liquids pipelines to annually index their rates up to a prescribed ceiling level and generally require that such pipelines index their rates down to the prescribed ceiling level if the index is negative. In addition, the FERC retains cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach.
Our ammonia pipeline is subject to regulation by the STB pursuant to the ICA applicable to such pipelines (which differs from the ICA applicable to interstate liquids pipelines). Under that regulation, the ammonia pipeline’s rates, classifications, rules and practices related to the interstate transportation of anhydrous ammonia must be reasonable and, in providing interstate transportation, the ammonia pipeline may not subject a person, place, port or type of traffic to unreasonable discrimination.Similar to the crude and refined products pipelines, the rates for transportation services on the ammonia pipeline are required to be in a tariff which is posted publicly on our website, however, that tariff is not required to be on file with the STB. The STB does not prescribe an indexing approach similar to the EP Act but rates under the STB must be reasonable and the pipeline may not subject a person, place, port or type of traffic to unreasonable discrimination.
In addition to federal regulatory body oversight, various states, including Colorado, Kansas, Louisiana, North Dakota and Texas, maintain commissions focused on the rates and practices of common carrier pipelines offering services within their borders. Although the applicable state statutes and regulations vary, they generally require that intrastate pipelines publish tariffs setting forth all rates, rules and regulations applying to intrastate service, and generally require that pipeline rates and practices be just, reasonable and nondiscriminatory.
Shippers may challenge tariff rates, rules and regulations on our pipelines. In most instances, state commissions have not initiated investigations of the rates or practices of pipelines in the absence of shipper complaints. There are no pending challenges or complaints regarding our tariffs or tariff rates.
ENVIRONMENTAL, HEALTH, SAFETY AND SECURITY REGULATION
Our operations are subject to extensive international, federal, state and local environmental laws and regulations, in the U.S. and in Mexico, including those relating to the discharge of materials into the environment, waste management, remediation, the characteristics and composition of fuels, climate change and greenhouse gases. In 2022, our capital expenditures attributable to compliance with environmental regulations were $5.9 million, and we currently project environmental regulatory compliance spending of approximately $6.3 million in 2023.
Our operations are also subject to extensive health, safety and security laws and regulations, including those relating to worker and pipeline safety, pipeline and storage tank integrity and operations security. The principal environmental, health, safety and security risks associated with our operations relate to unauthorized emissions into the air, releases into soil, surface water or groundwater, personal injury and property damage. We have adopted policies, practices, systems and procedures designed to comply with the laws and regulations, and to help minimize and mitigate these risks, limit the liability that could result from such events, prevent material environmental or other damage, ensure the safety of our employees and the public and secure our pipelines, terminals and operations. Compliance with environmental, health, safety and security laws, regulations and related permits increases our capital expenditures and operating expenses, and violation of these laws, regulations or permits could result in significant civil and criminal liabilities, injunctions or other penalties. Future governmental actions could result in more restrictive laws and regulations, which could increase required capital expenditures and operating expenses. At this time, we are unable to estimate either the impact, if any, of potential future regulation and/or legislation on our financial condition or results of operations, or the amount and timing of such possible future expenditures or expenses. The risk of additional compliance expenditures, expenses and liabilities are inherent to government-regulated industries, including midstream energy. As a result, there can be no assurances that significant expenditures, expenses and liabilities will not be incurred in the future. However, while compliance may affect our capital expenditures and operating expenses, we believe that the cost of such compliance will not have a material impact on our competitive position, financial condition or results of operations. Further, we do not believe that our cost of compliance is proportionately greater than the cost to other companies operating in our industry.
Discussed below are the primary U.S. environmental, health, safety and security laws applicable to our operations. Compliance with or violations of any of these laws and related regulations could result in significant expenditures, expenses and liabilities.
Occupational, Safety and Health
We are subject to the Occupational Safety and Health Act, as amended, and analogous or more stringent international, state and local laws and regulations for the protection of worker safety and health. In addition, we have operations subject to the Occupational Safety and Health Administration’s Process Safety Management regulations. These regulations apply to processes that involve certain loss contingencies,chemicals at or above specified thresholds.
Fuel Standards and Renewable Energy
International, federal, state and local laws and regulations regulate the outcomesfuels we transport and store for our customers. Changes in these laws or regulations could affect our earnings, including by reducing our throughput volumes, or require capital expenditures and expenses to segregate and separately store fuels. In addition, several federal and state programs require,
subsidize or encourage the purchase and use of competing fuels or energy, renewable energy, electric battery-powered motor vehicle engines and renewable fuels and blending additives, like ethanol, biodiesel and renewable diesel. These programs may over time offset projected increases or reduce the demand for refined products, particularly gasoline, in certain markets. However, the increased production and use of renewable fuels may also create opportunities for pipeline transportation and fuel blending. Other legislative changes in the future may similarly alter the expected demand and supply projections for refined products in ways that cannot be predicted.
Hazardous Substances and Hazardous Waste
The Federal Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA or “Superfund,” and analogous or more stringent international, state and local laws and regulations, impose restrictions and liability related to the release, threatened release, disposal and remediation of hazardous substances. This liability can be joint and several strict liability, without regard to fault or the legality of the original release or disposal. Current operators of a facility, past owners or operators of a facility and parties who arranged for the disposal of a hazardous substance can be held liable under these laws and regulations.
We currently own, lease, and operate on, and have in the past owned, leased and operated on, properties and at facilities that handled, transported and stored hazardous substances. Despite our compliance with applicable requirements and industry standards, hazardous substances may have been released on or under our facilities and properties, or on or under locations where these substances were taken for disposal. We are currently remediating subsurface contamination at several facilities, and, based on currently available information, we believe the costs related to these remedial activities should not materially affect our financial condition or results of operations. However, the aggregate total cost of remediation projects can be difficult to estimate, and there are no assurances that the cost of future remedial activities will not become material. Further, applicable laws or regulation, including those dictating the degree of remediation required, may be revised to be more restrictive in the future. As a result, we are unable to estimate the effect of future regulation on our financial condition or results of operations or the amount and timing of future expenditures required to comply with such possible regulatory changes.
The Federal Resource Conservation and Recovery Act, as amended, and analogous or more stringent international, state and local laws and regulations impose restrictions and strict controls regarding the handling and disposal of wastes, including hazardous wastes. We generate hazardous wastes and it is possible that additional wastes, which could include wastes currently generated during operations, will be designated as hazardous wastes in the future. Hazardous wastes are subject to more rigorous requirements than are non-hazardous wastes.
Air
The Federal Clean Air Act, as amended, and various applicable international, state and local laws and regulations impose restrictions and strict controls regarding emission into the air, including greenhouse gas emissions. These laws and regulations generally require permits issued by applicable federal, state or local authorities for emissions, and impose monitoring and reporting requirements. Such laws and regulations can also require pre-approval for the construction or modification of certain operations or facilities expected to produce or increase air emissions.
Water
The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, the federal Spill Prevention, Control, and Countermeasure and Facility Response Plan Rules and analogous or more stringent international, state and local laws and regulations impose restrictions and strict controls regarding the discharge of pollutants into state waters or waters of the United States. The discharge of pollutants into waters is generally prohibited, except in accordance with a permit issued by applicable federal or state authorities. The Oil Pollution Act further regulates the discharge of oil, and the response to and liability for oil spills, and the Rivers and Harbors Act regulates pipelines crossing navigable waters.
Pipeline and Other Asset Integrity, Safety and Security
Our pipeline, storage tank and other operations are subject to extensive international, federal, state and local laws and regulations governing integrity, safety and security, including those in Title 49 of the U.S. Code and its implementing regulations. These laws and regulations include the Pipeline and Hazardous Materials Safety Administration’s requirements for safe pipeline design, construction, operation, maintenance, inspection, testing and corrosion control, control rooms and qualification programs for operating personnel. In addition, we have an adversemarine terminal operations subject to Coast Guard safety, integrity and security regulations and standards. We also have operations subject to the Department of Homeland Security Chemical Facility Anti-Terrorism Standards and security guidelines and directives issued by the Transportation Security Administration.
Although we take proactive steps to protect our company, systems and data from cyberattacks, such as implementing multiple layers of security, segregated systems and user access, antivirus tools, vulnerability scanning, monitoring and patch
management, regular employee training, phishing tests, penetration tests, internal risk assessments, independent third-party assessments, tabletop exercises to test our incident response plan, enhanced cyber diligence of vendors and physical security measures, all companies are at risk of a cyberattack. Due to the continued acceleration of cyberattacks, generally and against our industry, regulatory actions by federal, state and local governmental agencies in the U.S. and in Mexico have increased. Although we believe that we have robust cybersecurity procedures and other safeguards in place, we cannot guarantee their effectiveness, and a significant failure, compromise, breach or interruption in our systems or those of our customers or vendors could have a material effect on our cash flowsoperations and results ofthe operations as further disclosed in Note 14 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”
RELATED PARTY TRANSACTIONS
Please refer to Note 17 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of our related party transactions.customers and vendors.
CRITICAL ACCOUNTING POLICIES
The preparation of financial statements in accordance with U.S. generally accepted accounting principles requires management to select accounting policies and to make estimates and assumptions related thereto that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The accounting policies below are considered critical due to judgments made by management and the sensitivity of these estimates to deviations of actual results from management’s assumptions. The critical accounting policies should be read in conjunction with Note 2 of the Notes to the Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data,” which summarizes our significant accounting policies.
Depreciation
We calculate depreciation expense using the straight-line method over the estimated useful lives of our property, plant and equipment. Due to the expected long useful lives of our property, plant and equipment, we depreciate our property, plant and equipment over periods ranging from 5 years to 40 years. Changes in the estimated useful lives of our property, plant and equipment could have a material adverse effect on our results of operations.
Impairment of Long-Lived Assets
We test long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. We evaluate recoverability using undiscounted estimated net cash flows generated by the related asset or asset group. If the results of that evaluation indicate that the undiscounted cash flows are less than the carrying amount of the asset (i.e., the asset is not recoverable) we perform an impairment analysis. If our intent is to hold the asset for continued use, we determine the amount of impairment as the amount by which the net carrying value exceeds its fair value. If our intent is to sell the asset, and the criteria required to classify an asset as held for sale are met, we determine the amount of impairment as the amount by which the net carrying amount exceeds its fair value less costs to sell.
In determining the existence of an impairment of the carrying value of an asset, we make a number of subjective assumptions as to:
•whether there is an event or circumstance that may indicate that the carrying amount of an asset may not be recoverable;
•the grouping of assets;
•the intention of holding, abandoning or selling an asset;
•the forecast of undiscounted expected future cash flows with respect to an asset or asset group; and
•if an impairment exists, the fair value of the asset or asset group.
Our estimates of undiscounted future cash flows include: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) estimates of useful lives of the assets. The identification of impairment indicators and the estimates of future undiscounted cash flows are highly subjective and are based on numerous assumptions about future operations and market conditions, which we believe to be reasonable but are inherently uncertain. The uncertainties underlying our assumptions and estimates could differ significantly from actual results and could cause a different conclusion about the recoverability of our assets. If we determined one or more assets was impaired, the amount of impairment could be material to our results of operations.
We recorded long-lived asset impairment charges of $154.9 million in 2021. Please refer to Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data,” for discussion of the impairment charges.
Impairment of Goodwill
We perform an assessment of goodwill annually or more frequently if events or changes in circumstances warrant. We have the option to first perform a qualitative annual assessment to determine whether it is necessary to perform a quantitative goodwill impairment test. A qualitative assessment includes, among other things, industry and market considerations, overall financial performance, other entity-specific events and events affecting individual reporting units. If after assessing the totality of events or circumstances for each reporting unit, we determine that it is more likely than not that the carrying value exceeds its fair value, then we would perform ana quantitative impairment test for that reporting unit. However, we chose to perform a quantitative goodwill impairment test for all reporting units as of October 1, 2017.
We recognize an impairment of goodwill if the carrying value of a reporting unit that contains goodwill exceeds its estimated fair value. In order to estimate the fair value of the reporting unit, including goodwill, management must make certain estimates and assumptions that affect the total fair value of the reporting unit including, among other things, an assessment of market conditions, projected cash flows, discount rates and
growth rates. Management’s estimates of projected cash flows related to the
reporting unit include, but are not limited to, future earnings of the reporting unit, assumptions about the use or disposition of assets included in the asset,reporting unit, estimated remaining lifelives of the asset,those assets, and future expenditures necessary to maintain the asset’sassets’ existing service potential.
We calculate the estimated fair value of each of our reporting units using a weighted-average of values calculated using an income approach and a market approach. The income approach involves estimating the fair value of each reporting unit by discounting its estimated future cash flows using a discount rate, consistent with a market participant’s assumption. The market approach bases the fair value measurement on information obtained from observed stock prices of public companies and recent merger and acquisition transaction data of comparable entities. Our fair value estimates are sensitive to typical valuation assumptions, particularly our estimates for the weighted-average cost of capital used for the income approach and the guideline public company and guideline transaction multiples used for the market approach.
We determined that no impairment charges resulted from our October 1, 2017 impairment assessment. Furthermore, our assessment did not reflect any reporting units at risk of failing step one of therecorded a goodwill impairment test, which compares the fair valuecharge of the reporting unit to its carrying value including goodwill.
Derivative Financial Instruments
We utilize various derivative instruments to manage our exposure to interest rate risk and commodity price risk. We record derivative instruments in the consolidated balance sheets at fair value, and apply hedge accounting when appropriate. We record changes to the fair values of derivative instruments in earnings for fair value hedges or as part of accumulated other comprehensive income (AOCI)$34.1 million for the effective portion of cash flow hedges. We reclassify the effective portion of cash flow hedges from AOCI to earnings when the underlying forecasted transaction occurs or becomes probable not to occur. We recognize ineffectiveness resulting from our derivatives immediately in earnings. With respect to cash flow hedges, we must exercise judgment to assess the probability of the forecasted transaction, which, among other things, depends upon market factors and our ability to reliably operate our assets.
Defined Benefit Plans
We estimate pension and other postretirement benefit obligations and costs based on actuarial valuations. The annual measurement date for our pension and other postretirement benefit plans is December 31. The actuarial valuations require the use of certain assumptions including discount rates, expected long-term rates of return on plan assets and expected rates of compensation increase. Changes in these assumptions are primarily influenced by factors outside our control. The discount rate is based on a hypothetical yield curve represented by a series of annualized individual discount rates. Each bond issue underlying the hypothetical yield curve required an average rating of double-A, when averaging all available ratings by Moody’s Investor Service Inc., Standard & Poor’s Ratings Services and Fitch, Inc. The resulting discount rates were 3.72% and 3.82% for our pension and other postretirement benefit plans, respectively, as ofyear ended December 31, 2017. The expected long-term rate of return on plan assets is based on the weighted averages of the expected long-term rates of return for each asset class of investments held in our plans as determined using historical data and the assumption that capital markets are informationally efficient. The expected rate of compensation increase represents average long-term salary increases.
These assumptions can have an effect on the amounts reported in our consolidated financial statements. The effect of a 0.25% change in the specified assumptions would have the following effects (thousands of dollars):
|
| | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| Increase in benefit obligation as of December 31, 2017 from: | | | |
| Discount rate decrease | $ | 5,200 |
| | $ | 500 |
|
| Compensation rate increase | $ | 1,500 |
| | n/a |
|
Increase in net periodic benefit cost for the year ending December 31, 2018 resulting from: | | | |
| Discount rate decrease | $ | 400 |
| | $ | 100 |
|
| Expected long-term rate of returns on plan assets decrease | $ | 300 |
| | n/a |
|
| Compensation rate increase | $ | 400 |
| | n/a |
|
2021. Please refer to Note 22Notes 4 and 10 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data”Data,” for further discussion of our pension and other postretirement benefit obligations.additional information.
Environmental Liabilities
Environmental remediation costs are expensed and an associated accrual is established when site restoration and environmental remediation and cleanup obligations are either known or considered probable and can be reasonably estimated. These environmental obligations are based on estimates of probable undiscounted future costs using currently available technology and applying current regulations, as well as our own internal environmental policies. The environmental liabilities have not been reduced by possible recoveries from third parties. Environmental costs include initial site surveys, costs for remediation and restoration and ongoing monitoring costs, as well as fines, damages and other costs, when estimable. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. Environmental liabilities are difficult to assess and estimate due to unknown factors, such as the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. We believe that we have adequately accrued for our environmental exposures.
Contingencies
We accrue for costs relating to litigation, claims and other contingent matters when such liabilities become probable and reasonably estimable. Such estimates may be based on advice from third parties or on management’s judgment, as appropriate. Due to the inherent uncertainty of litigation, actual amounts paid may differ from amounts estimated, and such differences will be charged to income in the period when final determination is made.
NEW ACCOUNTING PRONOUNCEMENTS
Please refer to Note 3 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of new accounting pronouncements.
AVAILABLE INFORMATION
Our internet website address is www.nustarenergy.com. Information contained on our website is not part of this report. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and any amendments thereto, filed with (or furnished to) the SEC are available on our website, free of charge, as soon as reasonably practicable after we file or furnish such material (select the “Investors” link, then the “SEC Filings” link). We also post our corporate governance guidelines, code of business conduct and ethics, code of ethics for senior financial officers and the charters of our board’s committees on our website free of charge (select the “Investors” link, then the “Corporate Governance” link).
Our governance documents are available in print to any unitholder that makes a written request to Corporate Secretary, NuStar Energy L.P., 19003 IH-10 West, San Antonio, Texas 78257 or corporatesecretary@nustarenergy.com.
ITEM 1A. RISK FACTORS
RISKS RELATED TO OUR BUSINESS
Changes in price levels could negatively impact our revenue, our expenses, or both, which could adversely affect our business.
The operation of our assets and the execution of capital projects require significant expenditures for labor, materials, property, equipment and services. As a result, such costs may increase during periods of high inflation, including as a result of rising commodity prices, supply chain disruptions and tight labor markets. Recent inflationary pressures affecting the general economy and the energy industry have increased our expenses and capital costs, and those costs may continue to increase. While we expect our pipeline systems to benefit from the positive revenue impact of our tariff indexation increases, we may not be able to pass all of these increased costs to our customers in the form of higher fees for our services, and, if so, our revenues and operating margins would be reduced. Prior to adjustments to applicable rates, material cost increases may affect our operating margins, even if margins in subsequent periods may be normalized following applicable rate adjustments. Accordingly, increased costs during periods of high inflation that are not passed through to customers or offset by other factors may have a material adverse effect on our financial position, results of operations and cash flows.
We may not be able to generate sufficient cash from operations to enable us to pay quarterly distributions to our unitholders.
The amount of cash that we can distribute to our unitholders each quarter principally depends upon the amount of cash we generate from our operations, based on, among other things:
•prevailing macroeconomic conditions as well as economic conditions in and specific to our primary markets;
•demand for and supply of crude oil, refined products, renewable fuels and anhydrous ammonia;
•volumes transported in our pipelines and stored in our terminals and storage facilities;
•the financial stability and strength of our customers;
•tariff and/or contractually determined rates and fees we charge and the revenue we realize for our services;
•domestic and foreign governmental laws, regulations, sanctions, embargoes and taxes;
•the effect of energy conservation, efficiency and other evolving priorities;
•the effect of weather events on our operations and demand for our services; and
•the results of our marketing, trading and hedging activities, which fluctuate depending upon the relationship between refined product prices and prices of crude oil and other feedstocks.
Furthermore, the amount of cash that we will have available for distribution depends on a number of other factors, including:
•our debt service requirements and restrictions on distributions contained in our current or future financing agreements;
•our capital expenditures;
•our operating costs;
•the costs to comply with environmental, health, safety and security laws and regulations;
•fluctuations in our working capital needs;
•adjustments in cash reserves made by our board of directors, in its discretion;
•availability of and access to equity capital and debt markets; and
•the sources of cash used to fund our acquisitions, if any.
Moreover, the total amount of cash that we have available for distribution to common unitholders is further reduced by the required distributions with respect to our preferred units.
It is possible that one or more of the factors listed above, which may be further impacted by the lingering impact of the COVID-19 pandemic or other public health crises, as well as the actions of oil-producing nations, may reduce our available cash to such an extent that we are unable to pay distributions at the current level or at all in a given quarter. Cash distributions to our unitholders depend primarily upon our cash flows, including cash flows from reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items; in other words, we may be able to make cash distributions during periods in which we record net losses and may not be able to make cash distributions during periods in which we record net income.
An extended period of reduced demand for or supply of crude oil and refined products could have an adverse impact on our results of operations, cash flows and ability to make distributions to our unitholders.
Our business is ultimately dependent upon the demand for and supply of the crude oil and refined products we transport in our pipelines and store in our terminals. Market prices for crude oil and refined products, including fuel oil, are subject to wide fluctuation in response to changes in global and regional supply that are beyond our control. Increases in the price of crude oil may result in a lower demand for refined products that we transport, store and market, including fuel oil, while sustained low prices may lead to reduced production in the markets served by our pipelines and storage terminals.
Any sustained decrease in demand for refined products in the markets our pipelines and terminals serve that extends beyond the expiration of our existing throughput and deficiency agreements could result in a significant reduction in throughputs in our pipelines and storage in our terminals, which would reduce our cash flows and impair our ability to make distributions to our unitholders. Factors that tend to decrease market demand include:
•a recession, inflation or other adverse economic conditions that result in lower spending by consumers on gasoline, diesel and travel;
•events that negatively impact global economic activity, travel and demand generally, such as occurred in response to the COVID-19 pandemic;
•higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline;
•an increase in aggregate automotive engine fuel economy;
•new government and regulatory actions or court decisions requiring the phase out or reduced use of gasoline-fueled vehicles;
•the increased use of and public demand for use of alternative fuel sources or electric vehicles;
•an increase in the market price of crude oil that increases refined product prices, which may reduce demand for refined products and increase demand for alternative products; and
•a decrease in corn acres planted for ethanol, which may reduce demand for anhydrous ammonia.
Similarly, any sustained decrease in the supply of crude oil and refined products in markets we serve could result in a significant reduction in throughputs in our pipelines and storage in our terminals, which would reduce our cash flows and undermine our ability to make distributions to our unitholders. Factors that tend to decrease supply and, by extension, utilization of our pipelines and terminals include:
•prolonged periods of low prices for crude oil and refined products that result in decreased exploration and development activity and reduced production in markets served by our pipelines and storage terminals;
•macroeconomic forces affecting, or actions taken by, oil and gas producing nations that impact supply of and prices for crude oil and refined products;
•a lack of drilling services, equipment or skilled personnel available to producers to accommodate production needs;
•changes in laws, regulations, sanctions or taxation that directly or indirectly delay supply or production or increase the cost of production of refined products; and
•political unrest or hostilities, activist interference and the resulting governmental response thereto.
Failure to retain or replace current customers and renew existing contracts on comparable terms to maintain utilization of our pipeline and storage assets at current or more favorable rates could reduce our revenue and cash flows to levels that adversely affect our ability to make quarterly distributions to our unitholders.
Our revenue and cash flows are generated primarily from our customers’ payments of fees under throughput contracts and storage agreements. Failure to renew or enter into new contracts or a material reduction in utilization under existing contracts results from many factors, including:
•sustained low crude oil prices;
•a material decrease in the supply or price of crude oil;
•a material decrease in demand for refined products in the markets served by our pipelines and terminals;
•political, social or economic instability in the United States or another country that has a detrimental impact on customers based there and our ability to conduct our operations;
•competition for customers from companies with comparable assets and capabilities;
•scheduled turnarounds or unscheduled maintenance at customers we serve;
•operational problems or catastrophic events affecting our assets or customers we serve;
•environmental or regulatory proceedings or other litigation that compel the cessation of all or a portion of the operations of our assets or those of the customers we serve;
•increasingly stringent environmental, health, safety and security regulations;
•a decision by our current customers to redirect products transported in our pipelines to markets not served by our pipelines or to transport crude oil or refined products by means other than our pipelines; and
•a decision by our current customers to shut down, limit operations of or sell one or more of the refineries we serve to a purchaser that elects not to use our pipelines and terminals.
Depending on conditions in the credit and capital markets at a given time, we may not be able to obtain funding on acceptable terms or at all, which may hinder or prevent us from meeting our future capital needs, satisfying our debt obligations, or making quarterly distributions to our unitholders.
From time to time, the domestic and global financial markets and economic conditions are volatile and disrupted by a variety of factors, including low consumer confidence, high unemployment, geoeconomic and geopolitical issues, weak economic conditions, uncertainty in the market and negative sentiment toward fossil fuel energy-related companies generally, or master limited partnerships specifically. For example, during the COVID-19 pandemic, global financial markets have experienced significant volatility, which is expected to continue during the pendency of the pandemic. In addition, there are fewer investors and lenders for master limited partnership debt and equity capital market issuances than there are for corporate issuances, and negative public sentiment toward the fossil fuel energy industry has led some investors and lenders to reduce or cease investing in and lending to fossil fuel energy companies. As a result, the cost of raising capital has increased, the availability of funds has diminished and certain lenders have, and others may, refuse to refinance existing debt on similar terms or at all and reduce, or in some cases cease to provide, funding to borrowers such as us.
In general, if we do not generate sufficient cash from operations to finance our expenditures and funding from external sources is not available when needed, or is available only on unfavorable terms, we may be unable to execute our growth strategy, complete future acquisitions or construction projects or take advantage of other business opportunities and may be required to reduce investments or capital expenditures or sell assets, which could have a material adverse effect on our revenues and results of operations, and we may not be able to satisfy our debt obligations or pay distributions to our unitholders.
Our future financial and operating flexibility may be adversely affected by our significant leverage, any future downgrades of our credit ratings, restrictions in our debt agreements and conditions in the financial markets.
As of December 31, 2022, our consolidated debt was $3.3 billion, and we have the ability to incur more debt. In addition to any potential direct financial impact of our debt, a material increase to our debt or other adverse financial factors would likely be viewed negatively by credit rating agencies, which could result in ratings downgrades, increased costs or inability for us to access the capital markets and an increase in interest rates on amounts borrowed under our revolving credit agreement and an increase in certain fees on our accounts receivable securitization program.
Our revolving credit agreement contains restrictive covenants, such as limitations on indebtedness, liens, mergers, asset transfers and certain investing activities. In addition, that agreement limits us to a consolidated debt coverage ratio (consolidated debt to consolidated EBITDA, each as defined in the agreement) not to exceed 5.00-to-1.00 and requires us to maintain a minimum consolidated interest coverage ratio (as defined in the agreement) of at least 1.75-to-1.00. Failure to comply with any of the restrictive covenants or the maximum consolidated debt coverage ratio or minimum consolidated interest coverage ratio requirements would constitute an event of default and could result in acceleration of our obligations under our revolving credit agreement and possibly other agreements. Our accounts receivable securitization program, senior
notes and other debt obligations also contain various customary affirmative and negative covenants and default, indemnification and termination provisions, and provide for acceleration of amounts owed upon the occurrence of certain specified events. Future financing agreements we may enter into may contain similar or more restrictive covenants and ratio requirements than those we have negotiated for our current financing agreements.
Our debt service obligations, restrictive covenants, ratio requirements and maturities may adversely affect our ability to finance future operations, pursue acquisitions, fund our capital needs and pay cash distributions to our unitholders. In addition, this leverage may make our results of operations more susceptible to adverse economic or operating conditions, limit our flexibility in planning for, or reacting to, changes in our business and industry and place us at a competitive disadvantage compared to competitors with proportionately less indebtedness. For example, during an event of default under certain of our debt agreements, we would be prohibited from making cash distributions to our unitholders.
Our ability to service our debt will depend on, among other things, our future financial and operating performance and our ability to access the capital markets, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our indebtedness and we are unable to access the capital markets or otherwise refinance our indebtedness, we may be required to reduce our distributions, reduce or delay our business activities, investments or capital expenditures, sell assets or issue additional equity, which could materially and adversely affect our financial condition, results of operations, cash flows and ability to make distributions to unitholders, as well as the trading price of our units.
Changes in interest rates could adversely affect our business and the trading price of our units.
We have significant exposure to increases in interest rates through variable rate provisions in certain of our debt instruments and our Series A, Series B and Series C preferred units. At December 31, 2022, we had approximately $3.3 billion of consolidated debt, of which $2.6 billion was at fixed interest rates and $0.7 billion was at variable interest rates. In addition, the distribution rates on our Series A, Series B and Series C preferred units converted from a fixed rate to a floating rate in December 2021, June 2022 and December 2022, respectively. Our results of operations, cash flows and financial position could be materially adversely affected by significant changes in interest rates and uncertainty regarding the floating rates referenced in our variable rate debt instruments and preferred units could adversely affect the value of those financing arrangements. Please see “Quantitative and Qualitative Disclosures about Market Risk” for discussion of our market risk related to interest rates.
Furthermore, although we have positioned ourselves to self-fund all of our expenses, distribution requirements and capital expenditures for 2023 using internally generated cash flows as we did for the full-year 2022 and 2021, we funded our strategic capital expenditures and any acquisitions prior to 2021 primarily from borrowings under our revolving credit agreement, funds raised through debt or equity offerings and/or sales of non-strategic assets. An increase in interest rates may also have a negative impact on our ability to access the capital markets at economically attractive rates.
Moreover, the market price of master limited partnership units, like other yield-oriented securities, may be affected by, among other factors, implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, increases or decreases in interest rates may affect whether or not certain investors decide to invest in master limited partnership units, including ours, and a rising interest rate environment could have an adverse impact on our unit price and impair our ability to issue additional equity or incur debt to fund growth or for other purposes, including distributions.
Our inability to develop, fund and execute growth projects and acquire new assets could limit our ability to maintain and grow quarterly distributions to our unitholders.
Our ability to maintain and grow our distributions to unitholders depends on the growth of our existing businesses and strategic acquisitions. Decisions regarding new growth projects rely on numerous estimates, including, among other factors, the ability to secure a commitment from a customer that sufficiently exceeds our cost of capital to justify the project cost, predictions of future demand for our services, future supply shifts, crude oil production estimates, commodity price environments, economic conditions, both domestic and foreign, and potential changes in the financial condition of our customers. Our predictions of such factors could cause us to forego certain investments and to lose opportunities to competitors who make investments based on different predictions or have greater access to financial resources. In addition, volatile market conditions have caused us to reevaluate the estimates underlying certain planned projects and delay the timing of certain projects until conditions improve. If we are unable to develop and execute expansion projects, implement business development opportunities, acquire new assets and finance such activities on economically acceptable terms, our future growth will be limited, which could have a significant adverse impact on our results of operations and cash flows and, accordingly, result in reduced distributions over time.
Failure to complete capital projects as planned adversely affects our financial condition, results of operations and cash flows.
While we incur financing costs during the planning and construction phases of our projects, a project does not generate expected operating cash flows until it is at least substantially completed, if at all. Additionally, our forecasted operating results from capital spending projects are based on future market fundamentals that are not within our control, including changes in
general economic conditions, the supply and demand of crude oil, refined products and renewable fuels, availability to our customers of attractively priced alternative solutions for storage, transportation or supplies of crude oil, refined products and renewable fuels and overall customer demand. As a result of these uncertainties, the anticipated benefits associated with our capital projects may not be achieved or could be delayed. In turn, this could have a negative impact on our results of operations and cash flow and our ability to make cash distributions to our unitholders.
Although we evaluate and monitor each capital spending project and try to anticipate difficulties that may arise, delays or cost increases related to capital spending programs involving construction of new facilities (or improvements and repairs to our existing facilities) adversely affect our ability to achieve forecasted operating results. Delays or cost increases arise as a result of many factors that are beyond our control, including:
•adverse economic conditions;
•market-related increases in a project’s debt or equity financing costs;
•severe adverse weather conditions, natural disasters or other events (such as hurricanes, equipment malfunctions, explosions, fires, spills or public health events) affecting our facilities or employees, or those of vendors and suppliers;
•non-performance or delay by, or disputes with, counterparties, vendors, suppliers, contractors or sub-contractors involved with a project;
•denial or delay in issuing requisite regulatory approvals and/or permits;
•delay or increased costs to obtain right-of-way or other property rights;
•delays or failures by third parties to complete related projects;
•protests and other activist interference with planned or in-process projects;
•unplanned increases in the cost of construction materials or labor;
•shortages or disruptions in transportation of modular components and/or construction materials; or
•shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages.
Competing midstream service providers, including certain major energy and chemical companies, possess, or have greater financial resources to acquire, assets better suited to meet customer demand, which could undermine our ability to obtain and retain customers or reduce utilization of our assets, which could reduce our revenues and cash flows, thereby reducing our ability to make our quarterly distributions to unitholders.
We face competition in all aspects of our business and can give no assurances that we will be able to compete effectively against our competitors. Our competitors include major energy and chemical companies, some of which have greater financial resources, more pipelines or storage terminals, greater capacity pipelines or storage terminals and greater access to supply than we do. Certain of our competitors also have advantages in competing for acquisitions or other new business opportunities because of their financial resources and synergies in operations. As a consequence of increased competition in the industry or market conditions, some customers are and others may be in the future reluctant to renew or enter into long-term contracts or contracts that provide for minimum throughput amounts. Our inability to renew or replace a significant portion of our current contracts as they expire, to enter into contracts for newly acquired, constructed or expanded assets and to respond appropriately to changing market conditions would have a negative effect on our revenue, cash flows and ability to make quarterly distributions to our unitholders.
Our operations are subject to operational hazards and interruptions, and we cannot insure against or predict all potential losses and liabilities that might result therefrom.
Our operations and those of our customers and suppliers are subject to operational hazards and unforeseen interruptions due to natural disasters, adverse weather conditions (such as hurricanes, tornadoes, storms, floods and earthquakes), accidents, fires, explosions, hazardous materials releases, mechanical failures, cyberattacks, acts of terrorism and other events beyond our control. These events have, and may in the future, result in a loss of life or equipment, injury or extensive property or environmental damage, as well as an interruption in our operations or those of our customers or suppliers. In the event any of our facilities, or those of our customers or suppliers, suffer significant damage or are forced to shut down for a significant period of time, it may have a material adverse effect on our results of operations and our financial condition as a whole. Additionally, our pipelines, terminals and storage assets are generally long-lived assets, and some have been in service for many years. The age and condition of our assets could result in increased maintenance or repair expenditures in the future.
As a result of market conditions and losses experienced by us and other companies, the premiums and deductibles for our insurance policies have increased and could continue to increase substantially; therefore, it has become increasingly difficult to, and we may not be able to, maintain or obtain insurance of the type and amount we desire at reasonable rates. In addition, certain insurance coverage is subject to broad exclusions, and may become subject to further exclusions, become unavailable altogether or become available only for reduced amounts of coverage and at higher rates. We are not fully insured against all hazards and risks to our business, and the insurance we carry requires us to meet deductibles before we collect for losses we sustain. If we incur a significant liability for which we are uninsured or not fully insured, or if there is a significant delay in payment of a major insurance claim, such a liability could have a material adverse effect on our financial position.
We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, vendors or other counterparties reduces our revenues and increases our expenses, and any significant level of nonpayment and nonperformance could have a negative impact on our ability to conduct our business, operating results, cash flows and our ability to service our debt obligations and make distributions to our unitholders.
Weak and volatile economic conditions and widespread financial stress reduce the liquidity of our customers, vendors or other counterparties, making it more difficult for them to meet their obligations to us. We are therefore subject to risks of loss resulting from nonpayment or nonperformance by our customers to whom we extend credit. Financial problems encountered by our customers limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements. In addition, nonperformance by vendors or their subcontractors, who have committed to provide us with critical products or services, increases our costs and could result in significant disruptions or interfere with our ability to successfully conduct our business. Although we attempt to mitigate our risk through warehouseman’s liens and other security protections, we are not always able to enforce such liens and protections due to competing claims from other parties. Any substantial increase in the nonpayment and nonperformance by our customers, vendors or other counterparties or our inability to enforce our warehouseman’s liens and other security protections could have a material adverse effect on our results of operations, cash flows and ability to make distributions to our unitholders.
We rely on our information technology and operational technology systems to conduct our business. Any significant cybersecurity breach or other significant disruption to those systems would cause our business, financial results and reputation to suffer, increase our costs and expose us to liability, and could adversely affect our ability to make distributions to our unitholders.
We rely on our information technology systems and our operational technology systems to process, transmit and store information, such as employee, customer and vendor data, and to conduct almost all aspects of our business, including safely operating our pipelines and storage facilities, recording and reporting commercial and financial transactions and receiving and making payments. We also rely on systems hosted by third parties, with respect to which we have limited visibility and control, and that have access to or store certain of our employee, customer and vendor data. The security of these networks and systems is critical to our operations and business strategy.
Although we take proactive steps to protect us, our systems and our data from cyberattacks, such as implementing multiple layers of security, segregated systems and user access, antivirus tools, vulnerability scanning, monitoring and patch management, regular employee training, phishing tests, penetration tests, internal risk assessments, independent third-party assessments, tabletop exercises to test our incident response plan, enhanced cyber diligence of vendors and physical security measures, all companies are at risk of a cyberattack. The number and sophistication of reported cyberattacks by both state-sponsored and criminal organizations continue to increase, across industries and around the world, including attacks on operators of critical infrastructure assets, such as pipelines, as well as the third parties that provide technology services for critical infrastructure, in some cases with considerable negative impact on targeted companies’ ability to conduct business.
Like other companies, we recognize that, despite our security measures, we remain subject to cybersecurity incidents due to attacks from a variety of external threat actors, internal employee error or malfeasance and cybersecurity incidents suffered by our service providers, vendors or customers. In addition, in connection with precautions during the COVID-19 pandemic, many of our employees and those of our service providers, vendors and customers began working, and some have continued to work, from home or other remote-work locations, where cybersecurity protections may be less robust and cybersecurity procedures and safeguards may be less effective. Moreover, certain attacker techniques and goals, such as surveillance, intelligence gathering or extended reconnaissance, may remain undetected for an extended period of time, which can increase the breadth and negative impact of an incident. A significant failure, compromise, breach or interruption in our systems or those of third parties critical to our operations could result in a disruption of our operations; physical damage to our assets or the environment; physical, financial, or other harm to employees or others; safety incidents; damage to our reputation; loss of customers or revenues; increased costs for remedial actions; and potential litigation or regulatory fines. Failures, interruptions and similar events that result in the loss or improper disclosure of information maintained in our systems and networks or those of our vendors, including personnel, customer and vendor information, have in the past and may in the future require reporting under relevant contractual obligations and laws and regulations protecting personal data and privacy and could also subject us to litigation or other liability under relevant contractual obligations, laws and regulations. Our financial results could also be adversely affected if our systems are breached or an employee, vendor or customer causes our systems to fail, either as a result of inadvertent error or deliberate tampering with or manipulation of our systems.
Due to the continued acceleration of cyberattacks, generally and against our industry, regulatory actions by federal, state and local governmental agencies in the United States and in Mexico have increased. Evolving laws and regulations governing cybersecurity and data privacy and protection pose increasingly complex compliance challenges. Although we believe that we have robust cybersecurity procedures and other safeguards in place, we cannot guarantee their effectiveness, and a significant failure, compromise, breach or interruption in our systems or those of our customers or vendors could have a material effect on our operations and the operations of our customers and vendors. As threats continue to evolve and cybersecurity and data privacy and protection laws and regulations continue to develop, we have spent and expect to continue spending additional resources to continue to enhance our cybersecurity, data protection, business continuity and incident response measures, to investigate and remediate any vulnerabilities to, or consequences of, cyber incidents, as well as on regulatory compliance.
Disputes regarding a failure to maintain product quality specifications or other claims related to the operation of our assets and the services we provide to our customers result in unforeseen expenses and could result in the loss of customers.
Certain of the products we store and transport are produced to precise customer specifications. If the quality and purity of the products we receive are not maintained or a product fails to perform in a manner consistent with the quality specifications required by our customers, customers have sought, and could in the future seek, replacement of the product or damages for costs incurred as a result of the product failing to perform as guaranteed. We also have faced, and could in the future face, other claims by our customers if our assets do not operate as expected by our customers or our services otherwise do not meet our customers’ expectations. Successful claims or a series of claims against us result in unforeseen expenditures and could result in the loss of one or more customers.
Climate change and fuels legislation and other regulatory initiatives restricting emissions of “greenhouse gases” may decrease demand for some of the products we store, transport and sell, increase our operating costs or reduce our ability to expand our facilities.
Federal and state legislative and regulatory initiatives in the United States, as well as international efforts, have attempted to and will continue to address climate change and control or limit emissions of greenhouse gases. For example, the United States is now a party to the Paris Agreement and has established an economy-wide target of reducing its net greenhouse gas emissions by 50-52 percent below 2005 levels in 2030 and achieving net zero greenhouse gas emissions economy-wide by no later than 2050. The United States has also established a goal to reach 100 percent carbon emissions-free electricity by 2035. Furthermore, many state and local leaders have stated their intent to increase efforts to control or limit emissions of greenhouse gases. To this end, climate change laws or regulations enacted by the United States and other political bodies that increase costs, reduce demand or otherwise impede our operations, could, directly or indirectly, have an adverse effect on our business. Specifically, certain regulatory changes have restricted, and future changes could restrict, our ability to expand our operations and have increased, and in the future could increase, our costs to operate and maintain our existing facilities by requiring that we measure and report our emissions, install new emission controls on our facilities, acquire allowances to authorize our emissions, pay taxes related to our emissions or administer and manage an emissions program, among other things. The passage of climate change legislation and interpretation and action of federal and state regulatory bodies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to greenhouse gases, or restrictions on their use, may reduce volumes available to us for transportation and storage. These developments could have adverse effects on our business, financial position, results of operations and prospects.
In addition, certain of our blending operations subject us to potential requirements to purchase renewable fuels credits. Even though we attempt to mitigate such lost revenues or increased costs through the contracts we sign with our customers, we sometimes are not able to recover those revenues or mitigate the increased costs, and any such recovery depends on events beyond our control, including the outcome of future rate proceedings before the Federal Energy Regulatory Commission (FERC) or other regulators and the provisions of any final legislation or regulations. Reductions in our revenues or increases in our expenses as a result of climate change legislation or other regulatory initiatives could have adverse effects on our business, financial position, results of operations and prospects.
Finally, increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. Such events have had and may in the future have an adverse effect on our assets and operations, especially those located in coastal regions.
Public sentiment towards climate change, fossil fuels and sustainability could adversely affect our business, operations and ability to attract capital.
Our business plans are based upon the assumption that public sentiment and the regulatory environment will continue to enable the future development, transportation and use of carbon-based fuels. Negative public perception of the industry in which we operate and the influence of environmental activists and initiatives aimed at limiting climate change could interfere with our business activities, operations and access to capital. Activists concerned about the potential effects of climate change have directed their attention towards sources of funding for fossil fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital reducing or ceasing lending to or investing in companies in the fossil fuel energy industry, such as us. Such negative sentiment regarding our industry could influence consumer preference and decrease demand for the products we transport and store and result in increased regulatory scrutiny, which could then result in additional laws, regulations, guidelines and enforcement interpretations, at the federal, state or local level. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation.
Members of the investment community are also increasing their focus on sustainability practices, including practices related to greenhouse gas emissions and climate change, in the energy industry. Additionally, some members of the investment community screen companies such as ours for sustainability performance before investing in our units. In response to the increasing pressure regarding sustainability disclosures and practices, we and other companies in our industries publish sustainability reports that are made available to investors. Such reports are used by some investors to inform their investment and voting decisions, and we may continue to face increasing pressure regarding sustainability practices and disclosures. Unfavorable sustainability ratings by organizations that provide such information to investors may lead to increased negative
investor sentiment toward us or our customers and to the diversion of investment to other industries, which would have a negative impact on our unit price and/or our access to and costs of capital.
Our operations are subject to federal, state and local laws and regulations, in the U.S. and in Mexico, relating to environmental, health, safety and security that require us to make substantial expenditures.
Our operations are subject to increasingly stringent international, federal, state and local environmental, health, safety and security laws and regulations. Transporting, storing and distributing hazardous materials, including petroleum products, entails the risk of releasing these products into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies including for damages to natural resources, personal injury or property damages to private parties and significant business interruption. Further, our pipeline facilities are subject to the pipeline integrity and safety regulations of various federal and state regulatory agencies, as well as cybersecurity directives. In recent years, increased regulatory focus on pipeline integrity, safety and security has resulted in various proposed or adopted regulations. The implementation of these regulations has required, and the adoption of future regulations could require, us to make additional capital or other expenditures, including to install new or modified safety or security measures, or to conduct new or more extensive inspection and maintenance programs.
Legislative action and regulatory initiatives have resulted in, and could in the future result in, changes to operating permits, material changes in operations, increased capital expenditures and operating costs, increased costs of the goods we transport and/or decreased demand for products we handle. Future impacts cannot be assessed with certainty at this time. Required expenditures to modify operations or install pollution control equipment or release prevention and containment systems or other environmental, health, safety or security measures could materially and adversely affect our business, financial condition, results of operations and liquidity if these expenditures, as with all costs, are not ultimately reflected in the tariffs and other fees we receive for our services.
We own or lease a number of properties that were used to transport, store or distribute products for many years before we acquired them; therefore, such properties were operated by third parties whose handling, disposal or release of products and wastes was not under our control. Environmental laws and regulations could impose obligations to conduct assessment or remediation efforts at our facilities, third-party sites where we take wastes for disposal, or where wastes have migrated. Environmental laws and regulations also impose joint and several liability on us for the conduct of third parties or for actions that complied with applicable requirements when taken, regardless of negligence or fault. If we were to incur a significant liability pursuant to environmental, health, safety or security laws or regulations, such a liability could have a material adverse effect on our financial position.
We operate assets outside of the United States, which exposes us to different legal and regulatory requirements and additional risk.
A portion of our revenues are generated from our assets located in northern Mexico. Our operations are subject to various risks unique to Mexico that could have a material adverse effect on our business, results of operations and financial condition, including political and economic instability from civil unrest; labor strikes; war and other armed conflict; inflation; currency fluctuations, devaluation and conversion restrictions or other factors. Any deterioration of social, political, labor or economic conditions, including the increasing threat of terrorist organizations and drug cartels in Mexico, or affecting a customer with whom we do business, as well as difficulties in staffing, obtaining necessary equipment and supplies and managing foreign operations, may adversely affect our operations or financial results. We are also exposed to the risk of foreign and domestic governmental actions that may: impose additional costs on us; delay permits or otherwise impede our operations; limit or disrupt markets for our operations, restrict payments or limit the movement of funds; impose sanctions on or otherwise restrict our ability to conduct business with certain customers or persons or in certain countries; or result in the deprivation of contract rights. Our operations outside the United States may also be affected by changes in trade protection laws, policies and measures, and other regulatory requirements affecting trade and investment, including the Foreign Corrupt Practices Act and foreign laws prohibiting corrupt payments, as well as travel restrictions and import and export regulations.
We may be unable to obtain or renew permits necessary for our current or proposed operations, which could inhibit our ability to conduct or expand our business.
Our facilities operate under a number of federal, state and local permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. These limits and standards require a significant amount of monitoring, recordkeeping and reporting in order to demonstrate compliance with the underlying permit, license or approval. Noncompliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. In addition, public protest, political activism and responsive government intervention have made it more difficult for energy companies to acquire the permits required to complete planned infrastructure projects. A decision by a government agency to deny or delay issuing a new or renewed permit, license or approval, or to revoke or substantially modify an existing permit, license or approval, could have a material adverse effect on our ability to continue or expand our operations and on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.
We could be subject to liabilities from our assets that predate our acquisition of those assets, but that are not covered by indemnification rights we have against the sellers of the assets.
We have acquired assets and businesses and we are not always indemnified by the seller for liabilities that precede our ownership. In addition, in some cases, we have indemnified the previous owners and operators of acquired assets or businesses. Some of our assets have been used for many years to transport and store crude oil and refined products, and past releases could require costly future remediation. If a significant release or event occurred in the past, the liability for which was not retained by the seller, or for which indemnification by the seller is not available, it could adversely affect our financial position and results of operations. Conversely, if liabilities arise from assets we have sold, we could incur costs related to those liabilities if the buyer possesses valid indemnification rights against us with respect to those assets.
Our interstate common carrier pipelines are subject to regulation by the FERC, which could have an adverse impact on our ability to recover the full cost of operating our pipelines and the revenue we are able to receive from those operations.
The FERC regulates the tariff rates and terms and conditions of service for interstate oil movements on common carrier pipelines. FERC requires that these rates be just and reasonable and that the pipeline not engage in undue discrimination with respect to any shipper. The FERC or shippers may challenge required pipeline tariff filings, including rates and terms and conditions of service. Further, other than for rates set under market-based rate authority, if a new rate is challenged by protest and investigated by the FERC, the FERC may require the pipeline owner to refund amounts collected in excess of the deemed just and reasonable rate. In addition, shippers may challenge by complaint tariff rates and terms and conditions of service even after they take effect, and the FERC may order a carrier to change its rates prospectively to a just and reasonable level. A complaining shipper also may obtain reparations for damages sustained during the two years prior to the date of the complaint.
We are able to use various FERC-authorized rate change methodologies for our interstate pipelines, including indexed rates, cost-of-service rates, market-based rates and negotiated rates. Typically, we adjust our rates annually in accordance with the FERC indexing methodology, which currently allows a pipeline to change its rates within prescribed ceiling levels that are tied to an inflation index. It is possible that the index may result in negative rate adjustments in some years, or that changes in the index might not be large enough to fully reflect actual increases in our costs. The FERC’s indexing methodology is subject to review and revision every five years, with the most recent five-year review occurring in 2020. On December 17, 2020, the FERC established the index level for the five-year period commencing July 1, 2021, which will end on June 30, 2026, at the Bureau of Labor’s producer price index for finished goods (PPI-FG) plus 0.78%. On January 20, 2022, the FERC granted rehearing of certain aspects of the final rule and revised the index level to PPI-FG minus 0.21%, effective March 1, 2022 through June 30, 2026. FERC ordered pipelines with filed rates that exceed their index ceiling levels based on PPI-FG minus 0.21% to file rate reductions effective March 1, 2022. Pending appellate review could result in a further change to the index.
FERC has granted us authority to charge market-based rates on some of our pipelines, which are not subject to cost-of-service or indexing constraints. If we were to lose market-based rate authority, however, we could be required to establish rates on some other basis, such as cost-of-service, which could reduce our revenues and cash flows. Additionally, because competition constrains our rates in various markets, we may from time to time be forced to reduce some of our rates to remain competitive.
We do not own all of the land on which our pipelines and facilities are located, and we are therefore subject to the possibility of increased costs or the inability to retain necessary land use.
Like other pipeline and storage logistics services providers, certain of our pipelines, storage terminals and other facilities are located on land owned by third parties and governmental agencies that we have obtained the right to utilize for these purposes through contract (rather than through outright purchase). Many of our rights-of-way or other property rights are perpetual in duration, but others are for a specific period of time. In addition, some of our facilities are located on leased premises. A potential loss of property rights through our inability to renew right-of-way contracts or leases or otherwise retain property rights on acceptable terms or the increased costs to renew such rights could adversely affect our financial condition, results of operations and cash flows available for distribution to our unitholders.
Increases in power prices could adversely affect our operating expenses and our ability to make distributions to our unitholders.
Power costs constitute a significant portion of our operating expenses. For the year ended December 31, 2022, our power costs equaled approximately $51.6 million, or 14% of our operating expenses for the year. We use mainly electric power at our pipeline pump stations and terminals, and such electric power is furnished by various utility companies. Requirements for utilities to use less carbon intensive power or to add pollution control devices also could cause our power costs to increase and our cash flows may be adversely affected, which could adversely affect our ability to make distributions to our unitholders.
We may be adversely affected by changes in the method of determining the London Interbank Offering Rate (LIBOR) or the replacement of LIBOR with an alternative reference rate, such as the Secured Overnight Financing Rate (SOFR).
The publication of non-U.S. dollar LIBOR rates ceased after publication on December 31, 2021 and the publication of U.S. dollar LIBOR rates for the most common tenors (overnight and one, three, six and twelve months) is expected to cease after publication on June 30, 2023. Regulators have emphasized that, despite any continued publication of U.S. dollar LIBOR rates through June 30, 2023, no new contracts using U.S. dollar LIBOR rates should be entered into after December 31, 2021.
Further, there is no assurance that LIBOR, or any particular currency and tenor, will continue to be published until any particular date.
In addition, in March 2022, the Adjustable Interest Rate (LIBOR) Act (the “LIBOR Act”) was signed into law. This law provides a statutory fallback mechanism to replace LIBOR with a benchmark rate that is selected by the Federal Reserve Board and based on SOFR for certain contracts that reference LIBOR without adequate fallback provisions providing for a clearly defined replacement benchmark. On December 16, 2022, the Federal Reserve Board adopted a final rule to implement the LIBOR Act and established benchmark rates based on SOFR to replace LIBOR contracts governed by U.S. law that reference certain tenors of U.S. dollar LIBOR after June 30, 2023. The regulations include provisions that (i) provide a mechanism for the automatic replacement of LIBOR with the benchmark rate selected by the Federal Reserve Board; (ii) clarify who may contractually select a benchmark replacement for LIBOR; and (iii) ensure that contracts transitioning to the replacement benchmark rate selected by the Federal Reserve Board will not be interrupted or terminated following the replacement of LIBOR.
Following the amendment and restatement of our revolving credit agreement and the amendment of our accounts receivable securitization program on January 28, 2022, to replace LIBOR with SOFR as the benchmark rate, we had approximately $0.4 billion of variable-rate indebtedness using LIBOR as a benchmark for establishing the interest rate. In addition, the distribution rates on our Series A, Series B and Series C preferred units converted from a fixed rate to a floating rate based on LIBOR in December 2021, June 2022 and December 2022, respectively. Although our variable rate indebtedness and Series A, Series B and Series C preferred units contain certain alternative calculation measures if LIBOR is no longer published, we are unable to unilaterally change the LIBOR-based rates on our variable rate indebtedness and Series A and Series B preferred units to a replacement benchmark rate without the consent of the holders of the variable rate indebtedness, the holders of 66-2/3% of each of the Series A and Series B preferred units, and we may not be able to do so on terms favorable to us. We do not anticipate seeking or obtaining consent of holders of the Series A and Series B preferred units. In accordance with the LIBOR Act, we expect that the floating rate based on LIBOR with respect to the Series A and Series B preferred units will be replaced with the 3-month SOFR plus a credit spread adjustment. The calculation agent for the Series C preferred units is able to select a replacement benchmark for LIBOR, however, such election may not be made in a manner favorable to us. Furthermore, given SOFR’s limited history and potential volatility as compared to other benchmark or market rates, the future performance of SOFR cannot be predicted based on historical performance. The consequences of the transition away from LIBOR and the use of SOFR cannot be entirely predicted but could include an increase in the cost of our variable-rate indebtedness, our Series A, Series B and Series C preferred units and other commercial arrangements tied to LIBOR.
An impairment of goodwill or long-lived assets could reduce our earnings.
As of December 31, 2022, we had $0.7 billion of goodwill and $3.9 billion of long-lived assets, including property, plant and equipment, net and intangible assets, net. U.S. generally accepted accounting principles requires us to test both goodwill and long-lived assets for impairment when events or circumstances occur indicating that either goodwill or long-lived assets might be impaired and, in the case of goodwill, at least annually. Charges to impair our goodwill or our long-lived assets reduce earnings and partners’ capital. Any event that causes a reduction in demand for our services could result in a reduction of our estimates of future cash flows and growth rates in our business, which could cause us to record an impairment charge to reduce the value of goodwill. Similarly, any event or change in circumstances that causes the carrying value of our long-lived assets to no longer be recoverable may require us to record an impairment charge to reduce the value of our long-lived assets.
If we determine that either our goodwill or our long-lived assets are impaired, the resulting charge will reduce earnings and partners’ capital.
RISKS INHERENT IN AN INVESTMENT IN US
As a master limited partnership, we do not have the same flexibility that corporations and other types of organizations may have to accumulate cash and prevent illiquidity in the future, which may also limit our growth.
Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our common unitholders of all available cash, after taking into account reserves for commitments and contingencies, including growth and other capital expenditures and operating costs, debt service requirements and payments with respect to our preferred units. We are therefore more likely than those organizations to require issuances of additional debt and equity securities to finance our growth plans, meet unforeseen cash requirements and service our debt and other obligations.
In addition, to the extent we issue additional units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain our current per unit distribution level and the value of our common units and other limited partner interests may decrease in correlation with any reduction in our cash distributions per unit. Accordingly, if we experience a liquidity shortage in the future, we may not be able to issue more equity to recapitalize.
Unitholders have limited voting rights, and our partnership agreement restricts the voting rights of certain unitholders owning 20% or more of any class of our units.
Unlike 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’ voting rights are further restricted by a provision in our partnership agreement providing that units held by certain persons that own 20% or more of any class of units then outstanding cannot vote on any matter without the prior approval of our general partner.
We may issue additional equity securities, including equity securities that are senior to our common units, which would dilute our unitholders’ existing ownership interests.
Our partnership agreement allows us to issue an unlimited number of additional equity securities without the approval of other unitholders as long as the newly issued equity securities are not senior to, or equally ranked with, our preferred units. With the consent of the holders of a majority of the Series D preferred units, we may issue an unlimited number of units that are senior to our common units and equally ranked with our preferred units. However, in certain circumstances, we may be required to obtain the approval of the holders of a majority of each class of our preferred units before we could issue equity securities that are equally ranked with our preferred units.
Our issuance of additional units or other equity interests 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 amount of cash available for redemption of, or payment of the liquidation preference on, each preferred unit may decrease;
•the ratio of taxable income to distributions may increase;
•the relative voting strength of each previously outstanding unit may be diminished; and
•the market price of our common units and preferred units may decline.
Holders of our Series D preferred units generally have the same voting rights as holders of our common units and generally vote on an as-converted basis with the holders of our common units as a single class. Although holders of our other preferred units also have voting rights, such rights are limited to certain matters and require that such holders vote as a separate class with all other series of our equally ranked securities that may be issued and possess similar voting rights. As a result, the voting rights of holders of our preferred units may be significantly diluted, and the holders of such future securities of equal rank may be able to control or significantly influence the outcome of any vote with respect to which the holders of our preferred units are entitled to vote. Our partnership agreement contains limited protections for the holders of our preferred units (other than Series D preferred units) in the event of a transaction, including a merger, sale, lease or conveyance of all or substantially all of our assets or business, which might adversely affect the holders of our preferred units.
Future issuances and sales of securities that rank equally with our preferred units, or the perception that such issuances and sales could occur, may cause prevailing market prices for our preferred units and our common units to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us. Furthermore, the payment of distributions on any additional units may increase the risk that we will not be able to make distributions at our prior per unit distribution levels. To the extent new units are senior to our common units, their issuance will increase the uncertainty of the payment of distributions on our common units.
If we do not pay distributions on our preferred units in any distribution period, we would be unable to declare or pay distributions on our common units until all unpaid preferred unit distribution obligations have been paid, and our common unitholders are not entitled to receive distributions for such prior period.
Our preferred units rank senior to our common units with respect to distribution rights and rights upon liquidation. If we do not pay the required distributions on our preferred units, we will be unable to declare or pay distributions on our common units. Additionally, because distributions to our preferred unitholders are cumulative, we will have to pay all unpaid accumulated preferred distributions before we can declare or pay any distributions to our common unitholders. Also, because distributions to our common unitholders are not cumulative, if we do not pay distributions on our common units with respect to any quarter, our common unitholders will not be entitled to receive distributions covering any prior periods. In addition, if we do not pay the required distributions on our Series D preferred units for three consecutive distribution periods, the holders of our Series D preferred units have certain additional rights until such distributions are paid, including the right to convert the Series D preferred units into common units, the right to appoint one director to our board of directors and the right to approve certain subsequent indebtedness, acquisitions or asset sales. The preferences and privileges of our preferred units could adversely affect the market price for our common units, or could make it more difficult for us to sell our common units in the future.
If a court were to determine that a unitholder action constituted control of our business, the unitholders may lose their legal protection from liability and be required to repay distributions wrongfully distributed to them.
Under Delaware law, if a court were to determine that actions of a unitholder constituted participation in the “control” of our business, unitholders would be held liable for our obligations to the same extent as a general partner. In addition, under
Delaware law, the general partner generally has unlimited liability for the obligations of the partnership, such as its debts and environmental liabilities, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner.
Furthermore, under Delaware law, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are nonrecourse to the partnership are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that, for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to us for the repayment of the distribution amount. Likewise, upon the winding up of our partnership, in the event that (a) we do not distribute assets in the following order: (1) to creditors in satisfaction of our debts; (2) to partners and former partners in satisfaction of liabilities for distributions owed under our partnership agreement; (3) to partners for the return of their contributions; and finally (4) to the partners in the proportions in which the partners share in distributions and (b) a limited partner knows at the time that the distribution violated Delaware law, then such limited partner will be liable to repay the distribution for a period of three years from the impermissible distribution under applicable Delaware law.
A purchaser of our common or preferred units becomes a limited partner and is liable for the obligations of the transferring limited partner to make contributions to us that are known to such purchaser of common or preferred units at the time it became a limited partner and, for unknown obligations, if the liabilities could be determined from our partnership agreement.
The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.
We currently list our common units on the NYSE under the symbol “NS” and certain of our preferred units on the NYSE under the symbols “NSprA,” “NSprB” and “NSprC,” respectively. Although our general partner has maintained a majority of independent directors on its board and all members of its board’s audit committee, compensation committee and nominating/governance & conflicts committee are independent directors, because we are a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to have a compensation committee or a nominating committee consisting of independent directors. Additionally, any future issuance of additional common or preferred units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules that apply to a corporation. Accordingly, the NYSE does not mandate the same protections for our unitholders as are required for certain corporations that are subject to all of the NYSE corporate governance requirements.
TAX RISKS TO OUR UNITHOLDERS
If we were treated as a corporation for federal or state income tax purposes or we were otherwise subject to a material amount of entity-level taxation, then our cash available for distribution to unitholders would be substantially reduced.
The anticipated after-tax benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes. Despite the fact that we are a limited partnership under Delaware law, we will be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement.
If we were treated as a corporation, we would pay federal income tax at the corporate tax rate and would likely pay state and local income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our distributable cash flow would be substantially reduced. Additionally, at the state level, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. If we were treated as a corporation for federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, then our cash available for distribution to unitholders would be substantially reduced and there would be a material reduction in the after-tax return to our unitholders, likely causing a substantial reduction in the value of our units.
The tax treatment of publicly traded partnerships or an investment in our 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 units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships, including elimination of partnership tax treatment for certain publicly traded partnerships.
Any changes to the federal income tax laws and interpretations thereof may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for federal income tax purposes or otherwise adversely affect our business, financial condition or results of operations. We are unable to predict whether any additional changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our units.
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, penalties and interest directly from us. If we bear such payment, our cash available for distribution to our unitholders might be substantially reduced.
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, penalties and interest resulting from such audit adjustment directly from us. To the extent possible under applicable rules, our general partner may pay such amounts directly to the IRS or, if we are eligible, elect to issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. No assurances can be made 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 common units in us during the tax year under audit. If, as a result of any such audit adjustment, we make payments of taxes, penalties and interest, our cash available for distribution to our unitholders could be substantially reduced.
Unitholders will be required to pay taxes on their share of our taxable income even if they do not receive cash distributions from us.
Unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their respective share of our taxable income, whether or not the unitholders receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their respective share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.
Tax gain or loss on the disposition of our common units could be different than expected.
A unitholder who sells units will recognize a gain or loss equal to the difference between the amount realized and the unitholder’s tax basis in those units. Prior distributions to the unitholder in excess of the total net taxable income with respect to a common unit will reduce the unitholder’s tax basis in that unit. As a result, the selling unitholder can recognize a gain if such unit is sold at a price greater than the unitholder’s tax basis in that unit, even if the price the unitholder receives is less than the unit’s original cost. A substantial portion of the amount realized, even if there is a net taxable loss realized on the sale, may be ordinary income to the selling unitholder. In addition, because the amount realized will include a unitholder’s share of our nonrecourse liabilities, a unitholder may incur a tax liability upon a sale of common units in excess of the amount of cash it receives from the sale.
Unitholders may be subject to limitations on their ability to deduct interest expense incurred by us.
Our ability to deduct interest paid or accrued on indebtedness properly allocable to a trade or business, “business interest”, may be limited in certain circumstances. Should our ability to deduct business interest be limited, the amount of taxable income allocated to our unitholders in the taxable year in which the limitation is in effect may increase. However, in certain circumstances, a unitholder may be able to utilize a portion of a business interest deduction subject to this limitation in future taxable years. Prospective unitholders should consult their tax advisors regarding the impact of this business interest deduction limitation on an investment in our units.
Tax-exempt entities face unique tax issues from owning our units that may result in adverse tax consequences to them.
Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (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. Tax-exempt entities should consult a tax advisor before investing in our 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 subject to U.S. federal income tax on income effectively connected with a U.S. trade or business (effectively connected income). A unitholder’s share of our income, gain, loss and deduction, and any gain from the sale or disposition of our units will generally be considered to be effectively connected income and subject to U.S. federal income tax. Additionally, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate.
Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person. Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor. Quarterly distributions made to our non-U.S. unitholders will also be subject to withholding under these rules to the extent a portion of a distribution is attributable to an amount in excess of our cumulative net income that has not previously been distributed. The determination of cumulative net income is complex and unclear in certain respects, and we intend to treat all of our distributions as being in excess of our cumulative net income for such purposes and subject to the additional 10% withholding tax. The Treasury regulations further provide that these rules will generally not apply to transfers of, or distributions on, interests in a publicly traded partnership occurring before January 1, 2023, and after that date, if effected through a broker, the obligation to withhold is imposed on the transferor’s broker. Current and prospective non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common and preferred units.
We will treat each purchaser of our common units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
Because we cannot match transferors and transferees of our common units, we have adopted depreciation and amortization positions that may not conform with all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the unitholder’s tax returns.
Unitholders will likely be subject to state and local taxes and return filing requirements as a result of investing in our units.
In addition to federal income taxes, unitholders will likely 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. Unitholders will likely 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. Further, unitholders may be subject to penalties for failure to comply with those requirements. We may own property or conduct business in other states or foreign countries in the future. It is each unitholder’s responsibility to file all federal, state and local tax returns.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our common unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. Treasury regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our common unitholders.
We have adopted certain valuation methodologies in determining a common unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methods or the resulting allocations and such a challenge could adversely affect the value of our common units.
In determining the items of income, gain, loss and deduction allocable to our common unitholders, we must routinely determine the fair market value of our respective assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make 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 respective 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, character and timing of taxable income or loss being allocated to our common unitholders. It also could affect the amount of gain 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 common unitholders’ tax returns without the benefit of additional deductions.
A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller”) may be considered as having disposed of those units. If so, the unitholder 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 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, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan 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 loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
Treatment of distributions on our preferred units as guaranteed payments for the use of capital creates a different tax treatment for the holders of preferred units than the holders of our common units and such distributions are not eligible for the 20% deduction for qualified publicly traded partnership income.
The tax treatment of distributions on our preferred units is uncertain. We will treat the holders of preferred units as partners for tax purposes and will treat distributions on the preferred units as guaranteed payments for the use of capital that will generally be taxable to the holders of preferred units as ordinary income. Holders of preferred units will recognize taxable income from the accrual of such a guaranteed payment even in the absence of a contemporaneous distribution. Otherwise, the holders of preferred units are generally not anticipated to share in our items of income, gain, loss or deduction, nor will we allocate any share of our nonrecourse liabilities to the holders of preferred units. If the preferred units were treated as indebtedness for tax
purposes, rather than as guaranteed payments for the use of capital, distributions likely would be treated as payments of interest by us to the holders of preferred units.
Although we expect that much of our income will be eligible for the 20% deduction for qualified publicly traded partnership income, Treasury regulations provide that income attributable to a guaranteed payment for the use of capital is not eligible for the 20% deduction for qualified business income. As a result, income attributable to a guaranteed payment for use of capital recognized by holders of our preferred units is not eligible for the 20% deduction for qualified business income.
A holder of preferred units will be required to recognize gain or loss on a sale of preferred units equal to the difference between the amount realized by such holder and such holder’s tax basis in the preferred units sold. The amount realized generally will equal the sum of the cash and the fair market value of other property such holder receives in exchange for such preferred units. Subject to general rules requiring a blended basis among multiple partnership interests, the tax basis of a preferred unit will generally be equal to the sum of the cash and the fair market value of other property paid to acquire such preferred unit. Gain or loss recognized on the sale or exchange of a preferred unit held for more than one year generally will be taxable as long-term capital gain or loss. Because holders of preferred units will generally not be allocated a share of our items of depreciation, depletion or amortization, it is not anticipated that such holders would be required to recharacterize any portion of their gain as ordinary income as a result of the recapture rules.
Investment in the preferred units by tax-exempt investors, such as employee benefit plans and IRAs, and non-U.S. persons raises issues unique to them. The treatment of guaranteed payments for the use of capital to tax-exempt investors is not certain and the income resulting from such payments may be treated as unrelated business taxable income for U.S. federal income tax purposes. A non-U.S. holder’s income from guaranteed payments and any gain from the sale or disposition of our units may be considered to be effectively connected income and subject to U.S. federal income tax. Distributions and any gain from the sale or disposition of our preferred units to non-U.S. holders of preferred units may be subject to withholding taxes. If the amount of withholding exceeds the amount of U.S. federal income tax actually due, non-U.S. holders of preferred units may be required to file U.S. federal income tax returns in order to seek a refund of such excess.
All holders of our preferred units are urged to consult a tax advisor with respect to the consequences of owning and selling our preferred units.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
We incorporate by reference into this Item 3 our disclosures in Note 14 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” under the caption, “Contingencies.”
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Series D Preferred Units
On November 16, 2022, NuStar Energy L.P. entered into agreements with EIG Nova Equity Aggregator, L.P and FS Energy and Power Fund to repurchase an aggregate 6,900,000 of our Series D Cumulative Convertible Preferred Units (Series D Preferred Units) at a price per unit of $32.73 for an aggregate purchase price of $225.8 million, including approximately $3.4 million related to accrued distributions. These transactions closed on November 22, 2022. The number of Series D Preferred Units outstanding as of December 31, 2022 and 2021, totaled 16,346,650 and 23,246,650, respectively.
Series A, B and C Preferred Units
Information on our 8.50% Series A, 7.625% Series B and 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (collectively, the Series A, B and C Preferred Units) is shown below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
ITEM 7A.Units | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | | | | | | | | | Units Issued and Outstanding as of December 31, 2022 | | Optional Redemption Date/Date When Distribution Rate Became Floating | | Floating Annual Rate (as a Percentage of the $25.00 Liquidation Preference Per Unit) |
| Series A Preferred Units | | | | | | | | | | 9,060,000 | | December 15, 2021 | | Three-month LIBOR plus 6.766% |
| Series B Preferred Units | | | | | | | | | | 15,400,000 | | June 15, 2022 | | Three-month LIBOR plus 5.643% |
| Series C Preferred Units | | | | | | | | | | 6,900,000 | | December 15, 2022 | | Three-month LIBOR plus 6.88% |
Interest Rate Risk
Common Units
Our common units are listed and traded on the New York Stock Exchange under the symbol “NS.” At the close of business on February 9, 2023, we had 360 holders of record of our common units.
Our partnership agreement requires that we distribute all “Available Cash” to our common limited partners each quarter. This term is defined in the partnership agreement generally as cash receipts less cash disbursements, including distributions to our preferred units, and cash reserves established by the general partner, in its sole discretion.
Please see Notes 17 and 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on our Series D Preferred Units, Series A, B and C Preferred Units and common units.
Performance Graph
The following Performance Graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference into any of NuStar Energy’s filings under the Securities Act of 1933 or the Securities Exchange Act of 1934, as amended, respectively. The stock or unit price performance included in this graph is not necessarily indicative of future stock or unit price performance.
The following graph compares the cumulative five-year total return provided to holders of NuStar Energy’s common units relative to the cumulative total returns of the S&P 500 index and the Alerian MLP index. An investment of $100 (with reinvestment of all dividends) is assumed to have been made in our common units and in each of the indexes on December 31, 2017, and its relative performance is tracked through December 31, 2022.
*$100 invested on December 31, 2017 in stock or index, including reinvestment of dividends.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| As of December 31, |
| 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | 2022 |
| NuStar Energy L.P. | 100.00 | | | 77.87 | | | 105.15 | | | 66.01 | | | 80.23 | | | 89.42 | |
| S&P 500 Index | 100.00 | | | 95.62 | | | 125.72 | | | 148.85 | | | 191.58 | | | 156.89 | |
| Alerian MLP Index | 100.00 | | | 87.58 | | | 93.32 | | | 66.55 | | | 93.28 | | | 122.12 | |
Sales of Unregistered Securities
During the fourth quarters of 2022, 2021 and 2020 and the first quarter of 2020, NuStar Energy issued an aggregate of 3,120 common units, 5,509 common units, 11,384 common units and nine common units, respectively, in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof, upon the vesting of outstanding awards under a long-term incentive plan.
ITEM 6. RESERVED
ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
INTEREST RATE RISK
Debt
We manage our exposure to changing interest rates principally through the use of a combination of fixed-rate debt and variable-rate debt. In addition, we utilize forward-starting interest rate swap agreements to lock in the rate on the interest payments related to forecasted debt issuances. Borrowings under our variable-rate debt expose us to increases in interest rates.
On January 28, 2022, we amended and restated our $1.0 billion unsecured revolving credit agreement to extend the maturity to April 27, 2025, replace the LIBOR-based interest rate and modify other terms. Also on January 28, 2022, we amended our $100.0 million receivables financing agreement to extend the scheduled termination date to January 31, 2025, replace the LIBOR-based interest rate and modify other terms. Please refer to Note 2 and Note 1612 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a more detailed discussion of our interest rate swaps. information.
