UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2021
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number 1-16417
NuStar Energy L.P.
(Exact name of registrant as specified in its charter)
|(State or other jurisdiction of incorporation or organization)|| ||(I.R.S. Employer Identification No.)|
19003 IH-10 West
San Antonio, Texas 78257
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code (210) 918-2000
Securities registered pursuant to Section 12(b) of the Act:
|Title of each class||Trading Symbol(s)||Name of each exchange on which registered|
|Common units||NS||New York Stock Exchange|
|Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units||NSprA||New York Stock Exchange|
|Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units||NSprB||New York Stock Exchange|
|Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units||NSprC||New York Stock Exchange|
Securities registered pursuant to 12(g) of the Act: None.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:
|Large accelerated filer|
|Non-accelerated filer||☐||Smaller reporting company||☐|
|Emerging growth company||☐|
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No þ
The aggregate market value of the common units held by non-affiliates was approximately $1.8 billion based on the last sales price quoted as of June 30, 2021, the last business day of the registrant’s most recently completed second quarter.
The number of common units outstanding as of January 31, 2022 was 110,101,839.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Proxy Statement for the registrant’s 2022 annual meeting of unitholders, expected to be filed within 120 days after the end of the fiscal year covered by this Form 10-K, are incorporated by reference into Part III to the extent described therein.
NUSTAR ENERGY L.P.
TABLE OF CONTENTS
Unless otherwise indicated, the terms “NuStar Energy,” “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.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION AND OTHER DISCLAIMERS
In this Form 10-K, we make certain forward-looking statements, such as statements regarding our plans, strategies, objectives, expectations, estimates, predictions, projections, assumptions, intentions, resources and the future impact of the coronavirus, or COVID-19, the responses thereto, economic activity and the actions by oil-producing nations on our business. While these forward-looking statements, and any assumptions upon which they are based, are made in good faith and reflect our current judgment regarding the direction of our business, actual results will almost always vary, sometimes materially, from any estimates, predictions, projections, assumptions or other future performance suggested in this report. These forward-looking statements can generally be identified by the words “anticipates,” “believes,” “expects,” “plans,” “intends,” “estimates,” “forecasts,” “budgets,” “projects,” “will,” “could,” “should,” “may” and similar expressions. These statements reflect our current views with regard to future events and are subject to various risks, uncertainties and assumptions, which may cause actual results to differ materially. Please read Item 1A. “Risk Factors” for a discussion of certain of those risks, uncertainties and assumptions.
If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those described in any forward-looking statement. Other unknown or unpredictable factors could also have material adverse effects on our future results. Readers are cautioned not to place undue reliance on this forward-looking information, which is as of the date of this Form 10-K. We do not intend to update these statements unless we are required by the securities laws to do so, and we undertake no obligation to publicly release the result of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.
This Form 10-K contains trade names, trademarks and service marks of others, which are the property of their respective owners. Solely for convenience, trademarks and trade names referred to in this Form 10-K appear without the ® or ™ symbols.
ITEMS 1., 2. and 7. BUSINESS, PROPERTIES AND MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NuStar Energy L.P. (NuStar Energy) is a Delaware limited partnership. Our principal executive offices are located at 19003 IH-10 West, San Antonio, Texas 78257, and our telephone number is (210) 918-2000. Our business is managed under the direction of the board of directors of NuStar GP, LLC, the general partner of our general partner, Riverwalk Logistics, L.P., both of which are wholly owned subsidiaries of ours. Our limited partner interests consist of the following:
•common units (NYSE: NS);
•8.50% Series A fixed-to-floating rate cumulative redeemable perpetual preferred units (NYSE: NSprA);
•7.625% Series B fixed-to-floating rate cumulative redeemable perpetual preferred units (NYSE: NSprB);
•9.00% Series C fixed-to-floating rate cumulative redeemable perpetual preferred units (NYSE: NSprC); and
•Series D cumulative convertible preferred units.
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. The term “throughput” as used in this document generally refers to barrels of crude oil, refined product or renewable fuels or tons of ammonia, as applicable, that pass through our pipelines, terminals or storage tanks.
We divide our operations into the following three reportable business segments: pipeline, storage and fuels marketing. As of December 31, 2021, our assets included 9,935 miles of pipeline and 64 terminal and storage facilities, which provide approximately 57 million barrels of storage capacity. We conduct our operations through our wholly owned subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics) and NuStar Pipeline Operating Partnership L.P. (NuPOP). We generate revenue primarily from:
•tariffs for transportation through our pipelines;
•fees for the use of our terminal and storage facilities and related ancillary services; and
•sales of petroleum products.
We are focused on:
•maintaining safe, reliable operations, continuing our strong safety and environmental stewardship, and controlling costs;
•improving our existing assets through strategic internal growth projects, including renewable fuel enhancements;
•continuing to self-fund our spending with internally generated cash flows; and
•reducing our leverage metrics to further strengthen our balance sheet.
The following factors affect our results of operations:
•economic factors and price volatility;
•industry factors, such as changes in the prices of petroleum products that affect demand or production, or regulatory changes that could increase costs or impose restrictions on operations;
•factors that affect our customers and the markets they serve, such as utilization rates and maintenance turnaround schedules of our refining company customers and drilling activity by our crude oil production customers;
•company-specific factors, such as facility integrity issues, maintenance requirements and outages that impact the throughput rates of our assets; and
•seasonal factors that affect the demand for products transported by and/or stored in our assets and the demand for products we sell.
Please read Item 1A. “Risk Factors” for additional discussion on how these factors could affect our operations.
The following map depicts our assets at December 31, 2021:
In 2021, we prioritized protecting our employees, maintaining safe, reliable operations, executing our capital projects and exercising fiscal discipline, as we continued to take steps to reduce our leverage metrics and further strengthen our balance sheet. Our recent steps in 2021 include the sale of our Eastern U.S. Terminal Operations, as described below, and the early repayment of our senior notes, which addressed our near-term debt maturity and improved our debt metrics. In 2021, we met our goal of funding all our expenses, distribution requirements and capital expenditures using internally generated cash flows as well as our promise to publish our inaugural Sustainability Report. In January 2022, we also extended the maturity of our $1.0 billion unsecured revolving credit agreement to April 27, 2025. By repaying our senior notes and extending our credit agreement, we now have no debt maturing until 2025.
Point Tupper Terminal Sale Agreement. On February 11, 2022, we entered into an agreement to sell the equity interests in our wholly owned subsidiaries that own our Point Tupper terminal facility to EverWind Fuels for $60.0 million. The terminal facility has a storage capacity of 7.8 million barrels and is included in the storage segment. We expect to complete the sale in the first half of 2022 and will utilize the sales proceeds to improve our debt metrics.
Debt Amendments and Repayments. 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. On November 1, 2021, we repaid our $250.0 million of 4.75% senior notes due February 1, 2022 with proceeds from the Eastern U.S. Terminals Disposition, as defined below. We repaid our $300.0 million of 6.75% senior notes due February 1, 2021 at maturity with borrowings under our revolving credit agreement. Please see Note 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.
Eastern U.S. Terminals Disposition. On October 8, 2021, we completed the sale of 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 in cash (the Eastern U.S. Terminals Disposition) and utilized the proceeds from the sale to reduce debt and improve our debt metrics. The terminals had an aggregate storage capacity of 14.8 million barrels and were included in the storage segment. We recorded a non-cash asset impairment loss of $95.7 million and a non-cash goodwill impairment loss of $34.1 million in the third quarter of 2021, which are reported in “Asset impairment losses” and “Goodwill impairment losses,” respectively, on the consolidated statement of income for the year ended December 31, 2021. Please refer to Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.
Houston Pipeline Impairment. In the third quarter of 2021, we recorded a non-cash 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). Please refer to Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.
COVID-19. The coronavirus, or COVID-19, had a severe negative impact on global economic activity in 2020, which significantly reduced global demand for petroleum products and increased the volatility of crude oil prices, beginning in March 2020. While a number of countries, including the United States, made significant progress during 2021 deploying COVID-19 vaccines, which has improved the economic conditions and outlook in those nations, many more continue to struggle to obtain and/or disseminate vaccinations to their populace, which continues to frustrate widespread global economic recovery. Even in the United States, if a sufficient proportion of people are not vaccinated, or as variants emerge, we may continue to face surges in COVID-19 cases in some regions, which could slow the pace of domestic economic improvement and undermine demand in the markets our assets serve. We continue to closely monitor each of our locations to ensure the safety of our employees as well as the operational functionality of each location.
Ongoing uncertainty surrounding the COVID-19 pandemic, including its duration and lingering impacts to the economy have caused and may continue to cause volatility and could have a significant impact on management’s estimates and assumptions in 2022 and beyond.
TRENDS AND OUTLOOK
As America continues to recover from the impact of COVID-19 and returns to normal activity and growth, we continue to see signs of stabilization and improvement, across the U.S. and in NuStar’s footprint. U.S. refined product demand outlook has improved as COVID-19 vaccinations have continued to allow more people to return to normal day-to-day activities and to begin traveling. However, variants may emerge that could significantly increase COVID-19 case counts, which may further impact the overall demand recovery in 2022.
Refined product demand on NuStar’s pipeline systems rebounded in 2021 to pre-pandemic levels or higher. We expect our refined products pipeline systems to perform at or above 100% of our pre-pandemic levels for 2022. Steady recovery in refined product demand has increased U.S. refiners’ demand for crude oil, which has contributed to increased throughputs on certain of our crude oil pipelines. Rebounding crude demand in the U. S. and abroad, has, in turn, contributed to higher global crude prices, which has in turn improved demand for U.S. shale production, particularly in the Permian Basin. We believe the Permian Basin, and our system in particular, has geological advantages over other shale plays, including lower production costs and higher product quality, that have benefited and will continue to benefit our assets in 2022 as crude demand, price and production continue to recover. Sustained healthy U.S. shale production growth, when combined with improving global demand, drives U.S. export growth over time; however, global demand has yet to rebound to pre-pandemic levels, which impacts crude volumes on our Corpus Christi Crude System, as well as our St. James terminal. In addition, we continue to expect to benefit from the growth of our renewable fuels distribution system on the West Coast. We expect to provide an increasing share of California’s renewable fuels as we complete our planned tank conversion projects.