The following tables present principal cash flows and related weighted-average interest rates by expected maturity dates for our long-term
debt:debt, excluding finance leases: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | Expected Maturity Dates | | | | |
| | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | There- after | | Total | | Fair Value |
| | (Thousands of Dollars, Except Interest Rates) |
| Long-term Debt: | | | | | | | | | | | | | | | |
| Fixed-rate | $ | 350,000 |
| | $ | — |
| | $ | 450,000 |
| | $ | 300,000 |
| | $ | 250,000 |
| | $ | 952,500 |
| | $ | 2,302,500 |
| | $ | 2,355,535 |
|
Weighted-average interest rate | 8.4 | % | | — |
| | 4.8 | % | | 6.8 | % | | 4.8 | % | | 6.5 | % | | 6.3 | % | | |
| Variable-rate | $ | — |
| | $ | — |
| | $ | 955,611 |
| | $ | — |
| | $ | — |
| | $ | 365,440 |
| | $ | 1,321,051 |
| | $ | 1,322,087 |
|
Weighted-average interest rate | — |
| | — |
| | 3.1 | % | | — |
| | — |
| | 1.7 | % | | 2.7 | % | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2022 |
| | Expected Maturity Dates | | | | |
| | 2023 | | 2024 | | 2025 | | 2026 | | 2027 | | There-
after | | Total | | Fair
Value |
| | (Thousands of Dollars, Except Interest Rates) |
| Fixed-rate debt | $ | — | | | $ | — | | | $ | 600,000 | | | $ | 500,000 | | | $ | 550,000 | | | $ | 922,140 | | | $ | 2,572,140 | | | $ | 2,478,720 | |
| Weighted-average rate | — | | | — | | | 5.8 | % | | 6.0 | % | | 5.6 | % | | 6.3 | % | | 6.0 | % | | — | |
| Variable-rate debt | $ | — | | | $ | — | | | $ | 300,900 | | | $ | — | | | $ | — | | | $ | 402,500 | | | $ | 703,400 | | | $ | 690,944 | |
| Weighted-average rate | — | | | — | | | 6.7 | % | | — | | | — | | | 10.8 | % | | 9.0 | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2021 |
| | Expected Maturity Dates | | | | |
| | 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | There-
after | | Total | | Fair
Value |
| | (Thousands of Dollars, Except Interest Rates) |
| Fixed-rate debt | $ | — | | | $ | — | | | $ | — | | | $ | 600,000 | | | $ | 500,000 | | | $ | 1,472,140 | | | $ | 2,572,140 | | | $ | 2,858,794 | |
| Weighted-average rate | — | | | — | | | — | | | 5.8 | % | | 6.0 | % | | 6.0 | % | | 6.0 | % | | — | |
| Variable-rate debt | $ | — | | | $ | 194,300 | | | $ | — | | | $ | — | | | $ | — | | | $ | 402,500 | | | $ | 596,800 | | | $ | 600,359 | |
| Weighted-average rate | — | | | 2.5 | % | | — | | | — | | | — | | | 6.9 | % | | 5.4 | % | | — | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2016 |
| | Expected Maturity Dates | | | | |
| | 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | There- after | | Total | | Fair Value |
| | (Thousands of Dollars, Except Interest Rates) |
| Long-term Debt: | | | | | | | | | | | | | | | |
| Fixed-rate | $ | — |
| | $ | 350,000 |
| | $ | — |
| | $ | 450,000 |
| | $ | 300,000 |
| | $ | 652,500 |
| | $ | 1,752,500 |
| | $ | 1,821,261 |
|
Weighted-average interest rate | — |
| | 8.2 | % | | — |
| | 4.8 | % | | 6.8 | % | | 6.5 | % | | 6.4 | % | | |
| Variable-rate | $ | — |
| | $ | 58,400 |
| | $ | 838,992 |
| | $ | — |
| | $ | — |
| | $ | 365,440 |
| | $ | 1,262,832 |
| | $ | 1,263,501 |
|
Weighted-average interest rate | — |
| | 1.6 | % | | 2.5 | % | | — |
| | — |
| | 0.7 | % | | 1.9 | % | | |
Series A, B and C Preferred Units
Distributions on our 8.50% Series A, 7.625% Series B and 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (collectively, the Series A, B and C Preferred Units) are payable out of any legally available funds, accrue and are cumulative from the original issuance dates, and are payable on the 15th day (or the next business day) of each of March, June, September and December of each year to holders of record on the first business day of each payment month. The following table presentsSeries A, B and C Preferred Units expose us to changes in interest rates as the distribution rates on these units converted to a floating rate of the applicable LIBOR plus a spread on December 15, 2021, June 15, 2022 and December 15, 2022, respectively. Based upon the 9,060,000 Series A Preferred Units, 15,400,000 Series B Preferred Units and 6,900,000 Series C Preferred Units outstanding at December 31, 2022 and the $25.00 liquidation preference per unit, a change of 1.0% in interest rates would increase or decrease the annual distributions on our Series A, B and C Preferred Units by an aggregate amount of $7.8 million. Please see Note 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information regardingon our forward-starting interest rate swap agreements:Series A, B and C Preferred Units.
|
| | | | | | | | | | | | | | | | | | | |
| Notional Amount as of December 31, | | Period of Hedge | | Weighted-Average Fixed Rate | | Fair Value as of December 31, |
| 2017 | | 2016 | | | | 2017 | | 2016 |
| (Thousands of Dollars) | | | | | | (Thousands of Dollars) |
| $ | 350,000 |
| | $ | 350,000 |
| | 04/2018 - 04/2028 | | 2.6 | % | | $ | (5,394 | ) | | $ | (1,333 | ) |
| 250,000 |
| | 250,000 |
| | 09/2020 - 09/2030 | | 2.8 | % | | (4,594 | ) | | 15 |
|
| $ | 600,000 |
| | $ | 600,000 |
| | | | 2.7 | % | | $ | (9,988 | ) | | $ | (1,318 | ) |
Commodity Price RiskCOMMODITY PRICE RISK
Since the operations of our fuels marketing segment expose us to commodity price risk, we also use derivative instruments to attempt to mitigate the effects of commodity price fluctuations. The derivative instruments we use consist primarily of commodity futures and swap contracts. Please refer to our derivativeDerivative financial instruments accounting policy in Note 2 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further information on our various types of derivatives.
We have a risk management committee that oversees our trading policies and procedures and certain aspects of risk management. Our risk management committee also reviews all new risk management strategies in accordanceassociated with our risk management policy, as approved by our board of directors.
The commodity contracts disclosed below represent only those contracts exposed to commodity price risk at the endwere not material for any periods presented.
|
| | | | | | | | | | | | | | |
| | December 31, 2017 |
| | Contract Volumes | | Weighted Average | | Fair Value of Current Asset (Liability) |
| Pay Price | | Receive Price | |
| | (Thousands of Barrels) | | | | | | (Thousands of Dollars) |
| Fair Value Hedges: | | | | | | | |
| Futures – long: | | | | | | | |
| (refined products) | 2 |
| | $ | 86.88 |
| | N/A |
| | $ | — |
|
| Futures – short: |
| |
| |
| |
|
| (refined products) | 5 |
| | N/A |
| | $ | 85.59 |
| | $ | (6 | ) |
| Swaps – short: |
| |
| |
| |
|
| (refined products) | 149 |
| | N/A |
| | $ | 55.79 |
| | $ | (106 | ) |
| |
| |
| |
| |
|
| Economic Hedges and Other Derivatives: |
| |
| |
| |
|
| Futures – long: |
| |
| |
| |
|
| (refined products) | 10 |
| | $ | 86.13 |
| | N/A |
| | $ | 7 |
|
| Futures – short: |
| |
| |
| |
|
| (refined products) | 14 |
| | N/A |
| | $ | 85.76 |
| | $ | (16 | ) |
| Swaps – long: |
| |
| |
| |
|
| (refined products) | 196 |
| | $ | 55.05 |
| | N/A |
| | $ | 264 |
|
| Swaps – short: |
| |
| |
| |
|
| (refined products) | 199 |
| | N/A |
| | $ | 53.76 |
| | $ | (525 | ) |
| | | | | | | | |
Total fair value of open positions exposed to commodity price risk | | | | | | | $ | (382 | ) |
|
| | | | | | | | | | | | | | |
| | December 31, 2016 |
| | Contract Volumes | | Weighted Average | | Fair Value of Current Asset (Liability) |
| Pay Price | | Receive Price | |
| | (Thousands of Barrels) | | | | | | (Thousands of Dollars) |
| Fair Value Hedges: | | | | | | | |
| Futures – long: | | | | | | | |
| (crude oil and refined products) | 47 |
| | $ | 55.53 |
| | N/A |
| | $ | 2 |
|
| Futures – short: |
| |
| |
| |
|
| (crude oil and refined products) | 107 |
| | N/A |
| | $ | 58.79 |
| | $ | (243 | ) |
| Swaps – long: |
| |
| |
| |
|
| (refined products) | 84 |
| | $ | 45.99 |
| | N/A |
| | $ | 141 |
|
| Swaps – short: |
| |
| |
| |
|
| (refined products) | 573 |
| | N/A |
| | $ | 41.87 |
| | $ | (3,322 | ) |
| |
| |
| |
| |
|
| Economic Hedges and Other Derivatives: |
| |
| |
| |
|
| Futures – long: |
| |
| |
| |
|
| (crude oil and refined products) | 18 |
| | $ | 72.06 |
| | N/A |
| | $ | 10 |
|
| Futures – short: |
| |
| |
| |
|
| (crude oil and refined products) | 9 |
| | N/A |
| | $ | 71.88 |
| | $ | (7 | ) |
| Swaps – long: |
| |
| |
| |
|
| (refined products) | 869 |
| | $ | 42.20 |
| | N/A |
| | $ | 4,737 |
|
| Swaps – short: |
| |
| |
| |
|
| (refined products) | 874 |
| | N/A |
| | $ | 41.40 |
| | $ | (5,459 | ) |
| Forward purchase contracts: |
| |
| |
| |
|
| (crude oil) | 310 |
| | $ | 52.78 |
| | N/A |
| | $ | 499 |
|
| Forward sales contracts: |
| |
| |
| |
|
| (crude oil) | 310 |
| | N/A |
| | $ | 52.76 |
| | $ | (507 | ) |
| | | | | | | | |
Total fair value of open positions exposed to commodity price risk | | | | | | | $ | (4,149 | ) |
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining effective internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934. Our management assessed the effectiveness of NuStar Energy L.P.’s internal control over financial reporting as of December 31, 2017.2022. In its evaluation, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (2013). Based on this assessment, management believes that, as of December 31, 2017,2022, our internal control over financial reporting was effective based on those criteria.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Management’s evaluation of and conclusion regarding the effectiveness of our internal control over financial reporting excludes the internal control over Navigator Energy Services, LLC acquired on May 4, 2017 (as described in Note 4), which contributed approximately 2% of our total revenues for the year ended December 31, 2017 and accounted for approximately 23% of our total assets as of December 31, 2017. We plan to fully integrate these assets and operations into our internal control over financial reporting in 2018.
The effectiveness of internal control over financial reporting as of December 31, 20172022 has been audited by KPMG LLP, the independent registered public accounting firm who audited our consolidated financial statements included in this Form 10-K. KPMG LLP’s attestation on the effectiveness of our internal control over financial reporting appears on page 69.53.
Report of Independent Registered Public Accounting Firm
TheTo the Board of Directors of NuStar GP, LLC
and Unitholders of NuStar Energy L.P.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of NuStar Energy L.P. (a Delaware limited partnership) and subsidiaries (the “Partnership”)Partnership) as of December 31, 20172022 and 2016,2021, the related consolidated statements of income (loss), comprehensive income (loss), cash flows, and partners’ equity and cash flowsmezzanine equity for each of the years in the three‑yearthree-year period ended December 31, 2017,2022, and the related notes (collectively, the “consolidatedconsolidated financial statements”)statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 20172022 and 2016,2021, and the results of its operations and its cash flows for each of the years in the three‑yearthree-year period ended December 31, 2017,2022, 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”)(PCAOB), the Partnership’s internal control over financial reporting as of December 31, 2017,2022, based on criteria established in Internal Control -– Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 28, 201823, 2023 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated 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 consolidated 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 consolidated 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 consolidated 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 consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Identification of triggering events related to the recoverability of certain long-lived assets or asset groups
As discussed in Note 2, the Partnership tests long-lived assets, including property, plant, and equipment, for impairment whenever events or changes in circumstances (triggering events) indicate that the carrying amount may not be recoverable. The Partnership evaluates recoverability using undiscounted estimated net cash flows generated by the related asset or asset group considering the intended use of the asset. The balance of property, plant, and equipment, net as of December 31, 2022 was $3,403 million, or 68% of total assets, of which certain assets or asset groups were not supported by existing revenue generating contacts or have not historically had consistent revenue generating activities.
We identified the assessment of the identification of triggering events related to the recoverability of certain long-lived assets or asset groups as a critical audit matter. Challenging auditor judgment was required to assess the identification of triggering events for certain long-lived assets or asset groups that were not supported by existing revenue generating contracts or have not historically had consistent revenue generating activities. Specifically, this assessment included the evaluation of subjective qualitative considerations, such as alternative customers and alternative uses for the asset or asset group, and the Partnership's intent for the asset or asset group.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Partnership's triggering event assessment. This included controls over the identification of long-lived asset groups that would be at greater risk for a triggering event and evaluation of the qualitative considerations in assessing the identification of a triggering event. We examined the Partnership's analysis of the long-lived assets and asset groups identified to be evaluated for a potential triggering event and assessed the factors considered in determining the identification of a triggering event. Specifically, we evaluated the Partnership's assessment of the factors considered, including alternative customers, alternative uses for the assets or asset group, and the Partnership's intent for the assets or asset group by evaluating internal and external documentation. Documentation evaluated included internal presentations, draft customer contracts, publicly available market data, and communications between the Partnership and potential customers.
We have served as the Partnership’s auditor since 2004.
/s/ KPMG LLP
San Antonio, Texas
February 28, 201823, 2023
Report of Independent Registered Public Accounting Firm
The Board of Directors of NuStar GP, LLC
and Unitholders of NuStar Energy L.P.:
Opinion on Internal Control Over Financial Reporting
We have audited NuStar Energy L.P. (a Delaware limited partnership) and subsidiaries’subsidiaries' (the “Partnership”)Partnership) internal control over financial reporting as of December 31, 2017,2022, based on criteria established in Internal Control -– Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2022, based on criteria established in Internal Control -– Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”)(PCAOB), the consolidated balance sheets of the Partnership as of December 31, 20172022 and 2016,2021, the related consolidated statements of income (loss), comprehensive income (loss), cash flows, and partners’ equity and cash flowsmezzanine equity for each of the years in the three-year period ended December 31, 2017,2022, and the related notes (collectively, the “consolidatedconsolidated financial statements”)statements), and our report dated February 28, 201823, 2023 expressed an unqualified opinion on those consolidated financial statements.
The Partnership acquired Navigator Energy Services, LLC during 2017, and management excluded from its assessment of the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2017, Navigator Energy Services, LLC’s internal control over financial reporting whose financial statements reflect 23 percent of total assets and 2 percent of total revenues of the related consolidated financial statement amounts of NuStar Energy L.P. as of and for the year ended December 31, 2017. Our audit of internal control over financial reporting of the Partnership also excluded an evaluation of the internal control over financial reporting of Navigator Energy Services, LLC.
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’sManagement's Report on 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 of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included 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/ KPMG LLP
San Antonio, Texas
February 28, 201823, 2023
NUSTAR ENERGY L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars, Except Unit Data)
| | | | December 31, | | December 31, |
| | 2017 | | 2016 | | 2022 | | 2021 |
| Assets | | | | Assets | | | |
| Current assets: | | | | Current assets: | |
| Cash and cash equivalents | $ | 24,292 |
| | $ | 35,942 |
| Cash and cash equivalents | $ | 14,489 | | | $ | 5,637 | |
Accounts receivable, net of allowance for doubtful accounts of $9,948 and $7,756 as of December 31, 2017 and 2016, respectively | 176,570 |
| | 170,293 |
| |
| Receivable from related party | 205 |
| | 317 |
| |
| Accounts receivable, net | | Accounts receivable, net | 149,971 | | | 135,126 | |
| | Inventories | 26,857 |
| | 37,945 |
| Inventories | 15,397 | | | 16,644 | |
| Other current assets | 22,508 |
| | 132,686 |
| |
| | Prepaid and other current assets | | Prepaid and other current assets | 24,067 | | | 27,135 | |
| | Total current assets | 250,432 |
| | 377,183 |
| Total current assets | 203,924 | | | 184,542 | |
| Property, plant and equipment, at cost | 6,243,481 |
| | 5,435,278 |
| Property, plant and equipment, at cost | 5,733,685 | | | 5,728,848 | |
| Accumulated depreciation and amortization | (1,942,548 | ) | | (1,712,995 | ) | Accumulated depreciation and amortization | (2,330,602) | | | (2,187,206) | |
| Property, plant and equipment, net | 4,300,933 |
| | 3,722,283 |
| Property, plant and equipment, net | 3,403,083 | | | 3,541,642 | |
| Intangible assets, net | 784,479 |
| | 127,083 |
| Intangible assets, net | 513,696 | | | 557,785 | |
| Goodwill | 1,097,475 |
| | 696,637 |
| Goodwill | 732,356 | | | 732,356 | |
| Deferred income tax asset | 233 |
| | 2,051 |
| |
| | Other long-term assets, net | 101,681 |
| | 105,308 |
| Other long-term assets, net | 120,627 | | | 140,007 | |
| Total assets | $ | 6,535,233 |
| | $ | 5,030,545 |
| Total assets | $ | 4,973,686 | | | $ | 5,156,332 | |
| Liabilities and Partners’ Equity | | | | |
| | Liabilities, Mezzanine Equity and Partners’ Equity | | Liabilities, Mezzanine Equity and Partners’ Equity | |
| Current liabilities: | | | | Current liabilities: | |
| Accounts payable | $ | 145,932 |
| | $ | 118,686 |
| Accounts payable | $ | 67,765 | | | $ | 82,446 | |
| Short-term debt | 35,000 |
| | 54,000 |
| |
| Current portion of long-term debt | 349,990 |
| | — |
| |
| | Current portion of finance leases | | Current portion of finance leases | 4,416 | | | 3,848 | |
| | Accrued interest payable | 40,449 |
| | 34,030 |
| Accrued interest payable | 37,607 | | | 34,139 | |
| Accrued liabilities | 61,578 |
| | 60,485 |
| Accrued liabilities | 76,072 | | | 79,818 | |
| Taxes other than income tax | 14,385 |
| | 15,685 |
| Taxes other than income tax | 10,607 | | | 14,475 | |
| Income tax payable | 4,172 |
| | 6,510 |
| |
| | Total current liabilities | 651,506 |
| | 289,396 |
| Total current liabilities | 196,467 | | | 214,726 | |
| Long-term debt, less current portion | 3,263,069 |
| | 3,014,364 |
| |
| Long-term debt, less current portion of finance leases | | Long-term debt, less current portion of finance leases | 3,293,415 | | | 3,183,555 | |
| | Deferred income tax liability | 22,272 |
| | 22,204 |
| Deferred income tax liability | 3,219 | | | 11,831 | |
| Other long-term liabilities | 118,297 |
| | 92,964 |
| Other long-term liabilities | 131,299 | | | 147,956 | |
| Total liabilities | | Total liabilities | 3,624,400 | | | 3,558,068 | |
| | Commitments and contingencies (Note 14) |
| |
| Commitments and contingencies (Note 14) | |
| Partners’ equity (Note 19): | | | | |
| Preferred limited partners | 756,603 |
| | 218,400 |
| |
Common limited partners (93,176,683 and 78,616,228 common units outstanding as of December 31, 2017 and 2016, respectively) | 1,770,587 |
| | 1,455,642 |
| |
| General partner | 37,826 |
| | 31,752 |
| |
| Series D preferred limited partners (16,346,650 and 23,246,650 units outstanding as of
December 31, 2022 and 2021, respectively) (Note 17) | | Series D preferred limited partners (16,346,650 and 23,246,650 units outstanding as of
December 31, 2022 and 2021, respectively) (Note 17) | 446,970 | | | 616,439 | |
| | Partners’ equity (Note 18): | | Partners’ equity (Note 18): | |
| Preferred limited partners: | | Preferred limited partners: | |
| Series A (9,060,000 units outstanding as of December 31, 2022 and 2021) | | Series A (9,060,000 units outstanding as of December 31, 2022 and 2021) | 218,307 | | | 218,307 | |
| Series B (15,400,000 units outstanding as of December 31, 2022 and 2021) | | Series B (15,400,000 units outstanding as of December 31, 2022 and 2021) | 371,476 | | | 371,476 | |
| Series C (6,900,000 units outstanding as of December 31, 2022 and 2021) | | Series C (6,900,000 units outstanding as of December 31, 2022 and 2021) | 166,518 | | | 166,518 | |
Common limited partners (110,818,718 and 109,986,273 common units outstanding
as of December 31, 2022 and 2021, respectively) | | Common limited partners (110,818,718 and 109,986,273 common units outstanding
as of December 31, 2022 and 2021, respectively) | 177,620 | | | 299,502 | |
| | Accumulated other comprehensive loss | (84,927 | ) | | (94,177 | ) | Accumulated other comprehensive loss | (31,605) | | | (73,978) | |
| | Total partners’ equity | 2,480,089 |
| | 1,611,617 |
| Total partners’ equity | 902,316 | | | 981,825 | |
| Total liabilities and partners’ equity | $ | 6,535,233 |
| | $ | 5,030,545 |
| |
| Total liabilities, mezzanine equity and partners’ equity | | Total liabilities, mezzanine equity and partners’ equity | $ | 4,973,686 | | | $ | 5,156,332 | |
See Notes to Consolidated Financial Statements.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(Thousands of Dollars, Except Unit and Per Unit Data)
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Revenues: | | | | | |
| Service revenues | $ | 1,128,726 |
| | $ | 1,083,165 |
| | $ | 1,114,153 |
|
| Product sales | 685,293 |
| | 673,517 |
| | 969,887 |
|
| Total revenues | 1,814,019 |
| | 1,756,682 |
| | 2,084,040 |
|
| Costs and expenses: | | | | | |
| Cost of product sales | 651,599 |
| | 633,653 |
| | 907,574 |
|
| Operating expenses (excluding depreciation and amortization expense): | | | | | |
| Third parties | 449,670 |
| | 426,686 |
| | 337,466 |
|
| Related party | — |
| | 21,681 |
| | 135,565 |
|
| Total operating expenses | 449,670 |
| | 448,367 |
| | 473,031 |
|
| General and administrative expenses (excluding depreciation and amortization expense): | | | | | |
| Third parties | 112,240 |
| | 88,324 |
| | 35,752 |
|
| Related party | — |
| | 10,493 |
| | 66,769 |
|
| Total general and administrative expenses | 112,240 |
| | 98,817 |
| | 102,521 |
|
| Depreciation and amortization expense | 264,232 |
| | 216,736 |
| | 210,210 |
|
| Total costs and expenses | 1,477,741 |
| | 1,397,573 |
| | 1,693,336 |
|
| Operating income | 336,278 |
| | 359,109 |
| | 390,704 |
|
| Interest expense, net | (173,083 | ) | | (138,350 | ) | | (131,868 | ) |
| Other (expense) income, net | (5,294 | ) | | (58,783 | ) | | 61,822 |
|
| Income from continuing operations before income tax expense | 157,901 |
| | 161,976 |
| | 320,658 |
|
| Income tax expense | 9,937 |
| | 11,973 |
| | 14,712 |
|
| Income from continuing operations | 147,964 |
| | 150,003 |
| | 305,946 |
|
| Income from discontinued operations, net of tax | — |
| | — |
| | 774 |
|
| Net income | $ | 147,964 |
| | $ | 150,003 |
| | $ | 306,720 |
|
| Basic and diluted net income per common unit: | | | | | |
| Continuing operations | $ | 0.64 |
| | $ | 1.27 |
| | $ | 3.29 |
|
| Discontinued operations | — |
| | — |
| | 0.01 |
|
| Total (Note 20) | $ | 0.64 |
| | $ | 1.27 |
| | $ | 3.30 |
|
| Basic weighted-average common units outstanding | 88,825,964 |
| | 78,080,484 |
| | 77,886,078 |
|
| | | | | | |
| Diluted weighted-average common units outstanding | 88,825,964 |
| | 78,113,002 |
| | 77,886,078 |
|
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2022 | | 2021 | | 2020 |
| Revenues: | | | | | |
| Service revenues | $ | 1,120,249 | | | $ | 1,157,410 | | | $ | 1,205,494 | |
| Product sales | 562,974 | | | 461,090 | | | 276,070 | |
| Total revenues | 1,683,223 | | | 1,618,500 | | | 1,481,564 | |
| | | | | |
| Costs and expenses: | | | | | |
| Costs associated with service revenues: | | | | | |
| | | | | |
| | | | | |
| | | | | |
| Operating expenses (excluding depreciation and amortization expense) | 364,989 | | | 388,078 | | | 403,579 | |
| Depreciation and amortization expense | 251,878 | | | 266,588 | | | 276,476 | |
| Total costs associated with service revenues | 616,867 | | | 654,666 | | | 680,055 | |
| Costs associated with product sales | 486,947 | | | 417,413 | | | 256,066 | |
| Goodwill impairment losses | — | | | 34,060 | | | 225,000 | |
| Other impairment losses | 46,122 | | | 154,908 | | | — | |
| | | | | |
| | | | | |
| | | | | |
| General and administrative expenses (excluding depreciation and amortization expense) | 117,116 | | | 113,207 | | | 102,716 | |
| Other depreciation and amortization expense | 7,358 | | | 7,792 | | | 8,625 | |
| | | | | |
| | | | | |
| Total costs and expenses | 1,274,410 | | | 1,382,046 | | | 1,272,462 | |
| | | | | |
| Operating income | 408,813 | | | 236,454 | | | 209,102 | |
| | | | | |
| Interest expense, net | (209,009) | | | (213,985) | | | (229,054) | |
| | | | | |
| Loss on extinguishment of debt | — | | | — | | | (141,746) | |
| Other income (expense), net | 26,182 | | | 19,644 | | | (34,622) | |
| Income (loss) before income tax expense | 225,986 | | | 42,113 | | | (196,320) | |
| Income tax expense | 3,239 | | | 3,888 | | | 2,663 | |
| Net income (loss) | $ | 222,747 | | | $ | 38,225 | | | $ | (198,983) | |
| | | | | |
| Basic and diluted net income (loss) per common unit (Note 19) | $ | 0.36 | | | $ | (0.99) | | | $ | (3.15) | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Basic and diluted weighted-average common units outstanding | 110,341,206 | | | 109,585,635 | | | 109,155,117 | |
| | | | | |
See Notes to Consolidated Financial Statements.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Thousands of Dollars)
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Net income | $ | 147,964 |
| | $ | 150,003 |
| | $ | 306,720 |
|
| Other comprehensive income (loss): | | | | | |
| Foreign currency translation adjustment | 17,466 |
| | (8,243 | ) | | (31,987 | ) |
| Net loss on pension and other postretirement benefit adjustments, net of income tax benefit of $184, $60 and $0 | (6,170 | ) | | (2,850 | ) | | — |
|
| Net (loss) gain on cash flow hedges | (2,046 | ) | | 5,710 |
| | 11,105 |
|
| Total other comprehensive income (loss) | 9,250 |
| | (5,383 | ) | | (20,882 | ) |
| Comprehensive income | $ | 157,214 |
| | $ | 144,620 |
| | $ | 285,838 |
|
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| Net income (loss) | $ | 222,747 | | | $ | 38,225 | | | $ | (198,983) | |
| Other comprehensive income (loss): | | | | | |
| | | | | |
| Foreign currency translation adjustment (Note 18) | 41,823 | | | 601 | | | 1,410 | |
| Net (loss) gain on pension and other postretirement benefit adjustments, net of income tax (expense) benefit of ($24), ($61) and $28 | (1,556) | | | 16,413 | | | (4,144) | |
| Change in unrealized loss on cash flow hedges | — | | | — | | | (30,291) | |
| Reclassification of loss on cash flow hedges to interest expense, net | 2,106 | | | 5,664 | | | 4,265 | |
| Total other comprehensive income (loss) | 42,373 | | | 22,678 | | | (28,760) | |
| Comprehensive income (loss) | $ | 265,120 | | | $ | 60,903 | | | $ | (227,743) | |
| | | | | |
| | | | | |
See Notes to Consolidated Financial Statements.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Cash Flows from Operating Activities: | | | | | |
| Net income | $ | 147,964 |
| | $ | 150,003 |
| | $ | 306,720 |
|
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Depreciation and amortization expense | 264,232 |
| | 216,736 |
| | 210,210 |
|
| Unit-based compensation expense | 8,132 |
| | 7,579 |
| | — |
|
| Amortization of debt related items | 6,147 |
| | 7,477 |
| | 8,840 |
|
| Loss (gain) from sale or disposition of assets | 4,984 |
| | 64 |
| | (1,617 | ) |
| Gain associated with the Linden Acquisition | — |
| | — |
| | (56,277 | ) |
| Impairment loss | — |
| | 58,655 |
| | — |
|
| Deferred income tax expense (benefit) | 6 |
| | (469 | ) | | 2,058 |
|
| Distributions of equity in earnings of joint ventures | — |
| | — |
| | 2,500 |
|
| Changes in current assets and current liabilities (Note 21) | (26,493 | ) | | 3,716 |
| | 50,559 |
|
| Other, net | 1,827 |
| | (7,000 | ) | | 1,944 |
|
| Net cash provided by operating activities | 406,799 |
| | 436,761 |
| | 524,937 |
|
| Cash Flows from Investing Activities: | | | | | |
| Capital expenditures | (384,638 | ) | | (204,358 | ) | | (324,808 | ) |
| Change in accounts payable related to capital expenditures | 36,903 |
| | (11,063 | ) | | (3,156 | ) |
| Acquisitions | (1,461,719 | ) | | (95,657 | ) | | (142,500 | ) |
| Proceeds from Axeon term loan | 110,000 |
| | — |
| | — |
|
| Proceeds from insurance recoveries | 977 |
| | — |
| | 4,867 |
|
| Proceeds from sale or disposition of assets | 2,036 |
| | — |
| | 17,132 |
|
| Investment in other long-term assets | — |
| | — |
| | (3,564 | ) |
| Net cash used in investing activities | (1,696,441 | ) | | (311,078 | ) | | (452,029 | ) |
| Cash Flows from Financing Activities: | | | | | |
| Proceeds from long-term debt borrowings | 1,465,767 |
| | 752,729 |
| | 860,131 |
|
| Proceeds from short-term debt borrowings | 1,051,000 |
| | 654,000 |
| | 823,500 |
|
| Proceeds from note offering, net of issuance costs | 543,333 |
| | — |
| | — |
|
| Long-term debt repayments | (1,417,539 | ) | | (772,152 | ) | | (500,410 | ) |
| Short-term debt repayments | (1,070,000 | ) | | (684,000 | ) | | (816,500 | ) |
| Proceeds from issuance of preferred units, net of issuance costs | 538,560 |
| | 218,400 |
| | — |
|
| Proceeds from issuance of common units, net of issuance costs | 643,878 |
| | 27,710 |
| | — |
|
| Contributions from general partner | 13,737 |
| | 680 |
| | — |
|
| Distributions to preferred unitholders | (38,833 | ) | | — |
| | — |
|
| Distributions to common unitholders and general partner | (446,306 | ) | | (392,962 | ) | | (392,204 | ) |
| Increase (decrease) in cash book overdrafts | 1,736 |
| | (11,237 | ) | | (2,954 | ) |
| Other, net | (9,061 | ) | | (4,492 | ) | | (792 | ) |
| Net cash provided by (used in) financing activities | 1,276,272 |
| | (211,324 | ) | | (29,229 | ) |
| Effect of foreign exchange rate changes on cash | 1,720 |
| | 2,721 |
| | (12,729 | ) |
| Net (decrease) increase in cash and cash equivalents | (11,650 | ) | | (82,920 | ) | | 30,950 |
|
| Cash and cash equivalents as of the beginning of the period | 35,942 |
| | 118,862 |
| | 87,912 |
|
| Cash and cash equivalents as of the end of the period | $ | 24,292 |
| | $ | 35,942 |
| | $ | 118,862 |
|
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2022 | | 2021 | | 2020 |
| Cash flows from operating activities: | | | | | |
| Net income (loss) | $ | 222,747 | | | $ | 38,225 | | | $ | (198,983) | |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | |
| Depreciation and amortization expense | 259,236 | | | 274,380 | | | 285,101 | |
| Amortization of unit-based compensation | 13,781 | | | 14,209 | | | 11,477 | |
| Amortization of debt related items | 10,267 | | | 12,490 | | | 11,463 | |
| (Gain) loss from sale or disposition of assets | (2,785) | | | (61) | | | 38,084 | |
| Gain from insurance recoveries | (16,366) | | | (14,860) | | | — | |
| Goodwill impairment losses | — | | | 34,060 | | | 225,000 | |
| Other impairment losses | 46,122 | | | 154,908 | | | — | |
| Loss on extinguishment of debt | — | | | — | | | 141,746 | |
| | | | | |
| Deferred income tax (benefit) expense | (946) | | | (1,369) | | | 212 | |
| Changes in current assets and current liabilities (Note 20) | 737 | | | (14,147) | | | 11,928 | |
| Decrease (increase) in other long-term assets | 1,091 | | | 9,867 | | | (8,101) | |
| (Decrease) increase in other long-term liabilities | (1,579) | | | (6,636) | | | 7,920 | |
| Other, net | (4,756) | | | 412 | | | 151 | |
| Net cash provided by operating activities | 527,549 | | | 501,478 | | | 525,998 | |
| | | | | |
| Cash flows from investing activities: | | | | | |
| Capital expenditures | (140,630) | | | (181,133) | | | (198,079) | |
| Change in accounts payable related to capital expenditures | (12,786) | | | 1,264 | | | (10,645) | |
| | | | | |
| Proceeds from insurance recoveries | 9,777 | | | 9,372 | | | — | |
| | | | | |
| Proceeds from sale or disposition of assets | 59,274 | | | 246,475 | | | 110,640 | |
| | | | | |
| | | | | |
| Net cash (used in) provided by investing activities | (84,365) | | | 75,978 | | | (98,084) | |
| | | | | |
| Cash flows from financing activities: | | | | | |
| Proceeds from Term Loan, net of discount and issuance costs | — | | | — | | | 463,045 | |
| Proceeds from note offerings, net of issuance costs | — | | | — | | | 1,182,035 | |
| Proceeds from other long-term debt borrowings | 989,900 | | | 977,000 | | | 883,748 | |
| Proceeds from short-term debt borrowings | — | | | — | | | 52,000 | |
| Term Loan repayment, including debt extinguishment costs | — | | | — | | | (601,316) | |
| Other long-term debt repayments | (883,300) | | | (1,389,700) | | | (1,813,963) | |
| Repurchase of Series D preferred limited partner units | (222,387) | | | — | | | — | |
| Short-term debt repayments | — | | | — | | | (57,500) | |
| | | | | |
| | | | | |
| Distributions to preferred unitholders | (127,299) | | | (127,551) | | | (124,622) | |
| Distributions to common unitholders | (176,413) | | | (175,263) | | | (196,203) | |
| Payments for termination of interest rate swaps | — | | | — | | | (49,225) | |
| Payment of tax withholding for unit-based compensation | (6,012) | | | (3,384) | | | (10,028) | |
| Increase (decrease) in cash book overdrafts | 2,331 | | | (142) | | | (2,288) | |
| Other, net | (11,773) | | | (6,539) | | | (17,067) | |
| Net cash used in financing activities | (434,953) | | | (725,579) | | | (291,384) | |
| | | | | |
| Effect of foreign exchange rate changes on cash | 707 | | | 136 | | | 916 | |
| Net increase (decrease) in cash, cash equivalents and restricted cash | 8,938 | | | (147,987) | | | 137,446 | |
| Cash, cash equivalents and restricted cash as of the beginning of the period | 14,439 | | | 162,426 | | | 24,980 | |
| Cash, cash equivalents and restricted cash as of the end of the period | $ | 23,377 | | | $ | 14,439 | | | $ | 162,426 | |
See Notes to Consolidated Financial Statements.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY
Years Ended December 31, 2017, 2016 and 2015 AND MEZZANINE EQUITY
(Thousands of Dollars, Except Per Unit Data)
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | Limited Partners | | | | | | |
| | Preferred (Note 19) | | Common | | General Partner | | Accumulated Other Comprehensive Loss (Note 19) | | Total Partners’ Equity |
| | Units | | Amount | | Units | | Amount | |
| Balance as of January 1, 2015 | — |
| | $ | — |
| | 77,886,078 |
| | $ | 1,744,810 |
| | $ | 39,312 |
| | $ | (67,912 | ) | | $ | 1,716,210 |
|
| Net income | — |
| | — |
| | — |
| | 258,230 |
| | 48,490 |
| | — |
| | 306,720 |
|
| Other comprehensive loss | — |
| | — |
| | — |
| | — |
| | — |
| | (20,882 | ) | | (20,882 | ) |
| Distributions to partners | — |
| | — |
| | — |
| | (341,140 | ) | | (51,064 | ) | | — |
| | (392,204 | ) |
| Balance as of December 31, 2015 | — |
| | — |
| | 77,886,078 |
| | 1,661,900 |
| | 36,738 |
| | (88,794 | ) | | 1,609,844 |
|
| Net income | — |
| | 1,925 |
| | — |
| | 102,580 |
| | 45,498 |
| | — |
| | 150,003 |
|
| Other comprehensive loss | — |
| | — |
| | — |
| | — |
| | — |
| | (5,383 | ) | | (5,383 | ) |
| Distributions to partners | — |
| | (1,925 | ) | | — |
| | (341,798 | ) | | (51,164 | ) | | — |
| | (394,887 | ) |
| Issuance of common units, including contribution from general partner | — |
| | — |
| | 595,050 |
| | 27,710 |
| | 575 |
| | — |
| | 28,285 |
|
| Issuance of preferred units | 9,060,000 |
| | 218,400 |
| | — |
| | — |
| | — |
| | — |
| | 218,400 |
|
| Unit-based compensation | — |
| | — |
| | 135,100 |
| | 5,250 |
| | 105 |
| | — |
| | 5,355 |
|
| Balance as of December 31, 2016 | 9,060,000 |
| | 218,400 |
| | 78,616,228 |
| | 1,455,642 |
| | 31,752 |
| | (94,177 | ) | | 1,611,617 |
|
| Net income | — |
| | 40,448 |
| | — |
| | 60,610 |
| | 46,906 |
| | — |
| | 147,964 |
|
| Other comprehensive income | — |
| | — |
| | — |
| | — |
| | — |
| | 9,250 |
| | 9,250 |
|
| Distributions to partners | — |
| | (40,448 | ) | | — |
| | (391,737 | ) | | (54,569 | ) | | — |
| | (486,754 | ) |
| Issuance of common units, including contribution from general partner | — |
| | — |
| | 14,375,000 |
| | 643,878 |
| | 13,597 |
| | — |
| | 657,475 |
|
| Issuance of preferred units | 22,300,000 |
| | 538,560 |
| | — |
| | — |
| | — |
| | — |
| | 538,560 |
|
| Unit-based compensation | — |
| | — |
| | 185,455 |
| | 2,516 |
| | 140 |
| | — |
| | 2,656 |
|
| Other | — |
| | (357 | ) | | — |
| | (322 | ) | | — |
| | — |
| | (679 | ) |
| Balance as of December 31, 2017 | 31,360,000 |
| | $ | 756,603 |
| | 93,176,683 |
| | $ | 1,770,587 |
| | $ | 37,826 |
| | $ | (84,927 | ) | | $ | 2,480,089 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Limited Partners | | | | | | Mezzanine Equity | | |
| | | Preferred | | | | Common | | Accumulated Other
Comprehensive Loss | | Total Partners’ Equity (Note 18) | | Series D Preferred Limited Partners (Note 17) | | Total |
| Balance as of January 1, 2020 | | | $ | 756,301 | | | | | $ | 1,087,805 | | | $ | (67,896) | | | $ | 1,776,210 | | | $ | 581,935 | | | $ | 2,358,145 | |
| Net income (loss) | | | 64,134 | | | | | (323,865) | | | — | | | (259,731) | | | 60,748 | | | (198,983) | |
| Other comprehensive loss | | | — | | | | | — | | | (28,760) | | | (28,760) | | | — | | | (28,760) | |
| Distributions to partners: | | | | | | | | | | | | | | | |
| Series A, B and C preferred | | | (64,134) | | | | | — | | | — | | | (64,134) | | | — | | | (64,134) | |
| Common ($1.80 per unit) | | | — | | | | | (196,203) | | | — | | | (196,203) | | | — | | | (196,203) | |
| Series D preferred | | | — | | | | | — | | | — | | | — | | | (60,748) | | | (60,748) | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Unit-based compensation | | | — | | | | | 22,219 | | | — | | | 22,219 | | | — | | | 22,219 | |
| Series D Preferred Unit accretion | | | — | | | | | (17,626) | | | — | | | (17,626) | | | 17,626 | | | — | |
| Other | | | — | | | | | (16) | | | — | | | (16) | | | (19) | | | (35) | |
| Balance as of December 31, 2020 | | | 756,301 | | | | | 572,314 | | | (96,656) | | | 1,231,959 | | | 599,542 | | | 1,831,501 | |
| Net income (loss) | | | 63,982 | | | | | (89,174) | | | — | | | (25,192) | | | 63,417 | | | 38,225 | |
| Other comprehensive income | | | — | | | | | — | | | 22,678 | | | 22,678 | | | — | | | 22,678 | |
| Distributions to partners: | | | | | | | | | | | | | | | |
| Series A, B and C preferred | | | (63,982) | | | | | — | | | — | | | (63,982) | | | — | | | (63,982) | |
| Common ($1.60 per unit) | | | — | | | | | (175,263) | | | — | | | (175,263) | | | — | | | (175,263) | |
| Series D preferred | | | — | | | | | — | | | — | | | — | | | (63,417) | | | (63,417) | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Unit-based compensation | | | — | | | | | 8,528 | | | — | | | 8,528 | | | — | | | 8,528 | |
| Series D Preferred Unit accretion | | | — | | | | | (16,903) | | | — | | | (16,903) | | | 16,903 | | | — | |
| Other | | | — | | | | | — | | | — | | | — | | | (6) | | | (6) | |
| Balance as of December 31, 2021 | | | 756,301 | | | | | 299,502 | | | (73,978) | | | 981,825 | | | 616,439 | | | 1,598,264 | |
| Net income | | | 66,526 | | | | | 95,158 | | | — | | | 161,684 | | | 61,063 | | | 222,747 | |
| Other comprehensive income | | | — | | | | | — | | | 42,373 | | | 42,373 | | | — | | | 42,373 | |
| Distributions to partners: | | | | | | | | | | | | | | | |
| Series A, B and C preferred | | | (66,526) | | | | | — | | | — | | | (66,526) | | | — | | | (66,526) | |
| Common ($1.60 per unit) | | | — | | | | | (176,413) | | | — | | | (176,413) | | | — | | | (176,413) | |
| Series D preferred | | | — | | | | | — | | | — | | | — | | | (61,063) | | | (61,063) | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Unit-based compensation | | | — | | | | | 12,302 | | | — | | | 12,302 | | | — | | | 12,302 | |
| Series D Preferred Unit accretion | | | — | | | | | (18,538) | | | — | | | (18,538) | | | 18,538 | | | — | |
| Series D Preferred Unit repurchase | | | — | | | | | (34,382) | | | — | | | (34,382) | | | (188,005) | | | (222,387) | |
| Other | | | — | | | | | (9) | | | — | | | (9) | | | (2) | | | (11) | |
| Balance as of December 31, 2022 | | | $ | 756,301 | | | | | $ | 177,620 | | | $ | (31,605) | | | $ | 902,316 | | | $ | 446,970 | | | $ | 1,349,286 | |
See Notes to Consolidated Financial Statements.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 20162022, 2021 and 20152020
1. ORGANIZATION AND OPERATIONS
Organization
NuStar Energy L.P. (NYSE: NS) is a Delaware limited partnership primarily engaged in the transportation, terminalling and storage of petroleum products and anhydrous ammonia,renewable fuels and the terminalling, storage and marketingtransportation of petroleum products.anhydrous ammonia. Unless otherwise indicated, the terms “NuStar Energy,” “NS,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to NuStar Energy L.P., to one or more of our consolidated subsidiaries or to all of them taken as a whole. NuStar GP Holdings, LLC (NuStar GP Holdings or NSH) (NYSE: NSH) owns our general partner, Riverwalk Logistics, L.P., and owns an approximate 11% common limited partner interest in us asOur business is managed under the direction of December 31, 2017.
Employee Transfer from NuStar GP, LLC. On March 1, 2016,the board of directors of NuStar GP, LLC, the general partner of our general partner, and a wholly owned subsidiary of NuStar GP Holdings, transferred and assigned to NuStar Services Company LLC (NuStar Services Co), a wholly owned subsidiary of NuStar Energy, all of NuStar GP, LLC’s employees and related benefit plans, programs, contracts and policies (the Employee Transfer). As a result of the Employee Transfer, we pay employee costs directly and sponsor the long-term incentive plan and other employee benefit plans. Please refer to Note 17 for further discussion of the Employee Transfer and our related party agreements, Note 22 for a discussion of our employee benefit plans and Note 23 for a discussion of our long-term incentive plan.
Recent Developments
Merger. On February 7, 2018, NuStar Energy, Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, aboth of which are indirectly wholly owned subsidiarysubsidiaries of NuStar Energy (Merger Sub), Riverwalk Holdings, LLC and NuStar GP Holdings, LLC (NuStar GP Holdings) entered into an Agreement and Plan of Merger (the Merger Agreement) pursuant to which Merger Sub will merge with and into NuStar GP Holdings with NuStar GP Holdings being the surviving entity (the Merger), such that NuStar Energy will be the sole member of NuStar GP Holdings following the Merger. Pursuant to the Merger Agreement and at the effective time of the Merger, our partnership agreement will be amended and restated to, among other things, (i) cancel the incentive distribution rights held by our general partner, (ii) convert the 2% general partner interest in NuStar Energy held by our general partner into a non-economic management interest and (iii) provide the holders of our common units with voting rights in the election of the members of the board of directors of NuStar GP, LLC at an annual meeting, beginning in 2019. The Merger is subject to the satisfaction or waiver of certain conditions, including approval of the Merger Agreement by NuStar GP Holdings unitholders. Please refer to Note 28 for further discussion of the Merger.ours.
Hurricane Activity. In the third quarter of 2017, parts of the Caribbean and Gulf of Mexico experienced three major hurricanes. Several of our facilities were affected by the hurricanes, but our St. Eustatius terminal experienced the most damage and was temporarily shut down. We incurred approximately $2.6 million of operating expenses to repair minor property damage at several of our domestic terminals. Additionally, we recorded a $5.0 million loss in “Other (expense) income, net” in the consolidated statements of income in the third quarter of 2017 for property damage at our St. Eustatius terminal, which represents the amount of our property deductible under our insurance policy. The hurricane impacts lowered revenues for our bunker fuel operations in our fuels marketing segment and lowered throughput and associated handling fees in our storage segment in the third and fourth quarters of 2017. We received insurance proceeds of $12.5 million in 2017 for damages at our St. Eustatius terminal, of which $3.8 million was for business interruption and the remainder was used for repairs and cleanup. Proceeds from business interruption insurance are included in “Operating expenses” in the consolidated statements of income and in “Cash flows from operating activities” in the consolidated statements of cash flows. In January 2018, we received $87.5 million of insurance proceeds in settlement of our property damage claim for our St. Eustatius terminal. We expect that the costs to repair the property damage at the terminal will not exceed the value of insurance proceeds received.
Navigator Acquisition and Financing Transactions. On May 4, 2017, we completed the acquisition of Navigator Energy Services, LLC for approximately $1.5 billion (the Navigator Acquisition). In order to fund the purchase price, we issued 14,375,000 common units for net proceeds of $657.5 million, issued $550.0 million of 5.625% senior notes for net proceeds of $543.3 million and issued 15,400,000 of our 7.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (Series B Preferred Units) for net proceeds of $371.8 million. Please refer to Notes 4, 12 and 19 for further discussion.
Axeon Term Loan. On February 22, 2017, we settled and terminated the $190.0 million term loan to Axeon Specialty Products, LLC (the Axeon Term Loan), pursuant to which we also provided credit support, such as guarantees, letters of credit and cash collateral, as applicable, of up to $125.0 million to Axeon Specialty Products, LLC (Axeon). We received $110.0 million in
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
settlement of the Axeon Term Loan, and our obligation to provide ongoing credit support to Axeon ceased. Please refer to Notes 7 and 15 for further discussion of the Axeon Term Loan and related credit support.
Operations
We conduct our operations through our subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics) and NuStar Pipeline Operating Partnership L.P. (NuPOP). We have three business segments: pipeline, storage and fuels marketing.
Pipeline. We own 3,1302,920 miles of refined product pipelines and 1,9302,050 miles of crude oil pipelines, as well as approximately 5.05.6 million barrels of crude oil storage capacity, which comprise our Central West System. In addition, we own 2,3702,495 miles of refined product pipelines, consisting of the East and North Pipelines,pipelines, and a 2,000-mile ammonia pipeline, which comprise our Central East System. The East and North Pipelinespipelines have aggregate storage capacity of approximately 6.87.4 million barrels. We charge tariffs on a per barrel basis for transporting refined products, crude oil and other feedstocks in our refined product and crude oil pipelines and on a per ton basis for transporting anhydrous ammonia in the Ammonia Pipeline.
Storage. We own terminal and storage facilities in the United States Canada,and Mexico, the Netherlands, including St. Eustatius in the Caribbean, and the United Kingdom, with approximately 84.836.4 million barrels of storage capacity. Our terminal and storage facilities provide storage, handling and other services on a fee basis for petroleumrefined products, crude oil, specialty chemicals, renewable fuels and other liquids.
Fuels Marketing. Within our fuels marketing operations, we purchase petroleum products for resale. The activities of the fuels marketing segment expose us to the risk of fluctuations in commodity prices, which has a direct impact on the segment’s results of operations. We enter into derivative contracts to attempt to mitigate the effect of commodity price fluctuations.
We ceased marketing crude oil in the second quarter of 2017 and exitedmainly includes our heavy fuels tradingbunkering operations in the third quarter of 2017. These actions are in line with our goal of reducing our exposure to commodity margins, and instead focusing on our core, fee-based pipeline and storage segments. The only operations remaining in our fuels marketing segment are our bunkering operations at our St. Eustatius and Texas City terminals,Gulf Coast, as well as certain of our blending operations.operations associated with our Central East System.
Recent Developments
Repurchase of Series D Preferred Units. On November 16, 2022, NuStar Energy L.P. entered into agreements with EIG Nova Equity Aggregator, L.P and FS Energy and Power Fund to repurchase an aggregate 6,900,000 of our Series D Cumulative Convertible Preferred Units (Series D Preferred Units), representing approximately one-third of the outstanding units, at a price per unit of $32.73 for an aggregate purchase price of $225.8 million, including approximately $3.4 million related to accrued distributions. These transactions closed on November 22, 2022 and were funded with borrowings under our $1.0 billion unsecured revolving credit agreement. Please see Note 17 for additional information.
Point Tupper Terminal Disposition. On April 29, 2022, we sold the equity interests in our wholly owned subsidiaries that owned our Point Tupper terminal facility to EverWind Fuels for $60.0 million (the Point Tupper Terminal Disposition). Please refer to Note 4 for more information.
Other Events
Debt Amendments. On January 28, 2022, we amended and restated our $1.0 billion unsecured revolving credit agreement to extend the maturity to April 27, 2025, replace the LIBOR-based interest rate and modify other terms. Also on January 28, 2022, we amended our $100.0 million receivables financing agreement to extend the scheduled termination date to January 31, 2025, replace the LIBOR-based interest rate and modify other terms. Please refer to Note 12 for more information.
Selby Terminal Fire. On October 15, 2019, our terminal facility in Selby, California experienced a fire that destroyed two storage tanks and temporarily shut down the terminal. We received insurance proceeds of $11.1 million, $28.5 million and $35.0 million, for the years ended December 31, 2022, 2021 and 2020, respectively. In addition, we received $12.4 million in January 2023, which represented the remaining proceeds from the settlement of the property loss claim. For the years ended December 31, 2022 and 2021, we recorded gains of $16.4 million and $14.9 million, respectively, for the amount by which the insurance recoveries exceeded our expenses incurred to date, which are included in “Other income (expense), net” in the consolidated statements of income (loss). We recorded gains from business interruption insurance of $4.0 million and $6.7 million for the years ended December 31, 2021 and 2020, respectively, which are included in “Operating expenses” in the consolidated statements of income (loss).
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Consolidation
The accompanying consolidated financial statements represent the consolidated operations of the Partnership and our subsidiaries. Inter-partnership balances and transactions have been eliminated in consolidation. The operations of certain pipelines and terminals in which we own an undivided interest are proportionately consolidated in the accompanying consolidated financial statements.
Use of Estimates
The preparation of consolidated financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. On an ongoing basis, management reviews its estimates based on currently available information. Management may revise estimates due to changes in facts and circumstances.
Cash and Cash Equivalents
Cash equivalents are all highly liquid investments with an original maturity of three months or less when acquired.
Accounts Receivable
Accounts receivable represent valid claims against non-affiliated customersTrade receivables are carried at amortized cost, net of a valuation allowance for products sold or services rendered.current expected credit losses. We extend credit terms to certain customers after review of various credit indicators, including the customer’s credit rating. Outstandingrating, and obtain letters of credit, guarantees or collateral as deemed necessary. We monitor our ongoing credit exposure through active review of customer receivable balances are regularly reviewed for possible non-payment indicatorsagainst contract terms and allowances for doubtful accounts are recordeddue dates and pool customer receivables based upon management’s estimate of collectability at the time of its review.days outstanding, which is our primary credit risk indicator. Our review activities include timely account reconciliations, dispute resolution and payment confirmations.
Inventories
Inventories consist of petroleum products, materials and supplies. Inventories except those associated with a qualifying fair value hedge, are valued at the lower of cost or net realizable value. Cost is determined using the weighted-average cost method. Our inventory, other than materials and supplies, consists of one end-product category, petroleum products, which we include in the fuels marketing segment. Accordingly, we determine lower of cost or net realizable value adjustments on an aggregate
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
basis. Inventories associated with qualifying fair value hedges are valued at current market prices. Materials and supplies are valued at the lower of average cost or net realizable value.
Restricted Cash
As of December 31, 2022 and 2021, we have restricted cash representing legally restricted funds that are unavailable for general use totaling $8.9 million and $8.8 million, respectively, which is included in “Other long-term assets, net” on the consolidated balance sheets.
Property, Plant and Equipment
We record additions to property, plant and equipment, including reliability and strategic capital expenditures, at cost. Repair and maintenance costs 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. Depreciation of property, plant and equipment is recorded on a straight-line basis over the estimated useful lives of the related assets. When property or equipment is retired, sold or otherwise disposed of, the difference between the carrying value and the net proceeds is recognized in “Other income (expense) income,, net” in the consolidated statements of income in the year of disposition.
(loss). We capitalize overhead costs and interest costs incurred on funds used to construct property, plant and equipment while the asset is under construction. The overhead costs and capitalized interest are recorded as part of the asset to which they relate and are amortized over the asset’s estimated useful life as a component of depreciation expense.
Leases
We lease assets used in our operations, including land and docks. We record all leases on our consolidated balance sheets except for those leases with an initial term of 12 months or less, which are expensed on a straight-line basis over the lease term. We use judgment in determining the reasonably certain lease term and consider factors such as the nature and utility of the leased asset, as well as the importance of the leased asset to our operations. We calculate the present value of our lease liabilities based upon our incremental borrowing rate unless the rate implicit in the lease is readily determinable. For all of our asset classes except the other pipeline and terminal equipment asset class, we combine lease and non-lease components and account for them as a single lease component.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Certain of our leases are subject to variable payment arrangements, the most notable of which include:
•dockage and wharfage charges, which are based on volumes moved over leased docks and are included in our calculation of our lease payments based on minimum throughput volume requirements. We recognize charges on excess throughput volumes in profit or loss in the period in which the obligation for those payments is incurred; and
•consumer price index (CPI) adjustments, which are measured and included in the calculation of our lease payments based on the CPI at the commencement date. We recognize changes in lease payments as a result of changes in the CPI in profit or loss in the period in which those payments are made.
See Note 15 for further discussion of our lease arrangements.
Goodwill
As of December 31, 2022 and 2021, our reporting units to which goodwill has been allocated consisted of the following:
•crude oil pipelines;
•refined product pipelines; and
•terminals, excluding our refinery crude storage tanks and our Point Tupper terminal facility, prior to its disposal on April 29, 2022.
Please see Notes 4 and 10 for a discussion of the balances of and changes in the carrying amount of goodwill.
We assess goodwill for impairment annually on October 1, or more frequently if events or changes in circumstances indicate it might be impaired. We have the option to first assess qualitative factors to determine whether it is necessary to perform a quantitative goodwill impairment test. We performed a quantitative goodwill impairment testelected to bypass the qualitative assessment for all reporting units as of October 1, 20172022 and 2016,October 1, 2021 and determinedperformed quantitative assessments, resulting in the determination that nogoodwill was not impaired.
We measure goodwill impairment charges occurred.as the excess of each reporting unit’s carrying value over its fair value, not to exceed the carrying amount of goodwill for that reporting unit. The carrying value of each reporting unit equals the total identified assets (including goodwill) less the sum of each reporting unit’s identified liabilities. We used reasonable and supportable methods to assign the assets and liabilities to the appropriate reporting units in a consistent manner.
We recognize an impairment of goodwill if the carrying value of a reporting unit that contains goodwill exceeds its estimated fair value. In order to estimate the fair value of the reporting unit, including goodwill, management must make certain estimates and assumptions that affect the total fair value of the reporting unit including, among other things, an assessment of market conditions, projected cash flows, discount rates and growth rates. Management’s estimates of projected cash flows related to the reporting unit include, but are not limited to, future earnings of the reporting unit, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and future expenditures necessary to maintain the asset’s existing service potential. We calculate the estimated fair value of each of our reporting units using a weighted-average of values calculated using an income approach and a market approach. The income approach involves estimating the fair value of each reporting unit by discounting its estimated future cash flows using a discount rate that would be consistent with a market participant’s assumption. The market approach bases the fair value measurement on information obtained from observed stock prices of public companies and recent merger and acquisition transaction data of comparable entities.
Our reporting units
Management’s estimates are based on numerous assumptions about future operations and market conditions, which we believe to be reasonable but are inherently uncertain. The uncertainties underlying our assumptions and estimates could differ significantly from actual results, which goodwill has been allocated consistcould lead to a different determination of the following:
crude oil pipelines;
refined product pipelines;
terminals, excluding our St. Eustatius and Point Tupper facilities and our refinery crude storage tanks; and
bunkering activity at our St. Eustatius and Point Tupper facilities.
The quantitative impairment test for goodwill consists of a two-step process. Step 1 compares the fair value of the reporting unit to its carrying value including goodwill. The carrying value of each reporting unit equals the total identified assets (including goodwill) less the sum of each reporting unit’s identified liabilities. We used reasonable and supportable methods to assign the assets and liabilities to the appropriate reporting units in a consistent manner. If the carrying value exceeds fair value, there is a potential impairment and step 2 must be performed to determine the amount of goodwill impairment. Step 2 compares the carrying value of the reporting unit’s goodwill to its implied fair value using a hypothetical allocation of the reporting unit’s fair value. If the goodwill carrying value exceeds its implied fair value, the excess is reported as impairment.our assets.
Impairment of Long-Lived Assets
We review long-lived assets, including property, plant and equipment, for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. We evaluate recoverability using undiscounted estimated net cash flows generated by the related asset or asset group. If the results of that evaluation indicate that the undiscounted cash flows are less than the carrying amount of the asset (i.e., the asset is not recoverable) we perform an impairment analysis. If our intent is to hold the asset for continued use, we determine the amount of impairment as the amount by which the net carrying value exceeds its fair value. If our intent is to sell the asset, and the criteria required to classify an asset as held for sale are met, we determine the amount of impairment as the amount by which the net carrying amount exceeds its fair value less costs to sell. See Note 4 for a discussion of our long-lived asset impairment charges. We believe that the carrying amounts of our long-lived assets as of December 31, 20172022 are recoverable.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Income Taxes
We are a limited partnership and generally are not subject to federal or state income taxes. Accordingly, our taxable income or loss, which may vary substantially from income or loss reported for financial reporting purposes, is generally included in the federal and state income tax returns of our partners. For transfers of publicly held common units subsequent to our initial public offering,
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
we have made an election permitted by Section 754 of the Internal Revenue Code (the Code) to adjust the common unit purchaser’s tax basis in our underlying assets to reflect the purchase price of the units. This results in an allocation of taxable income and expenses to the purchaser of the common units, including depreciation deductions and gains and losses on sales of assets, based upon the new unitholder’s purchase price for the common units.
We conduct certain of our operations through taxable wholly owned corporate subsidiaries. We account for income taxes related to our taxable subsidiaries using the asset and liability method. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. We measure deferred taxes using enacted tax rates expected to apply to taxable income in the year those temporary differences are expected to be recovered or settled.
We recognize a tax position if it is more likely than not that the tax position will be sustained, based on the technical merits of the position, upon examination. We record uncertain tax positions in the financial statements at the largest amount of benefit that is more likely than not to be realized. We had no unrecognized tax benefits as of December 31, 20172022 and 2016.2021.
NuStar Energy and certain of its subsidiaries file income tax returns in the U.S. federal jurisdiction and various state and foreign jurisdictions. For U.S. federal and state purposes, as well as for our major non-U.S. jurisdictions, tax years subject to examination are 20132017 through 2016,2021, according to standard statute of limitations.
Asset Retirement Obligations
We record a liability for asset retirement obligations at the fair value of the estimated costs to retire a tangible long-lived asset at the time we incur that liability, which is generally when the asset is purchased, constructed or leased, when we have a legal obligation to incur costs to retire the asset and when a reasonable estimate of the fair value of the obligation can be made. If a reasonable estimate cannot be made at the time the liability is incurred, we record the liability when sufficient information is available to estimate the fair value.
We have asset retirement obligations with respect to certain of our assets due to various legal obligations to clean and/or dispose of those assets at the time they are retired. However, these assets can be used for an extended and indeterminate period of time as long as they are properly maintained and/or upgraded. It is our practice and current intent to maintain our assets and continue making improvements to those assets based on technological advances. As a result, we believe that our assets have indeterminate lives for purposes of estimating asset retirement obligations because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of any asset, we estimate the costs of performing the retirement activities and record a liability for the fair value of these costs.
We also have legal obligations in the form of leases and right-of-way agreements, which require us to remove certain of our assets upon termination of the agreement. However, these lease or right-of-way agreements generally contain automatic renewal provisions that extend our rights indefinitely or we have other legal means available to extend our rights. We have recorded a liability of $0.7 million and $0.6 million as of December 31, 2017 and 2016, respectively, which is included in “Other long-term liabilities” in the consolidated balance sheets,Liabilities for conditional asset retirement obligations related to the retirement of terminal assets with lease and right-of-way agreements.agreements were not material as of December 31, 2022 and 2021.
Environmental Remediation Costs
Environmental remediation costs are expensed and an associated accrual established when site restoration and environmental remediation and cleanup obligations are either known or considered probable and can be reasonably estimated. These environmental obligations are based on estimates of probable undiscounted future costs using currently available technology and applying current regulations, as well as our own internal environmental policies. The environmental liabilities have not been reduced by possible recoveries from third parties. Environmental costs include initial site surveys, costs for remediation and restoration and ongoing monitoring costs, as well as fines, damages and other costs, when applicable and estimable. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods.
Environmental liabilities are difficult to assess and estimate due to unknown factors, such as the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. We believe that we have adequately accrued for our environmental exposures. Please refer to Note 13 for the amount of accruals for environmental matters.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Product Imbalances
We incur product imbalances as a result of variances in pipeline meter readings and volume fluctuations due to pressure and temperature changes. We use quoted market prices as of the reporting date to value our assets and liabilities related to product imbalances. Product imbalance liabilities are included in “Accrued liabilities” and product imbalance assets are included in “Other current assets” in the consolidated balance sheets.
Revenue Recognition
Revenue-Generating Activities.Revenues for the pipeline segment are derived from interstate and intrastate pipeline transportation of refined products, crude oil and anhydrous ammonia. Transportation revenues (basedammonia and the applicable pipeline tariff on pipeline tariffs) are recognized as the refined product,a per barrel basis for crude oil or anhydrous ammonia is delivered out ofrefined products and on a per ton basis for ammonia. Revenues generated from product sales in the pipelines.pipeline segment relate to surplus pipeline loss allowance volumes.
Revenues for the storage segment include fees for tank storage agreements, wherebyunder which a customer agrees to pay for a certain amount of storage in a tank over a period of time (storage terminal revenues), and throughput agreements, wherebyunder which a customer pays a fee per barrel for volumes moving through our terminals (throughput terminal revenues). Our terminals also provide blending, additive injections, handling and filtering services for which we charge additional fees. Certain of our facilities charge fees to provide marine services such as pilotage, tug assistance, line handling, launch service, emergency response services and other ship services. Storage terminal revenues are recognized when services are provided to the customer. Throughput revenues are recognized as refined products or crude oil are received in or delivered out of our terminal.
Revenues for marine servicesthe fuels marketing segment are recognized as those services are provided.
Revenuesderived from the sale of petroleum products.
Within both our pipeline and storage segments, we provide services on uninterruptible and interruptible bases. Uninterruptible services within our pipeline segment typically result from contracts that contain take-or-pay minimum volume commitments (MVCs) from the customer. Contracts with MVCs obligate the customer to pay for that minimum amount. If a customer fails to meet its MVC for the applicable service period, the customer is obligated to pay a deficiency fee based upon the shortfall between the actual volumes transported or stored and the MVC for that service period (deficiency payments). In exchange, those contracts with MVCs obligate us to stand ready to transport volumes up to the customer’s MVC.
Within our storage segment, uninterruptible services arise from contracts containing a fixed monthly fee for the portion of storage capacity reserved by the customer. These contracts require that the customer pay the fixed monthly fee, regardless of whether or not it uses our storage facility (i.e., take-or-pay obligation), and that we stand ready to store that volume. Interruptible services within our pipeline and storage segments are generally provided when and to the extent we determine the requested capacity is available. The customer typically pays a per-unit rate for the actual quantities of services it receives.
For the majority of our contracts, we recognize revenue in the amount to which we have a right to invoice. Generally, payment terms do not exceed 30 days.
Performance Obligations. The majority of our contracts contain a single performance obligation. For our pipeline segment, the single performance obligation encompasses multiple activities necessary to deliver our customers’ products to their destinations. Typically, we satisfy this performance obligation over time as the product volume is delivered in or out of the pipelines. Certain of our pipeline segment customer contracts include an incentive pricing structure, which provides a discounted rate for the remainder of the contract once the customer exceeds a cumulative volume. The ability to receive discounted future services represents a material right to the customer, which results in a second performance obligation in those contracts.
The performance obligation for our storage segment consists of multiple activities necessary to receive, store and deliver our customers’ products. We typically satisfy this performance obligation over time as the product volume is delivered in or out of the tanks (for throughput terminal revenues) or with the passage of time (for storage terminal revenues).
Product sales contracts generally include a single performance obligation to deliver specified volumes of a commodity, which we satisfy at a point in time, when the product is delivered and the customer obtains control of the commodity.
Optional services described in our contracts do not provide a material right to the customer, and are not considered a separate performance obligation in the contract. If and when a customer elects an optional service, and the terms of the contract are otherwise met, those services become part of the existing performance obligation.
Transaction Price. For uninterruptible services, we determine the transaction price at contract inception based on the guaranteed minimum amount of revenue over the term of the contract. For interruptible services and optional services, we determine the transaction price based on our right to invoice the customer for the value of services provided to the customer for the applicable period.
In certain instances, our customers reimburse us for capital projects, in arrangements referred to as contributions in aid of construction, or CIAC. Typically, in these instances, we receive upfront payments for future services, which are included in our fuels marketing segment, are recognized when product is delivered to the customer and title and risk pass totransaction price of the customer.underlying service contract.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
We collect taxes on certain revenue transactions to be remitted to governmental authorities, which may include sales, use, value-added and some excise taxes. These taxes are not included in revenue.the transaction price and are, therefore, excluded from revenues.
Allocation of Transaction Price. We allocate the transaction price to the single performance obligation that exists in the vast majority of our contracts with customers. For the few contracts that have a second performance obligation, such as those that include an incentive pricing structure, we calculate an average rate based on the estimated total volumes to be delivered over the term of the contract and the resulting estimated total revenue to be billed using the applicable rates in the contract. We allocate the transaction price to the two performance obligations by applying the average rate to product volumes as they are delivered to the customer over the term of the contract. Determining the timing and amount of volumes subject to these incentive pricing contracts requires judgment that can impact the amount of revenue allocated to the two separate performance obligations. We base our estimates on our analysis of expected future production information available from our customers or other sources, which we update at least quarterly.
Some of our MVC contracts include provisions that allow the customer to apply deficiency payments to future service periods (the carryforward period). In those instances, we have not satisfied our performance obligation as we still have the obligation to perform those services, subject to contractual and/or capacity constraints, at the customer’s request. At least quarterly, we assess the customer’s ability to utilize any deficiency payments during the carryforward period. If we receive a deficiency payment from a customer that we expect the customer to utilize during the carryforward period, we defer that amount as a contract liability. We will consider the performance obligation satisfied and allocate any deferred deficiency payments to our performance obligation when the customer utilizes the deficiency payment, the carryforward period ends or we determine the customer cannot or will not utilize the deficiency payment (i.e. breakage).If our contract does not allow the customer to apply deficiency payments to future service periods, we allocate the deficiency payment to the already satisfied portion of the performance obligation.
Income Allocation
Our partnership agreement as amended, sets forth the calculation to be used to determine the amount and priority of cash distributions that the unitholders and general partner will receive. The partnership agreement also contains provisions for the allocation of net income to the unitholders and the general partner; however, losses are only allocated to the common unitholders and the general partner.unitholders. Our net income for each quarterly reporting period is first allocated to the preferred limited partner unitholders in an amount equal to the earned distributions for the respective reporting period and then to the general partner in an amount equal to the general partner’s incentive distribution calculated based upon the declared distribution for the respective reporting period. We allocate the remaining net income or loss among the common unitholders (98%) and general partner (2%), as set forth in our partnership agreement.unitholders.
Basic and Diluted Net Income (Loss) Per Common Unit
Basic and diluted net income (loss) per common unit areis determined pursuant to the two-class method. Under this method, all earnings are allocated to our common limited partners and participating securities based on their respective rights to receive distributions earned during the period. Participating securities include our general partner interest and restricted units awarded under our long-term incentive plan.
plans. We compute basic net income (loss) per common unit by dividing net income (loss) attributable to our common limited partners by the weighted-average number of common units outstanding during the period. We compute diluted net income (loss) per common unit by dividing net income (loss) attributable to our common limited partners by the sum of (i) the weighted-average number of common units outstanding during the period and (ii) the effect of dilutive potential common units outstanding during the period. Dilutive potential common units include contingently issuable performance units awarded under our long-term incentive plan.and the Series D Preferred Units. See Note 2322 for additional information on our performance units.units, Note 17 for additional information on our Series D Preferred Units and Note 19 for the calculation of basic and diluted net income (loss) per common unit.
Derivative Financial Instruments
WeWhen we apply hedge accounting, we formally document all relationships between hedging instruments and hedged items. This process includes identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. To qualify for hedge accounting, at inception of the hedge we assess whether the derivative instruments that are used in our hedging transactions are expected to be highly effective in offsetting changes in cash flows or the fair value of the hedged items.flows. Throughout the designated hedge period and at least quarterly, we assess whether the derivative instruments are highly effective and continue to qualify for hedge accounting. To assess the effectiveness of the hedging relationship both prospectively and retrospectively, we use regression analysis to calculate the correlation of the changes in the fair values of the derivative instrument and related hedged item.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
We record commodity derivative instruments in the consolidated balance sheets at fair value. We recognize mark-to-market adjustments for derivative instruments designated and qualifying as fair value hedges (Fair Value Hedges) and the related change in the fair value of the associated hedged physical inventory or firm commitment within “Cost of product sales.” For derivative instruments designated and qualifying as cash flow hedges (Cash Flow Hedges), we record the effective portion of mark-to-market adjustments as a component of accumulated other comprehensive income (loss) (AOCI) until the underlying hedged forecasted transactions occur. Any hedge ineffectiveness is recognized immediately in “Cost of product sales.” Once a hedged transaction occurs, we reclassify the effective portion from AOCI to “Cost of product sales.” If it becomes probable that a hedged transaction will not occur, then the associated gains or losses are reclassified from AOCI to “Cost of product sales” immediately. For derivative instruments that have associated underlying physical inventory but do not qualify for hedge accounting (Economic Hedges and Other Derivatives), we record the mark-to-market adjustments in “Cost of product sales.”
Under the terms of our forward-starting interest rate swap agreements, we pay a fixed rate and receive a variable rate. We enteredenter into the forward-starting swaps in order to hedge the risk of changes in the interest payments attributable to changes in the benchmark interest rate during the period from the effective date of the swap to the issuance of the forecasted debt. We account for theFor forward-starting interest rate swaps designated and qualifying as Cash Flow Hedges, andcash flow hedges, we recognize the fair value of each interest rate swap in the consolidated balance sheets. We record changes in the effective portionfair value of mark-to-market adjustmentsthe hedge as a component of AOCI, andaccumulated other comprehensive income (loss) (AOCI), to the extent those cash flow hedges remain highly effective. If at any point a cash flow hedge ineffectiveness isceases to qualify for hedge accounting, changes in the fair value of the hedge are recognized immediately in “Interest expense, net.”
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
net” from that date forward. The amount accumulated in AOCI is amortized into “Interest expense, net” as the forecasted interest payments occur or if the interest payments are probable not to occur.
We classify cash flows associated with our derivative instruments as operating cash flows in the consolidated statements of cash flows, except for receipts or payments associated with terminated forward-starting interest rate swap agreements, which are included in cash flows from financing activities. See Note 16 for additional information regarding our derivative financial instruments.
Operating LeasesDefined Benefit Plans
We recognize rent expenseestimate pension and other postretirement benefit obligations and costs based on a straight-line basis overactuarial valuations. The annual measurement date for our pension and other postretirement benefit plans is December 31. The actuarial valuations require the lease term,use of certain assumptions including the impactdiscount rates, expected long-term rates of both scheduled rent increasesreturn on plan assets and free or reduced rents (commonly referredexpected rates of compensation increase. Changes in these assumptions are primarily influenced by factors outside our control. Please refer to as “rent holidays”).Note 21 for further discussion of our pension and other postretirement benefit obligations.
Unit-based CompensationRevenue Recognition
Unit-based compensationRevenue-Generating Activities.Revenues for the pipeline segment are derived from interstate and intrastate pipeline transportation of refined products, crude oil and anhydrous ammonia and the applicable pipeline tariff on a per barrel basis for crude oil or refined products and on a per ton basis for ammonia. Revenues generated from product sales in the pipeline segment relate to surplus pipeline loss allowance volumes.
Revenues for the storage segment include fees for tank storage agreements, under which a customer agrees to pay for a certain amount of storage in a tank over a period of time (storage terminal revenues), and throughput agreements, under which a customer pays a fee per barrel for volumes moving through our terminals (throughput terminal revenues). Our terminals also provide blending, additive injections, handling and filtering services for which we charge additional fees.
Revenues for the fuels marketing segment are derived from the sale of petroleum products.
Within both our pipeline and storage segments, we provide services on uninterruptible and interruptible bases. Uninterruptible services within our pipeline segment typically result from contracts that contain take-or-pay minimum volume commitments (MVCs) from the customer. Contracts with MVCs obligate the customer to pay for that minimum amount. If a customer fails to meet its MVC for the applicable service period, the customer is obligated to pay a deficiency fee based upon the shortfall between the actual volumes transported or stored and the MVC for that service period (deficiency payments). In exchange, those contracts with MVCs obligate us to stand ready to transport volumes up to the customer’s MVC.
Within our storage segment, uninterruptible services arise from contracts containing a fixed monthly fee for the portion of storage capacity reserved by the customer. These contracts require that the customer pay the fixed monthly fee, regardless of whether or not it uses our storage facility (i.e., take-or-pay obligation), and that we stand ready to store that volume. Interruptible services within our pipeline and storage segments are generally provided when and to the extent we determine the requested capacity is available. The customer typically pays a per-unit rate for the actual quantities of services it receives.
For the majority of our contracts, we recognize revenue in the amount to which we have a right to invoice. Generally, payment terms do not exceed 30 days.
Performance Obligations. The majority of our contracts contain a single performance obligation. For our pipeline segment, the single performance obligation encompasses multiple activities necessary to deliver our customers’ products to their destinations. Typically, we satisfy this performance obligation over time as the product volume is delivered in or out of the pipelines. Certain of our pipeline segment customer contracts include an incentive pricing structure, which provides a discounted rate for the remainder of the contract once the customer exceeds a cumulative volume. The ability to receive discounted future services represents a material right to the customer, which results in a second performance obligation in those contracts.
The performance obligation for our long-term incentive planstorage segment consists of multiple activities necessary to receive, store and deliver our customers’ products. We typically satisfy this performance obligation over time as the product volume is recordeddelivered in or out of the tanks (for throughput terminal revenues) or with the passage of time (for storage terminal revenues).
Product sales contracts generally include a single performance obligation to deliver specified volumes of a commodity, which we satisfy at a point in time, when the product is delivered and the customer obtains control of the commodity.
Optional services described in our consolidated balance sheetscontracts do not provide a material right to the customer, and are not considered a separate performance obligation in the contract. If and when a customer elects an optional service, and the terms of the contract are otherwise met, those services become part of the existing performance obligation.
Transaction Price. For uninterruptible services, we determine the transaction price at contract inception based on the fair valueguaranteed minimum amount of revenue over the term of the awards grantedcontract. For interruptible services and recognized as compensation expense primarily on a straight-line basis overoptional services, we determine the requisite service period. Forfeitures of our unit-based compensation awards are recognized as an adjustment to compensation expense when they occur. Unit-based compensation expense is included in “General and administrative expenses”transaction price based on our consolidated statements of income. See Note 23right to invoice the customer for additional information regarding our unit-based compensation.
Margin Deposits
Margin deposits relate to our exchange-traded derivative contracts and generally vary based on changes in the value of services provided to the contracts. Margin depositscustomer for the applicable period.
In certain instances, our customers reimburse us for capital projects, in arrangements referred to as contributions in aid of construction, or CIAC. Typically, in these instances, we receive upfront payments for future services, which are included in “Other current assets” in the consolidated balance sheets.
Foreign Currency Translation
The functional currencies of our foreign subsidiaries are the local currenciestransaction price of the countries in which the subsidiaries are located, except for our subsidiaries located in St. Eustatius in the Caribbean (formerly the Netherlands Antilles), whose functional currency is the U.S. dollar. The assets and liabilities of our foreign subsidiaries with local functional currencies are translated to U.S. dollars at period-end exchange rates, and income and expense items are translated to U.S. dollars at weighted-average exchange rates in effect during the period. These translation adjustments are included in “Accumulated other comprehensive loss” in the equity section of the consolidated balance sheets. Gains and losses on foreign currency transactions are included in “Other (expense) income, net” in the consolidated statements of income.underlying service contract.
3. NEW ACCOUNTING PRONOUNCEMENTS
Derivatives and Hedging
In August 2017, the Financial Accounting Standards Board (FASB) issued amended guidance intended to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. The amended guidance also makes certain targeted improvements to simplify the application of current hedge accounting guidance. The guidance is effective for annual and interim periods beginning after December 15, 2018, with early adoption permitted. Certain of the new requirements should be applied prospectively while others should be applied using a modified retrospective transition method. We currently expect to adopt the amended guidance on January 1, 2019. We do not
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
We collect taxes on certain revenue transactions to be remitted to governmental authorities, which may include sales, use, value-added and some excise taxes. These taxes are not included in the transaction price and are, therefore, excluded from revenues.
Allocation of Transaction Price. We allocate the transaction price to the single performance obligation that exists in the vast majority of our contracts with customers. For the few contracts that have a second performance obligation, such as those that include an incentive pricing structure, we calculate an average rate based on the estimated total volumes to be delivered over the term of the contract and the resulting estimated total revenue to be billed using the applicable rates in the contract. We allocate the transaction price to the two performance obligations by applying the average rate to product volumes as they are delivered to the customer over the term of the contract. Determining the timing and amount of volumes subject to these incentive pricing contracts requires judgment that can impact the amount of revenue allocated to the two separate performance obligations. We base our estimates on our analysis of expected future production information available from our customers or other sources, which we update at least quarterly.
Some of our MVC contracts include provisions that allow the customer to apply deficiency payments to future service periods (the carryforward period). In those instances, we have not satisfied our performance obligation as we still have the obligation to perform those services, subject to contractual and/or capacity constraints, at the customer’s request. At least quarterly, we assess the customer’s ability to utilize any deficiency payments during the carryforward period. If we receive a deficiency payment from a customer that we expect the guidancecustomer to haveutilize during the carryforward period, we defer that amount as a material impactcontract liability. We will consider the performance obligation satisfied and allocate any deferred deficiency payments to our performance obligation when the customer utilizes the deficiency payment, the carryforward period ends or we determine the customer cannot or will not utilize the deficiency payment (i.e. breakage).If our contract does not allow the customer to apply deficiency payments to future service periods, we allocate the deficiency payment to the already satisfied portion of the performance obligation.
Income Allocation
Our partnership agreement contains provisions for the allocation of net income to the unitholders. Our net income for each quarterly reporting period is first allocated to the preferred limited partner unitholders in an amount equal to the earned distributions for the respective reporting period. We allocate the remaining net income or loss among the common unitholders.
Basic and Diluted Net Income (Loss) Per Common Unit
Basic and diluted net income (loss) per common unit is determined pursuant to the two-class method. Under this method, all earnings are allocated to our limited partners and participating securities based on their respective rights to receive distributions earned during the period. Participating securities include restricted units awarded under our long-term incentive plans. We compute basic net income (loss) per common unit by dividing net income (loss) attributable to our common limited partners by the weighted-average number of common units outstanding during the period. We compute diluted net income (loss) per common unit by dividing net income (loss) attributable to our common limited partners by the sum of (i) the weighted-average number of common units outstanding during the period and (ii) the effect of dilutive potential common units outstanding during the period. Dilutive potential common units include contingently issuable performance units awarded and the Series D Preferred Units. See Note 22 for additional information on our financial position or results of operations, and we are assessing the impactperformance units, Note 17 for additional information on our disclosures.Series D Preferred Units and Note 19 for the calculation of basic and diluted net income (loss) per common unit.
Derivative Financial Instruments
Unit-Based PaymentsWhen we apply hedge accounting, we formally document all relationships between hedging instruments and hedged items. This process includes identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. To qualify for hedge accounting, at inception of the hedge we assess whether the derivative instruments that are used in our hedging transactions are expected to be highly effective in offsetting changes in cash flows. Throughout the designated hedge period and at least quarterly, we assess whether the derivative instruments are highly effective and continue to qualify for hedge accounting.
In May 2017,We enter into forward-starting swaps in order to hedge the FASB issued amended guidance that clarifies when a changerisk of changes in the interest payments attributable to changes in the benchmark interest rate during the period from the effective date of the swap to the terms and conditions of a unit-based payment award is accounted for as a modification. Under the amended guidance, an entity will apply modification accounting if the value, vesting or classificationissuance of the unit-based payment award changes. The guidance is effective for annualforecasted debt. For forward-starting interest rate swaps designated and interim periods beginning after December 15, 2017, and amendments should be applied prospectively. We adopted these provisions January 1, 2018, andqualifying as cash flow hedges, we recognize the guidance did not have a material impact on our financial position, resultsfair value of operations or disclosures.
Defined Benefit Plans
In March 2017, the FASB issued amended guidance that changes the presentation of net periodic pension cost related to defined benefit plans. Under the amended guidance, the service cost component of net periodic benefit cost will be presentedeach interest rate swap in the same income statement line items as other current employee compensation costs, but the remaining components of net periodic benefit cost will be presented outside of operating income. Theconsolidated balance sheets. We record changes are effective for annual and interim periods beginning after December 15, 2017, and amendments should be applied retrospectively. We adopted these provisions January 1, 2018, and the guidance did not have a material impact on our financial position, results of operations or disclosures.
Goodwill
In January 2017, the FASB issued amended guidance that simplifies the accounting for goodwill impairment by eliminating step 2 of the goodwill impairment test. Under the amended guidance, goodwill impairment will be measured as the excess of the reporting unit’s carrying value over its fair value, not to exceed the carrying amount of goodwill for that reporting unit. The changes are effective for annual and interim periods beginning after December 15, 2019, and amendments should be applied prospectively. Early adoption is permitted for any impairment tests performed after January 1, 2017, and we are currently evaluating whether we will adopt these provisions early. Regardless of our decision, we do not expect the guidance to have a material impact on our financial position, results of operations or disclosures.
Definition of a Business
In January 2017, the FASB issued amended guidance that clarifies the definition of a business used in evaluating whether a set of transferred assets and activities constitutes a business. Under the amended guidance, if substantially all of the fair value of the gross assets acquired is concentrated inhedge as a single identifiable asset or a groupcomponent of similar identifiable assets, the set of transferred assets and activities would not represent a business. To be considered a business, the set of assets transferred is also required to include at least one substantive process that together significantly contributeaccumulated other comprehensive income (loss) (AOCI), to the abilityextent those cash flow hedges remain highly effective. If at any point a cash flow hedge ceases to create outputs. In addition, the amended guidance narrows the definition of outputs to be consistent with how outputs are describedqualify for hedge accounting, changes in the new revenue recognition standard. The changesfair value of the hedge are effective for annual and interim periods beginning after December 15, 2017, and amendments should be applied prospectively. We adopted these provisions January 1, 2018, and they did not have an impact on our financial position, results of operations or disclosures.
Statement of Cash Flows
In August 2016, the FASB issued amended guidance that clarifies how entities should present certain cash receipts and cash payments on the statement of cash flows, including, but not limited to, debt prepayment or debt extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims and distributions received from equity method investees. The changes are effective for annual and interim periods beginning after December 15, 2017, and amendments should be applied retrospectively. We adopted these provisions January 1, 2018, and they did not have an impact on our statements of cash flows or disclosures.
Credit Losses
In June 2016, the FASB issued amended guidance that requires the use of a “current expected loss” model for financial assets measured at amortized cost and certain off-balance sheet credit exposures. Under this model, entities will be required to estimate the lifetime expected credit losses on such instruments based on historical experience, current conditions, and reasonable and supportable forecasts. This amended guidance also expands the disclosure requirements to enable users of financial statements to understand an entity’s assumptions, models and methods for estimating expected credit losses. The changes are effective for annual and interim periods beginning after December 15, 2019, and amendments should be applied using a modified retrospective approach. We currently expect to adopt the amended guidance on January 1, 2020 and are assessing the impact of this amended guidance on our financial position, results of operations and disclosures. We plan to provide additional information about the expected financial impact at a future date.
recognized in “Interest expense,
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
net” from that date forward. The amount accumulated in AOCI is amortized into “Interest expense, net” as the forecasted interest payments occur or if the interest payments are probable not to occur.
We classify cash flows associated with our derivative instruments as operating cash flows in the consolidated statements of cash flows, except for receipts or payments associated with terminated forward-starting interest rate swap agreements, which are included in cash flows from financing activities. See Note 16 for additional information regarding our derivative financial instruments.
LeasesDefined Benefit Plans
In February 2016,We estimate pension and other postretirement benefit obligations and costs based on actuarial valuations. The annual measurement date for our pension and other postretirement benefit plans is December 31. The actuarial valuations require the FASB issued amended guidance that requires lessees to recognize theuse of certain assumptions including discount rates, expected long-term rates of return on plan assets and liabilities that arise from most leases on the balance sheet. For lessors, this amended guidance modifies the classification criteriaexpected rates of compensation increase. Changes in these assumptions are primarily influenced by factors outside our control. Please refer to Note 21 for further discussion of our pension and the accounting for sales-type and direct financing leases. The changes are effective for annual and interim periods beginning after December 15, 2018, and amendments should be applied using a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements, with the option to use certain expedients. In January 2018, the FASB issued additional guidance that provides an optional transition practical expedient for land easements. We currently expect to adopt these provisions on January 1, 2019 using the modified retrospective approach of adoption. We are working to identify our lease arrangements and have begun the process of system implementation. We are continuing to evaluate the impact of this amended guidance on our financial position, results of operations, disclosures and internal controls and plan to provide additional information about the expected financial impact at a future date.other postretirement benefit obligations.
Financial Instruments
In January 2016, the FASB issued new guidance that addresses certain aspects of recognition, measurement, presentation and disclosure of financial instruments. The changes are effective for annual and interim periods beginning after December 15, 2017, and amendments should be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. We adopted these provisions January 1, 2018, and they did not have an impact on our financial position, results of operations or disclosures.
Revenue Recognition
In May 2014,Revenue-Generating Activities.Revenues for the FASBpipeline segment are derived from interstate and intrastate pipeline transportation of refined products, crude oil and anhydrous ammonia and the International Accounting Standards Board jointly issuedapplicable pipeline tariff on a comprehensive new revenue recognition standardper barrel basis for crude oil or refined products and on a per ton basis for ammonia. Revenues generated from product sales in the pipeline segment relate to surplus pipeline loss allowance volumes.
Revenues for the storage segment include fees for tank storage agreements, under which a customer agrees to pay for a certain amount of storage in a tank over a period of time (storage terminal revenues), and throughput agreements, under which a customer pays a fee per barrel for volumes moving through our terminals (throughput terminal revenues). Our terminals also provide blending, additive injections, handling and filtering services for which we charge additional fees.
Revenues for the fuels marketing segment are derived from the sale of petroleum products.
Within both our pipeline and storage segments, we provide services on uninterruptible and interruptible bases. Uninterruptible services within our pipeline segment typically result from contracts that requires an entitycontain take-or-pay minimum volume commitments (MVCs) from the customer. Contracts with MVCs obligate the customer to pay for that minimum amount. If a customer fails to meet its MVC for the applicable service period, the customer is obligated to pay a deficiency fee based upon the shortfall between the actual volumes transported or stored and the MVC for that service period (deficiency payments). In exchange, those contracts with MVCs obligate us to stand ready to transport volumes up to the customer’s MVC.
Within our storage segment, uninterruptible services arise from contracts containing a fixed monthly fee for the portion of storage capacity reserved by the customer. These contracts require that the customer pay the fixed monthly fee, regardless of whether or not it uses our storage facility (i.e., take-or-pay obligation), and that we stand ready to store that volume. Interruptible services within our pipeline and storage segments are generally provided when and to the extent we determine the requested capacity is available. The customer typically pays a per-unit rate for the actual quantities of services it receives.
For the majority of our contracts, we recognize revenue when it transfers promised goodsin the amount to which we have a right to invoice. Generally, payment terms do not exceed 30 days.
Performance Obligations. The majority of our contracts contain a single performance obligation. For our pipeline segment, the single performance obligation encompasses multiple activities necessary to deliver our customers’ products to their destinations. Typically, we satisfy this performance obligation over time as the product volume is delivered in or out of the pipelines. Certain of our pipeline segment customer contracts include an incentive pricing structure, which provides a discounted rate for the remainder of the contract once the customer exceeds a cumulative volume. The ability to receive discounted future services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The standard is effective for public entities for annual and interim periods beginning after December 15, 2017, using one of two retrospective transition methods. We adopted these provisions January 1, 2018 using the modified retrospective approach. The transition adjustment relatedrepresents a material right to the adoption was immaterial (less than 1%customer, which results in a second performance obligation in those contracts.
The performance obligation for our storage segment consists of total revenuesmultiple activities necessary to receive, store and deliver our customers’ products. We typically satisfy this performance obligation over time as the product volume is delivered in or out of the tanks (for throughput terminal revenues) or with the passage of time (for storage terminal revenues).
Product sales contracts generally include a single performance obligation to deliver specified volumes of a commodity, which we satisfy at a point in time, when the product is delivered and the customer obtains control of the commodity.
Optional services described in our contracts do not provide a material right to the customer, and are not considered a separate performance obligation in the contract. If and when a customer elects an optional service, and the terms of the contract are otherwise met, those services become part of the existing performance obligation.
Transaction Price. For uninterruptible services, we determine the transaction price at contract inception based on the guaranteed minimum amount of revenue over the term of the contract. For interruptible services and optional services, we determine the transaction price based on our right to invoice the customer for the year ended December 31, 2017 and total partners’ equity as of December 31, 2017), and we do not expect the adoption of this standard to materially impact the amount or timing of our revenue going forward. Under the new guidance, we will no longer recognize the fair value of product imbalance assets or liabilities on our consolidated balance sheets. We intendservices provided to provide additional disclosures as required by the new standard, which we are currently assessing, in our quarterly report on Form 10-Qcustomer for the first quarterapplicable period.
In certain instances, our customers reimburse us for capital projects, in arrangements referred to as contributions in aid of 2018.
4. ACQUISITIONS
Navigator Acquisition
On April 11, 2017,construction, or CIAC. Typically, in these instances, we entered into a Membership Interest Purchase and Sale Agreement (the Acquisition Agreement) with FR Navigator Holdings LLC to acquire all of the issued and outstanding limited liability company interests in Navigator Energy Services, LLC (Navigator)receive upfront payments for approximately $1.5 billion. We closed the Navigator Acquisition on May 4, 2017 and funded the purchase price with the net proceeds of the equity and debt issuances described in Notes 12 and 19. We acquired crude oil transportation, pipeline gathering and storage assets located in the Midland Basin of West Texas consisting of: (i) more than 500 miles of crude oil gathering and transportation pipelines with approximately 92,000 barrels per day ship-or-pay volume commitments and deliverability of approximately 412,000 barrels per day; (ii) a pipeline gathering system with more than 200 connected producer tank batteries capable of more than 400,000 barrels per day of pumping capacity covering over 500,000 dedicated acres with fixed fee contracts; and (iii) approximately 1.0 million barrels of crude oil storage capacity with 440,000 barrels contracted to third parties. We collectively refer to the acquired assets as our Permian Crude System. The assets acquiredfuture services, which are included in our pipeline segment within the Central West System.
The Navigator Acquisition broadens our geographic footprint by marking our entry into the Permian Basin and complements our existing asset base. We believe the Permian Crude System will provide a strong growth platform that, when coupled with our assets in the Eagle Ford region, serve to solidify our presence in twotransaction price of the most prolific basins in the United States.underlying service contract.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
We accounted for the Navigator Acquisition using the acquisition method. The fair value estimates of the assets acquired and liabilities assumed are basedcollect taxes on preliminary assumptions, pending the completion of an independent appraisal and other evaluations as information becomes available to us. The following table reflects the preliminary purchase price allocation as of December 31, 2017:
|
| | | |
| | Preliminary Purchase Price Allocation |
| | (Thousands of Dollars) |
| Accounts receivable | $ | 4,747 |
|
| Other current assets | 2,359 |
|
| Property, plant and equipment, net | 376,690 |
|
| Intangible assets (a) | 700,000 |
|
| Goodwill (b) | 400,838 |
|
| Other long-term assets, net | 2,199 |
|
| Current liabilities | (25,114 | ) |
| Preliminary purchase price allocation, net of cash acquired | $ | 1,461,719 |
|
| |
(a) | Intangible assets, which consist of customer contracts and relationships, are expected to be amortized on a straight-line basis over a period of 20 years. |
| |
(b) | The goodwill acquired represents the expected benefit from entering new geographic areas and the anticipated opportunities to generate future cash flows from the assets acquired and potential future projects. |
The values used in the purchase price allocation above are preliminary and subject to change after we finalize our review of certain of Navigator’s pre-acquisition liabilities, and pending the completion of an independent appraisal. Although a change in the value used for the assets acquired and liabilities assumed would cause a corresponding increase or decrease in goodwill, we do not expect any changerevenue transactions to be significant.
The consolidated statements of incomeremitted to governmental authorities, which may include the results of operations for Navigator commencing on May 4, 2017. The table below presents certain financial informationsales, use, value-added and some excise taxes. These taxes are not included in the consolidated statementstransaction price and are, therefore, excluded from revenues.
Allocation of income relatedTransaction Price. We allocate the transaction price to the Navigator Acquisition:single performance obligation that exists in the vast majority of our contracts with customers. For the few contracts that have a second performance obligation, such as those that include an incentive pricing structure, we calculate an average rate based on the estimated total volumes to be delivered over the term of the contract and the resulting estimated total revenue to be billed using the applicable rates in the contract. We allocate the transaction price to the two performance obligations by applying the average rate to product volumes as they are delivered to the customer over the term of the contract. Determining the timing and amount of volumes subject to these incentive pricing contracts requires judgment that can impact the amount of revenue allocated to the two separate performance obligations. We base our estimates on our analysis of expected future production information available from our customers or other sources, which we update at least quarterly.
Some of our MVC contracts include provisions that allow the customer to apply deficiency payments to future service periods (the carryforward period). In those instances, we have not satisfied our performance obligation as we still have the obligation to perform those services, subject to contractual and/or capacity constraints, at the customer’s request. At least quarterly, we assess the customer’s ability to utilize any deficiency payments during the carryforward period. If we receive a deficiency payment from a customer that we expect the customer to utilize during the carryforward period, we defer that amount as a contract liability. We will consider the performance obligation satisfied and allocate any deferred deficiency payments to our performance obligation when the customer utilizes the deficiency payment, the carryforward period ends or we determine the customer cannot or will not utilize the deficiency payment (i.e. breakage).If our contract does not allow the customer to apply deficiency payments to future service periods, we allocate the deficiency payment to the already satisfied portion of the performance obligation.
Income Allocation
Our partnership agreement contains provisions for the allocation of net income to the unitholders. Our net income for each quarterly reporting period is first allocated to the preferred limited partner unitholders in an amount equal to the earned distributions for the respective reporting period. We allocate the remaining net income or loss among the common unitholders.
Basic and Diluted Net Income (Loss) Per Common Unit
Basic and diluted net income (loss) per common unit is determined pursuant to the two-class method. Under this method, all earnings are allocated to our limited partners and participating securities based on their respective rights to receive distributions earned during the period. Participating securities include restricted units awarded under our long-term incentive plans. We compute basic net income (loss) per common unit by dividing net income (loss) attributable to our common limited partners by the weighted-average number of common units outstanding during the period. We compute diluted net income (loss) per common unit by dividing net income (loss) attributable to our common limited partners by the sum of (i) the weighted-average number of common units outstanding during the period and (ii) the effect of dilutive potential common units outstanding during the period. Dilutive potential common units include contingently issuable performance units awarded and the Series D Preferred Units. See Note 22 for additional information on our performance units, Note 17 for additional information on our Series D Preferred Units and Note 19 for the calculation of basic and diluted net income (loss) per common unit.
Derivative Financial Instruments
When we apply hedge accounting, we formally document all relationships between hedging instruments and hedged items. This process includes identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. To qualify for hedge accounting, at inception of the hedge we assess whether the derivative instruments that are used in our hedging transactions are expected to be highly effective in offsetting changes in cash flows. Throughout the designated hedge period and at least quarterly, we assess whether the derivative instruments are highly effective and continue to qualify for hedge accounting.
We enter into forward-starting swaps in order to hedge the risk of changes in the interest payments attributable to changes in the benchmark interest rate during the period from the effective date of the swap to the issuance of the forecasted debt. For forward-starting interest rate swaps designated and qualifying as cash flow hedges, we recognize the fair value of each interest rate swap in the consolidated balance sheets. We record changes in the fair value of the hedge as a component of accumulated other comprehensive income (loss) (AOCI), to the extent those cash flow hedges remain highly effective. If at any point a cash flow hedge ceases to qualify for hedge accounting, changes in the fair value of the hedge are recognized in “Interest expense,
|
| | | |
| | Year Ended December 31, 2017 |
| | (Thousands of Dollars) |
| Permian Crude System: | |
| Revenues | $ | 42,620 |
|
| Operating loss | $ | (1,724 | ) |
| | |
| Transaction costs: | |
| General and administrative expenses | $ | 10,391 |
|
| Interest expense, net | 3,688 |
|
| Total transaction costs | $ | 14,079 |
|
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
net” from that date forward. The amount accumulated in AOCI is amortized into “Interest expense, net” as the forecasted interest payments occur or if the interest payments are probable not to occur.
We classify cash flows associated with our derivative instruments as operating cash flows in the consolidated statements of cash flows, except for receipts or payments associated with terminated forward-starting interest rate swap agreements, which are included in cash flows from financing activities. See Note 16 for additional information regarding our derivative financial instruments.
Defined Benefit Plans
We estimate pension and other postretirement benefit obligations and costs based on actuarial valuations. The unaudited pro forma informationannual measurement date for our pension and other postretirement benefit plans is December 31. The actuarial valuations require the years ended December 31, 2017use of certain assumptions including discount rates, expected long-term rates of return on plan assets and 2016 presented below combines the historical financial informationexpected rates of compensation increase. Changes in these assumptions are primarily influenced by factors outside our control. Please refer to Note 21 for Navigatorfurther discussion of our pension and the Partnershipother postretirement benefit obligations.
Unit-based Compensation
Unit-based compensation for those periods. The information assumes we completed the Navigator Acquisitionour long-term incentive plans is recorded in our consolidated balance sheets based on January 1, 2016 and the following:
we issued approximately 14.4 million common units;
we received a contribution from our general partner of $13.6 million to maintain its 2% interest;
we issued 15.4 million Series B Preferred Units;
we issued $550.0 million of 5.625% senior notes;
additional depreciation and amortization that would have been incurred assuming the fair value adjustments to property, plant and equipment and intangible assets reflected in the preliminary purchase price allocation above; and
we satisfied Navigator’s outstanding obligations under its revolving credit agreement.
|
| | | | | | | |
| | Pro Forma Year Ended December 31, |
| | 2017 | | 2016 |
| | (Thousands of Dollars, Except Per Unit Data) |
| Revenues | $ | 1,828,418 |
| | $ | 1,782,932 |
|
| Net income | $ | 127,433 |
| | $ | 78,664 |
|
| | | | |
| Basic and diluted net income per common unit | $ | 0.31 |
| | $ | 0.01 |
|
The pro forma information for the year ended December 31, 2017 includes transaction costs of $14.1 million, which were directly attributable to the Navigator Acquisition. The pro forma information is unaudited and is not necessarily indicative of the results of operations that would have resulted had the Navigator Acquisition occurred on January 1, 2016 or that may result in the future.
Martin Terminal Acquisition. On December 21, 2016, we acquired crude oilawards granted and refined product storage assets in Corpus Christi, TX for $95.7 million, including $2.1 million of capital expenditure reimbursements, from Martin Operating Partnership L.P. (the Martin Terminal Acquisition). The assets acquired are in our storage segment and include 900,000 barrels of crude oil storage capacity, 250,000 barrels of refined product storage capacity and exclusive use of the Port of Corpus Christi’s new crude oil dock.
Linden Acquisition. On January 2, 2015, we acquired full ownership of ST Linden Terminal, LLC (Linden), which owns a refined products terminal in Linden, NJ with 4.3 million barrels of storage capacity (the Linden Acquisition). Linden is locatedrecognized as compensation expense primarily on a 44-acre facility that provides deep-water terminalling capabilities instraight-line basis over the New York Harbor and primarily stores petroleum products, including gasoline, jet fuel and fuel oils. Priorrequisite service period. Forfeitures of our unit-based compensation awards are recognized as an adjustment to the Linden Acquisition, Linden operated as a joint venture between Linden Holding Corp. and us, with each party owning 50%.
In connection with the Linden Acquisition, we ceased applying the equity method of accounting and consolidated Linden, whichcompensation expense when they occur. Unit-based compensation expense is included in “General and administrative expenses” on our storage segment. The consolidated statements of income include(loss). See Note 22 for additional information regarding our unit-based compensation.
Foreign Currency Translation
The functional currencies of our foreign subsidiaries are the resultslocal currencies of operations for Linden commencing on January 2, 2015. On the acquisition date, we remeasuredcountries in which the subsidiaries are located. The assets and liabilities of our existing 50%foreign subsidiaries with local functional currencies are translated to U.S. dollars at period-end exchange rates, and income and expense items are translated to U.S. dollars at weighted-average exchange rates in effect during the period. These translation adjustments are included in “Accumulated other comprehensive loss” in the equity section of the consolidated balance sheets. Upon the sale or liquidation of our investment in Lindena foreign subsidiary, translation adjustments that have historically accumulated in AOCI related to its fair valuethat subsidiary are released from AOCI and reported as part of $128.0 millionthe gain or loss on sale. Gains and we recognized a gain of $56.3 millionlosses on foreign currency transactions are included in “Other income (expense) income,, net” in the consolidated statementstatements of income (loss).
Reclassifications
We have reclassified certain previously reported amounts in the consolidated financial statements and notes to conform to current-period presentation.
3. NEW ACCOUNTING PRONOUNCEMENT
In March 2020, the Financial Accounting Standards Board (FASB) issued guidance intended to provide relief to companies impacted by reference rate reform, which is the transition away from the London Interbank Offering Rate (LIBOR) as its publication is expected to cease after June 30, 2023. The amended guidance provides optional expedients and exceptions for the year endedapplying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. The guidance is effective as of March 12, 2020 through December 31, 2015.2024. We estimatedadopted the fair value usingguidance on a market approachprospective basis on the effective date, and it did not have an income approach. The market approach estimatesimpact on our financial position, results of operations or disclosures at transition. We will continue to evaluate the enterprise valueimpact on contracts modified on or before December 31, 2024. As of December 31, 2022, we expect the interest rate on our subordinated notes and the distribution rates on our 8.50% Series A, 7.625% Series B and 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units to transition from LIBOR-based rates to rates based on an earnings multiple. The income approach calculates fair value by discounting the estimated net cash flows. We funded the acquisition with borrowings under our revolving credit agreement. The acquisition complements our existing storage operations, and having sole ownership of Linden strengthens our presenceSecured Overnight Financing Rate (SOFR), or a similar rate, beginning in the New York Harborthird quarter of 2023, in accordance with the guidance and the East Coast market.applicable rules and regulations governing such transition.
4. DISPOSITIONS AND IMPAIRMENTS
Point Tupper Terminal Disposition
On April 29, 2022, we sold the equity interests in our wholly owned subsidiaries that owned our Point Tupper terminal facility in Nova Scotia, Canada (the Point Tupper Terminal Operations) to EverWind Fuels for $60.0 million. The terminal facility had a storage capacity of 7.8 million barrels and was included in the storage segment. We utilized the sales proceeds to reduce debt and improve our debt metrics.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
During the first quarter of 2022, we determined the Point Tupper Terminal Operations met the criteria to be classified as held for sale. We compared the carrying value of the Point Tupper Terminal Operations, which included $42.2 million in cumulative foreign currency translation losses accumulated since our acquisition of the Point Tupper terminal facility in 2005, to its fair value less costs to sell, and we recognized a pre-tax impairment loss of $46.1 million in the first quarter of 2022, which is presented in "Other impairment losses" on the consolidated statements of income (loss). We believe that the sales price of $60.0 million provided a reasonable indication of the fair value of the Point Tupper Terminal Operations as it represented an exit price in an orderly transaction between market participants. The sales price was a quoted price for identical assets and liabilities in a market that was not active and, thus, our fair value estimate fell within Level 2 of the fair value hierarchy. Upon closing in the second quarter of 2022, we released $39.6 million of foreign currency translation losses from AOCI and finalized our sales price, resulting in a gain of $1.6 million, which is presented in “Other income (expense), net” on the consolidated statements of income (loss).
Eastern U.S. Terminals Disposition
On August 1, 2021, we entered into an agreement (the Purchase Agreement) to sell nine U.S. terminal and storage facilities, including all our North East Terminals and one terminal in Florida (the Eastern U.S. Terminal Operations) to Sunoco LP for $250.0 million (the Eastern U.S. Terminals Disposition). The Eastern U.S. Terminal Operations included terminals in the following locations; Jacksonville, Florida; Andrews Air Force Base, Maryland; Baltimore, Maryland; Piney Point, Maryland; Virginia Beach, Virginia; Paulsboro, New Jersey; and Blue Island, Illinois, as well as both Linden, New Jersey terminals. The Eastern U.S. Terminal Operations had an aggregate storage capacity of 14.8 million barrels and were included in the storage segment. We closed the sale on October 8, 2021 and used the proceeds from the sale to reduce debt and improve our debt metrics.
The Eastern U.S. Terminal Operations met the criteria to be classified as held for sale upon our entrance into the Purchase Agreement during the third quarter of 2021. At that time, we allocated goodwill of $34.1 million to the Eastern U.S. Terminal Operations based on its fair value relative to the terminals reporting unit, with which it had been fully integrated. We tested the allocated goodwill for impairment by comparing the fair value of the Eastern U.S. Terminal Operations to its carrying value. The results of our goodwill impairment test indicated that the carrying value of the Eastern U.S. Terminal Operations exceeded its fair value, and we recognized a related goodwill impairment charge of $34.1 million in the third quarter of 2021 to reduce the allocated goodwill to $0. The goodwill impairment loss is reported in “Goodwill impairment losses” on the consolidated statements of income (loss). We believe that the sales price of $250.0 million provided a reasonable indication of the fair value of the Eastern U.S. Terminal Operations as it represented an exit price in an orderly transaction between market participants. The sales price was a quoted price for identical assets and liabilities in a market that was not active and, thus, our fair value estimate fell within Level 2 of the fair value hierarchy.
We accounted forcompared the Linden Acquisition usingremaining carrying value of the acquisition method. The purchase price has been allocated basedEastern U.S. Terminal Operations, after its goodwill impairment, to its fair value less costs to sell. We recognized an asset impairment loss of $95.7 million in the third quarter of 2021, which is reported in “Other impairment losses” on the estimated fair valuesconsolidated statements of income (loss). The asset impairment loss included $23.9 million related to intangible assets representing customer contracts and relationships.
We determined the assets in the above dispositions were no longer synergistic with our core assets, and these dispositions did not qualify, either individually or in the aggregate, for reporting as discontinued operations, as the sales did not represent strategic shifts that would have a major effect on our operations or financial results.
Houston Pipeline Impairment
In the third quarter of 2021, we recorded a long-lived asset impairment charge of $59.2 million within our pipeline segment related to our refined product pipeline extending from Mt. Belvieu, Texas to Corpus Christi, Texas (the Houston Pipeline). During the third quarter of 2021, we identified an indication of impairment related to the southern section of the individual assets acquiredHouston Pipeline, specifically that its physical condition would require significant investment in order to pursue commercial opportunities. Consequently, we separated the pipeline into two distinct assets: the northern and liabilities assumed at the datesouthern sections. Our estimate of the acquisition.undiscounted cash flows associated with the southern section indicated it was not recoverable. Due to the factors described above, we determined the carrying value of the southern section exceeded its fair value, and reduced its carrying value to $0. We recorded the asset impairment charge in “Other impairment losses” on the consolidated statements of income (loss). We determined that the northern portion of the pipeline was not impaired.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Sale of Texas City Terminals
On December 7, 2020, we sold the equity interests in our wholly owned subsidiaries that owned two terminals in Texas City, Texas for $106.0 million (the Texas City Sale). The two terminals had an aggregate storage capacity of 3.0 million barrels and were previously included in our storage segment. We recorded a loss of $34.7 million in “Other income (expense), net” on our consolidated statements of income (loss) and utilized the sales proceeds to reduce debt and improve our debt metrics.
5. REVENUE FROM CONTRACTS WITH CUSTOMERS
Contract Assets and Contract Liabilities
The final purchase price allocation wasfollowing table provides information about contract assets and contract liabilities from contracts with customers:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2022 | | 2021 | | 2020 |
| Contract Assets | | Contract Liabilities | | Contract Assets | | Contract Liabilities | | Contract Assets | | Contract Liabilities |
| (Thousands of Dollars) |
| Balances as of January 1: | | | | | | | | | | | |
| Current portion | $ | 2,336 | | | $ | (15,443) | | | $ | 2,694 | | | $ | (22,019) | | | $ | 2,140 | | | $ | (21,083) | |
| Noncurrent portion | 504 | | | (46,027) | | | 932 | | | (47,537) | | | 1,003 | | | (40,289) | |
| | | | | | | | | | | |
| Total | 2,840 | | | (61,470) | | | 3,626 | | | (69,556) | | | 3,143 | | | (61,372) | |
| | | | | | | | | | | |
| Activity: | | | | | | | | | | | |
| Additions | 6,137 | | | (45,200) | | | 3,888 | | | (41,121) | | | 5,686 | | | (69,830) | |
| Transfer to accounts receivable | (5,978) | | | — | | | (3,977) | | | — | | | (4,828) | | | — | |
| Transfer to revenues | (83) | | | 47,618 | | | (697) | | | 49,207 | | | (375) | | | 61,646 | |
| | | | | | | | | | | |
| Total | 76 | | | 2,418 | | | (786) | | | 8,086 | | | 483 | | | (8,184) | |
| | | | | | | | | | | |
| Balances as of December 31: | | | | | | | | | | | |
| Current portion | 2,612 | | | (17,647) | | | 2,336 | | | (15,443) | | | 2,694 | | | (22,019) | |
| Noncurrent portion | 304 | | | (41,405) | | | 504 | | | (46,027) | | | 932 | | | (47,537) | |
| | | | | | | | | | | |
| Total | $ | 2,916 | | | $ | (59,052) | | | $ | 2,840 | | | $ | (61,470) | | | $ | 3,626 | | | $ | (69,556) | |
Contract assets relate to performance obligations satisfied in advance of scheduled billings. Current contract assets are included in “Prepaid and other current assets” and noncurrent contract assets are included in “Other long-term assets, net” on the consolidated balance sheets. Contract liabilities relate to payments received in advance of satisfying performance obligations under a contract, which mainly result from contracts with an incentive pricing structure, CIAC payments and contracts with MVCs. The current portion of contract liabilities are included in “Accrued liabilities” and the noncurrent portion of contract liabilities are included in “Other long-term liabilities” on the consolidated balance sheets.
Remaining Performance Obligations
The following table presents our estimated revenue from contracts with customers for remaining performance obligations that has not yet been recognized, representing our contractually committed revenue as follows (in thousands of dollars):December 31, 2022:
| | | | | |
| Remaining Performance Obligations |
| (Thousands of Dollars) |
| 2023 | $ | 352,995 | |
| 2024 | 250,738 | |
| 2025 | 154,585 | |
| 2026 | 101,656 | |
| 2027 | 34,621 | |
| Thereafter | 69,346 | |
| Total | $ | 963,941 | |
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
|
| | | |
| Cash paid for the Linden Acquisition | $ | 142,500 |
|
| Fair value of liabilities assumed | 22,865 |
|
| Consideration | 165,365 |
|
| Acquisition date fair value of previously held equity interest | 128,000 |
|
| Total | $ | 293,365 |
|
| | |
| Current assets (a) | $ | 9,513 |
|
| Property, plant and equipment | 134,484 |
|
| Goodwill | 79,208 |
|
| Intangible assets (b) | 70,050 |
|
| Other long-term assets | 110 |
|
| Purchase price allocation | $ | 293,365 |
|
| |
(a) | Current assets include a receivable of $7.8 million related to a pre-acquisition insurance claim, for which proceeds were received in 2015. |
| |
(b) | Intangible assets primarily consist of customer contracts and relationships and are being amortized over 10 years. |
Our contractually committed revenue, for purposes of the tabular presentation above, is generally limited to customer contracts that have fixed pricing and fixed volume terms and conditions, including contracts with MVC payment obligations.
5.Disaggregation of Revenues
The following table disaggregates our revenues:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| (Thousands of Dollars) |
| Pipeline segment: | | | | | |
| Crude oil pipelines | $ | 391,176 | | | $ | 331,485 | | | $ | 329,105 | |
| Refined products and ammonia pipelines (excluding lessor revenues) | 437,015 | | | 430,753 | | | 387,793 | |
| Total pipeline segment revenues from contracts with customers | 828,191 | | | 762,238 | | | 716,898 | |
| Lessor revenues | — | | | — | | | 1,925 | |
| Total pipeline segment revenues | 828,191 | | | 762,238 | | | 718,823 | |
| | | | | |
| Storage segment: | | | | | |
| Throughput terminals | 110,591 | | | 122,331 | | | 136,632 | |
| Storage terminals (excluding lessor revenues) | 180,903 | | | 263,883 | | | 316,496 | |
| Total storage segment revenues from contracts with customers | 291,494 | | | 386,214 | | | 453,128 | |
| Lessor revenues | 43,055 | | | 41,454 | | | 41,314 | |
| Total storage segment revenues | 334,549 | | | 427,668 | | | 494,442 | |
| | | | | |
| Fuels marketing segment: | | | | | |
| Revenues from contracts with customers | 520,486 | | | 428,608 | | | 268,345 | |
| | | | | |
| Consolidation and intersegment eliminations | (3) | | | (14) | | | (46) | |
| | | | | |
| Total revenues | $ | 1,683,223 | | | $ | 1,618,500 | | | $ | 1,481,564 | |
6. ALLOWANCE FOR DOUBTFUL ACCOUNTSCREDIT LOSSES
The changes
For the years ended December 31, 2022 and 2020, activity related to our allowance for credit losses was immaterial, and the balances as of December 31, 2022, 2021 and 2020 totaled $0.4 million, $0 and $0, respectively. We received a settlement of $1.7 million in the allowancefirst quarter of 2021 for doubtful accounts consisted of the following:a credit loss that was previously written off.
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (Thousands of Dollars) |
| Balance as of beginning of year | $ | 7,756 |
| | $ | 8,473 |
| | $ | 7,808 |
|
| Increase in allowance, net | 2,217 |
| | 24 |
| | 965 |
|
| Accounts charged against the allowance | (25 | ) | | (741 | ) | | (300 | ) |
| Balance as of end of year | $ | 9,948 |
| | $ | 7,756 |
| | $ | 8,473 |
|
6.7. INVENTORIES
Inventories consisted of the following:
| | | | | | | | | | | |
| | December 31, |
| | 2022 | | 2021 |
| | (Thousands of Dollars) |
| Petroleum products | $ | 11,291 | | | $ | 12,456 | |
| Materials and supplies | 4,106 | | | 4,188 | |
| Total | $ | 15,397 | | | $ | 16,644 | |
|
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| | (Thousands of Dollars) |
| Petroleum products | $ | 17,027 |
| | $ | 28,044 |
|
| Materials and supplies | 9,830 |
| | 9,901 |
|
| Total | $ | 26,857 |
| | $ | 37,945 |
|
We purchase petroleum products for resale. Our petroleum products consist of intermediates, gasoline, distillatesbunker fuel and other petroleum products. Materials and supplies mainly consistconsist of blending and additive chemicals and maintenance materials used in our pipeline and storage segments.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
7. OTHER CURRENT ASSETS
Other current assets consisted of the following:
|
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| | (Thousands of Dollars) |
| Axeon Term Loan | $ | — |
| | $ | 110,000 |
|
| Prepaid expenses | 15,982 |
| | 14,894 |
|
| Derivative assets | — |
| | 155 |
|
| Other | 6,526 |
| | 7,637 |
|
| Other current assets | $ | 22,508 |
| | $ | 132,686 |
|
Axeon Term Loan. In December 2016, Lindsay Goldberg LLC, the private investment firm that owned Axeon, informed us that they entered into an agreement to sell Axeon’s retail asphalt sales and distribution business (the Axeon Sale), and we entered into an agreement with Axeon (the Axeon Letter Agreement) to settle and terminate the Axeon Term Loan for a $110.0 million payment to us upon closing of the Axeon Sale. Therefore, we recorded a charge of $58.7 million, included in “Other (expense) income, net” in the consolidated statements of income, to reduce the carrying amount of the Axeon Term Loan to $110.0 million and reclassified the Axeon Term Loan from “Other long-term assets, net” to “Other current assets” on the consolidated balance sheet as of December 31, 2016. The Axeon Sale closed on February 22, 2017, at which time we received the $110.0 million payment in accordance with the Axeon Letter Agreement. Furthermore, the Axeon Term Loan and our obligation to provide ongoing credit support to Axeon all terminated concurrently on February 22, 2017. Please refer to Note 15 for a discussion of the guarantees. In addition, in connection with the closing of the Axeon Sale, the terminal storage agreements that Axeon has with our Jacksonville, FL and Baltimore, MD terminal facilities were amended to increase the storage fees.
Prior to the closing of the Axeon Sale, we reviewed the financial information of Axeon monthly for possible credit loss indicators. We recognized interest income associated with the Axeon Term Loan ratably over the term of the loan in “Interest expense, net” on the consolidated statements of income.
8. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment at cost, consisted of the following:
| | | | | | | | | | | | | | | | | | | | | | | |
| Estimated Useful Lives | | December 31, |
| | | 2022 | | 2021 |
| | (Years) | | (Thousands of Dollars) |
| Land, buildings and improvements | 0 | - | 40 | | $ | 362,444 | | | $ | 366,525 | |
| Pipelines, storage and terminals | 15 | - | 40 | | 4,936,780 | | | 4,897,041 | |
| Rights-of-way | 20 | - | 40 | | 365,171 | | | 353,262 | |
| Construction in progress | | | | | 69,290 | | | 112,020 | |
| Total | | | | | 5,733,685 | | | 5,728,848 | |
| Less accumulated depreciation and amortization | | | | | (2,330,602) | | | (2,187,206) | |
| Property, plant and equipment, net | | | | | $ | 3,403,083 | | | $ | 3,541,642 | |
|
| | | | | | | | | | | |
| | Estimated Useful Lives | | December 31, |
| | | 2017 | | 2016 |
| | (Years) | | (Thousands of Dollars) |
| Land | | - | | | $ | 143,527 |
| | $ | 138,224 |
|
| Land and leasehold improvements | 5 | - | 40 | | 203,085 |
| | 187,930 |
|
| Buildings | 15 | - | 40 | | 151,702 |
| | 144,773 |
|
| Pipelines, storage and terminals | 20 | - | 40 | | 5,080,795 |
| | 4,647,718 |
|
| Rights-of-way | 20 | - | 40 | | 264,170 |
| | 202,311 |
|
| Construction in progress | | - | | | 400,202 |
| | 114,322 |
|
| Total | | | | | 6,243,481 |
| | 5,435,278 |
|
| Less accumulated depreciation and amortization | | | | | (1,942,548 | ) | | (1,712,995 | ) |
| Property, plant and equipment, net | | | | | $ | 4,300,933 |
| | $ | 3,722,283 |
|
Capitalized interest costs added to property, plant and equipment totaled $5.5$3.9 million, $3.4$3.9 million and $5.5$4.9 million for the years ended December 31, 2017, 20162022, 2021 and 2015,2020, respectively. Depreciation and amortization expense for property, plant and equipment totaled $222.5$215.0 million, $200.7$225.7 million and $192.3$233.5 million for the years ended December 31, 2017, 20162022, 2021 and 2015, respectively.2020, respectively, which includes amortization of finance leases.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
9. INTANGIBLE ASSETS
Intangible assets consisted of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Weighted-Average Amortization Period | | December 31, 2022 | | December 31, 2021 |
| | | Cost | | Accumulated
Amortization | | Cost | | Accumulated
Amortization |
| | (Years) | | (Thousands of Dollars) |
| Customer contracts and relationships | 20 | | $ | 793,900 | | | $ | (281,618) | | | $ | 793,900 | | | $ | (237,579) | |
| Other | 47 | | 2,359 | | | (945) | | | 2,359 | | | (895) | |
| Total | | | $ | 796,259 | | | $ | (282,563) | | | $ | 796,259 | | | $ | (238,474) | |
|
| | | | | | | | | | | | | | | | | |
| | | | December 31, 2017 | | December 31, 2016 |
| | Weighted-Average Amortization Period | | Cost | | Accumulated Amortization | | Cost | | Accumulated Amortization |
| | (Years) | | (Thousands of Dollars) |
| Customer contracts and relationships | 18 | | $ | 863,950 |
| | $ | (81,136 | ) | | $ | 166,950 |
| | $ | (41,582 | ) |
| Other | 47 | | 2,359 |
| | (694 | ) | | 2,359 |
| | (644 | ) |
| Total | | | $ | 866,309 |
| | $ | (81,830 | ) | | $ | 169,309 |
| | $ | (42,226 | ) |
Intangible assets are recorded at fair value as of the date acquired. All of our intangible assets are amortized on a straight-line basis. Amortization expense for intangible assets was $39.6$44.1 million, $13.9$48.5 million and $16.7$51.4 million for the years ended December 31, 2017, 20162022, 2021 and 2015,2020, respectively. The estimated aggregate amortization expense is approximately $51.0$38.0 million for each of the years 20182023 through 2022.2026 and $35.0 million for 2027.
10. GOODWILL
Changes in the carrying amount of goodwill by segment were as follows:
|
| | | | | | | | | | | | | | | |
| | Pipeline | | Storage | | Fuels Marketing | | Total |
| | (Thousands of Dollars) |
| Balances as of January 1, 2016 and December 31, 2016: | | | | | | | |
| Goodwill | $ | 306,207 |
| | $ | 691,220 |
| | $ | 53,255 |
| | $ | 1,050,682 |
|
| Accumulated impairment losses | — |
| | (331,913 | ) | | (22,132 | ) | | (354,045 | ) |
| Net goodwill | 306,207 |
| | 359,307 |
| | 31,123 |
| | 696,637 |
|
| | | | | | | | |
| Activity for the year ended December 31, 2017: | | | | | | | |
| Navigator Acquisition preliminary purchase price allocation (a) | 400,838 |
| | — |
| | — |
| | 400,838 |
|
| | | | | | | | |
| Balances as of December 31, 2017: | | | | | | | |
| Goodwill | 707,045 |
| | 691,220 |
| | 53,255 |
| | 1,451,520 |
|
| Accumulated impairment losses | — |
| | (331,913 | ) | | (22,132 | ) | | (354,045 | ) |
| Net goodwill | $ | 707,045 |
| | $ | 359,307 |
| | $ | 31,123 |
| | $ | 1,097,475 |
|
| |
(a) | See Note 4 for discussion of the Navigator Acquisition. |
11. ACCRUED LIABILITIES
Accrued liabilities consisted of the following:
|
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| | (Thousands of Dollars) |
| Employee wages and benefit costs | $ | 16,963 |
| | $ | 30,807 |
|
| Unearned income | 18,243 |
| | 14,355 |
|
| Other | 26,372 |
| | 15,323 |
|
| Accrued liabilities | $ | 61,578 |
| | $ | 60,485 |
|
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
10. GOODWILL
The balances of and changes in the carrying amount of goodwill by segment were as follows:
| | | | | | | | | | | | | | | | | |
| Pipeline | | Storage | | Total |
| | (Thousands of Dollars) |
| Balances as of January 1, 2021: | | | | | |
| Goodwill | $ | 704,231 | | | $ | 287,185 | | | $ | 991,416 | |
| Accumulated impairment loss | (225,000) | | | — | | | (225,000) | |
| Net goodwill | 479,231 | | | 287,185 | | | 766,416 | |
| | | | | |
| Activity for the year ended December 31, 2021: | | | | | |
| Goodwill impairment loss on Eastern U.S. Terminal Operations | — | | | (34,060) | | | (34,060) | |
| | | | | |
| Balances as of December 31, 2021 and 2022: | | | | | |
| Goodwill | 704,231 | | | 253,125 | | | 957,356 | |
| Accumulated impairment loss | (225,000) | | | — | | | (225,000) | |
| Net goodwill | $ | 479,231 | | | $ | 253,125 | | | $ | 732,356 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
Eastern U.S. Terminals Operations. On October 8, 2021, we completed the sale of the Eastern U.S. Terminals Operations. In the third quarter of 2021, the Eastern U.S. Terminal Operations met the criteria to be classified as held for sale, and we tested the allocated goodwill for impairment. We recognized a goodwill impairment charge of $34.1 million in the third quarter of 2021. Please see Note 4 for additional information.
2020 Impairment. In March 2020, the COVID-19 pandemic and actions taken by the Organization of Petroleum Exporting Countries and other oil-producing nations (OPEC+) resulted in severe disruptions in the capital and commodities markets, which led to significant decline in our unit price. As a result, our equity market capitalization fell significantly. The decline in crude oil prices and demand for petroleum products also led to a decline in expected earnings from some of our goodwill reporting units. These factors and others related to COVID-19 and OPEC+ caused us to conclude there were triggering events that occurred in March 2020 that required us to perform a goodwill impairment test as of March 31, 2020. The assumptions in the fair value measurement reflected the then-current market environment, industry-specific factors and company-specific factors. The decline in expected earnings from certain of our long-lived assets was also an indicator that the carrying values of these long-lived assets may not be recoverable. Prior to performing the goodwill impairment test, we tested these long-lived assets for recoverability and determined they were fully recoverable as of March 31, 2020. We recognized a goodwill impairment charge of $225.0 million in the first quarter of 2020, which was reported in the pipeline segment. Our assessment did not identify any other reporting units at risk of a goodwill impairment.
11. ACCRUED LIABILITIES
Accrued liabilities consisted of the following:
| | | | | | | | | | | |
| | December 31, |
| | 2022 | | 2021 |
| | (Thousands of Dollars) |
| Employee wages and benefit costs | $ | 40,249 | | | $ | 40,209 | |
| Revenue contract liabilities | 17,647 | | | 15,443 | |
| | | |
| Operating lease liabilities | 5,541 | | | 10,346 | |
| | | |
| Environmental costs | 3,122 | | | 3,378 | |
| | | |
| Other | 9,513 | | | 10,442 | |
| Accrued liabilities | $ | 76,072 | | | $ | 79,818 | |
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
12. DEBT
Short-term debt consisted of the current portion of finance leases, with balances of $4.4 million and $3.8 million as of December 31, 2022 and 2021, respectively. Please refer to Note 15 for additional information.
Long-term debt consisted of the following:
|
| | | | | | | | | | | |
| | | | | | December 31, |
| | Maturity | | 2017 | | 2016 |
| | | | | | (Thousands of Dollars) |
| Revolving Credit Agreement | | 2020 | | | $ | 893,311 |
| | $ | 838,992 |
|
| 7.65% senior notes | | 2018 | | | 350,000 |
| | 350,000 |
|
| 4.80% senior notes | | 2020 | | | 450,000 |
| | 450,000 |
|
| 6.75% senior notes | | 2021 | | | 300,000 |
| | 300,000 |
|
| 4.75% senior notes | | 2022 | | | 250,000 |
| | 250,000 |
|
| 5.625% senior notes | | 2027 | | | 550,000 |
| | — |
|
| Subordinated Notes | | 2043 | | | 402,500 |
| | 402,500 |
|
| GoZone Bonds | 2038 | thru | 2041 | | 365,440 |
| | 365,440 |
|
| Receivables Financing Agreement | | 2020 | | | 62,300 |
| | 58,400 |
|
| Net fair value adjustments, unamortized discounts and unamortized debt issuance costs | | N/A | | | (10,492 | ) | | (968 | ) |
| Total long-term debt | | | | | 3,613,059 |
| | 3,014,364 |
|
| Less current portion | | | | | 349,990 |
| | — |
|
| Long-term debt, less current portion | | | | | $ | 3,263,069 |
| | $ | 3,014,364 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | December 31, |
| | Maturity | | 2022 | | 2021 |
| | | | | | (Thousands of Dollars) |
| Receivables Financing Agreement | January 31, 2025 | | $ | 80,900 | | | $ | 83,800 | |
| Revolving Credit Agreement | April 27, 2025 | | 220,000 | | | 110,500 | |
| 5.75% senior notes | October 1, 2025 | | 600,000 | | | 600,000 | |
| 6.00% senior notes | June 1, 2026 | | 500,000 | | | 500,000 | |
| 5.625% senior notes | April 28, 2027 | | 550,000 | | | 550,000 | |
| 6.375% senior notes | October 1, 2030 | | 600,000 | | | 600,000 | |
| GoZone Bonds | 2038 | thru | 2041 | | 322,140 | | | 322,140 | |
| Subordinated Notes | January 15, 2043 | | 402,500 | | | 402,500 | |
| Unamortized debt issuance costs | | N/A | | | (33,251) | | | (38,315) | |
| Total long-term debt (excluding finance leases) | | | | | 3,242,289 | | | 3,130,625 | |
| Finance leases (Note 15) | | | | | 51,126 | | | 52,930 | |
| | | | | | | |
| Long-term debt, less current portion of finance leases | | | | | $ | 3,293,415 | | | $ | 3,183,555 | |
The long-term debt repayments (excluding finance leases) as of December 31, 2022 are due as follows (in thousands of dollars):follows:
| | | | | |
| Long-Term Debt Repayments |
| (Thousands of Dollars) |
| 2023 | $ | — | |
| 2024 | — | |
| 2025 | 900,900 | |
| 2026 | 500,000 | |
| 2027 | 550,000 | |
| Thereafter | 1,324,640 | |
| Total repayments | 3,275,540 | |
| Unamortized debt issuance costs | (33,251) | |
| Total long-term debt (excluding finance leases) | $ | 3,242,289 | |
|
| | | |
| 2018 | $ | 350,000 |
|
| 2019 | — |
|
| 2020 | 1,405,611 |
|
| 2021 | 300,000 |
|
| 2022 | 250,000 |
|
| Thereafter | 1,317,940 |
|
| Total repayments | 3,623,551 |
|
| Net fair value adjustments, unamortized discounts and unamortized debt issuance costs | (10,492 | ) |
| Total long-term debt | $ | 3,613,059 |
|
Interest payments related to debt obligations totaled $163.6$197.3 million, $146.1$220.0 million and $138.9$207.2 million for the years ended December 31, 2017, 20162022, 2021 and 2015,2020, respectively. We amortized an aggregate of $5.0$8.2 million, $4.4$7.9 million and $4.0$11.4 million of debt issuance costs and debt discount combined for the years ended December 31, 2017, 20162022, 2021 and 2015,2020, respectively.
Revolving Credit Agreement
On August 22, 2017,As of December 31, 2022, NuStar Logistics amended itsLogistics’ $1.0 billion revolving credit agreement (the Revolving Credit Agreement), mainly to extend had $775.3 million available for borrowing and $220.0 million borrowings outstanding. Letters of credit issued under the maturity date from October 29, 2019 to October 29, 2020, and to increase the borrowing capacity from $1.50 billion to $1.75 billion. The Revolving Credit Agreement includestotaled $4.7 million as of December 31, 2022. Letters of credit limit the ability toamount we can borrow up tounder the equivalent of $250.0 million in Euros and up to the equivalent of $250.0 million in British Pounds Sterling.Revolving Credit Agreement. Obligations under the Revolving Credit Agreement are guaranteed by NuStar Energy and NuPOP. For the year ended December 31, 2017, we recorded deferred issuance costs of $3.1 million associated with the Revolving Credit Agreement to “Other long-term assets, net” on the consolidated balance sheet.
The Revolving Credit Agreement was also amendedis subject to increasemaximum consolidated debt coverage ratio and minimum consolidated interest coverage ratio requirements, which may limit the amount we can borrow to an amount less than the total amount available for borrowing. For the rolling period ending December 31, 2022, the maximum allowed consolidated debt coverage ratio (as defined in the Revolving Credit Agreement) from 5.00-to-1.00 to 5.50-to-1.00 through the rolling period ending March 31, 2018. Subsequently, the maximum allowed consolidated debt coverage ratio may not exceed 5.00-to-1.00 for any rolling period ending on or after June 30, 2018. If we complete one or more acquisitions for aggregate net consideration of at least $50.0 million, our maximumand the minimum consolidated debt coverage ratio will increase to 5.50-to-1.00 for two rolling periods. On November 22, 2017, the Revolving Credit Agreement was amended to continue to exclude our $402.5 million fixed-to-floating rate subordinated notes from the definition of consolidated debt for purposes of calculating our consolidated debtinterest coverage ratio
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
through December 31, 2018.(as defined in the Revolving Credit Agreement), must not be less than 1.75-to-1.00. The Revolving Credit Agreement also contains customary restrictive covenants, such as limitations on indebtedness, liens, mergers, asset transfers and certain investing activities.
The requirement not to exceed a maximum consolidated debt coverage ratio may limit the amount we can borrow under the Revolving Credit Agreement to an amount less than the total amount available for borrowing. As of December 31, 2017,2022, we had $853.0 million available for borrowing.believe that we are in compliance with the covenants in the Revolving Credit Agreement.
The Revolving Credit Agreement bears interest, at our option, based on an alternative base rate a LIBOR-based rate or a EURIBOR-basedSOFR-based rate. The interest rate on the Revolving Credit Agreement is subject to adjustment if our debt rating is downgraded (or upgraded) by certain credit rating agencies. AsIn August of December 31, 2017, our weighted-average interest rate was 3.2%. During the year ended December 31, 2017, the weighted-average interest rate related to borrowings under the Revolving Credit Agreement was 2.8%.
Letters of credit issued under the Revolving Credit Agreement totaled $3.7 million as of December 31, 2017. Letters of credit are limited to $400.0 million (including up to the equivalent of $25.0 million in Euros and up to the equivalent of $25.0 million in British Pounds Sterling) and also may restrict the amount we can borrow under the Revolving Credit Agreement.
In February 2018,2020, Moody’s Investor Service Inc. (Moody’s) lowereddowngraded our credit rating from Ba1Ba2 to Ba2.Ba3. This rating downgrade caused the interest rate on our Revolving Credit Agreement to increase by 0.25% effective February 2018.
Notes
NuStar Logistics Senior Notes. On April 28, 2017, NuStar Logistics issued $550.0 million of 5.625% senior notes due April 28, 2027. We used the net proceeds of $543.3 million from the offering to fund a portion of the purchase price for the Navigator Acquisition and to pay related fees and expenses. The interest on the 5.625% senior notes is payable semi-annually in arrears on April 28 and October 28 of each year beginning on October 28, 2017.
Interest is payable semi-annually in arrears for the $350.0 million of 7.65% senior notes, $450.0 million of 4.80% senior notes, $300.0 million of 6.75% senior notes, $250.0 million of 4.75% senior notes and $550.0 million of 5.625% senior notes (collectively, the NuStar Logistics Senior Notes).August 2020. The interest rate payable on the 7.65% senior notes isRevolving Credit Agreement and certain fees under the Receivables Financing Agreement, defined below, are the only debt arrangements that are subject to adjustment if our debt rating is downgraded (or upgraded) by certain credit rating agencies and was 8.40% asagencies. As of December 31, 2017. In November 2017, Standard & Poor’s Rating Services lowered2022, our credit rating from BB+ to BB. Additionally, the outlook was changed from stable to negative. The rating downgrade caused theweighted-average interest rate onunder our Revolving Credit Agreement was 6.9%. During the 7.65%year ended December 31, 2022, the weighted-average interest rate related to borrowings under the Revolving Credit Agreement was 4.3%.
On January 28, 2022, we amended and restated our unsecured Revolving Credit Agreement primarily to: (i) extend the maturity date from October 27, 2023 to April 27, 2025; (ii) increase the maximum amount of letters of credit capable of being issued from $400.0 million to $500.0 million; (iii) replace LIBOR benchmark provisions with customary SOFR benchmark provisions; (iv) remove the 0.50x increase permitted in our consolidated debt coverage ratio for certain rolling periods in which an acquisition for aggregate net consideration of at least $50.0 million occurs; and (v) add baskets and exceptions to certain negative covenants.
Notes
NuStar Logistics Senior Notes.On November 1, 2021, we repaid our $250.0 million of 4.75% senior notes due 2018February 1, 2022 with proceeds from the Eastern U.S. Terminals Disposition. We repaid our $300.0 million of 6.75% senior notes due February 1, 2021 and our $450.0 million of 4.8% senior notes due September 1, 2020 with borrowings under our Revolving Credit Agreement.
On September 14, 2020, NuStar Logistics issued $600.0 million of 5.75% senior notes due October 1, 2025 and $600.0 million of 6.375% senior notes due October 1, 2030. We received proceeds of $1,182.0 million, net of issuance costs of $18.0 million, which we used to increase from 8.15%repay outstanding borrowings and the early repayment premiums under the Term Loan, as defined below, as well as outstanding borrowings under our Revolving Credit Agreement. The issuance of the 5.75% and 6.375% senior notes bolstered our liquidity to 8.40%. The credit rating downgrade by Moody’saddress our senior note maturities that we repaid in February 2018 also increased2021.
Interest is payable semi-annually in arrears for the interest rate by 0.25%, resulting in an interest rate$600.0 million of 8.65% applicable to5.75% senior notes, $500.0 million of 6.0% senior notes, $550.0 million of 5.625% senior notes and $600.0 million of 6.375% senior notes (collectively, the interest payment due April 15, 2018.NuStar Logistics Senior Notes).
The NuStar Logistics Senior Notes do not have sinking fund requirements. These notes rank equally with existing senior unsecured indebtedness and senior to existing subordinated indebtedness of NuStar Logistics and contain restrictions on NuStar Logistics’ ability to incur additional secured indebtedness unless the same security is also provided for the benefit of holders of the NuStar Logistics Senior Notes. In addition, the NuStar Logistics Senior Notes limit the ability of NuStar Logistics’ abilityLogistics and its subsidiaries to, among other things, incur indebtedness secured by certain liens, and to engage in certain sale-leaseback transactions.transactions and engage in certain consolidations, mergers or asset sales. At the option of NuStar Logistics, the NuStar Logistics Senior Notes may be redeemed in whole or in part at any time at a redemption price, which includes a make-whole premium, plus accrued and unpaid interest to the redemption date. If we undergo a change of control, as defined in the supplemental indentures for the 6.75% senior notes or the 5.625% senior notes,NuStar Logistics Senior Notes, each holder of the 6.75% senior notes or the 5.625%applicable senior notes may require us to repurchase all or a portion of its notes at a price equal to 101% of the principal amount of the notes repurchased, plus any accrued and unpaid interest to the date of repurchase. The NuStar Logistics Senior Notes are fully and unconditionally guaranteed by NuStar Energy and NuPOP.
NuStar Logistics 7.625% Fixed-to-Floating Rate Subordinated Notes.NuStar Logistics’ $402.5 million of 7.625% fixed-to-floating rate subordinated notes are due January 15, 2043 (the Subordinated Notes). The Subordinated Notes are fully and unconditionally guaranteed on an unsecured and subordinated basis by NuStar Energy and NuPOP. The Subordinated Notes bore interest at a fixed annual rate of 7.625%, payable quarterly in arrears beginning on April 15, 2013 and ending onEffective January 15, 2018. Thereafter,2018, the interest rate on the Subordinated Notes bear interest atswitched to an annual rate equal to the sum of the three-month LIBOR rate for the related quarterly interest period, plus 6.734% payable quarterly, commencing April 15, 2018, unless payment is deferred in accordance with the terms of the notes. NuStar Logistics may elect to defer interest payments on the Subordinated Notes on one or more occasions for up to five consecutive years. Deferred interest will accumulate additional interest at a rate equal to the interest rate then applicable to the Subordinated
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Notes until paid. If NuStar Logistics elects to defer interest payments, NuStar Energy cannot declare or make cash distributions to its unitholders during the period that interest payments are deferred.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
December 31, 2022, the interest rate was 10.8%.
The Subordinated Notes do not have sinking fund requirements and are subordinated to existing senior unsecured indebtedness of NuStar Logistics and NuPOP. The Subordinated Notes do not contain restrictions on NuStar Logistics’ ability to incur additional indebtedness, including debt that ranks senior in priority of payment to the notes. In addition, the Subordinated Notes do not limit NuStar Logistics’ ability to incur indebtedness secured by liens or to engage in certain sale-leaseback transactions. Effective January 15, 2018, we may redeem the Subordinated Notes in whole or in part at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest to the redemption date.
Gulf Opportunity Zone Revenue Bonds
In 2008, 2010 and 2011, the Parish of St. James, Louisiana issued Revenue Bonds Series 2008, Series 2010, Series 2010A, Series 2010B and Series 2011 associated with our St. James terminal expansions pursuant to the Gulf Opportunity Zone Act of 2005 for an aggregate $365.4 million (collectively, the GoZone Bonds). The interest rates on these bonds are based on a weekly tax-exempt bond market interest rate, and interest is paid monthly. Following the issuances, the proceeds were deposited with a trustee and arewere disbursed to us upon our request for reimbursement of expenditures related to our St. James terminal expansions. We include the amount remainingterminal. On March 4, 2020, NuStar Logistics repaid $43.3 million of GoZone Bonds with unused funds, which had been held in the trust in “Other long-term assets, net,” and we include the amount of bonds issued in “Long-term debt” in our consolidated balance sheets. We did not receive any proceeds from the trustee for the year ended December 31, 2017, and for the year ended December 31, 2016, we received $12.5 million from the trustee.
trust. NuStar Logistics is solely obligated to servicemake payments in amounts sufficient to pay the principal of, premium, if any, interest and interestcertain other payments associated withon, the GoZone Bonds. Letters
On June 3, 2020, NuStar Logistics completed the reoffering and conversion of the GoZone Bonds through supplements to the original indentures governing the GoZone Bonds and supplements to the original agreements between NuStar Logistics and the Parish of St. James, which, among other things, converted the interest rate from a weekly rate to a long-term rate. In connection with the reoffering and conversion, we terminated the letters of credit werepreviously issued by various individual banks on our behalf to guaranteesupport the payment of interestpayments required in connection with the GoZone Bonds, and principal on the bonds. All letters of credit rank equally with existing senior unsecured indebtedness of NuStar Logistics. Obligations under the letters of credit issued are guaranteed by NuStar Energy and NuPOP. The letters of credit issued by individual banks doNuPOP guaranteed NuStar Logistics’ obligations with respect to the GoZone Bonds. We did not restrictreceive any proceeds from the amount we can borrow underreoffering, and the Revolving Credit Agreement.reoffering did not increase our outstanding debt.
The following table summarizes the GoZone Bonds outstanding as of December 31, 2017:2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Series | | Date Issued | | Amount
Outstanding | | | | | | | |
Interest Rate | | Mandatory
Purchase Date | | Maturity Date |
| | | | (Thousands of Dollars) | | | | | | |
| Series 2008 | | June 26, 2008 | | $ | 55,440 | | | | | | | | | 6.10 | % | | June 1, 2030 | | June 1, 2038 |
| Series 2010 | | July 15, 2010 | | 100,000 | | | | | | | | | 6.35 | % | | n/a | | July 1, 2040 |
| Series 2010A | | October 7, 2010 | | 43,300 | | | | | | | | | 6.35 | % | | n/a | | October 1, 2040 |
| Series 2010B | | December 29, 2010 | | 48,400 | | | | | | | | | 6.10 | % | | June 1, 2030 | | December 1, 2040 |
| Series 2011 | | August 9, 2011 | | 75,000 | | | | | | | | | 5.85 | % | | June 1, 2025 | | August 1, 2041 |
| | Total | | $ | 322,140 | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | |
| Date Issued | | Maturity Date | | Amount Outstanding | | Amount of Letter of Credit | | Amount Received from Trustee | | Amount Remaining in Trust (a) | |
Interest Rate (b) |
| | | | | (Thousands of Dollars) | | |
| June 26, 2008 | | June 1, 2038 | | $ | 55,440 |
| | $ | 56,169 |
| | $ | 55,440 |
| | $ | — |
| | 1.8 | % |
| July 15, 2010 | | July 1, 2040 | | 100,000 |
| | 101,315 |
| | 100,000 |
| | — |
| | 1.7 | % |
| October 7, 2010 | | October 1, 2040 | | 50,000 |
| | 50,658 |
| | 43,741 |
| | 6,546 |
| | 1.7 | % |
| December 29, 2010 | | December 1, 2040 | | 85,000 |
| | 86,118 |
| | 49,782 |
| | 35,997 |
| | 1.7 | % |
| August 29, 2011 | | August 1, 2041 | | 75,000 |
| | 75,986 |
| | 75,000 |
| | — |
| | 1.8 | % |
| | | Total | | $ | 365,440 |
| | $ | 370,246 |
| | $ | 323,963 |
| | $ | 42,543 |
| | |
| |
(a) | Amount remaining in trust includes accrued interest. |
| |
(b) | For the year ended December 31, 2017, our weighted-average interest rate on borrowings was 0.9%. |
Interest on the GoZone Bonds accrues from June 3, 2020 and is payable semi-annually on June 1 and December 1 of each year, beginning December 1, 2020. The holders of the Series 2008, Series 2010B and Series 2011 GoZone Bonds are required to tender their bonds at the applicable mandatory purchase date in exchange for 100% of the principal plus accrued and unpaid interest, after which these bonds will potentially be remarketed with a new interest rate established. Each of the Series 2010 and Series 2010A GoZone Bonds is subject to redemption on or after June 1, 2030 by the Parish of St. James, at our option, in whole or in part, at a redemption price of 100% of the principal amount to be redeemed plus accrued interest. The Series 2008, Series 2010B and Series 2011 GoZone Bonds are not subject to optional redemption.
NuStar Logistics’ agreements with the Parish of St. James related to the GoZone Bonds contain (i) customary restrictive covenants that limit the ability of NuStar Logistics and its subsidiaries, to, among other things, create liens, enter into certain sale-leaseback transactions, and engage in certain consolidations, mergers or asset sales and (ii) a change of control provision that provides each holder the right to require the trustee, with funds provided by NuStar Logistics, to repurchase all or a portion of that holder’s GoZone Bonds upon a change of control at a price equal to 101% of the aggregate principal amount repurchased, plus any accrued and unpaid interest.
Receivables Financing Agreement
NuStar Energy and NuStar Finance LLC (NuStar Finance), a special purpose entity and wholly owned subsidiary of NuStar Logistics,Energy, are parties to a $125.0$100.0 million receivables financing agreement with a third-party lenderslender (the Receivables Financing
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Agreement) and agreements with certain of NuStar Energy’s wholly owned subsidiaries (collectively(together with the Receivables Financing Agreement, the Securitization Program). Under the Securitization Program, certain of NuStar Energy’s wholly owned subsidiaries (collectively, the Originators), sell their accounts receivable to NuStar Finance on an ongoing basis, and NuStar Finance provides the newly acquired accounts receivable as collateral for its revolving borrowings under the Receivables Financing Agreement. NuStar Energy provides a performance guarantee in connection with the Securitization Program. The maximum amount available for borrowing by NuStar Finance under the Receivables Financing Agreement is $125.0 million, with an option for NuStar Finance to request an increase of up to $75.0 million from the lenders (for aggregate total borrowings not to exceed $200.0 million). The amount available for borrowing is based on the availability of eligible receivables and other customary factors and conditions. The Securitization Program contains various customary affirmative and negative covenants and default, indemnification and termination provisions, and the Receivables Financing Agreement provides for acceleration of amounts owed upon the occurrence of certain specified events. NuStar Finance’s sole activity consists of purchasing such receivables and providing them as collateral under the Securitization Program. NuStar Finance is a separate legal entity and the assets of NuStar Finance, including these accounts receivable, are not available to satisfy the claims of creditors of NuStar Energy, the Originators or their affiliates.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
On September 20, 2017,January 28, 2022, the Securitization ProgramReceivables Financing Agreement was amended to add certain of NuStar Energy’s wholly owned subsidiaries resulting from the Navigator Acquisition and toprimarily to: (i) extend the Securitization Program’s scheduled termination date from June 15, 2018 to September 20, 2020,2023 to January 31, 2025; (ii) reduce the floor rate in the calculation of our borrowing rates; and (iii) replace provisions related to the LIBOR rate of interest with the optionreferences to renew for additional 364-day periods thereafter. SOFR rates of interest.
Borrowings by NuStar Finance under the Receivables Financing Agreement bear interest, at the applicable bankNuStar Finance’s option, at a base rate or a SOFR rate, each as defined underin the Receivables Financing Agreement. As of December 31, 20172022 and 2016,2021, accounts receivable totaling $92.6$121.5 million and $104.5$119.2 million, respectively, were included in the Securitization Program. As of December 31, 2022, our interest rate under the Securitization Program was 6.0%. The weighted averageweighted-average interest rate related to outstanding borrowings under the Securitization Program during the year ended December 31, 20172022 was 2.0%3.4%.
Short-Term Lines ofTerm Loan Credit Agreement
On April 19, 2020, NuStar Energy and NuStar Logistics is party to two short-term line ofentered into an unsecured term loan credit agreementsagreement with certain lenders and Oaktree Fund Administration, LLC, as administrative agent for the lenders (the Term Loan). The Term Loan provided for an aggregate uncommitted borrowing capacitycommitment of up to $85.0$750.0 million which allow uspursuant to better manage fluctuations in our daily cash requirementsa three-year unsecured term loan credit facility. NuStar Logistics drew $500.0 million (the Initial Loan) on April 21, 2020. We utilized the proceeds from the Initial Loan, net of the original issue discount of $22.5 million (3.0% of the total commitment) and minimize our excess cash balances. The interest rate and maturity vary and are determined at the timeissuance costs of borrowing. We had $35.0$14.4 million, outstanding under these lines of credit as of December 31, 2017. Obligations under these short-term line of credit agreements are guaranteed by NuStar Energy. The weighted-average interest rate related to repay outstanding borrowings under our short-term linesRevolving Credit Agreement. The Term Loan bolstered our liquidity to address near-term senior note maturities.
On September 16, 2020, we used a portion of credit during the years ended December 31, 2017net proceeds from the issuance of the 5.75% and 2016, was 2.7%6.375% senior notes to repay the $500.0 million of outstanding borrowings under the Term Loan and 2.0%, respectively.pay related early repayment premiums totaling $97.6 million. We also recognized costs of $40.3 million related to unamortized debt issuance costs, unamortized discount and a commitment fee, which resulted in a loss from extinguishment of debt of $137.9 million in the third quarter of 2020. On February 16, 2021, we terminated the Term Loan. Outstanding borrowings, prior to repayment, bore interest at an aggregate rate of 12.0% per annum.