The COVID-19 pandemic continues to have lingering impacts that, when combined with other factors, can ripple through the U.S. economy, including rising inflation rates and supply chain issues that affected certain industries and geographic areas to varying degrees during 2021 and, may continue or worsen in 2022. For 2022 and in response to rising inflation, we expect interest rates to increase, which will increase the interest expense related to our variable rate debt; however, we also expect many of our pipelines to benefit from tariff rate increases. We plan to continue to manage our operations with fiscal discipline in this turbulent environment and remain committed to improving our debt metrics. We expect to continue to fund all of our expenses, distribution requirements and capital expenditures for the full-year 2022 using internally generated cash flows.
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 several factors, many of which are outside our control. These factors include, but are not limited to, uncertainty surrounding the COVID-19 pandemic, including its duration and lingering impacts to the economy; uncertainty surrounding future production decisions by the Organization of Petroleum Exporting Countries and other oil-producing nations (OPEC+); 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 petroleum products, renewable fuels and anhydrous ammonia; demand for our transportation and storage services; the availability and costs of personnel, equipment, supplies and services essential to our operations; the ability to obtain timely permitting approvals; and changes in laws and regulations affecting our operations.
CONSOLIDATED RESULTS OF OPERATIONS
The following discussion of our results of operations should be read in conjunction with Item 8. “Financial Statements and Supplementary Data” included in this report, which also contains additional detailed financial information about our segments in Note 24 of the Notes to Consolidated Financial Statements. A comparative discussion of our 2020 to 2019 results of operations 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 Annual Report on Form 10-K for the year ended December 31, 2020 filed with the Securities and Exchange Commission (SEC) on February 25, 2021.
The following table presents our consolidated financial results for the year ended December 31, 2021, compared to the year ended December 31, 2020:
| ||Year Ended December 31,|| |
|(Thousands of Dollars, Except Per Unit Data)|
|Statement of Income Data:|
|Service revenues||$||1,157,410 ||$||1,205,494 ||$||(48,084)|
|Product sales||461,090 ||276,070 ||185,020 |
|Total revenues||1,618,500 ||1,481,564 ||136,936 |
|Costs and expenses:|
|Costs associated with service revenues||654,666 ||680,055 ||(25,389)|
|Cost associated with product sales||417,413 ||256,066 ||161,347 |
|Asset impairment losses||154,908 ||— ||154,908 |
|Goodwill impairment losses||34,060 ||225,000 ||(190,940)|
|General and administrative expenses||113,207 ||102,716 ||10,491 |
|Other depreciation and amortization expense||7,792 ||8,625 ||(833)|
|Total costs and expenses||1,382,046 ||1,272,462 ||109,584 |
|Operating income||236,454 ||209,102 ||27,352 |
|Interest expense, net||(213,985)||(229,054)||15,069 |
|Loss on extinguishment of debt||— ||(141,746)||141,746 |
|Other income (expense), net||19,644 ||(34,622)||54,266 |
|Income (loss) before income tax expense||42,113 ||(196,320)||238,433 |
|Income tax expense||3,888 ||2,663 ||1,225 |
|Net income (loss)||$||38,225 ||$||(198,983)||$||237,208 |
|Basic and diluted net loss per common unit:||$||(0.99)||$||(3.15)||$||2.16 |
We recorded net income of $38.2 million for the year ended December 31, 2021, which includes non-cash asset and goodwill impairment losses related to our Eastern U.S. Terminal Operations of $95.7 million and $34.1 million, respectively, and a non-cash asset impairment loss of $59.2 million on our Houston Pipeline, as well as a gain of $14.9 million for insurance recoveries related to the 2019 fire at our Selby terminal.
For the year ended December 31, 2020, the net loss of $199.0 million is mainly due to a non-cash goodwill impairment charge of $225.0 million in the first quarter of 2020 related to our crude oil pipelines reporting unit, a loss on extinguishment of debt of $141.7 million, primarily resulting from the early repayment of $500.0 million of borrowings outstanding under our $750.0 million unsecured term loan credit agreement in the third quarter of 2020, and a loss of $34.7 million on the sale of our Texas City terminals in December 2020 (the Texas City Sale).
Operating income increased $27.4 million for the year ended December 31, 2021, compared to the year ended December 31, 2020, primarily due to higher operating income from our pipeline segment due to a rebound in demand across most of our pipelines in 2021. Partially offsetting the increase were the following: (i) the impacts of a winter storm in the first quarter of 2021; (ii) the continuing effects of the COVID-19 global pandemic; and (iii) lower operating income from our storage segment in 2021 due to the Eastern U.S. Terminals Disposition and the Texas City Sale and lower demand at certain terminal facilities.
General and administrative expenses increased $10.5 million for the year ended December 31, 2021, compared to the year ended December 31, 2020, mainly due to higher compensation costs.
Interest expense, net decreased $15.1 million for the year ended December 31, 2021, compared to the year ended December 31, 2020, mainly due to lower overall debt balances following the repayment of outstanding debt with the proceeds from our October 2021 and December 2020 asset sales described above. In addition, interest expense was lower in 2021 due to the repayment of the $750.0 million unsecured term loan credit agreement in September 2020 and senior note repayments in 2021, which more than offset the interest expense from the September 2020 issuance of $1.2 billion of senior notes.
We recorded other income, net of $19.6 million for the year ended December 31, 2021, compared to other expense, net of $34.6 million for the year ended December 31, 2020, mainly due to a gain of $14.9 million for insurance recoveries in 2021 related to the 2019 Selby terminal fire and a non-cash loss of $34.7 million related to the Texas City Sale in 2020.
SEGMENTS AND RESULTS OF OPERATIONS
Our pipeline operations consist of the transportation of refined products, crude oil and anhydrous ammonia. As of December 31, 2021, we owned and operated:
•refined product pipelines with an aggregate length of 3,205 miles and crude oil pipelines with an aggregate length of 2,230 miles in Texas, Oklahoma, Kansas, Colorado and New Mexico (collectively, the Central West System);
•a 2,050-mile refined product pipeline originating in southern Kansas and terminating at Jamestown, North Dakota, with a western extension to North Platte, Nebraska and an eastern extension into Iowa (the East Pipeline);
•a 450-mile refined product pipeline originating at Marathon Petroleum Corporation’s (Marathon) Mandan, North Dakota refinery and terminating in Minneapolis, Minnesota (the North Pipeline); and
•a 2,000-mile anhydrous ammonia pipeline originating in the Louisiana delta area and then running north through the Midwestern United States to Missouri before forking east and west to terminate in Indiana and Nebraska (the Ammonia Pipeline).
The following table lists information about our pipeline assets:
As of December 31, 2021
For the year ended December 31,
|Region / Pipeline System||Length||Terminals||Tank Capacity ||2021||2020|
|Central West System:|
|McKee Refined Product System||2,276 ||— ||— ||167,029 ||146,379 |
|Three Rivers System||373 ||— ||— ||106,526 ||94,892 |
|Valley Pipeline System||271 ||— ||55,790 ||52,513 |
|Other||285 ||— ||— ||18,362 ||7,600 |
|Central West Refined Products Pipelines||3,205 ||— ||— ||347,707 ||301,384 |
|Corpus Christi Crude Pipeline System||538 ||8 ||2,157,000 ||423,528 ||439,852 |
|McKee Crude System||598 ||— ||1,039,000 ||146,248 ||126,323 |
|Ardmore System||119 ||— ||824,000 ||81,609 ||81,569 |
|Permian Crude System||975 ||3 ||1,583,000 ||630,183 ||590,013 |
|Central West Crude Oil Pipelines||2,230 ||11 ||5,603,000 ||1,281,568 ||1,237,757 |
|Total Central West System||5,435 ||11 ||5,603,000 ||1,629,275 ||1,539,141 |
|Central East System:|
|East Pipeline||2,050 ||18 ||5,905,000 ||155,610 ||146,397 |
|North Pipeline||450 ||4 ||1,502,000 ||50,365 ||47,128 |
|Ammonia Pipeline||2,000 ||— ||— ||31,507 ||29,933 |
|Total Central East System||4,500 ||22 ||7,407,000 ||237,482 ||223,458 |
|Total||9,935 ||33 ||13,010,000 ||1,866,757 ||1,762,599 |
Description of Pipelines
Central West System. The Central West System covers a total of 5,435 miles, including refined product and crude oil pipelines. The refined product pipelines have an aggregate length of 3,205 miles (Central West Refined Products Pipelines) and transport gasoline, distillates (including diesel and jet fuel), renewable fuels, natural gas liquids and other products produced at the refineries to which they are connected, including Valero Energy Corporation’s (Valero Energy) McKee, Corpus Christi and Three Rivers refineries.
The crude oil pipelines have an aggregate length of 2,230 miles (Central West Crude Oil Pipelines) and transport crude oil and other feedstocks to the refineries to which they are connected, including Valero Energy’s McKee, Three Rivers and Ardmore refineries, or from the Permian Basin and Eagle Ford Shale regions to our North Beach marine export terminal or to third-party refineries in Corpus Christi, Texas. Our Corpus Christi Crude Pipeline System is comprised of pipelines that transport crude oil from the Eagle Ford region to Corpus Christi, Texas, including eight terminals along those pipelines, with aggregate storage capacity of 2.2 million barrels. In addition, the Corpus Christi Crude Pipeline System is connected to third-party long-haul pipelines that transport crude oil from the Permian Basin region to Corpus Christi, Texas.