13. HEALTH, SAFETY AND ENVIRONMENTAL MATTERS
Our operations are subject to extensive international, federal, state and local environmental laws and regulations, in the U.S. and in the other countries in which we operate,Mexico, including those relating to the discharge of materials into the environment, waste management, remediation, the characteristics and composition of fuels, climate change and greenhouse gases. Our operations are also subject to extensive health, safety and security laws and regulations, including those relating to worker and pipeline safety, pipeline and storage tank integrity and operations security. The principal environmental, health, safety and security risks associated with our operations relate to unauthorized emissions into the air, releases into soil, surface water or groundwater, personal injury and property damage. We have adopted policies, practices, systems and procedures designed to comply with the laws and regulations, and to help minimize and mitigate these risks, limit the liability that could result from such events, prevent material environmental or other damage, ensure the safety of our employees and the public and secure our pipelines, terminals and operations. Compliance with environmental, health, safety and security laws, regulations and related permits increases our capital expenditures and operating expenses, and violation of these laws, regulations or permits could result in significant civil and criminal liabilities, injunctions or other penalties. Future governmental action and regulatory initiatives could result in more restrictive laws and regulations, which could increase required capital expenditures and operating expenses. The risk of additional compliance expenditures, expenses and liabilities are inherent to government-regulated industries, including midstream energy. As a result, there can be no assurances that significant expenditures, expenses and liabilities will not be incurred in the future.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Most of our pipelines are subject to federal regulation by one or more of the following governmental agencies: the Federal Energy Regulatory Commission (the FERC), the Surface Transportation Board (the STB), the Department of Transportation (DOT)(the DOT), the Environmental Protection Agency (EPA)(the EPA) and the Department of Homeland Security. Additionally, the operations and integrity of theour pipelines are subject to the respective state jurisdictions along the routes of the systems.states those lines traverse.
We have adopted policies, practices and procedures to address pollution control, pipeline integrity, operator qualifications, public relations and education, process safety management, risk management planning, hazard communication, emergency response planning, community right-to-know, occupational health and the handling, storage, use and disposal of hazardous materials. Our policies are designed to comply with applicable federal, state and local regulations and to prevent material environmental or other damage, to ensure the safety of our pipelines, our employees, the public and the environment and to limit the financial liability that could result from such events. Future governmental action and regulatory initiatives could necessitate changes to expected operating permits and procedures, additional remedial actions or increased capital expenditures and operating costs. Risks of additional costs and liabilities are inherent within the industry, and there can be no assurances that significant costs and liabilities will not be incurred in the future.
Environmental and safety exposures and liabilities are difficult to assess and estimate due to unknown factors such as the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental and safety laws and regulations may change in the future. Although environmental and safety costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The balance of and changes in the accruals for environmental matters were as follows:
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2022 | | 2021 |
| | (Thousands of Dollars) |
| Balance as of the beginning of year | $ | 7,748 | | | $ | 8,373 | |
| Additions to accrual | 2,640 | | | 2,044 | |
| Payments | (2,019) | | | (2,669) | |
| | | |
| Balance as of the end of year | $ | 8,369 | | | $ | 7,748 | |
|
| | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 |
| | (Thousands of Dollars) |
| Balance as of the beginning of year | $ | 5,120 |
| | $ | 7,667 |
|
| Additions to accrual | 3,186 |
| | 870 |
|
| Payments | (2,675 | ) | | (3,302 | ) |
| Foreign currency translation | 52 |
| | (115 | ) |
| Balance as of the end of year | $ | 5,683 |
| | $ | 5,120 |
|
Accruals for environmental matters are included in the consolidated balance sheets as follows:
| | | | | | | | | | | |
| | December 31, |
| | 2022 | | 2021 |
| | (Thousands of Dollars) |
| Accrued liabilities | $ | 3,122 | | | $ | 3,378 | |
| Other long-term liabilities | 5,247 | | | 4,370 | |
| Accruals for environmental matters | $ | 8,369 | | | $ | 7,748 | |
|
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| | (Thousands of Dollars) |
| Accrued liabilities | $ | 3,054 |
| | $ | 3,281 |
|
| Other long-term liabilities | 2,629 |
| | 1,839 |
|
| Accruals for environmental matters | $ | 5,683 |
| | $ | 5,120 |
|
14. COMMITMENTS AND CONTINGENCIES
Commitments
Future minimum payments applicable to all noncancellable purchase obligations as of December 31, 2022 are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Payments Due by Period | | |
| | 2023 | | 2024 | | 2025 | | 2026 | | 2027 | | Thereafter | | Total |
| | (Thousands of Dollars) |
| Purchase obligations | $ | 7,643 | | | $ | 4,538 | | | $ | 2,817 | | | $ | 1,432 | | | $ | 1,443 | | | $ | 9,532 | | | $ | 27,405 | |
Our purchase obligations primarily consist of various right-of-way and easement agreements with property owners and service agreements with information technology providers.
Contingencies
We have contingent liabilities resulting from various litigation, claims and commitments. We record accruals for loss contingencies when losses are considered probable and can be reasonably estimated. Legal fees associated with defending the Partnership in legal matters are expensed as incurred. We accrued $7.3$0.3 million and $0.1 million for contingent losses as of December 31, 2017,2022 and had no accrual for contingent losses as of December 31, 2016.2021, respectively. The amount that will ultimately be paid related to such matters may differ from the recorded accruals, and the timing of such payments is uncertain. In addition, due to the inherent uncertainty of litigation, there can be no assuranceWe evaluate each contingent loss at least quarterly, and more frequently as each matter progresses and develops over time, and we do not believe that the resolution of any particular claim or proceeding, or all matters in the aggregate, would not have a material adverse effect on our results of operations, financial position or liquidity.
Commitments
Lessee Commitments. Future minimum rental payments applicable to all noncancellable operating leases and purchase obligations as of December 31, 2017 are as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Payments Due by Period |
| | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | There- after | | Total |
| | (Thousands of Dollars) |
| Operating leases | $ | 39,236 |
| | $ | 34,203 |
| | $ | 19,541 |
| | $ | 13,324 |
| | $ | 7,295 |
| | $ | 68,386 |
| | $ | 181,985 |
|
| Purchase obligations | $ | 6,963 |
| | $ | 6,133 |
| | $ | 4,686 |
| | $ | 4,690 |
| | $ | 4,480 |
| | $ | 300 |
| | $ | 27,252 |
|
Rental expense for all operating leases totaled $36.2 million, $37.0 million and $39.7 million for the years ended December 31, 2017, 2016 and 2015, respectively. NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
15. LEASE ASSETS AND LIABILITIES
Lessee Arrangements
Our operating leases consist primarily of the following:
a ten-year lease for tugsland and barges utilized at our St. Eustatius facility for bunker fuel sales, with two five-year renewal options; and
landdock leases at various terminal facilities, with originalfacilities. As of December 31, 2022, land and dock leases generally have remaining terms ranging from 10of about five years and include options to 100 years.extend for five to twenty-five years, which we are reasonably certain to exercise.
Our purchase obligations primarily consistThe primary component of an eleven-year chemical supply agreement relatedour finance lease portfolio is a dock at our Corpus Christi North Beach terminal, which includes a commitment for minimum dockage and wharfage throughput volumes. The dock lease has a remaining term of approximately three years and three additional five-year renewal periods, all of which we are reasonably certain to exercise.
Right-of-use assets and lease liabilities included in our pipelines.consolidated balance sheet were as follows:
| | | | | | | | | | | | | | | | | | | | |
| | | | December 31, |
| | Balance Sheet Location | | 2022 | | 2021 |
| | | | (Thousands of Dollars) |
| Right-of-use assets: | | | | | | |
| Operating | | Other long-term assets, net | | $ | 62,745 | | | $ | 76,867 | |
| Finance | | Property, plant and equipment, net of accumulated amortization of $19,295 and $13,561 | | $ | 68,219 | | | $ | 71,002 | |
| | | | | | |
| Lease liabilities: | | | | | | |
| Operating: | | | | | | |
| Current | | Accrued liabilities | | $ | 5,541 | | | $ | 10,346 | |
| Noncurrent | | Other long-term liabilities | | 56,577 | | | 65,060 | |
| Total operating lease liabilities | | | | $ | 62,118 | | | $ | 75,406 | |
| Finance: | | | | | | |
| Current | | Current portion of finance leases | | $ | 4,416 | | | $ | 3,848 | |
| Noncurrent | | Long-term debt, less current portion of finance leases | | 51,126 | | | 52,930 | |
| Total finance lease liabilities | | | | $ | 55,542 | | | $ | 56,778 | |
As of December 31, 2022, maturities of our operating and finance lease liabilities were as follows:
| | | | | | | | | | | | | | |
| | Operating Leases | | Finance Leases |
| | (Thousands of Dollars) |
| 2023 | | $ | 7,535 | | | $ | 6,366 | |
| 2024 | | 7,309 | | | 5,887 | |
| 2025 | | 6,926 | | | 5,065 | |
| 2026 | | 6,204 | | | 4,552 | |
| 2027 | | 6,027 | | | 3,935 | |
| Thereafter | | 53,183 | | | 48,941 | |
| Total lease payments | | $ | 87,184 | | | $ | 74,746 | |
| Less: Interest | | 25,066 | | | 19,204 | |
| Present value of lease liabilities | | $ | 62,118 | | | $ | 55,542 | |
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Costs incurred for leases were as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2022 | | 2021 | | 2020 |
| | (Thousands of Dollars) |
| Operating lease cost | | $ | 11,777 | | | $ | 15,323 | | | $ | 16,814 | |
| Finance lease cost: | | | | | | |
| Amortization of right-of-use assets | | $ | 5,770 | | | $ | 5,251 | | | $ | 4,700 | |
| Interest expense on lease liability | | $ | 2,023 | | | $ | 2,081 | | | $ | 2,201 | |
| Short-term lease cost | | $ | 10,345 | | | $ | 14,198 | | | $ | 15,359 | |
| Variable lease cost | | $ | 4,830 | | | $ | 4,939 | | | $ | 8,653 | |
| Total lease cost | | $ | 34,745 | | | $ | 41,792 | | | $ | 47,727 | |
The table below presents additional information regarding our leases.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2022 | | 2021 | | 2020 |
| Operating
Leases | | Finance
Leases | | Operating
Leases | | Finance
Leases | | Operating
Leases | | Finance
Leases |
| (Thousands of Dollars, Except Term and Rate Data) |
| For the year ended December 31: | | | | | | | | | | | |
| Cash outflows from operating activities | $ | 11,156 | | $ | 2,019 | | $ | 12,829 | | $ | 2,090 | | $ | 14,487 | | $ | 2,208 |
| Cash outflows from financing activities | $ | — | | $ | 4,222 | | $ | — | | $ | 4,244 | | $ | — | | $ | 4,981 |
| Right-of-use assets obtained in exchange for lease liabilities | $ | 10,060 | | $ | 3,004 | | $ | 3,278 | | $ | 3,173 | | $ | 20,830 | | $ | 3,077 |
| As of December 31: | | | | | | | | | | | |
| Weighted-average remaining lease term (in years) | 16 | | 16 | | 13 | | 18 | | 13 | | 19 |
| Weighted-average discount rate | 3.8 | % | | 3.6 | % | | 3.2 | % | | 3.6 | % | | 3.2 | % | | 3.7 | % |
Lessor Revenues. Arrangements
We have entered into certain revenue arrangements where we are considered to be the lessor in accordance with GAAP.lessor. Under the largest of these arrangements, we lease certain of our storage tanks in exchange for a fixed fee, subject to an annual consumer price indexCPI adjustment. The arrangementsoperating leases commenced on January 1, 2017, and have initial terms of ten10 years with successive ten-year automatic renewal terms. We recognized $39.1 million of lease revenues from these leases of $43.1 million, $41.5 million, and $41.3 million for the yearyears ended December 31, 2017,2022, 2021, and 2020, respectively, which isare included in “Service revenues”“Service revenues” in the consolidated statements of income. Futureincome (loss). As of December 31, 2022, we expect to receive minimum lease payments totaling $156.5 million, based upon the CPI as of the adoption date. We will recognize these payments ratably over the remaining initial lease term.
The table below presents cost, accumulated depreciation and useful life information related to our storage lease assets, which are included in our “Pipeline, storage and terminals” asset class within property, plant and equipment:
| | | | | | | | | | | | | | | | | |
| Estimated Useful Life | | December 31, |
| | | 2022 | | 2021 |
| | (Years) | | (Thousands of Dollars) |
| Lease storage assets, at cost | 30 | | $ | 251,801 | | | $ | 246,841 | |
| Less accumulated depreciation | | | (148,899) | | | (139,200) | |
| Lease storage assets, net | | | $ | 102,902 | | | $ | 107,641 | |
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
16. DERIVATIVES AND FAIR VALUE MEASUREMENTS
revenuesDerivative Instruments
We utilize various derivative instruments to manage our exposure to interest rate risk and commodity price risk. Our risk management policies and procedures are designed to monitor interest rates, futures and swap positions and over-the-counter positions, as well as physical commodity volumes, grades, locations and delivery schedules, to help ensure that our hedging activities address our market risks.
Commodity Price Risk. The results of operations for the fuels marketing segment depend largely on the margin between our cost and the sales prices of the products we expectmarket. Therefore, the results of operations for this segment are more sensitive to receive underchanges in commodity prices compared to the operations of the pipeline and storage segments. Since our fuels marketing operations expose us to commodity price risk, we enter into derivative instruments to mitigate the effect of commodity price fluctuations on our operations. Derivative financial instruments associated with commodity price risk with respect to our petroleum product inventories and related firm commitments to purchase and/or sell such inventories were not material for any period presented.
Interest Rate Risk.We were a party to certain interest rate swap agreements to manage our exposure to changes in interest rates, which consisted of forward-starting interest rate swap agreements related to forecasted debt issuances. We entered into these lease arrangementsswaps in order to hedge the risk of fluctuations in the required interest payments attributable to changes in the benchmark interest rate during the period from the effective date of the swap to the issuance of the forecasted debt. Under the terms of the swaps, we paid a weighted-average fixed rate and received a rate based on the three-month USD LIBOR. These swaps qualified as cash flow hedges, and we designated them as such. We recorded mark-to-market adjustments as a component of AOCI, and the amount in AOCI is recognized in “Interest expense, net” as the forecasted interest payments occur or if the interest payments are probable not to occur. In June 2020, in connection with the reoffering and conversion of the GoZone Bonds, we terminated forward-starting interest rate swaps with an aggregate notional amount of $250.0 million and paid $49.2 million, which will be amortized into “Interest expense, net” as the related forecasted interest payments occur. The termination payments are included in cash flows from financing activities on the consolidated statements of cash flows. Please see Note 2 for additional information. In conjunction with the early repayment of our $250.0 million 4.75% senior notes due February 1, 2022 in the fourth quarter of 2021, we reclassified a loss of $0.8 million from AOCI to “Interest expense, net.”
The remaining fair value amounts associated with unwound forward-starting interest rate swap agreements and included in “Accumulated other comprehensive loss” on the consolidated balance sheets are $34.4 million and $36.5 million as of December 31, 2017 total $352.2 million, which we will recognize2022 and 2021, respectively. These amounts are amortized ratably over the remaining life of the related debt instrument into “Interest expense, net” on the consolidated statements of income (loss).
Our forward-starting interest rate swaps had the following nine years. impact on earnings:
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2022 | | 2021 | | 2020 |
| | (Thousands of Dollars) |
| Change in unrealized loss on cash flow hedges | | $ | — | | | $ | — | | | $ | (30,291) | |
| Reclassification of loss on cash flow hedges to interest expense, net | | $ | 2,106 | | | $ | 5,664 | | | $ | 4,265 | |
As of December 31, 2017,2022, we expect to reclassify a loss of $2.6 million to “Interest expense, net” within the cost and accumulated depreciation of leased storage assets totaled $229.8 million and $104.9 million, respectively.next twelve months associated with unwound forward-starting interest rate swap agreements.
15. FAIR VALUE MEASUREMENTSFair Value Measurements
We segregate the inputs used in measuring fair value into three levels: Level 1, defined as observable inputs such as quoted prices for identical assets or liabilities in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable, such as quoted prices for similar assets or liabilities in active markets or quoted prices for identical assets or liabilities in markets that are not active; and Level 3, defined as unobservable inputs for which little or no market data exists. We consider counterparty credit risk and our own credit risk in the determination of all estimated fair values.
Recurring Fair Value Measurements
The following assets and liabilities are measured at fair value on a recurring basis:
|
| | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | Level 1 | | Level 2 | | Level 3 | | Total |
| | (Thousands of Dollars) |
| Assets: | | | | | | | |
| Other current assets: | | | | | | | |
| Product imbalances | $ | 3,890 |
| | $ | — |
| | $ | — |
| | $ | 3,890 |
|
| Liabilities: | | | | | | | |
| Accrued liabilities: | | | | | | | |
| Product imbalances | $ | (1,534 | ) | | $ | — |
| | $ | — |
| | $ | (1,534 | ) |
| Commodity derivatives | (878 | ) | | — |
| | — |
| | (878 | ) |
| Interest rate swaps | — |
| | (5,394 | ) | | — |
| | (5,394 | ) |
| Other long-term liabilities: | | | | | | | |
| Interest rate swaps | — |
| | (4,594 | ) | | — |
| | (4,594 | ) |
| Total | $ | (2,412 | ) | | $ | (9,988 | ) | | $ | — |
| | $ | (12,400 | ) |
|
| | | | | | | | | | | | | | | |
| | December 31, 2016 |
| | Level 1 | | Level 2 | | Level 3 | | Total |
| | (Thousands of Dollars) |
| Assets: | | | | | | | |
| Other current assets: | | | | | | | |
| Product imbalances | $ | 1,551 |
| | $ | — |
| | $ | — |
| | $ | 1,551 |
|
| Commodity derivatives | — |
| | 155 |
| | — |
| | 155 |
|
| Other long-term assets, net: | | | | | | | |
| Interest rate swaps | — |
| | 1,314 |
| | — |
| | 1,314 |
|
| Total | $ | 1,551 |
| | $ | 1,469 |
| | $ | — |
| | $ | 3,020 |
|
| Liabilities: | | | | | | | |
| Accrued liabilities: | | | | | | | |
| Product imbalances | $ | (1,577 | ) | | $ | — |
| | $ | — |
| | $ | (1,577 | ) |
| Commodity derivatives | (4,887 | ) | | (165 | ) | | — |
| | (5,052 | ) |
| Other long-term liabilities: | | | | | | | |
| Guarantee liability | — |
| | — |
| | (1,230 | ) | | (1,230 | ) |
| Interest rate swaps | — |
| | (2,632 | ) | | — |
| | (2,632 | ) |
| Total | $ | (6,464 | ) | | $ | (2,797 | ) | | $ | (1,230 | ) | | $ | (10,491 | ) |
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Product Imbalances.Since we value our assets and liabilities related to product imbalances using quoted market prices in active markets as of the reporting date, we include these product imbalances in Level 1 of the fair value hierarchy.
Commodity Derivatives. We base the fair value of certain of our commodity derivative instruments on quoted prices on an exchange; accordingly, we include these items in Level 1 of the fair value hierarchy. We also had derivative instruments for which we determined fair value using industry pricing services and other observable inputs, such as quoted prices on an exchange for similar derivative instruments, and we included these derivative instruments in Level 2 of the fair value hierarchy. See Note 16 for a discussion of our derivative instruments.
Interest Rate Swaps.Because we estimate the fair value of our forward-starting interest rate swaps using discounted cash flows, which use observable inputs such as time to maturity and market interest rates, we include these interest rate swaps in Level 2 of the fair value hierarchy.
Guarantees. We previously provided guarantees for commodity purchases, lease obligations and certain utilities for Axeon. As of December 31, 2016, we provided guarantees totaling $54.1 million, and one guarantee that did not specify a maximum amount. We estimated the fair value based on the guarantees outstanding and an estimate of the amount we would be obligated to pay under the guarantees at the time of default and considering the probability of default by Axeon. Our estimate of the fair value was based on significant inputs not observable in the market and thus fell within Level 3 of the fair value hierarchy. In conjunction with the termination of the Axeon Term Loan on February 22, 2017, our obligation to provide credit support to Axeon ceased. See Note 7 for additional information on the Axeon Term Loan.
Fair Value of Financial Instruments
We recognize cash equivalents, receivables, payables and debt in our consolidated balance sheets at their carrying amounts. The fair values of these financial instruments, except for long-term debt other than finance leases, approximate their carrying amounts. The estimated fair values and carrying amounts of the long-term debt, including the current portion, and the Axeon Term Loanexcluding finance leases, were as follows:
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| | (Thousands of Dollars) |
| Fair value | $ | 3,169,664 | | | $ | 3,459,153 | |
| Carrying amount | $ | 3,242,289 | | | $ | 3,130,625 | |
|
| | | | | | | | | | | |
| | December 31, 2017 | | December 31, 2016 |
| | Long-term Debt | | Long-term Debt | | Axeon Term Loan |
| | (Thousands of Dollars) |
| Fair value | $ | 3,677,622 |
| | $ | 3,084,762 |
| | $ | 110,000 |
|
| Carrying amount | $ | 3,613,059 |
| | $ | 3,014,364 |
| | $ | 110,000 |
|
We have estimated the fair value of our publicly traded senior notes based upon quoted prices in active markets; therefore, we determined that the fair value of our publicly traded senior notes falls in Level 1 of the fair value hierarchy. ForWith regard to our other debt, for which a quoted market price is not available, we have estimated the fair value using a discounted cash flow analysis using current incremental borrowing rates for similar types of borrowing arrangements and determined that the fair value falls in Level 2 of the fair value hierarchy. We determined that the fairThe carrying value includes unamortized debt issuance costs.
17. SERIES D CUMULATIVE CONVERTIBLE PREFERRED UNITS
Series D Preferred Units Issued and Outstanding
The following is a summary of the Axeon Term Loan approximated its carrying valueour Series D Preferred Units issued and outstanding as of December 31, 2016, which is included2022: | | | | | | | | | | | | | | |
| | Purchase / Repurchase Price per Unit | | Number of Units Issued (Repurchased) |
| June 29, 2018 (Initial Closing) | | $ | 25.38 | | | 15,760,441 | |
| July 13, 2018 (Second Closing) | | $ | 25.38 | | | 7,486,209 | |
| Total number of units issued | | | | 23,246,650 | |
| November 22, 2022 repurchase | | $ | 32.73 | | | (6,900,000) | |
| Units outstanding at December 31, 2022 | | | | 16,346,650 | |
On June 26, 2018, the Partnership entered into a purchase agreement (the Series D Preferred Unit Purchase Agreement) with investment funds, accounts and entities (collectively, the Purchasers) managed by EIG Management Company, LLC and FS/EIG Advisors, LLC to issue and sell Series D Preferred Units in “Other current assets” on the consolidated balance sheet. See Note 7a private placement.
On November 16, 2022, NuStar Energy L.P. entered into agreements with EIG Nova Equity Aggregator, L.P and FS Energy and Power Fund (the Purchase Agreements) to repurchase an aggregate 6,900,000 of our Series D Preferred Units at a price per unit of $32.73 for additional information on the Axeon Term Loan.
16. DERIVATIVES AND RISK MANAGEMENT ACTIVITIES
We utilize various derivative instruments to manage our exposure to interest rate risk and commodityan aggregate purchase price risk. Our risk management policies and procedures are designed to monitor interest rates, futures and swap positions and over-the-counter positions, as well as physical volumes, grades, locations and delivery schedules, to help ensure that our hedging activities address our market risks.
Interest Rate Risk
We are a party to certain interest rate swap agreements to manage our exposure to changes in interest rates, which include forward-starting interest rate swap agreementsof $225.8 million, including approximately $3.4 million related to forecasted debt issuancesaccrued distributions. These transactions closed on November 22, 2022 and were funded with borrowings under our Revolving Credit Agreement.
Upon entrance into the Purchase Agreements on November 16, 2022, we reclassified 6,900,000 mezzanine-equity-classified Series D Preferred Units with an aggregate carrying value of $188.0 million to liability-classified Series D Preferred Units valued at the repurchase price of $222.4 million, excluding accrued distributions. We recorded the $34.4 million difference between the carrying value of those Series D Preferred Units prior to reclassification and the repurchase price against our common equity as a deemed distribution and subtracted it from net income attributable to common units in 2018the calculation of basic and 2020. We entered into these swaps duringdiluted net income per common unit for the year ended December 31, 2015,2022, resulting in ordera $0.31 loss per common unit attributable to hedge the riskrepurchase. We accounted for the repurchase of changesthe liability-classified Series D Preferred Units on November 22, 2022 as an extinguishment of debt.
The Series D Preferred Units rank equal to other classes of preferred units and senior to common units in the interest payments attributablePartnership with respect to changesdistribution rights and rights upon liquidation. The Series D Preferred Units generally vote on an as-converted basis with the common units and have certain class voting rights with respect to a limited number of matters as set forth in the benchmark interest rate duringpartnership agreement. The Partnership is required to use its commercially reasonable efforts to register the period fromSeries D Preferred Units after the effective datesecond anniversary of the swapInitial Closing, no later than one year after receipt of a written request from holders holding a majority of the Series D Preferred Units to register the Series D Preferred Units. If the Partnership fails to cause such registration statement to become effective by the applicable date, the Partnership will be required to pay certain amounts to the issuance of the forecasted debt. Under the terms of the swaps,holders as liquidated damages. To date, we pay a fixed rate and receive a rate based on the three-month USD LIBOR. These swaps qualify as cash flow hedges, and we designate them as such. We record the effective portion of mark-to-market adjustments as a component of AOCI, and the amount in AOCI will be recognized in “Interest expense, net” as the forecasted interest payments occur or if the interest payments are probable not to occur. As of December 31, 2017 and 2016, the aggregate notional amount of forward-starting interest rate swaps totaled $600.0 million.
have received no such request.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Series D Preferred Units Distributions
The remaining fair value amount associated with unwound fixed-to-floating interest rate swap agreements totaled a $15.6 million and a $21.1 million gain as of December 31, 2017 and 2016, respectively, and is included in “Long-term debt”Distributions on the consolidated balance sheets. The remaining fair value amount associated with unwound forward-starting interest rate swap agreements totaled a $14.3 millionSeries D Preferred Units are payable out of any legally available funds, accrue and a $20.9 million loss as of December 31, 2017are cumulative from the issuance dates and 2016, respectively, and is included in AOCIare payable on the consolidated balance sheets. These amounts15th day (or next business day) of each of March, June, September and December, beginning September 17, 2018, to holders of record on the first business day of each payment month. The distribution rates on the Series D Preferred Units are amortized ratably overas follows: (i) 9.75% per annum ($0.619 per unit per distribution period) for the remaining lifefirst two years; (ii) 10.75% per annum ($0.682 per unit per distribution period) for years three through five; and (iii) the greater of 13.75% per annum ($0.872 per unit per distribution period) or the distribution per common unit thereafter. While the Series D Preferred Units are outstanding, the Partnership will be prohibited from paying distributions on any junior securities, including the common units, unless full cumulative distributions on the Series D Preferred Units (and any parity securities) have been, or contemporaneously are being, paid or set aside for payment through the most recent Series D Preferred Unit distribution payment date. Any Series D Preferred Unit distributions in excess of $0.635 per unit may be paid, in the Partnership’s sole discretion, in additional Series D Preferred Units, with the remainder paid in cash.
If we fail to pay in full any Series D Preferred Unit distribution amount, then, until we pay such distributions in full, the applicable distribution rate for each of those distribution periods shall be increased by $0.048 per Series D Preferred Unit. In addition, if we fail to pay in full any Series D Preferred Unit distribution amount for three consecutive distribution periods, then until we pay such distributions in full: (i) each holder of the related debt instrumentSeries D Preferred Units may elect to convert its Series D Preferred Units into “Interest expense, net”common units on a one-for-one basis, plus any unpaid Series D distributions, (ii) one person selected by the consolidated statementsholders holding a majority of income.
Commodity Price Risk
We are exposed to market risks related to the volatilityoutstanding Series D Preferred Units shall become an additional member of petroleum product prices. In order to reduce the risk of commodity price fluctuations with respect to our petroleum product inventories and related firm commitments to purchase and/or sell such inventories, we utilize commodity futures and swap contracts, which qualify and we designate as fair value hedges. Derivatives that are intended to hedge our commodity price risk, but fail to qualify as fair value or cash flow hedges, are considered economic hedges, and we record associated gains and losses in net income. Our risk management committee oversees our trading controls and procedures and certain aspects of commodity and trading risk management. Our risk management committee also reviews all new commodity and trading risk management strategies in accordance with our risk management policy, as approved by our board of directors. We ceased marketing crude oildirectors and (iii) we will not be permitted to incur any indebtedness (as defined in the second quarterRevolving Credit Agreement) or engage in any acquisitions or asset sales in excess of 2017 and exited our heavy fuels trading operations$50.0 million without the consent of the holders holding a majority of the outstanding Series D Preferred Units. In addition, we will permanently lose the ability to pay any part of the distributions on the Series D Preferred Units in the thirdform of additional Series D Preferred Units.
In January 2023, our board of directors declared a distribution of $0.682 per Series D Preferred Unit to be paid on March 15, 2023.
Distribution information on our Series D Preferred Units is as follows:
| | | | | | | | | | | | | | |
| Distribution Period | | Distribution Rate per Unit | | Total Distribution |
| | | | (Thousands of Dollars) |
| December 15, 2022 - March 14, 2023 | | $ | 0.682 | | | $ | 11,148 | |
| September 15, 2022 - December 14, 2022 | | $ | 0.682 | | | $ | 14,337 | |
| June 15, 2022 - September 14, 2022 | | $ | 0.682 | | | $ | 15,854 | |
| March 15, 2022 - June 14, 2022 | | $ | 0.682 | | | $ | 15,854 | |
| December 15, 2021 - March 14, 2022 | | $ | 0.682 | | | $ | 15,854 | |
Series D Preferred Units Conversion and Redemption Features
On or after June 29, 2020, each holder of Series D Preferred Units may convert all or any portion of its Series D Preferred Units into common units on a one-for-one basis (plus any unpaid Series D distributions), subject to anti-dilution adjustments, at any time, but not more than once per quarter, so long as any conversion is for at least $50.0 million based on the Purchase Price per Unit (or such lesser amount representing all of 2017, thereby reducing our overall hedging activity.a holder’s Series D Preferred Units).
The volumePartnership may redeem all or any portion of commodity contracts is basedthe Series D Preferred Units, in an amount not less than $50.0 million for cash at a redemption price equal to, as applicable: (i) $31.73 per Series D Preferred Unit at any time on open derivative positions and representsor after June 29, 2023 but prior to June 29, 2024; (ii) $30.46 per Series D Preferred Unit at any time on or after June 29, 2024 but prior to June 29, 2025; (iii) $29.19 per Series D Preferred Unit at any time on or after June 29, 2025; plus, in each case, the combined volumesum of our long and short open positionsany unpaid distributions on an absolute basis, which totaled 1.2 million barrels and 4.7 million barrels asthe applicable Series D Preferred Unit plus the distributions prorated for the number of December 31, 2017 and 2016, respectively. We had $0.3 million and $1.8 million of margin deposits as of December 31, 2017 and December 31, 2016, respectively.
The fair values of our derivative instruments included in our consolidated balance sheets were as follows: |
| | | | | | | | | | | | | | | | | |
| | | | Asset Derivatives | | Liability Derivatives |
| | Balance Sheet Location | | December 31, |
| | | 2017 | | 2016 | | 2017 | | 2016 |
| | | | (Thousands of Dollars) |
Derivatives Designated as Hedging Instruments: | | | | | | | | | |
| Interest rate swaps | Other long-term assets, net | | $ | — |
| | $ | 1,314 |
| | $ | — |
| | $ | — |
|
| Commodity contracts | Accrued liabilities | | — |
| | 144 |
| | (112 | ) | | (3,566 | ) |
| Interest rate swaps | Accrued liabilities | | — |
| | — |
| | (5,394 | ) | | — |
|
| Interest rate swaps | Other long-term liabilities | | — |
| | — |
| | (4,594 | ) | | (2,632 | ) |
| Total | | | — |
| | 1,458 |
| | (10,100 | ) | | (6,198 | ) |
| | | | | | | | | | |
Derivatives Not Designated as Hedging Instruments: | | | | | | | | | |
| Commodity contracts | Other current assets | | — |
| | 265 |
| | — |
| | (110 | ) |
| Commodity contracts | Accrued liabilities | | 742 |
| | 9,128 |
| | (1,508 | ) | | (10,758 | ) |
| Total | | | 742 |
| | 9,393 |
| | (1,508 | ) | | (10,868 | ) |
| | | | | | | | | | |
| Total Derivatives | | | $ | 742 |
| | $ | 10,851 |
| | $ | (11,608 | ) | | $ | (17,066 | ) |
Certain of our derivative instruments are eligible for offsetdays elapsed (not to exceed 90) in the consolidated balance sheets and subjectperiod of redemption (Series D Partial Period Distributions). The holders have the option to master netting arrangements. Under our master netting arrangements, there is a legally enforceableconvert the units prior to such redemption as discussed above.
Additionally, at any time on or after June 29, 2028, each holder of Series D Preferred Units will have the right to offset amounts, and we intendrequire the Partnership to settleredeem all of the Series D Preferred Units held by such amounts onholder at a net basis. The following areredemption price equal to $29.19 per Series D Preferred Unit plus any unpaid Series D distributions plus the net amounts presented onSeries D Partial Period Distributions. If a holder of Series D Preferred Units exercises its redemption right, the consolidated balance sheets:Partnership may elect to pay up to 50% of such amount in common units (which shall be valued at 93% of a volume-weighted average trading price of the common units); provided, that the common units to be issued do not, in the aggregate, exceed 15% of NuStar Energy’s common equity market capitalization at the time.
|
| | | | | | | | |
| | | December 31, |
| Commodity Contracts | | 2017 | | 2016 |
| | | (Thousands of Dollars) |
| Net amounts of assets presented in the consolidated balance sheets | | $ | — |
| | $ | 155 |
|
| Net amounts of liabilities presented in the consolidated balance sheets | | $ | (878 | ) | | $ | (5,052 | ) |
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Series D Preferred Units Change of Control
We recognize the impactUpon certain events involving a change of our commodity contracts on earnings in “Cost of product sales” on the consolidated income statements, and that impact was as follows:
|
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (Thousands of Dollars) |
| Derivatives Designated as Fair Value Hedging Instruments: | | | | | | |
| Gain (loss) recognized in income on derivative | | $ | 806 |
| | $ | (11,254 | ) | | $ | 21,589 |
|
| (Loss) gain recognized in income on hedged item | | (656 | ) | | 15,295 |
| | (18,047 | ) |
| Gain recognized in income for ineffective portion | | $ | 150 |
| | $ | 4,041 |
| | $ | 3,542 |
|
| | | | | | | |
| Derivatives Not Designated as Hedging Instruments: | | | | | | |
| (Loss) gain recognized in income on derivative | | $ | (668 | ) | | $ | 225 |
| | $ | 2,208 |
|
Our interest rate swaps had the following impact on earnings:
|
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (Thousands of Dollars) |
| Derivatives Designated as Cash Flow Hedging Instruments: | | | | | | |
(Loss) gain recognized in other comprehensive (loss) income on derivative (effective portion) | | $ | (8,670 | ) | | $ | (2,621 | ) | | $ | 1,303 |
|
Loss reclassified from AOCI into interest expense, net (effective portion) | | (6,624 | ) | | (8,331 | ) | | (9,802 | ) |
As of December 31, 2017, we expect to reclassify a loss of $5.1 million to “Interest expense, net” within the next twelve months associated with unwound forward-starting interest rate swaps.
17. RELATED PARTY TRANSACTIONS
Please refer to Note 28 for a discussioncontrol, each holder of the merger ofSeries D Preferred Units may elect to: (i) convert its Series D Preferred Units into common units on a subsidiary of ours with and into NuStar GP Holdings, pursuant to which we will become the sole member of NuStar GP Holdings.
GP Services Agreement. Prior to the Employee Transfer discussed in Note 1, our operations were managed by NuStar GP, LLC under a services agreement effective January 1, 2008 pursuant to which employees of NuStar GP, LLC performed services for our U.S. operations. Employees of NuStar GP, LLC provided services to us and NuStar GP Holdings; therefore, we reimbursed NuStar GP, LLC for all employee costs incurred prior to the Employee Transfer, other than the expenses allocated to NuStar GP Holdings. The following table summarizes information pertaining to our related party transactions prior to the Employee Transfer:
|
| | | | | | | |
| | Year Ended December 31, |
| | 2016 | | 2015 |
| | (Thousands of Dollars) |
| Operating expenses | $ | 21,681 |
| | $ | 135,565 |
|
| General and administrative expenses | $ | 10,493 |
| | $ | 66,769 |
|
| Expenses included in discontinued operations, net of tax | $ | — |
| | $ | 2 |
|
In conjunction with the Employee Transfer, we entered into an Amended and Restated Services Agreement with NuStar GP, LLC, effective March 1, 2016 (the Amended GP Services Agreement). The Amended GP Services Agreement provides that we will furnish administrative services necessary to conduct the business of NuStar GP Holdings. NuStar GP Holdings will compensate us for these services through an annual fee of $1.0 million, subject to adjustment based on the annual merit increase percentage applicable to our employees for the most recently completed fiscal year and for changes in level of service. The Amended GP Services Agreement will terminate on March 1, 2020 and will automatically renew for successive two-year terms, unless terminated by either party.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Assignment and Assumption Agreement. Also on March 1, 2016 and in connection with the Employee Transfer, we entered into an Assignment and Assumption Agreement with NuStar GP, LLC (the Assignment Agreement). Under the Assignment Agreement, NuStar GP, LLC assigned all of its employee benefit plans, programs, contracts, policies, and various of its other agreements and contracts with certain employees, affiliates and third-party service providers (collectively, the Assigned Programs) to NuStar Services Co. In addition, NuStar Services Co agreed to assume the sponsorship of and all obligations relating to the ongoing maintenance and administration of each of the plans and agreements in the Assigned Programs. Certain of our officers are also officers of NuStar GP Holdings and are considered dual employees of ours and NuStar GP Holdings.
The following table summarizes the related party transactions and changes to amounts reported on our consolidated balance sheet as a result of the Employee Transfer on March 1, 2016 (thousands of dollars):
|
| | | |
| Decrease in related party payable: | |
| Current | $ | 16,014 |
|
| Long-term | 32,656 |
|
| Decrease in related party payable | $ | 48,670 |
|
| | |
| Changes to our consolidated balance sheet: | |
| Current and long-term assets | $ | 2,154 |
|
| Current liabilities | 5,609 |
|
| Other long-term liabilities | 34,042 |
|
| Limited partners’ equity | 2,664 |
|
| Accumulated other comprehensive loss | 4,201 |
|
| Changes to our consolidated balance sheet | $ | 48,670 |
|
Non-Compete Agreement. On July 19, 2006, we entered into a non-compete agreement with NuStar GP Holdings, Riverwalk Logistics, L.P. and NuStar GP, LLC (the Non-Compete Agreement). The Non-Compete Agreement became effective on December 22, 2006 when NuStar GP Holdings ceased to be subject to the Amended and Restated Omnibus Agreement, dated March 31, 2006. Under the Non-Compete Agreement, we will have a right of first refusal with respect to the potential acquisition of assets that relate to the transportation, storage or terminalling of crude oil, feedstocks or refined petroleum products (including petrochemicals) in the United States and internationally. NuStar GP Holdings will have a right of first refusal with respect to the potential acquisition of general partner and other equity interests in publicly traded partnerships under common ownership with the general partner interest. With respect toone-for-one basis, plus any other business opportunities, neitherunpaid Series D distributions; (ii) require the Partnership nor NuStar GP Holdings are prohibited from engaging into redeem its Series D Preferred Units for an amount equal to $29.82 per Series D Preferred Unit plus any business, evenunpaid Series D distributions; (iii) if the Partnership is the surviving entity and NuStar GP Holdings would haveits common units continue to be listed, continue to hold its Series D Preferred Units; or (iv) if the Partnership will not be the surviving entity, or it will be the surviving entity but its common units will cease to be listed, require the Partnership to use its commercially reasonable efforts to deliver a conflict of interest with respectsecurity in the surviving entity that has substantially similar terms as the Series D Preferred Units; however, if the Partnership is unable to such other business opportunity.deliver a mirror security, each holder is still entitled to option (i) or (ii) above.
Series D Preferred Units Accounting Treatment 18. OTHER (EXPENSE) INCOME
Other (expense) income consistedThe Series D Preferred Units include redemption provisions at the option of the following:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (Thousands of Dollars) |
| (Loss) gain from sale or disposition of assets | $ | (4,984 | ) | | $ | (64 | ) | | $ | 1,617 |
|
| Impairment loss on Axeon Term Loan | — |
| | (58,655 | ) | | — |
|
| Gain associated with Linden Acquisition | — |
| | — |
| | 56,277 |
|
| Foreign exchange (losses) gains | (344 | ) | | (660 | ) | | 3,891 |
|
| Other, net | 34 |
| | 596 |
| | 37 |
|
| Other (expense) income, net | $ | (5,294 | ) | | $ | (58,783 | ) | | $ | 61,822 |
|
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
19. PARTNERS’ EQUITY
Please refer to Note 28 for a discussion of the merger of a subsidiary of ours with and into NuStar GP Holdings, pursuant to which we will become the sole member of NuStar GP Holdings.
Amendment of Partnership Agreement
In the second quarter of 2017, our general partner amended and restated our partnership agreement in connection with the issuanceholders of the Series BD Preferred Units as described below and upon a Series D Change of Control (as defined in the Navigator Acquisition to waive up to an aggregate $22.0 millionpartnership agreement), which are outside the Partnership’s control. Therefore, the Series D Preferred Units are presented in the mezzanine section of the quarterly incentive distributions to our general partner for any NS common units issued from the date of the Acquisition Agreement (other than those attributable to NS common units issued under any equity compensation plan) for ten consecutive quarters, starting with the distributions for the second quarter of 2017.consolidated balance sheets. The partnership agreement was amended and restated again in connection with the issuance of our Series CD Preferred Units described below.
Issuance of Common Units
On April 18, 2017, we issued 14,375,000 common units representing limited partner interestshave been recorded at a price of $46.35 per unit. We used thetheir issuance date fair value, net proceeds from this offering of $657.5 million, including a contribution of $13.6 million from our general partner to maintain its 2% general partner interest, to fund a portion of the purchase price for the Navigator Acquisition.
During the year ended December 31, 2016, we issued 595,050 common units representing limited partner interests at an average price of $47.39 per unit for proceeds of $28.3 million, net of $0.5 million of issuance costs. We used these proceeds,reassess the presentation of the Series D Preferred Units in our consolidated balance sheets on a quarterly basis.
The Series D Preferred Units are subject to accretion from their carrying value at the issuance date to the redemption value, which includeis based on the redemption right of the Series D Preferred Unit holders that may be exercised at any time on or after June 29, 2028, using the effective interest method over a contributionperiod of $0.6 millionten years. In the calculation of net income per unit, the accretion is treated in the same manner as a distribution and deducted from our general partnernet income to maintain its 2% general partner interest, for general partnership purposes, including repayments of outstanding borrowings under the Revolving Credit Agreement.arrive at net income attributable to common units.
For the years ended December 31, 2017
18. PARTNERS' EQUITY
Series A, B and 2016, we issued 185,455 and 135,100 common units, respectively, representing limited partner interests in connection with the vestings of awards issued under our long-term incentive plan.
C Preferred Units
The following is a summary ofInformation on our fixed-to-floating rate cumulative redeemable perpetual preferred units8.50% Series A, 7.625% Series B and 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (collectively the Series A, B and C Preferred Units) issued and outstanding as of December 31, 2017:2022 is shown below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Units | | Original
Issuance Date | | Units Issued and Outstanding | | Price per Unit | | | | Fixed Distribution Rate per Unit per Annum | | Fixed Distribution per Annum | | Optional Redemption Date/Date When Distribution Rate Became Floating | | Floating Annual Rate (as a Percentage of the $25.00 Liquidation Preference per Unit) |
| | | | | | | | | | | | (Thousands of Dollars) | | | | |
| Series A Preferred Units | | November 25, 2016 | | 9,060,000 | | | $ | 25.00 | | | | | $ | 2.125 | | | $ | 19,252 | | | December 15, 2021 | | Three-month LIBOR plus 6.766% |
| Series B Preferred Units | | April 28, 2017 | | 15,400,000 | | | $ | 25.00 | | | | | $ | 1.90625 | | | $ | 29,357 | | | June 15, 2022 | | Three-month LIBOR plus 5.643% |
| Series C Preferred Units | | November 30, 2017 | | 6,900,000 | | | $ | 25.00 | | | | | $ | 2.25 | | | $ | 15,525 | | | December 15, 2022 | | Three-month LIBOR plus 6.88% |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Units | | Original Issuance Date | | Number of Units Issued and Outstanding | | Price per Unit | | Net Proceeds (in millions) | | Fixed Distribution Rate per Annum (as a Percentage of the $25.00 Liquidation Preference per Unit) | | Fixed Distribution Rate per Unit per Annum | | Optional Redemption Date/Date at Which Distribution Rate Becomes Floating | | Floating Annual Rate (as a Percentage of the $25.00 Liquidation Preference per Unit) |
Series A Preferred Units | | November 25, 2016 | | 9,060,000 | | $ | 25.00 |
| | $ | 218.4 |
| | 8.50 | % | | $ | 2.125 |
| | December 15, 2021 | | Three-month LIBOR plus 6.766% |
Series B Preferred Units | | April 28, 2017 | | 15,400,000 | | $ | 25.00 |
| | $ | 371.8 |
| | 7.625 | % | | $ | 1.90625 |
| | June 15, 2022 | | Three-month LIBOR plus 5.643% |
Series C Preferred Units | | November 30, 2017 | | 6,900,000 | | $ | 25.00 |
| | $ | 166.7 |
| | 9.00 | % | | $ | 2.25 |
| | December 15, 2022 | | Three-month LIBOR plus 6.88% |
Distributions on the Series A, Series B and Series C Preferred Units (collectively, the Preferred Units) are payable out of any legally available funds, accrue and are cumulative from the original issuance dates, and are payable on the 15th day (or the next business day) of each of March, June, September and December of each year to holders of record on the first business day of each payment month. The Series A, B and C Preferred Units rank equal to each other and to the Series D Preferred Units, and senior to all of our other classes of equity securities with respect to distribution rights and rights upon liquidation.
In January 2023, our board of directors declared quarterly distributions with respect to the Series A, B and C Preferred Units to be paid on March 15, 2023.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Distribution information on our Series A, B and C Preferred Units is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Series A Preferred Units | | Series B Preferred Units | | Series C Preferred Units |
| Distribution Period | | Distribution Rate per Unit | | Total Distribution | | Distribution Rate per Unit | | Total Distribution | | Distribution Rate per Unit | | Total Distribution |
| | | | (Thousands of Dollars) | | | | (Thousands of Dollars) | | | | (Thousands of Dollars) |
| December 15, 2022 - March 14, 2023 | | $ | 0.71889 | | | $ | 6,513 | | | $ | 0.64871 | | | $ | 9,990 | | | $ | 0.72602 | | | $ | 5,010 | |
| September 15, 2022 - December 14, 2022 | | $ | 0.64059 | | | $ | 5,804 | | | $ | 0.57040 | | | $ | 8,784 | | | $ | 0.56250 | | | $ | 3,881 | |
| June 15, 2022 - September 14, 2022 | | $ | 0.54808 | | | $ | 4,966 | | | $ | 0.47789 | | | $ | 7,360 | | | $ | 0.56250 | | | $ | 3,881 | |
| March 15, 2022 - June 14, 2022 | | $ | 0.47817 | | | $ | 4,332 | | | $ | 0.47657 | | | $ | 7,339 | | | $ | 0.56250 | | | $ | 3,881 | |
| December 15, 2021 - March 14, 2022 | | $ | 0.43606 | | | $ | 3,951 | | | $ | 0.47657 | | | $ | 7,339 | | | $ | 0.56250 | | | $ | 3,881 | |
We may redeem any of our outstanding Series A, B and C Preferred Units at any time on or after the optional redemption date set forth above for each series of the Series A, B and C Preferred Units, in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions to, but not including, the date of redemption, whether or not declared. We may also redeem the Series A, B and C Preferred Units upon the occurrence of certain rating events or a change of control as defined in our partnership agreement. In the case of the latter instance, if we choose not to redeem the Series A, B and C Preferred Units, thethose preferred unitholders may have the ability to convert their Series A, B and C Preferred Units to common units at the then applicablethen-applicable conversion rate.rate, which are subject to caps of 1.0915, 1.04297 and 1.7928, respectively. Holders of the Series A, B and C Preferred Units have no voting rights except for certain exceptions set forth in our partnership agreement.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Common Units
The following table summarizes financial information related toshows the balance of and changes in the number of our preferred units:common units outstanding:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| Balance as of the beginning of year | 109,986,273 | | | 109,468,127 | | | 108,527,806 | |
| | | | | |
| Unit-based compensation (Note 22) | 832,445 | | | 518,146 | | | 940,321 | |
| Balance as of the end of year | 110,818,718 | | | 109,986,273 | | | 109,468,127 | |
|
| | | | | | | | | | | | | | | |
| | Preferred Limited Partners | | |
| | Series A | | Series B | | Series C | | Total |
| Balance as of January 1, 2016 | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Issuance of units | 218,400 |
| | — |
| | — |
| | 218,400 |
|
| Net income | 1,925 |
| | — |
| | — |
| | 1,925 |
|
| Distributions to partners | (1,925 | ) | | — |
| | — |
| | (1,925 | ) |
| Balance as of December 31, 2016 | 218,400 |
| | — |
| | — |
| | 218,400 |
|
| Issuance of units | — |
| | 371,823 |
| | 166,737 |
| | 538,560 |
|
| Net income | 19,253 |
| | 19,815 |
| | 1,380 |
| | 40,448 |
|
| Distributions to partners | (19,253 | ) | | (19,815 | ) | | (1,380 | ) | | (40,448 | ) |
| Other | (93 | ) | | (189 | ) | | (75 | ) | | (357 | ) |
| Balance as of December 31, 2017 | $ | 218,307 |
| | $ | 371,634 |
| | $ | 166,662 |
| | $ | 756,603 |
|
Net Income Applicable to the General Partner
The following table details the calculation of net income applicable to the general partner:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (Thousands of Dollars) |
| Net income attributable to NuStar Energy L.P. | $ | 147,964 |
| | $ | 150,003 |
| | $ | 306,720 |
|
| Less preferred limited partner interest | 40,448 |
| | 1,925 |
| | — |
|
| Less general partner incentive distribution | 45,669 |
| | 43,407 |
| | 43,220 |
|
Net income after general partner incentive distribution and preferred limited partner interest | 61,847 |
| | 104,671 |
| | 263,500 |
|
| General partner interest allocation | 2 | % | | 2 | % | | 2 | % |
| General partner interest allocation of net income | 1,237 |
| | 2,091 |
| | 5,270 |
|
| General partner incentive distribution | 45,669 |
| | 43,407 |
| | 43,220 |
|
| Net income applicable to general partner | $ | 46,906 |
| | $ | 45,498 |
| | $ | 48,490 |
|
Cash Distributions
General Partner and Common Limited Partners.Distributions. We make quarterly distributions to common unitholders and the general partner of 100% of our available cash,“Available Cash,” generally defined as cash receipts less cash disbursements, (includingincluding distributions to the Preferred Units)our preferred units, and cash reserves established by the general partner, in its sole discretion. These quarterly distributions are declared and paid within 45 days subsequent to each quarter-end. The common unitholders receive a distribution each quarter as determined by the board of directors, subject to limitation by the distributions in arrears, if any, on our preferred units.
The following table summarizes information about cash distributions to our common limited partners applicable to the Preferred Units. Our available cash is distributed based onperiod in which the percentages shown below:distributions were earned:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Cash Distributions Per Unit | | Total Cash Distributions | | Record Date | | Payment Date |
| | | | (Thousands of Dollars) | | | | |
| Quarter ended: | | | | | | | | |
| December 31, 2022 | | $ | 0.40 | | | $ | 44,328 | | | February 8, 2023 | | February 14, 2023 |
| September 30, 2022 | | 0.40 | | | 44,125 | | | November 7, 2022 | | November 14, 2022 |
| June 30, 2022 | | 0.40 | | | 44,128 | | | August 8, 2022 | | August 12, 2022 |
| March 31, 2022 | | 0.40 | | | 44,165 | | | May 9, 2022 | | May 13, 2022 |
| Year ended December 31, 2022 | | $ | 1.60 | | | $ | 176,746 | | | | | |
| | | | | | | | |
| Year ended December 31, 2021 | | $ | 1.60 | | | $ | 175,470 | | | | | |
| Year ended December 31, 2020 | | $ | 1.60 | | | $ | 174,873 | | | | | |
|
| | | | |
| | | Percentage of Distribution |
| Quarterly Distribution Amount per Common Unit | | Common Unitholders | | General Partner Including Incentive Distributions |
| Up to $0.60 | | 98% | | 2% |
| Above $0.60 up to $0.66 | | 90% | | 10% |
| Above $0.66 | | 75% | | 25% |
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table reflects the allocation of total cash distributions to the general partner and common limited partners applicable to the period in which the distributions were earned:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (Thousands of Dollars, Except Per Unit Data) |
| General partner interest | $ | 9,252 |
| | $ | 7,877 |
| | $ | 7,844 |
|
| General partner incentive distribution | 45,669 |
| | 43,407 |
| | 43,220 |
|
| Total general partner distribution | 54,921 |
| | 51,284 |
| | 51,064 |
|
| Common limited partners’ distribution | 407,681 |
| | 342,598 |
| | 341,140 |
|
| Total cash distributions | $ | 462,602 |
| | $ | 393,882 |
| | $ | 392,204 |
|
| | | | | | |
| Cash distributions per unit applicable to common limited partners | $ | 4.38 |
| | $ | 4.38 |
| | $ | 4.38 |
|
The following table summarizes information related to our quarterly cash distributions to our general partner and common limited partners:
|
| | | | | | | | | | | | |
| Quarter Ended | | Cash Distributions Per Unit | | Total Cash Distributions | | Record Date | | Payment Date |
| | | | | (Thousands of Dollars) | | | | |
| December 31, 2017 (a) | | $ | 1.095 |
| | $ | 115,267 |
| | February 8, 2018 | | February 13, 2018 |
| September 30, 2017 | | $ | 1.095 |
| | $ | 115,084 |
| | November 9, 2017 | | November 14, 2017 |
| June 30, 2017 | | $ | 1.095 |
| | $ | 115,083 |
| | August 7, 2017 | | August 11, 2017 |
| March 31, 2017 | | $ | 1.095 |
| | $ | 117,168 |
| | May 8, 2017 | | May 12, 2017 |
| |
(a) | The distribution was announced on January 29, 2018. |
Preferred Units. The following table summarizes information related to our quarterly cash distributions on our Preferred Units: |
| | | | | | | | | | | | |
| Period | | Cash Distributions Per Unit | | Total Cash Distributions | | Record Date | | Payment Date |
| | | | | (Thousands of Dollars) | | | | |
| Series A Preferred Units: | | | | | | | | |
| December 15, 2017 - March 14, 2018 (a) | | $ | 0.53125 |
| | $ | 4,813 |
| | March 1, 2018 | | March 15, 2018 |
| September 15, 2017 - December 14, 2017 | | $ | 0.53125 |
| | $ | 4,813 |
| | December 1, 2017 | | December 15, 2017 |
| June 15, 2017 - September 14, 2017 | | $ | 0.53125 |
| | $ | 4,813 |
| | September 1, 2017 | | September 15, 2017 |
| March 15, 2017 - June 14, 2017 | | $ | 0.53125 |
| | $ | 4,813 |
| | June 1, 2017 | | June 15, 2017 |
| November 25, 2016 - March 14, 2017 | | $ | 0.64930556 |
| | $ | 5,883 |
| | March 1, 2017 | | March 15, 2017 |
| | | | | | | | | |
| Series B Preferred Units: | | | | | | | | |
| December 15, 2017 - March 14, 2018 (a) | | $ | 0.47657 |
| | $ | 7,339 |
| | March 1, 2018 | | March 15, 2018 |
| September 15, 2017 - December 14, 2017 | | $ | 0.47657 |
| | $ | 7,339 |
| | December 1, 2017 | | December 15, 2017 |
| April 28, 2017 - September 14, 2017 | | $ | 0.725434028 |
| | $ | 11,172 |
| | September 1, 2017 | | September 15, 2017 |
| | | | | | | | | |
| Series C Preferred Units: | | | | | | | | |
| November 30, 2017 - March 14, 2018 (a) | | $ | 0.65625 |
| | $ | 4,528 |
| | March 1, 2018 | | March 15, 2018 |
| |
(a) | The distribution was announced on January 29, 2018. |
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Accumulated Other Comprehensive Income (Loss)
The balance of and changes in the components included in “Accumulated other comprehensive income (loss)”AOCI were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Foreign
Currency
Translation | | Cash Flow Hedges | | Pension and
Other
Postretirement
Benefits | | Total |
| (Thousands of Dollars) |
| Balance as of January 1, 2020 | $ | (43,772) | | | $ | (16,124) | | | $ | (8,000) | | | $ | (67,896) | |
| Other comprehensive income (loss) before reclassification adjustments | 1,410 | | | (30,291) | | | (2,924) | | | (31,805) | |
| Net gain on pension costs reclassified into other income, net | — | | | — | | | (1,220) | | | (1,220) | |
| Net loss on cash flow hedges reclassified into interest expense, net | — | | | 4,265 | | | — | | | 4,265 | |
| | | | | | | |
| Other comprehensive income (loss) | 1,410 | | | (26,026) | | | (4,144) | | | (28,760) | |
| Balance as of December 31, 2020 | (42,362) | | | (42,150) | | | (12,144) | | | (96,656) | |
| Other comprehensive income before reclassification adjustments | 601 | | | — | | | 17,721 | | | 18,322 | |
| Net gain on pension costs reclassified into other income, net | — | | | — | | | (1,308) | | | (1,308) | |
| Net loss on cash flow hedges reclassified into interest expense, net | — | | | 5,664 | | | — | | | 5,664 | |
| | | | | | | |
| Other comprehensive income | 601 | | | 5,664 | | | 16,413 | | | 22,678 | |
| Balance as of December 31, 2021 | (41,761) | | | (36,486) | | | 4,269 | | | (73,978) | |
| Other comprehensive income (loss) before reclassification adjustments | 2,177 | | | — | | | (516) | | | 1,661 | |
| Sale of Point Tupper Terminal Operations reclassified into net income (Note 4) | 39,646 | | | — | | | — | | | 39,646 | |
| Net gain on pension costs reclassified into other income, net | — | | | — | | | (1,040) | | | (1,040) | |
| Net loss on cash flow hedges reclassified into interest expense, net | — | | | 2,106 | | | — | | | 2,106 | |
| | | | | | | |
| Other comprehensive income (loss) | 41,823 | | | 2,106 | | | (1,556) | | | 42,373 | |
| Balance as of December 31, 2022 | $ | 62 | | | $ | (34,380) | | | $ | 2,713 | | | $ | (31,605) | |
19. NET INCOME (LOSS) PER COMMON UNIT
|
| | | | | | | | | | | | | | | |
| | Foreign Currency Translation | | Cash Flow Hedges | | Pension and Other Postretirement Benefits | | Total |
| | (Thousands of Dollars) |
| Balance as of January 1, 2015 | $ | (28,839 | ) | | $ | (39,073 | ) | | $ | — |
| | $ | (67,912 | ) |
Other comprehensive (loss) income before reclassification adjustments | (31,987 | ) | | 1,303 |
| | — |
| | (30,684 | ) |
Net loss on cash flow hedges reclassified into interest expense, net | — |
| | 9,802 |
| | — |
| | 9,802 |
|
| Other comprehensive (loss) income | (31,987 | ) | | 11,105 |
| | — |
| | (20,882 | ) |
| Balance as of December 31, 2015 | (60,826 | ) | | (27,968 | ) | | — |
| | (88,794 | ) |
| Employee Transfer | — |
| | — |
| | 4,201 |
| | 4,201 |
|
| Deferred income tax adjustments | — |
| | — |
| | 2,414 |
| | 2,414 |
|
Other comprehensive loss before reclassification adjustments | (8,243 | ) | | (2,621 | ) | | (7,852 | ) | | (18,716 | ) |
Net gain on pension costs reclassified into operating expense | — |
| | — |
| | (1,200 | ) | | (1,200 | ) |
Net gain on pension costs reclassified into general and administrative expense | — |
| | — |
| | (413 | ) | | (413 | ) |
Net loss on cash flow hedges reclassified into interest expense, net | — |
| | 8,331 |
| | — |
| | 8,331 |
|
| Other comprehensive (loss) income | (8,243 | ) | | 5,710 |
| | (2,850 | ) | | (5,383 | ) |
| Balance as of December 31, 2016 | (69,069 | ) | | (22,258 | ) | | (2,850 | ) | | (94,177 | ) |
Other comprehensive income (loss) before reclassification adjustments | 17,466 |
| | (8,670 | ) | | (4,641 | ) | | 4,155 |
|
Net gain on pension costs reclassified into operating
expense | — |
| | — |
| | (1,143 | ) | | (1,143 | ) |
Net gain on pension costs reclassified into general and
administrative expense | — |
| | — |
| | (386 | ) | | (386 | ) |
Net loss on cash flow hedges reclassified into interest expense, net | — |
| | 6,624 |
| | — |
| | 6,624 |
|
| Other comprehensive income (loss) | 17,466 |
| | (2,046 | ) | | (6,170 | ) | | 9,250 |
|
| Balance as of December 31, 2017 | $ | (51,603 | ) | | $ | (24,304 | ) | | $ | (9,020 | ) | | $ | (84,927 | ) |
As discussed in Note 17, the Series D Preferred Units contain certain unitholder conversion and redemption features, and we use the if-converted method to calculate the dilutive effect of the conversion or redemption feature that is most advantageous to our Series D preferred unitholders. The effect of the assumed conversion or redemption of the Series D Preferred Units outstanding was antidilutive for each of the years ended December 31, 2022, 2021 and 2020; therefore, we did not include such conversion or redemption in the computation of diluted net income (loss) per common unit.
Contingently issuable performance units are included as dilutive potential common units if it is probable that the performance measures will be achieved, unless to do so would be antidilutive. For the year ended December 31, 2022, there were no performance unit awards outstanding. For the years ended December 31, 2021 and 2020, we determined that it was probable that the performance measures would be achieved, but the effect would be antidilutive; therefore, we did not include any contingently issuable performance units as dilutive common units in the computation below.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
20. NET INCOME PER COMMON UNIT
The following table details the calculation of basic and diluted net income (loss) per common unit:
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2022 | | 2021 | | 2020 |
| | (Thousands of Dollars, Except Unit and Per Unit Data) |
| Net income (loss) | $ | 222,747 | | | $ | 38,225 | | | $ | (198,983) | |
| Distributions to preferred limited partners | (127,589) | | | (127,399) | | | (124,882) | |
| Distributions to common limited partners | (176,746) | | | (175,470) | | | (174,873) | |
| Distribution equivalent rights to restricted units | (2,534) | | | (2,396) | | | (2,093) | |
| Distributions in excess of income (loss) | $ | (84,122) | | | $ | (267,040) | | | $ | (500,831) | |
| | | | | |
| Distributions to common limited partners | $ | 176,746 | | | $ | 175,470 | | | $ | 174,873 | |
| Allocation of distributions in excess of income (loss) | (84,122) | | | (267,040) | | | (500,831) | |
| Series D Preferred Unit accretion (Note 17) | (18,538) | | | (16,903) | | | (17,626) | |
| Series D Preferred Unit repurchase (Note 17) | (34,382) | | | — | | | — | |
| Net income (loss) attributable to common units | $ | 39,704 | | | $ | (108,473) | | | $ | (343,584) | |
| | | | | |
| Basic and diluted weighted-average common units outstanding | 110,341,206 | | | 109,585,635 | | | 109,155,117 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Basic and diluted net income (loss) per common unit | $ | 0.36 | | | $ | (0.99) | | | $ | (3.15) | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (Thousands of Dollars, Except Per Unit Data) |
| Net income attributable to NuStar Energy L.P. | $ | 147,964 |
| | $ | 150,003 |
| | $ | 306,720 |
|
Less: Distributions to general partner (including incentive distribution rights) | 54,921 |
| | 51,284 |
| | 51,064 |
|
| Less: Distributions to common limited partners | 407,681 |
| | 342,598 |
| | 341,140 |
|
| Less: Distributions to preferred limited partners | 40,448 |
| | 1,925 |
| | — |
|
| Less: Distribution equivalent rights to restricted units | 2,965 |
| | 2,697 |
| | — |
|
| Distributions in excess of earnings | $ | (358,051 | ) | | $ | (248,501 | ) | | $ | (85,484 | ) |
| | | | | | |
| Net income attributable to common units: | | | | | |
| Distributions to common limited partners | $ | 407,681 |
| | $ | 342,598 |
| | $ | 341,140 |
|
| Allocation of distributions in excess of earnings | (350,890 | ) | | (243,530 | ) | | (83,774 | ) |
| Total | $ | 56,791 |
| | $ | 99,068 |
| | $ | 257,366 |
|
| | | | | | |
| Basic weighted-average common units outstanding | 88,825,964 |
| | 78,080,484 |
| | 77,886,078 |
|
| | | | | | |
| Diluted common units outstanding: | | | | | |
| Basic weighted-average common units outstanding | 88,825,964 |
| | 78,080,484 |
| | 77,886,078 |
|
| Effect of dilutive potential common units | — |
| | 32,518 |
| | — |
|
| Diluted weighted-average common units outstanding | 88,825,964 |
| | 78,113,002 |
| | 77,886,078 |
|
| | | | | | |
| Basic and diluted net income per common unit | $ | 0.64 |
| | $ | 1.27 |
| | $ | 3.30 |
|
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
21. STATEMENTS OF20. SUPPLEMENTAL CASH FLOWSFLOW INFORMATION
Changes in current assets and current liabilities were as follows:
| | | | Year Ended December 31, | | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | | 2022 | | 2021 | | 2020 |
| | (Thousands of Dollars) | | (Thousands of Dollars) |
| Decrease (increase) in current assets: | | | | | | Decrease (increase) in current assets: | |
| Accounts receivable | $ | (865 | ) | | $ | (23,234 | ) | | $ | 67,257 |
| Accounts receivable | $ | (6,762) | | | $ | (2,105) | | | $ | 14,589 | |
| Receivable from related parties | 112 |
| | (317 | ) | | — |
| |
| | Inventories | 11,936 |
| | 940 |
| | 16,776 |
| Inventories | 836 | | | (5,585) | | | 1,340 | |
| Other current assets | 3,393 |
| | 8,128 |
| | 4,414 |
| |
| | Prepaid and other current assets | | Prepaid and other current assets | 768 | | | (1,710) | | | (3,326) | |
| Increase (decrease) in current liabilities: | | | | | | Increase (decrease) in current liabilities: | |
| Accounts payable | (30,409 | ) | | 14,071 |
| | (32,152 | ) | Accounts payable | (2,960) | | | 10,202 | | | (25,455) | |
| Payable to related party, net | — |
| | 894 |
| | (872 | ) | |
| | Accrued interest payable | 6,489 |
| | (256 | ) | | 941 |
| Accrued interest payable | 3,468 | | | (16,708) | | | 12,922 | |
| Accrued liabilities | (11,157 | ) | | 161 |
| | (7,834 | ) | Accrued liabilities | 9,018 | | | 4,448 | | | 7,886 | |
| Taxes other than income tax | (3,529 | ) | | 2,690 |
| | (1,522 | ) | Taxes other than income tax | (3,631) | | | (2,689) | | | 3,972 | |
| Income tax payable | (2,463 | ) | | 639 |
| | 3,551 |
| |
| | Changes in current assets and current liabilities | $ | (26,493 | ) | | $ | 3,716 |
| | $ | 50,559 |
| Changes in current assets and current liabilities | $ | 737 | | | $ | (14,147) | | | $ | 11,928 | |
The above changes in current assets and current liabilities differ from changes between amounts reflected in the applicable consolidated balance sheets due to:
current assets and current liabilities acquired and disposed of during the period;
•the change in the amount accrued for capital expenditures;
•the effect of foreign currency translation;
reclassification•payments for the termination of interest rate swaps included in cash flows from financing activities;
•the Axeon Term Loan to other effect of accrued compensation expense paid with fully vested common unit awards; and
•current assets from other long-term assets, net;and current liabilities disposed of during the period.
changes in the fair values of our interest rate swap agreements;
reclassification of our 7.65% senior notes due April 15, 2018 from long-term debt to current portion of long-term debt; and
non-cash related party transactions associated with the Employee Transfer (see Note 17 for further information).
Cash flows related to interest and income taxes were as follows:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (Thousands of Dollars) |
| Cash paid for interest, net of amount capitalized | $ | 158,089 |
| | $ | 142,663 |
| | $ | 133,388 |
|
| Cash paid for income taxes, net of tax refunds received | $ | 11,338 |
| | $ | 11,847 |
| | $ | 9,971 |
|
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Cash flows related to interest and income taxes were as follows: | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2022 | | 2021 | | 2020 |
| | (Thousands of Dollars) |
| Cash paid for interest, net of amount capitalized | $ | 195,697 | | | $ | 218,181 | | | $ | 204,511 | |
| Cash paid for income taxes, net of tax refunds received | $ | 4,368 | | | $ | 5,491 | | | $ | 3,260 | |
22.
Restricted cash is included in "Other long-term assets, net" on the consolidated balance sheets. “Cash, cash equivalents and restricted cash” on the consolidated statements of cash flows was included in the consolidated balance sheets as follows:
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| (Thousands of Dollars) |
| Cash and cash equivalents | $ | 14,489 | | | $ | 5,637 | |
| Other long-term assets, net | 8,888 | | | 8,802 | |
| Cash, cash equivalents and restricted cash | $ | 23,377 | | | $ | 14,439 | |
21. EMPLOYEE BENEFIT PLANS
Employee Transfer
On March 1, 2016, and in conjunction with the Employee Transfer, we assumed $22.5 million and $10.2 million in benefit obligations associated with the pension plans and other postretirement benefit plans, respectively. Prior to the Employee Transfer, we reimbursed all costs incurred by NuStar GP, LLC related to these employee benefit plans at cost. For comparability purposes this footnote presents information related to these benefit plans on a combined basis for periods prior to the Employee Transfer and after the Employee Transfer, including changes in the benefit obligation and fair value of plan assets, components of net periodic benefit cost (income), and adjustments to other comprehensive income (loss). Consequently, certain amounts presented below will differ from amounts reflected in our consolidated financial statements. See Note 17 for additional discussion on the Employee Transfer.
Thrift Plans
The NuStar Thrift Plan (the Thrift Plan) is a qualified defined contribution plan that became effective June 26, 2006. Participation in the Thrift Plan is voluntary and open to substantially all our domestic employees upon their dates of hire. Thrift Plan participants can contribute from 1% up to 30% of their total annual compensation to the Thrift Plan in the form of pre-tax and/or after tax employee contributions. We make matching contributions in an amount equal to 100% of each participant’s employee contributions up to a maximum of 6% of the participant’s total annual compensation. The matching contributions to the Thrift Plan for the years ended December 31, 2017, 20162022, 2021 and 20152020 totaled $6.9$7.3 million, $6.6$7.6 million and $6.3$7.8 million, respectively.
The NuStar Excess Thrift Plan (the Excess Thrift Plan) is a nonqualified deferred compensation plan that became effective July 1, 2006. The Excess Thrift Plan provides benefits to those employees whose compensation and/or annual contributions under the Thrift Plan are subject to the limitations applicable to qualified retirement plans under the Code.
We also maintain several other defined contribution plans for certain international employees located in Canada, the Netherlands and the United Kingdom. For the years ended December 31, 2017, 2016 and 2015, our costs for these plans totaled $2.5 million, $2.4 million and $2.6 million, respectively.
Pension and Other Postretirement Benefits
The NuStar Pension Plan (the Pension Plan) is a qualified non-contributory defined benefit pension plan that provides eligible U.S. employees with retirement income as calculated under a cash balance formula. Under the cash balance formula, benefits are determined based on age, years of vesting service and interest credits, and employees become fully vested in their benefits upon attaining three years of vesting service. Prior to January 1, 2014, eligible employees were covered under either a cash balance formula or a final average pay formula (FAP). Effective January 1, 2014, theThe Pension Plan was amended to freeze the FAP benefits as of December 31, 2013, and going forward, alleffective January 1, 2014, eligible employees are covered under the cash balance formula discussed above.
We also maintain an excess pension plan (the Excess Pension Plan), which is a nonqualified deferred compensation plan that provides benefits to a select group of management or other highly compensated employees. Neither the Excess Thrift Plan nor the Excess Pension Plan is intended to constitute either a qualified plan under the provisions of Section 401 of the Code or a funded plan subject to the Employee Retirement Income Security Act.
The Pension Plan and Excess Pension Plan are collectively referred to as the Pension Plans in the tables and discussion below. Our other postretirement benefit plans include a contributory medical benefits plan for U.S. employees thatwho retired prior to April 1, 2014 and, for employees thatwho retire on or after April 1, 2014, a partial reimbursement for eligible third-party health care premiums. We use December 31 as the measurement date for our pension and other postretirement plans.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The changes in the benefit obligation, the changes in fair value of plan assets, the funded status and the amounts recognized in the consolidated balance sheets for our Pension Plans and other postretirement benefit plans as of and for the years ended December 31, 20172022 and 20162021 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Plans | | Other Postretirement
Benefit Plans |
| | 2022 | | 2021 | | 2022 | | 2021 |
| (Thousands of Dollars) |
| Change in benefit obligation: | | | | | | | |
| Benefit obligation, January 1 | $ | 179,907 | | | $ | 186,685 | | | $ | 16,270 | | | $ | 14,680 | |
| Service cost | 9,752 | | | 9,978 | | | 605 | | | 593 | |
| Interest cost | 4,619 | | | 4,084 | | | 423 | | | 326 | |
| Benefits paid (a) | (15,949) | | | (19,366) | | | (603) | | | (257) | |
| Participant contributions | — | | | — | | | 66 | | | 44 | |
| Actuarial (gain) loss | (34,221) | | | (694) | | | (4,778) | | | 884 | |
| Other | 203 | | | (780) | | | — | | | — | |
| Benefit obligation, December 31 | $ | 144,311 | | | $ | 179,907 | | | $ | 11,983 | | | $ | 16,270 | |
| Change in plan assets: | | | | | | | |
| Plan assets at fair value, January 1 | $ | 189,838 | | | $ | 182,727 | | | $ | — | | | $ | — | |
| Actual return on plan assets | (30,405) | | | 26,425 | | | — | | | — | |
| Employer contributions | 5,012 | | | 52 | | | 537 | | | 213 | |
| Benefits paid (a) | (15,949) | | | (19,366) | | | (603) | | | (257) | |
| Participant contributions | — | | | — | | | 66 | | | 44 | |
| Plan assets at fair value, December 31 | $ | 148,496 | | | $ | 189,838 | | | $ | — | | | $ | — | |
| Reconciliation of funded status: | | | | | | | |
| Fair value of plan assets at December 31 | $ | 148,496 | | | $ | 189,838 | | | $ | — | | | $ | — | |
| Less: Benefit obligation at December 31 | 144,311 | | | 179,907 | | | 11,983 | | | 16,270 | |
| Funded status at December 31 | $ | 4,185 | | | $ | 9,931 | | | $ | (11,983) | | | $ | (16,270) | |
| Amounts recognized in the consolidated balance sheets (b): | | | | | | | |
| Other long-term assets, net | $ | 9,130 | | | $ | 14,945 | | | $ | — | | | $ | — | |
| Accrued liabilities | (552) | | | (467) | | | (507) | | | (442) | |
| Other long-term liabilities | (4,393) | | | (4,547) | | | (11,476) | | | (15,828) | |
| Net pension asset (liability) | $ | 4,185 | | | $ | 9,931 | | | $ | (11,983) | | | $ | (16,270) | |
| | | | | | | |
| Accumulated benefit obligation | $ | 141,517 | | | $ | 171,899 | | | $ | 11,983 | | | $ | 16,270 | |
|
| | | | | | | | | | | | | | | |
| | Pension Plans | | Other Postretirement Benefit Plans |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (Thousands of Dollars) |
| Change in benefit obligation: | | | | | | | |
| Benefit obligation, January 1 | $ | 127,402 |
| | $ | 109,202 |
| | $ | 11,061 |
| | $ | 10,042 |
|
| Service cost | 8,955 |
| | 7,703 |
| | 456 |
| | 419 |
|
| Interest cost | 4,507 |
| | 4,023 |
| | 430 |
| | 401 |
|
| Benefits paid | (5,941 | ) | | (2,554 | ) | | (342 | ) | | (422 | ) |
| Participant contributions | — |
| | — |
| | 215 |
| | 253 |
|
| Actuarial loss | 14,894 |
| | 9,028 |
| | 590 |
| | 368 |
|
| Benefit obligation, December 31 | $ | 149,817 |
| | $ | 127,402 |
| | $ | 12,410 |
| | $ | 11,061 |
|
| Change in plan assets: | | | | | | | |
| Plan assets at fair value, January 1 | $ | 107,644 |
| | $ | 87,706 |
| | $ | — |
| | $ | — |
|
| Actual return on plan assets | 17,070 |
| | 6,891 |
| | — |
| | — |
|
| Employer contributions | 11,105 |
| | 15,601 |
| | 127 |
| | 169 |
|
| Benefits paid | (5,941 | ) | | (2,554 | ) | | (342 | ) | | (422 | ) |
| Participant contributions | — |
| | — |
| | 215 |
| | 253 |
|
| Plan assets at fair value, December 31 | $ | 129,878 |
| | $ | 107,644 |
| | $ | — |
| | $ | — |
|
| Reconciliation of funded status: | | | | | | | |
| Fair value of plan assets at December 31 | $ | 129,878 |
| | $ | 107,644 |
| | $ | — |
| | $ | — |
|
| Less: Benefit obligation at December 31 | 149,817 |
| | 127,402 |
| | 12,410 |
| | 11,061 |
|
| Funded status at December 31 | $ | (19,939 | ) | | $ | (19,758 | ) | | $ | (12,410 | ) | | $ | (11,061 | ) |
| Amounts recognized in the consolidated balance sheets (a): | | | | | | | |
| Accrued liabilities | $ | (210 | ) | | $ | (162 | ) | | $ | (376 | ) | | $ | (321 | ) |
| Other long-term liabilities | (19,729 | ) | | (19,596 | ) | | (12,034 | ) | | (10,740 | ) |
| Net pension liability | $ | (19,939 | ) | | $ | (19,758 | ) | | $ | (12,410 | ) | | $ | (11,061 | ) |
| |
(a) | For the Pension Plan, since assets exceed the present value of expected benefit payments for the next 12 months, all of the liability(b)For the Pension Plan, since assets exceed the present value of expected benefit payments for the next 12 months, all of the asset is noncurrent. For the Excess Pension Plan and the other postretirement benefit plans, since there are no assets, the current liability is the present value of expected benefit payments for the next 12 months; the remainder is noncurrent. |
The accumulated benefit obligation is the present value of benefits earnedexpected benefit payments for the next 12 months; the remainder is noncurrent.
The actuarial (gain) loss related to date, assuming no future salary increases. The aggregate accumulatedthe benefit obligation for our Pension Plans as of December 31, 2017 and 2016pension plans was $146.3 million and $125.0 million, respectively. As of December 31, 2017 and 2016,primarily attributable to an increase in the aggregate accumulateddiscount rates used to determine the benefit obligation forfrom 3.10% to 5.26% in 2022 and an increase from 2.84% to 3.10% in 2021. The fair value of our plan assets is affected by the Pension Plans exceededreturn on plan assets.
assets resulting primarily from the performance of equity and bond markets during the period.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The Excess Pension Plan has no plan assets and an accumulated benefit obligation of $4.6 million and $4.3 million as of December 31, 2022 and 2021, respectively. The accumulated benefit obligation is the present value of benefits earned to date, while the projected benefit obligation may include future salary increase assumptions. The projected benefit obligation for the Excess Pension Plan was $4.9 million and $5.0 million as of December 31, 2022 and 2021, respectively.
The components of net periodic benefit cost (income) related to our Pension Plans and other postretirement benefit plans were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Plans | | Other Postretirement Benefit Plans |
| Year Ended December 31, | | Year Ended December 31, |
| | 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 |
| | (Thousands of Dollars) |
| Service cost | $ | 9,752 | | | $ | 9,978 | | | $ | 9,174 | | | $ | 605 | | | $ | 593 | | | $ | 529 | |
| Interest cost | 4,619 | | | 4,084 | | | 4,693 | | | 423 | | | 326 | | | 399 | |
| Expected return on plan assets | (9,087) | | | (9,233) | | | (8,972) | | | — | | | — | | | — | |
| Amortization of prior service credit | (1,876) | | | (2,057) | | | (2,057) | | | (1,145) | | | (1,145) | | | (1,145) | |
| Amortization of net actuarial loss | 1,129 | | | 2,279 | | | 1,845 | | | 209 | | | 176 | | | 137 | |
| Other | 846 | | | (561) | | | 136 | | | — | | | — | | | — | |
| Net periodic benefit cost (income) | $ | 5,383 | | | $ | 4,490 | | | $ | 4,819 | | | $ | 92 | | | $ | (50) | | | $ | (80) | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Plans | | Other Postretirement Benefit Plans |
| | Year Ended December 31, | | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
| | (Thousands of Dollars) |
| Service cost | $ | 8,955 |
| | $ | 7,703 |
| | $ | 7,676 |
| | $ | 456 |
| | $ | 419 |
| | $ | 470 |
|
| Interest cost | 4,507 |
| | 4,023 |
| | 4,389 |
| | 430 |
| | 401 |
| | 448 |
|
| Expected return on plan assets | (6,411 | ) | | (5,407 | ) | | (5,018 | ) | | — |
| | — |
| | — |
|
| Amortization of prior service credit | (2,059 | ) | | (2,063 | ) | | (2,063 | ) | | (1,145 | ) | | (1,145 | ) | | (1,145 | ) |
| Amortization of net actuarial loss | 1,484 |
| | 1,091 |
| | 1,845 |
| | 191 |
| | 181 |
| | 269 |
|
| Net periodic benefit cost (income) | $ | 6,476 |
| | $ | 5,347 |
| | $ | 6,829 |
| | $ | (68 | ) | | $ | (144 | ) | | $ | 42 |
|
We amortize prior service costs and credits on a straight-line basis over the average remaining service period of employees expected to receive benefits under our Pension Plans and other postretirement benefit plans (“Amortization of prior service credit” in table above). We amortize the actuarial gains and losses that exceed 10 percent10% of the greater of the projected benefit obligation or market-related value of plan assets (smoothed asset value) over the average remaining service period of active employees expected to receive benefits under our Pension Plans and other postretirement benefit plans (“Amortization of net actuarial loss” in table above).
The service cost component of net periodic benefit cost (income) is reported in “General and administrative expenses” and “Operating expenses” on the consolidated statements of income (loss), and the remaining components of net periodic benefit cost (income) are reported in “Other income (expense), net”
Adjustments to other comprehensive (loss) income related to our Pension Plans and other postretirement benefit plans were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Plans | | Other Postretirement Benefit Plans |
| | Year Ended December 31, | | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
| | (Thousands of Dollars) |
| Net unrecognized (loss) gain arising during the year: | | | | | | | | | | | |
| Net actuarial (loss) gain | $ | (4,235 | ) | | $ | (7,544 | ) | | $ | 1,000 |
| | $ | (590 | ) | | $ | (368 | ) | | $ | 1,056 |
|
| Net (gain) loss reclassified into income: | | | | | | | | | | | |
| Amortization of prior service credit | (2,059 | ) | | (2,063 | ) | | (2,063 | ) | | (1,145 | ) | | (1,145 | ) | | (1,145 | ) |
| Amortization of net actuarial loss | 1,484 |
| | 1,091 |
| | 1,845 |
| | 191 |
| | 181 |
| | 269 |
|
| Net gain reclassified into income | (575 | ) | | (972 | ) | | (218 | ) | | (954 | ) | | (964 | ) | | (876 | ) |
| | | | | | | | | | | | |
| Income tax benefit (expense) | 162 |
| | 57 |
| | (362 | ) | | 22 |
| | 3 |
| | (382 | ) |
Total changes to other comprehensive (loss) income | $ | (4,648 | ) | | $ | (8,459 | ) | | $ | 420 |
| | $ | (1,522 | ) | | $ | (1,329 | ) | | $ | (202 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Plans | | Other Postretirement Benefit Plans |
| Year Ended December 31, | | Year Ended December 31, |
| | 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 |
| | (Thousands of Dollars) |
| Net unrecognized (loss) gain arising during the year: | | | | | | | | | | | |
| Net actuarial (loss) gain | $ | (5,271) | | | $ | 18,666 | | | $ | (2,159) | | | $ | 4,779 | | | $ | (884) | | | $ | (793) | |
| | | | | | | | | | | |
| Net (gain) loss reclassified into income: | | | | | | | | | | | |
| Amortization of prior service credit | (1,876) | | | (2,057) | | | (2,057) | | | (1,145) | | | (1,145) | | | (1,145) | |
| Amortization of net actuarial loss | 1,129 | | | 2,279 | | | 1,845 | | | 209 | | | 176 | | | 137 | |
| Other | 643 | | | (561) | | | — | | | — | | | — | | | — | |
| Net gain reclassified into income | (104) | | | (339) | | | (212) | | | (936) | | | (969) | | | (1,008) | |
| | | | | | | | | | | |
| Income tax (expense) benefit | (24) | | | (61) | | | 28 | | | — | | | — | | | — | |
| Total changes to other comprehensive (loss) income | $ | (5,399) | | | $ | 18,266 | | | $ | (2,343) | | | $ | 3,843 | | | $ | (1,853) | | | $ | (1,801) | |
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The amounts recorded as a component of “Accumulated other comprehensive loss” on the consolidated balance sheets related to our Pension Plans and other postretirement benefit plans were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Plans | | Other Postretirement
Benefit Plans |
| December 31, | | December 31, |
| | 2022 | | 2021 | | 2022 | | 2021 |
| | (Thousands of Dollars) |
| Unrecognized actuarial (loss) gain | $ | (7,247) | | | $ | (3,748) | | | $ | 434 | | | $ | (4,554) | |
| Prior service credit | 5,754 | | | 7,630 | | | 3,739 | | | 4,884 | |
| Deferred tax | 33 | | | 57 | | | — | | | — | |
Accumulated other comprehensive (loss) income, net of tax | $ | (1,460) | | | $ | 3,939 | | | $ | 4,173 | | | $ | 330 | |
|
| | | | | | | | | | | | | | | |
| | Pension Plans | | Other Postretirement Benefit Plans |
| | December 31, | | December 31, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (Thousands of Dollars) |
| Unrecognized actuarial loss | $ | (31,178 | ) | | $ | (28,427 | ) | | $ | (4,154 | ) | | $ | (3,755 | ) |
| Prior service credit | 16,604 |
| | 18,663 |
| | 9,464 |
| | 10,609 |
|
| Deferred tax asset | 219 |
| | 57 |
| | 25 |
| | 3 |
|
Accumulated other comprehensive (loss) income, net of tax | $ | (14,355 | ) | | $ | (9,707 | ) | | $ | 5,335 |
| | $ | 6,857 |
|
The following pre-tax amounts in accumulated other comprehensive loss as of December 31, 2017 are expected to be recognized as components of net periodic benefit cost (income) in 2018:
|
| | | | | | | |
| | Pension Plans | | Other Postretirement Benefit Plans |
| | (Thousands of Dollars) |
| Actuarial loss | $ | 2,174 |
| | $ | 214 |
|
| Prior service credit | $ | (2,057 | ) | | $ | (1,145 | ) |
Investment Policies and Strategies
The investment policies and strategies for the assets of our qualified Pension Plan incorporate a well-diversified approach that is expected to earn long-term returns from capital appreciation and a growing stream of current income. This approach recognizes that assets are exposed to risk, and the market value of the Pension Plan’s assets may fluctuate from year to year. Risk tolerance is determined based on our financial ability to withstand risk within the investment program and the willingness to accept return volatility. In line with the investment return objective and risk parameters, the Pension Plan’s mix of assets includes a diversified portfolio of equity and fixed-income instruments. The aggregate asset allocation is reviewed on an annual basis. As of December 31, 2017,2022, the target allocations for plan assets arewere 65% equity securities and 35% fixed income investments, with certain fluctuations permitted.
The overall expected long-term rate of return on plan assets for the Pension Plan is estimated using various models of asset returns. Model assumptions are derived using historical data with the assumption that capital markets are informationally efficient. Three models are used to derive the long-term expected returns for each asset class. Since each method has distinct advantages and disadvantages and differing results, an equal weighted average of the methods’ results is used.
Fair Value of Plan Assets
We disclose the fair value for each major class of plan assets in the Pension Plan intoin three levels: Level 1, defined as observable inputs such as quoted prices for identical assets or liabilities in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable, such as quoted prices for similar assets or liabilities in active markets or quoted prices for identical assets or liabilities in markets that are not active; and Level 3, defined as unobservable inputs for which little or no market data exists.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The major classes of plan assets measured at fair value for the Pension Plan were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2022 |
| | Level 1 | | Level 2 | | Level 3 | | Total |
| | (Thousands of Dollars) |
| Cash equivalent securities | $ | 789 | | | $ | — | | | $ | — | | | $ | 789 | |
| Equity securities: | | | | | | | |
| U.S. large cap equity fund (a) | — | | | 81,754 | | | — | | | 81,754 | |
| International stock index fund (b) | 14,836 | | | — | | | — | | | 14,836 | |
| Fixed income securities: | | | | | | | |
| Bond market index fund (c) | 51,117 | | | — | | | — | | | 51,117 | |
| Total | $ | 66,742 | | | $ | 81,754 | | | $ | — | | | $ | 148,496 | |
|
| | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | Level 1 | | Level 2 | | Level 3 | | Total |
| | (Thousands of Dollars) |
| Cash equivalent securities | $ | 381 |
| | $ | — |
| | $ | — |
| | $ | 381 |
|
| Equity securities: | | | | | | | |
| U.S. large cap equity fund (a) | — |
| | 75,353 |
| | — |
| | 75,353 |
|
| International stock index fund (b) | 14,480 |
| | — |
| | — |
| | 14,480 |
|
| Fixed income securities: | | | | | | | |
| Bond market index fund (c) | 39,664 |
| | — |
| | — |
| | 39,664 |
|
| Total | $ | 54,525 |
| | $ | 75,353 |
| | $ | — |
| | $ | 129,878 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2021 |
| | Level 1 | | Level 2 | | Level 3 | | Total |
| (Thousands of Dollars) |
| Cash equivalent securities | $ | 710 | | | $ | — | | | $ | — | | | $ | 710 | |
| Equity securities: | | | | | | | |
| U.S. large cap equity fund (a) | — | | | 110,672 | | | — | | | 110,672 | |
| International stock index fund (b) | 17,708 | | | — | | | — | | | 17,708 | |
| Fixed income securities: | | | | | | | |
| Bond market index fund (c) | 60,748 | | | — | | | — | | | 60,748 | |
| Total | $ | 79,166 | | | $ | 110,672 | | | $ | — | | | $ | 189,838 | |
(a)This fund is a low-cost equity index fund not actively managed that tracks the S&P 500. Fair values were estimated using pricing models, quoted prices of securities with similar characteristics or discounted cash flows. |
| | | | | | | | | | | | | | | |
| | December 31, 2016 |
| | Level 1 | | Level 2 | | Level 3 | | Total |
| | (Thousands of Dollars) |
| Cash equivalent securities | $ | 738 |
| | $ | — |
| | $ | — |
| | $ | 738 |
|
| Equity securities: | | | | | | | |
| U.S. large cap equity fund (a) | — |
| | 64,813 |
| | — |
| | 64,813 |
|
| International stock index fund (b) | 10,459 |
| | — |
| | — |
| | 10,459 |
|
| Fixed income securities: | | | | | | | |
| Bond market index fund (c) | 31,634 |
| | — |
| | — |
| | 31,634 |
|
| Total | $ | 42,831 |
| | $ | 64,813 |
| | $ | — |
| | $ | 107,644 |
|
| |
(a) | This fund is a low-cost equity index fund not actively managed that tracks the S&P 500. Fair values were estimated using pricing models, quoted prices of securities with similar characteristics or discounted cash flows. |
| |
(b) | This fund tracks the performance of the Total International Composite Index. |
| |
(c) | This fund tracks the performance of the Barclays Capital U.S. Aggregate Bond Index. |
(c)This fund tracks the performance of the Barclays Capital U.S. Aggregate Bond Index.
Contributions to the Pension Plans
For the year ended December 31, 2017,2022, we contributed $11.1$5.0 million and $0.1$0.5 million to our Pension Plan and other postretirement benefit plans, respectively. During 2023, we expect to contribute approximately $9.6 million and $0.5 million to the Pension Plans and other postretirement benefit plans, respectively. During 2018, we expectWe will monitor our funding status in 2023 to contribute approximately $11.2 million and $0.4 million to the Pension Plans and other postretirement benefit plans, respectively, which principally representsdetermine if any contributions eitherare required by regulations or laws, or with respect to unfunded plans, necessary to fund current benefits.
Estimated Future Benefit Payments
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid for the years ending December 31:
| | | | | | | | | | | |
| Pension Plans | | Other Postretirement Benefit Plans |
| | (Thousands of Dollars) |
| 2023 | $ | 11,134 | | | $ | 507 | |
| 2024 | $ | 10,228 | | | $ | 536 | |
| 2025 | $ | 11,689 | | | $ | 582 | |
| 2026 | $ | 11,775 | | | $ | 633 | |
| 2027 | $ | 11,707 | | | $ | 680 | |
| 2028-2032 | $ | 67,371 | | | $ | 4,102 | |
|
| | | | | | | |
| | Pension Plans | | Other Postretirement Benefit Plans |
| | (Thousands of Dollars) |
| 2018 | $ | 8,823 |
| | $ | 376 |
|
| 2019 | $ | 9,699 |
| | $ | 416 |
|
| 2020 | $ | 10,432 |
| | $ | 434 |
|
| 2021 | $ | 11,050 |
| | $ | 464 |
|
| 2022 | $ | 11,650 |
| | $ | 497 |
|
| Years 2023-2027 | $ | 64,799 |
| | $ | 3,090 |
|
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Assumptions
The discount rate is based on a hypothetical yield curve represented by a series of annualized individual discount rates. Each bond issue underlying the hypothetical yield curve required an average rating of double-A, when averaging all available ratings by Moody’s Investor Service Inc., S&P Global Ratings and Fitch Ratings. The expected long-term rate of return on plan assets is based on the weighted averages of the expected long-term rates of return for each asset class of investments held in our plans as determined using historical data and the assumption that capital markets are informationally efficient. The expected rate of compensation increase represents average long-term salary increases.
The weighted-average assumptions used to determine the benefit obligations were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Plans | | Other Postretirement Benefit Plans |
| December 31, | | December 31, |
| | 2022 | | 2021 | | 2022 | | 2021 |
| Discount rate | 5.26 | % | | 3.10 | % | | 5.25 | % | | 3.08 | % |
| Rate of compensation increase | 3.99 | % | | 3.99 | % | | n/a | | n/a |
| Cash balance interest crediting rate | 3.76 | % | | 2.00 | % | | n/a | | n/a |
|
| | | | | | | | | | | |
| | Pension Plans | | Other Postretirement Benefit Plans |
| | December 31, | | December 31, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| Discount rate | 3.72 | % | | 4.33 | % | | 3.82 | % | | 4.49 | % |
| Rate of compensation increase | 3.51 | % | | 3.51 | % | | n/a |
| | n/a |
|
The weighted-average assumptions used to determine the net periodic benefit cost (income) were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Plans | | Other Postretirement Benefit Plans |
| Year Ended December 31, | | Year Ended December 31, |
| | 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 |
| Discount rate | 3.10 | % | | 2.84 | % | | 3.34 | % | | 3.08 | % | | 2.83 | % | | 3.43 | % |
Expected long-term rate of return on plan assets | 6.00 | % | | 6.00 | % | | 6.50 | % | | n/a | | n/a | | n/a |
| Rate of compensation increase | 3.99 | % | | 3.51 | % | | 3.51 | % | | n/a | | n/a | | n/a |
| Cash balance interest crediting rate | 2.00 | % | | 2.00 | % | | 2.00 | % | | n/a | | n/a | | n/a |
|
| | | | | | | | | | | | | | | | | |
| | Pension Plans | | Other Postretirement Benefit Plans |
| | Year Ended December 31, | | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
| Discount rate | 4.33 | % | | 4.61 | % | | 4.22 | % | | 4.49 | % | | 4.75 | % | | 4.34 | % |
Expected long-term rate of return on plan assets | 6.00 | % | | 6.25 | % | | 6.50 | % | | n/a |
| | n/a |
| | n/a |
|
| Rate of compensation increase | 3.51 | % | | 3.51 | % | | 3.51 | % | | n/a |
| | n/a |
| | n/a |
|
The assumed health care cost trend rates were as follows:
|
| | | | | |
| | December 31, |
| | 2017 | | 2016 |
| Health care cost trend rate assumed for next year | 6.84 | % | | 6.84 | % |
| Rate to which the cost trend rate was assumed to decrease (the ultimate trend rate) | 5.00 | % | | 5.00 | % |
| Year that the rate reaches the ultimate trend rate | 2028 |
| | 2028 |
|
Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. We sponsor a contributory postretirement health care plan for employees thatwho retired prior to April 1, 2014. The plan has an annual limitation (a cap) on the increase of the employer’s share of the cost of covered benefits. The cap on the increase in employer’s cost is 2.5% per year. The assumed increase in total health care cost exceeds the 2.5% indexed cap, so increasing or decreasing the health care cost trend rate by 1% does not materially change our obligation or expense for the postretirement health care plan.rates were as follows:
| | | | | | | | | | | |
| | December 31, |
| | 2022 | | 2021 |
| Health care cost trend rate assumed for next year | 7.00 | % | | 6.84 | % |
| Rate to which the cost trend rate was assumed to decrease (the ultimate trend rate) | 5.00 | % | | 5.00 | % |
| Year that the rate reaches the ultimate trend rate | 2032 | | 2028 |
23.
22. UNIT-BASED COMPENSATION
Please refer to Note 28 for a discussion of the merger of a subsidiary of ours with and into NuStar GP Holdings, pursuant to which we will become the sole member of NuStar GP Holdings.
Overview
On January 28, 2016,2019 LTIP. In April 2019, our common unitholders approved the Fifth Amended and Restated 20002019 Long-Term Incentive Plan (the 2000(2019 LTIP) which, among other items, provides that we may use newly issued common units fromfor eligible employees, consultants and directors of NuStar Energy to satisfy unit awardsL.P., and extends the term of the 2000 LTIP to January 28, 2026. Prior to the Employee Transfer, NuStar GP, LLC sponsored the 2000 LTIP, and we reimbursed NuStar GP, LLC for awards under this plan. Following the approval of the 2000 LTIP and the Employee Transfer in 2016, most of our currently outstanding awards are now classified as equity awards as we intend to settle these awards through the issuance of our common units.
Effective March 1, 2016, we assumed sponsorship of the 2000 LTIP, which provides the Compensation Committee of the Board of Directors of NuStar GP, LLC, (the Compensation Committee) withand their respective affiliates who perform services for us and our subsidiaries. The 2019 LTIP allows for the right to issue and award up to 3,250,000awarding of our common units to employees and non-employee directors (NEDs). Awards available under the 2000 LTIP include(i) options; (ii) restricted units, performance units, unit options, unit awards andunits; (iii) distribution equivalent rights (DERs). The Compensation Committee may also include a tandem grant of a DER that will; (iv) performance cash; (v) performance units; and (vi) unit awards. DERs entitle the participant to receive cash equal to cash distributions made on any award prior to its vesting. The 2019 LTIP, as amended and restated on April 29, 2021, permits the granting of awards totaling an aggregate of 5,000,000 common units, and is subject to adjustment. The 2019 LTIP generally will be administered by the compensation committee of our board of directors. As of December 31, 2022, a total of 1,064,199 common units remained available to be awarded under the 2019 LTIP.
Other Plans. We sponsor the NuStar GP, LLC Fifth Amended and Restated 2000 Long-Term Incentive Plan, as amended (2000 LTIP), and the NuStar GP Holdings, LLC Long-Term Incentive Plan, as amended (2006 LTIP). Effective with the approval of the 2019 LTIP in April 2019, the 2000 LTIP and the 2006 LTIP terminated with respect to new grants; however, unvested restricted unit awards granted under the 2000 LTIP and the 2006 LTIP remain outstanding as of December 31, 2022.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
any award prior to its vesting. As of December 31, 2017, common units that remained available to be awarded under the 2000 LTIP totaled 679,045.
On March 1, 2016, we assumed all outstanding awards under the 2000 LTIP. The transfer of the outstanding awards qualifies as a plan modification. Therefore, we measured the fair value of the outstanding awards based on the common unit price on the transfer date.
The following table summarizes information pertaining to all of our long-term incentive plan compensation expense:plans:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Units Outstanding
December 31, | | Compensation Expense
Year Ended December 31, |
| 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 |
| | | | | | | (Thousands of Dollars) |
| Restricted units: | | | | | | | | | | | |
| Domestic employees | 2,859,189 | | | 2,520,436 | | | 2,235,125 | | | $ | 12,759 | | | $ | 11,892 | | | $ | 10,205 | |
| Non-employee directors (NEDs) | 133,604 | | | 129,312 | | | 98,769 | | | 1,021 | | | 856 | | | 631 | |
| International employees | — | | | 21,760 | | | 19,987 | | | (20) | | | 139 | | | 58 | |
| Performance awards | — | | | 33,695 | | | 87,122 | | | 2,442 | | | 3,047 | | | 1,291 | |
| | | | | | | | | | | |
| Unit awards | — | | | — | | | — | | | — | | | 4,645 | | | — | |
| Total | 2,992,793 | | | 2,705,203 | | | 2,441,003 | | | $ | 16,202 | | | $ | 20,579 | | | $ | 12,185 | |
|
| | | | | | | | | | | | | | | | |
| | Units Outstanding December 31, | | Transferred Units | | Compensation Expense Year Ended December 31, |
| | 2017 | | 2016 | | March 1, 2016 | | 2017 | | 2016 |
| | | | | | | | (Thousands of Dollars) |
| Restricted Units: | | | | | | | | | |
| Domestic employees | 736,746 |
| | 647,340 |
| | 586,524 |
| | $ | 7,881 |
| | $ | 5,980 |
|
| Non-employee directors (NEDs) | 27,097 |
| | 18,134 |
| | 17,629 |
| | 251 |
| | 388 |
|
| International employees | 58,107 |
| | 50,609 |
| | 49,121 |
| | 595 |
| | 715 |
|
| Performance Units | 80,961 |
| | 77,014 |
| | 77,014 |
| | — |
| | 1,211 |
|
| Total | 902,911 |
| | 793,097 |
| | 730,288 |
| | $ | 8,727 |
| | $ | 8,294 |
|
Prior to the Employee Transfer, we reimbursed NuStar GP, LLC for our long-term incentive plan compensation expense which totaled $6.4 million for the year ended December 31, 2015.
Restricted Units
Our restricted unit awards are considered phantom units, as they represent the right to receive our common units upon vesting.
We account for restricted units as either equity-classified awards or liability-classified awards, depending on expected method of settlement. Awards we settle with the issuance of common units upon vesting are equity-classified. Awards we settle in cash upon vesting are liability-classified. We record compensation expense ratably over the vesting period based on the fair value of the common units at the grant date (for domestic employees)employees and NEDs), or, prior to the sale of our Point Tupper Terminal Operations on April 29, 2022, the fair value of the common units measured at each reporting period (for NEDs and international employees). DERs paid with respect to outstanding equity-classified unvested restricted units reduce equity, similar to cash distributions to unitholders, whereas DERs paid with respect to outstanding liability-classified unvested restricted units are expensed.were expensed prior to the sale of our Point Tupper Terminal Operations on April 29, 2022. In connection with the DERs for equity awards, we paid or expect to pay $3.0$2.5 million, $2.4 million and $2.7$2.1 million respectively, in cash, for the years ended December 31, 20172022, 2021 and 2016. A summary of our restricted unit activity is as follows:2020.
|
| | | | | | | | | | | | |
| | Domestic Employees | | | | |
| | Number of Restricted Units | | Weighted- Average Grant-Date Fair Value Per Unit | | Number of Restricted Units to NEDs | | Number of Restricted Units to International Employees |
| Nonvested units as of January 1, 2016 | — |
| | $ | — |
| | — |
| | — |
|
| Transferred | 586,524 |
| | 35.03 |
| | 17,629 |
| | 49,121 |
|
| Granted | 246,070 |
| | 47.70 |
| | 8,730 |
| | 20,107 |
|
| Vested | (180,724 | ) | | 35.50 |
| | (8,225 | ) | | (14,812 | ) |
| Forfeited | (4,530 | ) | | 35.03 |
| | — |
| | (3,807 | ) |
| Nonvested units as of December 31, 2016 | 647,340 |
| | 39.72 |
| | 18,134 |
| | 50,609 |
|
| Granted | 307,009 |
| | 29.56 |
| | 17,110 |
| | 24,533 |
|
| Vested | (201,466 | ) | | 38.74 |
| | (8,147 | ) | | (16,440 | ) |
| Forfeited | (16,137 | ) | | 40.00 |
| | — |
| | (595 | ) |
| Nonvested units as of December 31, 2017 | 736,746 |
| | $ | 35.95 |
| | 27,097 |
| | 58,107 |
|
The total fair value of our equity-classified awards vested for the years ended December 31, 2017 and 2016 was $6.5 million and $9.0 million, respectively. We issued 152,017 common units in connection with these award vestings, net of employee tax withholding requirements, for the year ended December 31, 2017. Unrecognized compensation cost related to our equity-
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
classified employee awards totaled $25.5 million as of December 31, 2017, which we expect to recognize over a weighted-average period of 3.7 years.
Domestic Employees. The outstanding restricted units granted to domestic employees are equity-classified awards and generally vest over five years, beginning one year after the grant date. The fair value of these awards is measured at the transfer date (or grant date for issuances subsequent to the Employee Transfer).date.
Non-Employee Directors. The outstanding restricted units granted to NEDs are equity-classified awards that vest over three years. The fair value of these awards is measured at the grant date.
International Employees. Prior to the sale of our Point Tupper Terminal Operations on April 29, 2022, the outstanding restricted units granted to international employees were cash-settled and accounted for as liability-classified awards. These awards vested over three years and the fair value was equal to the market price of our common units at each reporting period.
International Employees. The outstanding For the year ended December 31, 2022, 11,364 restricted units grantedvested and 10,396 restricted units were forfeited related to our international employees are cash-settled and accounted foremployees.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
A summary of our equity-classified restricted unit awards is as liability-classified awards. These awards vest over three to five years and thefollows:
| | | | | | | | | | | | | | | | | |
| Measured at Grant Date Fair Value | | | | | | |
| Number of Units | | Weighted-Average Fair Value Per Unit | | | | | | |
| Nonvested units as of January 1, 2020 | 1,284,492 | | | $ | 27.48 | | | | | | | |
| | | | | | | | | |
| Granted | 1,454,998 | | | 12.10 | | | | | | | |
| Vested | (374,847) | | | 28.47 | | | | | | | |
| Forfeited | (30,749) | | | 26.75 | | | | | | | |
| Nonvested units as of December 31, 2020 | 2,333,894 | | | 17.70 | | | | | | | |
| Granted | 1,049,081 | | | 16.28 | | | | | | | |
| Vested | (630,888) | | | 20.07 | | | | | | | |
| Forfeited | (102,339) | | | 14.28 | | | | | | | |
| Nonvested units as of December 31, 2021 | 2,649,748 | | | 16.57 | | | | | | | |
| Granted | 1,206,824 | | | 16.09 | | | | | | | |
| Vested | (738,701) | | | 17.79 | | | | | | | |
| Forfeited | (125,078) | | | 16.23 | | | | | | | |
| Nonvested units as of December 31, 2022 | 2,992,793 | | | 16.08 | | | | | | | |
The total fair value is equal to the market price of our equity-classified restricted unit awards vested for the years ended December 31, 2022, 2021 and 2020 was $11.9 million, $10.3 million and $4.6 million, respectively. We issued 531,637, 460,076 and 275,146 common units at each reporting period.in connection with these award vestings, net of employee tax withholding requirements, for the years ended December 31, 2022, 2021 and 2020, respectively. Unrecognized compensation cost related to our equity-classified employee awards totaled $45.6 million as of December 31, 2022, which we expect to recognize over a weighted-average period of 3.7 years.
Performance UnitsAwards
Performance unitsawards are issued to certain of our key employees and represent either rights to receive our common units or cash upon achieving an objective performance measuremeasures for the performance period. The objective performance measure is determined each yearperiod established by the NuStar GP, LLC Compensation Committee for the following year.(the Compensation Committee). Achievement of the performance measuremeasures determines the rate at which the performance unitsawards convert into our common units or cash, which can rangeranges from zero to 200%. for certain awards.
Performance unitsawards vest in three annual increments (tranches), based upon our achievement of the performance measuremeasures set by the Compensation Committee during the one-year performance periods that end on December 31 of each year following the date of grant.applicable year. Therefore, the performance unitsawards are not considered granted for accounting purposes until the Compensation Committee has set the performance measuremeasures for each tranche of awards. Performance unitsunit awards are equity-classified awards measured at the grant date fair value. In addition, since the performance unitsunit awards granted do not receive DERs, the grant date fair value of these awards is reduced by the per unit distributions expected to be paid to common unitholders during the vesting period. Performance cash awards are accounted for as a liability but may be settled in common units. We record compensation expense ratably for each vesting tranche over its requisite service period (one year) if it is probable that the specified performance measuremeasures will be achieved. Additionally, changes in the actual or estimated outcomes that affect the quantity of performance unitsawards expected to be converted into common units or paid in cash, are recognized as a cumulative adjustment.
For Performance units vested relate to the period fromperformance for the Employee Transfer date to December 31, 2016, no performance units were granted or forfeited. For the yearperiod ended December 31 2017, we issued 33,438 common units in connection withof the performance award vestings related to 2016 performance, net of employee tax withholding requirements. For 2017, we did not achieve the performance measure.previous year.
A summary of our performance units is shown below:
|
| | | | | | | | | |
| | | | Granted for Accounting Purposes |
| | Total Performance Units Awarded | | Performance Units | | Weighted-Average Grant Date Fair Value per Unit |
| Outstanding as of January 1, 2017 | 77,014 |
| | 35,373 |
| | $ | 31.75 |
|
| Granted | 39,320 |
| | 38,865 |
| | 50.04 |
|
| Vested | (35,373 | ) | | (35,373 | ) | | 31.75 |
|
| Outstanding as of December 31, 2017 | 80,961 |
| | 38,865 |
| | $ | 50.04 |
|
Performance units vested during the year ended December 31, 2017 with respect to 2016 performance were as follows:
|
| | | | | | | | |
| | Vested Units | | Actual Conversion Rate | | Gross Number of Units Issued |
| 2014 awards | 9,613 |
| | 150 | % | | 14,420 |
|
| 2015 awards | 9,878 |
| | 150 | % | | 14,818 |
|
| 2016 awards | 15,882 |
| | 150 | % | | 23,825 |
|
| Total | 35,373 |
| | | | 53,063 |
|
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
A summary of our performance awards is shown below: | | | | | | | | | | | | | | | | | | | | | | | |
| | | Performance Unit Awards |
| | | | | Granted for Accounting Purposes |
| Performance Cash Awards | | Total Performance
Unit Awards Granted | | Performance Unit Awards | | Weighted-Average Grant Date Fair Value per Unit |
| (Thousands of Dollars) | | | | | | |
| Outstanding as of January 1, 2020 | $ | — | | | 161,561 | | | 74,439 | | | $ | 28.01 | |
| Granted | 2,167 | | | — | | | 57,448 | | | 13.21 | |
| Performance adjustment (a) | — | | | 72,951 | | | 72,951 | | | 28.01 | |
| Vested | — | | | (147,390) | | | (147,390) | | | 28.01 | |
| Outstanding as of December 31, 2020 | 2,167 | | | 87,122 | | | 57,448 | | | 13.21 | |
| Granted | 2,254 | | | 4,021 | | | 33,695 | | | 15.79 | |
| | | | | | | |
| Vested (b) | (672) | | | (53,427) | | | (53,427) | | | 13.21 | |
| Forfeitures | (51) | | | (4,021) | | | (4,021) | | | 13.21 | |
| Outstanding as of December 31, 2021 | 3,698 | | | 33,695 | | | 33,695 | | | 15.79 | |
| Granted | 2,954 | | | — | | | — | | | — | |
| Performance adjustment (a) | — | | | 14,839 | | | 14,839 | | | 15.79 | |
| Vested (b) | (1,507) | | | (48,534) | | | (48,534) | | | 15.79 | |
| | | | | | | |
| Outstanding as of December 31, 2022 | $ | 5,145 | | | — | | | — | | | — | |
24. INCOME TAXES(a) For the year ended December 31, 2020, common units granted and issued upon vesting resulted from performance units earned at 198% of the 2019 target. For the year ended December 31, 2022, common units granted and issued upon vesting resulted from performance units earned at 150% of the 2021 target.
(b) For the years ended December 31, 2022 and 2021, we settled performance cash awards with 137,931 and 43,733 common units, respectively, and issued 84,778 and 26,704 common units, net of employee tax withholding requirements, respectively.
The total fair value of our performance unit awards vested for the years ended December 31, 2022, 2021 and 2020 was $0.8 million, $0.8 million and $4.2 million, respectively. For the years ended December 31, 2022, 2021, and 2020 we issued 29,840, 31,366 and 93,440 common units in connection with the performance unit award vestings, net of employee tax withholding requirements, respectively.
On December 22, 2017,January 26, 2023, we settled performance cash awards in common units, and together with the U.S. enacted the Tax Cutsperformance unit awards, we issued 82,353 common units, net of employee tax withholding requirements, respectively.
Unit Awards
Unit awards are equity-classified awards of fully vested common units. We accrued compensation expense in 2021 and Jobs Act (“the Act”). The Act, which is also commonly referred to as “U.S. tax reform,” significantly changes U.S. corporate income tax laws by, among other things, reducing the U.S. corporate tax rate from 35% to 21%, starting2019 that was paid in 2018, and creating a territorial tax system with a one-time mandatory tax on previously deferred foreign earnings of U.S. subsidiaries. As a result, we recorded an expense of $0.8 millionunit awards in the fourth quarterfirst quarters of 2017. This amount, which is included in “Income tax expense”the respective subsequent years. We base the number of unit awards granted on the consolidated statementsfair value of income, consists of two components: (i) $0.7 million relating to the one-time mandatory tax on previously deferred earnings of certain non-U.S. subsidiaries that are wholly owned by onecommon units at the grant date. A summary of our U.S. subsidiaries and (ii) $0.1 million resulting from the revaluation of our net deferred tax assets in the U.S. based on the new lower corporate income tax rate.unit awards is shown below:
| | | | | | | | | | | | | | | | | | | | |
| Date of Grant | | Grant Date Fair Value | | Unit Awards Granted | | Common Units Issued, Net of Employee Withholding Tax |
| | (Thousands of Dollars) | | | | |
| February 2022 | | $ | 4,645 | | | 280,685 | | | 186,190 | |
| February and March 2020 | | $ | 22,941 | | | 834,224 | | | 571,735 | |
Although the $0.8 million expense represents what we believe to be a reasonable estimate of the impact of the income tax effects of the Act on our consolidated financial statements as of December 31, 2017, it should be considered provisional. We are continuing to gather additional information to more precisely compute our deferred tax assets balance in the U.S., as well as the income tax expense associated with the one-time mandatory tax. Any adjustments to these provisional amounts will be reported as a component of “Income tax expense” on the consolidated statements of income in the reporting period in which any such adjustments are determined, which will be no later than the fourth quarter of 2018, and are not expected to be significant.
Due to the complexity of the new Global Intangible Low-Tax Income (GILTI) tax rules, we are continuing to evaluate this provision of the Act and the application of FASB’s Accounting Standards Codification 740 (ASC 740). Under U.S. GAAP, we are allowed to make an accounting policy choice of either (i) treating taxes due on future U.S. inclusions in taxable income related to GILTI as a current-period expense when incurred (the “period cost method”) or (ii) factoring such amounts into a company’s measurement of its deferred taxes (the “deferred method”). Our selection of an accounting policy with respect to the new GILTI tax rules will depend, in part, on analyzing our global income to determine whether we expect to have future U.S. inclusions in taxable income related to GILTI and, if so, what the impact is expected to be. Because whether we expect to have future U.S. inclusions in taxable income related to GILTI depends on not only our current structure and estimated future results of global operations, but also our intent and ability to modify our structure and/or our business, we are not yet able to reasonably estimate the effect of this provision of the Tax Act. Therefore, we have not made any adjustments related to potential GILTI tax in our consolidated financial statements as of December 31,2017, and have not made a policy decision regarding whether to record deferred taxes on GILTI.
Due to the complexity of the new Base Erosion Anti-Abuse Tax (BEAT) rules, we are continuing to evaluate this provision of the Act and the application of ASC 740. Under U.S. GAAP, because the BEAT provisions are designed to be an “incremental tax,” BEAT is treated as a current-period expense when incurred (the period cost method). Therefore, we have not made any adjustments related to the potential BEAT in our consolidated financial statements.
Components of income tax expense related to certain of our continuing operations conducted through separate taxable wholly owned corporate subsidiaries were as follows:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (Thousands of Dollars) |
| Current: | | | | | |
| U.S. | $ | 3,117 |
| | $ | 2,280 |
| | $ | 908 |
|
| Foreign | 6,335 |
| | 6,329 |
| | 9,820 |
|
| Foreign withholding tax | 479 |
| | 3,833 |
| | 1,926 |
|
| Total current | 9,931 |
| | 12,442 |
| | 12,654 |
|
| | | | | | |
| Deferred: | | | | | |
| U.S. | 1,468 |
| | 2,680 |
| | 1,022 |
|
| Foreign | (1,065 | ) | | (1,122 | ) | | (1,464 | ) |
| Foreign withholding tax | (397 | ) | | (2,027 | ) | | 2,500 |
|
| Total deferred | 6 |
| | (469 | ) | | 2,058 |
|
| | | | | | |
| Total income tax expense | $ | 9,937 |
| | $ | 11,973 |
| | $ | 14,712 |
|
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
23. INCOME TAXES
Components of income tax expense related to certain of our operations conducted through separate taxable wholly owned corporate subsidiaries were as follows:
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2022 | | 2021 | | 2020 |
| | (Thousands of Dollars) |
| Current: | | | | | |
| U.S. | $ | 3,558 | | | $ | 3,755 | | | $ | 36 | |
| Foreign | 272 | | | 221 | | | 2,415 | |
| Foreign withholding tax | 355 | | | 1,281 | | | — | |
| Total current | 4,185 | | | 5,257 | | | 2,451 | |
| | | | | |
| Deferred: | | | | | |
| U.S. | 341 | | | (93) | | | 300 | |
| Foreign | (1,287) | | | (531) | | | (621) | |
| Foreign withholding tax | — | | | (745) | | | 533 | |
| Total deferred | (946) | | | (1,369) | | | 212 | |
| | | | | |
| Income tax expense | $ | 3,239 | | | $ | 3,888 | | | $ | 2,663 | |
The difference between income tax expense recorded in our consolidated statements of income (loss) and income taxes computed by applying the applicable statutory federal income tax rate (35% for all years presented) to income before income tax expense is due to the fact that the majority of our income is not subject to federal income tax due to our status as a limited partnership. We record a tax provision related to the amount of undistributed earnings of our foreign subsidiaries expected to be repatriated.
The tax effects of significant temporary differences representing deferred income tax assets and liabilities were as follows:
| | | | December 31, | | December 31, |
| | 2017 | | 2016 | | 2022 | | 2021 |
| | (Thousands of Dollars) | | (Thousands of Dollars) |
| Deferred income tax assets: | | | | Deferred income tax assets: | |
| Net operating losses | $ | 20,688 |
| | $ | 31,539 |
| Net operating losses | $ | 17,710 | | | $ | 20,005 | |
| Employee benefits | 483 |
| | 697 |
| |
| Environmental and legal reserves | 185 |
| | 148 |
| |
| Allowance for bad debt | 1,982 |
| | 2,697 |
| |
| | Capital loss | | Capital loss | 3,714 | | | 3,735 | |
| Other | 2,050 |
| | 1,697 |
| Other | 793 | | | 625 | |
| Total deferred income tax assets | 25,388 |
| | 36,778 |
| Total deferred income tax assets | 22,217 | | | 24,365 | |
| Less: Valuation allowance | (11,251 | ) | | (12,759 | ) | Less: Valuation allowance | (21,573) | | | (23,718) | |
| Net deferred income tax assets | 14,137 |
| | 24,019 |
| Net deferred income tax assets | 644 | | | 647 | |
| | | | | | | | |
| Deferred income tax liabilities: | | | | Deferred income tax liabilities: | |
| Property, plant and equipment | (36,176 | ) | | (43,788 | ) | Property, plant and equipment | (3,534) | | | (11,884) | |
| Foreign withholding tax | — |
| | (384 | ) | Foreign withholding tax | (286) | | | (272) | |
| Other | | Other | (43) | | | (322) | |
| Total deferred income tax liabilities | (36,176 | ) | | (44,172 | ) | Total deferred income tax liabilities | (3,863) | | | (12,478) | |
| | | | | | | | |
| Net deferred income tax liability | $ | (22,039 | ) | | $ | (20,153 | ) | Net deferred income tax liability | $ | (3,219) | | | $ | (11,831) | |
| | | | | |
| Reported on the consolidated balance sheets as: | | | | |
| Deferred income tax asset | $ | 233 |
| | $ | 2,051 |
| |
| Deferred income tax liability | (22,272 | ) | | (22,204 | ) | |
| Net deferred income tax liability | $ | (22,039 | ) | | $ | (20,153 | ) | |
|
As of December 31, 2017,2022, our U.S. and foreign corporate operations have net operating loss carryforwards for tax purposes totaling $79.9$51.1 million and $13.1$23.3 million, respectively, which are subject to various limitations on use and expire in years 20252032 through 20362034 for U.S. losses and in years 20182023 through 20262033 for foreign losses.
As of However, U.S. losses generated after December 31, 2017, totaling $5.2 million, can be carried forward indefinitely. As of December 31, 2022, our U.S. corporate operations
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
have a capital loss carryforward for tax purposes totaling $17.7 million, which is subject to limitations on use and 2016,expires in 2024.
As of December 31, 2022 and 2021, we recordedhave a valuation allowance of $11.3$21.6 million and $12.8$23.7 million, respectively, related to our deferred tax assets.assets on net operating losses and capital losses. We estimate the amount of valuation allowance based upon our expectations of taxable income in the various jurisdictions in which we operate and the period over which we can utilize those future deductions. The valuation allowance reflects uncertainties related to our ability to utilize certain net operating loss carryforwards before they expire. In 2017,2022, there was a $1.9$2.3 million decrease in the valuation allowance for the U.S. net operating loss and a $0.4$0.1 million increase in the foreign net operating loss valuation allowance due to changes in our estimates of the amount of those loss carryforwards that will be realized, based upon future taxable income.
The realization of net deferred income tax assets recorded as of December 31, 20172022 is dependent upon our ability to generate future taxable income in the United States. We believe it is more likely than not that the net deferred income tax assets as of December 31, 20172022 will be realized, based on expected future taxable income.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
25.24. SEGMENT INFORMATION
Our reportable business segments consist of the pipeline, storage and fuels marketing.marketing segments. Our segments represent strategic business units that offer different services and products. We evaluate the performance of each segment based on its respective operating income, before general and administrative expenses and certain non-segmental depreciation and amortization expense. General and administrative expenses are not allocated to the operating segments since those expenses relate primarily to the overall management at the entity level. Our principal operations includeWe are primarily engaged in the transportation, of petroleum products and anhydrous ammonia, the terminalling and storage of petroleum products and renewable fuels and the marketingtransportation of anhydrous ammonia. We also market petroleum products. Intersegment revenues result from storage agreements with wholly owned subsidiaries of NuStar Energy at rates consistent with the rates charged to third parties for storage.
Results of operations for the reportable segments were as follows:
| | | | Year Ended December 31, | | Year Ended December 31, |
| | 2017 |
| 2016 | | 2015 | | 2022 | | 2021 | | 2020 |
| | (Thousands of Dollars) | | (Thousands of Dollars) |
| Revenues: | | | | | | Revenues: | |
| Pipeline | $ | 516,288 |
| | $ | 485,650 |
| | $ | 508,522 |
| Pipeline | $ | 828,191 | | | $ | 762,238 | | | $ | 718,823 | |
| Storage: | | | | | | |
| Third parties | 604,847 |
| | 589,098 |
| | 599,302 |
| |
| Intersegment | 12,106 |
| | 20,944 |
| | 25,606 |
| |
| Total storage | 616,953 |
| | 610,042 |
| | 624,908 |
| |
| | Storage | | Storage | 334,549 | | | 427,668 | | | 494,442 | |
| | Fuels marketing | 692,884 |
| | 681,934 |
| | 976,216 |
| Fuels marketing | 520,486 | | | 428,608 | | | 268,345 | |
| Consolidation and intersegment eliminations | (12,106 | ) | | (20,944 | ) | | (25,606 | ) | Consolidation and intersegment eliminations | (3) | | | (14) | | | (46) | |
| Total revenues | $ | 1,814,019 |
| | $ | 1,756,682 |
| | $ | 2,084,040 |
| Total revenues | $ | 1,683,223 | | | $ | 1,618,500 | | | $ | 1,481,564 | |
| | | | | | | | | | | | |
| Depreciation and amortization expense: | | | | | | Depreciation and amortization expense: | |
| Pipeline | $ | 128,061 |
| | $ | 89,554 |
| | $ | 84,951 |
| Pipeline | $ | 178,802 | | | $ | 179,088 | | | $ | 177,384 | |
| Storage | 127,473 |
| | 118,663 |
| | 116,768 |
| Storage | 73,076 | | | 87,500 | | | 99,092 | |
| | Total segment depreciation and amortization expense | 255,534 |
| | 208,217 |
| | 201,719 |
| Total segment depreciation and amortization expense | 251,878 | | | 266,588 | | | 276,476 | |
| Other depreciation and amortization expense | 8,698 |
| | 8,519 |
| | 8,491 |
| Other depreciation and amortization expense | 7,358 | | | 7,792 | | | 8,625 | |
| Total depreciation and amortization expense | $ | 264,232 |
| | $ | 216,736 |
| | $ | 210,210 |
| Total depreciation and amortization expense | $ | 259,236 | | | $ | 274,380 | | | $ | 285,101 | |
| | | | | | | | | | | | |
| Operating income: | | | | | | Operating income: | |
| Pipeline | $ | 231,795 |
| | $ | 248,238 |
| | $ | 270,349 |
| Pipeline | $ | 438,670 | | | $ | 321,472 | | | $ | 118,429 | |
| Storage | 219,439 |
| | 214,801 |
| | 217,818 |
| Storage | 61,081 | | | 24,800 | | | 189,781 | |
| Fuels marketing | 5,983 |
| | 3,406 |
| | 13,507 |
| Fuels marketing | 33,536 | | | 11,181 | | | 12,233 | |
| Consolidation and intersegment eliminations | (1 | ) | | — |
| | 42 |
| |
| | Total segment operating income | 457,216 |
| | 466,445 |
| | 501,716 |
| Total segment operating income | 533,287 | | | 357,453 | | | 320,443 | |
| General and administrative expenses | 112,240 |
| | 98,817 |
| | 102,521 |
| General and administrative expenses | 117,116 | | | 113,207 | | | 102,716 | |
| Other depreciation and amortization expense | 8,698 |
| | 8,519 |
| | 8,491 |
| Other depreciation and amortization expense | 7,358 | | | 7,792 | | | 8,625 | |
| | Total operating income | $ | 336,278 |
| | $ | 359,109 |
| | $ | 390,704 |
| Total operating income | $ | 408,813 | | | $ | 236,454 | | | $ | 209,102 | |
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Revenues by geographic area are shown in the table below:
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2022 | | 2021 | | 2020 |
| | (Thousands of Dollars) |
| United States | $ | 1,667,672 | | | $ | 1,582,672 | | | $ | 1,441,892 | |
| Foreign | 15,551 | | | 35,828 | | | 39,672 | |
| Consolidated revenues | $ | 1,683,223 | | | $ | 1,618,500 | | | $ | 1,481,564 | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (Thousands of Dollars) |
| United States | $ | 1,406,626 |
| | $ | 1,352,936 |
| | $ | 1,599,088 |
|
| Netherlands | 322,251 |
| | 313,395 |
| | 386,282 |
|
| Other | 85,142 |
| | 90,351 |
| | 98,670 |
|
| Consolidated revenues | $ | 1,814,019 |
| | $ | 1,756,682 |
| | $ | 2,084,040 |
|
For the years ended December 31, 2017, 20162022, 2021 and 2015,2020, Valero Energy Corporation accounted for approximately 17%18%, or $300.0$307.3 million, 18%19%, or $310.0$308.5 million,, and 16%20%, or $331.7$295.1 million, of our consolidated revenues, respectively. These revenues were included in all of our reportable business segments. No other single customer accounted for 10% or more of our consolidated revenues.
Total amounts of property, plant and equipment, net by geographic area were as follows:
| | | | | | | | | | | |
| | December 31, |
| | 2022 | | 2021 |
| | (Thousands of Dollars) |
| United States | $ | 3,359,427 | | | $ | 3,428,441 | |
| Foreign | 43,656 | | | 113,201 | |
| Consolidated property, plant and equipment, net | $ | 3,403,083 | | | $ | 3,541,642 | |
|
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| | (Thousands of Dollars) |
| United States | $ | 3,519,965 |
| | $ | 3,086,337 |
|
| Netherlands | 572,817 |
| | 469,061 |
|
| Other | 208,151 |
| | 166,885 |
|
| Consolidated long-lived assets | $ | 4,300,933 |
| | $ | 3,722,283 |
|
Total assets by reportable segment were as follows:
| | | | | | | | | | | |
| | December 31, |
| | 2022 | | 2021 |
| | (Thousands of Dollars) |
| Pipeline | $ | 3,360,685 | | | $ | 3,441,272 | |
| Storage | 1,438,609 | | | 1,537,037 | |
| Fuels marketing | 37,763 | | | 41,562 | |
| Total segment assets | 4,837,057 | | | 5,019,871 | |
| | | |
| Other partnership assets | 136,629 | | | 136,461 | |
| Total consolidated assets | $ | 4,973,686 | | | $ | 5,156,332 | |
|
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| | (Thousands of Dollars) |
| Pipeline | $ | 3,492,417 |
| | $ | 2,024,633 |
|
| Storage | 2,735,563 |
| | 2,522,586 |
|
| Fuels marketing | 118,746 |
| | 168,347 |
|
| Total segment assets | 6,346,726 |
| | 4,715,566 |
|
| Other partnership assets | 188,507 |
| | 314,979 |
|
| Total consolidated assets | $ | 6,535,233 |
| | $ | 5,030,545 |
|
Capital expenditures including acquisitions and investments in other noncurrent assets, by reportable segment were as follows: | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2022 | | 2021 | | 2020 |
| | (Thousands of Dollars) |
| Pipeline | $ | 90,430 | | | $ | 67,340 | | | $ | 122,512 | |
| Storage | 47,222 | | | 112,043 | | | 71,788 | |
| | | | | |
| Other partnership assets | 2,978 | | | 1,750 | | | 3,779 | |
| Total capital expenditures | $ | 140,630 | | | $ | 181,133 | | | $ | 198,079 | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (Thousands of Dollars) |
| Pipeline | $ | 1,596,311 |
| | $ | 88,373 |
| | $ | 175,657 |
|
| Storage | 244,398 |
| | 206,641 |
| | 285,258 |
|
| Other partnership assets | 5,648 |
| | 5,001 |
| | 9,957 |
|
| Total capital expenditures | $ | 1,846,357 |
| | $ | 300,015 |
| | $ | 470,872 |
|
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
26. CONDENSED CONSOLIDATINGITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL STATEMENTSDISCLOSURE
NuStar Energy has no operations, and its assets consist mainly of its 100% indirectly owned subsidiaries, NuStar Logistics and NuPOP. The senior and subordinated notes issued by NuStar Logistics are fully and unconditionally guaranteed by NuStar Energy and NuPOP. As a result, the following condensed consolidating financial statements are presented as an alternative to providing separate financial statements for NuStar Logistics and NuPOP.
Condensed Consolidating Balance Sheets
December 31, 2017
(Thousands of Dollars)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | NuStar Energy | | NuStar Logistics | | NuPOP | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated |
| Assets | | | | | | | | | | | |
| Cash and cash equivalents | $ | 885 |
| | $ | 29 |
| | $ | — |
| | $ | 23,378 |
| | $ | — |
| | $ | 24,292 |
|
| Receivables, net | — |
| | 280 |
| | — |
| | 176,495 |
| | — |
| | 176,775 |
|
| Inventories | — |
| | 1,686 |
| | 8,611 |
| | 16,560 |
| | — |
| | 26,857 |
|
| Other current assets | 61 |
| | 11,412 |
| | 4,191 |
| | 6,844 |
| | — |
| | 22,508 |
|
| Intercompany receivable | — |
| | 3,112,164 |
| | — |
| | — |
| | (3,112,164 | ) | | — |
|
| Total current assets | 946 |
| | 3,125,571 |
| | 12,802 |
| | 223,277 |
| | (3,112,164 | ) | | 250,432 |
|
| Property, plant and equipment, net | — |
| | 1,893,720 |
| | 591,070 |
| | 1,816,143 |
| | — |
| | 4,300,933 |
|
| Intangible assets, net | — |
| | 58,530 |
| | — |
| | 725,949 |
| | — |
| | 784,479 |
|
| Goodwill | — |
| | 149,453 |
| | 170,652 |
| | 777,370 |
| | — |
| | 1,097,475 |
|
Investment in wholly owned subsidiaries | 2,891,371 |
| | 24,162 |
| | 1,301,717 |
| | 790,882 |
| | (5,008,132 | ) | | — |
|
| Deferred income tax asset | — |
| | — |
| | — |
| | 233 |
| | — |
| | 233 |
|
| Other long-term assets, net | 303 |
| | 65,684 |
| | 27,493 |
| | 8,201 |
| | — |
| | 101,681 |
|
| Total assets | $ | 2,892,620 |
| | $ | 5,317,120 |
| | $ | 2,103,734 |
| | $ | 4,342,055 |
| | $ | (8,120,296 | ) | | $ | 6,535,233 |
|
| Liabilities and Partners’ Equity | | | | | | | | | | | |
| Current portion of long-term debt | $ | — |
| | $ | 349,990 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 349,990 |
|
| Payables | 4,078 |
| | 27,642 |
| | 13,160 |
| | 101,052 |
| | — |
| | 145,932 |
|
| Short-term debt | — |
| | 35,000 |
| | — |
| | — |
| | — |
| | 35,000 |
|
| Accrued interest payable | — |
| | 40,402 |
| | — |
| | 47 |
| | — |
| | 40,449 |
|
| Accrued liabilities | 1,105 |
| | 17,628 |
| | 9,450 |
| | 33,395 |
| | — |
| | 61,578 |
|
| Taxes other than income tax | 125 |
| | 7,110 |
| | 3,794 |
| | 3,356 |
| | — |
| | 14,385 |
|
| Income tax payable | — |
| | 732 |
| | 4 |
| | 3,436 |
| | — |
| | 4,172 |
|
| Intercompany payable | 322,296 |
| | — |
| | 1,277,691 |
| | 1,512,177 |
| | (3,112,164 | ) | | — |
|
| Total current liabilities | 327,604 |
| | 478,504 |
| | 1,304,099 |
| | 1,653,463 |
| | (3,112,164 | ) | | 651,506 |
|
| Long-term debt, less current portion | — |
| | 3,201,220 |
| | — |
| | 61,849 |
| | — |
| | 3,263,069 |
|
| Deferred income tax liability | — |
| | 1,262 |
| | 12 |
| | 20,998 |
| | — |
| | 22,272 |
|
| Other long-term liabilities | — |
| | 58,806 |
| | 8,861 |
| | 50,630 |
| | — |
| | 118,297 |
|
| Total partners’ equity | 2,565,016 |
| | 1,577,328 |
| | 790,762 |
| | 2,555,115 |
| | (5,008,132 | ) | | 2,480,089 |
|
Total liabilities and partners’ equity | $ | 2,892,620 |
| | $ | 5,317,120 |
| | $ | 2,103,734 |
| | $ | 4,342,055 |
| | $ | (8,120,296 | ) | | $ | 6,535,233 |
|
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Condensed Consolidating Balance Sheets
December 31, 2016
(Thousands of Dollars)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | NuStar Energy | | NuStar Logistics | | NuPOP | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated |
| Assets | | | | | | | | | | | |
| Cash and cash equivalents | $ | 870 |
| | $ | 5 |
| | $ | — |
| | $ | 35,067 |
| | $ | — |
| | $ | 35,942 |
|
| Receivables, net | — |
| | 3,040 |
| | — |
| | 167,570 |
| | — |
| | 170,610 |
|
| Inventories | — |
| | 2,216 |
| | 2,005 |
| | 33,724 |
| | — |
| | 37,945 |
|
| Other current assets | 61 |
| | 120,350 |
| | 1,829 |
| | 10,446 |
| | — |
| | 132,686 |
|
| Intercompany receivable | — |
| | 1,308,415 |
| | — |
| | 57,785 |
| | (1,366,200 | ) | | — |
|
| Total current assets | 931 |
| | 1,434,026 |
| | 3,834 |
| | 304,592 |
| | (1,366,200 | ) | | 377,183 |
|
| Property, plant and equipment, net | — |
| | 1,935,172 |
| | 589,139 |
| | 1,197,972 |
| | — |
| | 3,722,283 |
|
| Intangible assets, net | — |
| | 71,033 |
| | — |
| | 56,050 |
| | — |
| | 127,083 |
|
| Goodwill | — |
| | 149,453 |
| | 170,652 |
| | 376,532 |
| | — |
| | 696,637 |
|
Investment in wholly owned subsidiaries | 1,964,736 |
| | 34,778 |
| | 1,221,717 |
| | 874,649 |
| | (4,095,880 | ) | | — |
|
| Deferred income tax asset | — |
| | — |
| | — |
| | 2,051 |
| | — |
| | 2,051 |
|
| Other long-term assets, net | 1,255 |
| | 63,586 |
| | 28,587 |
| | 11,880 |
| | — |
| | 105,308 |
|
| Total assets | $ | 1,966,922 |
| | $ | 3,688,048 |
| | $ | 2,013,929 |
| | $ | 2,823,726 |
| | $ | (5,462,080 | ) | | $ | 5,030,545 |
|
| Liabilities and Partners’ Equity | | | | | | | | | | | |
| Payables | $ | 2,436 |
| | $ | 24,272 |
| | $ | 7,124 |
| | $ | 84,854 |
| | $ | — |
| | $ | 118,686 |
|
| Short-term debt | — |
| | 54,000 |
| | — |
| | — |
| | — |
| | 54,000 |
|
| Accrued interest payable | — |
| | 34,008 |
| | — |
| | 22 |
| | — |
| | 34,030 |
|
| Accrued liabilities | 1,070 |
| | 7,118 |
| | 10,766 |
| | 41,531 |
| | — |
| | 60,485 |
|
| Taxes other than income tax | 125 |
| | 6,854 |
| | 3,253 |
| | 5,453 |
| | — |
| | 15,685 |
|
| Income tax payable | — |
| | 1,326 |
| | 5 |
| | 5,179 |
| | — |
| | 6,510 |
|
| Intercompany payable | 257,497 |
| | — |
| | 1,108,703 |
| | — |
| | (1,366,200 | ) | | — |
|
| Total current liabilities | 261,128 |
| | 127,578 |
| | 1,129,851 |
| | 137,039 |
| | (1,366,200 | ) | | 289,396 |
|
| Long-term debt | — |
| | 2,956,338 |
| | — |
| | 58,026 |
| | — |
| | 3,014,364 |
|
| Deferred income tax liability | — |
| | 1,862 |
| | 13 |
| | 20,329 |
| | — |
| | 22,204 |
|
| Other long-term liabilities | — |
| | 34,358 |
| | 9,436 |
| | 49,170 |
| | — |
| | 92,964 |
|
| Total partners’ equity | 1,705,794 |
| | 567,912 |
| | 874,629 |
| | 2,559,162 |
| | (4,095,880 | ) | | 1,611,617 |
|
Total liabilities and partners’ equity | $ | 1,966,922 |
| | $ | 3,688,048 |
| | $ | 2,013,929 |
| | $ | 2,823,726 |
| | $ | (5,462,080 | ) | | $ | 5,030,545 |
|
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Condensed Consolidating Statements of Income (Loss)
For the Year Ended December 31, 2017
(Thousands of Dollars)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | NuStar Energy | | NuStar Logistics | | NuPOP | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated |
| Revenues | $ | — |
| | $ | 496,454 |
| | $ | 221,125 |
| | $ | 1,097,458 |
| | $ | (1,018 | ) | | $ | 1,814,019 |
|
| Costs and expenses | 1,868 |
| | 317,871 |
| | 146,243 |
| | 1,012,777 |
| | (1,018 | ) | | 1,477,741 |
|
| Operating (loss) income | (1,868 | ) | | 178,583 |
| | 74,882 |
| | 84,681 |
| | — |
| | 336,278 |
|
Equity in earnings (loss) of subsidiaries | 149,775 |
| | (10,616 | ) | | 89,405 |
| | 158,700 |
| | (387,264 | ) | | — |
|
| Interest income (expense), net | 57 |
| | (176,897 | ) | | (5,587 | ) | | 9,344 |
| | — |
| | (173,083 | ) |
| Other income (expense), net | — |
| | 145 |
| | 3 |
| | (5,442 | ) | | — |
| | (5,294 | ) |
Income (loss) before income tax (benefit) expense | 147,964 |
| | (8,785 | ) | | 158,703 |
| | 247,283 |
| | (387,264 | ) | | 157,901 |
|
| Income tax (benefit) expense | — |
| | (820 | ) | | 2 |
| | 10,755 |
| | — |
| | 9,937 |
|
| Net income (loss) | $ | 147,964 |
| | $ | (7,965 | ) | | $ | 158,701 |
| | $ | 236,528 |
| | $ | (387,264 | ) | | $ | 147,964 |
|
Condensed Consolidating Statements of Income (Loss)
For the Year Ended December 31, 2016
(Thousands of Dollars)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | NuStar Energy | | NuStar Logistics | | NuPOP | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated |
| Revenues | $ | — |
| | $ | 511,650 |
| | $ | 224,966 |
| | $ | 1,021,804 |
| | $ | (1,738 | ) | | $ | 1,756,682 |
|
| Costs and expenses | 1,806 |
| | 302,099 |
| | 150,384 |
| | 945,022 |
| | (1,738 | ) | | 1,397,573 |
|
| Operating (loss) income | (1,806 | ) | | 209,551 |
| | 74,582 |
| | 76,782 |
| | — |
| | 359,109 |
|
Equity in earnings (loss) of subsidiaries | 151,794 |
| | (13,769 | ) | | 82,202 |
| | 156,036 |
| | (376,263 | ) | | — |
|
| Interest (expense) income, net | — |
| | (139,827 | ) | | (744 | ) | | 2,221 |
| | — |
| | (138,350 | ) |
| Other income (expense), net | 18 |
| | (58,264 | ) | | (26 | ) | | (511 | ) | | — |
| | (58,783 | ) |
Income (loss) before income tax expense (benefit) | 150,006 |
| | (2,309 | ) | | 156,014 |
| | 234,528 |
| | (376,263 | ) | | 161,976 |
|
| Income tax expense (benefit) | 3 |
| | 1,607 |
| | (23 | ) | | 10,386 |
| | — |
| | 11,973 |
|
| Net income (loss) | $ | 150,003 |
| | $ | (3,916 | ) | | $ | 156,037 |
| | $ | 224,142 |
| | $ | (376,263 | ) | | $ | 150,003 |
|
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Condensed Consolidating Statements of Income
For the Year Ended December 31, 2015
(Thousands of Dollars)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | NuStar Energy | | NuStar Logistics | | NuPOP | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated |
| Revenues | $ | — |
| | $ | 547,959 |
| | $ | 215,469 |
| | $ | 1,322,675 |
| | $ | (2,063 | ) | | $ | 2,084,040 |
|
| Costs and expenses | 1,717 |
| | 293,708 |
| | 140,081 |
| | 1,259,935 |
| | (2,105 | ) | | 1,693,336 |
|
| Operating (loss) income | (1,717 | ) | | 254,251 |
| | 75,388 |
| | 62,740 |
| | 42 |
| | 390,704 |
|
Equity in earnings (loss) of subsidiaries | 308,437 |
| | (7,257 | ) | | 120,768 |
| | 197,760 |
| | (619,708 | ) | | — |
|
| Interest (expense) income, net | — |
| | (137,847 | ) | | 1,611 |
| | 4,368 |
| | — |
| | (131,868 | ) |
| Other income, net | — |
| | 1,179 |
| | 5 |
| | 60,638 |
| | — |
| | 61,822 |
|
Income from continuing operations before income tax (benefit) expense | 306,720 |
| | 110,326 |
| | 197,772 |
| | 325,506 |
| | (619,666 | ) | | 320,658 |
|
| Income tax (benefit) expense | — |
| | (392 | ) | | 23 |
| | 15,081 |
| | — |
| | 14,712 |
|
Income from continuing operations | 306,720 |
| | 110,718 |
| | 197,749 |
| | 310,425 |
| | (619,666 | ) | | 305,946 |
|
Income from discontinued operations, net of tax | — |
| | — |
| | — |
| | 774 |
| | — |
| | 774 |
|
| Net income | $ | 306,720 |
| | $ | 110,718 |
| | $ | 197,749 |
| | $ | 311,199 |
| | $ | (619,666 | ) | | $ | 306,720 |
|
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Condensed Consolidating Statements of Comprehensive Income (Loss)
For the Year Ended December 31, 2017
(Thousands of Dollars)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | NuStar Energy | | NuStar Logistics | | NuPOP | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated |
| Net income (loss) | $ | 147,964 |
| | $ | (7,965 | ) | | $ | 158,701 |
| | $ | 236,528 |
| | $ | (387,264 | ) | | $ | 147,964 |
|
| | | | | | | | | | | | |
| Other comprehensive income (loss): | | | | | | | | | | | |
Foreign currency translation adjustment | — |
| | — |
| | — |
| | 17,466 |
| | — |
| | 17,466 |
|
| Net loss on pension and other postretirement benefit adjustments, net of tax benefit | — |
| | — |
| | — |
| | (6,170 | ) | | — |
| | (6,170 | ) |
| Net loss on cash flow hedges | — |
| | (2,046 | ) | | — |
| | — |
| | — |
| | (2,046 | ) |
Total other comprehensive (loss) income | — |
| | (2,046 | ) | | — |
| | 11,296 |
| | — |
| | 9,250 |
|
| Comprehensive income (loss) | $ | 147,964 |
| | $ | (10,011 | ) | | $ | 158,701 |
| | $ | 247,824 |
| | $ | (387,264 | ) | | $ | 157,214 |
|
Condensed Consolidating Statements of Comprehensive Income
For the Year Ended December 31, 2016
(Thousands of Dollars)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | NuStar Energy | | NuStar Logistics | | NuPOP | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated |
| Net income (loss) | $ | 150,003 |
| | $ | (3,916 | ) | | $ | 156,037 |
| | $ | 224,142 |
| | $ | (376,263 | ) | | $ | 150,003 |
|
| | | | | | | | | | | | |
| Other comprehensive income (loss): | | | | | | | | | | | |
Foreign currency translation adjustment | — |
| | — |
| | — |
| | (8,243 | ) | | — |
| | (8,243 | ) |
| Net loss on pension and other postretirement benefit adjustments, net of tax benefits | — |
| | — |
| | — |
| | (2,850 | ) | | — |
| | (2,850 | ) |
| Net gain on cash flow hedges | — |
| | 5,710 |
| | — |
| | — |
| | — |
| | 5,710 |
|
Total other comprehensive income (loss) | — |
| | 5,710 |
| | — |
| | (11,093 | ) | | — |
| | (5,383 | ) |
| Comprehensive income | $ | 150,003 |
| | $ | 1,794 |
| | $ | 156,037 |
| | $ | 213,049 |
| | $ | (376,263 | ) | | $ | 144,620 |
|
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Condensed Consolidating Statements of Comprehensive Income
For the Year Ended December 31, 2015
(Thousands of Dollars)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | NuStar Energy | | NuStar Logistics | | NuPOP | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated |
| Net income | $ | 306,720 |
| | $ | 110,718 |
| | $ | 197,749 |
| | $ | 311,199 |
| | $ | (619,666 | ) | | $ | 306,720 |
|
| | | | | | | | | | | | |
| Other comprehensive income (loss): | | | | | | | | | | | |
Foreign currency translation adjustment | — |
| | — |
| | — |
| | (31,987 | ) | | — |
| | (31,987 | ) |
| Net gain on cash flow hedges | — |
| | 11,105 |
| | — |
| | — |
| | — |
| | 11,105 |
|
Total other comprehensive income (loss) | — |
| | 11,105 |
| | — |
| | (31,987 | ) | | — |
| | (20,882 | ) |
| Comprehensive income | $ | 306,720 |
| | $ | 121,823 |
| | $ | 197,749 |
| | $ | 279,212 |
| | $ | (619,666 | ) | | $ | 285,838 |
|
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Condensed Consolidating Statements of Cash Flows
For the Year Ended December 31, 2017
(Thousands of Dollars)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | NuStar Energy | | NuStar Logistics | | NuPOP | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated |
Net cash provided by operating activities | $ | 483,481 |
| | $ | 152,101 |
| | $ | 102,405 |
| | $ | 405,950 |
| | $ | (737,138 | ) | | $ | 406,799 |
|
| Cash flows from investing activities: | | | | | | | | | | | |
| Capital expenditures | — |
| | (47,600 | ) | | (35,041 | ) | | (301,997 | ) | | — |
| | (384,638 | ) |
Change in accounts payable related to capital expenditures | — |
| | (1,988 | ) | | 5,964 |
| | 32,927 |
| | — |
| | 36,903 |
|
| Acquisitions | — |
| | — |
| | — |
| | (1,461,719 | ) | | — |
| | (1,461,719 | ) |
| Proceeds from Axeon term loan | — |
| | 110,000 |
| | — |
| | — |
| | — |
| | 110,000 |
|
| Proceeds from insurance recoveries | — |
| | — |
| | — |
| | 977 |
| | — |
| | 977 |
|
Proceeds from sale or disposition of assets | — |
| | 1,955 |
| | 18 |
| | 63 |
| | — |
| | 2,036 |
|
| Investment in subsidiaries | (1,262,000 | ) | | — |
| | — |
| | (126 | ) | | 1,262,126 |
| | — |
|
| Net cash (used in) provided by investing activities | (1,262,000 | ) | | 62,367 |
| | (29,059 | ) | | (1,729,875 | ) | | 1,262,126 |
| | (1,696,441 | ) |
| Cash flows from financing activities: | | | | | | | | | | | |
| Debt borrowings | — |
| | 2,969,400 |
| | — |
| | 90,700 |
| | — |
| | 3,060,100 |
|
| Debt repayments | — |
| | (2,400,739 | ) | | — |
| | (86,800 | ) | | — |
| | (2,487,539 | ) |
| Issuance of preferred units, net of issuance costs | 538,560 |
| | — |
| | — |
| | — |
| | — |
| | 538,560 |
|
Issuance of common units, net of issuance costs | 643,878 |
| | — |
| | — |
| | — |
| | — |
| | 643,878 |
|
| General partner contribution | 13,737 |
| | — |
| | — |
| | — |
| | — |
| | 13,737 |
|
| Distributions to preferred unitholders | (38,833 | ) | | (19,417 | ) | | (19,416 | ) | | (19,418 | ) | | 58,251 |
| | (38,833 | ) |
Distributions to common unitholders and general partner | (446,306 | ) | | (223,153 | ) | | (223,153 | ) | | (223,176 | ) | | 669,482 |
| | (446,306 | ) |
Contributions from (distributions to) affiliates | — |
| | 1,262,000 |
| | — |
| | (9,279 | ) | | (1,252,721 | ) | | — |
|
| Net intercompany activity | 73,206 |
| | (1,801,218 | ) | | 169,223 |
| | 1,558,789 |
| | — |
| | — |
|
| Other, net | (5,708 | ) | | (1,317 | ) | | — |
| | (300 | ) | | — |
| | (7,325 | ) |
Net cash provided by (used in) financing activities | 778,534 |
| | (214,444 | ) | | (73,346 | ) | | 1,310,516 |
| | (524,988 | ) | | 1,276,272 |
|
Effect of foreign exchange rate changes on cash | — |
| | — |
| | — |
| | 1,720 |
| | — |
| | 1,720 |
|
| Net increase (decrease) in cash and cash equivalents | 15 |
| | 24 |
| | — |
| | (11,689 | ) | | — |
| | (11,650 | ) |
Cash and cash equivalents as of the beginning of the period | 870 |
| | 5 |
| | — |
| | 35,067 |
| | — |
| | 35,942 |
|
Cash and cash equivalents as of the end of the period | $ | 885 |
| | $ | 29 |
| | $ | — |
| | $ | 23,378 |
| | $ | — |
| | $ | 24,292 |
|
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Condensed Consolidating Statements of Cash Flows
For the Year Ended December 31, 2016
(Thousands of Dollars)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | NuStar Energy | | NuStar Logistics | | NuPOP | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated |
Net cash provided by operating activities | $ | 391,773 |
| | $ | 167,900 |
| | $ | 211,816 |
| | $ | 359,283 |
| | $ | (694,011 | ) | | $ | 436,761 |
|
| Cash flows from investing activities: | | | | | | | | | | | |
| Capital expenditures | — |
| | (64,334 | ) | | (52,637 | ) | | (87,387 | ) | | — |
| | (204,358 | ) |
Change in accounts payable related to capital expenditures | — |
| | (10,076 | ) | | (285 | ) | | (702 | ) | | — |
| | (11,063 | ) |
| Acquisitions | — |
| | (95,657 | ) | | — |
| | — |
| | — |
| | (95,657 | ) |
| Investment in subsidiaries | — |
| | — |
| | (212,900 | ) | | — |
| | 212,900 |
| | — |
|
| Net cash used in investing activities | — |
| | (170,067 | ) | | (265,822 | ) | | (88,089 | ) | | 212,900 |
| | (311,078 | ) |
| Cash flows from financing activities: | | | | | | | | | | | |
| Debt borrowings | — |
| | 1,365,529 |
| | — |
| | 41,200 |
| | — |
| | 1,406,729 |
|
| Debt repayments | — |
| | (1,419,852 | ) | | — |
| | (36,300 | ) | | — |
| | (1,456,152 | ) |
Issuance of preferred units, net of
issuance costs | 218,400 |
| | — |
| | — |
| | — |
| | — |
| | 218,400 |
|
Issuance of common units, net of
issuance costs | 27,710 |
| | — |
| | — |
| | — |
| | — |
| | 27,710 |
|
| General partner contribution | 680 |
| | — |
| | — |
| | — |
| | — |
| | 680 |
|
Distributions to common unitholders and general partner | (392,962 | ) | | (196,481 | ) | | (196,481 | ) | | (196,501 | ) | | 589,463 |
| | (392,962 | ) |
| Contributions from affiliates | — |
| | — |
| | — |
| | 108,352 |
| | (108,352 | ) | | — |
|
| Net intercompany activity | (241,131 | ) | | 255,326 |
| | 250,487 |
| | (264,682 | ) | | — |
| | — |
|
| Other, net | (4,485 | ) | | (2,354 | ) | | — |
| | (8,890 | ) | | — |
| | (15,729 | ) |
| Net cash (used in) provided by financing activities | (391,788 | ) | | 2,168 |
| | 54,006 |
| | (356,821 | ) | | 481,111 |
| | (211,324 | ) |
Effect of foreign exchange rate changes on cash | — |
| | — |
| | — |
| | 2,721 |
| | — |
| | 2,721 |
|
Net (decrease) increase in cash and cash equivalents | (15 | ) | | 1 |
| | — |
| | (82,906 | ) | | — |
| | (82,920 | ) |
Cash and cash equivalents as of the beginning of the period | 885 |
| | 4 |
| | — |
| | 117,973 |
| | — |
| | 118,862 |
|
Cash and cash equivalents as of the end of the period | $ | 870 |
| | $ | 5 |
| | $ | — |
| | $ | 35,067 |
| | $ | — |
| | $ | 35,942 |
|
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Condensed Consolidating Statements of Cash Flows
For the Year Ended December 31, 2015
(Thousands of Dollars)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | NuStar Energy | | NuStar Logistics | | NuPOP | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated |
Net cash provided by operating activities | $ | 389,967 |
| | $ | 237,780 |
| | $ | 119,928 |
| | $ | 365,588 |
| | $ | (588,326 | ) | | $ | 524,937 |
|
| Cash flows from investing activities: | | | | | | | | | | | |
| Capital expenditures | — |
| | (201,388 | ) | | (39,533 | ) | | (83,887 | ) | | — |
| | (324,808 | ) |
Change in accounts payable related to capital expenditures | — |
| | (4,950 | ) | | 33 |
| | 1,761 |
| | — |
| | (3,156 | ) |
| Acquisitions | — |
| | — |
| | — |
| | (142,500 | ) | | — |
| | (142,500 | ) |
| Proceeds from insurance recoveries | — |
| | — |
| | — |
| | 4,867 |
| | — |
| | 4,867 |
|
Proceeds from sale or disposition of assets | — |
| | 10,320 |
| | 22 |
| | 6,790 |
| | — |
| | 17,132 |
|
| Investment in other long-term assets | — |
| | — |
| | — |
| | (3,564 | ) | | — |
| | (3,564 | ) |
| Net cash used in investing activities | — |
| | (196,018 | ) | | (39,478 | ) | | (216,533 | ) | | — |
| | (452,029 | ) |
| Cash flows from financing activities: | | | | | | | | | | | |
| Debt borrowings | — |
| | 1,589,131 |
| | — |
| | 94,500 |
| | — |
| | 1,683,631 |
|
| Debt repayments | — |
| | (1,275,910 | ) | | — |
| | (41,000 | ) | | — |
| | (1,316,910 | ) |
Distributions to common unitholders and general partner | (392,204 | ) | | (196,102 | ) | | (196,102 | ) | | (196,122 | ) | | 588,326 |
| | (392,204 | ) |
| Net intercompany activity | 2,199 |
| | (155,278 | ) | | 115,652 |
| | 37,427 |
| | — |
| | — |
|
| Other, net | — |
| | (3,605 | ) | | — |
| | (141 | ) | | — |
| | (3,746 | ) |
| Net cash used in financing activities | (390,005 | ) | | (41,764 | ) | | (80,450 | ) | | (105,336 | ) | | 588,326 |
| | (29,229 | ) |
Effect of foreign exchange rate changes on cash | — |
| | — |
| | — |
| | (12,729 | ) | | — |
| | (12,729 | ) |
Net (decrease) increase in cash and cash equivalents | (38 | ) | | (2 | ) | | — |
| | 30,990 |
| | — |
| | 30,950 |
|
Cash and cash equivalents as of the beginning of the period | 923 |
| | 6 |
| | — |
| | 86,983 |
| | — |
| | 87,912 |
|
Cash and cash equivalents as of the end of the period | $ | 885 |
| | $ | 4 |
| | $ | — |
| | $ | 117,973 |
| | $ | — |
| | $ | 118,862 |
|
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
27. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following table summarizes quarterly financial data for the years ended December 31, 2017 and 2016:
|
| | | | | | | | | | | | | | | | | | | |
| | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | | Total |
| | (Thousands of Dollars, Except Per Unit Data) |
| 2017: | | | | | | | | | |
| Revenues | $ | 487,430 |
| | $ | 435,488 |
| | $ | 440,566 |
| | $ | 450,535 |
| | $ | 1,814,019 |
|
| Operating income | $ | 97,139 |
| | $ | 73,404 |
| | $ | 91,717 |
| | $ | 74,018 |
| | $ | 336,278 |
|
| Net income | $ | 57,940 |
| | $ | 26,250 |
| | $ | 38,592 |
| | $ | 25,182 |
| | $ | 147,964 |
|
| Basic and diluted net income per common unit | $ | 0.49 |
| | $ | 0.05 |
| | $ | 0.15 |
| | $ | — |
| | $ | 0.64 |
|
| Cash distributions per unit applicable to common limited partners | $ | 1.095 |
| | $ | 1.095 |
| | $ | 1.095 |
| | $ | 1.095 |
| | $ | 4.380 |
|
| | | | | | | | | | |
| 2016: | | | | | | | | | |
| Revenues | $ | 405,703 |
| | $ | 437,804 |
| | $ | 441,418 |
| | $ | 471,757 |
| | $ | 1,756,682 |
|
| Operating income | $ | 94,565 |
| | $ | 91,217 |
| | $ | 87,954 |
| | $ | 85,373 |
| | $ | 359,109 |
|
| Net income (loss) | $ | 57,401 |
| | $ | 52,517 |
| | $ | 51,141 |
| | $ | (11,056 | ) | | $ | 150,003 |
|
| Basic and diluted net income (loss) per common unit | $ | 0.57 |
| | $ | 0.52 |
| | $ | 0.49 |
| | $ | (0.31 | ) | | $ | 1.27 |
|
| Cash distributions per unit applicable to common limited partners | $ | 1.095 |
| | $ | 1.095 |
| | $ | 1.095 |
| | $ | 1.095 |
| | $ | 4.380 |
|
The quarterly financial data in the table above includes the impact of a $58.7 million non-cash impairment charge on the Axeon Term Loan in the fourth quarter of 2016.