Our Permian Crude System consists of crude oil transportation, pipeline connection and storage assets located in the Midland Basin of West Texas, that aggregate receipts from wellhead connection lines into intra-basin trunk lines for delivery to regional hubs and to connections with third-party mainline takeaway pipelines. The system consists of 975 miles of pipelines and covers approximately 500,000 dedicated acres controlled by producers, with approximately 320 receipt points. The Permian Crude System also includes three terminals in Texas, at Big Spring, Stanton and Colorado City, as well as several truck stations and other operational storage facilities, with an aggregate storage capacity of 1.6 million barrels.
Central East System. The Central East System covers a total of 4,500 miles and consists of the East Pipeline, the North Pipeline and the Ammonia Pipeline.
The East Pipeline covers 2,050 miles and transports refined products and natural gas liquids north via pipelines to our terminals and third-party terminals along the system and to receiving pipeline connections in Kansas. Shippers on the East Pipeline obtain
refined products from refineries in Kansas, Oklahoma and Texas. The East Pipeline includes 18 truck-loading terminals, with storage capacity of 4.5 million barrels and two tank farms with storage capacity of 1.4 million barrels at McPherson and El Dorado, Kansas.
The North Pipeline originates at Marathon’s Mandan, North Dakota refinery and runs from west-to-east for approximately 450 miles to its termination in Minneapolis, Minnesota. The North Pipeline includes four truck-loading terminals with storage capacity of 1.5 million barrels.
The 2,000-mile Ammonia Pipeline originates in the Louisiana delta area, where it connects to three third-party marine terminals and three anhydrous ammonia plants located along the Mississippi River. The line then runs north through Louisiana and Arkansas into Missouri, where, at Hermann, Missouri, it splits into two branches, one of which goes east into Illinois and Indiana, while the other branch continues north into Iowa and then turns west into Nebraska. The Ammonia Pipeline is connected to multiple third-party-owned terminals, which include industrial facility delivery locations. Product is supplied to the pipeline from anhydrous ammonia plants in Louisiana and imported product delivered through the marine terminals. Anhydrous ammonia is primarily used as agricultural fertilizer. It is also used as a feedstock to produce other nitrogen derivative fertilizers and explosives.
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. Fees related to storage facilities included with these pipeline systems predominately relate to the volumes transported on the pipelines and are included in the respective pipeline tariff. As a result, these storage facilities are included in this segment instead of the storage segment.
In general, shippers on our crude oil and refined product pipelines deliver petroleum products to our pipelines for transport to/from: (i) refineries that connect to our pipelines, (ii) third-party pipelines or terminals and (iii) our terminals for further delivery to marine vessels or pipelines. We charge our shippers tariff rates based on transportation from the origination point on the pipeline to the point of delivery.
Our pipelines are regulated by one or more of the following federal governmental agencies: the Federal Energy Regulatory Commission (the FERC), the Surface Transportation Board (the STB), the Department of Transportation (the DOT), the Environmental Protection Agency (the EPA) and the Department of Homeland Security. In addition, our pipelines are subject to the respective jurisdictions of the states those lines traverse. See “Rate Regulation” and “Environmental, Health, Safety and Security Regulation” below for additional discussion.
The majority of our pipelines are deemed to be “common carrier” lines. Common carrier activities are those for which transportation is available to any shipper who requests such services and satisfies the conditions and specifications for transportation. Published tariffs for our petroleum product pipeline shipments are (i) filed with the FERC for interstate pipeline shipments and (ii) filed with the relevant state authority for intrastate pipeline shipments.
We operate our pipelines remotely through an operational technology system called the Supervisory Control and Data Acquisition, or SCADA, system.
Demand for and Sources of Refined Products and Crude Oil
Throughput activity on our Central West Refined Product Pipelines and the East and North Pipelines depends on the level of demand for refined products and other products in the markets served by those pipelines, as well as the ability and willingness of the refiners and marketers with access to the pipelines to supply that demand through our pipelines. Demand for renewable products handled by our pipeline systems, such as biodiesel and ethanol, is driven by the overall level of demand for refined products mentioned above, as well as regulatory requirements and our customers’ goals to increase their use of renewable fuels.
The majority of the refined products delivered through the Central West Refined Product Pipelines and the North Pipeline are gasoline and diesel fuel that originate at refineries connected to our pipelines. Demand for motor fuels fluctuates as prices for these products fluctuate. Prices fluctuate for a variety of reasons, including the overall balance in supply and demand, which is affected by general economic conditions, among other factors. Prices for gasoline and diesel fuel usually increase in the warm weather months when people tend to drive automobiles more often and for longer distances.
Much of the refined products and natural gas liquids delivered through the East Pipeline, and a portion of volumes on the North Pipeline, are ultimately used as fuel for railroads, ethanol denaturant or in agricultural operations, including fuel for farm equipment, irrigation systems, trucks used for transporting crops and crop-drying facilities. Demand for refined products for agricultural use, and the relative mix of products required is affected by weather conditions in the markets served by the East and North Pipelines. The agricultural sector is also affected by government agricultural policies and crop commodity prices.
Although periods of drought suppress agricultural demand for some refined products, particularly those used for fueling farm equipment, the demand for fuel to power irrigation systems often increases during such times. The mix of refined products delivered for agricultural use varies seasonally, with gasoline demand peaking in early summer, diesel fuel demand peaking in late summer and propane demand highest in the fall.
Our refined product pipelines are also dependent upon adequate levels of production of refined products by refineries connected to the pipelines, directly or through connecting pipelines. The refineries are, in turn, dependent upon adequate supplies of suitable grades of crude oil. Certain of our Central West Refined Products Pipelines are connected directly to Valero Energy refineries and are subject to long-term throughput agreements with Valero Energy. If operations at one of these refineries were discontinued or significantly reduced, it could have a material adverse effect on our operations, although we would endeavor to minimize the impact by seeking alternative customers for those pipelines.
The North Pipeline is heavily dependent on Marathon’s Mandan, North Dakota refinery, which primarily runs North Dakota crude oil (although it has the ability to process other crude oils), and an interruption in operations at the Marathon refinery could have a material adverse effect on our operations. In addition, the North Pipeline receives refined products from the Laurel, Montana refinery operated by CHS Inc. The majority of the refined products transported through the East Pipeline are produced at three refineries located at McPherson and El Dorado, Kansas and Ponca City, Oklahoma, which are operated by CHS Inc., HollyFrontier Corporation and Phillips 66, respectively. The East Pipeline also has access to Gulf Coast supplies of products through third-party connecting pipelines that receive products originating from Gulf Coast refineries.
Other than the Valero Energy refineries and the Marathon refinery described above, if operations at any one refinery were discontinued, we believe (assuming stable demand for refined products in markets served by the refined product pipelines) that the effects thereof would be short-term in nature, and our business would not be materially adversely affected over the long-term because such discontinued production could be replaced by other refineries or other sources.
Our crude oil pipelines are dependent on our customers’ continued access to sufficient crude oil and sufficient demand for refined products for our customers to operate their refineries. The supply of crude oil production (domestic and foreign) could fluctuate with the price of crude oil. Changes in crude oil prices could also affect the exploration and production of shale plays, which could affect demand for crude oil pipelines serving those regions, such as our Corpus Christi Crude Pipeline System and Permian Crude System. During periods of sustained low prices, or uncertainty in regulatory changes that could increase costs or impose restrictions on operations, producers tend to reduce their capital spending and drilling activity and narrow their focus to assets in the most cost-advantaged regions.
In addition, certain of our crude oil pipelines, including the McKee System, are the primary source of crude oil for our customers’ refineries. Therefore, these “demand-pull” pipelines are less affected by changes in crude oil prices. For example, refiners can benefit from lower crude oil prices if they are able to take advantage of lower feedstock prices in areas with healthy regional demand; however, as refined product inventories increase, refiners typically reduce their production rate, which may reduce the degree to which they are able to benefit from low crude prices.
The impacts from COVID-19 and actions by OPEC+, including crude oil price volatility and reduced refinery production rates, drilling activity and overall consumer demand, negatively impacted demand for our crude and refined product pipelines primarily in 2020. Although demand in most of our pipelines returned to pre-pandemic levels or higher in 2021, the lingering impact on economic activity from the COVID-19 pandemic could continue to cause volatility in demand for the transportation in our pipelines.
Demand for and Sources of Anhydrous Ammonia
Our Ammonia Pipeline is currently the only major pipeline in the United States transporting anhydrous ammonia into the nation’s corn belt. The pipeline is connected to domestic production facilities and also has the capability to receive products from outside the United States directly into the system.
Throughputs on our Ammonia Pipeline depend on overall demand for nitrogen fertilizer use, the price of natural gas, which is the primary component of anhydrous ammonia, and the level of demand for direct application of anhydrous ammonia as a fertilizer for crop production (Direct Application). Demand for Direct Application is dependent on the weather, as Direct Application is not effective when soil is either too wet or too dry.
Corn producers have fertilizer alternatives to anhydrous ammonia, such as liquid or dry nitrogen fertilizers. Liquid and dry nitrogen fertilizers are both less sensitive to weather conditions during application but are generally more costly than anhydrous ammonia. In addition, anhydrous ammonia has the highest nitrogen content of any nitrogen-derivative fertilizer.
Demand for anhydrous ammonia has been insulated from the negative impacts from COVID-19 by continued strong agricultural demand and lower-density population centers in the Midwest.
As discussed above, our customers include integrated oil companies, refining companies and others. Valero Energy, the largest customer of our pipeline segment, accounted for approximately 26% of the total segment revenues for the year ended December 31, 2021. No other single customer accounted for a significant portion of the total revenues of our pipeline segment.