28. SUBSEQUENT EVENTS
On February 7, 2018, NuStar Energy, Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, a wholly owned subsidiary of NuStar Energy (Merger Sub), Riverwalk Holdings, LLC and NuStar GP Holdings entered into an Agreement and Plan of Merger (the Merger Agreement) pursuant to which Merger Sub will merge with and into NuStar GP Holdings with NuStar GP Holdings being the surviving entity (the Merger), such that NuStar Energy will be the sole member of NuStar GP Holdings following the Merger. Pursuant to the Merger Agreement and at the effective time of the Merger, NuStar Energy’s partnership agreement will be amended and restated to, among other things, (i) cancel the incentive distribution rights held by our general partner, (ii) convert the 2% general partner interest in NuStar Energy held by our general partner into a non-economic management interest and (iii) provide the holders of our common units with voting rights in the election of the members of the board of directors of NuStar GP, LLC at an annual meeting, beginning in 2019.
At the effective time of the Merger, each outstanding NuStar GP Holdings common unit, other than those held by NuStar GP Holdings or its subsidiaries, will be converted into the right to receive 0.55 of a NuStar Energy common unit. All NuStar GP Holdings common units, when converted, will cease to be outstanding and will automatically be cancelled and no longer exist. No fractional NuStar Energy common units will be issued in the Merger; instead, each holder of NuStar GP Holdings’ common units otherwise entitled to receive a fractional NuStar Energy common unit will receive cash in lieu thereof. Furthermore, the 10,214,626 NuStar Energy common units currently owned by NuStar GP Holdings will be cancelled and will cease to exist.
At the effective time of the Merger, each outstanding award of NuStar GP Holdings restricted units will be converted, on the same terms and conditions as were applicable to the awards immediately prior to the Merger, into an award of NuStar Energy restricted units. The number of NuStar Energy restricted units subject to the converted awards will be determined as provided in the Merger Agreement. Each of our executive officers and directors has agreed and acknowledged that the Merger will not be deemed to trigger a “change of control” as defined under any NuStar Energy or NuStar GP Holdings plan or award, and has waived any rights to vesting, payment or other benefit thereunder that would arise upon a “change of control,” to which he or she might otherwise have been entitled.
The Merger Agreement contains customary representations and warranties and covenants by each of the parties. Completion of the Merger is conditioned upon, among other things: (i) approval of the Merger Agreement by the affirmative vote of holders of
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
a Unit Majority, as defined in the Second Amended and Restated Limited Liability Company Agreement of NuStar GP Holdings, as amended; (ii) the effectiveness of a registration statement on Form S-4 with respect to the issuance by NuStar Energy of its common units in connection with the Merger; (iii) the absence of certain legal injunctions or impediments prohibiting the transactions; (iv) the receipt of certain tax opinions from a nationally recognized tax counsel; and (v) the approval for the listing of NuStar Energy’s common units to be issued in the Merger on the New York Stock Exchange.
NuStar Energy entered into a Support Agreement, dated as of February 7, 2018 (the Support Agreement), with Merger Sub, WLG Holdings, LLC, a Texas limited liability company controlled by Mr. Greehey (WLG Holdings), Mr. Greehey (together, WLG Holdings and Mr. Greehey are referred to as the Greehey Unitholders), and, for limited purposes, NuStar GP Holdings, pursuant to which the Greehey Unitholders have agreed to vote in favor of the approval and adoption of the Merger Agreement, the approval of the Merger and any other action required in furtherance thereof submitted for the vote or written consent of NuStar GP Holdings unitholders. The Greehey Unitholders collectively own approximately 21% of the outstanding NuStar GP Holdings units. The Support Agreement will terminate (i) at the effective time of the Merger, (ii) upon the termination of the Merger Agreement as provided therein, or (iii) at such time as NuStar Energy and the Greehey Unitholders agree in writing to terminate the Support Agreement.
After the Merger, the NuStar GP, LLC board of directors is expected to consist of nine members, initially composed of the six members of the NuStar GP, LLC board of directors and the three independent directors of the board of directors of NuStar GP Holdings.
Additionally, on February 8, 2018, we announced that our management anticipates recommending to the board of directors of NuStar GP, LLC, and the board of directors expects to adopt, a reset of our quarterly distribution per common unit to $0.60 ($2.40 on an annualized basis), starting with the first-quarter distribution payable in May 2018.
| |
ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
| |
ITEM 9A. | CONTROLS AND PROCEDURES |
ITEM 9A.CONTROLS AND PROCEDURES
DISCLOSURE CONTROLS AND PROCEDURES
Our management has evaluated, with the participation of the principal executive officer and principal financial officer of NuStar GP, LLC, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the Exchange Act))1934) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures were effective as of December 31, 2017.2022.
INTERNAL CONTROL OVER FINANCIAL REPORTINGRestricted Units
| |
(a) | Management’s Report on Internal Control over Financial Reporting. |
Management’s reportOur restricted unit awards are considered phantom units, as they represent the right to receive our common units upon vesting. We account for restricted units as either equity-classified awards or liability-classified awards, depending on NuStar Energy L.P.’s internal controlexpected method of settlement. Awards we settle with the issuance of common units upon vesting are equity-classified. Awards we settle in cash upon vesting are liability-classified. We record compensation expense ratably over financial reporting required by Item 9A. appears in Item 8.the vesting period based on the fair value of this Form 10-K,the common units at the grant date (for domestic employees and is incorporated herein by reference.
| |
(b) | Attestation Report of the Registered Public Accounting Firm. |
The report of KPMG LLP on NuStar Energy L.P.’s internal control over financial reporting appears in Item 8. of this Form 10-K, and is incorporated herein by reference.
| |
(c) | Changes in Internal Control over Financial Reporting. |
There has been no change in our internal control over financial reporting that occurred during our last fiscal quarter that has materially affected,NEDs), or, is reasonably likelyprior to materially affect, our internal control over financial reporting.
| |
ITEM 9B. | OTHER INFORMATION |
None.
PART III
| |
ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
DIRECTORS AND EXECUTIVE OFFICERS OF NUSTAR GP, LLC
We do not have directors or officers. The directors and officers of NuStar GP, LLC, the general partnersale of our general partner, Riverwalk Logistics, L.P., perform allPoint Tupper Terminal Operations on April 29, 2022, the fair value of the common units measured at each reporting period (for international employees). DERs paid with respect to outstanding equity-classified unvested restricted units reduce equity, similar to cash distributions to unitholders, whereas DERs paid with respect to outstanding liability-classified unvested restricted units were expensed prior to the sale of our management functions. NuStar GP Holdings,Point Tupper Terminal Operations on April 29, 2022. In connection with the sole memberDERs for equity awards, we paid $2.5 million, $2.4 million and $2.1 million respectively, in cash, for the years ended December 31, 2022, 2021 and 2020.
Domestic Employees. The outstanding restricted units granted to domestic employees are equity-classified awards and generally vest over five years, beginning one year after the grant date. The fair value of NuStar GP, LLC, selectsthese awards is measured at the directorsgrant date.
Non-Employee Directors. The outstanding restricted units granted to NEDs are equity-classified awards that vest over three years. The fair value of NuStar GP, LLC (the Board) annually. Officers of NuStar GP, LLC are appointed annually by its directors.these awards is measured at the grant date.
As described below in Item 13, on February 7, 2018, NuStar Energy, Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, a wholly owned subsidiary of NuStar Energy (Merger Sub), Riverwalk Holdings, LLC and NuStar GP Holdings entered into an Agreement and Plan of Merger (the Merger Agreement) pursuant to which Merger Sub will merge with and into NuStar GP Holdings with NuStar GP Holdings being the surviving entity (the Merger), such that NuStar Energy will be the sole member of NuStar GP Holdings following the Merger. Pursuant
International Employees. Prior to the Merger Agreementsale of our Point Tupper Terminal Operations on April 29, 2022, the outstanding restricted units granted to international employees were cash-settled and ataccounted for as liability-classified awards. These awards vested over three years and the effective timefair value was equal to the market price of the Merger, NuStar Energy’s partnership agreement will be amended and restated to, among other things, provide the holders of NuStar Energyour common units with voting rights in the election of the members of the Board of NuStar GP, LLC at an annual meeting, beginning in 2019. After the Merger, the NuStar GP, LLC Board is expected to consist of nine members, initially composed of the six members of the NuStar GP, LLC Board and the three independent directors of the board of directors of NuStar GP Holdings, LLC. The Merger is subject to the satisfaction or waiver of certain conditions, including approval of the Merger Agreement by NuStar GP Holdings unitholders. Please refer to Item 13 for further discussion of the Merger.
Set forth below is certain information concerning the directors and executive officers of NuStar GP, LLC, effective as of February 20, 2018.
|
| | | | |
Name | | Age | | Position Held with NuStar GP, LLC |
William E. Greehey | | 81 | | Chairman of the Board |
Bradley C. Barron | | 52 | | President, Chief Executive Officer and Director |
J. Dan Bates | | 73 | | Director |
Dan J. Hill | | 77 | | Director |
Robert J. Munch | | 66 | | Director |
W. Grady Rosier | | 69 | | Director |
Mary Rose Brown | | 61 | | Executive Vice President and Chief Administrative Officer |
Thomas R. Shoaf | | 59 | | Executive Vice President and Chief Financial Officer |
Jorge A. del Alamo | | 48 | | Senior Vice President and Controller |
Daniel S. Oliver | | 51 | | Senior Vice President-Marketing and Business Development |
Amy L. Perry | | 49 | | Senior Vice President, General Counsel-Corporate & Commercial Law and Corporate Secretary |
Karen M. Thompson | | 50 | | Senior Vice President and General Counsel-Litigation, Regulatory & Environmental |
Michael Truby | | 58 | | Senior Vice President-Operations |
As a limited partnership, we are not required by the NYSE rules to have a nominating committee. However, in 2013, the Board created a Nominating/Governance & Conflicts Committee to identify candidates for membership on the Board. The members of the Nominating/Governance & Conflicts Committee are Mr. Rosier (Chairman), Mr. Bates, Mr. Hill and Mr. Munch. In accordance with our Corporate Governance Guidelines, individuals are considered for membership on the Board based on their character, judgment, integrity, diversity, age, skills (including financial literacy), independence and experience in the context of the overall needs of the Board. Our directors are also selected based on their knowledge about our industry and their respective experience leading or advising large companies. We require that our directors have the ability to work collegially, exercise good judgment and think critically. The Nominating/Governance & Conflicts Committee strives to find the best possible candidates to represent the interests of NuStar Energy and its unitholders. As part of its annual self-assessment process, the Nominating/Governance & Conflicts Committee evaluates the mix of independent and non-independent directors, the selection and functions of the presiding director and whether the Board has the appropriate range of talents, expertise and backgrounds.
The Board is led by its Chairman, Mr. Greehey. Although the Board believes that separating the roles of Chairman and Chief Executive Officer is appropriate in the current circumstances, our Corporate Governance Guidelines do not establish this approach as a policy. The Board also has appointed Mr. Hill as its presiding director to serve as a point of contact for unitholders wishing to communicate with the Board and to lead executive sessions of the non-management directors.
Mr. Greehey became Chairman of the Board in January 2002. He also has been the Chairman of the board of directors of NuStar GP Holdings since March 2006. Mr. Greehey served as Chairman of the board of directors of Valero Energy Corporation (Valero Energy) from 1979 through January 2007. Mr. Greehey was Chief Executive Officer of Valero Energy from 1979 through December 2005, and President of Valero Energy from 1998 until January 2003.
Mr. Barron became President, Chief Executive Officer and a director of NuStar GP, LLC and NuStar GP Holdings in January 2014. He served as Executive Vice President and General Counsel of NuStar GP, LLC and NuStar GP Holdings from February 2012 until his promotion in January 2014. From April 2007 to February 2012, he served as Senior Vice President and General Counsel of NuStar GP, LLC and NuStar GP Holdings. Mr. Barron also served as Secretary of NuStar GP, LLC and NuStar GP Holdings from April 2007 to February 2009. He served as Vice President, General Counsel and Secretary of NuStar GP, LLC from January 2006 until April 2007 and as Vice President, General Counsel and Secretary of NuStar GP Holdings from March 2006 until his promotion in April 2007. He has been with NuStar GP, LLC since July 2003 and, prior to that, was with Valero Energy from January 2001 to July 2003.
Mr. Bates became a director of NuStar GP, LLC in April 2006. He served as President and CEO of the Southwest Research Institute from 1997 until October 2014 and continues to serve as a director and as President Emeritus of the Southwest Research Institute. Mr. Bates also serves as a director of Signature Science L.L.C., Broadway Bank and Broadway Bankshares, Inc. He served as Chairman or Vice Chairman of the board of directors of the Federal Reserve Bank of Dallas’ San Antonio Branch from January 2005 through December 2009.
Mr. Hill became a director of NuStar GP, LLC in July 2004. From February 2001 through May 2004, he served as a consultant to El Paso Corporation. Prior to that, he served as President and CEO of Coastal Refining and Marketing Company. In 1978, Mr. Hill was named as Senior Vice President of the Coastal Corporation and President of Coastal States Crude Gathering. In 1971, he began managing Coastal’s NGL business. Previously, Mr. Hill worked for Amoco and Mobil.
Mr. Munch became a director of NuStar GP, LLC in January 2016. He served as General Manager and Head of Corporate & Investment Banking of Mizuho Bank, Ltd. from 2006 to 2013 and as Deputy General Manager, Origination, of Mizuho Bank, Ltd. from 2005 to 2006. Prior to his service with Mizuho Bank Ltd., Mr. Munch also served in several senior management positions with Canadian Imperial Bank of Commerce and CIBC World Markets from 1980 to 2001 and Fidelity Union Bancorporation (now Wells Fargo) from 1973 to 1980.
Mr. Rosier became a director of NuStar GP, LLC in March 2013. He has been the President and Chief Executive Officer of McLane Company, Inc., a leading supply chain services company and subsidiary of Berkshire Hathaway, Inc., since February 1995. Mr. Rosier has been with McLane Company, Inc. since 1984, serving in various senior management positions prior to his current position. Mr. Rosier also has served as a director of NVR, Inc. since December 2008. He was formerly a director of Tandy Brands Accessories, Inc. from February 2006 to October 2011, serving as the lead director from October 2009 to October 2010.
Ms. Brown became Executive Vice President and Chief Administrative Officer of NuStar GP, LLC and NuStar GP Holdings in April 2013. She served as Executive Vice President - Administration of NuStar GP, LLC and NuStar GP Holdings from February 2012 until her promotion in April 2013. Ms. Brown served as Senior Vice President - Administration of NuStar GP, LLC from April 2008 through February 2012. She served as Senior Vice President - Corporate Communications of NuStar GP, LLC from April 2007 through April 2008. Prior to her service to NuStar GP, LLC, Ms. Brown served as Senior Vice President - Corporate Communications for Valero Energy from September 1997 to April 2007.
Mr. Shoaf became Executive Vice President and Chief Financial Officer of NuStar GP, LLC and NuStar GP Holdings in January 2014. He served as Senior Vice President and Controller of NuStar GP, LLC and NuStar GP Holdings from February 2012 until his promotion in January 2014. Mr. Shoaf served as Vice President and Controller of NuStar GP, LLC from July 2005 to February 2012 and Vice President and Controller of NuStar GP Holdings from March 2006 until February 2012. He served as Vice President - Structured Finance for Valero Corporate Services Company, a subsidiary of Valero Energy, from 2001 until joining NuStar GP, LLC.
Mr. del Alamo became Senior Vice President and Controller of NuStar GP, LLC and NuStar GP Holdings in July 2014. Prior thereto, he served as Vice President and Controller of NuStar GP, LLC and NuStar GP Holdings since January 2014. He served as Vice President and Assistant Controller of NuStar GP, LLC from July 2010 until his promotion in January 2014. From April 2008 to July 2010 he served as Assistant Controller of NuStar GP, LLC. Prior to his service at NuStar GP, LLC, Mr. del Alamo served as Director-Sarbanes Oxley Compliance for Valero Energy.
Mr. Oliver became Senior Vice President - Marketing and Business Development of NuStar GP, LLC and NuStar GP Holdings in May 2014. Prior thereto, he served as Senior Vice President - Business and Corporate Development of NuStar GP, LLC and NuStar GP Holdings since March 2011. He served as Senior Vice President - Marketing and Business Development of NuStar GP, LLC and NuStar GP Holdings from May 2010 to March 2011 and as Vice President - Marketing and Business Development of NuStar GP, LLC from October 2008 until May 2010 and of NuStar GP Holdings from December 2009 until May 2010. Prior to that, Mr. Oliver served as Vice President for NuStar Marketing LLC. Previously, Mr. Oliver served as Vice President - Product Supply & Distribution for Valero Energy from May 1997 to July 2007.
Ms. Perry became Senior Vice President, General Counsel-Corporate & Commercial Law and Corporate Secretary of NuStar GP, LLC and NuStar GP Holdings in January 2014. She served as Vice President, Assistant General Counsel and Corporate Secretary of NuStar GP, LLC and as Corporate Secretary of NuStar GP Holdings from February 2010 until her promotion in January 2014. From June 2005 to February 2010 she served as Assistant General Counsel and Assistant Secretary of NuStar GP, LLC and, from March 2006 to February 2010, Assistant Secretary of NuStar GP Holdings. Prior to her service at NuStar GP, LLC, Ms. Perry served as Counsel to Valero Energy.
Ms. Thompson became Senior Vice President, General Counsel-Litigation, Regulatory & Environmental of NuStar GP, LLC and NuStar GP Holdings in January 2014. She served as Vice President, Assistant General Counsel and Assistant Secretary of NuStar GP, LLC from February 2010 until her promotion in January 2014. From May 2007 to February 2010 she served as Assistant General Counsel and Assistant Secretary of NuStar GP, LLC. Prior to her service at NuStar GP, LLC, Ms. Thompson served as Managing Counsel to Valero Energy.
Mr. Truby became Senior Vice President - Operations of NuStar GP, LLC in February 2013 and of NuStar GP Holdings in November 2015. Prior thereto, he served as Vice President - Pipeline Operations of NuStar GP, LLC since April 2012 and as Vice President - Health, Safety and Environmental of NuStar GP, LLC from January 2012 until April 2012. Previously he served as Vice President and General Manager of NuStar GP, LLC’s former San Antonio Refinery from May 2011 until January 2012 and led NuStar GP, LLC’s East Region from November 2009 until May 2011.
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 NuStar Energy’s equity securities to file certain reports with the Securities and Exchange Commission (SEC) concerning their beneficial ownership of NuStar Energy’s equity securities. We believe that our directors, executive officers and greater than 10% unitholders have filed all Section 16(a) reports by the applicable deadlines with respect toeach reporting period. For the year ended December 31, 2017.2022, 11,364 restricted units vested and 10,396 restricted units were forfeited related to our international employees.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL OFFICERSSTATEMENTS – (Continued)
A summary of our equity-classified restricted unit awards is as follows:
| | | | | | | | | | | | | | | | | |
| Measured at Grant Date Fair Value | | | | | | |
| Number of Units | | Weighted-Average Fair Value Per Unit | | | | | | |
| Nonvested units as of January 1, 2020 | 1,284,492 | | | $ | 27.48 | | | | | | | |
| | | | | | | | | |
| Granted | 1,454,998 | | | 12.10 | | | | | | | |
| Vested | (374,847) | | | 28.47 | | | | | | | |
| Forfeited | (30,749) | | | 26.75 | | | | | | | |
| Nonvested units as of December 31, 2020 | 2,333,894 | | | 17.70 | | | | | | | |
| Granted | 1,049,081 | | | 16.28 | | | | | | | |
| Vested | (630,888) | | | 20.07 | | | | | | | |
| Forfeited | (102,339) | | | 14.28 | | | | | | | |
| Nonvested units as of December 31, 2021 | 2,649,748 | | | 16.57 | | | | | | | |
| Granted | 1,206,824 | | | 16.09 | | | | | | | |
| Vested | (738,701) | | | 17.79 | | | | | | | |
| Forfeited | (125,078) | | | 16.23 | | | | | | | |
| Nonvested units as of December 31, 2022 | 2,992,793 | | | 16.08 | | | | | | | |
The total fair value of our equity-classified restricted unit awards vested for the years ended December 31, 2022, 2021 and 2020 was $11.9 million, $10.3 million and $4.6 million, respectively. We issued 531,637, 460,076 and 275,146 common units in connection with these award vestings, net of employee tax withholding requirements, for the years ended December 31, 2022, 2021 and 2020, respectively. Unrecognized compensation cost related to our equity-classified employee awards totaled $45.6 million as of December 31, 2022, which we expect to recognize over a weighted-average period of 3.7 years.
Performance Awards
Performance awards are issued to certain of our key employees and represent either rights to receive our common units or cash upon achieving performance measures for the performance period established by the NuStar GP, LLC has adopted a Code of Ethics for Senior Financial Officers that applies to NuStar GP, LLC’s principal executive officer, principal financial officer and controller. A copyCompensation Committee (the Compensation Committee). Achievement of the code is available on NuStar Energy’s websiteperformance measures determines the rate at www.nustarenergy.com. This code chargeswhich the senior financial officers with responsibilities regarding honest and ethical conduct, the preparation and qualityperformance awards convert into our common units or cash, which ranges from zero to 200% for certain awards.
Performance awards vest in three annual increments (tranches), based upon our achievement of the disclosures in documents and reports we file with or submit to the SEC, compliance with applicable laws, rules and regulations, adherence to the code and reporting of violations of the code. We also have a Code of Business Conduct and Ethics that applies to all of our employees and directors.
CORPORATE GOVERNANCE
AUDIT COMMITTEE
The Audit Committee reviews and reports to the Board on various auditing and accounting matters, including the quality, objectivity and performance of NuStar Energy’s internal and external accountants and auditors, the adequacy of its financial controls and the reliability of financial information reported to the public. The Audit Committee also monitors NuStar Energy’s compliance with environmental laws and regulations. The Board has adopted a written charter for the Audit Committee, a copy of which is available on NuStar Energy’s website at www.nustarenergy.com. The members of the Audit Committee are Mr. Bates (Chairman), Mr. Hill, Mr. Munch and Mr. Rosier. The Board has determined that Mr. Bates is an “audit committee financial expert” (as defined by the SEC), and that each member of the Audit Committee is “independent” as that term is used in the NYSE Listing Standards and described below in Item 13. The Audit Committee met eight times during 2017. For further information, see the Audit Committee Report below.
AUDIT COMMITTEE REPORT
Management of NuStar GP, LLC is responsible for NuStar Energy’s internal controls and the financial reporting process. KPMG LLP (KPMG), NuStar Energy’s independent registered public accounting firm for the year ended December 31, 2017, is responsible for performing an independent audit of NuStar Energy’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (PCAOB) and generally accepted auditing standards, and an audit of NuStar Energy’s internal control over financial reporting in accordance with the standards of the PCAOB, and issuing a report thereon. The Audit Committee monitors and oversees these processes and approves the selection and appointment of NuStar Energy’s independent registered public accounting firm and recommends the ratification of such selection and appointment to the Board.
The Audit Committee has reviewed and discussed NuStar Energy’s audited consolidated financial statements with management and KPMG. The Audit Committee has discussed with KPMG the matters required to be discussed by Auditing Standard 1301, “Communications with Audit Committees,” issued by the PCAOB. The Audit Committee has received written disclosures and the letter from KPMG required by applicable requirements of the PCAOB concerning independence and has discussed with KPMG its independence.
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 NuStar Energy be included in NuStar Energy’s Annual Report on Form 10-K for the year ended December 31, 2017.
Members of the Audit Committee:
J. Dan Bates (Chairman)
Dan J. Hill
Robert J. Munch
W. Grady Rosier
RISK OVERSIGHT
Although it is the job of management to assess and manage our risk, the Board of Directors and its Audit Committee (each where applicable) discuss the guidelines and policies that govern the process by which risk assessment and management is undertaken and evaluate reports from various functions with the management team on risk assessment and management. The Board interfaces regularly with management and receives periodic reports that include updates on operational, financial, legal and risk management matters. The Audit Committee assists the Board in oversight of the integrity of NuStar Energy’s financial statements and NuStar Energy’s compliance with legal and regulatory requirements, including those related to the health, safety and environmental performance of our company. The Audit Committee also reviews and assesses the performance of NuStar Energy’s internal audit function and its independent auditors. The Board receives regular reports from the Audit Committee. For a description of our oversight and evaluation of compensation risk, see “Evaluation of Compensation Risk” in Item 11 below.
ITEM 11. EXECUTIVE COMPENSATION
COMPENSATION COMMITTEE
The Compensation Committee reviews and reports to the Board on matters related to compensation strategies, policies and programs, including certain personnel policies and policy controls, management development, management succession and benefit programs. The Compensation Committee also conducts periodic reviews of director compensation and makes recommendations to the Board regarding director compensation. The Compensation Committee also approves and administers NuStar Energy’s equity compensation plans and incentive bonus plan. The Board has adopted a written charter for the Compensation Committee, a copy of which is available on NuStar Energy’s website at www.nustarenergy.com. The members of the Compensation Committee are Mr. Hill (Chairman), Mr. Bates, Mr. Munch and Mr. Rosier, none of whom is a current or former employee or officer of NuStar GP, LLC and each of whom has been determined by the Board to be “independent,” as described below in Item 13. The Compensation Committee met four times during 2017.
COMPENSATION COMMITTEE REPORT
The Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis with management. Based on its review and discussion and such other matters the Compensation Committee deemed relevant and appropriate, the Compensation Committee recommended to the Board that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.
Members of the Compensation Committee:
Dan J. Hill (Chairman)
J. Dan Bates
Robert J. Munch
W. Grady Rosier
COMPENSATION DISCUSSION AND ANALYSIS
EXECUTIVE COMPENSATION PHILOSOPHY
Our philosophy for compensating our named executive officers (NEOs) is based on the belief that a significant portion of executive compensation should be incentive-based and determined by both the performance of NuStar Energy and the executive’s individual performance objectives. Our executive compensation programs are designed to accomplish the following long-term objectives:
increase value to unitholders, while practicing good corporate governance;
support our business strategy and business plan by clearly communicating what is expected of executives with respect to goals and results;
provide the Compensation Committee with the flexibility to respond to the continually changing environment in which NuStar Energy operates;
align executive incentive compensation with NuStar Energy’s short- and long-term performance results; and
provide market-competitive compensation and benefits to enable us to recruit, retain and motivate the executive talent necessary to produce sustainable growth for our unitholders.
Compensation for our NEOs primarily consists of base salary, an annual incentive bonus and long-term, equity-based incentives, which we refer to as “Total Direct Compensation.” Our NEOs participate in the same group benefit programs available to our salaried employees in the United States, and each NEO’s incentive bonus is awarded in accordance with the same bonus plan and metric that we use for each of our other employees. In addition, as discussed under “Post-Employment Benefits” below, our NEOs may participate in certain non-qualified, retirement-related programs. Our NEOs do not have employment or severance agreements, other than the change of control severance agreements described under “Potential Payments Upon Termination or Change of Control” in this Item 11. The Compensation Committee targets base salary for our NEOs, as well as annual incentive bonus and long-term incentive opportunities (expressed, in each case, as a percentage of base salary), with reference to prevailing practices of our peer companies and information from survey sources. In determining total compensation, as well as each component thereof, we consider the unique responsibilities of each individual’s position, as well as his or her experience and performance, together with the market information.
Our NEOs for the year ended December 31, 2017 were:
Bradley C. Barron, President and Chief Executive Officer (CEO);
Thomas R. Shoaf, Executive Vice President and Chief Financial Officer;
Mary Rose Brown, Executive Vice President and Chief Administrative Officer;
Daniel S. Oliver, Senior Vice President-Marketing and Business Development; and
Michael Truby, Senior Vice President-Operations.
ADMINISTRATION OF EXECUTIVE COMPENSATION PROGRAMS
Our executive compensation programs are administered by our Board’s Compensation Committee. The Compensation Committee is composed of independent directors who are not participants in our executive compensation programs. Policies adopted by the Compensation Committee are implemented by our Human Resources department.
The Compensation Committee considers market trends in compensation, including the practices of identified competitors, and the alignment of the compensation program with NuStar Energy’s strategy. Specifically, for our NEOs, the Compensation Committee:
| |
�� | establishes and approves target compensation levels for each NEO; |
approves company performance measures and goals;
determines the mix between cash and equity compensation, short-term and long-term incentives and benefits;
verifies the achievement of previously established performance goals; and
approves the resulting cash or equity awards to our NEOs.
In making determinations about Total Direct Compensation for our NEOs, the Compensation Committee takes into account a number of factors, including:
the competitive market for talent;
compensation paid at peer companies;
industry-wide trends;
NuStar Energy’s performance;
the particular NEO’s role, responsibilities, experience and performance; and
retention.
The Compensation Committee also considers other equitable factors such as the role, contribution and performance of an individual relative to his or her peers at the company. The Compensation Committee does not assign specific weight to these factors, but rather makes a subjective judgment taking all of these factors into account.
During 2017, the Compensation Committee retained Energy Partners Pay Advisors (EPPA) as its independent compensation consultant for expertise and guidance with respect to executive compensation matters. In its role as advisor to the Compensation Committee, EPPA was retained directly by the Compensation Committee, which has the authority to select, retain and/or terminate its relationship with a consulting firm. The Compensation Committee determined that there are no conflicts of interest between the company, the Compensation Committee and EPPA because: EPPA provides no other services to NuStar Energy; EPPA has policies in place to prevent a conflict of interest, including a policy that no employee of EPPA may own NuStar Energy units; and there is no business or personal relationship between EPPA’s consultant and any of NuStar Energy’s officers or directors.
Selection of Compensation Comparative Data
To establish compensation for each of the NEOs, the Compensation Committee consults with management and EPPA and considers compensation provided by certain peer companies when evaluating competitive levels of compensation. The competitive data regarding the peer companies is derived from their respective publicly filed annual proxy statements or Annual Reports on Form 10-K.
Following the sale of our remaining 50% interest in the asphalt business during 2014, the Compensation Committee consulted with management and the Compensation Committee’s independent compensation consultant at the time, reevaluated our peer group and removed the independent refining companies that were previously included in our peer group (the 2014 Compensation Comparative Group). Since that time, several of the companies in the peer group have merged, consolidated or otherwise no longer publicly disclose comprehensive executive compensation information. Due to the changes in the midstream and logistics industry since 2014, the Compensation Committee consulted with management and EPPA and updated our peer group again in 2017 to: (1) remove entities that have been acquired or otherwise no longer publicly disclose comprehensive executive compensation information; (2) remove sponsored master limited partnerships (MLPs) for which the executives’ primary responsibility relates to the sponsor’s operations rather than the operations of the MLP; (3) add other comparable midstream and/or logistics entities; and (4) recognize the scope of responsibility of executive teams that manage two public companies, similar to NuStar Energy and NuStar GP Holdings (the Current Compensation Comparative Group).
The tables below list: (1) the companies in the 2014 Compensation Comparative Group after giving effect to all merger or consolidation transactions that closed prior to December 31, 2017 (with the relevant transactions described in the footnote); and (2) the companies in the Current Compensation Comparative Group.
2014 Compensation Comparative Group
|
| |
Company (1)
| Ticker |
1. Andeavor Logistics LP (previously known as Tesoro Logistics LP) | ANDX |
2. Arc Logistics Partners LP | ARCX |
3. Boardwalk Pipeline Partners, LP | BWP |
4. Buckeye Partners, L.P. | BPL |
5. Enable Midstream Partners, LP | ENBL |
6. Enbridge Energy Partners, L.P. | EEP |
7. Energy Transfer Partners, L.P. | ETP |
8. EnLink Midstream Partners, LP | ENLK |
9. Enterprise Products Partners L.P. | EPD |
10. Genesis Energy, L.P. | GEL |
11. Holly Energy Partners, L.P. | HEP |
12. Magellan Midstream Partners, L.P. | MMP |
13. MPLX LP | MPLX |
14. Phillips 66 Partners LP | PSXP |
15. Plains All American Pipeline, L.P. | PAA |
16. Valero Energy Partners LP | VLP |
(1) The following companies have been removed from the 2014 Compensation Comparative Group originally established in July 2014 as a result of the transactions described in this footnote: Access Midstream Partners, L.P. merged with Williams Partners L.P. in February 2015; Atlas Pipeline Partners, L.P. was acquired by Targa Resources Partners LP in February 2015; Kinder Morgan Energy Partners, L.P. was acquired by Kinder Morgan, Inc. in November 2014; MarkWest Energy Partners, L.P. was acquired by MPLX LP in December 2015; Regency Energy Partners LP was acquired by Energy Transfer Partners, L.P. in April 2015; Targa Resources Partners LP was acquired by Targa Resources Corp. in February 2016; Energy Transfer Partners, L.P. merged with Sunoco Logistics Partners L.P. in April 2017; and Western Refining Logistics, LP was acquired by Andeavor Logistics LP in October 2017.
Current Compensation Comparative Group
|
| |
Company | Ticker |
1. Boardwalk Pipeline Partners, LP | BWP |
2. Buckeye Partners, L.P. | BPL |
3. Calumet Specialty Products Partners, L.P. | CLMT |
4. Enable Midstream Partners, LP | ENBL |
5. Enbridge Energy Partners, L.P./Enbridge Energy Management, L.L.C. | EEP/EEQ |
6. Energy Transfer Partners, L.P. /Energy Transfer Equity, L.P. (1)
| ETP/ETE |
7. EnLink Midstream Partners, LP/EnLink Midstream, LLC | ENLK/ENLC |
8. Enterprise Products Partners L.P. | EPD |
9. Genesis Energy, L.P. | GEL |
10. Holly Energy Partners, L.P. | HEP |
11. Magellan Midstream Partners, L.P. | MMP |
12. MPLX LP | MPLX |
13. ONEOK, Inc. (includes operations of ONEOK Partners, L.P.) | OKE |
14. SemGroup Corporation | SEMG |
15. Sunoco Logistics Partners L.P. (1)
| SXL |
16. Targa Resources Corp. (includes operations of Targa Resources Partners LP) | TRGP |
| |
(1) | Although Energy Transfer Partners, L.P. and Sunoco Logistics Partners L.P. merged in April 2017, both entities are listed as separate peer companies in the Current Compensation Comparative Group because their executive compensation for the year ended December 31, 2016 was publicly disclosed separately and considered along with the compensation of the other peer companies as part of the evaluation of our 2017 compensation. |
At the Compensation Committee’s request, EPPA also reviews survey data reported on a position-by-position basis to obtain additional information regarding compensation of comparable positions. The survey data consists of general industry data for specific executive positions reported in published executive compensation surveys. We refer to the competitive survey data, together with the 2014 Compensation Comparative Group data or the Current Compensation Comparative Group data, as applicable, as the “Compensation Comparative Data.”
Process and Timing of Compensation Decisions
The Compensation Committee reviews and approves all compensation of the NEOs. The CEO develops recommendations for the compensation of the other NEOs in consultation with our Human Resources department and with EPPA. In making these recommendations, the CEO considers the Compensation Comparative Data and evaluates the individual performance of each NEO and their respective contributions to NuStar Energy. The recommendations are then reviewed by the Compensation Committee, which may accept the recommendations or may make adjustments to the recommended compensation based on the Compensation Committee’s assessment of the individual’s performance and contributions to NuStar Energy.
As required by the Compensation Committee’s charter, the CEO’s compensation is reviewed and approved by the Compensation Committee based on the Compensation Comparative Data and the Compensation Committee’s independent evaluation of the CEO’s contributions to NuStar Energy’s performance.
Each July, the Compensation Committee reviews each NEO’s Total Direct Compensation, including base salary and the target levels of annual incentive and long-term incentive compensation. The review includes a comparison with competitive market data provided by EPPA (as described above), an evaluation of the Total Direct Compensation of the NEOs from an internal equity perspective and a review of reports on the compensation history of each NEO. Based on these reviews and evaluations, the Compensation Committee establishes annual salary rates for each NEO for the upcoming 12-month period and sets target levels of annual incentive and long-term incentive compensation. Although the target levels are established in July, the long-term incentives are reviewed again at the time of grant, typically in the fourth quarter for restricted units and in the first quarter for performance units. The Compensation Committee also may review salaries or grant long-term incentive awards at other times during the year because of new appointments, promotions or other extraordinary circumstances.
The following table summarizes the typical timing of some of our significant compensation events.
|
| |
Event | Timing |
- Establish financial performance objectives for the current year’s annual incentive bonus
- Evaluate achievement of the bonus metric for the prior year
- Review prior year financial performance for performance units
- Grant performance units for the current year
| First quarter |
- Review NEO base salaries and targets for annual incentive bonus and long-term incentive grants for the current year | Third quarter |
- Grant restricted units to employees, including the NEOs
- Grant restricted units to non-employee directors pursuant to the director compensation program
- Set meeting dates for action by the Compensation Committee for the upcoming year
| Fourth quarter |
Additional information regarding the timing of the 2017 long-term incentive grants is discussed below under “Restricted Units” and “Performance Units.”
ELEMENTS OF EXECUTIVE COMPENSATION
Compensation for our NEOs primarily consists of the following elements, which we refer to as Total Direct Compensation:
|
| | | |
| Element | Form | Purpose |
Fixed | Base Salary | Cash | - Foundation of the executive compensation program
- Provides a fixed level of competitive pay
- Reflects the individual’s primary duties and responsibilities
- Foundation for incentive opportunities and benefit levels
|
At-Risk | Annual Incentive Bonus | Cash | - Focus NEOs on improving performance |
At-Risk | Long-Term Equity-Based Incentives: | Units | - Directly tie NEO financial reward opportunities with the rewards to unitholders, as measured by long-term unit price performance and payment of distributions |
- Restricted Units | - Time-vesting award focused on retention and increasing ownership levels |
- Performance Units | - Performance-vesting award focused on attainment of objective performance measure |
We also offer group medical and other insurance benefits to provide our employees (including our NEOs) affordable coverage at group rates, as well as pension benefits that reward continued service and a thrift plan that provides a tax-advantaged savings opportunity.
Relative Size of Primary Elements of Compensation
In setting compensation, the Compensation Committee considers the aggregate amount of compensation payable to each NEO and the form of the compensation. The Compensation Committee seeks to achieve the appropriate balance between salary, cash rewards earned for the achievement of company and personal objectives, and long-term incentives that align the interests of our NEOs with those of our unitholders. The size of each element is based on competitive market practices, as well as company and individual performance.
As illustrated by the chart below, the level of at-risk incentive compensation typically increases in relation to an NEO’s responsibilities, with the level of incentive compensation for more senior executive officers being a greater percentage of Total Direct Compensation than for less senior executives. The Compensation Committee believes that tying a significant portion of an NEO’s incentive compensation to NuStar Energy’s performance more closely aligns the NEO’s interests with those of our unitholders.
Because we place such a large percentage of our Total Direct Compensation at risk in the form of variable pay (i.e., annual and long-term incentives), the Compensation Committee does not adjust current compensation based upon realized gains or losses from prior incentive awards. For example, we will not reduce the size of a target long-term incentive grant in a particular year solely because NuStar Energy’s unit price performed well during the immediately preceding years. We believe that adopting a policy of making such adjustments would penalize management’s current compensation for NuStar Energy’s prior success.
Individual Performance and Personal Objectives
The Compensation Committee evaluates our NEOs’ individual performance and personal objectives with input from our CEO. Our CEO’s performance is evaluated by the Compensation Committee in consultation with other members of the Board.
Assessment of individual performance may include objective criteria, but is a largely subjective process. The criteria used to measure an individual’s performance may include use of quantitative criteria (e.g., execution of projects within budget, improving an operating unit’s profitability, or timely completion of an acquisition or divestiture), as well as more qualitative factors, such as the NEO’s ability to lead, communicate and successfully adhere to NuStar Energy’s core values (i.e., environmental and workplace safety, integrity, work commitment, effective communication and teamwork). There are no specific weights given to any of these various elements of individual performance.
The Compensation Committee uses its evaluation of individual performance to supplement the objective compensation criteria and adjust an NEO’s recommended compensation. For example, although an individual’s indicated bonus may be calculated to be $100,000 based on NuStar Energy’s performance, the individual’s performance evaluation might result in a reduction or increase in that amount.
Base Salaries
The Compensation Committee reviews the base salaries for our NEOs annually based on recommendations by our CEO, with input from EPPA and our Human Resources department. Our CEO’s base salary is reviewed and approved by the Compensation Committee based on its review of recommendations by EPPA, our Chairman and our Human Resources department.
The competitiveness of base salaries for each NEO’s position is determined by an evaluation of the Compensation Comparative Data described above. Base salaries may be adjusted to achieve what is determined to be a reasonably competitive level or to reflect promotions, the assignment of additional responsibilities, individual performance or the performance of NuStar Energy.
Following a detailed analysis performed in July 2014 by the Compensation Committee’s independent compensation consultant at the time, for 2015 and 2016 base salaries the Compensation Committee considered, among other factors, the Consumer Price Index, the average base salary increase anticipated by nationwide compensation surveys, the increases required by NuStar Energy’s union contracts and the anticipated increases by other local companies and raised the base salaries of each of the NEOs effective on each of July 1, 2015 and July 1, 2016 to remain competitive.
During July 2017, EPPA performed a comprehensive review of our NEOs’ Total Direct Compensation. After consultation with EPPA, the Chairman (in the case of the CEO’s base salary) and the CEO (in the case of the base salaries for each other NEO), the Compensation Committee raised the base salaries of each of the NEOs effective July 1, 2017 to remain competitive. The July 1, 2017 increases and the December 31, 2017 base salaries for each of the NEOs are presented in the table below.
|
| | | | | | | | |
| Name | Annualized Base Salary at December 31, 2017 ($) | July 1, 2017 Increase to Prior Annualized Salary ($) |
| Barron | 592,250 |
| | | 17,250 |
| | |
| Shoaf | 360,200 |
| | | 10,500 |
| | |
| Brown | 388,000 |
| | | 11,300 |
| | |
| Oliver | 328,000 |
| | | 9,700 |
| | |
| Truby | 305,000 |
| | | 24,400 |
| | |
Annual Incentive Bonus
Our NEOs participate in the same annual incentive program in which all of our domestic employees participate. Under our annual bonus plan, participants can earn annual incentive bonuses based on the following three factors:
The individual’s position, which is used to determine a targeted percentage of annual base salary that may be awarded as incentive bonus. Generally, the target amount for the NEOs is set following the analysis of market practices in the Compensation Comparative Group with reference to the median bonus target available to comparable executives in those companies;
NuStar Energy’s attainment of specific quantitative financial goals, which are established by the Compensation Committee during the first quarterperformance periods that end on December 31 of each applicable year. Therefore, the year; and
A discretionary evaluation byperformance awards are not considered granted for accounting purposes until the Compensation Committee has set the performance measures for each tranche of both NuStar Energy’sawards. Performance unit awards are equity-classified awards measured at the grant date fair value. In addition, since the performance and,unit awards granted do not receive DERs, the grant date fair value of these awards is reduced by the per unit distributions expected to be paid to common unitholders during the vesting period. Performance cash awards are accounted for as a liability but may be settled in common units. We record compensation expense ratably for each vesting tranche over its requisite service period (one year) if it is probable that the specified performance measures will be achieved. Additionally, changes in the caseactual or estimated outcomes that affect the quantity of performance awards expected to be converted into common units or paid in cash, are recognized as a cumulative adjustment. Performance units vested relate to the performance for the performance period ended December 31 of the NEOs, the individual’s performance.previous year.
In July 2015, after consultation with the Compensation Committee’s independent compensation consultant at the time and the Chairman, the Compensation Committee raised the annual incentive bonus target for Mr. Barron from 90% to 100%. The Compensation Committee did not make any changes to the annual incentive bonus target for Mr. Barron during 2016 or for any
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
A summary of our NEOs’ Total Direct Compensation,performance awards is shown below:
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Performance Unit Awards |
| | | | | Granted for Accounting Purposes |
| Performance Cash Awards | | Total Performance
Unit Awards Granted | | Performance Unit Awards | | Weighted-Average Grant Date Fair Value per Unit |
| (Thousands of Dollars) | | | | | | |
| Outstanding as of January 1, 2020 | $ | — | | | 161,561 | | | 74,439 | | | $ | 28.01 | |
| Granted | 2,167 | | | — | | | 57,448 | | | 13.21 | |
| Performance adjustment (a) | — | | | 72,951 | | | 72,951 | | | 28.01 | |
| Vested | — | | | (147,390) | | | (147,390) | | | 28.01 | |
| Outstanding as of December 31, 2020 | 2,167 | | | 87,122 | | | 57,448 | | | 13.21 | |
| Granted | 2,254 | | | 4,021 | | | 33,695 | | | 15.79 | |
| | | | | | | |
| Vested (b) | (672) | | | (53,427) | | | (53,427) | | | 13.21 | |
| Forfeitures | (51) | | | (4,021) | | | (4,021) | | | 13.21 | |
| Outstanding as of December 31, 2021 | 3,698 | | | 33,695 | | | 33,695 | | | 15.79 | |
| Granted | 2,954 | | | — | | | — | | | — | |
| Performance adjustment (a) | — | | | 14,839 | | | 14,839 | | | 15.79 | |
| Vested (b) | (1,507) | | | (48,534) | | | (48,534) | | | 15.79 | |
| | | | | | | |
| Outstanding as of December 31, 2022 | $ | 5,145 | | | — | | | — | | | — | |
(a) For the Compensation Committee raised the annual incentive bonus target for Mr. Truby from 50% to 55% and retained the existing annual incentive bonus targets for all other NEOs. The following table shows each NEO’s annual incentive bonus target for the fiscal year ended December 31, 2017 (expressed as a percent2020, common units granted and issued upon vesting resulted from performance units earned at 198% of base salary paid).the 2019 target. For the year ended December 31, 2022, common units granted and issued upon vesting resulted from performance units earned at 150% of the 2021 target.
(b) For the years ended December 31, 2022 and 2021, we settled performance cash awards with 137,931 and 43,733 common units, respectively, and issued 84,778 and 26,704 common units, net of employee tax withholding requirements, respectively. |
| |
Name | Annual Incentive Bonus Target
(% of base salary)
|
Barron | 100 |
Shoaf | 60 |
Brown | 60 |
Oliver | 55 |
Truby | 55 |
DeterminationThe total fair value of Annual Incentive Target Opportunitiesour performance unit awards vested for the years ended December 31, 2022, 2021 and 2020 was $0.8 million, $0.8 million and $4.2 million, respectively. For the years ended December 31, 2022, 2021, and 2020 we issued 29,840, 31,366 and 93,440 common units in connection with the performance unit award vestings, net of employee tax withholding requirements, respectively.
As illustrated
On January 26, 2023, we settled performance cash awards in common units, and together with the performance unit awards, we issued 82,353 common units, net of employee tax withholding requirements, respectively.
Unit Awards
Unit awards are equity-classified awards of fully vested common units. We accrued compensation expense in 2021 and 2019 that was paid in unit awards in the table above, each NEO has an annual incentive opportunity generally based on a stated percentage of his or her salary paid that year. The target amount is awarded for achieving a 100% score on our stated financial goal under the annual bonus plan. For example, in a year with a 100% score, an NEO paid $200,000 with a target annual incentive opportunity equal to 60% of his base salary paid would be eligible to receive a bonus of $120,000 based on those financial goals.
Once the financial goals have been reviewed and measured, the Compensation Committee has the authority to exercise its discretion in evaluating NuStar Energy’s performance. In exercising this discretionary judgment, the Compensation Committee considers such relevant performance factors as growth, attainment of strategic objectives, acquisitions and divestitures, safety and environmental compliance, as well as other considerations. This discretionary judgment may result in an increase or decrease to the aggregate earned award for all employees that is based upon the attainment of NuStar Energy’s financial goals.
The CEO develops individual incentive bonus recommendations for the other NEOs based upon the methodology described above. In addition, both the CEO and the Compensation Committee may make adjustments to the recommended incentive bonus amounts based upon an assessment of an individual’s performance and contributions to NuStar Energy. The CEO and the Compensation Committee also review and discuss each NEO’s bonus on a case-by-case basis, considering such factors as teamwork, leadership, individual accomplishments and initiative, and may adjust the bonus awarded to a specific NEO to reflect these factors.
The bonus target for the CEO is decided solely by the Compensation Committee, and the Compensation Committee may make discretionary adjustments to the calculated level of bonus for the CEO based upon its independent evaluationfirst quarters of the CEO’s performance and contributions.
Company Performance Objectives
As in prior years, our annual incentive bonus for 2017 was designed to focus our NEOs on improving NuStar Energy’s distributable cash flow (DCF). Inrespective subsequent years. We base the MLP investment community, DCF is widely regarded as a significant indicatornumber of operating performance. As such, the Compensation Committee believes the measure appropriately aligns our management’s interest with our unitholders’ interest.
For 2017, the Compensation Committee determined that a bonus pool for all employees would be established based on DCF such that employees would receive a 100% bonus for 2017 if NuStar Energy achieved a target distribution coverage ratio (DCR) of 1.01 times. After achieving a 100% bonus, incremental DCF earned would be shared between the bonus pool and NuStar Energy until employees achieve a 200% bonus. If DCR for 2017 is below 1.00 times, the bonus pool would be reduced dollar-for-dollar until a 1.00 times DCR is achieved or the pool is reduced to $0. The Compensation Committee has discretion to raise or lower the incentive opportunity resulting from this calculation by 25%. In addition, the budgeted DCF may be adjusted during the year in order to account for acquisitions or other significant changes not anticipated at the time the target was determined.
DCF and DCR are non-GAAP measures of performance. We derive DCF from our financial statements by adjusting our net income for depreciation and amortization expense, unrealized gains and losses arising from certain derivative contracts and other non-cash items, including non-cash gains or losses or impairment charges. We further adjust our earnings by (1) subtracting our aggregate annual reliability capital expenditures, (2) adding non-cash unit-based compensation expenses for awards that we intend to satisfy with the issuance of units upon vesting and (3) adding or subtracting, as applicable, certain cash receipts and disbursements not included in net income. DCR is determined by dividing DCF applicable to common limited partners by the distributions applicable to common limited partners.
Determination of Awards
Our executive officers, including our NEOs, did not receive cash bonuses for 2017. For the 2017 annual incentive bonus determination, the Compensation Committee reviewed NuStar Energy’s DCF against the established target of attaining a DCR of 1.01 times and considered NuStar Energy’s overall performance and the performance of each NEO. Based solely on our 2017 DCR results, our NEOs were not eligible to receive a bonus award for 2017 under the annual incentive bonus plan. The Compensation Committee recognized NuStar Energy’s significant accomplishments during 2017, including the successful acquisition of the Permian Crude System and NuStar Energy’s achievement of its best safety record in the history of the company, with only one employee recordable injury and zero lost-time injuries. The Compensation Committee also considered the strain on the business and the MLP sector generally from continued low crude oil prices and the further negative impact on NuStar Energy of several unexpected items, such as losses at seven facilities impacted by five hurricanes, losses resulting from unplanned turnarounds and downtime at customers’ refineries, a decline in results at our St. Eustatius terminal from under-utilization by an important customer there due to deteriorating conditions in Venezuela and the expense of an unanticipated reliability project on our Ammonia Pipeline.
After considering our 2017 DCR results and these additional factors, upon the recommendation of executive management (other than with respect to the CEO) and our Chairman (with respect to the CEO), the Compensation Committee decided not to award cash bonuses under the annual incentive bonus plan for any of our executive officers, including our NEOs, for 2017.
Long-Term Incentive Awards
We provide unit-based, long-term incentive compensation for employees, including our NEOs, and for our non-employee directors through our 2000 Long-Term Incentive Plan (as amended and restated from time to time, the 2000 LTIP). The 2000 LTIP provides for unit awards and a variety of unit-based awards, including unit options, restricted units and performance units. Long-term incentive awards vest over a period determined by the Compensation Committee, with performance units vesting upon the achievement of an objective performance goal.
Under the design of our long-term incentive awards, a target long-term incentive award opportunity expressed as a percentage of base salary is established for each plan participant, including each NEO. This percentage reflectsgranted on the fair value of the common units at the grant date. A summary of our unit awards is shown below:
| | | | | | | | | | | | | | | | | | | | |
| Date of Grant | | Grant Date Fair Value | | Unit Awards Granted | | Common Units Issued, Net of Employee Withholding Tax |
| | (Thousands of Dollars) | | | | |
| February 2022 | | $ | 4,645 | | | 280,685 | | | 186,190 | |
| February and March 2020 | | $ | 22,941 | | | 834,224 | | | 571,735 | |
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
23. INCOME TAXES
Components of income tax expense related to certain of our operations conducted through separate taxable wholly owned corporate subsidiaries were as follows:
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2022 | | 2021 | | 2020 |
| | (Thousands of Dollars) |
| Current: | | | | | |
| U.S. | $ | 3,558 | | | $ | 3,755 | | | $ | 36 | |
| Foreign | 272 | | | 221 | | | 2,415 | |
| Foreign withholding tax | 355 | | | 1,281 | | | — | |
| Total current | 4,185 | | | 5,257 | | | 2,451 | |
| | | | | |
| Deferred: | | | | | |
| U.S. | 341 | | | (93) | | | 300 | |
| Foreign | (1,287) | | | (531) | | | (621) | |
| Foreign withholding tax | — | | | (745) | | | 533 | |
| Total deferred | (946) | | | (1,369) | | | 212 | |
| | | | | |
| Income tax expense | $ | 3,239 | | | $ | 3,888 | | | $ | 2,663 | |
The difference between income tax expense recorded in our consolidated statements of income (loss) and income taxes computed by applying the applicable statutory federal income tax rate to income before income tax expense is due to the fact that the majority of our income is not subject to federal income tax due to our status as a limited partnership. We record a tax provision related to the amount of undistributed earnings of our foreign subsidiaries expected to be granted.repatriated.
The Compensation Committee didtax effects of significant temporary differences representing deferred income tax assets and liabilities were as follows:
| | | | | | | | | | | |
| December 31, |
| | 2022 | | 2021 |
| | (Thousands of Dollars) |
| Deferred income tax assets: | | | |
| Net operating losses | $ | 17,710 | | | $ | 20,005 | |
| | | |
| | | |
| | | |
| Capital loss | 3,714 | | | 3,735 | |
| Other | 793 | | | 625 | |
| Total deferred income tax assets | 22,217 | | | 24,365 | |
| Less: Valuation allowance | (21,573) | | | (23,718) | |
| Net deferred income tax assets | 644 | | | 647 | |
| | | |
| Deferred income tax liabilities: | | | |
| Property, plant and equipment | (3,534) | | | (11,884) | |
| Foreign withholding tax | (286) | | | (272) | |
| Other | (43) | | | (322) | |
| Total deferred income tax liabilities | (3,863) | | | (12,478) | |
| | | |
| Net deferred income tax liability | $ | (3,219) | | | $ | (11,831) | |
| | | |
| | | |
| | | |
| | | |
| | | |
As of December 31, 2022, our U.S. and foreign corporate operations have net operating loss carryforwards for tax purposes totaling $51.1 million and $23.3 million, respectively, which are subject to various limitations on use and expire in years 2032 through 2034 for U.S. losses and in years 2023 through 2033 for foreign losses. However, U.S. losses generated after December 31, 2017, totaling $5.2 million, can be carried forward indefinitely. As of December 31, 2022, our U.S. corporate operations
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
have a capital loss carryforward for tax purposes totaling $17.7 million, which is subject to limitations on use and expires in 2024.
As of December 31, 2022 and 2021, we have a valuation allowance of $21.6 million and $23.7 million, respectively, related to our deferred tax assets on net operating losses and capital losses. We estimate the amount of valuation allowance based upon our expectations of taxable income in the various jurisdictions in which we operate and the period over which we can utilize those future deductions. The valuation allowance reflects uncertainties related to our ability to utilize certain net operating loss carryforwards before they expire. In 2022, there was a $2.3 million decrease in the valuation allowance for the U.S. net operating loss and a $0.1 million increase in the foreign net operating loss valuation allowance due to changes in our estimates of the amount of loss carryforwards that will be realized, based upon future taxable income.
The realization of net deferred income tax assets recorded as of December 31, 2022 is dependent upon our ability to generate future taxable income in the United States. We believe it is more likely than not make any changesthat the net deferred income tax assets as of December 31, 2022 will be realized, based on expected future taxable income.
24. SEGMENT INFORMATION
Our reportable business segments consist of the pipeline, storage and fuels marketing segments. Our segments represent strategic business units that offer different services and products. We evaluate the performance of each segment based on its respective operating income, before general and administrative expenses and certain non-segmental depreciation and amortization expense. General and administrative expenses are not allocated to the individual long-term incentive target percentagesoperating segments since those expenses relate primarily to the overall management at the entity level. We are primarily engaged in the transportation, terminalling and storage of petroleum products and renewable fuels and the transportation of anhydrous ammonia. We also market petroleum products.
Results of operations for our NEOs servingthe reportable segments were as such during 2015follows:
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2022 | | 2021 | | 2020 |
| | (Thousands of Dollars) |
| Revenues: | | | | | |
| Pipeline | $ | 828,191 | | | $ | 762,238 | | | $ | 718,823 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Storage | 334,549 | | | 427,668 | | | 494,442 | |
| | | | | |
| Fuels marketing | 520,486 | | | 428,608 | | | 268,345 | |
| Consolidation and intersegment eliminations | (3) | | | (14) | | | (46) | |
| Total revenues | $ | 1,683,223 | | | $ | 1,618,500 | | | $ | 1,481,564 | |
| | | | | |
| Depreciation and amortization expense: | | | | | |
| Pipeline | $ | 178,802 | | | $ | 179,088 | | | $ | 177,384 | |
| Storage | 73,076 | | | 87,500 | | | 99,092 | |
| | | | | |
| Total segment depreciation and amortization expense | 251,878 | | | 266,588 | | | 276,476 | |
| Other depreciation and amortization expense | 7,358 | | | 7,792 | | | 8,625 | |
| Total depreciation and amortization expense | $ | 259,236 | | | $ | 274,380 | | | $ | 285,101 | |
| | | | | |
| Operating income: | | | | | |
| Pipeline | $ | 438,670 | | | $ | 321,472 | | | $ | 118,429 | |
| Storage | 61,081 | | | 24,800 | | | 189,781 | |
| Fuels marketing | 33,536 | | | 11,181 | | | 12,233 | |
| | | | | |
| Total segment operating income | 533,287 | | | 357,453 | | | 320,443 | |
| General and administrative expenses | 117,116 | | | 113,207 | | | 102,716 | |
| Other depreciation and amortization expense | 7,358 | | | 7,792 | | | 8,625 | |
| | | | | |
| | | | | |
| Total operating income | $ | 408,813 | | | $ | 236,454 | | | $ | 209,102 | |
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Revenues by geographic area are shown in the table below:
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2022 | | 2021 | | 2020 |
| | (Thousands of Dollars) |
| United States | $ | 1,667,672 | | | $ | 1,582,672 | | | $ | 1,441,892 | |
| Foreign | 15,551 | | | 35,828 | | | 39,672 | |
| Consolidated revenues | $ | 1,683,223 | | | $ | 1,618,500 | | | $ | 1,481,564 | |
For the years ended December 31, 2022, 2021 and 2020, Valero Energy Corporation accounted for approximately 18%, or 2016. In July 2017, following EPPA’s comprehensive review$307.3 million, 19%, or $308.5 million, and 20%, or $295.1 million, of our NEOs’ revenues, respectively. These revenues were included in all of our reportable business segments. No other single customer accounted for 10% or more of our consolidated revenues.
Total Direct Compensation, the Compensation Committee raised the long-term incentive targets for Mr. Barron from 200% to 250%, for Mr. Shoafamounts of property, plant and Ms. Brown from 150% to 180% and for Mr. Truby from 100% to 125%, and retained the existing target for Mr. Oliver. The following table shows each NEO’s long-term incentive target for 2017 (expressedequipment, net by geographic area were as a percent of base salary).follows:
| | | | | | | | | | | |
| | December 31, |
| | 2022 | | 2021 |
| | (Thousands of Dollars) |
| United States | $ | 3,359,427 | | | $ | 3,428,441 | |
| Foreign | 43,656 | | | 113,201 | |
| Consolidated property, plant and equipment, net | $ | 3,403,083 | | | $ | 3,541,642 | |
Total assets by reportable segment were as follows:
| | | | | | | | | | | |
| | December 31, |
| | 2022 | | 2021 |
| | (Thousands of Dollars) |
| Pipeline | $ | 3,360,685 | | | $ | 3,441,272 | |
| Storage | 1,438,609 | | | 1,537,037 | |
| Fuels marketing | 37,763 | | | 41,562 | |
| Total segment assets | 4,837,057 | | | 5,019,871 | |
| | | |
| Other partnership assets | 136,629 | | | 136,461 | |
| Total consolidated assets | $ | 4,973,686 | | | $ | 5,156,332 | |
Capital expenditures by reportable segment were as follows: | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2022 | | 2021 | | 2020 |
| | (Thousands of Dollars) |
| Pipeline | $ | 90,430 | | | $ | 67,340 | | | $ | 122,512 | |
| Storage | 47,222 | | | 112,043 | | | 71,788 | |
| | | | | |
| Other partnership assets | 2,978 | | | 1,750 | | | 3,779 | |
| Total capital expenditures | $ | 140,630 | | | $ | 181,133 | | | $ | 198,079 | |
|
| |
Name | Long-Term Incentive Target
|
Barron | 250 |
Shoaf | 180 |
Brown | 180 |
Oliver | 125 |
Truby | 125 |
The Compensation Committee allocates a percentage of long-term incentive award value to performance-based awards and a percentage to awards that focus on retention and increasing ownership levels of executive officers (including our NEOs). SinceITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.CONTROLS AND PROCEDURES
DISCLOSURE CONTROLS AND PROCEDURES
Our management has evaluated, with the fourth quarter of 2011, the target levels of long-term incentive award value have been allocated in the following manner:
35% performance units; and
65% restricted units.
The Compensation Committee reviews and approves long-term incentive grants for eachparticipation of the NEOs. The CEO develops individual grant recommendations forprincipal executive officer and principal financial officer of NuStar GP, LLC, the other NEOs based uponeffectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the methodology described above, but both the CEO and the Compensation Committee may make adjustments to the recommended grants based upon an assessmentSecurities Exchange Act of an individual’s performance and contributions to NuStar Energy. Grants to the CEO are decided solely by the Compensation Committee following the methodology described above, and the Compensation Committee may make discretionary adjustments to the calculated level of long-term incentives for the CEO based upon its independent evaluation1934) as of the CEO’s performanceend of the period covered by this report, and contributions.has concluded that our disclosure controls and procedures were effective as of December 31, 2022.
Restricted Units
Restricted units comprise approximately 65% of each NEO’s total NuStar Energy long-term incentive target. The Compensation Committee expects to grant restricted units on an annual basis. In 2017, the NEOs’ long-term incentive targets included approximately 70% NuStar Energy restricted units to be granted by the Compensation Committee under the 2000 LTIP and 30% NuStar GP Holdings phantom units (which we refer to as “restricted units” in Part III of this Annual Report on Form 10-K) to be granted by NuStar GP Holdings’ compensation committee under its long-term incentive plan. In both cases, no units are issued at the time of grant and the awards represent the right to receive common units upon vesting. The awards are calculated from an assumed unit value based on the average closing price of the common units for the first 10 business days of the month prior to the committee meeting at which the awards are to be approved. The restricted units all vest over five years in equal increments on the anniversary of the grant date, and common unit distribution equivalents are paid in cash quarterly for all unvested NuStar Energy and NuStar GP Holdings restricted units. Restricted units of NuStar GP Holdings were introduced into the compensation program in 2008 to reflect the fact that the performance of NuStar GP Holdings is directly tied to the performance of NuStar Energy since NuStar GP Holdings’ sole asset is its interest in NuStar Energy. As described under “Accounting Treatment” below, effective March 1, 2016, NuStar GP Holdings retains the expense associated with the NuStar GP Holdings restricted unit awards.
The annual grants of NuStar GP Holdings restricted units, as well as the annual grants of NuStar Energy restricted units, were approved in a joint meeting of the Compensation Committee and the compensation committee of NuStar GP Holdings’ board of directors on October 18, 2017. The committees determined that the grants would be made as soon as administratively practicable and no earlier than the third business day following our third quarter earnings release. Due to the time required to award and implement the grants, the 2017 annual grants were not effective until November 16, 2017. The following table sets forth the restricted units granted to each of our NEOs in 2017.
|
| | |
| Name | Restricted Units Granted in 2017 |
| NuStar Energy | NuStar GP Holdings |
| Barron | 16,660 | 13,315 |
| Shoaf | 7,295 | 5,830 |
| Brown | 7,860 | 6,280 |
| Oliver | 4,615 | 3,690 |
| Truby | 4,290 | 3,430 |
For more information regarding the 2017 restricted unit grants, see the table entitled “Grants of Plan-Based Awards During the Year Ended December 31, 2017.”
Performance Units
Performance units comprise approximately 35% of each NEO’s total NuStar Energy long-term incentive target and typically have been awarded in the first quarter of each year. The number of performance units awarded is determined by multiplying the annual base salary rate by the NEO’s long-term incentive target percentage, and then multiplying that product by 35%. That product is divided by the assumed value of an individual unit, which is the product of (x) the average common unit price for the period of December 15 through December 31 (using the daily closing prices) and (y) a factor reflecting the risk that the award might be forfeited.
Performance units are earned only upon NuStar Energy’s achievement of an objective performance measure for the performance period. The Compensation Committee believes this type of incentive award strengthens the tie between each NEO’s pay and our financial performance.
Since 2014, the target performance measure for performance unit awards has been NuStar Energy achieving a specific DCR, after taking into account the aggregate expense of the performance units. As described above, the Compensation Committee believes that distribution coverage appropriately aligns our NEOs’ interest with our unitholders’ interest.
Performance units are awarded pursuant to the 2000 LTIP, with each award subject to vesting in three annual increments (or tranches), based upon our DCR during the one-year performance periods that end on December 31 of each year following the date of grant, as illustrated in the table below.
|
| | | |
| Annual Performance Target | 2015 Target= DCR 1.01 : 1 | 2016 Target= DCR 1.03 : 1 | 2017 Target= DCR 1.01 : 1 |
| 2015 Award Tranche Eligible to Vest | 1st | 2nd | 3rd |
| 2016 Award Tranche Eligible to Vest | N/A | 1st | 2nd |
| 2017 Award Tranche Eligible to Vest | N/A | N/A | 1st |
| Performance Achieved for One-Year Performance Period | 1.11 : 1 | 1.07 : 1 | 0.63 : 1 |
| Percent of Eligible Units Vested for One-Year Performance Period | 200% | 150% | 0% |
If the DCR falls between the benchmarks established by the Compensation Committee for the performance period, the percentage vesting with respect to performance during that period will be determined through straight-line interpolation. The Compensation Committee retains the full discretion to vest up to 200% of performance units available for vesting, regardless of the DCR that NuStar Energy attains for the applicable performance period. As illustrated in the table above, performance units did not vest with respect to 2017 performance and vested at the 150% and 200% levels with respect to 2016 and 2015 performance, respectively. Additional information is provided below regarding the performance targets established by the Compensation Committee and the performance attained by NuStar Energy for each of the 2015, 2016 and 2017 performance periods.