Competition and Other Business Considerations
Because pipelines are generally the lowest-cost method for intermediate and long-haul movement of crude oil and refined products, our more significant competitors are common carrier and proprietary pipelines owned and operated by major integrated and large independent oil companies and other pipeline companies in our service areas. Competition between common carrier pipelines is based primarily on transportation charges, quality of customer service and proximity to end users. Trucks may deliver products competitively for short-hauls; however, trucking costs render that mode of transportation uncompetitive with pipeline options for longer hauls or larger volumes.
Most of our refined product pipelines and certain of our crude oil pipelines within the Central West System are physically integrated with, and principally serve, refineries owned by Valero Energy. As a result, we do not believe that we will face significant competition for transportation services provided to the Valero Energy refineries we serve.
Certain of our crude oil pipelines serve areas and/or refineries that are affected by domestic shale oil production in the Eagle Ford, Permian Basin and Granite Wash regions. Our pipelines also face competition from other crude oil pipelines and truck transportation in these regions. However, some of that exposure is mitigated through our long-term contracts and minimum volume commitments with creditworthy customers.
The East and North Pipelines compete with an independent common carrier pipeline system owned by Magellan Midstream Partners, L.P. (Magellan) that operates approximately 100 miles east of and parallel to the East Pipeline and in close proximity to the North Pipeline. Certain of the East Pipeline’s and the North Pipeline’s delivery terminals are in direct competition with Magellan’s terminals. Competition with Magellan is based primarily on transportation charges, quality of customer service and proximity to end users.
Competitors of the Ammonia Pipeline include Midwest production facilities, nitrogen fertilizer substitutes and barge, truck and railroad transportation under certain market conditions.
Looking forward, we have seen growing interest for utilization of ammonia as a source for renewable electricity generation to power fuel-cell vehicles. While future uses for lower emission-producing “blue” and “green” ammonia are still developing, we are partnering with existing and potential customers to develop these projects, which could increase demand for and utilization of our Ammonia Pipeline.
Results of Operations
The following table presents operating highlights for the pipeline segment:
| ||Year Ended December 31,|| |
|Pipeline Segment:||(Thousands of Dollars, Except Barrel Data)|
|Crude oil pipelines throughput (barrels/day)||1,281,568 ||1,237,757 ||43,811 |
|Refined products and ammonia pipelines throughput (barrels/day)||585,189 ||524,842 ||60,347 |
|Total throughput (barrels/day)||1,866,757 ||1,762,599 ||104,158 |
|Throughput and other revenues||$||762,238 ||$||718,823 ||$||43,415 |
|Operating expenses||202,481 ||198,010 ||4,471 |
|Depreciation and amortization expense||179,088 ||177,384 ||1,704 |
|Asset impairment loss||59,197 ||— ||59,197 |
|Goodwill impairment loss||— ||225,000 ||(225,000)|
|Segment operating income||$||321,472 ||$||118,429 ||$||203,043 |
Pipeline segment revenues increased $43.4 million and throughputs increased 104,158 barrels per day for the year ended December 31, 2021, compared to the year ended December 31, 2020. Although 2020 began with strong demand in the first quarter, prior to the pandemic, demand was severely reduced for the remainder of the year, resulting from COVID-19 restrictions, including stay-at-home orders and business closures. In comparison, the 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 and throughputs increased primarily due to the 2021 rebound in demand resulting in:
•an increase in revenues of $29.9 million and an increase in throughputs of 40,170 barrels per day on our Permian Crude System, which included an increase of $17.5 million in sales of crude oil from surplus pipeline loss allowance;
•an increase in revenues of $4.7 million and an increase in throughputs of 3,277 barrels per day on our Valley Pipeline System, combined with higher minimum volume commitments that began in September 2020;
•an increase in revenues of $18.2 million and an increase in throughputs of 12,450 barrels per day on our East and North pipelines combined;
•an increase in revenues of $13.0 million and an increase in throughputs of 40,575 barrels per day on our McKee System pipelines, partially offset by the effects of Winter Storm Uri in the first quarter of 2021;
•an increase in revenues of $3.3 million and an increase in throughputs of 11,634 barrels per day on our Three Rivers System, combined with the reactivation of our refined products pipeline to transport diesel to our Nuevo Laredo terminal in Mexico, which was at full service at the end of the first quarter of 2020; and
•an increase in revenues of $3.1 million and an increase in throughputs of 1,574 barrels per day on our Ammonia Pipeline due to strong agricultural demand.
These increases were partially offset by:
•a decrease in revenues of $22.1 million and a decrease in throughputs of 16,324 barrels per day on our Corpus Christi Crude Pipeline System, mainly due to lower demand for exports in 2021, with the most significant impact in the first quarter of 2021, compared to the first quarter of 2020 pre-pandemic demand; and
•a decrease in revenues of $7.2 million despite throughputs remaining flat on our Ardmore System, primarily due to fewer barrels moved at higher average tariffs in 2021, compared to 2020 and the expiration of a customer contract at the end of the first quarter of 2021. Volumes were flat due to lower demand in 2020 and fewer barrels moved due to Winter Storm Uri.
Operating expenses increased $4.5 million for the year ended December 31, 2021, compared to the year ended December 31, 2020, primarily due to higher compensation expense of $6.9 million and an increase in insurance expense of $2.5 million due to higher premiums, partially offset by a decrease of $4.5 million in maintenance and regulatory expenses, mainly on our Ammonia Pipeline.
Depreciation and amortization expense increased $1.7 million for the year ended December 31, 2021, compared to the year ended December 31, 2020, mainly due to the completion of projects on our Permian Crude System and other completed projects.
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 Pipeline. In the first quarter of 2020, the negative impact of the COVID-19 pandemic, combined with actions by OPEC+, led to a decline in our unit price and market capitalization in March 2020 and, as a result, we recorded a non-cash goodwill impairment charge of $225.0 million related to our crude oil pipelines reporting unit. Please refer to Notes 4 and 10 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion.
Our storage 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, 2021, we owned and operated 29 terminal and storage facilities in the United States, one terminal in Nuevo Laredo, Mexico and one terminal located in Point Tupper, Canada, with an aggregate storage capacity of 44.2 million barrels. The following table sets forth information about our terminal and storage facilities as of December 31, 2021:
|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||491,000 |
|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||8,576,000 |
|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||817,000 |
|Portland, OR||1,348,000 |
|Tacoma, WA||391,000 |
|Vancouver, WA (b)||774,000 |
|West Coast Terminals||7,006,000 |
|Benicia, CA||3,683,000 |
|Corpus Christi, TX||4,030,000 |
|Texas City, TX||3,141,000 |
|Refinery Storage Tanks||10,854,000 |
|Point Tupper, Canada||7,778,000 |
(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 Major Terminal and Storage Facilities
Refinery Storage Tanks. We own and operate 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.
St. James, Louisiana. Our St. James terminal, which is located on the Mississippi River near St. James, Louisiana, has a total storage capacity of 9.9 million barrels. The facility 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 of the tanks capable of fuel oil or heated crude oil storage. Additionally, the facility has one barge dock and two ship docks and we 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.
Point Tupper. We own and operate a 7.8 million barrel terminalling and storage facility located at Point Tupper on the Strait of Canso, near Port Hawkesbury, Nova Scotia. This facility is the deepest ice-free marine terminal on the North American Atlantic coast, with access to the East Coast, Canada and the Midwestern United States markets via the St. Lawrence Seaway and the Great Lakes system. With one of the premier jetty facilities in North America, the Point Tupper facility can accommodate heavily laden ultra-large crude carriers (ULCCs) for loading and discharging crude oil, petroleum products and petrochemicals. Crude oil and petroleum product movements at the terminal are fully automated. Separate fees apply for use of the jetty facility, as well as associated services, including pilotage, tug assistance, line handling, launch service, emergency response services and other ship services (all of which are considered optional services). On February 11, 2022, we entered into an agreement to sell the equity interests in our wholly owned subsidiaries that own our Point Tupper facility and we expect to complete the sale in the first half of 2022.
Corpus Christi North Beach. We own and operate a 4.0 million barrel crude oil storage and terminalling facility located at the Port of Corpus Christi in Texas. The facility supports our pipelines that transport 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. This facility has access to four docks, including two private docks. We can accommodate Suezmax-class vessels and load crude oil onto ships 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.
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. 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.
Demand for Storage Services
The operations of our refined product terminals depend in large part on the 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 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,” 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, Corpus Christi exports have not returned to pre-pandemic levels due to lower global demand for refined products and crude oil.
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 expected to continue, we have completed, and continue to develop, renewable fuel storage projects at our West Coast terminals to meet this demand.
Overall, refinery production rates, drilling activity and overall consumer demand in the U.S. has rebounded in 2021 bringing demand for most of our terminal and storage facilities back to pre-pandemic levels. In addition, certain of our storage facilities continued to benefit in 2021 from the contango market that emerged in March and April of 2020 due to contracts that extended into 2021. However, the detrimental impact of the pandemic has continued to affect global demand, resulting in less crude oil exports from our Corpus Christi North Beach facility. The duration, severity and lingering impact on economic activity from the COVID-19 pandemic and future production decisions from OPEC+ could continue to cause volatility in demand for our terminal and storage facilities.
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. Valero Energy and Trafigura Trading LLC, the largest customers of our storage segment, accounted for approximately 26% and 19%, respectively, of the total revenues of the segment for the year ended December 31, 2021. 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 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 operator. Operators with versatile storage capabilities typically require less modification prior to usage, ultimately making the storage cost to the customer more attractive. On the West Coast, regulatory priorities continue to increase demand for renewable fuels in the region, while at the same time, obtaining permits for such greenfield projects remains difficult, adding more value to our existing assets.
Our crude oil refinery storage tanks are physically integrated with and serve refineries owned by Valero Energy, and we have entered into various agreements with Valero Energy governing the use 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
Eastern U.S. Terminal Operations. 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. The nine terminals had an aggregate storage capacity of 14.8 million barrels and were included in the storage segment until the sale closed on October 8, 2021.
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 two terminals had an aggregate storage capacity of 3.0 million barrels and were previously included in our storage segment.
Selby Terminal Fire. We recognized gains from business interruption insurance of $4.0 million and $6.7 million for the years ended December 31, 2021 and 2020, respectively, which are included in “Operating expenses” in the consolidated statements of income (loss) and relate to a fire in October 2019 at our terminal facility in Selby, California.
The following table presents operating highlights for the storage segment:
| ||Year Ended December 31,|| |
|Storage Segment:||(Thousands of Dollars, Except Barrel Data)|
|Throughput (barrels/day)||421,862 ||469,862 ||(48,000)|
|Throughput terminal revenues||$||122,331 ||$||136,632 ||$||(14,301)|
|Storage terminal revenues||305,337 ||357,810 ||(52,473)|
|Total revenues||427,668 ||494,442 ||(66,774)|
|Operating expenses||185,597 ||205,569 ||(19,972)|
|Depreciation and amortization expense||87,500 ||99,092 ||(11,592)|
|Asset impairment loss||95,711 ||— ||95,711 |
|Goodwill impairment loss||34,060 ||— ||34,060 |
|Segment operating income||$||24,800 ||$||189,781 ||$||(164,981)|
Throughput terminal revenues decreased $14.3 million and throughputs decreased 48,000 barrels per day for the year ended December 31, 2021, compared to the year ended December 31, 2020, mainly due to a decrease in revenues of $18.7 million and a decrease in throughputs of 67,129 barrels per day at our Corpus Christi North Beach terminal. Consistent with lower volumes on our Corpus Christi Crude Pipeline System, these decreases at our Corpus Christi North Beach terminal were due to a decrease in export demand and volumes delivered to our customers’ refineries instead of over our docks in 2021, as well as a reduction in minimum volume commitments. These decreases were partially offset by an increase in revenues of $4.5 million and an increase in throughputs of 19,834 barrels per day at our Central West Terminals, due to the 2021 rebound in demand.
Storage terminal revenues decreased $52.5 million for the year ended December 31, 2021, compared to the year ended December 31, 2020, primarily due to:
•a decrease in revenues of $31.8 million due to the Texas City Sale in December 2020;
•a decrease in revenues of $16.5 million due to the Eastern U.S. Terminals Disposition in October 2021; and
•a decrease in revenues of $10.5 million and $5.0 million at our St. James and Point Tupper terminals, respectively, mainly due to the expiration of customer contracts.
These decreases were partially offset by the following:
•an increase in revenues of $5.7 million at our West Coast Terminals, mainly due to completed projects, resulting in new contracts and rate escalations, as well as higher throughputs and handling fees; and
•an increase in revenues of $1.7 million at our Central West Terminals, primarily due to the reactivation of our refined products pipeline to transport diesel to our Nuevo Laredo terminal in Mexico, which began full service at the end of the first quarter of 2020.
Operating expenses decreased $20.0 million for the year ended December 31, 2021, compared to the year ended December 31, 2020, primarily due to an aggregate decrease in operating expenses of $30.4 million due to the Eastern U.S. Terminals Disposition in October 2021 and the Texas City Sale in December 2020. This decrease was partially offset by an increase in compensation expense of $4.3 million, an increase in insurance expense of $3.5 million due to higher premiums and lower business interruption insurance recovery of $2.7 million in 2021 related to the Selby terminal.
Depreciation and amortization expense decreased $11.6 million for the year ended December 31, 2021, compared to the year ended December 31, 2020, mainly due to lower depreciation and amortization expense related to the Eastern U.S. Terminals Disposition in October 2021 and the Texas City Sale in December 2020.
FUELS MARKETING SEGMENT
The fuels marketing segment includes our bunkering operations in the Gulf Coast, as well as certain of our blending operations associated with our Central East System. The results of operations for the fuels marketing segment depend largely on the margin between our costs and the sales prices of the products we market. Therefore, the results of operations for this segment are more sensitive to changes in commodity prices compared to the operations of the pipeline and storage segments. We enter into derivative contracts to attempt to mitigate the effects of commodity price fluctuations. The financial impacts of the derivative financial instruments associated with commodity price risk were not material for any periods presented. The COVID-19 pandemic has caused volatility in commodity prices and volumes in 2021 and 2020, especially for our blending operations and bunker fuel sales to cruise ships.
Customers for bunker fuel sales are mainly ship owners, including cruise line companies, marketers and traders. In the sale of bunker fuel, we compete with ports offering bunker fuels that are along the route of travel of the vessel. One of our customers, a marketer of petroleum products, was the largest customer of our fuels marketing segment and accounted for approximately 14% of the total segment revenues for the year ended December 31, 2021. No other customer accounted for a significant portion of the total revenues of the fuels marketing segment for the year ended December 31, 2021.
Results of Operations
The following table presents operating highlights for the fuels marketing segment:
| ||Year Ended December 31,|| |
|Fuels Marketing Segment:||(Thousands of Dollars)|
|Product sales||$||428,608 ||$||268,345 ||$||160,263 |
|Cost of goods||417,000 ||253,704 ||163,296 |
|Gross margin||11,608 ||14,641 ||(3,033)|
|Operating expenses||427 ||2,408 ||(1,981)|
|Segment operating income||$||11,181 ||$||12,233 ||$||(1,052)|
Segment operating income decreased $1.1 million for the year ended December 31, 2021, compared to the year ended December 31, 2020, primarily due to lower gross margins of $4.8 million from our bunkering operations, partially offset by higher gross margins of $1.7 million from our blending operations and a credit loss recovery of $1.7 million that we received in the first quarter of 2021, which is included in operating expenses.
LIQUIDITY AND CAPITAL RESOURCES
Our primary cash requirements are for distributions to our partners, debt service, capital expenditures and operating expenses. Our partnership agreement requires that we distribute all “Available Cash” to our common limited partners each quarter. “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, 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.
In prior years, our objective was to fund our reliability capital expenditures and distribution requirements with net cash provided by operating activities during that year. If we did not generate sufficient cash from operations to meet that objective, we used cash on hand or other sources of cash flow, such as borrowings under our revolving credit agreement, sales of non-strategic assets and funds raised through debt or equity offerings. Prior to 2021, we funded our strategic capital expenditures primarily from borrowings under our revolving credit agreement, funds raised through debt or equity offerings and/or sales of non-strategic assets. However, our ability to raise funds by issuing debt or equity depends on many factors beyond our control, including our ability to access such markets with the continued uncertainty surrounding the duration and severity of the impact from the COVID-19 pandemic. Our risk factors in Item 1A. “Risk Factors” describe the risks inherent to these sources of funding and the availability thereof.
In 2020, due to the negative impacts of, and the continued uncertainty related to, the COVID-19 pandemic and actions taken by OPEC+, we took steps to preserve and enhance our liquidity, and we continued to prioritize liquidity in 2021 by extending the maturity on our $1.0 billion revolving credit agreement to April 27, 2025; extending the scheduled termination date on our $100.0 million receivables financing agreement to January 31, 2025; and selling our Eastern U.S. Terminal Operations on October 8, 2021. In 2021, we also reduced our strategic capital expenditures by over 10%, as compared to 2020, which had been lowered by approximately 50% to reduce our overall cash requirements at the beginning of the pandemic. We continue to manage our operations with fiscal discipline and monitor our cash requirements in this turbulent environment.
Beginning in 2021, in response to the shifting expectations of our industry, including continuing to reduce leverage, combined with the ongoing lack of access to equity markets and the COVID-19 environment, we positioned ourselves to fund all of our expenses, distribution requirements and capital expenditures using internally generated cash flows for the full-year. We met our objective in 2021, and we expect to do so again in 2022.
Beyond 2022, absent a change to the factors described above, including a return of access to equity capital markets, we plan to continue to fund our expenses, distribution requirements and capital expenditures with internally generated cash flows, which could include proceeds from asset dispositions. We have no long-term debt maturities until 2025, and we have been and expect to continue to be able to access debt capital markets to refinance those maturities. 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 begun taking steps to position ourselves to redeem the Series D Preferred Units gradually over the next several years in advance of the possible mandatory redemption. By reducing our leverage, primarily through the disposition of non-strategic assets in recent years, and continuing to increase the amount by which our internally generated cash flows exceed our expenses, distribution requirements and capital expenditures, we are increasing our financial flexibility. Beyond those items, we would also continue to evaluate other sources of liquidity to manage the optional or mandatory redemption of the Series D Preferred Units, including the issuance of common or other preferred units.
A discussion of our cash flows and other changes in financial position for 2019 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 Annual Report on Form 10-K for the year ended December 31, 2020 filed with the SEC on February 25, 2021.
CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2021 AND 2020
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,|
|(Thousands of Dollars)|
|Net cash provided by (used in):|
|Operating activities||$||501,478 ||$||525,998 |
|Investing activities||75,978 ||(98,084)|
|Effect of foreign exchange rate changes on cash||136 ||916 |
|Net (decrease) increase in cash, cash equivalents and restricted cash||$||(147,987)||$||137,446 |
For the years ended December 31, 2021 and 2020, net cash provided by operating activities exceeded our distributions to unitholders, reliability capital expenditures and strategic capital expenditures.