2015 Performance Period. The target measure established by the Compensation Committee on January 29, 2015 for performance unit vesting with respect to 2015 performance was NuStar Energy achieving a DCR of 1.01:1, with all units eligible for vesting as follows based on the DCR for 2015:
|
| | |
Level | DCR | % Performance Units Earned |
Below Threshold | Below 1.00 : 1 | 0% |
Threshold | 1.00 : 1 | 90% |
Target | 1.01 : 1 | 100% |
Exceeds Target | 1.05 : 1 | 150% |
Maximum | 1.10 : 1 | 200% |
On January 28, 2016, the Compensation Committee determined that NuStar Energy achieved a DCR of 1.11:1 for 2015 and, in accordance with the award terms, the performance units available to vest under the applicable tranche for each of the 2014 awards and 2015 awards with respect to 2015 performance vested at 200%.
2016 Performance Period. The target measure established by the Compensation Committee on February 24, 2016 for performance unit vesting with respect to 2016 performance was NuStar Energy achieving a DCR of 1.03:1, with all units eligible for vesting as follows based on the DCR for 2016:
|
| | |
Level | DCR | % Performance Units Earned |
Below Threshold | Below 1.00 : 1 | 0% |
Threshold | 1.00 : 1 | 90% |
Target | 1.03 : 1 | 100% |
Exceeds Target | 1.07 : 1 | 150% |
Maximum | 1.12 : 1 | 200% |
On January 26, 2017, the Compensation Committee determined that NuStar Energy achieved a DCR of 1.07:1 for 2016 and, in accordance with the award terms, the performance units available to vest under the applicable tranche for each of the 2014 awards, 2015 awards and 2016 awards with respect to 2016 performance vested at 150%.
2017 Performance Period. On February 23, 2017, the Compensation Committee awarded the target number of performance units set forth below to our NEOs:
|
| |
Name | Performance Units Awarded in 2017
|
Barron | 11,000 |
Shoaf | 4,776 |
Brown | 5,145 |
Oliver | 3,624 |
Truby | 2,556 |
The target measure established by the Compensation Committee on February 23, 2017 for performance unit vesting with respect to 2017 performance was NuStar Energy achieving a DCR of 1.01:1, with all units eligible for vesting as follows based on the DCR for 2017:
|
| | |
Level | DCR | % Performance Units Earned |
Below Threshold | Below 1.00 : 1 | 0% |
Threshold | 1.00 : 1 | 90% |
Target | 1.01 : 1 | 100% |
Exceeds Target | 1.05 : 1 | 150% |
Maximum | 1.10 : 1 | 200% |
On January 25, 2018, the Compensation Committee determined that NuStar Energy achieved a DCR of 0.63:1 for 2017 and, in accordance with the award terms, the performance units available to vest under the applicable tranche for each of the 2015 awards, 2016 awards and 2017 awards with respect to 2017 performance did not vest. See the table entitled “Grants of Plan-Based Awards During the Year Ended December 31, 2017” for the performance units that did not vest with respect to the 2017 performance period.
Perquisites and Other Benefits
Perquisites
We provide only minimal perquisites to our NEOs. Each of our NEOs received federal income tax preparation services and personal liability insurance in 2017. For more information on perquisites, see the Summary Compensation Table and its footnotes.
Other Benefits
We provide other benefits, including medical, life, dental and disability insurance in line with competitive market practices. Our NEOs are eligible for the same benefit plans provided to our other employees, including our pension plans, 401(k) thrift plan (the Thrift Plan), and insurance and supplemental plans chosen and paid for by employees who desire additional coverage. Our NEOs and other employees whose compensation exceeds certain limits are eligible to participate in non-qualified excess benefit programs whereby those individuals can choose to make larger contributions than allowed under the qualified plan rules and receive correspondingly higher benefits. These plans are described below under “Post-Employment Benefits.”
Post-Employment Benefits
Pension Plans
For a discussion of our Pension Plan, as well as the Excess Pension Plan, please see the narrative description accompanying the table entitled “Pension Benefits for the Year Ended December 31, 2017.”
Nonqualified Deferred Compensation Plan (Excess Thrift Plan)
The Excess Thrift Plan provides unfunded benefits to those employees whose annual additions under the Thrift Plan are subject to the limitations under §415 of the Internal Revenue Code of 1986, as amended (the Code), and/or who are constrained from making maximum contributions under the Thrift Plan by §401(a)(17) of the Code, which limits the amount of an employee’s annual compensation that may be taken into account under that plan. The Excess Thrift Plan is comprised of two separate components, consisting of (1) an “excess benefit plan” as defined under §3(36) of The Employee Retirement Income Security Act of 1974, as amended (ERISA), and (2) a plan that is maintained primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees. Each component of the Excess Thrift Plan consists of a separate plan for purposes of Title I of ERISA. To the extent a participant’s annual total compensation exceeds the compensation limits for the calendar year under §401(a)(17) of the Code ($270,000 for 2017) or a participant’s annual additions under the Thrift Plan are limited by the maximum annual additions permitted under §415 of the Code ($54,000 for 2017), the participant’s Excess Thrift Plan account is credited with that number of hypothetical NuStar Energy units that could have been purchased with the difference between:
The total company matching contributions that would have been credited to the participant’s account under the Thrift Plan had the participant’s contributions not been limited pursuant to §401(a)(17) and/or §415; and
The actual company matching contributions credited to such participant’s account.
Each of our NEOs participated in the Excess Thrift Plan in 2017.
Change of Control Severance Arrangements
We initially entered into change of control severance agreements with each of our NEOs in, or prior to, 2007. The change of control severance agreements are intended to ensure the continued availability of these executives in the event of certain transactions culminating in a “change of control” as defined in the agreements. The change of control severance agreements have three-year terms and are automatically extended for one year upon each anniversary unless we give notice not to extend. If a “change of control” (as defined in the agreements) occurs during the term of an agreement, then the agreement becomes operative for a fixed three-year period. The agreements provide generally that the NEO’s terms and conditions of employment (including position, location, compensation and benefits) will not be adversely changed during the three-year period after a change of control.
The agreements contain tiers of compensation and benefits based on each NEO’s position. Each tier corresponds to a certain “severance multiple” used to calculate cash severance and other benefits to be provided under the agreements. Compensation and benefits under the agreements are triggered upon the occurrence of any of the following in connection with a change of control:
termination of employment by the employer other than for “cause” (as defined in the agreements), death or disability;
termination by the NEO for “good reason” (as defined in the agreements);
termination by the NEO other than for “good reason;” and
termination of employment because of death or disability.
These triggers were designed to ensure the continued availability of these executives following a change of control, and to compensate them at appropriate levels if their employment is unfairly or prematurely terminated during the applicable term following a change of control.
The following table sets forth the severance multiple applicable to each NEO, based on his or her current officer position.
|
| | |
Name | Applicable Officer Position | Severance Multiple |
Barron | Chief Executive Officer | 3 |
Shoaf | Executive Vice President | 2.5 |
Brown | Executive Vice President | 2.5 |
Oliver | Senior Vice President | 2 |
Truby | Senior Vice President | 2 |
When determining the amounts and benefits payable under the agreements, the Compensation Committee sought to secure compensation that is competitive in our market in order to recruit and retain executive officer talent. Consideration was given to the principal economic terms found in written employment and change of control agreements of other publicly traded companies. For more information regarding payments and benefits that may be provided under our change of control severance arrangements, see our disclosures below under the caption “Potential Payments upon Termination or Change of Control.”
Each of our NEOs has agreed and acknowledged that the Merger will not be deemed to trigger a “change of control” as defined under any NuStar Energy or NuStar GP Holdings plan or award, and has waived any rights to vesting, payment or other benefit thereunder that would arise upon a “change of control,” to which he or she might otherwise have been entitled.
Employment Agreements
None of the NEOs have employment agreements, other than the change of control severance agreements described above. As a result, in the event of a termination, retirement, death or disability that is not related to a change of control, an NEO will only receive the compensation or benefits to which he or she would be entitled under the terms of the defined contribution, defined benefit, medical or long-term incentive plans, as applicable.
IMPACT OF ACCOUNTING AND TAX TREATMENTS
Accounting Treatment
Services Agreement
As described in Item 13 below, on March 1, 2016, NuStar GP, LLC transferred and assigned to NuStar Services Co, a wholly owned subsidiary of ours, employment of all of NuStar GP, LLC’s employees. Our executive officers continue to serve as officers of NuStar GP Holdings and NuStar GP, LLC, and also serve as officers of NuStar Services Co and other NuStar Energy subsidiaries. Our NEOs serve as employees of both NuStar GP, LLC and NuStar Services Co. In connection with the transfer and assignment, we amended and restated the Services Agreement such that, beginning March 1, 2016, NuStar GP Holdings and NuStar Energy receive all management and administrative services from NuStar Services Co. NuStar Energy reimburses NuStar Services Co for all services provided to NuStar Energy, including payroll and benefit costs, as well as NuStar Energy unit-based compensation costs. NuStar GP Holdings pays NuStar Services Co an administrative services fee, subject to certain adjustments, but no longer pays 1.0% of our domestic bonus and unit compensation expenses. Instead, NuStar GP Holdings retains the expense associated with any NuStar GP Holdings common unit awards or other compensation that it provides to its officers and directors.
Unit-Based Compensation
In connection with the employee transfer on March 1, 2016, we assumed all outstanding awards under the 2000 LTIP. Our financial statements include the expense for awards of NuStar Energy restricted units and performance units. The transfer of the outstanding awards qualified as a plan modification. Therefore, we measured the fair value of then-outstanding awards to domestic employees (including our NEOs) based on the common unit price on the transfer date. Restricted units awarded to international employees are liability-classified awards that are cash-settled and measured at fair value based on the common unit price at each reporting period.
NuStar Energy Restricted Units. Our restricted unit awards are considered “phantom” units, as they represent the right to receive our common units upon vesting. We account for restricted units expected to result in the issuance of our common units upon vesting as equity-classified awards. The restricted units granted to our domestic employees (including our NEOs) generally vest over five years and the restricted units granted to non-employee directors generally vest over three years. We record compensation expense ratably over the vesting period based on the fair value of the units at the grant date (for domestic employees, including our NEOs) or the fair value of the units measured at each reporting period (for non-employee directors) using the market price of our common units on the applicable date. Common unit distribution equivalents paid with respect to outstanding, unvested equity-classified restricted units reduce equity, similar to cash distributions to unitholders.
NuStar Energy Performance Units. Performance units are equity-classified awards that vest in three increments (tranches) and represent the right to receive our common units, based upon our achievement of the performance measure set by the Compensation Committee during the one-year performance periods that end on December 31 of each year following the grant date. Under applicable accounting standards, a tranche of performance units is not considered “granted” until the Compensation Committee has set the performance measure for that specific tranche of the award. Therefore, performance units are measured at the grant date fair value once the performance measure is established for a specific tranche. In addition, since the performance units granted do not receive common unit distribution equivalents, the estimated fair value of these awards does not include the per unit distributions expected to be paid to unitholders during the vesting period. We record compensation expense ratably for each vesting tranche over its one-year service period if it is probable that the specified performance measure will be achieved. Additionally, changes in the actual or estimated outcomes that affect the quantity of performance units expected to be converted are recognized as a cumulative adjustment.
NuStar GP Holdings, LLC Restricted Units. NuStar GP Holdings’ restricted units are “phantom” units, as they represent the right to receive NuStar GP Holdings’ common units upon vesting. As described above, pursuant to the amended and restated services agreement, NuStar GP Holdings retains the expense associated with NuStar GP Holdings restricted unit awards. NuStar GP Holdings accounts for restricted units that it awards under its long-term incentive plan to its directors and employees (including our NEOs) at fair value. NuStar GP Holdings uses the market price at the grant date as the fair value of its restricted units. Awards of NuStar GP Holdings’ restricted units to its employees vest over five years, and NuStar GP Holdings recognizes the resulting compensation expense ratably over the vesting period.
Tax Treatment
We are a limited partnership and not a corporation for U.S. federal income tax purposes. Therefore, we are not subject to the executive compensation deduction limitations under Section 162(m) of the Code.
COMPENSATION-RELATED POLICIES
Unit Ownership Guidelines
We believe that ownership of NuStar Energy units aligns the interests of our directors and executives with those of NuStar Energy’s unitholders. We have long emphasized and reinforced the importance of unit ownership among our executives and directors.
During 2006, the Compensation Committee worked with its independent compensation consultant to formalize unit ownership and retention guidelines for our directors and officers to ensure continuation of our successful track record in aligning the interests of our directors and officers with those of our unitholders through unit ownership. During 2015, at the request of the Board and its committees, management undertook a review of the unit ownership and retention guidelines. Management discussed the results of its review with the Compensation Committee’s independent compensation consultant at the time, which agreed with management’s conclusions. The Compensation Committee and the Nominating/Governance and Conflicts Committee of NuStar GP, LLC’s Board, as well as the board of directors of NuStar GP Holdings, have approved the updated unit ownership and retention guidelines described below.
Non-Employee Director Unit Ownership Guidelines
Non-employee directors are expected to acquire and hold during their service as a Board member NuStar Energy units and/or NuStar GP Holdings units with an aggregate value of at least two times their annual cash retainer. Directors have five years from their initial election to the Board to meet the target unit ownership guidelines, and they are expected to continuously own sufficient units to meet the guidelines, once attained. As of December 31, 2017, each of our directors exceeded the ownership levels set forth in the unit ownership guidelines.
Officer Unit Ownership Guidelines
Unit ownership guidelines for the officers set forth below are as follows:
|
| | |
Officer | Value of NuStar Energy Units and/or
NuStar GP Holdings Units Owned
|
CEO/President | 4.0x base salary | |
EVP serving on CEO’s officer committee | 3.0x base salary | |
SVP serving on CEO’s officer committee | 2.0x base salary | |
VP serving on CEO’s officer committee | 1.0x base salary | |
The officers subject to the unit ownership and retention guidelines, including each of our NEOs, are expected to meet the applicable guidelines within five years of becoming subject to the guidelines and continuously own sufficient units to meet the guidelines, once attained. As of December 31, 2017, each of our NEOs exceeded the ownership levels set forth in the unit ownership guidelines.
Unit Ownership
For purposes of satisfying the unit ownership guidelines, the following units are considered owned:
units owned directly;
units owned indirectly through possession of the right to sell, transfer and/or vote such units; and
unvested restricted or phantom units granted under our long-term incentive plan or NuStar GP Holdings’ long-term incentive plan.
Unexercised unit options and unvested performance units are not considered owned for purposes of satisfying the unit ownership guidelines.
Prohibition on Insider Trading and Speculation in NuStar Energy or NuStar GP Holdings Units
We have established policies prohibiting our officers, directors and employees from purchasing or selling either NuStar Energy or NuStar GP Holdings securities while in possession of material, nonpublic information or otherwise using such information for their personal benefit or in any manner that would violate applicable laws and regulations. Our directors, officers and certain other employees are prohibited from trading in either NuStar Energy or NuStar GP Holdings securities for the period beginning on the last business day of each calendar quarter through the first business day following our disclosure of our quarterly or annual financial results. In addition, our policies prohibit our officers, directors and employees from speculating in either NuStar Energy or NuStar GP Holdings units, such as by short selling (profiting if the market price of our units decreases), buying or selling publicly traded options (including writing covered calls), hedging or any other type of derivative arrangement that has a similar economic effect. Our directors, officers and certain other employees also are required to obtain consent from the CEO (or, in the case of the CEO, from the Chair of the applicable company’s Audit Committee) before they enter into margin loans or other financing arrangements that may lead to the ownership or other rights to their NuStar Energy or NuStar GP Holdings securities being transferred to a third party.
EVALUATION OF COMPENSATION RISK
The Compensation Committee has focused on aligning our compensation policies with the long-term interests of NuStar Energy and avoiding short-term rewards for management decisions that could pose long-term risks to NuStar Energy. As described above in “Compensation Discussion and Analysis,” the primary elements of our compensation program are base salary, annual incentive bonus and long-term incentives. We believe that our compensation program appropriately balances cash with equity-based compensation and fixed compensation with short- and long-term incentives such that no single pay element would motivate unnecessary risk taking.
NuStar Energy’s compensation program is structured so that base salaries provide a fixed level of competitive pay that reflects the individual’s primary duties and responsibilities, and a considerable amount of our management’s compensation is tied to NuStar Energy’s long-term fiscal health. Bonuses, including executive bonuses, are determined with reference to a well-defined performance measure selected by the Compensation Committee and applicable to all employees, as well as the Compensation Committee’s review of each individual executive’s performance. Historically, our long-term incentives have taken the form of performance units and restricted units that typically vest over three- and five-year periods, respectively, which we believe serves to align our employees’ interests with the long-term goals of NuStar Energy. No business group or unit is compensated differently than any other, regardless of profitability. There also is a maximum number of performance units that may be earned, based on the performance of NuStar Energy relative to a performance measure selected by the Compensation Committee. As such, we believe that our compensation policies encourage employees to operate our business in a fundamentally sound manner, align our executives’ interests with those of our unitholders and do not create incentives to take risks that are reasonably likely to have a material adverse effect on NuStar Energy.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
There are no compensation committee interlocks. The members of our Compensation Committee are Mr. Hill (Chairman), Mr. Bates, Mr. Munch and Mr. Rosier. None of the members of our Compensation Committee have served as an officer or employee of ours. Furthermore, except for compensation arrangements disclosed in this Annual Report on Form 10-K, NuStar Energy has not participated in any contracts, loans, fees or awards, nor does it have financial interests, direct or indirect, with any Compensation Committee member. In addition, none of NuStar Energy’s management or Board members are aware of any means, directly or indirectly, by which a Compensation Committee member could receive a material benefit from NuStar Energy.
COMPENSATION OF EXECUTIVE OFFICERS AND DIRECTORS
The following pages of this Item 11 provide information required by the SEC regarding compensation paid to or earned by our NEOs and the members of our Board for the periods indicated. We have used captions and headings in the tables provided below in accordance with the SEC regulations requiring these disclosures. The footnotes to these tables provide important information to explain the values presented in the tables, and are an important part of our disclosures.
SUMMARY COMPENSATION TABLE
The following table provides a summary of compensation paid for the years ended December 31, 2017, December 31, 2016 and December 31, 2015 to our Chief Executive Officer, Chief Financial Officer and our three other most highly compensated executive officers serving during 2017. For each NEO, the table shows amounts earned for services rendered to us in all capacities in which the NEO served during the periods presented for that NEO. Mr. Oliver and Mr. Truby were not considered “executive officers” for SEC reporting purposes prior to 2017 and, accordingly, their compensation is reported only with respect to 2017.
|
| | | | | | | | | | | | | | | | | | | |
Name and Principal Position | Year | Salary ($) | Unit Awards ($)(1) | Non-Equity Incentive Plan Compensation ($)(2) | Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)(3) | All Other Compensation ($)(4) | Total ($) |
Bradley C. Barron President and Chief Executive Officer
| 2017 | 583,625 |
| | 1,233,907 |
| | —
|
| | 218,342 |
| | 54,897 |
| | 2,090,771 |
| |
| 2016 | 557,500 |
| | 1,039,456 |
| | 700,000 |
| | 184,931 |
| | 35,698 |
| | 2,517,585 |
| |
| 2015 | 515,000 |
| | 1,077,860 |
| | 800,000 |
| | 47,061 |
| | 35,677 |
| | 2,475,598 |
| |
| Thomas R. Shoaf Executive Vice President and Chief Financial Officer | 2017 | 354,950 |
| | 554,372 |
| | —
|
| | 171,513 |
| | 28,387 |
| | 1,109,222 |
| |
| 2016 | 344,600 |
| | 479,970 |
| | 260,000 |
| | 124,479 |
| | 22,924 |
| | 1,231,973 |
| |
| 2015 | 334,550 |
| | 515,023 |
| | 311,000 |
| | 47,692 |
| | 21,729 |
| | 1,229,994 |
| |
Mary Rose Brown Executive Vice President and Chief Administrative Officer | 2017 | 382,350 |
| | 597,187 |
| | —
|
| | 188,315 |
| | 60,689 |
| | 1,228,541 |
| |
| 2016 | 371,200 |
| | 516,952 |
| | 280,000 |
| | 142,437 |
| | 24,520 |
| | 1,335,109 |
| |
| 2015 | 360,350 |
| | 554,552 |
| | 335,000 |
| | 173,968 |
| | 23,836 |
| | 1,447,706 |
| |
Daniel S. Oliver Senior Vice President-Marketing and Business Development
| 2017 | 323,150 |
| | 382,223 |
| | —
|
| | 142,129 |
| | 29,973 |
| | 877,475 |
| |
Michael Truby Senior Vice President-Operations | 2017 | 293,800 |
| | 310,868 |
| | — |
| | 112,573 |
| | 23,259 |
| | 740,500 |
| |
| |
(1) | The amounts reported represent the aggregate grant date fair value of grants of NuStar Energy restricted units, NuStar Energy performance units and NuStar GP Holdings restricted units. Under a services agreement in effect prior to March 1, 2016, we reimbursed NuStar GP, LLC for 99% of the compensation expense associated with NuStar Energy awards. On March 1, 2016, NuStar GP, LLC transferred and assigned to NuStar Services Co, a wholly owned subsidiary of ours, employment of all of NuStar GP, LLC’s employees and we assumed all outstanding NuStar Energy awards. Our NEOs are employees of both NuStar Services Co and NuStar GP, LLC. NuStar GP Holdings retains the expense associated with the NuStar GP Holdings restricted unit awards. |
Restricted Units
The grant date fair valueOur restricted unit awards are considered phantom units, as they represent the right to receive our common units upon vesting. We account for restricted units presented inas either equity-classified awards or liability-classified awards, depending on expected method of settlement. Awards we settle with the table above was determined by multiplying the numberissuance of NuStar Energy restricted units or NuStar GP Holdings restricted units that were granted by the NYSE closing unit price of NuStar Energy common units or NuStar GP Holdings common units, as applicable,upon vesting are equity-classified. Awards we settle in cash upon vesting are liability-classified. We record compensation expense ratably over the vesting period based on the date of grant.
Performance Units
For the 2015 row in the Summary Compensation Table, the grant date fair value of the NuStar Energy performance units was determined by multiplying the target number of performance units that were granted by the NYSE closing unit price of NuStar Energy common units at the grant date (for domestic employees and NEDs), or, prior to the sale of our Point Tupper Terminal Operations on the date of grant.
On March 1, 2016, in connection with the employee transfer, we assumed all outstanding NuStar Energy awards, and performance unit awards are now equity-classified awards. The transfer qualified as a plan modification, and we measuredApril 29, 2022, the fair value of then-outstandingthe common units measured at each reporting period (for international employees). DERs paid with respect to outstanding equity-classified unvested restricted units reduce equity, similar to cash distributions to unitholders, whereas DERs paid with respect to outstanding liability-classified unvested restricted units were expensed prior to the sale of our Point Tupper Terminal Operations on April 29, 2022. In connection with the DERs for equity awards, based on our common unit price onwe paid $2.5 million, $2.4 million and $2.1 million respectively, in cash, for the transferyears ended December 31, 2022, 2021 and 2020.
Domestic Employees. The outstanding restricted units granted to domestic employees are equity-classified awards and generally vest over five years, beginning one year after the grant date. Under applicable accounting standards, a trancheThe fair value of performance unitsthese awards is not considered “granted” until the Compensation Committee has set the performance measure for that specific tranche of the award. Therefore, performance units are measured at the grant datedate.
Non-Employee Directors. The outstanding restricted units granted to NEDs are equity-classified awards that vest over three years. The fair value once the performance measureof these awards is established for a specific tranche (or, for 2016, the transfer date).
Beginning with the 2016 period,measured at the grant date fair value presented indate.
International Employees. Prior to the Summary Compensation Table includessale of our Point Tupper Terminal Operations on April 29, 2022, the outstanding restricted units granted to international employees were cash-settled and accounted for as liability-classified awards. These awards vested over three years and the fair value was equal to the market price of our common units at each tranchereporting period. For the year ended December 31, 2022, 11,364 restricted units vested and 10,396 restricted units were forfeited related to our international employees.
the amount reported for 2016 includes the one trancheNUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
A summary of each of the 2014, 2015 and 2016 performanceour equity-classified restricted unit awards subjectis as follows:
| | | | | | | | | | | | | | | | | |
| Measured at Grant Date Fair Value | | | | | | |
| Number of Units | | Weighted-Average Fair Value Per Unit | | | | | | |
| Nonvested units as of January 1, 2020 | 1,284,492 | | | $ | 27.48 | | | | | | | |
| | | | | | | | | |
| Granted | 1,454,998 | | | 12.10 | | | | | | | |
| Vested | (374,847) | | | 28.47 | | | | | | | |
| Forfeited | (30,749) | | | 26.75 | | | | | | | |
| Nonvested units as of December 31, 2020 | 2,333,894 | | | 17.70 | | | | | | | |
| Granted | 1,049,081 | | | 16.28 | | | | | | | |
| Vested | (630,888) | | | 20.07 | | | | | | | |
| Forfeited | (102,339) | | | 14.28 | | | | | | | |
| Nonvested units as of December 31, 2021 | 2,649,748 | | | 16.57 | | | | | | | |
| Granted | 1,206,824 | | | 16.09 | | | | | | | |
| Vested | (738,701) | | | 17.79 | | | | | | | |
| Forfeited | (125,078) | | | 16.23 | | | | | | | |
| Nonvested units as of December 31, 2022 | 2,992,793 | | | 16.08 | | | | | | | |
The total fair value of our equity-classified restricted unit awards vested for the years ended December 31, 2022, 2021 and 2020 was $11.9 million, $10.3 million and $4.6 million, respectively. We issued 531,637, 460,076 and 275,146 common units in connection with these award vestings, net of employee tax withholding requirements, for the years ended December 31, 2022, 2021 and 2020, respectively. Unrecognized compensation cost related to vesting based onour equity-classified employee awards totaled $45.6 million as of December 31, 2022, which we expect to recognize over a weighted-average period of 3.7 years.
Performance Awards
Performance awards are issued to certain of our key employees and represent either rights to receive our common units or cash upon achieving performance measures for the performance criteriaperiod established by the NuStar GP, LLC Compensation Committee on February 24, 2016 with respect to 2016 performance; and
the amount reported for 2017 includes the one tranche of each(the Compensation Committee). Achievement of the 2015, 2016 and 2017 performance unit awards subject to vesting based onmeasures determines the rate at which the performance criteria established by the Compensation Committee on February 23, 2017 with respectawards convert into our common units or cash, which ranges from zero to 2017 performance.200% for certain awards.
|
| | |
Award | Tranche Considered “Granted” |
In 2017 with respect to 2017 Performance Measure | In 2016 with respect to 2016 Performance Measure |
2014 Performance Unit Award | N/A | 3rd |
2015 Performance Unit Award | 3rd | 2nd |
2016 Performance Unit Award | 2nd | 1st |
2017 Performance Unit Award | 1st | N/A |
For 2017 and 2016, the grant date fair valuePerformance awards vest in three annual increments (tranches), based upon our achievement of the NuStar Energy performance units was determined by multiplying the probable number of performance units for all tranches eligible to vest with respect to 2017 and 2016 performance (as illustrated in the table above), respectively, by the NYSE closing unit price of NuStar Energy common units on the grant date (or, for 2016, the transfer date as described above), reduced by the per unit value of distributions not paid on performance units prior to vesting.
If the maximum number of NuStar Energy performance units had been used to determine the grant date fair value of performance units for the 2017 and 2016 periods presented, the grant date fair value for performance units for the 2017 and 2016 periods presented in the Summary Compensation Table for each of our NEOs would have been as set forth in the table below:
|
| | | | |
| Name | Grant Date Fair Value Based on Maximum Number of Performance Units |
| 2017 ($) | 2016 ($) |
| Barron | 1,077,444 |
| 618,393 |
|
| Shoaf | 499,944 |
| 305,958 |
|
| Brown | 538,471 |
| 329,513 |
|
| Oliver | 379,247 |
| N/A |
|
| Truby | 263,667 |
| N/A |
|
Please see the “Long-Term Incentive Awards” section and the “Accounting Treatment” section of “Compensation Discussion and Analysis” above in this Item 11 and Note 23 of the Notes to Consolidated Financial Statements in Item 8 for additional information regarding the vesting schedules and the assumptions made in the valuation.
| |
(2) | Our NEOs did not receive cash annual incentive bonus amounts for 2017. The amounts reported as “non-equity incentive plan compensation” for 2016 and 2015 reflect the cash annual incentive bonus amounts paid to our NEOs pursuant to the annual bonus plan with respect to performance for those years. Any bonus amounts are paid in February of each year with respect to performance during the immediately preceding year. Bonuses are determined taking into consideration NuStar Energy’s performance in the applicable year, each individual NEO’s target and each NEO’s performance, as described above under “Compensation Discussion and Analysis-Elements of Executive Compensation-Annual Incentive Bonus.” For an explanation of the amount of salary and bonus in proportion to total compensation, see “Compensation Discussion and Analysis-Elements of Executive Compensation-Relative Size of Primary Elements of Compensation.” |
| |
(3) | The amounts reported reflect the amounts attributable to the aggregate change in the actuarial present value of each NEO’s accumulated benefit under our defined benefit and actuarial pension plans, including supplemental plans (but excluding tax-qualified defined contribution plans and nonqualified defined contribution plans). None of the NEOs received any above-market or preferential earnings on compensation that is deferred on a basis that is not tax-qualified during the periods presented. |
| |
(4) | The amounts reported in this column for 2017 consist of the following for each NEO: |
|
| | | | | | | | | | | | | | |
| Name | Company Contribution to Thrift Plan ($) | Company Contribution to Excess Thrift Plan ($) | Tax Preparation ($) | Personal Liability Insurance ($) | Executive Health Exams ($)(a) | TOTAL ($) |
| Barron | 16,200 |
| | 36,316 |
| | 850 |
| | 1,531 |
| — | 54,897 |
|
| Shoaf | 16,200 |
| | 7,226 |
| | 850 |
| | 1,531 |
| 2,580 | 28,387 |
|
| Brown | 13,185 |
| | 42,543 |
| | 850 |
| | 1,531 |
| 2,580 | 60,689 |
|
| Oliver | 16,200 |
| | 11,392 |
| | 850 |
| | 1,531 |
| — | 29,973 |
|
| Truby | 16,200 |
| | 4,678 |
| | 850 |
| | 1,531 |
| — | 23,259 |
|
| |
(a) | The amount reported is the difference between the value of the respective NEO’s health exams and the value of NuStar Energy’s all-employee wellness assessments. |
PAY RATIO
As required by SEC regulations, we are providing the following information regarding the ratio of the annual total compensation of our President and Chief Executive Officer, Mr. Barron, to the median of the annual total compensation of our employees for our last completed fiscal year.
For 2017:
the median of the annual total compensation of all of our employees (other than our President and Chief Executive Officer) was $88,610; and
the annual total compensation of our President and Chief Executive Officer, as reported in the Summary Compensation Table above, was $2,090,771.
Accordingly, for 2017, the ratio of the annual total compensation of our President and Chief Executive Officer to the annual total compensation of our median employee was 24 to 1.
To determine our median employee, we identified each individual employed by us on October 1, 2017 (our Determination Date), and, for each individual employed by us on the Determination Date, we examined each of the following elements of compensation (which we refer to as the Total Comparable Compensation) that we paid those employees during the period from October 1, 2016 through September 30, 2017 (the Compensation Review Period):
salary, wages and any overtime paid during the Compensation Review Period;
any bonus awards paid during the Compensation Review Period; and
the grant date fair value of any restricted units awarded during the Compensation Review Period.
As of our Determination Date, we had approximately 1,690 employees located in five countries. We selected our Determination Date and our Compensation Review Period to provide sufficient time for us to gather the necessary information from multiple countries and to enable us to make the identification of the median employee in a reasonably efficient and economical manner. After identifying the median employee based on Total Comparable Compensation, we calculated the annual total compensation for the median employee for 2017 using the same methodology we use to calculate the annual total compensation for our NEOs for 2017, as set forth in the Summary Compensation Table above. We did not make any assumptions, adjustments or estimates to identify the median employee, to determine the Total Comparable Compensation for each employee or to determine the annual total compensation for the median employee.
GRANTS OF PLAN-BASED AWARDS
DURING THE YEAR ENDED DECEMBER 31, 2017
The following table provides information regarding grants of plan-based awards to the NEOs during 2017.
|
| | | | | | | | | | | | | | | | | | | | | | |
| Name | Grant Date | Date of Approval by Compensation Committee of Equity-Based Awards | Estimated Future Payouts Under Non-Equity Incentive Plan Awards | Estimated Future Payouts Under Equity Incentive Plan Awards | All Other Unit Awards: Number of Units (#) | Grant Date Fair Value of Unit Awards ($) |
| Threshold ($) | Target ($) | Maximum ($) | Threshold (#) | Target (#) | Maximum (#) |
| Barron | N/A | (1) | N/A | N/A | 583,625 |
| 1,167,250 |
| — |
| — |
| — |
| — |
| | — | |
| 2/23/2017 | (2) | 2/23/2017 | — | — |
| — |
| 9,665 |
| 10,739 |
| 21,478 |
| — |
| | 538,722 | |
| 11/16/2017 | (3) | 10/18/2017 | — | — |
| — |
| — |
| — |
| — |
| 16,660 |
| 16,660 |
| 486,805 | |
| 11/16/2017 | (4) | 10/18/2017 | — | — |
| — |
| — |
| — |
| — |
| 13,315 |
| | 208,380 | |
| Shoaf | N/A | (1) | N/A | N/A | 212,970 |
| 425,940 |
| — |
| — |
| — |
| — |
| | — | |
| 2/23/2017 | (2) | 2/23/2017 | — | — |
| — |
| 4,485 |
| 4,983 |
| 9,966 |
| — |
| 249,972 | |
| 11/16/2017 | (3) | 10/18/2017 | — | — |
| — |
| — |
| — |
| — |
| 7,295 |
| 213,160 | |
| 11/16/2017 | (4) | 10/18/2017 | — | — |
| — |
| — |
| — |
| — |
| 5,830 |
| 91,240 | |
| Brown | N/A | (1) | N/A | N/A | 229,410 |
| 458,820 |
| — |
| — |
| — |
| — |
| | — | |
| 2/23/2017 | (2) | 2/23/2017 | — | — |
| — |
| 4,830 |
| 5,367 |
| 10,734 |
| — |
| 269,236 | |
| 11/16/2017 | (3) | 10/18/2017 | — | — |
| — |
| — |
| — |
| — |
| 7,860 |
| 229,669 | |
| 11/16/2017 | (4) | 10/18/2017 | — | — |
| — |
| — |
| — |
| — |
| 6,280 |
| 98,282 | |
| Oliver | N/A | (1) | N/A | N/A | 177,733 |
| 355,465 |
| — |
| — |
| — |
| — |
| | — | |
| 2/23/2017 | (2) | 2/23/2017 | — | — |
| — |
| 3,402 |
| 3,780 |
| 7,560 |
| — |
| | 189,624 | |
| 11/16/2017 | (3) | 10/18/2017 | — | — |
| — |
| — |
| — |
| — |
| 4,615 |
| | 134,850 | |
| 11/16/2017 | (4) | 10/18/2017 | — | — |
| — |
| — |
| — |
| — |
| 3,690 |
| | 57,749 | |
| Truby | N/A | (1) | N/A | N/A | 161,590 |
| 323,180 |
| — |
| — |
| — |
| — |
| | — | |
| 2/23/2017 | (2) | 2/23/2017 | — | — |
| — |
| 2,365 |
| 2,628 |
| 5,256 |
| — |
| | 131,834 | |
| 11/16/2017 | (3) | 10/18/2017 | — | — |
| — |
| — |
| — |
| — |
| 4,290 |
| | 125,354 | |
| 11/16/2017 | (4) | 10/18/2017 | — | — |
| — |
| — |
| — |
| — |
| 3,430 |
| | 53,680 | |
| |
(1) | The amounts reported represent the target and maximum amounts that would potentially have been payable in cash to the NEOs as annual incentive bonus awards under the annual bonus plan with respect to 2017 performance. The annual incentive bonus awards with respect to 2017 performance did not include a threshold amount that would potentially be payable to the NEOs. As reflected in the “Non-Equity Incentive Plan Compensation” column of the Summary Compensation Table and as described above under “Compensation Discussion and Analysis-Elements of Executive Compensation-Annual Incentive Bonus,” the target level of performance with respect to 2017 was not met, and, upon the recommendation of executive management, the Compensation Committee did not award our executives, including our NEOs, annual incentive bonus award payments with respect to 2017 performance. |
| |
(2) | Performance units were awarded by the Compensation Committee on February 23, 2017 pursuant to the 2000 LTIP. Performance units vest in three annual increments (tranches), based upon our achievement of the performance measuremeasures set by the Compensation Committee during the one-year performance periods that end on December 31 of each year following the date of grant. Under applicable accounting standards, a tranche of performance units is not considered “granted” until the Compensation Committee has set the performance measure for that specific tranche of the award. Therefore, performance units are measured at the grant date fair value once the performance measure is established for a specific tranche. In addition, since the performance units granted do not receive common unit distribution equivalents, the estimated fair value of these awards does not include the per unit distributions expected to be paid to unitholders during the vesting period. |
The estimated future payouts and the grant date fair value presented in the table above with respect to performance units includes each tranche of performance units for which the Compensation Committee established a performance measure during 2017. For 2017, the amounts presented include the one tranche of each of the 2015, 2016 and 2017 performance unit awards that was subject to vesting based on the performance criteria established by the Compensation Committee on February 23, 2017 with respect to 2017 performance, as illustrated in the table below:
|
| |
Award | Tranche Considered “Granted” in 2017 With Respect to 2017 Performance Measure |
2015 Performance Unit Award | 3rd |
2016 Performance Unit Award | 2nd |
2017 Performance Unit Award | 1st |
On January 25, 2018, the Compensation Committee determined that, based on the performance level attained for the performance period ended December 31, 2017, the performance units reported in the table above did not vest. See “Compensation Discussion and Analysis-Elements of Executive Compensation-Long Term Incentive Awards-Performance Units” for a description of the performance measure and the performance level attained with respect to the 2017 performance period. See “Compensation Discussion and Analysis-Impact of Accounting and Tax Treatments-Accounting Treatment” and footnote (1) to the Summary Compensation Table above in this Item 11 for information regarding the assumptions made in valuation.
| |
(3) | Restricted units of NuStar Energy were approved by the Compensation Committee on October 18, 2017, and the grant date for these NuStar Energy restricted units was set at that time for the date that was as soon as administratively practicable after the meeting and no earlier than the third business day following our third quarter earnings release. The NuStar Energy restricted units were awarded pursuant to the 2000 LTIP and vest 1/5 annually over five years beginning on the first anniversary of the grant date. All grantees receiving NuStar Energy restricted units are entitled to receive an amount in cash equal to the product of (a) the number of restricted units granted to the grantee that remain outstanding and unvested as of the record date for such quarter and (b) the quarterly distribution declared by the Board for such quarter with respect to NuStar Energy’s common units. See “Compensation Discussion and Analysis-Impact of Accounting and Tax Treatments-Accounting Treatment” and footnote (1) to the Summary Compensation Table above in this Item 11 for information regarding the assumptions made in valuation. |
| |
(4) | Restricted units of NuStar GP Holdings were approved by the compensation committee of NuStar GP Holdings on October 18, 2017, and the grant date for these NuStar GP Holdings restricted units was set at that time for the date that was as soon as administratively practicable after the meeting and no earlier than the third business day following NuStar GP Holdings’ third quarter earnings release. The NuStar GP Holdings restricted units were awarded pursuant to the NuStar GP Holdings Long-Term Incentive Plan, as amended and restated as of April 1, 2007, and vest 1/5 annually over five years beginning on the first anniversary of the grant date. All grantees receiving NuStar GP Holdings restricted units are entitled to receive an amount in cash equal to the product of (a) the number of restricted units granted to the grantee that remain outstanding and unvested as of the record date for such quarter and (b) the quarterly distribution declared by the NuStar GP Holdings Board for such quarter with respect to NuStar GP Holdings’ common units. See “Compensation Discussion and Analysis-Impact of Accounting and Tax Treatments-Accounting Treatment” and footnote (1) to the Summary Compensation Table above in this Item 11 for information regarding the assumptions made in valuation. |
At the effective time of the Merger, each outstanding award of NuStar GP Holdings restricted units will be converted, on the same terms and conditions as were applicable to the awards immediately prior to the Merger, into an award of NuStar Energy restricted units. The number of NuStar Energy restricted units subject to the converted awards will be determined as provided in the Merger Agreement.
OUTSTANDING EQUITY AWARDS
AT DECEMBER 31, 2017
The following table provides information regarding our NEOs’ unvested restricted units and the target amount of our NEOs’ unvested performance units as of December 31, 2017. The value of NuStar Energy restricted units, NuStar Energy performance units and NuStar GP Holdings restricted units reported below was determined by multiplying (1) the number of units reflected in the table by (2) $29.95 (the closing price of NuStar Energy common units on December 29, 2017, the last trading day of the year) or $15.70 (the closing price of NuStar GP Holdings common units on December 29, 2017, the last trading day of the year), as applicable.
At the effective time of the Merger, each outstanding award of NuStar GP Holdings restricted units will be converted, on the same terms and conditions as were applicable to the awards immediately prior to the Merger, into an award of NuStar Energy restricted units. The number of NuStar Energy restricted units subject to the converted awards will be determined as provided in the Merger Agreement. Each of our NEOs has agreed and acknowledged that the Merger will not be deemed to trigger a “change of control” as defined under any NuStar Energy or NuStar GP Holdings plan or award, and has waived any rights to vesting, payment or other benefit thereunder that would arise upon a “change of control,” to which he or she might otherwise have been entitled.
|
| | | | | | | |
| Name | Unit Awards |
| Type of Award | Number of Units That Have Not Vested (#) | Market Value of Units That Have Not Vested ($) | Equity Incentive Plan Awards: Number of Unearned Units or Other Rights That Have Not Vested (#) | Equity Incentive Plan Awards: Market or Payout Value of Unearned Units or Other Rights That Have Not Vested ($) |
| Barron | NuStar Energy Performance Unit (1) | — | — |
| 22,480 | 673,276 |
|
NuStar Energy Restricted Unit (2) | 35,272 | 1,056,396 |
| — | — |
|
NuStar GP Holdings Restricted Unit (3) | 27,505 | 431,829 |
| — | — |
|
| Shoaf | NuStar Energy Performance Unit (4) | — | — |
| 10,245 | 306,838 |
|
NuStar Energy Restricted Unit (5) | 16,102 | 482,255 |
| — | — |
|
NuStar GP Holdings Restricted Unit (6) | 12,551 | 197,051 |
| — | — |
|
| Brown | NuStar Energy Performance Unit (7) | — | — |
| 11,035 | 330,498 |
|
NuStar Energy Restricted Unit (8) | 17,607 | 527,330 |
| — | — |
|
NuStar GP Holdings Restricted Unit (9) | 13,709 | 215,231 |
| — | — |
|
| Oliver | NuStar Energy Performance Unit (10) | — | — |
| 7,772 | 232,771 |
|
NuStar Energy Restricted Unit (11) | 11,479 | 343,796 |
| — | — |
|
NuStar GP Holdings Restricted Unit (12) | 8,924 | 140,107 |
| — | — |
|
| Truby | NuStar Energy Performance Unit (13) | — | — |
| 5,444 | 163,048 |
|
NuStar Energy Restricted Unit (14) | 9,650 | 289,018 |
| — | — |
|
NuStar GP Holdings Restricted Unit (15) | 6,259 | 98,266 |
| — | — |
|
| |
(1) | Mr. Barron’s target number of NuStar Energy performance units consist of: 2,666 units awarded January 29, 2015; 8,814 units awarded February 24, 2016; and 11,000 units awarded February 23, 2017. |
The performance units awarded in 2015, 2016 and 2017 are eligible to vest in three annual increments and are payable in NuStar Energy’s common units. Upon vesting, the performance units are converted into a number of NuStar Energy common units based upon NuStar Energy’s performance during the one-year performance periods that end on December 31 of each year followingapplicable year. Therefore, the date of grant against an objective performance measure established by the Compensation Committee.
On January 25, 2018,awards are not considered granted for accounting purposes until the Compensation Committee determined that, based onhas set the performance level attainedmeasures for each tranche of awards. Performance unit awards are equity-classified awards measured at the grant date fair value. In addition, since the performance unit awards granted do not receive DERs, the grant date fair value of these awards is reduced by the per unit distributions expected to be paid to common unitholders during the vesting period. Performance cash awards are accounted for as a liability but may be settled in common units. We record compensation expense ratably for each vesting tranche over its requisite service period (one year) if it is probable that the specified performance measures will be achieved. Additionally, changes in the actual or estimated outcomes that affect the quantity of performance awards expected to be converted into common units or paid in cash, are recognized as a cumulative adjustment. Performance units vested relate to the performance for the performance period ended December 31 2017,of the previous year.
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
A summary of our performance awards is shown below:
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Performance Unit Awards |
| | | | | Granted for Accounting Purposes |
| Performance Cash Awards | | Total Performance
Unit Awards Granted | | Performance Unit Awards | | Weighted-Average Grant Date Fair Value per Unit |
| (Thousands of Dollars) | | | | | | |
| Outstanding as of January 1, 2020 | $ | — | | | 161,561 | | | 74,439 | | | $ | 28.01 | |
| Granted | 2,167 | | | — | | | 57,448 | | | 13.21 | |
| Performance adjustment (a) | — | | | 72,951 | | | 72,951 | | | 28.01 | |
| Vested | — | | | (147,390) | | | (147,390) | | | 28.01 | |
| Outstanding as of December 31, 2020 | 2,167 | | | 87,122 | | | 57,448 | | | 13.21 | |
| Granted | 2,254 | | | 4,021 | | | 33,695 | | | 15.79 | |
| | | | | | | |
| Vested (b) | (672) | | | (53,427) | | | (53,427) | | | 13.21 | |
| Forfeitures | (51) | | | (4,021) | | | (4,021) | | | 13.21 | |
| Outstanding as of December 31, 2021 | 3,698 | | | 33,695 | | | 33,695 | | | 15.79 | |
| Granted | 2,954 | | | — | | | — | | | — | |
| Performance adjustment (a) | — | | | 14,839 | | | 14,839 | | | 15.79 | |
| Vested (b) | (1,507) | | | (48,534) | | | (48,534) | | | 15.79 | |
| | | | | | | |
| Outstanding as of December 31, 2022 | $ | 5,145 | | | — | | | — | | | — | |
(a) For the year ended December 31, 2020, common units granted and issued upon vesting resulted from performance units earned at 198% of the 2019 target. For the year ended December 31, 2022, common units granted and issued upon vesting resulted from performance units earned at 150% of the 2021 target.
(b) For the years ended December 31, 2022 and 2021, we settled performance cash awards with 137,931 and 43,733 common units, respectively, and issued 84,778 and 26,704 common units, net of employee tax withholding requirements, respectively.
The total fair value of our performance unit awards vested for the years ended December 31, 2022, 2021 and 2020 was $0.8 million, $0.8 million and $4.2 million, respectively. For the years ended December 31, 2022, 2021, and 2020 we issued 29,840, 31,366 and 93,440 common units in connection with the performance unit award vestings, net of employee tax withholding requirements, respectively.
On January 26, 2023, we settled performance cash awards in common units, availableand together with the performance unit awards, we issued 82,353 common units, net of employee tax withholding requirements, respectively.
Unit Awards
Unit awards are equity-classified awards of fully vested common units. We accrued compensation expense in 2021 and 2019 that was paid in unit awards in the first quarters of the respective subsequent years. We base the number of unit awards granted on the fair value of the common units at the grant date. A summary of our unit awards is shown below:
| | | | | | | | | | | | | | | | | | | | |
| Date of Grant | | Grant Date Fair Value | | Unit Awards Granted | | Common Units Issued, Net of Employee Withholding Tax |
| | (Thousands of Dollars) | | | | |
| February 2022 | | $ | 4,645 | | | 280,685 | | | 186,190 | |
| February and March 2020 | | $ | 22,941 | | | 834,224 | | | 571,735 | |
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
23. INCOME TAXES
Components of income tax expense related to vestcertain of our operations conducted through separate taxable wholly owned corporate subsidiaries were as follows:
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2022 | | 2021 | | 2020 |
| | (Thousands of Dollars) |
| Current: | | | | | |
| U.S. | $ | 3,558 | | | $ | 3,755 | | | $ | 36 | |
| Foreign | 272 | | | 221 | | | 2,415 | |
| Foreign withholding tax | 355 | | | 1,281 | | | — | |
| Total current | 4,185 | | | 5,257 | | | 2,451 | |
| | | | | |
| Deferred: | | | | | |
| U.S. | 341 | | | (93) | | | 300 | |
| Foreign | (1,287) | | | (531) | | | (621) | |
| Foreign withholding tax | — | | | (745) | | | 533 | |
| Total deferred | (946) | | | (1,369) | | | 212 | |
| | | | | |
| Income tax expense | $ | 3,239 | | | $ | 3,888 | | | $ | 2,663 | |
The difference between income tax expense recorded in our consolidated statements of income (loss) and income taxes computed by applying the applicable statutory federal income tax rate to income before income tax expense is due to the fact that the majority of our income is not subject to federal income tax due to our status as a limited partnership. We record a tax provision related to the amount of undistributed earnings of our foreign subsidiaries expected to be repatriated.
The tax effects of significant temporary differences representing deferred income tax assets and liabilities were as follows:
| | | | | | | | | | | |
| December 31, |
| | 2022 | | 2021 |
| | (Thousands of Dollars) |
| Deferred income tax assets: | | | |
| Net operating losses | $ | 17,710 | | | $ | 20,005 | |
| | | |
| | | |
| | | |
| Capital loss | 3,714 | | | 3,735 | |
| Other | 793 | | | 625 | |
| Total deferred income tax assets | 22,217 | | | 24,365 | |
| Less: Valuation allowance | (21,573) | | | (23,718) | |
| Net deferred income tax assets | 644 | | | 647 | |
| | | |
| Deferred income tax liabilities: | | | |
| Property, plant and equipment | (3,534) | | | (11,884) | |
| Foreign withholding tax | (286) | | | (272) | |
| Other | (43) | | | (322) | |
| Total deferred income tax liabilities | (3,863) | | | (12,478) | |
| | | |
| Net deferred income tax liability | $ | (3,219) | | | $ | (11,831) | |
| | | |
| | | |
| | | |
| | | |
| | | |
As of December 31, 2022, our U.S. and foreign corporate operations have net operating loss carryforwards for tax purposes totaling $51.1 million and $23.3 million, respectively, which are subject to various limitations on use and expire in years 2032 through 2034 for U.S. losses and in years 2023 through 2033 for foreign losses. However, U.S. losses generated after December 31, 2017, totaling $5.2 million, can be carried forward indefinitely. As of December 31, 2022, our U.S. corporate operations
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
have a capital loss carryforward for tax purposes totaling $17.7 million, which is subject to limitations on use and expires in 2024.
As of December 31, 2022 and 2021, we have a valuation allowance of $21.6 million and $23.7 million, respectively, related to our deferred tax assets on net operating losses and capital losses. We estimate the amount of valuation allowance based upon our expectations of taxable income in the various jurisdictions in which we operate and the period over which we can utilize those future deductions. The valuation allowance reflects uncertainties related to our ability to utilize certain net operating loss carryforwards before they expire. In 2022, there was a $2.3 million decrease in the valuation allowance for the U.S. net operating loss and a $0.1 million increase in the foreign net operating loss valuation allowance due to changes in our estimates of the amount of loss carryforwards that will be realized, based upon future taxable income.
The realization of net deferred income tax assets recorded as of December 31, 2022 is dependent upon our ability to generate future taxable income in the United States. We believe it is more likely than not that the net deferred income tax assets as of December 31, 2022 will be realized, based on expected future taxable income.
24. SEGMENT INFORMATION
Our reportable business segments consist of the pipeline, storage and fuels marketing segments. Our segments represent strategic business units that offer different services and products. We evaluate the performance of each segment based on its respective operating income, before general and administrative expenses and certain non-segmental depreciation and amortization expense. General and administrative expenses are not allocated to the operating segments since those expenses relate primarily to the overall management at the entity level. We are primarily engaged in the transportation, terminalling and storage of petroleum products and renewable fuels and the transportation of anhydrous ammonia. We also market petroleum products.
Results of operations for the reportable segments were as follows:
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2022 | | 2021 | | 2020 |
| | (Thousands of Dollars) |
| Revenues: | | | | | |
| Pipeline | $ | 828,191 | | | $ | 762,238 | | | $ | 718,823 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Storage | 334,549 | | | 427,668 | | | 494,442 | |
| | | | | |
| Fuels marketing | 520,486 | | | 428,608 | | | 268,345 | |
| Consolidation and intersegment eliminations | (3) | | | (14) | | | (46) | |
| Total revenues | $ | 1,683,223 | | | $ | 1,618,500 | | | $ | 1,481,564 | |
| | | | | |
| Depreciation and amortization expense: | | | | | |
| Pipeline | $ | 178,802 | | | $ | 179,088 | | | $ | 177,384 | |
| Storage | 73,076 | | | 87,500 | | | 99,092 | |
| | | | | |
| Total segment depreciation and amortization expense | 251,878 | | | 266,588 | | | 276,476 | |
| Other depreciation and amortization expense | 7,358 | | | 7,792 | | | 8,625 | |
| Total depreciation and amortization expense | $ | 259,236 | | | $ | 274,380 | | | $ | 285,101 | |
| | | | | |
| Operating income: | | | | | |
| Pipeline | $ | 438,670 | | | $ | 321,472 | | | $ | 118,429 | |
| Storage | 61,081 | | | 24,800 | | | 189,781 | |
| Fuels marketing | 33,536 | | | 11,181 | | | 12,233 | |
| | | | | |
| Total segment operating income | 533,287 | | | 357,453 | | | 320,443 | |
| General and administrative expenses | 117,116 | | | 113,207 | | | 102,716 | |
| Other depreciation and amortization expense | 7,358 | | | 7,792 | | | 8,625 | |
| | | | | |
| | | | | |
| Total operating income | $ | 408,813 | | | $ | 236,454 | | | $ | 209,102 | |
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Revenues by geographic area are shown in the table below:
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2022 | | 2021 | | 2020 |
| | (Thousands of Dollars) |
| United States | $ | 1,667,672 | | | $ | 1,582,672 | | | $ | 1,441,892 | |
| Foreign | 15,551 | | | 35,828 | | | 39,672 | |
| Consolidated revenues | $ | 1,683,223 | | | $ | 1,618,500 | | | $ | 1,481,564 | |
For the years ended December 31, 2022, 2021 and 2020, Valero Energy Corporation accounted for approximately 18%, or $307.3 million, 19%, or $308.5 million, and 20%, or $295.1 million, of our revenues, respectively. These revenues were included in all of our reportable business segments. No other single customer accounted for 10% or more of our consolidated revenues.
Total amounts of property, plant and equipment, net by geographic area were as follows:
| | | | | | | | | | | |
| | December 31, |
| | 2022 | | 2021 |
| | (Thousands of Dollars) |
| United States | $ | 3,359,427 | | | $ | 3,428,441 | |
| Foreign | 43,656 | | | 113,201 | |
| Consolidated property, plant and equipment, net | $ | 3,403,083 | | | $ | 3,541,642 | |
Total assets by reportable segment were as follows:
| | | | | | | | | | | |
| | December 31, |
| | 2022 | | 2021 |
| | (Thousands of Dollars) |
| Pipeline | $ | 3,360,685 | | | $ | 3,441,272 | |
| Storage | 1,438,609 | | | 1,537,037 | |
| Fuels marketing | 37,763 | | | 41,562 | |
| Total segment assets | 4,837,057 | | | 5,019,871 | |
| | | |
| Other partnership assets | 136,629 | | | 136,461 | |
| Total consolidated assets | $ | 4,973,686 | | | $ | 5,156,332 | |
Capital expenditures by reportable segment were as follows: | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2022 | | 2021 | | 2020 |
| | (Thousands of Dollars) |
| Pipeline | $ | 90,430 | | | $ | 67,340 | | | $ | 122,512 | |
| Storage | 47,222 | | | 112,043 | | | 71,788 | |
| | | | | |
| Other partnership assets | 2,978 | | | 1,750 | | | 3,779 | |
| Total capital expenditures | $ | 140,630 | | | $ | 181,133 | | | $ | 198,079 | |
ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.CONTROLS AND PROCEDURES
DISCLOSURE CONTROLS AND PROCEDURES
Our management has evaluated, with the participation of the principal executive officer and principal financial officer of NuStar GP, LLC, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the 2015 awards, 2016 awardsSecurities Exchange Act of 1934) as of the end of the period covered by this report, and 2017 awards with respecthas concluded that our disclosure controls and procedures were effective as of December 31, 2022.
INTERNAL CONTROL OVER FINANCIAL REPORTING
(a)Management’s Report on Internal Control over Financial Reporting.
Management’s report on NuStar Energy L.P.’s internal control over financial reporting appears in Item 8. of this Form 10-K, and is incorporated herein by reference.
(b)Attestation Report of the Registered Public Accounting Firm.
The report of KPMG LLP on NuStar Energy L.P.’s internal control over financial reporting appears in Item 8. of this Form 10-K, and is incorporated herein by reference.
(c)Changes in Internal Control over Financial Reporting.
There has been no change in our internal control over financial reporting that occurred during our last fiscal quarter that has materially affected, or is reasonably likely to 2017 performance did not vest. Seematerially affect, our internal control over financial reporting.
ITEM 9B.OTHER INFORMATION
None.
ITEM 9C.DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
PART III
ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information required to be disclosed under this Item 10 is incorporated by reference to the table entitledfollowing sections of our Proxy Statement for the 2023 annual meeting of unitholders (Proxy Statement), which is expected to be filed within 120 days after the end of the fiscal year covered by this Form 10-K: “Corporate Governance;” “Proposal No. 1 Election of Directors;” and “Information About Our Executive Officers.”
ITEM 11. EXECUTIVE COMPENSATION
Information required to be disclosed under this Item 11 is incorporated by reference to the following sections of our Proxy Statement: “Compensation Discussion and Analysis;” “Evaluation of Compensation Risk;” “Summary Compensation Table;” “Pay Ratio;” “Grants of Plan-Based Awards During the Year Ended December 31, 2017” for the performance units that did not vest with respect to the 2017 performance period. See “Compensation Discussion and Analysis-Elements of Executive Compensation-Long Term Incentive Awards-Performance Units” for a description of the performance measure and the performance level attained with respect to the 2017 performance period.
If the maximum level of performance (200%) had been assumed for all of the target unvested performance units reported in the table, the number of performance units outstanding and the market value thereof as of December 31, 2017 would have been twice the amounts reflected in the table.
| |
(2) | Mr. Barron’s restricted NuStar Energy units consist of: 950 restricted units granted December 16, 2013; 2,862 restricted units granted December 19, 2014; 6,000 restricted units granted November 16, 2015; 8,800 restricted units granted November 16, 2016; and 16,660 restricted units granted November 16, 2017. All of Mr. Barron’s NuStar Energy restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant. |
| |
(3) | Mr. Barron’s restricted NuStar GP Holdings units consist of: 688 restricted units granted December 16, 2013; 1,922 restricted units granted December 19, 2014; 4,380 restricted units granted November 16, 2015; 7,200 restricted units granted November 16, 2016; and 13,315 restricted units granted November 16, 2017. All of Mr. Barron’s NuStar GP Holdings restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant. |
| |
(4) | Mr. Shoaf’s target number of NuStar Energy performance units consist of: 1,313 units awarded January 29, 2015; 4,156 units awarded February 24, 2016; and 4,776 units awarded February 23, 2017. The performance units vest in accordance with the description in footnote (1) above. |
| |
(5) | Mr. Shoaf’s restricted NuStar Energy units consist of: 637 restricted units granted December 16, 2013; 1,444 restricted units granted December 19, 2014; 2,790 restricted units granted November 16, 2015; 3,936 restricted units granted November 16, 2016; and 7,295 restricted units granted November 16, 2017. All of Mr. Shoaf’s NuStar Energy restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant. |
| |
(6) | Mr. Shoaf’s restricted NuStar GP Holdings units consist of: 461 restricted units granted December 16, 2013; 970 restricted units granted December 19, 2014; 2,058 restricted units granted November 16, 2015; 3,232 restricted units granted November 16, 2016; and 5,830 restricted units granted November 16, 2017. All of Mr. Shoaf’s NuStar GP Holdings restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant. |
| |
(7) | Ms. Brown’s target number of NuStar Energy performance units consist of: 1,414 units awarded January 29, 2015; 4,476 units awarded February 24, 2016; and 5,145 units awarded February 23, 2017. The performance units vest in accordance with the description in footnote (1) above. |
| |
(8) | Ms. Brown’s restricted NuStar Energy units consist of: 950 restricted units granted December 16, 2013; 1,554 restricted units granted December 19, 2014; 3,003 restricted units granted November 16, 2015; 4,240 restricted units granted November 16, 2016; and 7,860 restricted units granted November 16, 2017. All of Ms. Brown’s NuStar Energy restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant. |
| |
(9) | Ms. Brown’s restricted NuStar GP Holdings units consist of: 688 restricted units granted December 16, 2013; 1,044 restricted units granted December 19, 2014; 2,217 restricted units granted November 16, 2015; 3,480 restricted units granted November 16, 2016; and 6,280 restricted units granted November 16, 2017. All of Ms. Brown’s NuStar GP Holdings restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant. |
| |
(10) | Mr. Oliver’s target number of NuStar Energy performance units consist of: 996 units awarded January 29, 2015; 3,152 units awarded February 24, 2016; and 3,624 units awarded February 23, 2017. The performance units vest in accordance with the description in footnote (1) above. |
| |
(11) | Mr. Oliver’s restricted NuStar Energy units consist of: 671 restricted units granted December 16, 2013; 1,094 restricted units granted December 19, 2014; 2,115 restricted units granted November 16, 2015; 2,984 restricted units granted November 16, 2016; and 4,615 restricted units granted November 16, 2017. All of Mr. Oliver’s NuStar Energy restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant. |
| |
(12) | Mr. Oliver’s restricted NuStar GP Holdings units consist of: 486 restricted units granted December 16, 2013; 736 restricted units granted December 19, 2014; 1,560 restricted units granted November 16, 2015; 2,452 restricted units granted November 16, 2016; and 3,690 restricted units granted November 16, 2017. All of Mr. Oliver’s NuStar GP Holdings restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant. |
| |
(13) | Mr. Truby’s target number of NuStar Energy performance units consist of: 664 units awarded July 23, 2015; 2,224 units awarded February 24, 2016; and 2,556 units awarded February 23, 2017. The performance units vest in accordance with the description in footnote (1) above. |
| |
(14) | Mr. Truby’s restricted NuStar Energy units consist of: 747 restricted units granted December 16, 2013; 1,018 restricted units granted December 19, 2014; 1,491 restricted units granted November 16, 2015; 2,104 restricted units granted November 16, 2016; and 4,290 restricted units granted November 16, 2017. All of Mr. Truby’s NuStar Energy restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant. |
| |
(15) | Mr. Truby’s restricted NuStar GP Holdings units consist of: 1,101 restricted units granted November 16, 2015; 1,728 restricted units granted November 16, 2016; and 3,430 restricted units granted November 16, 2017. All of Mr. Truby’s NuStar GP Holdings restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant. |
OPTION EXERCISES AND UNITS VESTED
DURING THE YEAR ENDED DECEMBER 31, 2017
The following table provides information regarding the vesting of restricted units and performance units held by our NEOs during 2017. None of our NEOs had outstanding unit option awards during 2017.
|
| | | |
| Unit2022;” “Outstanding Equity Awards |
Name | Number of Units
Acquired on Vesting (#)
| Value Realized
on Vesting ($)(1)
|
Barron | 27,269(2)
| 1,106,122 |
|
Shoaf | 13,734(3)
| 553,181 |
|
Brown | 15,654(4)
| 616,374 |
|
Oliver | 10,988(5)
| 430,859 |
|
Truby | 6,074(6)
| 237,937 |
|
| |
(1) | The value realized on vesting of NuStar Energy restricted units and performance units was calculated by multiplying the closing price of NuStar Energy common units on the NYSE on the date of vesting by the number of NuStar Energy units vested. The value realized on vesting of NuStar GP Holdings restricted units was calculated by multiplying the closing price of NuStar GP Holdings common units on the NYSE on the date of vesting by the number of NuStar GP Holdings units vested. In the case of the December 16, 2017 vesting date, which was not a trading day, the value realized was calculated using the NuStar Energy or NuStar GP Holdings closing price, as applicable, on the preceding trading day. The closing prices on the applicable dates are as follows: |
|
| | |
Closing Prices for 2017 Vestings |
Date | NuStar Energy Closing Price ($) |
January 26, 2017 | 55.31 |
|
November 16, 2017 | 29.22 |
|
December 15, 2017 | 30.54 |
|
December 19, 2017 | 30.18 |
|
Date | NuStar GP Holdings Closing Price ($) |
November 16, 2017 | 15.65 |
|
December 15, 2017 | 15.05 |
|
December 19, 2017 | 14.50 |
|
| |
(2) | Mr. Barron's restricted NuStar Energy units vested in 2017 as follows: 4,200 units on November 16, 2017; 950 units on December 16, 2017; and 2,121 units on December 19, 2017. Mr. Barron's restricted NuStar GP Holdings units vested in 2017 as follows: 3,260 units on November 16, 2017; 688 units on December 16, 2017; and 1,439 units on December 19, 2017. On January 26, 2017, 14,611 of Mr. Barron’s NuStar Energy performance units vested. |
| |
(3) | Mr. Shoaf’s restricted NuStar Energy units vested in 2017 as follows: 1,914 units on November 16, 2017; 637 units on December 16, 2017; and 1,190 units on December 19, 2017. Mr. Shoaf’s restricted NuStar GP Holdings units vested in 2017 as follows: 1,494 units on November 16, 2017; 461 units on December 16, 2017; and 809 units on December 19, 2017. On January 26, 2017, 7,229 of Mr. Shoaf’s NuStar Energy performance units vested. |
| |
(4) | Ms. Brown’s restricted NuStar Energy units vested in 2017 as follows: 2,061 units on November 16, 2017; 950 units on December 16, 2017; and 1,523 units on December 19, 2017. Ms. Brown’s restricted NuStar GP Holdings units vested in 2017 as follows: 1,609 units on November 16, 2017; 688 units on December 16, 2017; and 1,038 units on December 19, 2017. On January 26, 2017, 7,785 of Ms. Brown’s NuStar Energy performance units vested. |
| |
(5) | Mr. Oliver’s restricted NuStar Energy units vested in 2017 as follows: 1,451 units on November 16, 2017; 671 units on December 16, 2017; and 1,114 units on December 19, 2017. Mr. Oliver’s restricted NuStar GP Holdings units vested in 2017 as follows: 1,133 units on November 16, 2017; 486 units on December 16, 2017; and 733 units on December 19, 2017. On January 26, 2017, 5,400 of Mr. Oliver’s NuStar Energy performance units vested. |
| |
(6) | Mr. Truby’s restricted NuStar Energy units vested in 2017 as follows: 1,023 units on November 16, 2017; 747 units on December 16, 2017; and 841 units on December 19, 2017. On November 16, 2017, 799 of Mr. Truby’s restricted NuStar GP Holdings units vested. On January 26, 2017, 2,664 of Mr. Truby’s NuStar Energy performance units vested. |
POST-EMPLOYMENT COMPENSATION
PENSION BENEFITS
FOR THE YEAR ENDED DECEMBER 31, 2017
We maintain a noncontributory defined benefit pension plan (the Pension Plan) in which most of our employees are eligible to participate and under which contributions by individual participants are neither required nor permitted. We also maintain a noncontributory, non-qualified excess pension plan (the Excess Pension Plan), which provides supplemental pension benefits to certain highly compensated employees. The Excess Pension Plan provides eligible employees with additional retirement savings opportunities that cannot be achieved with tax-qualified plans due to the Code’s limits on (1) annual compensation that can be taken into account under qualified plans or (2) annual benefits that can be provided under qualified plans.
The following table provides information regarding the accumulated benefits of our NEOs under our pension plans during the year ended December 31, 2017.
|
| | | | | | | | | |
Name | Plan Name | Number of Years
Credited Service
| Present Value of
Accumulated
Benefit ($)(1)
| Payments During Last
Fiscal Year ($)
|
Barron | Pension Plan | (2)
| | 366,056 |
| | — |
| |
Excess Pension Plan | (2)
| | 610,215 |
| | — |
| |
Shoaf | Pension Plan | (2)
| | 483,611 |
| | — |
| |
Excess Pension Plan | (2)
| | 482,321 |
| | — |
| |
Brown | Pension Plan | (2)
| | 484,661 |
| | — |
| |
Excess Pension Plan | (2)
| | 611,118 |
| | — |
| |
Oliver | Pension Plan | (2)
| | 336,416 |
| | — |
| |
Excess Pension Plan | (2)
| | 376,814 |
| | — |
| |
Truby | Pension Plan | (2)
| | 465,657 |
| | — |
| |
Excess Pension Plan | (2)
| | 132,458 |
| | — |
| |
| |
(1) | The present values stated in the table above were calculated using the same interest rates and mortality tables we use for our financial reporting. The present values as of December 31, 2017 were determined using plan-specific discount rates (3.73% for the Pension Plan and 3.42% for the Excess Pension Plan) and the plans’ earliest unreduced retirement age (age 62). The present values reflect post-retirement mortality rates based on the RP2006 generational mortality table projected using scale MP2016. No decrements were included for pre-retirement termination, mortality or disability. Where applicable, lump sums were determined based on a 3.23% interest rate and the mortality table prescribed by the IRS in Rev. Ruling 2007-67 and updated by IRS Notices 2008-85 and 2013-49 for distributions in the years 2009-2017. |
| |
(2) | As of December 31, 2013, the final average pay formula used in the Pension Plan and the Excess Pension Plan, which was based on years of service and compensation during service, was frozen. Benefits for service after December 31, 2013 accrue under a cash balance formula described below. The number of years of credited service under the final average pay formula and the cash balance formula for each of our NEOs under the Pension Plan and the Excess Pension Plan are set forth below. |
|
| | | | | | |
| Name | Plan Name | Number of Years Credited Service - Final Average Pay Formula (Frozen as of December 31, 2013) | Number of Years Credited Service - Cash Balance Formula |
| Barron | Pension Plan | 7.5 |
| | 17.0 |
|
| Excess Pension Plan | 13.0 |
| | 17.0 |
|
| Shoaf | Pension Plan | 7.5 |
| | 32.5 |
|
| Excess Pension Plan | 28.5 |
| | 32.5 |
|
| Brown | Pension Plan | 6.7 |
| | 20.3 |
|
| Excess Pension Plan | 6.7 |
| | 20.3 |
|
| Oliver | Pension Plan | 6.8 |
| | 20.7 |
|
| Excess Pension Plan | 6.8 |
| | 20.7 |
|
| Truby | Pension Plan | 7.5 |
| | 25.0 |
|
| Excess Pension Plan | 7.5 |
| | 25.0 |
|
Pension Plan
The Pension Plan is a qualified, non-contributory defined benefit pension plan that became effective as of July 1, 2006. The Pension Plan covers substantially all of our employees and generally provides retirement income calculated under a cash balance formula (CBF), which is comprised of contribution credits based on age and years of vesting service and interest credits. Employees become fully vested in their CBF benefits upon attaining three years of vesting service. Prior to January 1, 2014, eligible employees were covered under either the CBF or a defined benefit final average pay formula (FAP) based on years of service and compensation during their period of service, and employees became fully vested in their benefits upon attaining five years of service under the FAP and upon attaining three years of service under the CBF. The Pension Plan was amended to freeze the FAP benefit at December 31, 20132022;” “Option Exercises and on or after January 1, 2014, all employees are covered underUnits Vested During the CBF.
An eligible employee’s benefits under the Pension Plan will be equal to:
1.6% of the employee’s average monthly compensation multiplied by the employee’s years of credited service for service through December 31, 2013 for the FAP benefit plus
the employee’s CBF account balance.
An employee may start receiving his or her benefits under the Pension Plan at any time following his or her separation of service, but must begin receiving benefits by April 1 of the year after the employee attains age 70½. Mr. Shoaf, Ms. Brown and Mr. Truby have attained the Early Retirement Age, which is defined in the Pension Plan as age 55. If an employee with a FAP benefit begins receiving benefits after the Early Retirement Age and before age 62, the FAP benefit amount will be reduced by 4% for each full year between the benefit start date and age 62. If an employee with a FAP benefit begins receiving benefits before the Early Retirement Age, the amount of the FAP benefit will be the actuarial equivalent of the lump sum that otherwise would have been payable on the date the employee starts benefits. The CBF benefit amount under the Pension Plan is based on the CBF account balance and, therefore, is not reduced based on the age at which the employee begins receiving benefits.
Excess Pension Plan
The Excess Pension Plan, which became effective July 1, 2006, provides benefits to our eligible employees whose pension benefits under the Pension Plan and the Valero Energy Pension Plan, where applicable, are subject to limitations under the Code. The Excess Pension Plan is an excess benefit plan as contemplated under ERISA for those benefits provided in excess of the maximum amount allowable under Section 415 of the Code. Benefits provided as a result of other statutory limitations are limited to a select group of management or highly compensated employees. The Excess Pension Plan is not intended to constitute either a qualified plan under the Code or a funded plan subject to ERISA. For our employees who were eligible to receive a benefit under the Valero Energy Excess Pension Plan (the Predecessor Excess Pension Plan) as of July 1, 2006, the Excess Pension Plan assumed the liabilities of the Predecessor Excess Pension Plan and will provide a single, nonqualified defined benefit to eligible employees for their pre-July 1, 2006 benefit accruals under the Predecessor Excess Pension Plan and their post-July 1, 2006 benefit accruals under the Excess Pension Plan.
An eligible employee’s monthly pension under the Excess Pension Plan will be equal to:
1.6% of the employee’s average monthly compensation multiplied by the employee’s years of credited service for service through December 31, 2013, plus
the employee’s CBF benefits, in each case without regard to the limitations imposed by the Code, less
the employee’s Pension Plan benefit.
All of our NEOs participated in the Excess Pension Plan during 2017.
NONQUALIFIED DEFERRED COMPENSATION
FOR THE YEAR ENDED DECEMBER 31, 2017
The following table provides information regarding our contributions and the contributions by each of our NEOs under our non-qualified defined contribution plan, the Excess Thrift Plan, during the year ended December 31, 2017. The table also presents each NEO’s withdrawals, earnings and year-end balances in such plan. Please see the description of our Excess Thrift Plan above in “Compensation Discussion and Analysis-Elements of Executive Compensation-Post-Employment Benefits.”
|
| | | | | | | | | | | | | | | |
| Name | Executive Contributions in 2017 ($)(1) | Registrant Contributions in 2017 ($)(2) | Aggregate Earnings/(Losses) in 2017 ($)(3) | Aggregate Withdrawals/ Distributions ($) | Aggregate Balance at December 31, 2017 ($)(4) |
| Barron | — |
| | 36,316 |
| | (37,400 | ) | | — |
| | 83,402 |
| |
| Shoaf | — |
| | 7,226 |
| | (5,798 | ) | | — |
| | 15,482 |
| |
| Brown | — |
| | 42,543 |
| | (36,590 | ) | | — |
| | 75,737 |
| |
| Oliver | — |
| | 11,392 |
| | (6,711 | ) | | — |
| | 15,728 |
| |
| Truby | — |
| | 4,678 |
| | (1,349 | ) | | — |
| | 3,637 |
| |
| |
(1) | The NEOs made no contributions during 2017. |
| |
(2) | Amounts reported represent our contributions to our Excess Thrift Plan. All of the amounts included in this column are included within the amounts reported as “All Other Compensation” for 2017 in the Summary Compensation Table. |
| |
(3) | Amounts reported reflect the losses for each NEO’s respective account in our Excess Thrift Plan. |
| |
(4) | Amounts include the aggregate balance at year end, if any, of each NEO’s respective account in our Excess Thrift Plan and include registrant contributions that were previously reported as compensation to each of the NEOs in the “All Other Compensation” column in the Summary Compensation Table for 2017 and previous years, as applicable. |
POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE OF CONTROL
SEC regulations require us to disclose potential payments to an NEO in connection with his or her termination or a change of control of NuStar Energy, other than those amounts disclosed under the headings “Pension Benefits For The Year Ended December 31, 2017” and “Nonqualified Deferred Compensation For The2022;” “Pension Benefits for the Year Ended December 31, 2017” above in this Item 112022;” “Nonqualified Deferred Compensation for the Year Ended December 31, 2022;” “Potential Payments Upon Termination or amounts pursuant to arrangements that do not discriminate in favorChange of executive officersControl;” “Pay Versus Performance;” “Director Compensation;” “Corporate Governance-Compensation Committee Interlocks and are generally available to salaried employees. The following narrativeInsider Participation;” “Compensation Committee Report;” “Corporate Governance-Board Structure and table provide the required disclosures.
None of our NEOs have employment agreements, other than the change of control severance agreements described below. As a result, in the event of a termination, retirement, death or disability that does not occur in connection with a change of control, an NEO will only receive the compensation or benefits to which he or she would already be entitled under the terms of, as applicable, the defined contribution, defined benefit, medical or long-term incentive plans. Therefore, these scenarios are not presented in the table below.
Each of our NEOs has entered into a change of control severance agreement with NuStar EnergyGovernance;” and our wholly owned subsidiary, NuStar Services Co. These agreements seek to ensure the continued availability of these executives in the event of a “change of control” (described below). The agreements contain tiers of compensation and benefits based on each NEO’s position. Each tier corresponds to a certain “severance multiple” used to calculate cash severance and other benefits to be provided under the agreements. The following table sets forth the severance multiple applicable to each NEO, based on his or her current officer position.
|
| | |
Name | Applicable Officer Position | Severance Multiple |
Barron | Chief Executive Officer | 3 |
Shoaf | Executive Vice President | 2.5 |
Brown | Executive Vice President | 2.5 |
Oliver | Senior Vice President | 2 |
Truby | Senior Vice President | 2 |
If a change of control occurs, the agreements become operative for a fixed three-year period. The agreements provide generally that the NEO’s terms of employment will not be adversely changed during the three-year period after a change of control. In addition, any outstanding unit options held by the NEO will automatically vest, restrictions applicable to any outstanding restricted units held by the NEO will lapse and any unvested performance units held by the NEO will fully vest and become payable at 200% of target. The NEOs also are entitled to receive a payment in an amount sufficient to make the NEO whole for any excise tax on excess parachute payments imposed under Section 4999“Corporate Governance-Committees of the Code, as set forth in the table below. Each agreement subjects the NEO to obligations of confidentiality, both during the term and after termination, for secret and confidential information that the NEO acquired during his or her employment relating to NuStar Energy, NuStar Services Co and affiliated companies.Board.”
For purposes of these agreements, a “change of control” means any of the following (subject to additional particulars as stated in the agreements):
the acquisition by an individual, entity or group of beneficial ownership of 40% of NuStar GP Holdings’ voting interests;
the failure of NuStar GP Holdings to control NuStar GP, LLC, NuStar Energy’s general partner, Riverwalk Logistics, L.P., or all of the general partner interests of NuStar Energy;
Riverwalk Logistics, L.P. ceases to be NuStar Energy’s general partner or Riverwalk Logistics, L.P. is no longer controlled by either NuStar GP, LLC or one of its affiliated companies;
the acquisition of more than 50% of all voting interests of NuStar Energy then outstanding;
certain consolidations or mergers of NuStar GP Holdings;
certain consolidations or mergers of NuStar Energy;
the sale of all or substantially all of the assets of NuStar GP Holdings to anyone other than its affiliated companies;
the sale of all or substantially all of the assets of NuStar Energy to anyone other than its affiliated companies; or
a change in the composition of the NuStar GP Holdings board of directors so that fewer than a majority of those directors are “incumbent directors” as defined in the agreements.
In the agreements, “cause” is defined to mean, generally, the willful and continued failure of the NEO to perform substantially his or her duties, or the willful engaging by the NEO in illegal or gross misconduct that is materially and demonstrably injurious to NuStar Energy, NuStar Services Co or any affiliated company.
“Good reason” is defined to mean, generally:
a diminution in the NEO’s position, authority, duties or responsibilities;
failure of the successor of NuStar Energy or NuStar Services Co to assume and perform under the agreement; and
relocation of the NEO or increased travel requirements.
Except as otherwise noted, the values in the table below assume that a change of control occurred on December 31, 2017 and that the NEO’s employment terminated on that date.
Under the change of control severance agreements, if an NEO’s employment is terminated for “cause” following a change of control, the NEO will not receive any additional benefits or compensation as a result of the termination and will only receive accrued salary or vacation pay that remained unpaid through the date of termination and any other benefits that the NEO would already be entitled to receive, if any. Therefore, there is no presentation of termination for “cause” in the table below.
Each of our NEOs has agreed and acknowledged that the Merger will not be deemed to trigger a “change of control” as defined under any NuStar Energy or NuStar GP Holdings plan or award, and has waived any rights to vesting, payment or other benefit thereunder that would arise upon a “change of control,” to which he or she might otherwise have been entitled.
|
| | | | | | | | | | | | | | | | |
Executive Benefits and Payments(1) | Termination of Employment by the Employer Other Than for “Cause,” Death or Disability, or by the Executive for “Good Reason” ($)(2) | Termination of Employment because of Death or Disability ($)(3) | Termination by the Executive Other Than for “Good Reason” ($)(4) | Continued Employment Following Change of Control ($)(5) |
Salary (1) | | | | | | | |
| Barron | | 1,776,750 |
| | | — |
| | | — |
| | | — |
| |
| Shoaf | 900,500 | | | — | | | — | | | — | | |
| Brown | 970,000 | | | — | | | — | | | — | | |
| Oliver | 656,000 | | | — | | | — | | | — | | |
| Truby | 610,000 | | | — | | | — | | | — | | |
Bonus (1) | | | | | | | |
| Barron | | 3,200,000 |
| | | 800,000 |
| | | 800,000 |
| | | 800,000 |
| |
| Shoaf | 1,125,432 | | | 321,552 | | | 321,552 | | | 321,552 | | |
| Brown | 1,212,005 | | | 346,287 | | | 346,287 | | | 346,287 | | |
| Oliver | 784,761 | | | 261,587 | | | 261,587 | | | 261,587 | | |
| Truby | 630,000 | | | 210,000 | | | 210,000 | | | 210,000 | | |
| Pension and Excess Pension Benefits | | | | | | | |
| Barron | | 424,576 |
| | | — |
| | | — |
| | | — |
| |
| Shoaf | 247,975 | | | — | | | — | | | — | | |
| Brown | 348,378 | | | — | | | — | | | — | | |
| Oliver | 142,462 | | | — | | | — | | | — | | |
| Truby | 137,743 | | | — | | | — | | | — | | |
| Contributions under Defined Contribution Plans | | | | | | | |
| Barron | | 157,547 |
| | | — |
| | | — |
| | | — |
| |
| Shoaf | 58,564 | | | — | | | — | | | — | | |
| Brown | 139,321 | | | — | | | — | | | — | | |
| Oliver | 55,184 | | | — | | | — | | | — | | |
| Truby | 41,755 | | | — | | | — | | | — | | |
Health and Welfare Plan Benefits (6) | | | | | | |
| Barron | | 43,932 |
| | | — |
| | | — |
| | | — |
| |
| Shoaf | 53,709 | | | — | | | — | | | — | | |
| Brown | 28,662 | | | — | | | — | | | — | | |
| Oliver | 42,209 | | | — | | | — | | | — | | |
| Truby | 27,566 | | | — | | | — | | | — | | |
|
| | | | | | | | | | | | | | | | |
Executive Benefits and Payments(1) | Termination of Employment by the Employer Other Than for “Cause,” Death or Disability, or by the Executive for “Good Reason” ($)(2) | Termination of Employment because of Death or Disability ($)(3) | Termination by the Executive Other Than for “Good Reason” ($)(4) | Continued Employment Following Change of Control ($)(5) |
| Accelerated Vesting of Unit Options | | | | | | | | | | | | |
| Barron | | — |
| | | — |
| | | — |
| | | — |
| |
| Shoaf | | — |
| | | — |
| | | — |
| | | — |
| |
| Brown | | — |
| | | — |
| | | — |
| | | — |
| |
| Oliver | | — |
| | | — |
| | | — |
| | | — |
| |
| Truby | | — |
| | | — |
| | | — |
| | | — |
| |
Accelerated Vesting of Restricted Units (7) | | | | | | | |
| Barron | | 1,488,225 |
| | | 1,488,225 |
| | | 1,488,225 |
| | | 1,488,225 |
| |
| Shoaf | 679,306 | | | 679,306 | | | 679,306 | | | 679,306 | | |
| Brown | 742,561 | | | 742,561 | | | 742,561 | | | 742,561 | | |
| Oliver | 483,903 | | | 483,903 | | | 483,903 | | | 483,903 | | |
| Truby | 387,284 | | | 387,284 | | | 387,284 | | | 387,284 | | |
Accelerated Vesting of Performance Units (8) | | | | | | | |
| Barron | | 1,346,552 |
| | | 1,346,552 |
| | | 1,346,552 |
| | | 1,346,552 |
| |
| Shoaf | 613,676 | | | 613,676 | | | 613,676 | | | 613,676 | | |
| Brown | 660,996 | | | 660,996 | | | 660,996 | | | 660,996 | | |
| Oliver | 465,542 | | | 465,542 | | | 465,542 | | | 465,542 | | |
| Truby | 326,096 | | | 326,096 | | | 326,096 | | | 326,096 | | |
280G Tax Gross-Up (9) | | | | | | | |
| Barron | | 3,312,255 |
| | | — |
| | | — |
| | | — |
| |
| Shoaf | 1,350,583 | | | — | | | — | | | — | | |
| Brown | 1,388,646 | | | — | | | — | | | — | | |
| Oliver | — | | | — | | | — | | | — | | |
| Truby | 777,507 | | | — | | | — | | | — | | |
| Totals | | | | | | |
| Barron | | 11,749,837 |
| | | 3,634,777 |
| | | 3,634,777 |
| | | 3,634,777 |
| |
| Shoaf | 5,029,745 | | | 1,614,534 | | | 1,614,534 | | | 1,614,534 | | |
| Brown | 5,490,569 | | | 1,749,844 | | | 1,749,844 | | | 1,749,844 | | |
| Oliver | 2,630,061 | | | 1,211,032 | | | 1,211,032 | | | 1,211,032 | | |
| Truby | 2,937,951 | | | 923,380 | | | 923,380 | | | 923,380 | | |
| |
(1) | Per SEC regulations, for purposes of this analysis we assumed each NEO’s compensation at the time of each triggering event to be as stated below. The listed salary is the NEO’s actual annualized rate of pay as of December 31, 2017. The listed bonus amount (referred to in these footnotes as the Highest Annual Bonus) represents the highest bonus earned by the executive with respect to any of the fiscal years 2014, 2015 and 2016 (the three full fiscal years prior to the date of the assumed change of control) or the most recent fiscal year (2017): |
|
| | | | | | | | |
| Name | Annual Salary ($) | Highest Annual Bonus ($) |
| Barron | 592,250 | | | 800,000 | | |
| Shoaf | 360,200 | | | 321,552 | | |
| Brown | 388,000 | | | 346,287 | | |
| Oliver | 328,000 | | | 261,587 | | |
| Truby | 305,000 | | | 210,000 | | |
| |
(2) | The change of control severance agreements provide that if the employer terminates the NEO’s employment (other than for “cause,” death or “disability,” as defined in the agreements) or if the NEO terminates his or her employment for “good reason,” as defined in the agreements, the NEO is generally entitled to receive the following: |
(A) a lump sum cash payment equal to the sum of:
| |
(i) | accrued and unpaid compensation through the date of termination, including a pro-rata annual bonus based on the Highest Annual Bonus; |
| |
(ii) | the NEO’s severance multiple multiplied by the sum of the NEO’s annual base salary plus the NEO’s Highest Annual Bonus; |
| |
(iii) | the amount of the excess of the actuarial present value of the pension benefits (qualified and nonqualified) the NEO would have received for an additional number of years of service equal to the NEO’s severance multiple over the actuarial present value of the NEO’s actual pension benefits; and |
| |
(iv) | the equivalent of employer contributions under the tax-qualified and supplemental defined contribution plans for the number of years equal to the NEO’s severance multiple; |
(B) continued welfare benefits for a number of years equal to the NEO’s severance multiple; and
(C) vesting of all outstanding equity incentive awards on the date of the change of control, as described above.
| |
(3) | If the NEO’s employment is terminated by reason of his or her death or disability, then his or her estate or beneficiaries will be entitled to receive a lump sum cash payment equal to any accrued and unpaid salary and vacation pay plus a bonus equal to the Highest Annual Bonus earned by the NEO (prorated to the date of termination). In addition, in the case of disability, the NEO would be entitled to any disability and related benefits at least as favorable as those provided by us under our plans and programs during the 120-days prior to the NEO’s termination of employment. In addition, all outstanding equity incentive awards will automatically vest on the date of the change of control, as described above. |
| |
(4) | If the NEO voluntarily terminates his or her employment other than for “good reason,” then he or she will be entitled to a lump sum cash payment equal to any accrued and unpaid salary and vacation pay plus a bonus equal to the Highest Annual Bonus earned by the NEO (prorated to the date of termination). In addition, all outstanding equity incentive awards will automatically vest on the date of the change of control, as described above. |
| |
(5) | The change of control severance agreements provide for a three-year term of employment following a change of control. The agreements generally provide that the NEO will continue to receive a salary and bonus at least as favorable as the highest salary received during the past 12 months and the highest bonus received during the past three years and will continue to receive benefits on terms at least as favorable as in effect prior to the change of control. Accordingly, no additional amounts are shown for salary, pension and excess pension benefits, contributions under defined contribution plans and health and welfare plan benefits because those amounts would remain as in effect at the time of a change of control. The amount shown as bonus reflects each NEO’s Highest Annual Bonus. In addition, all outstanding equity incentive awards will automatically vest on the date of the change of control, as described above. |
| |
(6) | The NEO is entitled to coverage under the welfare benefit plans (e.g., health, dental, etc.) for a number of years following the date of termination equal to the NEO’s severance multiple.
|
| |
(7) | The amounts stated in the table represent the gross value of previously unvested restricted units, derived by multiplying (x) the number of units whose restrictions lapsed because of the change of control, times (y) (as applicable) $29.95 (the closing price of NuStar Energy’s common units on the NYSE on December 29, 2017, the last trading day of 2017) or $15.70 (the closing price of NuStar GP Holdings’ common units on the NYSE on December 29, 2017, the last trading day of 2017). |
| |
(8) | The amounts stated in the table represent the product of (x) the number of performance units whose vesting was accelerated because of the change of control, times (y) 200%, times (z) $29.95 (the closing price of NuStar Energy’s common units on the NYSE on December 29, 2017, the last trading day of 2017). |
| |
(9) | If any payment or benefit is determined to be subject to an excise tax under Section 4999 of the Code, the impacted NEO is entitled to receive an additional payment to adjust for the incremental tax cost of the payment or benefit. However, if it is determined that the NEO is entitled to receive an additional payment to adjust for the incremental tax cost but the value of all payments to the NEO does not exceed 110% of 2.99 times the NEO’s “base amount” (as defined by Section 280G(b)(3) of the Code) (the Safe Harbor Amount), the additional payment will not be made and the amount payable to the NEO will be reduced so that the aggregate value of all payments equals the Safe Harbor Amount. |
DIRECTOR COMPENSATION
FOR THE YEAR ENDED DECEMBER 31, 2017
The following table provides a summary of compensation paid for the year ended December 31, 2017 to the directors who served on the Board during 2017. The table shows amounts earned by such persons for services rendered to NuStar GP, LLC in all capacities in which they served during 2017.
|
| | | | | | | | | | | | | | |
| Name | Fees Earned or Paid in Cash ($)(1) | Unit Awards ($)(2) | Non-Equity Incentive Plan Compensation ($)(3) | Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)(3) | All Other Compensation ($) | TOTAL ($) |
| William E. Greehey | 141,167 |
| | 119,977 |
| | N/A |
| N/A | — |
| 261,144 |
| |
| Bradley C. Barron | (4) |
| | (4 | ) | | (4 | ) | (4) | (4 | ) | (4 | ) | |
| J. Dan Bates | 106,667 |
| | 94,994 |
| | N/A |
| N/A | — |
| 201,661 |
| |
| Dan J. Hill | 121,667 |
| | 94,994 |
| | N/A |
| N/A | — |
| 216,661 |
| |
| Robert J. Munch | 90,667 |
| | 94,994 |
| | N/A |
| N/A | — |
| 185,661 |
| |
| W. Grady Rosier | 97,167 |
| | 94,994 |
| | N/A |
| N/A | — |
| 192,161 |
| |
| |
(1) | The amounts disclosed in this column exclude reimbursement for expenses for transportation to and from Board meetings and lodging while attending meetings. |
| |
(2) | The amounts reported for Messrs. Greehey, Bates, Hill and Rosier represent the grant date fair value for the November 16, 2017 grant of restricted NuStar Energy units to them as non-employee directors for the fiscal year ended December 31, 2017 (4,106 restricted units for Mr. Greehey, as Chairman, and 3,251 restricted units for each of Messrs. Bates, Hill, Munch and Rosier) based on the closing price of NuStar Energy’s common units on the NYSE on November 16, 2017 ($29.22). Please see “Compensation Discussion and Analysis-Impact of Accounting and Tax Treatments-Accounting Treatment” above in this Item 11 and Note 23 of the Notes to Consolidated Financial Statements in Item 8 for information regarding the assumptions made in the valuation. |
As of December 31, 2017, each director listed in the table above held the following aggregate number of NuStar Energy restricted units. None of the directors had outstanding unit options as of December 31, 2017. |
| | | | |
Name | Aggregate # of Restricted Units |
Greehey | 6,336 | |
Barron | * | |
Bates | 4,924 | |
Hill | 4,924 | |
Munch | 5,989 | |
Rosier | 4,924 | |
| |
* Mr. Barron’s aggregate holdings are disclosed above in the Outstanding Equity Awards at December 31, 2017 table in this Item 11. |
| |
(3) | Non-employee directors do not participate in these plans. |
| |
(4) | Mr. Barron was not compensated for his service as a director of NuStar GP, LLC. His compensation for his services as President and Chief Executive Officer is included above in the Summary Compensation Table. |
Directors who are our employees receive no compensation (other than reimbursement of expenses) for serving as directors. The compensation structure for our non-employee directors consists of the following components: (1) an annual cash retainer; (2) an annual restricted unit grant; (3) an additional cash payment for each meeting attended in-person and telephonically; (4) an additional annual cash retainer for each committee chair; (5) an additional annual retainer for the Chairman of the Board, which includes both cash and restricted units; and (6) an additional annual cash retainer for the lead director.
During 2017, the Compensation Committee engaged EPPA to review our non-employee directors’ compensation. Based on its review, EPPA recommended, and our Board and Compensation Committee approved effective July 27, 2017, increasing the annual cash retainer from $60,000 to $70,000 and increasing the value of the annual equity award from $75,000 to $95,000, resulting in the compensation structure for our non-employee directors set forth in the table below.
|
| | |
Non-Employee Director Compensation Component | Amount |
Annual Cash Retainer ($) | 70,000 |
|
Annual Restricted Unit Grant ($ value of restricted units) | 95,000 |
|
Per Meeting Fees (in-person attendance) ($) | 1,500 |
|
Per Meeting Fees (telephonic attendance) ($) | 500 |
|
Annual Audit and Compensation Committee Chair Additional Retainers ($) | 15,000 |
|
Annual Nominating, Governance and Conflicts Committee Chair Additional Retainer ($) | 10,000 |
|
Annual Chairman of the Board Retainer ($25,000 value in restricted units/$50,000 cash) | 75,000 |
|
Annual Lead Director Additional Retainer ($) | 15,000 |
|
| |
As described above, we supplement the cash compensation paid to non-employee directors with an annual grant of restricted NuStar Energy units that vests in equal annual installments over a three-year period. We believe this annual grant of restricted units increases the non-employee directors’ identification with the interests of NuStar Energy’s unitholders through ownership of NuStar Energy common units. Upon a non-employee director’s initial election to the Board, the director will receive a grant of restricted units.
In the event of a “change of control” as defined in the 2000 LTIP, all unvested restricted units previously granted immediately become vested. The 2000 LTIP also contains anti-dilution provisions providing for an adjustment in the number of restricted units that have been granted to prevent dilution of benefits in the event there is a change in the capital structure of NuStar Energy that affects the NuStar Energy units. Each of our directors has agreed and acknowledged that the Merger will not be deemed to trigger a “change of control” as defined under any NuStar Energy or NuStar GP Holdings plan or award, and has waived any rights to vesting, payment or other benefit thereunder that would arise upon a “change of control,” to which he might otherwise have been entitled.
| |
ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS |
SECURITY OWNERSHIP OF MANAGEMENT AND DIRECTORS
The following table sets forth information as of February 20, 2018 regarding: (1) NuStar Energy common units, 8.50% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (Series A Preferred Units) and 7.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (Series B Preferred Units); and (2) NuStar GP Holdings common units, in each case beneficially owned (or deemed beneficially owned) by each director, each named executive officer and all of our directors and executive officers as a group. Unless otherwise indicated in the notes to the table, each of the named persons and members of the group has sole voting and investment power with respect to the units shown and none of the units shown are pledged as security. None of the named persons or members of the group beneficially owns (or is deemed to beneficially own) any NuStar Energy 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units.
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | NuStar Energy L.P. | | NuStar GP Holdings, LLC |
| | | Common Units | | Series A Preferred Units | | Series B Preferred Units | | Common Units |
Name of Beneficial Owner (1) | | Number of Units Beneficially Owned (2) | | Percentage of Units Beneficially Owned (2) | | Number of Units Beneficially Owned (2) | | Percentage of Units Beneficially Owned (2) | | Number of Units Beneficially Owned (2) | | Percentage of Units Beneficially Owned (2) | | Number of Units Beneficially Owned (2) | | Percentage of Units Beneficially Owned (2) |
William E. Greehey (3) | | 3,480,533 |
| | 3.7 | % | | — |
| | * | | — |
| | * | | 9,178,320 |
| | 21.4 | % |
| Bradley C. Barron | | 53,640 |
| | * |
| | — |
| | * | | — |
| | * | | 31,540 |
| | * |
|
J. Dan Bates (4) | | 33,107 |
| | * |
| | — |
| | * | | — |
| | * | | — |
| | * |
|
Dan J. Hill (5) | | 28,149 |
| | * |
| | — |
| | * | | 8,000 |
| | * | | — |
| | * |
|
| Robert J. Munch | | 2,406 |
| | * |
| | 1,000 |
| | * | | — |
| | * | | — |
| | * |
|
W. Grady Rosier (6) | | 35,035 |
| | * |
| | — |
| | * | | 12,000 |
| | * | | — |
| | * |
|
| Mary Rose Brown | | 59,125 |
| | * |
| | — |
| | * | | — |
| | * | | 46,977 |
| | * |
|
| Thomas R. Shoaf | | 25,137 |
| | * |
| | — |
| | * | | — |
| | * | | 12,022 |
| | * |
|
| Daniel S. Oliver | | 30,628 |
| | * |
| | — |
| | * | | — |
| | * | | 12,920 |
| | * |
|
| Michael Truby | | 16,633 |
| | * |
| | — |
| | * | | — |
| | * | | 1,028 |
| | * |
|
| | | | | | | | | | | | | | | | | |
All directors and executive officers as a group (13 people) (7) | | 3,797,807 |
| | 4.1 | % | | 1,000 | | * | | 20,000 |
| | * | | 9,286,349 |
| | 21.6 | % |
| | | | | | | | | | | | | | | | | |
| * Indicates that the percentage of beneficial ownership does not exceed 1% of the class. |
| |
(1) | The business address for all beneficial owners listed above is 19003 IH-10 West, San Antonio, Texas 78257. |
| |
(2) | As of February 20, 2018, 93,182,030 NuStar Energy common units, 9,060,000 NuStar Energy Series A Preferred Units, 15,400,000 NuStar Energy Series B Preferred Units, 6,900,000 NuStar Energy Series C Preferred Units and 42,953,132 NuStar GP Holdings common units were outstanding. Beneficial ownership is calculated in accordance with Rule 13d-3 of the Exchange Act. Restricted units awarded under NuStar GP, LLC’s long-term incentive plan and phantom units (which we refer to as “restricted units” for purposes of Part III of this Annual Report on Form 10-K) awarded under NuStar GP Holdings’ long-term incentive plan are rights to receive NuStar Energy common units or NuStar GP Holdings common units, respectively, upon vesting and, as such, may not be disposed of or voted until vested. The restricted units do not vest within 60 days after February 20, 2018. Accordingly, the restricted units set forth in the table below are not included in the calculation of beneficial ownership pursuant to Rule 13d-3 and are not reflected in the table above. As described below in Item 13, on February 7, 2018, we, Riverwalk Logistics, L.P., NuStar GP, LLC, Merger Sub, Riverwalk Holdings, LLC and NuStar GP Holdings entered into the Merger Agreement pursuant to which Merger Sub will merge with and into NuStar GP Holdings with NuStar GP Holdings being the surviving entity, such that we will be the sole member of NuStar GP Holdings following the Merger. At the effective time of the Merger, each NuStar GP Holdings common unit outstanding will be converted into the right to receive 0.55 of a NuStar Energy common unit and each award of NuStar GP Holdings restricted units will be converted into an award of NuStar Energy restricted units, in each case as provided in the Merger Agreement. |
|
| | | | | | |
| | | Restricted Units Not Reflected in Table Above |
| Name | | NuStar Energy L.P. | | NuStar GP Holdings, LLC |
| William E. Greehey | | 6,336 |
| | 10,558 |
|
| Bradley C. Barron | | 35,272 |
| | 27,505 |
|
| J. Dan Bates | | 4,924 |
| | — |
|
| Dan J. Hill | | 4,924 |
| | — |
|
| Robert J. Munch | | 5,166 |
| | — |
|
| W. Grady Rosier | | 4,924 |
| | — |
|
| Mary Rose Brown | | 17,607 |
| | 13,709 |
|
| Thomas R. Shoaf | | 16,102 |
| | 12,551 |
|
| Daniel S. Oliver | | 11,479 |
| | 8,924 |
|
| Michael Truby | | 9,650 |
| | 6,259 |
|
| All directors and executive officers as a group (13 people) | | 140,897 |
| | 97,670 |
|
| |
(3) | The number of NuStar GP Holdings common units shown as beneficially owned by Mr. Greehey includes 385,889 common units owned indirectly by Mr. Greehey through a limited liability company. |
| |
(4) | The number of NuStar Energy common units shown as beneficially owned by Mr. Bates includes 28,526 common units owned indirectly by Mr. Bates through a trust. |
| |
(5) | The number of NuStar Energy common units shown as beneficially owned by Mr. Hill includes 600 common units owned indirectly by Mr. Hill through his spouse. |
| |
(6) | The number of NuStar Energy common units shown as beneficially owned by Mr. Rosier includes an aggregate of 29,215 common units owned indirectly by Mr. Rosier through two trusts. |
| |
(7) | The number of NuStar Energy common units shown as beneficially owned by all directors and executive officers as a group includes 28,526 common units owned indirectly by Mr. Bates, 600 common units owned indirectly by Mr. Hill and 29,215 common units owned indirectly by Mr. Rosier, as described above. The number of NuStar GP Holdings common units shown as beneficially owned by all directors and executive officers as a group includes 385,889 common units owned indirectly by Mr. Greehey. |
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The following table sets forth information as of December 31, 2017 regarding each entity known to us to be the beneficial owner of more than 5% of NuStar Energy’s outstanding common units, and is based solely upon reports filed by such entities with the SEC.
|
| | | | | | |
| Name and Address of Beneficial Owner | | Number of Common Units Beneficially Owned | | Percentage of Common Units Beneficially Owned(1) |
NuStar GP Holdings (2) | | 10,214,626 |
| | 11.0 | % |
OppenheimerFunds, Inc. (3) | | 6,732,640 |
| | 7.2 | % |
ALPS Advisors, Inc. (4) | | 6,571,734 |
| | 7.1 | % |
| |
(1) | As of December 31, 2017, there were 93,176,683 NuStar Energy common units issued and outstanding. |
| |
(2) | As of December 31, 2017, NuStar GP Holdings owns these NuStar Energy common units through its wholly owned subsidiaries, NuStar GP, LLC and Riverwalk Holdings, LLC. NuStar GP Holdings controls voting and investment power over the common units through these wholly owned subsidiaries. NuStar GP Holdings’ business address is 19003 IH-10 West, San Antonio, Texas 78257. |
| |
(3) | As reported on a Schedule 13G/A filed on February 6, 2018, OppenheimerFunds, Inc. (OFI) is an investment adviser that may be deemed to beneficially own, and has shared voting and dispositive power with respect to, 6,732,640 common units. OFI’s business address is 225 Liberty Street, New York, New York 10281. |
| |
(4) | As reported on a Schedule 13G/A filed on February 6, 2018, ALPS Advisors, Inc. (AAI) is an investment adviser that may be deemed to beneficially own, and has shared voting and dispositive power with respect to, 6,571,734 common units. The 6,571,734 common units that AAI may be deemed to beneficially own include 6,549,442 common units that Alerian MLP ETF (Alerian), an investment company, may be deemed to beneficially own. Alerian has shared voting and dispositive power with respect to the 6,549,442 common units. AAI disclaims beneficial ownership of the common units pursuant to Rule 13d-4 of the Securities Exchange Act of 1934. The business address of AAI and Alerian is 1290 Broadway, Suite 1100, Denver, Colorado 80203. |
EQUITY COMPENSATION PLAN INFORMATION
The following table sets forth information as of December 31, 2017 about the equity compensation plan under which securities of NuStar Energy are issuable, which is described in further detail in Note 23 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”
|
| | | | | | | | | |
| Plan categories | | Number of securities to be issued upon exercise of outstanding unit options, warrants and rights (#) | | Weighted-average exercise price of outstanding unit options, warrants and rights ($) (1) | | Number of securities remaining for future issuance under equity compensation plans (#) |
Equity Compensation Plans approved by security holders (2) | | 902,911 |
| | — |
| | 679,045 |
|
| Equity Compensation Plans not approved by security holders | | — |
| | — |
| | — |
|
| |
(1) | No value is included in this column because there were no unit options outstanding as of December 31, 2017 and because restricted units and performance units do not have an exercise price. |
| |
(2) | The information in this row relates to the 2000 LTIP. See the “Compensation Discussion and Analysis” section of Item 11 above for further details regarding the 2000 LTIP. |
| |
ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE |
TRANSACTIONS WITH MANAGEMENT AND OTHERSRELATED UNITHOLDER MATTERS
In January 2007, our Board adopted a written related person transaction policy that codifies our prior practice. For purposes of the policy, a related person transaction is one that is not available to all employees generally or involves $10,000 or more when aggregated with similar transactions. The policy requires that any related person transaction between NuStar Energy or NuStar GP, LLC and: (1) any vice president, Section 16 officer, director or any other person designated for these purposes as an officer by the Board; (2) any unitholder owning greater than 5% of NuStar Energy, its controlled affiliates or NuStar GP Holdings; (3) any immediate family member of any officer or director; or (4) any entity owned or controlled by any of (1), (2) or (3) (or in which any of (1), (2) or (3) owns a 5% or greater ownership interest or controls such entity) must be approved by the disinterested members of the Board. In addition, the policy requires that the officers and directors have an affirmative obligation to inform and provide updates to our Corporate Secretary regarding his or her immediate family members, as well as any entities in which he or she controls or owns 5% or more.
Please see “Potential Payments upon Termination or Change of Control” in Item 11 for a discussion of our change of control severance agreements with the NEOs.
On December 10, 2007, NuStar Logistics, L.P., our wholly owned subsidiary, entered into a non-exclusive Aircraft Time Sharing Agreement (the Time Share Agreement) with William E. Greehey, Chairman of our Board. The Time Share Agreement provides that NuStar Logistics, L.P. will sublease the aircraft to Mr. Greehey on an “as needed and as available” basis, and will provide a fully qualified flight crew for all of Mr. Greehey’s flights. Mr. Greehey will pay NuStar Logistics, L.P. an amount equal to the maximum amount of expense reimbursement permitted in accordance with Section 91.501(d) of the Aeronautics Regulations of the Federal Aviation Administration and the Department of Transportation, which expenses include and are limited to: fuel oil, lubricants and other additives; travel expenses of the crew, including food, lodging and ground transportation; hangar and tie down costs away from the aircraft’s base of operation; insurance obtained for the specific flight; landing fees, airport taxes and similar assessments; customs, foreign permit and similar fees directly related to the flight; in-flight food and beverages; passenger ground transportation; flight planning and weather contract services; and an additional charge equal to 100% of the costs of the fuel oil, lubricants and other additives. The Time Share Agreement had an initial term of two years, and automatically renews for one-year terms until terminated by either party. The Time Share Agreement was approved by the disinterested members of the Board on December 5, 2007. The Time Share Agreement was amended as of September 4, 2009 to reflect the addition of another aircraft and as of August 18, 2017 to reflect a change in the aircraft owner trustee.
On April 24, 2008, the independent directors of NuStar GP, LLC approved the adoption of a Services Agreement, effective January 1, 2008, between NuStar GP, LLC and NuStar Energy (the Services Agreement). Pursuant to the Services Agreement, NuStar GP, LLC historically furnished all services necessary for the conduct of the business of NuStar Energy, and NuStar Energy reimbursed NuStar GP, LLC for all payroll and related benefit costs, including pension and unit-based compensation costs, other than the expenses allocated to NuStar GP Holdings. The expenses allocated to NuStar GP Holdings under the Services Agreement equaled to $1.1 million (as adjusted), plus 1.0% of NuStar GP, LLC’s domestic employee bonus and unit compensation expense for the applicable fiscal year, subject to adjustment (1) by an annual amount equal to NuStar GP, LLC’s annual merit increase percentage for the most recently completed contract year and (2) for changed levels of services due to expansion of operations through, among other things, expansion of operations, acquisitions or the construction of new businesses or assets. On March 1, 2016, NuStar GP, LLC transferred and assigned to NuStar Services Co, a wholly owned subsidiary of NuStar Energy, employment of all of NuStar GP, LLC’s employees. Our executive officers continue to serve as officers of NuStar GP Holdings and NuStar GP, LLC, and also serve as officers of NuStar Services Co and other NuStar Energy subsidiaries. In connection with the transfer and assignment, we amended and restated the Services Agreement (the Amended and Restated Services Agreement) such that, beginning March 1, 2016, NuStar GP Holdings and NuStar Energy receive all management and administrative services from NuStar Services Co. NuStar Energy reimburses NuStar Services Co for all services provided to NuStar Energy, including payroll and benefit costs, as well as NuStar Energy unit-based compensation costs. NuStar GP Holdings pays NuStar Services Co an administrative services fee of $1.0 million per year, subject to adjustment (1) by an annual amount equal to NuStar Services Co’s annual merit increase percentage for the most recently completed fiscal year and (2) for changed levels of services due to expansion of operations through acquisitions, construction of new businesses or assets or otherwise. For 2017 the administrative services fee was approximately $900,000. Beginning March 1, 2016, NuStar GP Holdings no longer pays 1.0% of our domestic bonus and unit compensation expenses. Instead, NuStar GP Holdings retains the expense associated with any NuStar GP Holdings common unit awards or other compensation that it provides to its officers.
John D. Greehey, an employee, is the son of Mr. Greehey. As such, he is deemed to be a “related person” under Item 404(a) of the SEC’s Regulation S-K. Mr. J. Greehey is a Vice President of certain subsidiaries of NuStar Energy. In 2017, Mr. J. Greehey did not attend any Board or Committee meetings. The aggregate value of compensation paid to Mr. J. Greehey in 2017 was less than $500,000. There were no material differences between the compensation paid to Mr. J. Greehey and the compensation paid to any other employees who hold analogous positions.
RIGHTS OF NUSTAR GP HOLDINGS
Due to its ownership of NuStar GP, LLC and Riverwalk Holdings, LLC, as of December 31, 2017, NuStar GP Holdings indirectly owned:
the general partner interest in NuStar Energy, through its indirect 100% ownership interest in Riverwalk Logistics, L.P.;
100% of the incentive distribution rights issued by us, which entitle NuStar GP Holdings to receive increasing percentages of the cash we distribute; and
10,214,626 NuStar Energy common units.
Certain of our officers also are officers of NuStar GP Holdings. Our Chairman, Mr. Greehey, also is the Chairman of Board and, as of December 31, 2017, beneficially owned approximately 21% of the common units of NuStar GP Holdings. NuStar GP Holdings appoints NuStar GP, LLC’s directors. NuStar GP, LLC’s board is responsible for overseeing NuStar GP, LLC’s role as the owner of the general partner of NuStar Energy. NuStar GP Holdings must also approve matters that have or would reasonably be expected to have a material effect on NuStar GP Holdings’ interests as one of our major unitholders.
NuStar Energy’s partnership agreement requires that NuStar GP, LLC maintain a Conflicts Committee, composed entirely of independent directors, to review and resolve certain potential conflicts of interest between Riverwalk Logistics, L.P. and its affiliates, on the one hand, and NuStar Energy, on the other.
MERGER AGREEMENT
On February 7, 2018, NuStar Energy, Riverwalk Logistics, L.P., NuStar GP, LLC, Merger Sub, Riverwalk Holdings, LLC and NuStar GP Holdings entered into the Merger Agreement pursuant to which Merger Sub will merge with and into NuStar GP Holdings with NuStar GP Holdings being the surviving entity, such that NuStar Energy will be the sole member of NuStar GP Holdings following the Merger. Pursuant to the Merger Agreement and at the effective time of the Merger, NuStar Energy’s partnership agreement will be amended and restated to, among other things, (1) cancel the incentive distribution rights held by the general partner, (2) convert the 2% general partner interest in NuStar Energy held by the general partner into a non-economic management interest and (3) provide the holders of NuStar Energy common units with voting rights in the election of the members of the Board of NuStar GP, LLC at an annual meeting, beginning in 2019.
At the effective time of the Merger, each outstanding NuStar GP Holdings common unit, other than those held by NuStar GP Holdings or its subsidiaries, will be converted into the right to receive 0.55 of a NuStar Energy common unit. All NuStar GP Holdings common units, when converted, will cease to be outstanding and will automatically be cancelled and no longer exist. No fractional NuStar Energy common units will be issued in the Merger; instead, each holder of NuStar GP Holdings’ common units otherwise entitled to receive a fractional NuStar Energy common unit will receive cash in lieu thereof. Furthermore, the 10,214,626 NuStar Energy common units currently owned by NuStar GP Holdings will be cancelled and will cease to exist.
At the effective time of the Merger, each outstanding award of NuStar GP Holdings restricted units will be converted, on the same terms and conditions as were applicable to the awards immediately prior to the Merger, into an award of NuStar Energy restricted units. The number of NuStar Energy restricted units subject to the converted awards will be determined as provided in the Merger Agreement. Each of our executive officers and directors has agreed and acknowledged that the Merger will not be deemed to trigger a “change of control” as defined under any NuStar Energy or NuStar GP Holdings plan or award, and has waived any rights to vesting, payment or other benefit thereunder that would arise upon a “change of control,” to which he or she might otherwise have been entitled.
The Merger Agreement contains customary representations and warranties and covenants by each of the parties. Completion of the Merger is conditioned upon, among other things: (1) approval of the Merger Agreement by the affirmative vote of holders of a Unit Majority, as defined in the Second Amended and Restated Limited Liability Company Agreement of NuStar GP Holdings, as amended; (2) the effectiveness of a registration statement on Form S-4 with respect to the issuance by NuStar Energy of its common units in connection with the Merger; (3) the absence of certain legal injunctions or impediments prohibiting the transactions; (4) the receipt of certain tax opinions from a nationally recognized tax counsel; and (5) the approval for the listing on the New York Stock Exchange of NuStar Energy’s common units to be issued in the Merger.
NuStar Energy entered into a Support Agreement, dated as of February 7, 2018 (the Support Agreement), with Merger Sub, WLG Holdings, LLC, a Texas limited liability company controlled by Mr. Greehey (WLG Holdings), Mr. Greehey (together, WLG Holdings and Mr. Greehey are referred to as the Greehey Unitholders), and, for limited purposes, NuStar GP Holdings, pursuant to which the Greehey Unitholders have agreed to vote in favor of the approval and adoption of the Merger Agreement, the approval of the Merger and any other action required in furtherance thereof submitted for the vote or written consent of NuStar GP Holdings unitholders. The Support Agreement will terminate (1) at the effective time of the Merger, (2) upon the termination of the Merger Agreement as provided therein, or (3) at such time as NuStar Energy and the Greehey Unitholders agree in writing to terminate the Support Agreement.
After the Merger, the NuStar GP, LLC Board is expected to consist of nine members, initially composed of the six members of the NuStar GP, LLC Board and the three independent directors of the board of directors of NuStar GP Holdings, LLC.
DIRECTOR INDEPENDENCE
Our business is managed under the direction of the Board of NuStar GP, LLC, the general partner of Riverwalk Logistics, L.P., the general partner of NuStar Energy. The Board conducts its business through meetings of the Board and its committees. The Board has standing Audit, Compensation and Nominating/Governance & Conflicts Committees. Each committee has a written charter. During 2017, the Board held ten meetings, the Audit Committee held eight meetings, the Compensation Committee held four meetings and the Nominating/Governance & Conflicts Committee held one meeting. No member of the Board attended less than 75% of the meetings of the Board and committees during the period in which he was a member during 2017.
INDEPENDENT DIRECTORS
The Board has one member of management, Mr. Barron, President and Chief Executive Officer, and five non-management directors. As a limited partnership, NuStar Energy is not required to have a majority of independent directors. However, the Board has determined that four of five of its current non-management directors meet the independence requirements of the NYSE listing standards as set forth in the NYSE Listed Company Manual. The independent directors are: Mr. Bates, Mr. Hill, Mr. Munch and Mr. Rosier.
Mr. Greehey, Chairman of the Board, also serves as the Chairman of the NuStar GP Holdings board of directors and, as of December 31, 2017, beneficially owned approximately 21% of the common units of NuStar GP Holdings. Mr. Greehey is not an independent director under the NYSE’s listing standards.
Mr. Barron has been President and Chief Executive Officer of NuStar GP, LLC since January 2014. Mr. Barron also serves as President and Chief Executive Officer of NuStar GP Holdings. As a member of management, Mr. Barron is not an independent director under the NYSE’s listing standards.
The Audit, Compensation and Nominating/Governance & Conflicts Committees of the Board are each composed entirely of directors who meet the independence requirements of the NYSE listing standards. Each member of the Audit Committee also meets the additional independence standards for Audit Committee members set forth in the regulations of the SEC. For further information about the committees, see also Item 10 and Item 11 above.
INDEPENDENCE DETERMINATIONS
Under the NYSE’s listing standards, no director qualifies as independent unless the Board affirmatively determines that the director has no material relationship with NuStar Energy. Based upon information requested annually from and provided by each director concerning their background, employment and affiliations, including commercial, industrial, banking, consulting, legal, accounting, charitable and familial relationships, the Board has determined that, other than being a director of NuStar GP, LLC, a unitholder of NuStar Energy and/or a unitholder of NuStar GP Holdings, each of the independent directors named above has either no relationship with NuStar Energy, either directly or as a partner, equityholder or officer of an organization that has a relationship with NuStar Energy, or has only immaterial relationships with NuStar Energy, and is therefore independent under the NYSE’s listing standards.
As provided for under the NYSE listing standards, the Board has adopted categorical standards or guidelines to assist the Board in making its independence determinations with respect to each director. Under the NYSE listing standards, immaterial relationships that fall within the guidelines are notInformation required to be disclosed inunder this Annual Report on Form 10-K.Item 12 is incorporated by reference to the following sections of our Proxy Statement: “Security Ownership.”
A relationship falls within the guidelines adopted by the Board if it:
is not a relationship that would preclude a determination of independence under Section 303A.02(b) of the NYSE Listed Company Manual;ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
consists of charitable contributions by NuStar Energy to an organization where a director is an executive officer and does not exceed the greater of $1 million or 2% of the organization’s gross revenue in any of the last three years;
consists of charitable contributions by NuStar Energy to any organization with which a director, or any member of a director’s immediate family, is affiliated as an officer, director or trustee pursuant to a matching gift program of NuStar Energy and made on terms applicable to employees and directors generally, or is in amounts that do not exceed $250,000 per year; and
is notInformation required to be disclosed inunder this Annual Report on Form 10-K.Item 13 is incorporated by reference to the following sections of our Proxy Statement: “Corporate Governance-Director Independence;” “Corporate Governance-Board Structure and Governance;” and “Certain Relationships and Related Party Transactions.”
Our Corporate Governance Guidelines contain the director qualification standards, including the guidelines listed above, and are available on NuStar Energy’s website at www.nustarenergy.com (in the “Investors” section) or are available in print upon request to NuStar GP, LLC’s Corporate Secretary at the address indicated on the cover page of this Annual Report on Form 10-K or corporatesecretary@nustarenergy.com.
PRESIDING DIRECTOR/MEETINGS OF NON-MANAGEMENT DIRECTORS
The Board has designated Mr. Hill to serve as the Presiding Director for meetings of the non-management Board members outside the presence of management.
COMMUNICATIONS WITH THE BOARD, NON-MANAGEMENT DIRECTORS OR PRESIDING DIRECTOR
Unitholders and other interested parties may communicate with the Board, the non-management directors or the Presiding Director by sending a written communication in an envelope addressed to “Board of Directors,” “Non-Management Directors,” or “Presiding Director” in care of NuStar GP, LLC’s Corporate Secretary at the address indicated on the cover page of this Annual Report on Form 10-K or corporatesecretary@nustarenergy.com.
AVAILABILITY OF GOVERNANCE DOCUMENTS
NuStar Energy has posted its Corporate Governance Guidelines, Code of Business Conduct and Ethics, Code of Ethics for Senior Financial Officers and the Charters of the Audit Committee, Compensation Committee and Nominating/Governance & Conflicts Committee on NuStar Energy’s website at www.nustarenergy.com (in the “Investors” section). NuStar Energy’s governance documents are available in print to any unitholder of record who makes a written request to NuStar Energy. Requests must be directed to NuStar GP, LLC’s Corporate Secretary at the address indicated on the cover page of this Annual Report on Form 10-K or corporatesecretary@nustarenergy.com.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Our independent registered public accounting firm is KPMG FEESLLP, San Antonio, Texas, Auditor Firm ID: 185.
The aggregate fees for professional services rendered to us by KPMG for the years ended December 31, 2017 and 2016 were:
|
| | | | | | | | |
| Category of Service | | 2017 | | 2016 |
Audit fees (1) | | $ | 3,227,500 |
| | $ | 2,633,321 |
|
Audit-related fees (2) | | 3,000 |
| | — |
|
| Tax fees | | — |
| | — |
|
| All other fees | | — |
| | — |
|
| Total | | $ | 3,230,500 |
| | $ | 2,633,321 |
|
| |
(1) | Audit fees for 2017 and 2016 were for professional services rendered by KPMG in connection with the audits of our annual financial statements for the years ended December 31, 2017 and 2016, respectively, included in our Annual Reports on Form 10-K, reviews of our interim financial statements included in our Quarterly Reports on Form 10-Q, the audit of the effectiveness of our internal control over financial reporting as of December 31, 2017 and 2016, respectively, and related services that are normally provided by the principal auditor (e.g., comfort letters and assistance with review of documents filed with the SEC).
|
| |
(2) | Audit-related fees for 2017 were for assurance and related services rendered by KPMG that are reasonably related to the performance of the audit or review of our financial statements and are not reported under “Audit fees.” |
AUDIT COMMITTEE PRE-APPROVAL POLICY
The Audit Committee has adopted a pre-approval policy to address the pre-approval of all servicesInformation required to be rendered to usdisclosed under this Item 14 is incorporated by our independent auditor and ensure that the provision of any non-audit services does not impair the auditor’s independence. None of the services (described above) for 2017 or 2016 provided by KPMG were approved by the Audit Committee pursuantreference to the pre-approval waiver contained in paragraph (c)(7)(i)(C)following sections of Rule 2-01our Proxy Statement: “KPMG Fees;” and “Audit Committee Pre-Approval Policy.”
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
|
| | | | | | | | | | | | | |
| (a) | | (1(1) | ) | | Financial Statements. The following consolidated financial statements of NuStar Energy L.P. and its subsidiaries are included in Part II, Item 8 of this Form 10-K: |
| | | | |
| | (2(2) | ) | | Financial Statement Schedules and Other Financial Information. No financial statement schedules are submitted because either they are inapplicable or because the required information is included in the consolidated financial statements or notes thereto. |
| | (3(3) | ) | | Exhibits. |
| | | | The following are filed or furnished, as applicable, as part of this Form 10-K: |
|
| | | | | | | | | | | | | |
Exhibit
Number
| | Description | | Incorporated by Reference
to the Following Document
|
| | | | |
2.013.01 |
| |
| | NuStar Energy L.P.’s Current Report on Form 8-K filed April 11, 2017 (File No. 001-16417), Exhibit 2.1 |
| | | | |
2.02 |
| | Agreement and Plan of Merger, dated as of February 7, 2018, by and among NuStar Energy L.P., Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, Riverwalk Holdings, LLC and NuStar GP Holdings, LLC | | NuStar Energy L.P.’s Current Report on Form 8-K filed February 8, 2018 (File No. 001-16417), Exhibit 2.1 |
| | | | |
3.01 |
| | | | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.3 |
| | | | |
| 3.02 |
| | | | NuStar Energy L.P.’s Current Report on Form 8-K filed March 27, 2007 (File No. 001-16417), Exhibit 3.01 |
| | | | |
| 3.03 |
| | | | NuStar Energy L.P.’s Current Report on Form 8-K filed November 30, 2017July 20, 2018 (File No. 001-16417), Exhibit 3.1 |
| | | | |
| 3.04 |
| | | | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.8 |
| | | | |
| 3.05 |
| | | | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2007 (File No. 001-16417), Exhibit 3.03 |
| | | | |
| 3.06 |
| | | | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2014 (File No. 001-16417), Exhibit 3.09 |
| | | | |
| 3.07 |
| | | | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.9 |
| | | | |
| 3.08 |
| | | | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2001 (File No. 001-16417), Exhibit 4.1 |
| | | | |
|
| | | | | |
Exhibit
Number
3.09 | | Description | | Incorporated by Reference
to the Following Document
|
| | | | |
3.09 |
| | | | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.10 |
| | | | |
3.10 |
| | | |
| | | | | | | | | | | | | | |
Exhibit
Number | | Description | | Incorporated by Reference
to the Following Document |
| | | | |
| 3.10 | | | | | NuStar Energy L.P.’s Registration Statement on Form S-1 filed August 14, 2000 (File No. 333-43668), Exhibit 3.7 |
| | | | |
| 3.11 |
| | | | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.16 |
| | | | |
| 3.12 |
| | | | NuStar Energy L.P.’s Registration Statement on Form S-1 filed August 14, 2000 (File No. 333-43668), Exhibit 3.9 |
| | | | |
| 3.13 |
| | | | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.14 |
| | | | |
| 3.14 |
| | | | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2007 (File No. 001-16417), Exhibit 3.02 |
| | | | |
| 3.15 |
| | | | NuStar Energy L.P.’s Amendment No. 5 to Registration Statement on Form S-1 filed March 29, 2001 (File No. 333-43668), Exhibit 3.10 |
| | | | |
3.16 |
| | | | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.15 |
| | | | |
3.17 |
| | | | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2014 (File No. 001-16417), Exhibit 3.20 |
| | | | |
3.18 |
| | | | NuStar Energy L.P.’s QuarterlyCurrent Report on Form 10-Q for quarter ended June 30, 20168-K filed July 20, 2018 (File No. 001-16417), Exhibit 3.013.2 |
| | | | |
| 4.01 |
| | | | * |
| | | | |
| 4.02 | | | Indenture, dated as of July 15, 2002, among Valero Logistics Operations, L.P., as Issuer, Valero L.P., as Guarantor, and The Bank of New York, as Trustee, relating to Senior Debt Securities | | NuStar Energy L.P.’s Current Report on Form 8-K filed July 15, 2002 (File No. 001-16417), Exhibit 4.1 |
| | | | |
4.024.03 |
| | Third Supplemental Indenture, dated as of July 1, 2005, to Indenture dated as of July 15, 2002, as amended and supplemented, among Valero Logistics Operations, L.P., Valero L.P., Kaneb Pipe Line Operating Partnership, L.P., and The Bank of New York Trust Company, N.A. | | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.02 |
| | | | |
4.034.04 |
| | Instrument of Resignation, Appointment and Acceptance, dated March 31, 2008, among NuStar Logistics, L.P., NuStar Energy L.P., Kaneb Pipeline Operating Partnership, L.P., The Bank of New York Trust Company N.A., and Wells Fargo Bank, National Association | | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2008 (File No. 001-16417), Exhibit 4.05 |
| | | | |
| | | | |
| | | | |
|
| | | | | |
Exhibit
Number
4.05 | | Description | | Incorporated by Reference
to the Following Document
|
| | | | |
4.04 |
| | Fourth Supplemental Indenture, dated as of April 4, 2008, to Indenture dated as of July 15, 2002, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, and Wells Fargo Bank, National Association, as Successor Trustee | | NuStar Energy L.P.’s Current Report on Form 8-K filed April 4, 2008 (File No. 001-16417), Exhibit 4.2 |
| | | | |
4.05 |
| | Fifth Supplemental Indenture, dated as of August 12, 2010, to Indenture dated as of July 15, 2002, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, and Wells Fargo Bank, National Association, as Successor Trustee | | NuStar Energy L.P.’s Current Report on Form 8-K filed August 16, 2010 (File No. 001-16417), Exhibit 4.3 |
| | | | |
4.06 |
| | Sixth Supplemental Indenture, dated as of February 2, 2012, to Indenture dated as of July 15, 2002, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, and Wells Fargo Bank, National Association, as Successor Trustee | | NuStar Energy L.P.’s Current Report on Form 8-K filed February 7, 2012 (File No. 001-16417), Exhibit 4.3 |
| | | | |
4.07 |
| | Seventh Supplemental Indenture, dated as of August 19, 2013, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, and Wells Fargo Bank, National Association, as Successor Trustee | | NuStar Energy L.P.’s Current Report on Form 8-K filed August 23, 2013 (File No. 001-16417), Exhibit 4.3 |
| | | | |
4.08 |
| | Eighth Supplemental Indenture, dated as of April 28, 2017, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, and Wells Fargo Bank, National Association, as Successor Trustee
| | NuStar Energy L.P.’s Current Report on Form 8-K filed April 28, 2017 (File No. 001-16417), Exhibit 4.4 |
| | | | |
4.094.06 |
| | Ninth Supplemental Indenture, dated as of May 22, 2019, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, and Wells Fargo Bank, National Association, as Successor Trustee | | NuStar Energy L.P.’s Current Report on Form 8-K filed May 22, 2019 (File No. 001-16417), Exhibit 4.3 |
| | | | |
| 4.07 | | Tenth Supplemental Indenture, dated as of September 14, 2020, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, and Wells Fargo Bank, National Association, as Successor Trustee | | NuStar Energy L.P.’s Current Report on Form 8-K filed September 14, 2020 (File No. 001-16417), Exhibit 4.3 |
| | | | |
| | | | |
| | | | | | | | | | | | | | |
Exhibit
Number | | Description | | Incorporated by Reference
to the Following Document |
| | | | |
| | | | |
| 4.08 | | Indenture, dated as of January 22, 2013, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee, relating to Subordinated Debt Securities | | NuStar Energy L.P.’s Current Report on Form 8-K filed January 22, 2013 (File No. 001-16417), Exhibit 4.1 |
| | | | |
4.104.09 |
| | First Supplemental Indenture, dated as of January 22, 2013, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Parent Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, and Wells Fargo Bank, National Association, as Trustee | | NuStar Energy L.P.’s Current Report on Form 8-K filed January 22, 2013 (File No. 001-16417), Exhibit 4.2 |
| | | | |
10.014.10 |
| | | | NuStar Energy L.P.’s Current Report on Form 8-K filed June 29, 2018 (File No. 001-16417), Exhibit 4.2 |
| | | | |
| 10.01 | | | Second Amended and Restated 5-Year Revolving Credit Agreement, dated as of October 29, 2014,January 28, 2022, among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and JPMorgan Chase Bank, N.A.NuStar Pipeline Operating Partnership L.P., as Administrative Agent, SunTrust Bank and Mizuho Bank, Ltd., as Co-Syndication Agents, Wells Fargo Bank, National Association, as Administrative Agent, and PNC Bank, National Association, as Co-Documentation Agents, and J.P. Morgan Securities LLC, SunTrust Robinson Humphrey, Inc., Mizuho Bank, Ltd., Wells Fargo Securities, LLC and PNC Capital Markets LLC, as Joint Bookrunners and Joint Lead Arrangersthe Lenders party thereto | | NuStar Energy L.P.’s Current Report on Form 8-K filed OctoberJanuary 31, 20142022 (File No. 001-16417), Exhibit 10.1 |
| | | | |
| | | | |
| 10.01 |
| | | | | |
Exhibit
Number
10.02 | | Description | | Incorporated by Reference
|
| | | | |
10.02 |
| | First Amendment to AmendedParish of St. James, State of Louisiana and Restated 5-Year Revolving Credit Agreement,NuStar Logistics, L.P. dated as of March 19, 2015, among NuStar Logistics, L.P., NuStar Energy L.P., JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders party theretoJune 1, 2008 | | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2015 (File No. 001-16417), Exhibit 10.01
|
| | | | |
10.03 |
| |
| | NuStar Energy L.P.’s Current Report on Form 8-K filed August 22, 2017June 5, 2020 (File No. 001-16417), Exhibit 10.0110.1 |
| | | | |
10.0410.03 |
| | ThirdFirst Supplement and Amendment to Amended and Restated 5-Year Revolving CreditLease Agreement (Series 2008), dated asJune 1, 2020, among the Parish of November 22, 2017, amongSt. James, State of Louisiana, NuStar Logistics, L.P., NuStar Energy L.P., JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders party theretoNuStar Pipeline Operating Partnership L.P. | | NuStar Energy L.P.’s Current Report on Form 8-K filed November 22, 2017June 5, 2020 (File No. 001-16417), Exhibit 10.0110.2 |
| | | | |
10.0510.04 |
| | | | NuStar Energy L.P.’s Current Report on Form 8-K filed July 21, 2010 (File No. 001-16417), Exhibit 10.01 |
| | | | |
10.0610.05 |
| | Letter of CreditFirst Supplement and Amendment to Lease Agreement (Series 2010), dated June 5, 20121, 2020, among the Parish of St. James, State of Louisiana, NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and Mizuho Corporate Bank, Ltd., as Issuing Bank and Administrative AgentNuStar Pipeline Operating Partnership L.P. | | NuStar Energy L.P.’s Current Report on Form 8-K filed June 12, 20125, 2020 (File No. 001-16417), Exhibit 10.0110.4 |
| | | | |
10.0710.06 |
| | First Amendment to LetterLease Agreement between the Parish of Credit Agreement,St. James, State of Louisiana and NuStar Logistics, L.P. dated as of June 29, 2012, among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and Mizuho Corporate Bank, Ltd., as Issuing Bank and Administrative AgentOctober 1, 2010 | | NuStar Energy L.P.’s Current Report on Form 8-K filed July 6, 2012June 5, 2020 (File No. 001-16417), Exhibit 10.210.5 |
| | | | |
10.0810.07 |
| | SecondFirst Supplement and Amendment to LetterLease Agreement (Series 2010A), dated June 1, 2020, among the Parish of Credit Agreement, dated asSt. James, State of January 17, 2013, amongLouisiana, NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and Mizuho Corporate Bank, Ltd., as Issuing Bank and Administrative AgentNuStar Pipeline Operating Partnership L.P. | | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2014 (File No. 001-16417), Exhibit 10.10
|
| | | | |
10.09 |
| | | | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2014 (File No. 001-16417), Exhibit 10.11
|
| | | | |
10.10 |
| | | | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2014 (File No. 001-16417), Exhibit 10.12
|
| | | | |
10.11 |
| | | | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2014 (File No. 001-16417), Exhibit 10.13
|
| | | | |
10.12 |
| | | | NuStar Energy L.P.’s Current Report on Form 8-K filed November 6, 2014June 5, 2020 (File No. 001-16417), Exhibit 10.1 |
| | | | |
| 10.6 |
| | | | | |
Exhibit
Number
10.08 | | Description | | Incorporated by Reference
to the Following Document
|
| | | | |
10.13 |
| | | | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2015 (File No. 001-16417), Exhibit 10.02
|
| | | | |
10.14 |
| | | | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2016 (File No. 001-16417), Exhibit 10.01
|
| | | | |
10.15 |
| | | | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2017 (File No. 001-16417), Exhibit 10.03
|
| | | | |
10.16 |
| | | | NuStar Energy L.P.’s Current Report on Form 8-K filed December 30, 2010 (File No. 001-16417), Exhibit 10.01 |
| | | | |
10.17 |
| | | |
| | | | | | | | | | | | | | |
Exhibit
Number | | Description | | Incorporated by Reference
to the Following Document |
| | | | |
| | | | |
| 10.09 | | LetterFirst Supplement and Amendment to Lease Agreement (Series 2010B), dated June 1, 2020, among the Parish of Credit Agreement dated asSt. James, State of September 3, 2014 amongLouisiana, NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Issuing Bank and Administrative AgentNuStar Pipeline Operating Partnership L.P. | | NuStar Energy L.P.’s Current Report on Form 8-K filed September 9, 2014June 5, 2020 (File No. 001-16417), Exhibit 10.110.8 |
| | | | |
10.1810.10 |
| | | | NuStar Energy L.P.’s Current Report on Form 8-K filed November 6, 2014 (File No. 001-16417), Exhibit 10.3 |
| | | | |
10.19 |
| | | | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2015 (File No. 001-16417), Exhibit 10.01
|
| | | | |
10.20 |
| | | | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2016 (File No. 001-16417), Exhibit 10.02
|
| | | | |
10.21 |
| | | | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2017 (File No. 001-16417), Exhibit 10.02
|
| | | | |
10.22 |
| | | | NuStar Energy L.P.’s Current Report on Form 8-K filed August 10, 2011 (File No. 001-16417), Exhibit 10.01 |
| | | | |
| | | | |
| | | | |
|
| | | | | |
Exhibit
Number
10.11 | | Description | | Incorporated by Reference
|
| | | | |
10.23 |
| | | | NuStar Energy L.P.’s Current Report on Form 8-K filed June 11, 20135, 2020 (File No. 001-16417), Exhibit 10.0110.10 |
| | | | |
10.2410.12 |
| | | | NuStar Energy L.P.’s Current Report on Form 8-K filed November 6, 2014 (File No. 001-16417), Exhibit 10.2 |
| | | | |
10.25 |
| | Purchase and Sale Agreement, dated as of June 15, 2015, among NuStar Energy Services, Inc., NuStar Logistics, L.P., NuStar Pipeline Operating Partnership L.P. and NuStar Supply & Trading LLC, as Originators, NuStar Energy L.P., as Servicer, and NuStar Finance LLC, as Buyer | | NuStar Energy L.P.'s Current Report on Form 8-K filed June 19, 2015 (File No. 001-16417), Exhibit 10.1
|
| | | | |
10.2610.13 |
| | Receivables Financing Agreement, dated as of June 15, 2015, by and among NuStar Finance LLC, as Borrower, the persons from time to time party thereto as Lenders and Group Agents, PNC Bank, National Association, as Administrative Agent, and NuStar Energy L.P., as initial Servicer | | NuStar Energy L.P.'s Current Report on Form 8-K filed June 19, 2015 (File No. 001-16417), Exhibit 10.2 |
| | | | |
10.2710.14 |
| | | | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2015 (File No. 001-16417), Exhibit 10.26 |
| | | | |
10.2810.15 |
| | | | NuStar Energy L.P.’s Current Report on Form 8-K filed September 20, 2017 (File No. 001-16417), Exhibit 10.01 |
| | | | |
10.2910.16 |
| | Second Amendment to Receivables Financing Agreement, dated as of September 20, 2017, by and among NuStar Finance, LLC, as Borrower, NuStar Energy L.P., as initial Servicer, Mizuho Bank, Ltd. and PNC Bank, National Association | | NuStar Energy L.P.’s Current Report on Form 8-K filed September 20, 2017 (File No. 001-16417), Exhibit 10.02 |
| | | | |
+10.3010.17 |
| | Third Amendment to Receivables Financing Agreement, dated as of March 28, 2018, by and among NuStar Finance, LLC, as Borrower, NuStar Energy L.P., as initial Servicer, Mizuho Bank, Ltd. and PNC Bank, National Association | | NuStar Energy L.P.’s Current Report on Form 8-K filed March 28, 2018 (File No. 001-16417), Exhibit 10.01 |
| | | | |
| 10.18 | | Fourth Amendment to Receivables Financing Agreement, dated as of April 29, 2019, by and among NuStar Finance, LLC, as Borrower, NuStar Energy L.P., as initial Servicer, Mizuho Bank, Ltd. and PNC Bank, National Association | | NuStar Energy L.P.’s Current Report on Form 8-K filed April 29, 2019 (File No. 001-16417), Exhibit 10.1 |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | | | | | | | | | | | |
Exhibit
Number | | Description | | Incorporated by Reference
to the Following Document |
| | | | |
| 10.19 | | | | NuStar Energy L.P.’s Current Report on Form 8-K filed September 3, 2020 (File No. 001-16417), Exhibit 10.01 |
| | | | |
| 10.20 | | | | NuStar Energy L.P.’s Current Report on Form 8-K filed January 31, 2022 (File No. 001-16417), Exhibit 10.02 |
| | | | |
| +10.21 | | | | * Originally filed as Appendix A to NuStar Energy L.P.’s Proxy StatementAnnual Report on Schedule 14A filedForm 10-K for year ended December 17, 201531, 2017 (File No. 001-16417) and refiled herewith, Exhibit 10.30 |
| | | | |
+10.3110.22 |
| | | | * |
| | | | |
+10.32 |
| | | | NuStar Energy L.P.’s Current Report on Form 8-K filed January 31, 2012 (File No. 001-16417), Exhibit 10.2 |
| | | | |
+10.33 |
| | | | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 20132017 (File No. 001-16417), Exhibit 10.15 |
| | | | |
| | | | |
| 10.31 |
| | | | | |
Exhibit
Number
+10.23 | | Description | | Incorporated by Reference
to the Following Document
|
| | | | |
+10.34 |
| | | | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2016 (File No. 001-16417), Exhibit 10.28 |
| | | | |
+10.3510.24 |
| | | | NuStar GP Holdings, LLC’s Quarterly Report on Form 10-Q for quarter ended June 30, 2007 (File No. 001-32040), Exhibit 10.04 |
| | | | |
| +10.25 | | | | NuStar GP Holdings, LLC’s Annual Report on Form 10-K for year ended December 31, 2017 (File No. 001-32040), Exhibit 10.46 |
| | | | |
| +10.26 | | | | NuStar Energy L.P.’s Current Report on Form 8-K filed July 20, 2018 (File No. 001-16417), Exhibit 10.1 |
| | | | |
| +10.27 | | | | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2018 (File No. 001-16417), Exhibit 10.06 |
| | | | |
| +10.28 | | | | NuStar Energy L.P.’s Current Report on Form 8-K filed April 23, 2019 (File No. 001-16417), Exhibit 10.2 |
| | | | |
| +10.29 | | | | NuStar Energy L.P.’s Current Report on Form 8-K filed April 23, 2019 (File No. 001-16417), Exhibit 10.3 |
| | | | |
| +10.30 | | | | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2020 (File No. 001-16417), Exhibit 10.11 |
| | | | |
| +10.31 | | | | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2020 (File No. 001-16417), Exhibit 10.43 |
| | | | |
| +10.32 | | | | NuStar Energy L.P.’s Current Report on Form 8-K filed April 30, 2021 (File No. 001-16417), Exhibit 10.1 |
| | | | |
| +10.33 | | | | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2021 (File No. 001-16417), Exhibit 10.02 |
| | | | |
| +10.34 | | | | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2021 (File No. 001-16417), Exhibit 10.35 |
| | | | | | | | | | | | | | |
Exhibit
Number | | Description | | Incorporated by Reference
to the Following Document |
| | | | |
| +10.35 | | | | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2021 (File No. 001-16417), Exhibit 10.36 |
| | | | |
| +10.36 | | | | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 20172022 (File No. 001-16417), Exhibit 10.0110.03 |
| | | | |
+10.3610.37 |
| | | | * |
| | | | |
| +10.38 | | | | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2016 (File No. 001-16417), Exhibit 10.31* |
| | | | |
+10.3710.39 |
| | | | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2006 (File No. 001-16417), Exhibit 10.18 |
| | | | |
+10.3810.40 |
| | | | NuStar Energy L.P.’s Current Report on Form 8-K filed August 4, 2016 (File No. 001-16417), Exhibit 10.1 |
| | | | |
+10.3910.41 |
| | | | * |
| | | | |
+10.40 |
| | | | * |
| | | | |
+10.41 |
| | | | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2015 (File No. 001-16417), Exhibit 10.45 |
| | | | |
| +10.42 |
| | | | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2018 (File No. 001-16417), Exhibit 10.04 |
| | | | |
| +10.43 | | | | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2008 (File No. 001-16417), Exhibit 10.30 |
| | | | |
+10.4310.44 |
| | | | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2017 (File No. 001-16417), Exhibit 10.02 |
| | | | |
10.44+10.45 |
| | Non-Compete Agreement, dated July 19, 2006, between Valero GP Holdings, LLC, Valero L.P., Riverwalk Logistics, L.P. and Valero GP, LLCAmendment No. 2 to NuStar Excess Thrift Plan, effective October 9, 2018 | | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 20062018 (File No. 001-16417), Exhibit 10.0310.05 |
| | | | |
10.4510.46 |
| | | | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2008 (File No. 001-16417), Exhibit 10.01 |
| | | | |
10.46 |
| | | | NuStar Energy L.P.’s Current Report on Form 8-K filed March 1, 2016 (File No. 001-16417), Exhibit 10.2 |
| | | | |
10.47 |
| | | | NuStar Energy L.P.’s Current Report on Form 8-K filed March 1, 2016 (File No. 001-16417), Exhibit 10.1 |
| | | | |
10.48 |
| | | | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2009 (File No. 001-16417), Exhibit 10.24 |
| | | | |
10.4910.47 |
| | | | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2017 (File No. 001-16417), Exhibit 10.02 |
| | | | |
|
| | | | | |
Exhibit
Number
21.01 | | Description | | Incorporated by Reference
to the Following Document
|
| | | | |
10.50 |
| | Support Agreement, dated as of February 7, 2018, by and among NuStar Energy L.P., Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, Riverwalk Holdings, LLC and NuStar GP Holdings, LLC | | NuStar Energy L.P.’s Current Report on Form 8-K filed February 8, 2018 (File No. 001-16417), Exhibit 10.1 |
| | | | |
12.01 |
| | | | * |
| | | | |
21.01 |
| | | | * |
| | | | |
23.0122.01 |
| | | | * |
| | | | |
| 23.01 | | | | * |
| | | | |
| 24.01 |
| | | | * |
| | | | |
| 31.01 |
| | | | * |
| | | | |
| | | | | | | | | | | | | | |
31.02Exhibit
Number |
| Description | | Incorporated by Reference
to the Following Document |
| | | | |
| | | | |
| 31.02 | | | | * |
| | | | |
| 32.01 |
| | | | ** |
| | | | |
| 32.02 |
| | | | ** |
| | | | |
| 101.INS |
| | Inline XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | | * |
| | | | |
| 101.SCH |
| | Inline XBRL Taxonomy Extension Schema Document | | * |
| | | | |
| 101.CAL |
| | Inline XBRL Taxonomy Extension Calculation Linkbase Document | | * |
| | | | |
| 101.DEF |
| | Inline XBRL Taxonomy Extension Definition Linkbase Document | | * |
| | | | |
| 101.LAB |
| | Inline XBRL Taxonomy Extension Label Linkbase Document | | * |
| | | | |
| 101.PRE |
| | Inline XBRL Taxonomy Extension Presentation Linkbase Document | | * |
| | | | |
| 104 | | | Cover page Interactive Data File - Formatted in Inline XBRL and contained in Exhibit 101 | | * |
| | | | | |
| * | Filed herewith. |
| |
| ** | FiledFurnished herewith. |
| |
**+ | Furnished herewith. |
| |
+ | Identifies management contracts or compensatory plans or arrangements required to be filed as an exhibit hereto pursuant to Item 15(c)15 of Form 10-K. |
An electronic copy of this Form 10-K is available on our website, free of charge, at www.nustarenergy.com
(select the “Investors” link, then the “SEC Filings” link). A paper copy of the Form 10-K also is available without charge to unitholders upon written request at the address below. Copies of exhibits filed as a part of this Form 10-K may be obtained by unitholders of record at a charge of $0.15 per page, minimum $5.00 each request. Direct inquiries to Corporate Secretary, NuStar Energy L.P., 19003 IH-10 West, San Antonio, Texas 78257.78257 or
corporatesecretary@nustarenergy.com.
ITEM 16. FORM 10-K SUMMARY
Not applicable.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| | | | | |
| |
| |
| NUSTAR ENERGY L.P. |
| (Registrant) |
| |
| By: | Riverwalk Logistics, L.P., its general partner |
| By: NuStar GP, LLC, its general partner |
| |
| By: | /s/ Bradley C. Barron |
| Bradley C. Barron |
| Chairman of the Board, President and Chief Executive Officer |
| February 28, 201823, 2023 |
| |
| By: | /s/ Thomas R. Shoaf |
| Thomas R. Shoaf |
| Executive Vice President and Chief Financial Officer |
| February 28, 201823, 2023 |
| |
| By: | /s/ Jorge A. del Alamo |
| Jorge A. del Alamo |
| Senior Vice President and Controller |
| February 28, 201823, 2023 |
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints Bradley C. Barron, Thomas R. Shoaf and Amy L. Perry, or any of them, each with power to act without the other, his or her true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any or all subsequent amendments and supplements to this Annual Report on Form 10-K, and to file the same, or cause to be filed the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto each said attorney-in-fact and agent full power to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he or she might or could do in person, hereby qualifying and confirming all that said attorney-in-fact and agent or his or her substitute or substitutes may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| | | | | | | | |
| Signature | Title | Date |
| | |
| /s/ Bradley C. Barron | Chairman of the Board, President and | February 23, 2023 |
| Bradley C. Barron | Chief Executive Officer
(Principal Executive Officer) | |
| | |
Signature | Title | Date |
| | |
/s/ William E. Greehey | Chairman of the Board | February 28, 2018 |
William E. Greehey | | |
| | |
/s/ Bradley C. Barron | President, Chief Executive | February 28, 2018 |
Bradley C. Barron | Officer and Director
(Principal Executive Officer)
| |
| | |
| /s/ Thomas R. Shoaf | Executive Vice President | February 28, 201823, 2023 |
| Thomas R. Shoaf | and Chief Financial Officer
(Principal Financial Officer)
| |
| | |
| /s/ Jorge A. del Alamo | Senior Vice President and Controller | February 28, 201823, 2023 |
| Jorge A. del Alamo | (Principal Accounting Officer) | |
| | |
| /s/ J. Dan Bates | Director | February 28, 201823, 2023 |
| J. Dan Bates | | |
| | |
| /s/ Jelynne LeBlanc Burley | Director | February 23, 2023 |
| Jelynne LeBlanc Burley | | |
| | |
| /s/ William B. Burnett | Director | February 23, 2023 |
| William B. Burnett | | |
| | |
| /s/ Ed A. Grier | Director | February 23, 2023 |
| Ed A. Grier | | |
| | |
| /s/ Dan J. Hill | Director | February 28, 201823, 2023 |
| Dan J. Hill | | |
| | |
| /s/ Robert J. Munch | Director | February 28, 201823, 2023 |
| Robert J. Munch | | |
| | |
| /s/ W. Grady Rosier | Director | February 28, 201823, 2023 |
| W. Grady Rosier | | |
| | |
| /s/ Martin Salinas, Jr. | Director | February 23, 2023 |
| Martin Salinas, Jr. | | |
| | |