Net cash provided by operating activities decreased by $24.5 million for the year ended December 31, 2021, compared to the year ended December 31, 2020, primarily due to changes in working capital. Our working capital increased by $14.1 million for the year ended December 31, 2021, compared to a decrease of $11.9 million for the year ended December 31, 2020. Working capital requirements are mainly affected by our accounts receivable and accounts payable balances, which vary depending on the timing of payments. In addition, the timing of payments related to accrued interest payable changed due to the senior note repayments in 2021. Cash flows from operating activities include $19.1 million and $35.0 million of insurance proceeds for the years ended December 31, 2021 and 2020, respectively, related to repairs/cleanup costs and business interruption from the 2019 Selby terminal fire.
For the year ended December 31, 2021, we recorded net cash provided by investing activities of $76.0 million, compared to net cash used in investing activities of $98.1 million for the year ended December 31, 2020, primarily due to higher proceeds from asset sales of $135.8 million.
Net cash used in financing activities increased by $434.2 million for the year ended December 31, 2021, compared to the year ended December 31, 2020, mainly due to an increase in net debt repayments. For the year ended December 31, 2021, we had net debt repayments of $412.7 million associated with senior note maturities, which we paid primarily with proceeds from asset sales. For the year ended December 31, 2020, we had $108.0 million in net borrowings and a $49.2 million payment to terminate interest rate swaps.
SOURCES OF LIQUIDITY
Issuance of 5.75% and 6.375% Senior Notes
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 repay outstanding borrowings under the Term Loan, along with early repayment premiums (discussed further below), as well as outstanding borrowings under our Revolving Credit Agreement, as defined below. The interest on the 5.75% and 6.375% senior notes is payable semi-annually in arrears on April 1 and October 1 of each year, beginning on April 1, 2021. These notes rank equally with existing senior unsecured indebtedness and senior to existing subordinated indebtedness of NuStar Logistics. These notes contain terms comparable to our other senior notes and are guaranteed by NuStar Energy and NuPOP.
Revolving Credit Agreement
As of December 31, 2021, NuStar Logistics’ $1.0 billion unsecured revolving credit agreement (the Revolving Credit Agreement) had $884.8 million available for borrowing and $110.5 million of borrowings outstanding. Letters of credit issued under the Revolving Credit Agreement totaled $4.7 million as of December 31, 2021. 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, 2021, 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, 2021, our consolidated interest coverage ratio was 2.11x and our consolidated debt coverage ratio was 3.99x.
On January 28, 2022, we amended and restated our unsecured Revolving Credit Agreement to, among other things: (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 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.
In November 2021, S&P Global Ratings affirmed our credit rating and our rating outlook and, in October 2021, Fitch Ratings affirmed our credit rating and our rating outlook. In April 2021, Moody’s Investor Service Inc. affirmed our credit rating and changed our rating outlook from negative to stable. In August 2020, Moody’s Investor Service Inc. downgraded our credit rating from Ba2 to Ba3 and changed our rating outlook to negative. This rating downgrade caused the interest rate on our Revolving Credit Agreement to increase by 0.25% effective August 2020. 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|
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 $100.0 million receivables financing agreement with a third-party lender (the Receivables Financing Agreement) and agreements with certain of NuStar Energy’s wholly owned subsidiaries (together with the Receivables Financing Agreement, the Securitization Program). 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.
On January 28, 2022, the Receivables Financing Agreement was amended to, among other things: (i) extend the scheduled termination date from September 20, 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 references 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 the Receivables Financing Agreement.
On April 19, 2020, NuStar Energy and NuStar Logistics entered into an unsecured term loan credit agreement with certain lenders and Oaktree Fund Administration, LLC, as administrative agent for the lenders. The Term Loan provided for an aggregate commitment of up to $750.0 million pursuant to a three-year unsecured term loan credit facility. NuStar Logistics drew $500.0 million (the Initial Loan) on April 21, 2020 (the Initial Loan Funding Date). 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 issuance costs of $14.4 million, to repay outstanding borrowings under our Revolving Credit Agreement.
On September 16, 2020, we used a portion of the net proceeds from the issuance of the 5.75% and 6.375% senior notes to repay the $500.0 million of outstanding borrowings under the Term Loan and 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 commitment fee, which resulted in a loss from extinguishment of debt of $137.9 million in the third quarter of 2020. We terminated the Term Loan on February 16, 2021.
Please refer to Note 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of our debt agreements.
We used the proceeds from the Eastern U.S. Terminals Disposition in 2021 and the Texas City Sale in 2020 to reduce debt and thereby improve our debt metrics.
MATERIAL CASH REQUIREMENTS
Our operations require significant investments to maintain, upgrade or enhance the operating capacity of our existing assets. Our capital expenditures consist of:
•strategic capital expenditures, such as those to expand or upgrade the operating capacity, increase efficiency or increase the earnings potential of existing assets, whether through construction or acquisition, as well as certain capital expenditures related to support functions; and
•reliability capital expenditures, such as those required to maintain the current operating capacity of existing assets or extend their useful lives, as well as those required to maintain equipment reliability and safety.
The following table summarizes our capital expenditures:
|Strategic Capital Expenditures||Reliability Capital Expenditures||Total|
|(Thousands of Dollars)|
|For the year ended December 31:|
|2021||$||140,867 ||$||40,266 ||$||181,133 |
|2020||$||159,507 ||$||38,572 ||$||198,079 |
Expected for the year ended December 31, 2022
|$ 130,000 - 160,000||$ 35,000 - 45,000|
Strategic capital expenditures for the years ended December 31, 2021 and December 31, 2020 mainly consisted of expansion projects on our Permian Crude System and our West Coast biofuels terminal projects, and in 2020, expansion projects on our Corpus Christi Crude System. Strategic capital expenditures also included projects to increase flexibility at our St. James and other terminals in 2020. Reliability capital expenditures primarily related to maintenance upgrade projects at our terminals.
We expect our strategic capital expenditures for the year ended December 31, 2022 to include spending of approximately $55.0 million on expansion projects to accommodate production growth in the Permian Basin and approximately $25.0 million on projects to handle biofuels demand on the West Coast, as well as other smaller projects. We continue to evaluate our capital budget and internal growth projects can be accelerated or scaled back depending on market conditions or customer demand. Therefore, our actual capital expenditures for 2022 may increase or decrease from the expected amounts noted above. We expect to self-fund all of our capital expenditures in 2022.
Pension and Other Postretirement Plan Contributions
The NuStar pension plan was well-funded at December 31, 2021 and, accordingly, we did not make any discretionary contributions in 2021. During 2021, we contributed $0.3 million to our pension and postretirement benefit plans in order to fund current benefits. We will monitor our funding status in 2022 to determine if any contributions are required by regulations or laws, or, with respect to unfunded plans, necessary to fund current benefits. We expect to contribute approximately $9.9 million to our pension and postretirement benefit plans in 2022. Pension and postretirement benefit plans funding beyond 2022 is uncertain as the funding varies from year to year based upon changes in the fair value of the plan assets and actuarial assumptions.
Common Limited Partners. Distribution payments are made to our common limited partners within 45 days after the end of each quarter as of a record date that is set after the end of each quarter. The following table summarizes information about cash distributions to our common limited partners applicable to the period in which the distributions were earned:
|Cash Distributions Per Unit||Total Cash Distributions||Record Date||Payment Date|
|(Thousands of Dollars)|
|December 31, 2021||$||0.40 ||$||44,008 ||February 8, 2022||February 14, 2022|
|September 30, 2021||0.40 ||43,814 ||November 8, 2021||November 12, 2021|
|June 30, 2021||0.40 ||43,814 ||August 6, 2021||August 12, 2021|
|March 31, 2021||0.40 ||43,834 ||May 10, 2021||May 14, 2021|
Year ended December 31, 2021
|$||1.60 ||$||175,470 |
Year ended December 31, 2020
|$||1.60 ||$||174,873 |
Preferred Units. Distributions on our 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 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 Series A, B and C Preferred Units):
|Units||Fixed Distribution Rate Per Annum (as a Percentage of the $25.00 Liquidation Preference Per Unit)||Fixed Distribution Rate Per Unit Per Annum||Fixed Distribution Per Annum||Optional Redemption Date/Date at Which Distribution Rate Becomes Floating||Floating Annual Rate (as a Percentage of the |
Preference Per Unit)
|(Thousands of Dollars)|
|Series A Preferred Units||8.50%||$||2.125 ||$||19,252 ||December 15, 2021||Three-month LIBOR plus 6.766%|
|Series B Preferred Units||7.625%||$||1.90625 ||$||29,357 ||June 15, 2022||Three-month LIBOR plus 5.643%|
|Series C Preferred Units||9.00%||$||2.25 ||$||15,525 ||December 15, 2022||Three-month LIBOR plus 6.88%|
The Series A Preferred Units switched from a fixed distribution rate to a floating rate on December 15, 2021, with the floating rate set forth below for the period indicated:
|Period||Distribution Rate per Unit||Total Distribution|
|(Thousands of Dollars)|
|December 15, 2021 - March 14, 2022||$||0.43606 ||$||3,951 |
The distribution rates on the 23,246,650 Series D Preferred Units issued and outstanding are as follows: (i) 9.75%, or $57.6 million, per annum ($0.619 per unit per distribution period) for the first two years (beginning with the September 17, 2018 distribution); (ii) 10.75%, or $63.4 million, per annum ($0.682 per unit per distribution period) for years three through five; and (iii) the greater of 13.75%, or $81.1 million, 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 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 $0.048 per Series D Preferred Unit. We would also be subject to other requirements.
In January 2022, our board of directors declared quarterly distributions with respect to the Series A, B and C Preferred Units and the Series D Preferred Units to be paid on March 15, 2022.
The following table summarizes our debt obligations:
| ||Maturity||Outstanding Obligations as of December 31, 2021|
| ||(Thousands of Dollars)|
Revolving Credit Agreement, 2.9% as of December 31, 2021
|April 27, 2025 (a)||$||110,500 |
|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 |
Subordinated notes, 6.9% as of December 31, 2021
|January 15, 2043||$||402,500 |
|GoZone Bonds 5.85% - 6.35%||2038||thru||2041||$||322,140 |
Receivables Financing Agreement, 2.3% as of December 31, 2021
|January 31, 2025 (a)||$||83,800 |
(a)On January 28, 2022, the maturity date on the Revolving Credit Agreement was extended from October 27, 2023 to April 27, 2025 and the scheduled termination date of the Receivables Financing Agreement was extended from September 20, 2023 to January 31, 2025.
On November 1, 2021, we repaid our $250.0 million of 4.75% senior notes due February 1, 2022 with proceeds from the Eastern U.S. Terminals Disposition. We used borrowings under our Revolving Credit Agreement to repay our $300.0 million of 6.75% senior notes due February 1, 2021 at maturity and our $450.0 million of 4.8% senior notes due September 1, 2020 at maturity.
On June 3, 2020, NuStar Logistics completed the reoffering and conversion of the GoZone Bonds, which, among other things, converted the interest rate from a weekly rate to a long-term rate. We did not receive any proceeds from the reoffering, and the reoffering did not increase our outstanding debt. As reflected in the table below, certain series of GoZone Bonds in principal amounts totaling $75.0 million and $103.8 million contain a requirement for the bondholders to tender their bonds in exchange for 100% of the principal plus accrued and unpaid interest on June 1, 2025 and on June 1, 2030, respectively, after which these bonds will potentially be remarketed with a new interest rate established.
The following table summarizes the GoZone Bonds outstanding as of December 31, 2021:
| ||(Thousands of Dollars)|| |
|Series 2008||June 26, 2008||$||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|
We believe that, as of December 31, 2021, 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.
The following table presents summarized combined income statement and balance sheet 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.
|Guarantor Issuer Group|
|(Thousands of Dollars)|
Summarized Combined Balance Sheet Information as of December 31, 2021:
|Current assets||$||33,645 |
|Long-term assets||$||2,791,481 |
|Current liabilities (a)||$||119,841 |
|Long-term liabilities, including long-term debt||$||3,162,351 |
|Series D preferred limited partners||$||616,439 |
Summarized Combined Income Statement Information for the year ended December 31, 2021:
|Operating income||$||244,975 |
|Interest expense, net||$||(214,836)|
|Net income||$||33,704 |
(a)Excluding $1,004.5 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 $2,180.3 million as of December 31, 2021. Revenue and net income for the non-guarantor subsidiaries totaled $781.0 million and $4.5 million, respectively, for the year ended December 31, 2021. Please refer to Note 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of our debt agreements.
The following table presents our contractual obligations and commitments as of December 31, 2021:
| ||(Thousands of Dollars)|
|Long-term debt maturities||$||— ||$||3,168,940 |
|Interest payments (a)||192,461 ||1,705,420 |
|Operating leases (b)||12,252 ||84,739 |
|Finance leases (b)||5,831 ||71,724 |
|Purchase obligations (c)||10,606 ||15,122 |
|Total ||$||221,150 ||$||5,045,945 |
(a)The interest payments calculated for our variable-rate, long-term debt are based on interest rates and the outstanding borrowings as of December 31, 2021. The interest payments on our fixed-rate debt are based on the stated interest rates and the outstanding borrowings as of December 31, 2021. Please see Note 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.
(b)Our operating leases consist primarily of land and dock leases at various terminal facilities and leases for marine vessels at our Point Tupper terminal facility. Our finance leases consist primarily of a dock lease at our Corpus Christi North Beach terminal facility with a remaining term of approximately four 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.
(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. 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 Redemption Features
We may redeem all or any portion of the 23,246,650 Series D Preferred Units issued and 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 $737.6 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 $708.1 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 $678.6 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, or approximately $678.6 million if all Series D Preferred Units are tendered, 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.
Environmental, Health and Safety
As described below under “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 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, 2021 and December 31, 2020 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.
We are subject to certain loss contingencies, and we 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, as further disclosed in Note 14 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”
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.
As of December 31, 2021, we have 1,267 employees, of which 1,187 are based in the United States, 69 are based in Canada and 11 are based in Mexico. Four and a half percent of our 1,267 employees are represented under collective bargaining agreements. In the United States, 496 of our employees work at our headquarters in San Antonio, Texas, with the remaining 691 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, 2021:
•19.8% of all of our employees and 31.2% of our employees at senior manager level and above are female; and
•31.6% of our U.S. employees and 23.9% 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, benefits and health and wellness programs, including 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, educational reimbursement, a disaster relief fund, 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.
NuStar’s culture revolves around 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 NuStar’s success and have helped us to recruit and retain our employees and make NuStar a great place to work. NuStar has been recognized on FORTUNE’S “100 Best Companies to Work For” list 12 times, FORTUNE’S “Best Workplaces for Millennials” list five times and was also recognized in 2021 on Latino Leader Magazine’s “Best Companies for Latinos to Work” list. NuStar also has been recognized as a top employer by regional and local publications. 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, 2021, our voluntary turnover rate was 4.4%, and 251 of our employees have been employed by NuStar or predecessor entities for at least 20 years.
As a midstream energy company, 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 2021 total recordable incident rate (TRIR) of 0.13 was 14.6 times better than the 1.9 average most recently reported by BLS for the bulk terminals industry and 7.7 times better than the 1.0 average most recently reported by BLS for the pipeline transportation industry, while our 2021 days away, restricted or transferred rate (DART) of 0.0 far exceeds the 1.5 average most recently reported by BLS for the bulk terminals industry and the 0.5 average most recently reported by BLS for the pipeline transportation industry. NuStar also participates in the Occupational Health and Safety 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, 2021, 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 11 times. Throughout the COVID-19 pandemic, we have continued to focus on safety and have taken measures to protect our employees and maintain safe, reliable operations to continue supplying the energy our country needs.
During 2021, we published our inaugural Sustainability Report, which also covers topics similar to those described above, including our guiding principles; operations and economic impact; COVID-19 pandemic response; environmental and safety programs, policies and statistics; employee engagement, development and training; diversity and inclusion; community involvement; recent awards; human rights and indigenous communities; and governance matters. Our Sustainability Report can be viewed at https://sustainability.nustarenergy.com. Information contained on our website is not part of this Annual Report on Form 10-K.
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.
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 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 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. In 2021, our capital expenditures attributable to compliance with environmental regulations were $6.4 million, and we currently project environmental regulatory compliance spending of approximately $6.8 million in 2022.
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.
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.
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 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 other countries in which we operate 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. Ongoing uncertainty surrounding the COVID-19 pandemic, including its duration and lingering impacts, and uncertainty surrounding future production decisions by oil-producing nations continue to cause volatility and could significantly impact management’s estimates and 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.
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 and $305.7 million in 2019. 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 goodwill impairment charges of $34.1 million, $225.0 million and $31.1 million for the years ended December 31, 2021, 2020 and 2019, respectively. Please refer to Notes 4 and 10 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data,” for discussion of the impairment charges.
Defined Benefit Plans
We estimate pension and other postretirement benefit obligations and costs based on actuarial valuations. The annual measurement date for our pension and other postretirement benefit plans is December 31. The actuarial valuations require the use of certain assumptions including discount rates, expected long-term rates of return on plan assets and expected rates of compensation increase. Changes in these assumptions are primarily influenced by factors outside our control. The discount rate is based on a hypothetical yield curve represented by a series of annualized individual discount rates. Each bond issue underlying the hypothetical yield curve required an average rating of double-A, when averaging all available ratings by Moody’s Investor Service Inc., S&P Global Ratings and Fitch Ratings. The expected long-term rate of return on plan assets is based on the weighted averages of the expected long-term rates of return for each asset class of investments held in our plans as determined using historical data and the assumption that capital markets are informationally efficient. The expected rate of compensation increase represents average long-term salary increases.
These assumptions can have an effect on the amounts reported in our consolidated financial statements. A 0.25% change in the specified assumptions would have the following effects (thousands of dollars):
Increase in benefit obligation as of December 31, 2021 resulting from:
|Discount rate decrease||$||6,900 ||$||600 |
|Compensation rate increase||$||600 ||n/a|
Increase in net periodic benefit cost for the year ending December 31, 2022
|Discount rate decrease||$||500 ||$||100 |
|Expected long-term rate of returns on plan assets decrease||$||400 ||n/a|
|Compensation rate increase||$||200 ||n/a|
Please refer to Note 21 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of our pension and other postretirement benefit obligations.
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. Please refer to Note 13 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for the amount of accruals for environmental matters.
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. Please see Note 14 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on our contingent liabilities.
NEW ACCOUNTING PRONOUNCEMENTS
Management’s Discussion and Analysis, Selected Financial Data, and Supplementary Financial Information
In November 2020, the Securities and Exchange Commission (SEC) issued final rules to modernize, simplify and enhance certain financial disclosure requirements in Regulation S-K. Among other changes, the amended guidance eliminates the requirements to present five-year selected financial data, the two-year quarterly financial data table and the contractual obligations table in the Form 10-K, while it adds requirements to disclose material cash requirements and additional information regarding critical accounting estimates. The rule changes became effective on February 10, 2021, and we are required to apply the amended rules in our filings for the fiscal year ending on December 31, 2021. Early application by amended Regulation S-K item was permitted any time after the effective date. We elected to apply provisions related to selected financial data and quarterly financial information in our Annual Report on Form 10-K for the year ended December 31, 2020 and applied the remaining provisions in our Annual Report on Form 10-K for the year ended December 31, 2021.
Please refer to Note 3 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a further discussion of new accounting pronouncements.
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 email@example.com.
ITEM 1A. RISK FACTORS
RISKS RELATED TO OUR BUSINESS
The ongoing effects of the COVID-19 pandemic, the actions taken in response thereto and developments in the global oil markets may continue to adversely affect our business, financial condition, results of operations or cash flows.
The coronavirus, or COVID-19, had a severe negative impact on global economic activity during 2020, which significantly reduced demand for petroleum products and increased the volatility of crude oil prices, beginning in March 2020. While a number of countries, including the United States, made significant progress during 2021 deploying COVID-19 vaccines, which has improved the economic conditions and outlook in those nations, many more continue to struggle to obtain and/or disseminate vaccinations to their populace, which continues to frustrate widespread global economic recovery. Even in the United States, if a sufficient proportion of people are not vaccinated, or as variants emerge, we may continue to face surges in COVID-19 cases in some regions, which could slow the pace of domestic economic improvement and undermine demand in the markets our assets serve. The COVID-19 pandemic and other public health crises may also have the effect of heightening many of the other risks described in the risk factors below.
Ongoing uncertainty surrounding the COVID-19 pandemic, including its duration and lingering impacts to the economy, as well as uncertainty surrounding future production decisions by the Organization of Petroleum Exporting Countries and other oil-producing nations (OPEC+), have caused and may continue to cause volatility and could have a significant impact on management’s estimates and assumptions for 2022 and beyond. The extent of the impacts of any of these factors on our business, financial condition, results of operations and cash flows will depend on future developments that are highly uncertain and cannot be accurately predicted, such as: the duration and severity of the COVID-19 pandemic or other public health crises
and any lingering effect on the economy; uncertainty surrounding future production decisions by OPEC+; 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, renewable fuels and anhydrous ammonia; demand for our transportation and storage services; the availability and costs of personnel, equipment, supplies and services essential to our operations; the ability to obtain timely permitting approvals; and changes in laws and regulations affecting our business.
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 ongoing 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 has 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 existing contracts 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, in light of the ongoing 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, 2021, our consolidated debt was $3.2 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, B and C preferred units. At December 31, 2021, we had approximately $3.2 billion of consolidated debt, of which $2.6 billion was at fixed interest rates and $0.6 billion was at variable interest rates. In addition, the distribution rates on our Series A preferred units converted from a fixed rate to a floating rate in December 2021, with our Series B and C preferred units scheduled to convert to a floating rate in 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.
Furthermore, although we have positioned ourselves to self-fund all of our expenses, distribution requirements and capital expenditures for 2022 using internally generated cash flows, we have historically funded our strategic capital expenditures and any acquisitions 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 COVID-19 precautions, many of our employees and those of our service providers, vendors and customers have been working, and some may continue 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 other countries in which we operate 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 direct or indirect effect on our business. Specifically, certain regulatory changes have and future changes could restrict our ability to expand our operations and 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 the other countries in which we operate, 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 Canada and northern Mexico. Our operations in both locations are subject to various risks unique to each country in which we operate that could have a material adverse effect on our business, results of operations and financial condition. With respect to any particular country, these risks may include political and economic instability, including: civil unrest; labor strikes; war and other armed conflict; inflation; and currency
fluctuations, devaluation and conversion restrictions. Any deterioration of social, political, labor or economic conditions, including the increasing threat of terrorist organizations and drug cartels, in a country or region in which we do business, 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. Subsequent 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, 2021, our power costs equaled approximately $46.4 million, or 12% 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.
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. Accordingly, the transition away from the widespread use of LIBOR to alternative rates has begun and is expected to continue over the next couple of years. Further, there is no assurance that LIBOR, or any particular currency and tenor, will continue to be published until any particular date.
Following the amendment and restatement of our revolving credit agreement and the amendment of our accounts receivable securitization program on January 28, 2022, 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 preferred units converted from a fixed rate to a floating rate based on LIBOR in December 2021, with our Series B and C preferred units scheduled to convert to a floating rate based on LIBOR in June 2022 and December 2022, respectively. Although our variable rate indebtedness and Series A, B and 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, B and C 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 the calculation agent for the Series C preferred units, and we may not be able to do so on terms favorable to us. The consequences of the transition away from LIBOR cannot be entirely predicted but could include an increase in the cost of our variable-rate indebtedness, our Series A, B and C preferred units and other commercial arrangements tied to LIBOR. Furthermore, uncertainty regarding the continued use and reliability of LIBOR as a benchmark rate and uncertainty regarding its replacement could disrupt the financial markets or adversely affect the value of our arrangements tied to LIBOR.
An impairment of goodwill or long-lived assets could reduce our earnings.
As of December 31, 2021, we had $0.7 billion of goodwill and $4.1 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. For example, in October 2021, we sold our Eastern U.S. Terminal Operations, and in the third quarter of 2021, we recorded long-lived asset and goodwill impairment charges related to the sale of $95.7 million and $34.1 million, respectively. We also recorded a long-lived asset impairment charge of $59.2 million during the third quarter of 2021 related to a section of a refined products pipeline that would require significant investment in order to pursue commercial opportunities.
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 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 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.
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. The Treasury regulations further provide that withholding on a transfer of an interest in a publicly traded partnership will not be imposed on a transfer that occurs prior to January 1, 2022, and after that date, if effected through a broker, the obligation to withhold is imposed on the transferor’s broker. 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 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.
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
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 normal business operations, including regulatory and environmental matters. Due to the inherent uncertainty of litigation, there can be no assurance that the resolution of any particular claim or proceeding would not have a material adverse effect on our results of operations, financial position or liquidity.
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 from our business activity.
ITEM 4. MINE SAFETY DISCLOSURES
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, 2022, we had 370 holders of record of our common units. The following table presents the amount, record date and payment date of the quarterly cash distributions on our common units with respect to 2021 and 2020:
| ||Cash Distributions|
| ||Amount Per|
|Record Date||Payment Date|
|4th Quarter||$||0.40 ||February 8, 2022||February 14, 2022|
|3rd Quarter||$||0.40 ||November 8, 2021||November 12, 2021|
|2nd Quarter||$||0.40 ||August 6, 2021||August 12, 2021|
|1st Quarter||$||0.40 ||May 10, 2021||May 14, 2021|
|4th Quarter||$||0.40 ||February 8, 2021||February 12, 2021|
|3rd Quarter||$||0.40 ||November 6, 2020||November 13, 2020|
|2nd Quarter||$||0.40 ||August 7, 2020||August 13, 2020|
|1st Quarter||$||0.40 ||May 11, 2020||May 15, 2020|
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. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for further information regarding our distributions.
Preferred Unit Distributions
The following table provides the terms related to distributions for our Series A, B and C Preferred Units:
|Units||Fixed Distribution Rate Per Annum (as a Percentage of the $25.00 Liquidation Preference Per Unit)||Fixed Distribution Rate Per Unit Per Annum||Fixed Distribution Per Annum||Optional Redemption Date/Date at Which Distribution Rate Becomes Floating||Floating Annual Rate (as a Percentage of the |
Preference Per Unit)
|(Thousands of Dollars)|
|Series A Preferred Units||8.50%||$||2.125 ||$||19,252 ||December 15, 2021||Three-month LIBOR plus 6.766%|
|Series B Preferred Units||7.625%||$||1.90625 ||$||29,357 ||June 15, 2022||Three-month LIBOR plus 5.643%|
|Series C Preferred Units||9.00%||$||2.25 ||$||15,525 ||December 15, 2022||Three-month LIBOR plus 6.88%|
The Series A Preferred Units switched from a fixed distribution rate to a floating rate on December 15, 2021, with the floating rate set forth below for the period indicated:
|Period||Distribution Rate per Unit||Total Distribution|
|(Thousands of Dollars)|
|December 15, 2021 - March 14, 2022||$||0.43606 ||$||3,951 |
The distribution rates on our 23,246,650 Series D Preferred Units issued and outstanding are as follows: (i) 9.75%, or $57.6 million, per annum ($0.619 per unit per distribution period) for the first two years (beginning with the September 17, 2018 distribution); (ii) 10.75%, or $63.4 million, per annum ($0.682 per unit per distribution period) for years three through five; and (iii) the greater of 13.75%, or $81.1 million, per annum ($0.872 per unit per distribution period) or the distribution per common unit thereafter.
Distributions on our 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 equal to each other and senior to all of our other classes of equity securities with respect to distribution rights and rights upon liquidation. 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 distributions to our preferred unitholders.
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, 2016, and its relative performance is tracked through December 31, 2021.
*$100 invested on December 31, 2016 in stock or index, including reinvestment of dividends.
|As of December 31,|
|NuStar Energy L.P.||100.00 ||66.73 ||51.96 ||70.16 ||44.05 ||53.53 |
|S&P 500 Index||100.00 ||121.83 ||116.49 ||153.17 ||181.35 ||233.41 |
|Alerian MLP Index||100.00 ||93.48 ||81.87 ||87.24 ||62.21 ||87.20 |
Sales of Unregistered Securities
During the fourth quarters of 2021, 2020 and 2019 and the first quarter of 2020, NuStar Energy issued an aggregate of 5,509 common units, 11,384 common units, 14,896 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.
During the fourth quarter of 2019, NuStar Energy issued 527,426 common units at a price of $28.44 per unit to William E. Greehey, Chairman of the Board of Directors of NuStar GP, LLC, in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof. We used the proceeds of $15.0 million from the sale of these units for general partnership purposes.
ITEM 6. RESERVED
ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We manage our exposure to changing interest rates principally through the use of a combination of fixed-rate debt and variable-rate debt. 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 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for more information.
On November 1, 2021, we repaid our $250.0 million of 4.75% senior notes due February 1, 2022. The following tables present principal cash flows and related weighted-average interest rates by expected maturity dates for our long-term debt, excluding finance leases: