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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2021

OR

☐ 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)

Delaware	74-2956831
(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	þ	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.

Table of Contents

NUSTAR ENERGY L.P.

FORM 10-K

TABLE OF CONTENTS

PART I
Items 1., 2. & 7	Business, Properties and Management's Discussion and Analysis of Financial Condition and Results of Operations	3
	Overview	3
	Recent Developments	5
	Trends and Outlook	6
	Consolidated Results of Operations	7
	Segments and Results of Operations	8
	Liquidity and Capital Resources	18
	Human Capital	27
	Properties	28
	Rate Regulation	28
	Environmental, Health, Safety and Security Regulation	29
	Critical Accounting Policies	31
	New Accounting Pronouncements	33
	Available Information	33
Item 1A.	Risk Factors	33
Item 1B.	Unresolved Staff Comments	47
Item 3.	Legal Proceedings	47
Item 4.	Mine Safety Disclosures	47
PART II
Item 5.	Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities	48
Item 6.	Reserved	51
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	51
Item 8.	Financial Statements and Supplementary Data	52
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	103
Item 9A.	Controls and Procedures	103
Item 9B.	Other Information	103
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	103
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	104
Item 11.	Executive Compensation	104
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	104
Item 13.	Certain Relationships and Related Transactions and Director Independence	104
Item 14.	Principal Accountant Fees and Services	104
PART IV
Item 15.	Exhibits and Financial Statement Schedules	105
Item 16.	Form 10-K Summary	111
Signatures		112

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PART I

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

OVERVIEW

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.

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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:

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RECENT DEVELOPMENTS

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.

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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.

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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,
	2021		2020		Change
	(Thousands of Dollars, Except Per Unit Data)
Statement of Income Data:
Revenues:
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

Overview

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).

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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.

Corporate Items

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

PIPELINE SEGMENT

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).

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The following table lists information about our pipeline assets:

	As of December 31, 2021			Throughput For the year ended December 31,
Region / Pipeline System	Length	Terminals	Tank Capacity	2021	2020
	(Miles)		(Barrels)	(Barrels/Day)
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

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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.

Pipeline Operations

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.

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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.

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Customers

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,
	2021		2020		Change
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

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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.

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STORAGE SEGMENT

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:

Facility	Tank Capacity
	(Barrels)
Colorado Springs, CO	327,000
Denver, CO	110,000
Albuquerque, NM	250,000
Rosario, NM	167,000
Catoosa, OK	359,000
Abernathy, TX	161,000
Amarillo, TX	269,000
Corpus Christi, TX	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
Total	44,207,000

(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.

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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.

Storage Operations

We generate storage segment revenues through fees for tank storage agreements, under which a customer agrees to pay for a certain amount of storage in a tank over a period of time (storage terminal revenues), and throughput agreements, under which a customer pays a fee per barrel for volumes moved through our terminals (throughput terminal revenues). Our terminals also provide blending, additive injections, handling and filtering services for which we charge additional fees. 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.

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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.

Customers

We provide storage and terminalling services for crude oil, refined products and other products to many of the world’s largest producers of crude oil, integrated oil companies, chemical companies, oil traders and refiners. In addition, our blending capabilities in our storage assets have attracted customers who have leased capacity primarily for blending purposes. 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.

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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,
	2021		2020		Change
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.

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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,
	2021		2020		Change
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

OVERVIEW

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.

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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,
	2021		2020
	(Thousands of Dollars)
Net cash provided by (used in):
Operating activities	$	501,478	$	525,998
Investing activities	75,978		(98,084)
Financing activities	(725,579)		(291,384)
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.

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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
Ratings	BB-	Ba3	BB-
Outlook	Stable	Stable	Stable

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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.

Term Loan

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.

Asset Sales

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

Capital Expenditures

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

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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.

Distributions

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)
Quarter ended:
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.

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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 $25.00 Liquidation 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.

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Debt Obligations

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:

Series	Date Issued	Amount Outstanding		Interest Rate		Mandatory Purchase Date	Maturity Date
		(Thousands of Dollars)
Series 2008	June 26, 2008	$	55,440	6.10	%	June 1, 2030	June 1, 2038
Series 2010	July 15, 2010	100,000		6.35	%	n/a	July 1, 2040
Series 2010A	October 7, 2010	43,300		6.35	%	n/a	October 1, 2040
Series 2010B	December 29, 2010	48,400		6.10	%	June 1, 2030	December 1, 2040
Series 2011	August 9, 2011	75,000		5.85	%	June 1, 2025	August 1, 2041
	Total	$	322,140

We believe that, as of December 31, 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

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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:
Revenues	$	837,493
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.

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Contractual Obligations

The following table presents our contractual obligations and commitments as of December 31, 2021:

	Current		Long-Term
	(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.

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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.

Contingencies

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.”

HUMAN CAPITAL

We strive to make NuStar a safe, positive, inclusive and rewarding workplace, with competitive compensation, benefits and health and wellness programs and opportunities for our employees to grow and develop in their careers.

Our Employees

As of December 31, 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.

Safety

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

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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.

Sustainability Report

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.

PROPERTIES

Our principal properties are described above under the caption “Segments and Results of Operations” above, and that information is incorporated herein by reference. We believe that we have satisfactory title to all of our properties. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, liens for current taxes and other burdens and easements, and restrictions or other encumbrances, including those related to environmental liabilities associated with historical operations, to which the underlying properties were subject at the time of acquisition by us or our predecessors, we believe that none of these burdens will materially detract from the value of these properties or from our interest in these properties or will materially interfere with their use in the operation of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this report. We perform scheduled maintenance on all of our pipelines, terminals, crude oil tanks and related equipment and make repairs and replacements when necessary or appropriate. We believe that our pipelines, terminals, crude oil tanks and related equipment have been constructed and are maintained in all material respects in accordance with applicable federal, state and local laws and the regulations and standards prescribed by the American Petroleum Institute, the DOT and accepted industry practice.

RATE REGULATION

Several of our crude oil and refined products pipelines are interstate common carrier pipelines, which are subject to regulation by the FERC under the Interstate Commerce Act (ICA) and the Energy Policy Act of 1992 (the EP Act). The ICA and its implementing regulations give the FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate liquids pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates a common carrier pipeline charges for providing transportation services on its interstate common carrier liquids pipelines, as well as the rules and regulations governing these services, to be maintained on file with the FERC and posted publicly. The EP Act deemed certain rates in effect prior to its passage to be just and reasonable and limited the circumstances under which a complaint can be made against such “grandfathered” rates. The EP Act and its implementing regulations also allow interstate common carrier liquids pipelines to annually index their rates up to a prescribed ceiling level and 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

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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

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blending. Other legislative changes in the future may similarly alter the expected demand and supply projections for refined products in ways that cannot be predicted.

Hazardous Substances and Hazardous Waste

The Federal Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA or “Superfund,” and analogous or more stringent international, state and local laws and regulations, impose restrictions and liability related to the release, threatened release, disposal and remediation of hazardous substances. This liability can be joint and several strict liability, without regard to fault or the legality of the original release or disposal. Current operators of a facility, past owners or operators of a facility and parties who arranged for the disposal of a hazardous substance can be held liable under these laws and regulations.

We currently own, lease, and operate on, and have in the past owned, leased and operated on, properties and at facilities that handled, transported and stored hazardous substances. Despite our compliance with applicable requirements and industry standards, hazardous substances may have been released on or under our facilities and properties, or on or under locations where these substances were taken for disposal. We are currently remediating subsurface contamination at several facilities, and, based on currently available information, we believe the costs related to these remedial activities should not materially affect our financial condition or results of operations. However, the aggregate total cost of remediation projects can be difficult to estimate, and there are no assurances that the cost of future remedial activities will not become material. Further, applicable laws or regulation, including those dictating the degree of remediation required, may be revised to be more restrictive in the future. As a result, we are unable to estimate the effect of future regulation on our financial condition or results of operations or the amount and timing of future expenditures required to comply with such possible regulatory changes.

The Federal Resource Conservation and Recovery Act, as amended, and analogous or more stringent international, state and local laws and regulations impose restrictions and strict controls regarding the handling and disposal of wastes, including hazardous wastes. We generate hazardous wastes and it is possible that additional wastes, which could include wastes currently generated during operations, will be designated as hazardous wastes in the future. Hazardous wastes are subject to more rigorous requirements than are non-hazardous wastes.

Air

The Federal Clean Air Act, as amended, and various applicable international, state and local laws and regulations impose restrictions and strict controls regarding emission into the air, including greenhouse gas emissions. These laws and regulations generally require permits issued by applicable federal, state or local authorities for emissions, and impose monitoring and reporting requirements. Such laws and regulations can also require pre-approval for the construction or modification of certain operations or facilities expected to produce or increase air emissions.

Water

The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, the federal Spill Prevention, Control, and Countermeasure and Facility Response Plan Rules and analogous or more stringent international, state and local laws and regulations impose restrictions and strict controls regarding the discharge of pollutants into state waters or waters of the United States. The discharge of pollutants into waters is generally prohibited, except in accordance with a permit issued by applicable federal or state authorities. The Oil Pollution Act further regulates the discharge of oil, and the response to and liability for oil spills, and the Rivers and Harbors Act regulates pipelines crossing navigable waters.

Pipeline and Other Asset Integrity, Safety and Security

Our pipeline, storage tank and other operations are subject to extensive international, federal, state and local laws and regulations governing integrity, safety and security, including those in Title 49 of the U.S. Code and its implementing regulations. These laws and regulations include the Pipeline and Hazardous Materials Safety Administration’s requirements for safe pipeline design, construction, operation, maintenance, inspection, testing and corrosion control, control rooms and qualification programs for operating personnel. In addition, we have 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

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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

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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):

	Pension Benefits		Other Postretirement Benefits
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 resulting from:
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 Liabilities

Environmental remediation costs are expensed and an associated accrual is established when site restoration and environmental remediation and cleanup obligations are either known or considered probable and can be reasonably estimated. These environmental obligations are based on estimates of probable undiscounted future costs using currently available technology and applying current regulations, as well as our own internal environmental policies. The environmental liabilities have not been reduced by possible recoveries from third parties. Environmental costs include initial site surveys, costs for remediation and restoration and ongoing monitoring costs, as well as fines, damages and other costs, when estimable. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. Environmental liabilities are difficult to assess and estimate due to unknown factors, such as the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. We believe that we have

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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.

Contingencies

We accrue for costs relating to litigation, claims and other contingent matters when such liabilities become probable and reasonably estimable. Such estimates may be based on advice from third parties or on management’s judgment, as appropriate. Due to the inherent uncertainty of litigation, actual amounts paid may differ from amounts estimated, and such differences will be charged to income in the period when final determination is made. 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.

AVAILABLE INFORMATION

Our internet website address is www.nustarenergy.com. Information contained on our website is not part of this report. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and any amendments thereto, filed with (or furnished to) the SEC are available on our website, free of charge, as soon as reasonably practicable after we file or furnish such material (select the “Investors” link, then the “SEC Filings” link). We also post our corporate governance guidelines, code of business conduct and ethics, code of ethics for senior financial officers and the charters of our board’s committees on our website free of charge (select the “Investors” link, then the “Corporate Governance” link).

Our governance documents are available in print to any unitholder that makes a written request to Corporate Secretary, NuStar Energy L.P., 19003 IH-10 West, San Antonio, Texas 78257 or corporatesecretary@nustarenergy.com.

ITEM 1A.    RISK FACTORS

RISKS RELATED TO OUR BUSINESS

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

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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;

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•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

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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.

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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.

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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

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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.

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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

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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.

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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.

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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.

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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

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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.

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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,

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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

None.

ITEM 3.    LEGAL PROCEEDINGS

We are named as a defendant in litigation and are a party to other claims and legal proceedings relating to our 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

Not applicable.

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PART II

ITEM 5.    MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Common Unit Distributions

Our common units are listed and traded on the New York Stock Exchange under the symbol “NS.” At the close of business on February 8, 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 Common Unit		Record Date	Payment Date
Year 2021
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
Year 2020
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 $25.00 Liquidation 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.

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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.

Performance Graph

The following Performance Graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference into any of NuStar Energy’s filings under the Securities Act of 1933 or the Securities Exchange Act of 1934, as amended, respectively. The stock or unit price performance included in this graph is not necessarily indicative of future stock or unit price performance.

The following graph compares the cumulative five-year total return provided to holders of NuStar Energy’s common units relative to the cumulative total returns of the S&P 500 index and the Alerian MLP index. An investment of $100 (with reinvestment of all dividends) is assumed to have been made in our common units and in each of the indexes on December 31, 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,
	2016	2017	2018	2019	2020	2021
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

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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.

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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:

	December 31, 2021
	Expected Maturity Dates
	2022		2023			2024		2025			2026			There- after			Total			Fair Value
	(Thousands of Dollars, Except Interest Rates)
Fixed-rate debt	$	—	$	—		$	—	$	600,000		$	500,000		$	1,472,140		$	2,572,140		$	2,858,794
Weighted-average rate	—		—			—		5.8		%	6.0		%	6.0		%	6.0		%	—
Variable-rate debt	$	—	$	194,300		$	—	$	—		$	—		$	402,500		$	596,800		$	600,359
Weighted-average rate	—		2.5		%	—		—			—			6.9		%	5.4		%	—

	December 31, 2020
	Expected Maturity Dates
	2021			2022			2023			2024		2025			There- after			Total			Fair Value
	(Thousands of Dollars, Except Interest Rates)
Fixed-rate debt	$	300,000		$	250,000		$	—		$	—	$	600,000		$	1,972,140		$	3,122,140		$	3,396,542
Weighted-average rate	6.8		%	4.8		%	—			—		5.8		%	6.0		%	5.9		%	—
Variable-rate debt	$	—		$	—		$	57,000		$	—	$	—		$	402,500		$	459,500		$	402,836
Weighted-average rate	—			—			2.3		%	—		—			7.0		%	6.4		%	—

We utilized forward-starting interest rate swap agreements to lock in the rate on the interest payments related to forecasted debt issuances. Please refer to Notes 2 and 16 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a more detailed discussion of our interest rate swaps.

Since the operations of our fuels marketing segment expose us to commodity price risk, we also use derivative instruments to attempt to mitigate the effects of commodity price fluctuations. Derivative financial instruments associated with commodity price risk were not material for any periods presented.

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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining effective internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934. Our management assessed the effectiveness of NuStar Energy L.P.’s internal control over financial reporting as of December 31, 2021. In its evaluation, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (2013). Based on this assessment, management believes that, as of December 31, 2021, our internal control over financial reporting was effective based on those criteria.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

The effectiveness of internal control over financial reporting as of December 31, 2021 has been audited by KPMG LLP, the independent registered public accounting firm who audited our consolidated financial statements included in this Form 10-K. KPMG LLP’s attestation on the effectiveness of our internal control over financial reporting appears on page 56.

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Report of Independent Registered Public Accounting Firm

To the Board of Directors of NuStar GP, LLC

and Unitholders of NuStar Energy L.P.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of NuStar Energy L.P. and subsidiaries (the Partnership) as of December 31, 2021 and 2020, the related consolidated statements of income (loss), comprehensive income (loss), cash flows, and partners’ equity and mezzanine equity for each of the years in the three-year period ended December 31, 2021, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 24, 2022 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Identification of triggering events related to the recoverability of certain long-lived assets or asset groups

As discussed in Note 2, the Partnership tests long-lived assets, including property, plant, and equipment, for impairment whenever events or changes in circumstances (triggering events) indicate that the carrying amount may not be recoverable. The Partnership evaluates recoverability using undiscounted estimated net cash flows generated by the related asset or asset group considering the intended use of the asset. The balance of property, plant, and equipment, net as of December 31, 2021 was $3,541.6 million, or 68.7% of total assets, of which certain assets or asset groups were not supported by existing revenue generating contacts or have not historically had consistent revenue generating activities.

We identified the assessment of the identification of triggering events related to the recoverability of certain long-lived assets or asset groups as a critical audit matter. Challenging auditor judgment was required to assess the identification of triggering events for certain long-lived assets or asset groups that were not supported by existing revenue generating contracts or have not historically had consistent revenue generating activities. Specifically, this assessment included the evaluation of subjective qualitative considerations, such as alternative customers and alternative uses for the asset or asset group, and the Partnership’s intent for the asset or asset group.

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The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Partnership’s triggering event assessment. This included controls over the identification of long-lived asset groups that would be at greater risk for a triggering event and evaluation of the qualitative considerations in assessing the identification of a triggering event. We examined the Partnership’s analysis of the long-lived assets and asset groups identified to be evaluated for a potential triggering event and assessed the factors considered in determining the identification of a triggering event. Specifically, we evaluated the Partnership’s assessment of the factors considered, including alternative customers, alternative uses for the assets or asset group, and the Partnership’s intent for the assets or asset group by evaluating internal and external documentation. Documentation evaluated included internal presentations, draft customer contracts, publicly available market data, and communications between the Partnership and potential customers.

We have served as the Partnership’s auditor since 2004.

/s/ KPMG LLP

San Antonio, Texas

February 24, 2022

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Report of Independent Registered Public Accounting Firm

The Board of Directors of NuStar GP, LLC

and Unitholders of NuStar Energy L.P.:

Opinion on Internal Control Over Financial Reporting

We have audited NuStar Energy L.P. and subsidiaries' (the Partnership) internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Partnership as of December 31, 2021 and 2020, the related consolidated statements of income (loss), comprehensive income (loss), cash flows, and partners’ equity and mezzanine equity for each of the years in the three-year period ended December 31, 2021, and the related notes (collectively, the consolidated financial statements), and our report dated February 24, 2022 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ KPMG LLP

San Antonio, Texas

February 24, 2022

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of Dollars, Except Unit Data)

	December 31,
	2021		2020
Assets
Current assets:
Cash and cash equivalents	$	5,637	$	153,625
Accounts receivable	135,126		133,473
Inventories	16,644		11,059
Prepaid and other current assets	27,135		25,400
Total current assets	184,542		323,557
Property, plant and equipment, at cost	5,728,848		6,164,742
Accumulated depreciation and amortization	(2,187,206)		(2,207,230)
Property, plant and equipment, net	3,541,642		3,957,512
Intangible assets, net	557,785		630,209
Goodwill	732,356		766,416
Other long-term assets, net	140,007		139,324
Total assets	$	5,156,332	$	5,817,018
Liabilities, Mezzanine Equity and Partners’ Equity
Current liabilities:
Accounts payable	$	82,446	$	71,731
Current portion of finance lease obligations	3,848		3,839
Accrued interest payable	34,139		50,847
Accrued liabilities	79,818		77,770
Taxes other than income tax	14,475		16,998
Total current liabilities	214,726		221,185
Long-term debt, less current portion	3,183,555		3,593,496
Deferred income tax liability	11,831		13,011
Other long-term liabilities	147,956		157,825
Total liabilities	3,558,068		3,985,517
Commitments and contingencies (Note 14)
Series D preferred limited partners (23,246,650 units outstanding as of December 31, 2021 and 2020) (Note 17)	616,439		599,542
Partners’ equity (Note 18):
Preferred limited partners:
Series A (9,060,000 units outstanding as of December 31, 2021 and 2020)	218,307		218,307
Series B (15,400,000 units outstanding as of December 31, 2021 and 2020)	371,476		371,476
Series C (6,900,000 units outstanding as of December 31, 2021 and 2020)	166,518		166,518
Common limited partners (109,986,273 and 109,468,127 common units outstanding as of December 31, 2021 and 2020, respectively)	299,502		572,314
Accumulated other comprehensive loss	(73,978)		(96,656)
Total partners’ equity	981,825		1,231,959
Total liabilities, mezzanine equity and partners’ equity	$	5,156,332	$	5,817,018

See Notes to Consolidated Financial Statements.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

(Thousands of Dollars, Except Unit and Per Unit Data)

	Year Ended December 31,
	2021		2020		2019
Revenues:
Service revenues	$	1,157,410	$	1,205,494	$	1,148,167
Product sales	461,090		276,070		349,854
Total revenues	1,618,500		1,481,564		1,498,021
Costs and expenses:
Costs associated with service revenues:
Operating expenses (excluding depreciation and amortization expense)	388,078		403,579		404,682
Depreciation and amortization expense	266,588		276,476		264,564
Total costs associated with service revenues	654,666		680,055		669,246
Cost associated with product sales	417,413		256,066		321,644
Asset impairment losses	154,908		—		—
Goodwill impairment losses	34,060		225,000		—
General and administrative expenses (excluding depreciation and amortization expense)	113,207		102,716		107,855
Other depreciation and amortization expense	7,792		8,625		8,360
Total costs and expenses	1,382,046		1,272,462		1,107,105
Operating income	236,454		209,102		390,916
Interest expense, net	(213,985)		(229,054)		(183,070)
Loss on extinguishment of debt	—		(141,746)		—
Other income (expense), net	19,644		(34,622)		3,742
Income (loss) from continuing operations before income tax expense	42,113		(196,320)		211,588
Income tax expense	3,888		2,663		4,754
Income (loss) from continuing operations	38,225		(198,983)		206,834
Loss from discontinued operations, net of tax	—		—		(312,527)
Net income (loss)	$	38,225	$	(198,983)	$	(105,693)
Basic and diluted net (loss) income per common unit:
Continuing operations	$	(0.99)	$	(3.15)	$	0.60
Discontinued operations	—		—		(2.90)
Total (Note 19)	$	(0.99)	$	(3.15)	$	(2.30)
Basic weighted-average common units outstanding	109,585,635		109,155,117		107,789,030
Diluted weighted-average common units outstanding	109,585,635		109,155,117		107,854,699

See Notes to Consolidated Financial Statements.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Thousands of Dollars)

	Year Ended December 31,
	2021		2020		2019
Net income (loss)	$	38,225	$	(198,983)	$	(105,693)
Other comprehensive income (loss):
Foreign currency translation adjustment	601		1,410		3,527
Net gain (loss) on pension and other postretirement benefit adjustments, net of income tax (expense) benefit of ($61), $28 and $14	16,413		(4,144)		(1,314)
Change in unrealized loss on cash flow hedges	—		(30,291)		(19,045)
Reclassification of loss on cash flow hedges to interest expense, net	5,664		4,265		3,814
Total other comprehensive income (loss)	22,678		(28,760)		(13,018)
Comprehensive income (loss)	$	60,903	$	(227,743)	$	(118,711)

See Notes to Consolidated Financial Statements.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of Dollars)

	Year Ended December 31,
	2021		2020		2019
Cash Flows from Operating Activities:
Net income (loss)	$	38,225	$	(198,983)	$	(105,693)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization expense	274,380		285,101		281,460
Amortization of unit-based compensation	14,209		11,477		14,386
Amortization of debt related items	12,490		11,463		5,209
(Gain) loss from sale or disposition of assets	(61)		38,084		3,499
Gain from insurance recoveries	(14,860)		—		—
Asset and goodwill impairment losses	188,968		225,000		336,838
Loss on extinguishment of debt	—		141,746		—
Deferred income tax (benefit) expense	(1,369)		212		(476)
Changes in current assets and current liabilities (Note 20)	(14,147)		11,928		(44,765)
Decrease (increase) in other long-term assets	9,867		(8,101)		22,020
(Decrease) increase in other long-term liabilities	(6,636)		7,920		(1,407)
Other, net	412		151		(2,314)
Net cash provided by operating activities	501,478		525,998		508,757
Cash Flows from Investing Activities:
Capital expenditures	(181,133)		(198,079)		(533,568)
Change in accounts payable related to capital expenditures	1,264		(10,645)		(12,731)
Proceeds from insurance recoveries	9,372		—		—
Proceeds from sale or disposition of assets	246,475		110,640		228,152
Other, net	—		—		(1,100)
Net cash provided by (used in) investing activities	75,978		(98,084)		(319,247)
Cash Flows from Financing Activities:
Proceeds from Term Loan, net of discount and issuance costs	—		463,045		—
Proceeds from note offerings, net of issuance costs	—		1,182,035		491,580
Proceeds from other long-term debt borrowings	977,000		883,748		659,300
Proceeds from short-term debt borrowings	—		52,000		307,500
Term Loan repayment, including debt extinguishment costs	—		(601,316)		—
Other long-term debt repayments	(1,389,700)		(1,813,963)		(928,900)
Short-term debt repayments	—		(57,500)		(320,500)
Proceeds from issuance of common units	—		—		15,000
Distributions to preferred unitholders	(127,551)		(124,622)		(121,693)
Distributions to common unitholders	(175,263)		(196,203)		(258,354)
Payments for termination of interest rate swaps	—		(49,225)		—
Payment of tax withholding for unit-based compensation	(3,384)		(10,028)		(8,771)
Decrease in cash book overdrafts	(142)		(2,288)		(3,752)
Other, net	(6,539)		(17,067)		(9,060)
Net cash used in financing activities	(725,579)		(291,384)		(177,650)
Effect of foreign exchange rate changes on cash	136		916		(524)
Net (decrease) increase in cash, cash equivalents and restricted cash	(147,987)		137,446		11,336
Cash, cash equivalents and restricted cash as of the beginning of the period	162,426		24,980		13,644
Cash, cash equivalents and restricted cash as of the end of the period	$	14,439	$	162,426	$	24,980

See Notes to Consolidated Financial Statements.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY AND MEZZANINE EQUITY

(Thousands of Dollars, Except Per Unit Data)

	Limited Partners								Mezzanine Equity
	Preferred		Common		Accumulated Other Comprehensive Loss		Total Partners’ Equity (Note 18)		Series D Preferred Limited Partners (Note 17)		Total
Balance as of January 1, 2019	$	756,301	$	1,556,308	$	(54,878)	$	2,257,731	$	563,992	$	2,821,723
Net income (loss)	64,134		(227,386)		—		(163,252)		57,559		(105,693)
Other comprehensive loss	—		—		(13,018)		(13,018)		—		(13,018)
Distributions to partners:
Series A, B and C preferred	(64,134)		—		—		(64,134)		—		(64,134)
Common ($2.40 per unit)	—		(258,354)		—		(258,354)		—		(258,354)
Series D preferred	—		—		—		—		(57,559)		(57,559)
Issuance of common units	—		15,000		—		15,000		—		15,000
Unit-based compensation	—		20,766		—		20,766		—		20,766
Series D Preferred Unit accretion	—		(18,085)		—		(18,085)		18,085		—
Other	—		(444)		—		(444)		(142)		(586)
Balance as of December 31, 2019	756,301		1,087,805		(67,896)		1,776,210		581,935		2,358,145
Net income (loss)	64,134		(323,865)		—		(259,731)		60,748		(198,983)
Other comprehensive loss	—		—		(28,760)		(28,760)		—		(28,760)
Distributions to partners:
Series A, B and C preferred	(64,134)		—		—		(64,134)		—		(64,134)
Common ($1.80 per unit)	—		(196,203)		—		(196,203)		—		(196,203)
Series D preferred	—		—		—		—		(60,748)		(60,748)
Unit-based compensation	—		22,219		—		22,219		—		22,219
Series D Preferred Unit accretion	—		(17,626)		—		(17,626)		17,626		—
Other	—		(16)		—		(16)		(19)		(35)
Balance as of December 31, 2020	756,301		572,314		(96,656)		1,231,959		599,542		1,831,501
Net income (loss)	63,982		(89,174)		—		(25,192)		63,417		38,225
Other comprehensive income	—		—		22,678		22,678		—		22,678
Distributions to partners:
Series A, B and C preferred	(63,982)		—		—		(63,982)		—		(63,982)
Common ($1.60 per unit)	—		(175,263)		—		(175,263)		—		(175,263)
Series D preferred	—		—		—		—		(63,417)		(63,417)
Unit-based compensation	—		8,528		—		8,528		—		8,528
Series D Preferred Unit accretion	—		(16,903)		—		(16,903)		16,903		—
Other	—		—		—		—		(6)		(6)
Balance as of December 31, 2021	$	756,301	$	299,502	$	(73,978)	$	981,825	$	616,439	$	1,598,264

See Notes to Consolidated Financial Statements.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2021, 2020 and 2019

1. ORGANIZATION AND OPERATIONS

Organization

NuStar Energy L.P. (NYSE: NS) is a Delaware limited partnership primarily engaged in the transportation, terminalling and storage of petroleum products and renewable fuels and the transportation of anhydrous ammonia. Unless otherwise indicated, the terms “NuStar Energy,” “NS,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to NuStar Energy L.P., to one or more of our consolidated subsidiaries or to all of them taken as a whole. 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 indirectly wholly owned subsidiaries of ours.

Operations

We conduct our operations through our subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics) and NuStar Pipeline Operating Partnership L.P. (NuPOP). We have three business segments: pipeline, storage and fuels marketing.

Pipeline. We own 3,205 miles of refined product pipelines and 2,230 miles of crude oil pipelines, as well as 5.6 million barrels of crude oil storage capacity, which comprise our Central West System. In addition, we own 2,500 miles of refined product pipelines, consisting of the East and North Pipelines, and a 2,000-mile ammonia pipeline, which comprise our Central East System. The East and North Pipelines have storage capacity of 7.4 million barrels. We charge tariffs on a per barrel basis for transporting refined products, crude oil and other feedstocks in our refined product and crude oil pipelines and on a per ton basis for transporting anhydrous ammonia in the Ammonia Pipeline.

Storage. We own terminal and storage facilities in the United States, Canada and Mexico, with 44.2 million barrels of storage capacity. Our terminal and storage facilities provide storage, handling and other services on a fee basis for refined products, crude oil, specialty chemicals, renewable fuels and other liquids.

Fuels Marketing. 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.

Recent Developments

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. Please refer to Note 25 for more information.

Debt Amendments. On January 28, 2022, we amended and restated our $1.0 billion unsecured revolving credit agreement to extend the maturity to April 27, 2025, replace the LIBOR-based interest rate and modify other terms. Also on January 28, 2022, we amended our $100.0 million receivables financing agreement to extend the scheduled termination date to January 31, 2025, replace the LIBOR-based interest rate and modify other terms. Please refer to Note 12 for more information.

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). We recorded asset and goodwill impairment losses of $95.7 million and $34.1 million, respectively, in the third quarter of 2021. Please see Note 4 for further discussion.

Houston Pipeline Impairment. In the third quarter of 2021, we recorded a long-lived asset impairment charge of $59.2 million related to the southern section of our Houston refined product pipeline. Please see Note 4 for further discussion.

Senior Notes. 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. On February 1, 2021 we repaid our $300.0 million of 6.75% senior notes at maturity with borrowings under our Revolving Credit Agreement.

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Other Events

Selby Terminal Fire. On October 15, 2019, our terminal facility in Selby, California experienced a fire that destroyed two storage tanks and temporarily shut down the terminal. The property damage was isolated, and in the fourth quarter of 2019, we incurred losses of $5.4 million, which represent the aggregate amount of our deductibles under various insurance policies. We received insurance proceeds of $28.5 million and $35.0 million, for the years ended December 31, 2021 and 2020, respectively. Gains from business interruption insurance of $4.0 million, $6.7 million and $1.3 million for the years ended December 31, 2021, 2020 and 2019, respectively, are included in “Operating expenses” in the consolidated statements of income (loss). For the year ended December 31, 2021, we recorded a gain of $14.9 million for the amount by which the insurance recoveries exceeded our expenses incurred to date, which is included in “Other income (expense), net” in the consolidated statements of income (loss). Insurance proceeds related to cleanup costs and business interruption are included in “Cash flows from operating activities” in the consolidated statements of cash flows. In addition, we received $5.8 million of insurance proceeds in January 2022. We believe we have adequate insurance to offset additional costs.

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. We recorded a non-cash loss of $34.7 million and utilized the sales proceeds to improve our debt metrics. Please refer to Note 4 for further discussion.

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, as defined below, as well as outstanding borrowings under our revolving credit agreement. On September 1, 2020, we repaid our $450.0 million of 4.80% senior notes at maturity with borrowings under our revolving credit agreement. Please refer to Note 12 for further discussion.

Term Loan Credit 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). The Term Loan provided for an aggregate commitment of up to $750.0 million pursuant to a three-year unsecured term loan credit facility. On April 21, 2020 we drew $500.0 million, which we repaid on September 16, 2020. The repayment required certain contractual premiums, and we recognized a loss of $137.9 million in the third quarter of 2020. On February 16, 2021, we terminated the Term Loan. Please refer to Note 12 for further discussion about the Term Loan.

Sale of St. Eustatius Operations. On July 29, 2019, we sold our St. Eustatius terminal and bunkering operations (the St. Eustatius Operations) for net proceeds of approximately $230.0 million (the St. Eustatius Disposition). In 2019, we recorded long-lived asset and goodwill impairment charges totaling $336.8 million related to the St. Eustatius Operations in “Loss from discontinued operations, net of tax” on our consolidated statement of loss. In the second quarter of 2019, we determined the St. Eustatius Operations and the European operations, which we sold in 2018, met the requirements to be reported as discontinued operations, and as a result, we reclassified certain balances to assets held for sale and liabilities held for sale and certain revenues and expenses to discontinued operations for all applicable periods presented.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Consolidation

The accompanying consolidated financial statements represent the consolidated operations of the Partnership and our subsidiaries. Inter-partnership balances and transactions have been eliminated in consolidation. The operations of certain pipelines and terminals in which we own an undivided interest are proportionately consolidated in the accompanying consolidated financial statements.

Use of Estimates

The preparation of consolidated financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. On an ongoing basis, management reviews its estimates based on currently available information. Management may revise estimates due to changes in facts and circumstances.

Cash and Cash Equivalents

Cash equivalents are all highly liquid investments with an original maturity of three months or less when acquired.

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Accounts Receivable

Trade receivables are carried at amortized cost, net of a valuation allowance for current expected credit losses. We extend credit to certain customers after review of various credit indicators, including the customer’s credit rating, and obtain letters of credit, guarantees or collateral as deemed necessary. We monitor our ongoing credit exposure through active review of customer balances against contract terms and due dates and pool customer receivables based upon days outstanding, which is our primary credit risk indicator. Our review activities include timely account reconciliations, dispute resolution and payment confirmations.

Inventories

Inventories consist of petroleum products, materials and supplies. Inventories are valued at the lower of cost or net realizable value. Cost is determined using the weighted-average cost method. Our inventory, other than materials and supplies, consists of one end-product category, petroleum products, which we include in the fuels marketing segment. Accordingly, we determine lower of cost or net realizable value adjustments on an aggregate basis. Materials and supplies are valued at the lower of average cost or net realizable value.

Restricted Cash

As of December 31, 2021 and 2020, we have restricted cash representing legally restricted funds that are unavailable for general use totaling $8.8 million, which is included in “Other long-term assets, net” on the consolidated balance sheet.

Property, Plant and Equipment

We record additions to property, plant and equipment, including reliability and strategic capital expenditures, at cost. Repair and maintenance costs associated with existing assets that are minor in nature and do not extend the useful life of existing assets are charged to operating expenses as incurred. Depreciation of property, plant and equipment is recorded on a straight-line basis over the estimated useful lives of the related assets. When property or equipment is retired, sold or otherwise disposed of, the difference between the carrying value and the net proceeds is recognized in “Other income (expense), net” or “Loss from discontinued operations, net of tax” in the consolidated statements of income (loss) in the year of disposition. We capitalize overhead costs and interest costs incurred on funds used to construct property, plant and equipment while the asset is under construction. The overhead costs and capitalized interest are recorded as part of the asset to which they relate and are amortized over the asset’s estimated useful life as a component of depreciation expense.

Leases - Lessee

We lease assets used in our operations, including land, docks, and marine vessels. We record all leases on our consolidated balance sheet except for those leases with an initial term of 12 months or less, which are expensed on a straight-line basis over the lease term. We use judgment in determining the reasonably certain lease term and consider factors such as the nature and utility of the leased asset, as well as the importance of the leased asset to our operations. We calculate the present value of our lease liabilities based upon our incremental borrowing rate unless the rate implicit in the lease is readily determinable. For all of our asset classes except the other pipeline and terminal equipment asset class, we combine lease and non-lease components and account for them as a single lease component.

Certain of our leases are subject to variable payment arrangements, the most notable of which include:

•dockage and wharfage charges, which are based on volumes moved over leased docks and are included in our calculation of our lease payments based on minimum throughput volume requirements. We recognize charges on excess throughput volumes in profit or loss in the period in which the obligation for those payments is incurred; and

•consumer price index adjustments, which are measured and included in the calculation of our lease payments based on the consumer price index at the commencement date. We recognize changes in lease payments as a result of changes in the consumer price index in profit or loss in the period in which those payments are made.

See Note 15 for further discussion of our lessee arrangements.

Goodwill

We assess goodwill for impairment annually on October 1, or more frequently if events or changes in circumstances indicate it might be impaired. We have the option to first assess qualitative factors to determine whether it is necessary to perform a quantitative goodwill impairment test. We elected to bypass the qualitative assessment for all reporting units as of October 1, 2021 and October 1, 2020 and performed quantitative assessments, resulting in the determination that goodwill was not impaired.

We measure goodwill impairment as the excess of each reporting unit’s carrying value over its fair value, not to exceed the carrying amount of goodwill for that reporting unit. The carrying value of each reporting unit equals the total identified assets

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(including goodwill) less the sum of each reporting unit’s identified liabilities. We used reasonable and supportable methods to assign the assets and liabilities to the appropriate reporting units in a consistent manner.

As of December 31, 2021 and 2020, our reporting units to which goodwill has been allocated consisted of the following:

•crude oil pipelines;

•refined product pipelines; and

•terminals, excluding our Point Tupper facility and our refinery crude storage tanks.

Please see Notes 4 and 10 for a discussion of the balances of and changes in the carrying amount of goodwill.

We recognize an impairment of goodwill if the carrying value of a reporting unit that contains goodwill exceeds its estimated fair value. In order to estimate the fair value of the reporting unit, including goodwill, management must make certain estimates and assumptions that affect the total fair value of the reporting unit including, among other things, an assessment of market conditions, projected cash flows, discount rates and growth rates. Management’s estimates of projected cash flows related to the reporting unit include, but are not limited to, future earnings of the reporting unit, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and future expenditures necessary to maintain the asset’s existing service potential. We calculate the estimated fair value of each of our reporting units using a weighted-average of values calculated using an income approach and a market approach. The income approach involves estimating the fair value of each reporting unit by discounting its estimated future cash flows using a discount rate that would be consistent with a market participant’s assumption. The market approach bases the fair value measurement on information obtained from observed stock prices of public companies and recent merger and acquisition transaction data of comparable entities.

Management’s estimates are based on numerous assumptions about future operations and market conditions, which we believe to be reasonable but are inherently uncertain. The uncertainties underlying our assumptions and estimates could differ significantly from actual results, including with respect to the duration and severity of the COVID-19 pandemic, which could lead to a different determination of the fair value of our assets. We will continue to monitor the business and consider additional interim analysis of goodwill as appropriate.

Impairment of Long-Lived Assets

We review long-lived assets, including property, plant and equipment, for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. We evaluate recoverability using undiscounted estimated net cash flows generated by the related asset or asset group. If the results of that evaluation indicate that the undiscounted cash flows are less than the carrying amount of the asset (i.e., the asset is not recoverable) we perform an impairment analysis. If our intent is to hold the asset for continued use, we determine the amount of impairment as the amount by which the net carrying value exceeds its fair value. If our intent is to sell the asset, and the criteria required to classify an asset as held for sale are met, we determine the amount of impairment as the amount by which the net carrying amount exceeds its fair value less costs to sell. See Note 4 for a discussion of our long-lived asset impairment charges. We believe that the carrying amounts of our long-lived assets as of December 31, 2021 are recoverable.

Income Taxes

We are a limited partnership and generally are not subject to federal or state income taxes. Accordingly, our taxable income or loss, which may vary substantially from income or loss reported for financial reporting purposes, is generally included in the federal and state income tax returns of our partners. For transfers of publicly held common units subsequent to our initial public offering, we have made an election permitted by Section 754 of the Internal Revenue Code (the Code) to adjust the common unit purchaser’s tax basis in our underlying assets to reflect the purchase price of the units. This results in an allocation of taxable income and expenses to the purchaser of the common units, including depreciation deductions and gains and losses on sales of assets, based upon the new unitholder’s purchase price for the common units.

We conduct certain of our operations through taxable wholly owned corporate subsidiaries. We account for income taxes related to our taxable subsidiaries using the asset and liability method. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. We measure deferred taxes using enacted tax rates expected to apply to taxable income in the year those temporary differences are expected to be recovered or settled.

We recognize a tax position if it is more likely than not that the tax position will be sustained, based on the technical merits of the position, upon examination. We record uncertain tax positions in the financial statements at the largest amount of benefit that is more likely than not to be realized. We had no unrecognized tax benefits as of December 31, 2021 and 2020.

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NuStar Energy and certain of its subsidiaries file income tax returns in the U.S. federal jurisdiction and various state and foreign jurisdictions. For U.S. federal and state purposes, as well as for our major non-U.S. jurisdictions, tax years subject to examination are 2016 through 2020, according to standard statute of limitations.

Asset Retirement Obligations

We record a liability for asset retirement obligations at the fair value of the estimated costs to retire a tangible long-lived asset at the time we incur that liability, which is generally when the asset is purchased, constructed or leased, when we have a legal obligation to incur costs to retire the asset and when a reasonable estimate of the fair value of the obligation can be made. If a reasonable estimate cannot be made at the time the liability is incurred, we record the liability when sufficient information is available to estimate the fair value.

We have asset retirement obligations with respect to certain of our assets due to various legal obligations to clean and/or dispose of those assets at the time they are retired. However, these assets can be used for an extended and indeterminate period of time as long as they are properly maintained and/or upgraded. It is our practice and current intent to maintain our assets and continue making improvements to those assets based on technological advances. As a result, we believe that our assets have indeterminate lives for purposes of estimating asset retirement obligations because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of any asset, we estimate the costs of performing the retirement activities and record a liability for the fair value of these costs.

We also have legal obligations in the form of leases and right-of-way agreements, which require us to remove certain of our assets upon termination of the agreement. However, these lease or right-of-way agreements generally contain automatic renewal provisions that extend our rights indefinitely or we have other legal means available to extend our rights. Liabilities for conditional asset retirement obligations related to the retirement of terminal assets with lease and right-of-way agreements were not material as of December 31, 2021 and 2020.

Environmental Remediation Costs

Environmental remediation costs are expensed and an associated accrual established when site restoration and environmental remediation and cleanup obligations are either known or considered probable and can be reasonably estimated. These environmental obligations are based on estimates of probable undiscounted future costs using currently available technology and applying current regulations, as well as our own internal environmental policies. The environmental liabilities have not been reduced by possible recoveries from third parties. Environmental costs include initial site surveys, costs for remediation and restoration and ongoing monitoring costs, as well as fines, damages and other costs, when applicable and estimable. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods.

Revenue Recognition

Revenue-Generating Activities. Revenues for the pipeline segment are derived from interstate and intrastate pipeline transportation of refined products, crude oil and anhydrous ammonia and the applicable pipeline tariff on a per barrel basis for crude oil or refined products and on a per ton basis for ammonia. Revenues generated from product sales in the pipeline segment relate to surplus pipeline loss allowance volumes.

Revenues for the storage segment include fees for tank storage agreements, under which a customer agrees to pay for a certain amount of storage in a tank over a period of time (storage terminal revenues), and throughput agreements, under which a customer pays a fee per barrel for volumes moving through our terminals (throughput terminal revenues). Our terminals also provide blending, additive injections, handling and filtering services for which we charge additional fees. 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 (all of which are considered optional services). We are considered to be the lessor in certain revenue contracts. To the extent that a contract contains both lease and non-lease components, such as when we provide both storage capacity and optional services to a customers, we combine the lease and non-lease components and account for the transaction based on the predominant component.

Revenues for the fuels marketing segment are derived from the sale of petroleum products.

Within our pipeline and storage segments, we provide services on uninterruptible and interruptible bases. Uninterruptible services within our pipeline segment typically result from contracts that contain take-or-pay minimum volume commitments (MVCs) from the customer. Contracts with MVCs obligate the customer to pay for that minimum amount. If a customer fails to meet its MVC for the applicable service period, the customer is obligated to pay a deficiency fee based upon the shortfall

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between the actual volumes transported or stored and the MVC for that service period (deficiency payments). In exchange, those contracts with MVCs obligate us to stand ready to transport volumes up to the customer’s MVC.

Within our storage segment, uninterruptible services arise from contracts containing a fixed monthly fee for the portion of storage capacity reserved by the customer. These contracts require that the customer pay the fixed monthly fee, regardless of whether or not it uses our storage facility (i.e., take-or-pay obligation), and that we stand ready to store that volume. Interruptible services within our pipeline and storage segments are generally provided when and to the extent we determine the requested capacity is available. The customer typically pays a per-unit rate for the actual quantities of services it receives.

For the majority of our contracts, we recognize revenue in the amount to which we have a right to invoice. Generally, payment terms do not exceed 30 days.

Performance Obligations. The majority of our contracts contain a single performance obligation. For our pipeline segment, the single performance obligation encompasses multiple activities necessary to deliver our customers’ products to their destinations. Typically, we satisfy this performance obligation over time as the product volume is delivered in or out of the pipelines. Certain of our pipeline segment customer contracts include an incentive pricing structure, which provides a discounted rate for the remainder of the contract once the customer exceeds a cumulative volume. The ability to receive discounted future services represents a material right to the customer, which results in a second performance obligation in those contracts.

The performance obligation for our storage segment consists of multiple activities necessary to receive, store and deliver our customers’ products. We typically satisfy this performance obligation over time as the product volume is delivered in or out of the tanks (for throughput terminal revenues) or with the passage of time (for storage terminal revenues).

Product sales contracts generally include a single performance obligation to deliver specified volumes of a commodity, which we satisfy at a point in time, when the product is delivered and the customer obtains control of the commodity.

Optional services described in our contracts do not provide a material right to the customer, and are not considered a separate performance obligation in the contract. If and when a customer elects an optional service, and the terms of the contract are otherwise met, those services become part of the existing performance obligation.

Transaction Price. For uninterruptible services, we determine the transaction price at contract inception based on the guaranteed minimum amount of revenue over the term of the contract. For interruptible services and optional services, we determine the transaction price based on our right to invoice the customer for the value of services provided to the customer for the applicable period.

In certain instances, our customers reimburse us for capital projects, in arrangements referred to as contributions in aid of construction, or CIAC. Typically, in these instances, we receive upfront payments for future services, which are included in the transaction price of the underlying service contract.

We collect taxes on certain revenue transactions to be remitted to governmental authorities, which may include sales, use, value-added and some excise taxes. These taxes are not included in the transaction price and are, therefore, excluded from revenues.

Allocation of Transaction Price. We allocate the transaction price to the single performance obligation that exists in the vast majority of our contracts with customers. For the few contracts that have a second performance obligation, such as those that include an incentive pricing structure, we calculate an average rate based on the estimated total volumes to be delivered over the term of the contract and the resulting estimated total revenue to be billed using the applicable rates in the contract. We allocate the transaction price to the two performance obligations by applying the average rate to product volumes as they are delivered to the customer over the term of the contract. Determining the timing and amount of volumes subject to these incentive pricing contracts requires judgment that can impact the amount of revenue allocated to the two separate performance obligations. We base our estimates on our analysis of expected future production information available from our customers or other sources, which we update at least quarterly.

Some of our MVC contracts include provisions that allow the customer to apply deficiency payments to future service periods (the carryforward period). In those instances, we have not satisfied our performance obligation as we still have the obligation to perform those services, subject to contractual and/or capacity constraints, at the customer’s request. At least quarterly, we assess the customer’s ability to utilize any deficiency payments during the carryforward period. If we receive a deficiency payment

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from a customer that we expect the customer to utilize during the carryforward period, we defer that amount as a contract liability. We will consider the performance obligation satisfied and allocate any deferred deficiency payments to our performance obligation when the customer utilizes the deficiency payment, the carryforward period ends or we determine the customer cannot or will not utilize the deficiency payment (i.e. breakage). If our contract does not allow the customer to apply deficiency payments to future service periods, we allocate the deficiency payment to the already satisfied portion of the performance obligation.

Income Allocation

Our partnership agreement contains provisions for the allocation of net income to the unitholders. Our net income for each quarterly reporting period is first allocated to the preferred limited partner unitholders in an amount equal to the earned distributions for the respective reporting period. We allocate the remaining net income or loss among the common unitholders.

Basic and Diluted Net Income (Loss) Per Common Unit

Basic and diluted net income (loss) per common unit is determined pursuant to the two-class method. Under this method, all earnings are allocated to our limited partners and participating securities based on their respective rights to receive distributions earned during the period. Participating securities include restricted units awarded under our long-term incentive plans.

We compute basic net income (loss) per common unit by dividing net income (loss) attributable to our common limited partners by the weighted-average number of common units outstanding during the period. We compute diluted net income (loss) per common unit by dividing net income (loss) attributable to our common limited partners by the sum of (i) the weighted-average number of common units outstanding during the period and (ii) the effect of dilutive potential common units outstanding during the period. Dilutive potential common units include contingently issuable performance units awarded and the Series D Preferred Units. See Note 22 for additional information on our performance units, Note 17 for additional information on our Series D Preferred Units and Note 19 for the calculation of basic and diluted net income (loss) per common unit.

Derivative Financial Instruments

When we apply hedge accounting, we formally document all relationships between hedging instruments and hedged items. This process includes identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. To qualify for hedge accounting, at inception of the hedge we assess whether the derivative instruments that are used in our hedging transactions are expected to be highly effective in offsetting changes in cash flows. Throughout the designated hedge period and at least quarterly, we assess whether the derivative instruments are highly effective and continue to qualify for hedge accounting.

We enter into the forward-starting swaps in order to hedge the risk of changes in the interest payments attributable to changes in the benchmark interest rate during the period from the effective date of the swap to the issuance of the forecasted debt. For forward-starting interest rate swaps designated and qualifying as cash flow hedges, we recognize the fair value of each interest rate swap in the consolidated balance sheets. We record changes in the fair value of the hedge as a component of accumulated other comprehensive income (loss) (AOCI), to the extent those cash flow hedges remain highly effective. If at any point a cash flow hedge ceases to qualify for hedge accounting, changes in the fair value of the hedge are recognized in “Interest expense, net” from that date forward. The amount accumulated in AOCI is amortized into “Interest expense, net” as the forecasted interest payments occur or if the interest payments are probable not to occur.

We classify cash flows associated with our derivative instruments as operating cash flows in the consolidated statements of cash flows, except for receipts or payments associated with terminated forward-starting interest rate swap agreements, which are included in cash flows from financing activities. See Note 16 for additional information regarding our derivative financial instruments.

Unit-based Compensation

Unit-based compensation for our long-term incentive plans is recorded in our consolidated balance sheets based on the fair value of the awards granted and recognized as compensation expense primarily on a straight-line basis over the requisite service period. Forfeitures of our unit-based compensation awards are recognized as an adjustment to compensation expense when they occur. Unit-based compensation expense is included in “General and administrative expenses” on our consolidated statements of income (loss). Most of our currently outstanding awards are classified as equity awards as we intend to settle these awards through the issuance of our common units. See Note 22 for additional information regarding our unit-based compensation.

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Foreign Currency Translation

The functional currencies of our foreign subsidiaries are the local currencies of the countries in which the subsidiaries are located. The assets and liabilities of our foreign subsidiaries with local functional currencies are translated to U.S. dollars at period-end exchange rates, and income and expense items are translated to U.S. dollars at weighted-average exchange rates in effect during the period. These translation adjustments are included in “Accumulated other comprehensive loss” in the equity section of the consolidated balance sheets. Gains and losses on foreign currency transactions are included in “Other income (expense), net” in the consolidated statements of income (loss).

Reclassifications

We have reclassified certain previously reported amounts in the consolidated financial statements and notes to conform to current-period presentation.

3. NEW ACCOUNTING PRONOUNCEMENTS

Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity

In August 2020, the Financial Accounting Standards Board (FASB) issued guidance intended to simplify the accounting for convertible instruments by eliminating certain accounting models for convertible debt instruments and convertible preferred stock, requiring the calculation of diluted earnings-per-unit to include the effect of potential unit settlement for any convertible instruments that may be settled in either cash or units, and amending the disclosure requirements for convertible instruments. The guidance is effective for annual periods beginning after December 15, 2021, and early adoption was permitted for annual periods beginning after December 15, 2020. Amendments may be applied using either a modified retrospective approach or a fully retrospective approach. We adopted the amended guidance on January 1, 2022 using the modified retrospective approach. While the amended guidance did not have a material impact on our financial position, results of operations, or disclosures at adoption, changes to the earnings-per-unit guidance could result in changes to our diluted net income (loss) per common unit.

Reference Rate Reform

In March 2020, the FASB issued guidance intended to provide relief to companies impacted by reference rate reform. The amended guidance provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. The publication of U.S. dollar LIBOR rates for the most common tenors is expected to cease after publication on June 30, 2023. As of December 31, 2021, approximately $0.6 billion of our variable-rate debt uses LIBOR as a benchmark for establishing the interest rate. In addition, the distribution rates on our Series A, B and C preferred units convert from fixed rates to floating rates based on LIBOR, beginning in December 2021, June 2022 and December 2022, respectively. The FASB’s guidance is effective as of March 12, 2020 through December 31, 2022. We adopted the guidance on the effective date on a prospective basis. The guidance did not have an impact on our financial position, results of operations or disclosures at transition, but we will continue to evaluate its impact on contracts modified on or before December 31, 2022.

4. DISPOSITIONS, DISCONTINUED OPERATIONS AND IMPAIRMENTS

Eastern U.S. Terminals Disposition

On August 1, 2021, we entered into an agreement (the Purchase Agreement) to sell the Eastern U.S. Terminal Operations to Sunoco LP for $250.0 million in cash. The Eastern U.S. Terminal Operations include terminals in the following locations; Jacksonville, Florida; Andrews Air Force Base, Maryland; Baltimore, Maryland; Piney Point, Maryland; Virginia Beach, Virginia; Paulsboro, New Jersey; and Blue Island, Illinois, as well as both Linden, New Jersey terminals. The Eastern U.S. Terminal Operations had an aggregate storage capacity of 14.8 million barrels and were included in the storage segment. We determined these assets were no longer synergistic with our core assets. The Eastern U.S. Terminal Operations did not qualify for reporting as discontinued operations, as the sale did not represent a strategic shift that would have a major effect on our operations or financial results. We closed the sale on October 8, 2021 and used the proceeds from the sale to reduce debt and thereby improve our debt metrics.

The Eastern U.S. Terminal Operations met the criteria to be classified as held for sale upon our entrance into the Purchase Agreement during the third quarter of 2021. At that time, we allocated goodwill of $34.1 million to the Eastern U.S. Terminal Operations based on its fair value relative to the terminals reporting unit, with which it had been fully integrated. We tested the allocated goodwill for impairment by comparing the fair value of the Eastern U.S. Terminal Operations to its carrying value. The results of our goodwill impairment test indicated that the carrying value of the Eastern U.S. Terminal Operations exceeded its fair value, and we recognized a related goodwill impairment charge of $34.1 million in the third quarter of 2021 to reduce the allocated goodwill to $0. The goodwill impairment loss is reported in “Goodwill impairment losses” on the consolidated statement of income for the year ended December 31, 2021. We believe that the sales price of $250.0 million provided a

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reasonable indication of the fair value of the Eastern U.S. Terminal Operations as it represents an exit price in an orderly transaction between market participants. The sales price is a quoted price for identical assets and liabilities in a market that is not active and, thus, our fair value estimate falls within Level 2 of the fair value hierarchy.

We compared the remaining carrying value of the Eastern U.S. Terminal Operations, after its goodwill impairment, to its fair value less costs to sell. We recognized an asset impairment loss of $95.7 million in the third quarter of 2021, which is reported in “Asset impairment losses” on the consolidated statement of income for the year ended December 31, 2021. The asset impairment loss included $23.9 million related to intangible assets representing customer contracts and relationships.

Houston Pipeline Impairment

In the third quarter of 2021, we recorded a long-lived asset impairment charge of $59.2 million within our pipeline segment related to our refined product pipeline extending from Mt. Belvieu, Texas to Corpus Christi, Texas (the Houston Pipeline). During the third quarter of 2021, we identified an indication of impairment related to the southern section of the Houston Pipeline, specifically that its physical condition would require significant investment in order to pursue commercial opportunities. Consequently, we separated the pipeline into two distinct assets: the northern and southern sections. Our estimate of the undiscounted cash flows associated with the southern section indicated it was not recoverable. Due to the factors described above, we determined the carrying value of the southern section exceeded its fair value, and reduced its carrying value to $0. We recorded the asset impairment charge in “Asset impairment losses” on the consolidated statement of income for the year ended December 31, 2021. We determined that the northern portion of the pipeline was not impaired.

Sale of Texas City Terminals

On December 7, 2020, we sold the equity interests in our wholly owned subsidiaries that owned two terminals in Texas City, Texas for $106.0 million (the Texas City Sale). The two terminals had an aggregate storage capacity of 3.0 million barrels and were previously included in our storage segment. We recorded a non-cash loss of $34.7 million in “Other income (expense), net” on our consolidated statement of loss for the year ended December 31, 2020 and utilized the sales proceeds to reduce debt and thereby improve our debt metrics.

Sale of St. Eustatius Operations

On July 29, 2019, we sold the St. Eustatius Operations for net proceeds of approximately $230.0 million. The St. Eustatius Disposition included a 14.3 million barrel storage and terminalling facility and related assets on the island of St. Eustatius in the Caribbean Netherlands. We previously reported the terminal operations in our storage segment and the bunkering operations in our fuels marketing segment. We recognized a non-cash loss on the sale of $3.9 million in “Loss from discontinued operations, net of tax” on the consolidated statement of loss for the year ended December 31, 2019.

Impairments. On January 28, 2019, the U.S. Department of the Treasury’s Office of Foreign Assets Control added Petroleos de Venezuela, S.A. (PDVSA), at the time a customer at the St. Eustatius facility, to its List of Specially Designated Nationals and Blocked Persons (the SDN List). The inclusion of PDVSA on the SDN List required us to wind down our contracts with PDVSA. Prior to winding down such contracts, PDVSA was the St. Eustatius terminal’s largest customer. The effect of the sanctions issued against PDVSA, combined with the progression in the sale negotiations that occurred during March 2019, resulted in triggering events that caused us to evaluate the long-lived assets and goodwill associated with the St. Eustatius terminal and bunkering operations for potential impairment.

With respect to the terminal operations long-lived assets, our estimates of future expected cash flows included the possibility of a near-term sale, as well as continuing to operate the terminal. The carrying value of the terminal’s long-lived assets exceeded our estimate of the total expected cash flows, indicating the long-lived assets were potentially impaired. To determine an impairment amount, we estimated the fair value of the long-lived assets for comparison to the carrying amount of those assets. Our estimate of the fair value considered the expected sales price as well as estimates generated from income and market approaches using a market participant’s assumptions. The estimated fair values resulting from the market and income approaches were consistent with the expected sales price. Therefore, we concluded that the estimated sales price, which was less than the carrying amount of the long-lived assets, represented the best estimate of fair value at March 31, 2019, and we recorded a long-lived asset impairment charge of $297.3 million in the first quarter of 2019 to reduce the carrying value of the assets to their estimated fair value. We recorded an additional impairment charge of $8.4 million in the second quarter of 2019, mainly due to additional capital expenditures incurred in that quarter.

With respect to the goodwill in the Statia Bunkering reporting unit, which consisted of our bunkering operations at the St. Eustatius terminal facility, we estimated the fair value based on the expected sales price discussed above, which is inclusive of the bunkering operations. As a result, we concluded the goodwill was impaired. We measured the goodwill impairment as the

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difference between the reporting unit’s carrying value and its fair value. Therefore, we recognized a goodwill impairment charge of $31.1 million in the first quarter of 2019 to reduce the goodwill to $0 for the Statia Bunkering reporting unit.

The impairment charges are included in “Loss from discontinued operations, net of tax” on the consolidated statement of loss for the year ended December 31, 2019.

Discontinued Operations. During the second quarter of 2019, we determined the assets and liabilities associated with the St. Eustatius Operations met the criteria to be classified as held for sale. We determined the St. Eustatius Operations met the requirements to be reported as discontinued operations since the St. Eustatius Disposition and the sale of the European operations in November 2018 together represented a strategic shift that will have a major impact on our operations and financial results. These sales were part of our plan to improve our debt metrics and partially fund capital projects to grow our core business in North America. Accordingly, we reclassified certain balances to assets held for sale and liabilities held for sale. The consolidated statement of loss for the year ended December 31, 2019 reflects the St. Eustatius Operations as discontinued operations.

The following is a reconciliation of the major classes of line items included in “Loss from discontinued operations, net of tax” on the consolidated statements of income (loss):

	Year Ended December 31, 2019
	(Thousands of Dollars)
Revenues	$	248,981
Costs and expenses:
Cost of revenues	220,595
Impairment losses	336,838
General and administrative expenses (excluding depreciation and amortization expense)	1,231
Total costs and expenses	558,664
Operating loss	(309,683)
Interest income, net	32
Other expense, net	(2,775)
Loss from discontinued operations before income tax expense	(312,426)
Income tax expense	101
Loss from discontinued operations, net of tax	$	(312,527)

The consolidated statements of cash flows have not been adjusted to separately disclose cash flows related to discontinued operations. The following table presents selected cash flow information associated with our discontinued operations:

	Year Ended December 31, 2019
	(Thousands of Dollars)
Capital expenditures	$	(27,954)
Significant noncash operating activities and other adjustments:
Depreciation and amortization expense	$	8,536
Asset impairment losses	$	305,715
Goodwill impairment loss	$	31,123
Loss from sale of the St. Eustatius Operations	$	3,942

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5. REVENUE FROM CONTRACTS WITH CUSTOMERS

Contract Assets and Contract Liabilities

The following table provides information about contract assets and contract liabilities from contracts with customers:

	2021				2020				2019
	Contract Assets		Contract Liabilities		Contract Assets		Contract Liabilities		Contract Assets		Contract Liabilities
	(Thousands of Dollars)
Balances as of January 1:
Current portion	$	2,694	$	(22,019)	$	2,140	$	(21,083)	$	2,066	$	(21,579)
Noncurrent portion	932		(47,537)		1,003		(40,289)		539		(38,945)
Held for sale	—		—		—		—		—		(25,357)
Total	3,626		(69,556)		3,143		(61,372)		2,605		(85,881)
Activity:
Additions	3,888		(41,121)		5,686		(69,830)		4,890		(52,957)
Transfer to accounts receivable	(3,977)		—		(4,828)		—		(4,352)		—
Transfer to revenues, including amounts reported in discontinued operations	(697)		49,207		(375)		61,646		—		77,466
Total	(786)		8,086		483		(8,184)		538		24,509
Balances as of December 31:
Current portion	2,336		(15,443)		2,694		(22,019)		2,140		(21,083)
Noncurrent portion	504		(46,027)		932		(47,537)		1,003		(40,289)
Total	$	2,840	$	(61,470)	$	3,626	$	(69,556)	$	3,143	$	(61,372)

Contract assets relate to performance obligations satisfied in advance of scheduled billings. Current contract assets are included in “Other current assets” and noncurrent contract assets are included in “Other long-term assets, net” on the consolidated balance sheets. Contract liabilities relate to payments received in advance of satisfying performance obligations under a contract, which mainly result from contracts with an incentive pricing structure, CIAC payments and contracts with MVCs. The current portion of contract liabilities are included in “Accrued liabilities” and the noncurrent portion of contract liabilities are included in “Other long-term liabilities” on the consolidated balance sheets.

Remaining Performance Obligations

The following table presents our estimated revenue from contracts with customers for remaining performance obligations that has not yet been recognized, representing our contractually committed revenue as of December 31, 2021 (in thousands of dollars):

2022	$	413,612
2023	277,278
2024	187,995
2025	131,877
2026	89,103
Thereafter	92,064
Total	$	1,191,929

Our contractually committed revenue, for purposes of the tabular presentation above, is generally limited to customer contracts that have fixed pricing and fixed volume terms and conditions, generally including contracts with MVC payment obligations.

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Disaggregation of Revenues

The following table disaggregates our revenues:

	Year Ended December 31,
	2021		2020		2019
	(Thousands of Dollars)
Pipeline segment:
Crude oil pipelines	$	331,485	$	329,105	$	316,417
Refined products and ammonia pipelines (excluding lessor revenues)	430,753		387,793		376,588
Total pipeline segment revenues from contracts with customers	762,238		716,898		693,005
Lessor revenues	—		1,925		8,825
Total pipeline segment revenues	762,238		718,823		701,830
Storage segment:
Throughput terminals	122,331		136,632		114,243
Storage terminals (excluding lessor revenues)	263,883		316,496		298,984
Total storage segment revenues from contracts with customers	386,214		453,128		413,227
Lessor revenues	41,454		41,314		40,774
Total storage segment revenues	427,668		494,442		454,001
Fuels marketing segment:
Revenues from contracts with customers	428,608		268,345		342,215
Consolidation and intersegment eliminations	(14)		(46)		(25)
Total revenues	$	1,618,500	$	1,481,564	$	1,498,021

6. ALLOWANCE FOR CREDIT LOSSES

The balance of and changes in the allowance for credit losses consisted of the following:

	Year Ended December 31,
	2020		2019
	(Thousands of Dollars)
Balance as of beginning of year	$	72	$	9,412
Current period provision for credit losses	441		2,322
Write-offs charged against the allowance	(513)		(11,662)
Balance as of end of year	$	—	$	72

Activity for the year ended December 31, 2021 was immaterial and the balance as of December 31, 2021 was $0.

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7. INVENTORIES

Inventories consisted of the following:

	December 31,
	2021		2020
	(Thousands of Dollars)
Petroleum products	$	12,456	$	7,394
Materials and supplies	4,188		3,665
Total	$	16,644	$	11,059

We purchase petroleum products for resale. Our petroleum products consist of intermediates, gasoline, distillates and other petroleum products. Materials and supplies mainly consist of blending and additive chemicals and maintenance materials used in our pipeline and storage segments.

8. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:

	Estimated Useful Lives			December 31,
				2021		2020
	(Years)			(Thousands of Dollars)
Land, buildings and improvements	0	-	40	$	366,525	$	440,358
Pipelines, storage and terminals	15	-	40	4,897,041		5,253,507
Rights-of-way	20	-	40	353,262		359,441
Construction in progress				112,020		111,436
Total				5,728,848		6,164,742
Less accumulated depreciation and amortization				(2,187,206)		(2,207,230)
Property, plant and equipment, net				$	3,541,642	$	3,957,512

Capitalized interest costs added to property, plant and equipment, including amounts related to discontinued operations, totaled $3.9 million, $4.9 million and $8.9 million for the years ended December 31, 2021, 2020 and 2019, respectively. Depreciation and amortization expense for property, plant and equipment totaled $220.4 million, $228.8 million and $226.0 million for the years ended December 31, 2021, 2020 and 2019, respectively, including depreciation and amortization expense reported in “Loss from discontinued operations, net of tax” on the consolidated statements of income (loss).

9. INTANGIBLE ASSETS

Intangible assets consisted of the following:

	Weighted-Average Amortization Period	December 31, 2021				December 31, 2020
		Cost		Accumulated Amortization		Cost		Accumulated Amortization
	(Years)	(Thousands of Dollars)
Customer contracts and relationships	17	$	793,900	$	(237,579)	$	863,900	$	(235,205)
Other	47	2,359		(895)		2,359		(845)
Total		$	796,259	$	(238,474)	$	866,259	$	(236,050)

Intangible assets are recorded at fair value as of the date acquired. All of our intangible assets are amortized on a straight-line basis. Amortization expense for intangible assets was $48.5 million for the year ended December 31, 2021 and $51.4 million for each of the years ended December 31, 2020 and 2019. The estimated aggregate amortization expense is $44.0 million for 2022 and $38.0 million for each of the years 2023 through 2026.

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10. GOODWILL

The balances of and changes in the carrying amount of goodwill by segment were as follows:

	Pipeline		Storage		Total
	(Thousands of Dollars)
Balances as of January 1, 2020	$	704,231	$	301,622	$	1,005,853
Activity for the year ended December 31, 2020:
Goodwill impairment loss on crude oil pipelines	(225,000)		—		(225,000)
Texas City Sale	—		(14,437)		(14,437)
Balances as of December 31, 2020:
Goodwill	704,231		287,185		991,416
Accumulated impairment loss	(225,000)		—		(225,000)
Net goodwill	479,231		287,185		766,416
Activity for the year ended December 31, 2021:
Goodwill impairment loss on Eastern U.S. Terminal Operations	—		(34,060)		(34,060)
Balances as of December 31, 2021:
Goodwill	704,231		253,125		957,356
Accumulated impairment loss	(225,000)		—		(225,000)
Net goodwill	$	479,231	$	253,125	$	732,356

Eastern U.S. Terminals Operations. On October 8, 2021, we completed the sale of the Eastern U.S. Terminals Operations. In the third quarter of 2021, the Eastern U.S. Terminal Operations met the criteria to be classified as held for sale, and we tested the allocated goodwill for impairment. We recognized a goodwill impairment charge of $34.1 million in the third quarter of 2021. Please see Note 4 for additional information on the disposition.

Texas City Sale. On December 7, 2020, we completed the Texas City Sale and the goodwill associated with the sold terminals was included in the calculation of the loss on sale. Please see Note 4 for additional information on the sale.

2020 Impairment. In March 2020, the COVID-19 pandemic and actions taken by the Organization of Petroleum Exporting Countries and other oil-producing nations (OPEC+) resulted in severe disruptions in the capital and commodities markets, which led to significant decline in our unit price. As a result, our equity market capitalization fell significantly. The decline in crude oil prices and demand for petroleum products also led to a decline in expected earnings from some of our goodwill reporting units. These factors and others related to COVID-19 and OPEC+ caused us to conclude there were triggering events that occurred in March 2020 that required us to perform a goodwill impairment test as of March 31, 2020. We recognized a goodwill impairment charge of $225.0 million in the first quarter of 2020, which is reported in the pipeline segment. Our assessment did not identify any other reporting units at risk of a goodwill impairment.

We calculated the estimated fair value of each of our reporting units using a weighted-average of values determined from an income approach and a market approach. The income approach involves estimating the fair value of each reporting unit by discounting its estimated future cash flows using a discount rate that would be consistent with a market participant’s assumption. The market approach bases the fair value measurement on information obtained from observed stock prices of public companies and recent merger and acquisition transaction data of comparable entities. In order to estimate the fair value of 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. The assumptions in the fair value measurement reflect the current market environment, industry-specific factors and company-specific factors.

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The decline in expected earnings from certain of our long-lived assets was also an indicator that the carrying values of these long-lived assets may not be recoverable. Prior to performing the goodwill impairment test, we tested these long-lived assets for recoverability and determined they were fully recoverable as of March 31, 2020.

Management’s estimates are based on numerous assumptions about future operations and market conditions, which we believe to be reasonable but are inherently uncertain. The uncertainties underlying our assumptions and estimates could differ significantly from actual results, including with respect to the duration and severity of the COVID-19 pandemic.

11. ACCRUED LIABILITIES

Accrued liabilities consisted of the following:

	December 31,
	2021		2020
	(Thousands of Dollars)
Employee wages and benefit costs	$	40,209	$	27,805
Revenue contract liabilities	15,443		22,019
Operating lease liabilities	10,346		10,890
Environmental costs	3,378		5,371
Other	10,442		11,685
Accrued liabilities	$	79,818	$	77,770

12. DEBT

Short-term debt consisted of the current portion of finance leases, with balances of $3.8 million as of December 31, 2021 and 2020. Please refer to Note 15 for additional information.

Long-term debt consisted of the following:

				December 31,
	Maturity			2021		2020
				(Thousands of Dollars)
Revolving Credit Agreement	April 27, 2025 (a)			$	110,500	$	—
6.75% senior notes	February 1, 2021			—		300,000
4.75% senior notes	February 1, 2022			—		250,000
5.75% senior notes	October 1, 2025			600,000		600,000
6.00% senior notes	June 1, 2026			500,000		500,000
5.625% senior notes	April 28, 2027			550,000		550,000
6.375% senior notes	October 1, 2030			600,000		600,000
Subordinated Notes	January 15, 2043			402,500		402,500
GoZone Bonds	2038	thru	2041	322,140		322,140
Receivables Financing Agreement	January 31, 2025 (a)			83,800		57,000
Net fair value adjustments, unamortized discounts and unamortized debt issuance costs		N/A		(38,315)		(42,382)
Total long-term debt (excluding finance leases)				3,130,625		3,539,258
Finance leases (refer to Note 15)				52,930		54,238
Long-term debt, less current portion				$	3,183,555	$	3,593,496

(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.

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The long-term debt repayments (excluding finance leases) as of December 31, 2021 are due as follows (in thousands of dollars):

2022	$	—
2023 (a)	194,300
2024	—
2025	600,000
2026	500,000
Thereafter	1,874,640
Total repayments	3,168,940
Net fair value adjustments, unamortized discounts and unamortized debt issuance costs	(38,315)
Total long-term debt (excluding finance leases)	$	3,130,625

(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.

Interest payments totaled $220.0 million, $207.2 million and $183.8 million for the years ended December 31, 2021, 2020 and 2019, respectively, related to debt obligations. We amortized an aggregate of $7.9 million, $11.4 million and $6.5 million of debt issuance costs and debt discount combined for the years ended December 31, 2021, 2020 and 2019, respectively.

Revolving Credit Agreement

As of December 31, 2021, NuStar Logistics’ $1.0 billion revolving credit agreement (the Revolving Credit Agreement) had $884.8 million available for borrowing and $110.5 million 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 ending December 31, 2021, the maximum allowed consolidated debt coverage ratio (as defined in the Revolving Credit Agreement) may 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, we believe that we are in compliance with the covenants in the Revolving Credit Agreement.

Prior to the amendment on January 28, 2022, described below, the Revolving Credit Agreement bore interest, at our option, based on an alternative base rate or a LIBOR-based rate. The interest rate on the Revolving Credit Agreement is subject to adjustment if our debt rating is downgraded (or upgraded) by certain credit rating agencies. In August of 2020, Moody’s Investor Service Inc. downgraded our credit rating from Ba2 to Ba3. 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. As of December 31, 2021, our weighted-average interest rate under our Revolving Credit Agreement was 2.9%. During the year ended December 31, 2021, the weighted-average interest rate related to borrowings under the Revolving Credit Agreement was 2.7%.

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. On April 6, 2020, we amended the Revolving Credit Agreement to allow for certain transactions related to the GoZone Bonds discussed below. On March 6, 2020, we amended the Revolving Credit Agreement to, among other things, reduce the total amount available for borrowing from $1.2 billion to $1.0 billion and increase the rates included in the definition of Applicable Rate contained in the Revolving Credit Agreement.

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Notes

NuStar Logistics Senior Notes. 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 repaid our $300.0 million of 6.75% senior notes due February 1, 2021 and our $450.0 million of 4.8% senior notes due September 1, 2020 with borrowings under our Revolving Credit Agreement.

On September 14, 2020, NuStar Logistics issued $600.0 million of 5.75% senior notes due October 1, 2025 and $600.0 million of 6.375% senior notes due October 1, 2030. We received proceeds of $1,182.0 million, net of issuance costs of $18.0 million, which we used to repay outstanding borrowings and the early repayment premiums under the Term Loan, as defined below, as well as outstanding borrowings under our Revolving Credit Agreement. The issuance of the 5.75% and 6.375% senior notes bolstered our liquidity to address our senior note maturities that we repaid in 2021. On May 22, 2019, NuStar Logistics issued $500.0 million of 6.0% senior notes due June 1, 2026. We received net proceeds of $491.6 million, which we used to repay outstanding borrowings under our Revolving Credit Agreement.

Interest is payable semi-annually in arrears for the $600.0 million of 5.75% senior notes, $500.0 million of 6.0% senior notes, $550.0 million of 5.625% senior notes and $600.0 million of 6.375% senior notes (collectively, the NuStar Logistics Senior Notes).

The NuStar Logistics Senior Notes do not have sinking fund requirements. These notes rank equally with existing senior unsecured indebtedness and senior to existing subordinated indebtedness of NuStar Logistics and contain restrictions on NuStar Logistics’ ability to incur secured indebtedness unless the same security is also provided for the benefit of holders of the NuStar Logistics Senior Notes. In addition, the NuStar Logistics Senior Notes limit the ability of NuStar Logistics and its subsidiaries to, among other things, incur indebtedness secured by certain liens, engage in certain sale-leaseback transactions and engage in certain consolidations, mergers or asset sales. At the option of NuStar Logistics, the NuStar Logistics Senior Notes may be redeemed in whole or in part at any time at a redemption price, plus accrued and unpaid interest to the redemption date. If we undergo a change of control, as defined in the supplemental indentures for the NuStar Logistics Senior Notes, each holder of the applicable senior notes may require us to repurchase all or a portion of its notes at a price equal to 101% of the principal amount of the notes repurchased, plus any accrued and unpaid interest to the date of repurchase. The NuStar Logistics Senior Notes are fully and unconditionally guaranteed by NuStar Energy and NuPOP.

NuStar Logistics Subordinated Notes. NuStar Logistics’ $402.5 million of fixed-to-floating rate subordinated notes are due January 15, 2043 (the Subordinated Notes). The Subordinated Notes are fully and unconditionally guaranteed on an unsecured and subordinated basis by NuStar Energy and NuPOP. Effective January 15, 2018, the interest rate on the Subordinated Notes switched to an annual rate equal to the sum of the three-month LIBOR for the related quarterly interest period, plus 6.734% payable quarterly, commencing April 15, 2018, unless payment is deferred in accordance with the terms of the notes. NuStar Logistics may elect to defer interest payments on the Subordinated Notes on one or more occasions for up to five consecutive years. Deferred interest will accumulate additional interest at a rate equal to the interest rate then applicable to the Subordinated Notes until paid. If NuStar Logistics elects to defer interest payments, NuStar Energy cannot declare or make cash distributions to its unitholders during the period that interest payments are deferred. As of December 31, 2021, the interest rate was 6.9%.

The Subordinated Notes do not have sinking fund requirements and are subordinated to existing senior unsecured indebtedness of NuStar Logistics and NuPOP. The Subordinated Notes do not contain restrictions on NuStar Logistics’ ability to incur additional indebtedness, including debt that ranks senior in priority of payment to the notes. In addition, the Subordinated Notes do not limit NuStar Logistics’ ability to incur indebtedness secured by liens or to engage in certain sale-leaseback transactions. Effective January 15, 2018, we may redeem the Subordinated Notes in whole or in part at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest to the redemption date.

Gulf Opportunity Zone Revenue Bonds

In 2008, 2010 and 2011, the Parish of St. James, Louisiana issued Revenue Bonds Series 2008, Series 2010, Series 2010A, Series 2010B and Series 2011 associated with our St. James terminal expansions pursuant to the Gulf Opportunity Zone Act of 2005 for an aggregate $365.4 million (collectively, the GoZone Bonds). Following the issuances, the proceeds were deposited with a trustee and were disbursed to us upon our request for reimbursement of expenditures related to our St. James terminal. On March 4, 2020, NuStar Logistics repaid $43.3 million of GoZone Bonds with unused funds, which had been held in trust. NuStar Logistics is obligated to make payments in amounts sufficient to pay the principal of, premium, if any, interest and certain other payments on, the GoZone Bonds.

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On June 3, 2020, NuStar Logistics completed the reoffering and conversion of the GoZone Bonds through supplements to the original indentures governing the GoZone Bonds and supplements to the original agreements between NuStar Logistics and the Parish of St. James, which, among other things, converted the interest rate from a weekly rate to a long-term rate. In connection with the reoffering and conversion, we terminated the letters of credit previously issued by various individual banks on our behalf to support the payments required in connection with the GoZone Bonds, and NuStar Energy and NuPOP guaranteed NuStar Logistics’ obligations with respect to the GoZone Bonds. We did not receive any proceeds from the reoffering, and the reoffering did not increase our outstanding debt.

The following table summarizes the GoZone Bonds outstanding as of December 31, 2021:

Series	Date Issued	Amount Outstanding		Interest Rate		Mandatory Purchase Date	Maturity Date
		(Thousands of Dollars)
Series 2008	June 26, 2008	$	55,440	6.10	%	June 1, 2030	June 1, 2038
Series 2010	July 15, 2010	100,000		6.35	%	n/a	July 1, 2040
Series 2010A	October 7, 2010	43,300		6.35	%	n/a	October 1, 2040
Series 2010B	December 29, 2010	48,400		6.10	%	June 1, 2030	December 1, 2040
Series 2011	August 9, 2011	75,000		5.85	%	June 1, 2025	August 1, 2041
	Total	$	322,140

Interest on the GoZone Bonds accrues from June 3, 2020 and is payable semi-annually on June 1 and December 1 of each year, beginning December 1, 2020. The holders of the Series 2008, Series 2010B and Series 2011 GoZone Bonds are required to tender their bonds at the applicable mandatory purchase date in exchange for 100% of the principal plus accrued and unpaid interest, after which these bonds will potentially be remarketed with a new interest rate established. Each of the Series 2010 and Series 2010A GoZone Bonds is subject to redemption on or after June 1, 2030 by the Parish of St. James, at our option, in whole or in part, at a redemption price of 100% of the principal amount to be redeemed plus accrued interest. The Series 2008, Series 2010B and Series 2011 GoZone Bonds are not subject to optional redemption.

NuStar Logistics’ agreements with the Parish of St. James related to the GoZone Bonds contain (i) customary restrictive covenants that limit the ability of NuStar Logistics and its subsidiaries, to, among other things, create liens or enter into sale-leaseback transactions, consolidations, mergers or asset sales and (ii) a change of control provision that provides each holder the right to require the trustee, with funds provided by NuStar Logistics, to repurchase all or a portion of that holder’s GoZone Bonds upon a change of control at a price equal to 101% of the aggregate principal amount repurchased, plus any accrued and unpaid interest.

Receivables Financing Agreement

NuStar Energy and NuStar Finance LLC (NuStar Finance), a special purpose entity and wholly owned subsidiary of NuStar 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). Under the Securitization Program, certain of NuStar Energy’s wholly owned subsidiaries (collectively, the Originators), sell their accounts receivable to NuStar Finance on an ongoing basis, and NuStar Finance provides the newly acquired accounts receivable as collateral for its revolving borrowings under the Receivables Financing Agreement. NuStar Energy provides a performance guarantee in connection with the Securitization Program. The amount available for borrowing is based on the availability of eligible receivables and other customary factors and conditions. The Securitization Program contains various customary affirmative and negative covenants and default, indemnification and termination provisions, and the Receivables Financing Agreement provides for acceleration of amounts owed upon the occurrence of certain specified events. NuStar Finance’s sole activity consists of purchasing such receivables and providing them as collateral under the Securitization Program. NuStar Finance is a separate legal entity and the assets of NuStar Finance, including these accounts receivable, are not available to satisfy the claims of creditors of NuStar Energy, the Originators or their affiliates.

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. On September 3, 2020, the Receivables Financing Agreement was amended to, among other things: (i) reduce the amount available for borrowing from $125.0 million to $100.0 million, (ii) provide that the failure to satisfy the consolidated debt coverage ratio, as

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defined in the Revolving Credit Agreement, would constitute an Event of Default as defined in the Receivables Financing Agreement, and (iii) increase the interest rate.

Prior to the January 28, 2022 amendment described above, borrowings by NuStar Finance under the Receivables Financing Agreement bore interest at the applicable bank rate, as defined under the Receivables Financing Agreement. 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. As of December 31, 2021 and 2020, accounts receivable totaling $119.2 million and $110.6 million, respectively, were included in the Securitization Program. The weighted average interest rate related to outstanding borrowings under the Securitization Program during the year ended December 31, 2021 was 2.3%.

Term Loan Credit 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. The Term Loan bolstered our liquidity to address near-term senior note maturities.

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 a commitment fee, which resulted in a loss from extinguishment of debt of $137.9 million in the third quarter of 2020. On February 16, 2021, we terminated the Term Loan.

Outstanding borrowings bore interest at an aggregate rate of 12.0% per annum, and the Term Loan was subject to a commitment fee in the amount of 5.0% per annum on the average daily undrawn amount of $250.0 million until April 19, 2021.

13. HEALTH, SAFETY AND ENVIRONMENTAL MATTERS

Our operations are subject to extensive international, federal, state and local environmental laws and regulations, in the U.S. and in the other countries in which we operate, including those relating to the discharge of materials into the environment, waste management, remediation, the characteristics and composition of fuels, climate change and greenhouse gases. Our operations are also subject to extensive health, safety and security laws and regulations, including those relating to worker and pipeline safety, pipeline and storage tank integrity and operations security. The principal environmental, health, safety and security risks associated with our operations relate to unauthorized emissions into the air, releases into soil, surface water or groundwater, personal injury and property damage. We have adopted policies, practices, systems and procedures designed to comply with the laws and regulations, and to help minimize and mitigate these risks, limit the liability that could result from such events, prevent material environmental or other damage, ensure the safety of our employees and the public and secure our pipelines, terminals and operations. Compliance with environmental, health, safety and security laws, regulations and related permits increases our capital expenditures and operating expenses, and violation of these laws, regulations or permits could result in significant civil and criminal liabilities, injunctions or other penalties. Future governmental action and regulatory initiatives could result in more restrictive laws and regulations, which could increase required capital expenditures and operating expenses. The risk of additional compliance expenditures, expenses and liabilities are inherent to government-regulated industries, including midstream energy. As a result, there can be no assurances that significant expenditures, expenses and liabilities will not be incurred in the future.

Most of our pipelines are subject to federal regulation by one or more of the following governmental agencies: the Federal Energy Regulatory Commission (the FERC), the Surface Transportation Board (the STB), the Department of Transportation (DOT), the Environmental Protection Agency (EPA) and the Department of Homeland Security. Additionally, our pipelines are subject to the respective jurisdictions of the states those lines traverse.

Environmental and safety exposures and liabilities are difficult to assess and estimate due to unknown factors such as the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental and safety laws and regulations may change in the future. Although environmental and safety costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.

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The balance of and changes in the accruals for environmental matters were as follows:

	Year Ended December 31,
	2021		2020
	(Thousands of Dollars)
Balance as of the beginning of year	$	8,373	$	7,938
Additions to accrual	2,044		3,692
Payments	(2,669)		(3,257)
Balance as of the end of year	$	7,748	$	8,373

Accruals for environmental matters are included in the consolidated balance sheets as follows:

	December 31,
	2021		2020
	(Thousands of Dollars)
Accrued liabilities	$	3,378	$	5,371
Other long-term liabilities	4,370		3,002
Accruals for environmental matters	$	7,748	$	8,373

14. COMMITMENTS, CONTINGENCIES AND UNCERTAINTIES

Commitments

Future minimum rental payments applicable to all noncancellable purchase obligations as of December 31, 2021 are as follows:

	Payments Due by Period
	2022		2023		2024		2025		2026		Thereafter		Total
	(Thousands of Dollars)
Purchase obligations	$	10,606	$	5,125	$	2,226	$	1,552	$	753	$	5,466	$	25,728

Our purchase obligations primarily consist of an eleven-year chemical supply agreement related to our pipelines that terminates in 2022 and various service agreements with information technology providers.

Contingencies

We have contingent liabilities resulting from various litigation, claims and commitments. We record accruals for loss contingencies when losses are considered probable and can be reasonably estimated. Legal fees associated with defending the Partnership in legal matters are expensed as incurred. We accrued $0.1 million and $2.6 million for contingent losses as of December 31, 2021 and 2020, respectively. The amount that will ultimately be paid related to such matters may differ from the recorded accruals, and the timing of such payments is uncertain. We evaluate each contingent loss at least quarterly, and more frequently as each matter progresses and develops over time, and we do not believe that the resolution of any particular claim or proceeding, or all matters in the aggregate, would have a material adverse effect on our results of operations, financial position or liquidity.

Uncertainties

The coronavirus, or COVID-19, had a severe negative impact on global economic activity during 2020, significantly reducing demand for petroleum products and increasing the volatility of crude oil prices, beginning in March 2020. While the U.S. economy has demonstrated signs of stabilization and improvement in 2021, ongoing uncertainty surrounding the COVID-19 pandemic has caused and may continue to cause volatility and could have a significant impact on management’s estimates and assumptions in 2022 and beyond.

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15. LEASE ASSETS AND LIABILITIES

Lessee Arrangements

Our operating leases consist primarily of land and dock leases at various terminal facilities. As of December 31, 2021, land and dock leases have remaining terms generally of up to four years and include options to extend, some up to twenty years, which we are reasonably certain to exercise. During 2020, we modified three leases for marine vessels at our Point Tupper terminal facility in order to extend their lease terms by five years. The modifications and related remeasurements resulted in additional lease liabilities and right-of-use assets totaling $20.1 million.

The primary component of our finance lease portfolio is a dock at our Corpus Christi North Beach terminal facility, which includes a commitment for minimum dockage and wharfage throughput volumes. The dock lease has a remaining term of approximately four years and three additional five-year renewal periods, all of which we are reasonably certain to exercise.

Right-of-use assets and lease liabilities included in our consolidated balance sheet were as follows:

		December 31,
	Balance Sheet Location	2021		2020
		(Thousands of Dollars)
Right-of-Use Assets:
Operating	Other long-term assets, net	$	76,867	$	87,443
Finance	Property, plant and equipment, net of accumulated amortization of $13,561 and $8,444	$	71,002	$	73,319
Lease Liabilities:
Operating:
Current	Accrued liabilities	$	10,346	$	10,890
Noncurrent	Other long-term liabilities	65,060		74,899
Total operating lease liabilities		$	75,406	$	85,789
Finance:
Current	Current portion of finance lease obligations	$	3,848	$	3,839
Noncurrent	Long-term debt, less current portion	52,930		54,238
Total finance lease liabilities		$	56,778	$	58,077

As of December 31, 2021, maturities of our operating and finance lease liabilities were as follows:

	Operating Leases		Finance Leases
	(Thousands of Dollars)
2022	$	12,252	$	5,831
2023	10,960		5,705
2024	10,656		5,217
2025	8,705		4,424
2026	5,876		3,979
Thereafter	48,542		52,399
Total lease payments	$	96,991	$	77,555
Less: Interest	21,585		20,777
Present value of lease liabilities	$	75,406	$	56,778

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Costs incurred for leases, including costs associated with discontinued operations, were as follows:

	Year Ended December 31,
	2021		2020		2019
	(Thousands of Dollars)
Operating lease cost	$	15,323	$	16,814	$	29,167
Finance lease cost:
Amortization of right-of-use assets	$	5,251	$	4,700	$	3,748
Interest expense on lease liability	$	2,081	$	2,201	$	2,212
Short-term lease cost	$	14,198	$	15,359	$	19,140
Variable lease cost	$	4,939	$	8,653	$	6,990
Total lease cost	$	41,792	$	47,727	$	61,257

The table below presents additional information regarding our leases.

	2021						2020						2019
	Operating Leases			Finance Leases			Operating Leases			Finance Leases			Operating Leases			Finance Leases
	(Thousands of Dollars, Except Term and Rate Data)
For the year ended December 31:
Cash outflows from operating activities	$	12,829		$	2,090		$	14,487		$	2,208		$	27,567		$	2,027
Cash outflows from financing activities	$	—		$	4,244		$	—		$	4,981		$	—		$	3,700
Right-of-use assets obtained in exchange for lease liabilities	$	3,278		$	3,173		$	20,830		$	3,077		$	2,153		$	4,430
As of December 31:
Weighted-average remaining lease term (in years)	13			18			13			19			15			20
Weighted-average discount rate	3.2		%	3.6		%	3.2		%	3.7		%	3.6		%	3.7		%

Lessor Arrangements

We have entered into certain revenue arrangements where we are considered to be the lessor. Under the largest of these arrangements, we lease certain of our storage tanks in exchange for a fixed fee, subject to an annual consumer price index adjustment. The operating leases commenced on January 1, 2017, and have initial terms of 10 years with successive automatic renewal terms. We recognized lease revenues from these leases of $41.5 million, $41.3 million, and $40.8 million for the years ended December 31, 2021, 2020, and 2019, respectively, which are included in “Service revenues” in the consolidated statements of income (loss). As of December 31, 2021, we expect to receive minimum lease payments totaling $195.6 million, based upon the consumer price index as of the adoption date. We will recognize these payments ratably over the remaining initial lease term.

The table below presents cost, accumulated depreciation and useful life information related to our storage lease assets, which are included in our “Pipeline, storage and terminals” asset class within property, plant and equipment:

	Estimated Useful Life	December 31,
		2021		2020
	(Years)	(Thousands of Dollars)
Lease storage assets, at cost	30	$	246,841	$	241,664
Less accumulated depreciation		(139,200)		(130,217)
Lease storage assets, net		$	107,641	$	111,447

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16. DERIVATIVES AND FAIR VALUE MEASUREMENTS

Derivative Instruments

We utilize various derivative instruments to manage our exposure to interest rate risk and commodity price risk. Our risk management policies and procedures are designed to monitor interest rates, futures and swap positions and over-the-counter positions, as well as physical commodity volumes, grades, locations and delivery schedules, to help ensure that our hedging activities address our market risks.

Commodity Price Risk. The results of operations for the fuels marketing segment depend largely on the margin between our cost and the sales prices of the products we 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. Since our fuels marketing operations expose us to commodity price risk, we enter into derivative instruments to mitigate the effect of commodity price fluctuations on our operations. Derivative financial instruments associated with commodity price risk with respect to our petroleum product inventories and related firm commitments to purchase and/or sell such inventories were not material for any period presented.

Interest Rate Risk. We were a party to certain interest rate swap agreements to manage our exposure to changes in interest rates, which consisted of forward-starting interest rate swap agreements related to forecasted debt issuances. We entered into these swaps in order to hedge the risk of fluctuations in the required interest payments attributable to changes in the benchmark interest rate during the period from the effective date of the swap to the issuance of the forecasted debt. Under the terms of the swaps, we paid a weighted-average fixed rate and received a rate based on the three-month USD LIBOR. These swaps qualified as cash flow hedges, and we designated them as such. We recorded mark-to-market adjustments as a component of AOCI, and the amount in AOCI is recognized in “Interest expense, net” as the forecasted interest payments occur or if the interest payments are probable not to occur. In June 2020, in connection with the reoffering and conversion of the GoZone Bonds, we terminated forward-starting interest rate swaps with an aggregate notional amount of $250.0 million and paid $49.2 million, which will be amortized into “Interest expense, net” as the related forecasted interest payments occur. The termination payments are included in cash flows from financing activities on the consolidated statements of cash flows. Please see Note 2 for additional information. In conjunction with the early repayment of our $250.0 million 4.75% senior notes due February 1, 2022 in the fourth quarter of 2021, we reclassified a loss of $0.8 million from AOCI to “Interest expense, net.”

The remaining fair value amounts associated with unwound interest rate swap agreements are presented in the table below. These amounts are amortized ratably over the remaining life of the related debt instrument into “Interest expense, net” on the consolidated statements of income (loss).

		December 31,
Unwound Interest Rate Swap Agreements	Balance Sheet Location	2021		2020
		(Thousands of Dollars)
Fixed-to-floating	Long-term debt, less current portion	$	—	$	1,363
Forward-starting	Accumulated other comprehensive loss	$	(36,486)	$	(42,150)

Our forward-starting interest rate swaps had the following impact on earnings:

	Year Ended December 31,
	2021		2020		2019
	(Thousands of Dollars)
Change in unrealized loss on cash flow hedges	$	—	$	(30,291)	$	(19,045)
Reclassification of loss on cash flow hedges to interest expense, net	$	5,664	$	4,265	$	3,814

As of December 31, 2021, we expect to reclassify a loss of $2.1 million to “Interest expense, net” within the next twelve months associated with unwound forward-starting interest rate swap agreements.

Fair Value Measurements

We segregate the inputs used in measuring fair value into three levels: Level 1, defined as observable inputs such as quoted prices for identical assets or liabilities in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable, such as quoted prices for similar assets or liabilities in active markets or quoted prices for identical assets or liabilities in markets that are not active; and Level 3, defined as unobservable inputs for which little

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or no market data exists. We consider counterparty credit risk and our own credit risk in the determination of all estimated fair values.

We recognize cash equivalents, receivables, payables and debt in our consolidated balance sheets at their carrying amounts. The fair values of these financial instruments, except for long-term debt other than finance leases, approximate their carrying amounts. The estimated fair values and carrying amounts of the long-term debt, excluding finance leases, were as follows:

	December 31,
	2021		2020
	(Thousands of Dollars)
Fair value	$	3,459,153	$	3,799,378
Carrying amount	$	3,130,625	$	3,539,258

We have estimated the fair value of our publicly traded notes based upon quoted prices in active markets; therefore, we determined that the fair value of our publicly traded notes falls in Level 1 of the fair value hierarchy. With regard to our other debt, for which a quoted market price is not available, we have estimated the fair value using a discounted cash flow analysis using current incremental borrowing rates for similar types of borrowing arrangements and determined that the fair value falls in Level 2 of the fair value hierarchy. The carrying value includes net fair value adjustments, unamortized discounts and unamortized debt issuance costs.

17. SERIES D CUMULATIVE CONVERTIBLE PREFERRED UNITS

Series D Preferred Units Issued and Outstanding

On June 26, 2018, the Partnership entered into a purchase agreement (the Series D Preferred Unit Purchase Agreement) with investment funds, accounts and entities (collectively, the Purchasers) managed by EIG Management Company, LLC and FS/EIG Advisors, LLC to issue and sell Series D Cumulative Convertible Preferred Units (Series D Preferred Units) in a private placement. The following is a summary of our Series D Preferred Units issued and outstanding as of December 31, 2021:

	Original Issuance Date	Number of Units Issued and Outstanding	Purchase Price per Unit
Initial Closing	June 29, 2018	15,760,441	$	25.38
Second Closing	July 13, 2018	7,486,209	$	25.38
Total		23,246,650

The Series D Preferred Units rank equal to other classes of preferred units and senior to common units in the Partnership with respect to distribution rights and rights upon liquidation. The Series D Preferred Units generally vote on an as-converted basis with the common units and have certain class voting rights with respect to a limited number of matters as set forth in the partnership agreement. The Partnership is required to use its commercially reasonable efforts to register the Series D Preferred Units after the second anniversary of the Initial Closing, no later than one year after receipt of a written request from holders holding a majority of the Series D Preferred Units to register the Series D Preferred Units. If the Partnership fails to cause such registration statement to become effective by the applicable date, the Partnership will be required to pay certain amounts to the holders as liquidated damages.

Series D Preferred Units Distributions

Distributions on the Series D Preferred Units are payable out of any legally available funds, accrue and are cumulative from the issuance dates and are payable on the 15th day (or next business day) of each of March, June, September and December, beginning September 17, 2018, to holders of record on the first business day of each payment month. The distribution rates on the Series D Preferred Units are as follows: (i) 9.75%, or $57.6 million, per annum ($0.619 per unit per distribution period) for the first two years; (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 per unit may be paid, in the Partnership’s sole discretion, in additional Series D Preferred Units, with the remainder paid in cash.

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If we fail to pay in full any Series D Preferred Unit distribution amount, then, until we pay such distributions in full, the applicable distribution rate for each of those distribution periods shall be increased by $0.048 per Series D Preferred Unit. In addition, if we fail to pay in full any Series D Preferred Unit distribution amount for three consecutive distribution periods, then until we pay such distributions in full: (i) each holder of the Series D Preferred Units may elect to convert its Series D Preferred Units into common units on a one-for-one basis, plus any unpaid Series D distributions, (ii) one person selected by the holders holding a majority of the outstanding Series D Preferred Units shall become an additional member of our board of directors and (iii) we will not be permitted to incur any indebtedness (as defined in the Revolving Credit Agreement) or engage in any acquisitions or asset sales in excess of $50.0 million without the consent of the holders holding a majority of the outstanding Series D Preferred Units. In addition, we will permanently lose the ability to pay any part of the distributions on the Series D Preferred Units in the form of additional Series D Preferred Units.

In January 2022, our board of directors declared a distribution of $0.682 per Series D Preferred Unit to be paid on March 15, 2022.

Series D Preferred Units Conversion and Redemption Features

On or after June 29, 2020, each holder of Series D Preferred Units may convert all or any portion of its Series D Preferred Units into common units on a one-for-one basis (plus any unpaid Series D distributions), subject to anti-dilution adjustments, at any time, but not more than once per quarter, so long as any conversion is for at least $50.0 million based on the Purchase Price per Unit (or such lesser amount representing all of a holder’s Series D Preferred Units).

The Partnership may redeem all or any portion of the Series D Preferred Units, in an amount not less than $50.0 million for cash at a redemption price equal to, as applicable: (i) $31.73 per Series D Preferred Unit at any time on or after June 29, 2023 but prior to June 29, 2024; (ii) $30.46 per Series D Preferred Unit at any time on or after June 29, 2024 but prior to June 29, 2025; (iii) $29.19 per Series D Preferred Unit at any time on or after June 29, 2025; plus, in each case, the 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 above.

Additionally, at any time on or after June 29, 2028, each holder of Series D Preferred Units will have the right to require the Partnership to redeem all of the Series D Preferred Units held by such holder at a redemption price equal to $29.19 per Series D Preferred Unit plus any unpaid Series D distributions plus the Series D Partial Period Distributions. If a holder of Series D Preferred Units exercises its redemption right, the Partnership may elect to pay up to 50% of such amount in common units (which shall be valued at 93% of a volume-weighted average trading price of the common units); provided, that the common units to be issued do not, in the aggregate, exceed 15% of NuStar Energy’s common equity market capitalization at the time.

Series D Preferred Units Change of Control

Upon certain events involving a change of control, each holder of the Series D Preferred Units may elect to: (i) convert its Series D Preferred Units into common units on a one-for-one basis, plus any unpaid Series D distributions; (ii) require the Partnership to redeem its Series D Preferred Units for an amount equal to the sum of (a) $29.82 per Series D Preferred Unit plus (b) any unpaid Series D distributions plus (c) the applicable distribution amount for the distribution periods ending after the change of control event and prior to (but including) the fourth anniversary of the Initial Closing; (iii) if the Partnership is the surviving entity and its common units continue to be listed, continue to hold its Series D Preferred Units; or (iv) if the Partnership will not be the surviving entity, or it will be the surviving entity but its common units will cease to be listed, require the Partnership to use its commercially reasonable efforts to deliver a security in the surviving entity that has substantially similar terms as the Series D Preferred Units; however, if the Partnership is unable to deliver a mirror security, each holder is still entitled to option (i) or (ii) above.

Series D Preferred Units Accounting Treatment

The Series D Preferred Units include redemption provisions at the option of the holders of the Series D Preferred Units and upon a Series D Change of Control (as defined in the partnership agreement), which are outside the Partnership’s control. Therefore, the Series D Preferred Units are presented in the mezzanine section of the consolidated balance sheets. The Series D Preferred Units have been recorded at their issuance date fair value, net of issuance costs. We reassess the presentation of the Series D Preferred Units in our consolidated balance sheets on a quarterly basis.

The Series D Preferred Units are subject to accretion from their carrying value at the issuance date to the redemption value, which is based on the redemption right of the Series D Preferred Unit holders that may be exercised at any time on or after June 29, 2028, using the effective interest method over a period of ten years. In the calculation of net income per unit, the

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accretion is treated in the same manner as a distribution and deducted from net income to arrive at net income attributable to common units.

18. PARTNERS’ EQUITY

Series A, B and C Preferred Units

The following is a summary of 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) issued and outstanding as of December 31, 2021:

Units	Original Issuance Date	Number of Units Issued and Outstanding	Price per Unit		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 (in thousands of dollars)		Optional Redemption Date/Date at Which Distribution Rate Becomes Floating	Floating Annual Rate (as a Percentage of the $25.00 Liquidation Preference per Unit)
Series A Preferred Units	November 25, 2016	9,060,000	$	25.00	8.50	%	$	2.125	$	19,252	December 15, 2021	Three-month LIBOR plus 6.766%
Series B Preferred Units	April 28, 2017	15,400,000	$	25.00	7.625	%	$	1.90625	$	29,357	June 15, 2022	Three-month LIBOR plus 5.643%
Series C Preferred Units	November 30, 2017	6,900,000	$	25.00	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

Distributions on the Series A, B and C Preferred Units are payable out of any legally available funds, accrue and are cumulative from the original issuance dates, and are payable on the 15th day (or the next business day) of each of March, June, September and December of each year to holders of record on the first business day of each payment month. The Series A, B and C Preferred Units rank equal to each other and to the Series D Preferred Units, and senior to all of our other classes of equity securities with respect to distribution rights and rights upon liquidation.

In January 2022, our board of directors declared quarterly distributions with respect to the Series A, B and C Preferred Units to be paid on March 15, 2022.

We may redeem any of our outstanding Series A, B and C Preferred Units at any time on or after the optional redemption date set forth above for each series of the Series A, B and C Preferred Units, in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions to, but not including, the date of redemption, whether or not declared. We may also redeem the Series A, B and C Preferred Units upon the occurrence of certain rating events or a change of control as defined in our partnership agreement. In the case of the latter instance, if we choose not to redeem the Series A, B and C Preferred Units, those preferred unitholders may have the ability to convert their Series A, B and C Preferred Units to common units at the then applicable conversion rate. Holders of the Series A, B and C Preferred Units have no voting rights except for certain exceptions set forth in our partnership agreement.

Common Units

Issuances of Common Units. In the fourth quarter of 2019, we 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. We used the proceeds of $15.0 million from the sale of these units for general partnership purposes.

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The following table shows the balance of and changes in the number of our common units outstanding:

	Year Ended December 31,
	2021	2020	2019
Balance as of the beginning of year	109,468,127	108,527,806	107,225,156
Issuance of units	—	—	527,426
Unit-based compensation (refer to Note 22 for discussion)	518,146	940,321	775,224
Balance as of the end of year	109,986,273	109,468,127	108,527,806

Cash Distributions. We make quarterly distributions to common unitholders of 100% of our “Available Cash,” generally defined as cash receipts less cash disbursements, including distributions to our preferred units, and cash reserves established by the general partner, in its sole discretion. These quarterly distributions are declared and paid within 45 days subsequent to each quarter-end. The common unitholders receive a distribution each quarter as determined by the board of directors, subject to limitation by the distributions in arrears, if any, on our preferred units.

The following table summarizes information about cash distributions to our common limited partners applicable to the period in which the distributions were earned:

	Cash Distributions Per Unit		Total Cash Distributions		Record Date	Payment Date
			(Thousands of Dollars)
Quarter ended:
December 31, 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
Year ended December 31, 2019	$	2.40	$	259,136

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Accumulated Other Comprehensive Income (Loss)

The balance of and changes in the components included in AOCI were as follows:

	Foreign Currency Translation		Cash Flow Hedges		Pension and Other Postretirement Benefits		Total
	(Thousands of Dollars)
Balance as of January 1, 2019	$	(47,299)	$	(893)	$	(6,686)	$	(54,878)
Other comprehensive income (loss) before reclassification adjustments	3,527		(19,045)		1,000		(14,518)
Net gain on pension costs reclassified into other income, net	—		—		(2,314)		(2,314)
Net loss on cash flow hedges reclassified into interest expense, net	—		3,814		—		3,814
Other comprehensive income (loss)	3,527		(15,231)		(1,314)		(13,018)
Balance as of December 31, 2019	(43,772)		(16,124)		(8,000)		(67,896)
Other comprehensive income (loss) before reclassification adjustments	1,410		(30,291)		(2,924)		(31,805)
Net gain on pension costs reclassified into other income, net	—		—		(1,220)		(1,220)
Net loss on cash flow hedges reclassified into interest expense, net	—		4,265		—		4,265
Other comprehensive income (loss)	1,410		(26,026)		(4,144)		(28,760)
Balance as of December 31, 2020	(42,362)		(42,150)		(12,144)		(96,656)
Other comprehensive income before reclassification adjustments	601		—		17,721		18,322
Net gain on pension costs reclassified into other income, net	—		—		(1,308)		(1,308)
Net loss on cash flow hedges reclassified into interest expense, net	—		5,664		—		5,664
Other comprehensive income	601		5,664		16,413		22,678
Balance as of December 31, 2021	$	(41,761)	$	(36,486)	$	4,269	$	(73,978)

19. NET INCOME (LOSS) PER COMMON UNIT

As discussed in Note 17, the Series D Preferred Units are convertible into common units at the option of the holder at any time on or after June 29, 2020. As such, we calculated the dilutive effect of the Series D Preferred Units using the if-converted method. The effect of the assumed conversion of the Series D Preferred Units outstanding was antidilutive for each of the years ended December 31, 2021, 2020 and 2019; therefore, we did not include such conversion in the computation of diluted net (loss) income per common unit.

Contingently issuable performance units are included as dilutive potential common units if it is probable that the performance measures will be achieved, unless to do so would be antidilutive. For the years ended December 31, 2021 and 2020, we determined that it was probable that the performance measures would be achieved, but the effect would be antidilutive; therefore, we did not include any contingently issuable performance units as dilutive common units in the computation below.

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The following table details the calculation of net income (loss) per common unit:

	Year Ended December 31,
	2021		2020		2019
	(Thousands of Dollars, Except Unit and Per Unit Data)
Net income (loss)	$	38,225	$	(198,983)	$	(105,693)
Distributions to preferred limited partners	(127,399)		(124,882)		(121,693)
Distributions to common limited partners	(175,470)		(174,873)		(259,136)
Distribution equivalent rights to restricted units	(2,396)		(2,093)		(2,659)
Distributions in excess of income (loss)	$	(267,040)	$	(500,831)	$	(489,181)
Distributions to common limited partners	$	175,470	$	174,873	$	259,136
Allocation of distributions in excess of income (loss)	(267,040)		(500,831)		(489,181)
Series D Preferred Unit accretion (refer to Note 17)	(16,903)		(17,626)		(18,085)
Net loss attributable to common units	$	(108,473)	$	(343,584)	$	(248,130)
Basic weighted-average common units outstanding	109,585,635		109,155,117		107,789,030
Diluted common units outstanding:
Basic weighted-average common units outstanding	109,585,635		109,155,117		107,789,030
Effect of dilutive potential common units	—		—		65,669
Diluted weighted-average common units outstanding	109,585,635		109,155,117		107,854,699
Basic and diluted net loss per common unit	$	(0.99)	$	(3.15)	$	(2.30)

20. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in current assets and current liabilities were as follows:

	Year Ended December 31,
	2021		2020		2019
	(Thousands of Dollars)
Decrease (increase) in current assets:
Accounts receivable	$	(2,105)	$	14,589	$	(23,480)
Inventories	(5,585)		1,340		(866)
Prepaid and other current assets	(1,710)		(3,326)		(5,103)
Increase (decrease) in current liabilities:
Accounts payable	10,202		(25,455)		8,068
Accrued interest payable	(16,708)		12,922		1,632
Accrued liabilities	4,448		7,886		(19,740)
Taxes other than income tax	(2,689)		3,972		(5,276)
Changes in current assets and current liabilities	$	(14,147)	$	11,928	$	(44,765)

The above changes in current assets and current liabilities differ from changes between amounts reflected in the applicable consolidated balance sheets due to:

•the change in the amount accrued for capital expenditures;

•the effect of foreign currency translation;

•payments for the termination of interest rate swaps included in cash flows from financing activities;

•the effect of accrued compensation expense paid with fully vested common unit awards;

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•the reclassification of certain assets and liabilities to “Assets held for sale” and “Liabilities held for sale” on the consolidated balance sheets (please refer to Note 4 for additional discussion); and

•current assets and current liabilities disposed of during the period.

Cash flows related to interest and income taxes were as follows:

	Year Ended December 31,
	2021		2020		2019
	(Thousands of Dollars)
Cash paid for interest, net of amount capitalized	$	218,181	$	204,511	$	176,859
Cash paid for income taxes, net of tax refunds received	$	5,491	$	3,260	$	6,817

Restricted cash is included in "Other long-term assets, net" on the consolidated balance sheets. “Cash, cash equivalents and restricted cash” on the consolidated statements of cash flows was included in the consolidated balance sheets as follows:

	December 31,
	2021		2020
	(Thousands of Dollars)
Cash and cash equivalents	$	5,637	$	153,625
Other long-term assets, net	8,802		8,801
Cash, cash equivalents and restricted cash	$	14,439	$	162,426

21. EMPLOYEE BENEFIT PLANS

Thrift Plans

The NuStar Thrift Plan (the Thrift Plan) is a qualified defined contribution plan that became effective June 26, 2006. Participation in the Thrift Plan is voluntary and open to substantially all our domestic employees upon their dates of hire. Thrift Plan participants can contribute from 1% up to 30% of their total annual compensation to the Thrift Plan in the form of pre-tax and/or after tax employee contributions. We make matching contributions in an amount equal to 100% of each participant’s employee contributions up to a maximum of 6% of the participant’s total annual compensation. The matching contributions to the Thrift Plan for the years ended December 31, 2021, 2020 and 2019 totaled $7.6 million, $7.8 million and $7.6 million, respectively.

The NuStar Excess Thrift Plan (the Excess Thrift Plan) is a nonqualified deferred compensation plan that became effective July 1, 2006. The Excess Thrift Plan provides benefits to those employees whose compensation and/or annual contributions under the Thrift Plan are subject to the limitations applicable to qualified retirement plans under the Code.

We also maintain other defined contribution plans for certain international employees located in Canada. We maintained plans for international employees in the Caribbean Netherlands prior to the St. Eustatius Disposition on July 29, 2019. For the years ended December 31, 2021, 2020 and 2019, our costs for these plans totaled $0.6 million, $0.5 million and $0.9 million, respectively.

Pension and Other Postretirement Benefits

The NuStar Pension Plan (the Pension Plan) is a qualified non-contributory defined benefit pension plan that provides eligible U.S. employees with retirement income as calculated under a cash balance formula. Under the cash balance formula, benefits are determined based on age, years of vesting service and interest credits, and employees become fully vested in their benefits upon attaining three years of vesting service. Prior to January 1, 2014, eligible employees were covered under either a cash balance formula or a final average pay formula (FAP). Effective January 1, 2014, the Pension Plan was amended to freeze the FAP benefits as of December 31, 2013, and going forward, all eligible employees are covered under the cash balance formula discussed above.

We also maintain an excess pension plan (the Excess Pension Plan), which is a nonqualified deferred compensation plan that provides benefits to a select group of management or other highly compensated employees. Neither the Excess Thrift Plan nor the Excess Pension Plan is intended to constitute either a qualified plan under the provisions of Section 401 of the Code or a funded plan subject to the Employee Retirement Income Security Act.

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The Pension Plan and Excess Pension Plan are collectively referred to as the Pension Plans in the tables and discussion below. Our other postretirement benefit plans include a contributory medical benefits plan for U.S. employees who retired prior to April 1, 2014 and, for employees who retire on or after April 1, 2014, a partial reimbursement for eligible third-party health care premiums. We use December 31 as the measurement date for our pension and other postretirement plans.

The changes in the benefit obligation, the changes in fair value of plan assets, the funded status and the amounts recognized in the consolidated balance sheets for our Pension Plans and other postretirement benefit plans as of and for the years ended December 31, 2021 and 2020 were as follows:

	Pension Plans				Other Postretirement Benefit Plans
	2021		2020		2021		2020
	(Thousands of Dollars)
Change in benefit obligation:
Benefit obligation, January 1	$	186,685	$	167,257	$	14,680	$	13,196
Service cost	9,978		9,174		593		529
Interest cost	4,084		4,693		326		399
Benefits paid (a)	(19,366)		(9,520)		(257)		(281)
Participant contributions	—		—		44		44
Actuarial (gain) loss	(694)		15,081		884		793
Other	(780)		—		—		—
Benefit obligation, December 31	$	179,907	$	186,685	$	16,270	$	14,680
Change in plan assets:
Plan assets at fair value, January 1	$	182,727	$	159,036	$	—	$	—
Actual return on plan assets	26,425		21,758		—		—
Employer contributions	52		11,453		213		237
Benefits paid (a)	(19,366)		(9,520)		(257)		(281)
Participant contributions	—		—		44		44
Plan assets at fair value, December 31	$	189,838	$	182,727	$	—	$	—
Reconciliation of funded status:
Fair value of plan assets at December 31	$	189,838	$	182,727	$	—	$	—
Less: Benefit obligation at December 31	179,907		186,685		16,270		14,680
Funded status at December 31	$	9,931	$	(3,958)	$	(16,270)	$	(14,680)
Amounts recognized in the consolidated balance sheets (b):
Other long-term assets, net	$	14,945	$	—	$	—	$	—
Accrued liabilities	(467)		(382)		(442)		(352)
Other long-term liabilities	(4,547)		(3,576)		(15,828)		(14,328)
Net pension asset (liability)	$	9,931	$	(3,958)	$	(16,270)	$	(14,680)
Accumulated benefit obligation	$	171,899	$	181,263	$	16,270	$	14,680

(a)Benefit payments for the year ended December 31, 2021 include lump-sum payments of $9.6 million to participants of the Pension Plans following the Eastern U.S. Terminals Disposition on October 8, 2021 and the Texas City Sale on December 7, 2020.

(b)For the Pension Plan, since assets exceed the present value of expected benefit payments for the next 12 months, all of the liability is noncurrent. For the Excess Pension Plan and the other postretirement benefit plans, since there are no assets, the current liability is the present value of expected benefit payments for the next 12 months; the remainder is noncurrent.

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The actuarial (gain) loss related to the benefit obligation for our pension plans was primarily attributable to an increase in the discount rates used to determine the benefit obligation from 2.84% to 3.10% in 2021 and a decrease from 3.34% to 2.84% in 2020. The fair value of our plan assets is affected by the return on plan assets resulting primarily from the performance of equity and bond markets during the period.

The Excess Pension Plan has no plan assets and an accumulated benefit obligation of $4.3 million and $3.8 million as of December 31, 2021 and 2020, respectively. The accumulated benefit obligation is the present value of benefits earned to date, while the projected benefit obligation may include future salary increase assumptions. The projected benefit obligation for the Excess Pension Plan was $5.0 million and $3.8 million as of December 31, 2021 and 2020, respectively.

The components of net periodic benefit cost (income) related to our Pension Plans and other postretirement benefit plans were as follows:

	Pension Plans						Other Postretirement Benefit Plans
	Year Ended December 31,						Year Ended December 31,
	2021		2020		2019		2021		2020		2019
	(Thousands of Dollars)
Service cost	$	9,978	$	9,174	$	9,549	$	593	$	529	$	431
Interest cost	4,084		4,693		5,480		326		399		453
Expected return on plan assets	(9,233)		(8,972)		(8,015)		—		—		—
Amortization of prior service credit	(2,057)		(2,057)		(2,057)		(1,145)		(1,145)		(1,145)
Amortization of net actuarial loss	2,279		1,845		846		176		137		42
Other	(561)		136		—		—		—		—
Net periodic benefit cost (income)	$	4,490	$	4,819	$	5,803	$	(50)	$	(80)	$	(219)

We amortize prior service costs and credits on a straight-line basis over the average remaining service period of employees expected to receive benefits under our Pension Plans and other postretirement benefit plans (“Amortization of prior service credit” in table above). We amortize the actuarial gains and losses that exceed 10% of the greater of the projected benefit obligation or market-related value of plan assets (smoothed asset value) over the average remaining service period of active employees expected to receive benefits under our Pension Plans and other postretirement benefit plans (“Amortization of net actuarial loss” in table above).

The service cost component of net periodic benefit cost (income) is reported in “General and administrative expenses” and “Operating expenses” on the consolidated statements of income (loss), and the remaining components of net periodic benefit cost (income) are reported in “Other income (expense), net.”

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Adjustments to other comprehensive income (loss) related to our Pension Plans and other postretirement benefit plans were as follows:

	Pension Plans						Other Postretirement Benefit Plans
	Year Ended December 31,						Year Ended December 31,
	2021		2020		2019		2021		2020		2019
	(Thousands of Dollars)
Net unrecognized gain (loss) arising during the year:
Net actuarial gain (loss)	$	18,666	$	(2,159)	$	2,545	$	(884)	$	(793)	$	(1,559)
Net (gain) loss reclassified into income:
Amortization of prior service credit	(2,057)		(2,057)		(2,057)		(1,145)		(1,145)		(1,145)
Amortization of net actuarial loss	2,279		1,845		846		176		137		42
Other	(561)		—		—		—		—		—
Net gain reclassified into income	(339)		(212)		(1,211)		(969)		(1,008)		(1,103)
Income tax (expense) benefit	(61)		28		14		—		—		—
Total changes to other comprehensive income (loss)	$	18,266	$	(2,343)	$	1,348	$	(1,853)	$	(1,801)	$	(2,662)

The amounts recorded as a component of “Accumulated other comprehensive loss” on the consolidated balance sheets related to our Pension Plans and other postretirement benefit plans were as follows:

	Pension Plans				Other Postretirement Benefit Plans
	December 31,				December 31,
	2021		2020		2021		2020
	(Thousands of Dollars)
Unrecognized actuarial loss	$	(3,748)	$	(24,878)	$	(4,554)	$	(3,846)
Prior service credit	7,630		10,433		4,884		6,029
Deferred tax asset	57		118		—		—
Accumulated other comprehensive income (loss), net of tax	$	3,939	$	(14,327)	$	330	$	2,183

Investment Policies and Strategies

The investment policies and strategies for the assets of our qualified Pension Plan incorporate a well-diversified approach that is expected to earn long-term returns from capital appreciation and a growing stream of current income. This approach recognizes that assets are exposed to risk, and the market value of the Pension Plan’s assets may fluctuate from year to year. Risk tolerance is determined based on our financial ability to withstand risk within the investment program and the willingness to accept return volatility. In line with the investment return objective and risk parameters, the Pension Plan’s mix of assets includes a diversified portfolio of equity and fixed-income instruments. The aggregate asset allocation is reviewed on an annual basis. As of December 31, 2021, the target allocations for plan assets were 65% equity securities and 35% fixed income investments, with certain fluctuations permitted.

The overall expected long-term rate of return on plan assets for the Pension Plan is estimated using various models of asset returns. Model assumptions are derived using historical data with the assumption that capital markets are informationally efficient. Three models are used to derive the long-term expected returns for each asset class. Since each method has distinct advantages and disadvantages and differing results, an equal weighted average of the methods’ results is used.

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Fair Value of Plan Assets

We disclose the fair value for each major class of plan assets in the Pension Plan in three levels: Level 1, defined as observable inputs such as quoted prices for identical assets or liabilities in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable, such as quoted prices for similar assets or liabilities in active markets or quoted prices for identical assets or liabilities in markets that are not active; and Level 3, defined as unobservable inputs for which little or no market data exists.

The major classes of plan assets measured at fair value for the Pension Plan were as follows:

	December 31, 2021
	Level 1		Level 2		Level 3		Total
	(Thousands of Dollars)
Cash equivalent securities	$	710	$	—	$	—	$	710
Equity securities:
U.S. large cap equity fund (a)	—		110,672		—		110,672
International stock index fund (b)	17,708		—		—		17,708
Fixed income securities:
Bond market index fund (c)	60,748		—		—		60,748
Total	$	79,166	$	110,672	$	—	$	189,838

	December 31, 2020
	Level 1		Level 2		Level 3		Total
	(Thousands of Dollars)
Cash equivalent securities	$	2,125	$	—	$	—	$	2,125
Equity securities:
U.S. large cap equity fund (a)	—		104,857		—		104,857
International stock index fund (b)	20,732		—		—		20,732
Fixed income securities:
Bond market index fund (c)	55,013		—		—		55,013
Total	$	77,870	$	104,857	$	—	$	182,727

(a)This fund is a low-cost equity index fund not actively managed that tracks the S&P 500. Fair values were estimated using pricing models, quoted prices of securities with similar characteristics or discounted cash flows.

(b)This fund tracks the performance of the Total International Composite Index.

(c)This fund tracks the performance of the Barclays Capital U.S. Aggregate Bond Index.

Contributions to the Pension Plans

For the year ended December 31, 2021, we contributed $0.1 million and $0.2 million to the Pension Plans and other postretirement benefit plans, respectively. During 2022, we expect to contribute approximately $9.5 million and $0.4 million to the Pension Plans and other postretirement benefit plans, respectively. 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.

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Estimated Future Benefit Payments

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid for the years ending December 31:

	Pension Plans		Other Postretirement Benefit Plans
	(Thousands of Dollars)
2022	$	10,652	$	442
2023	$	11,232	$	497
2024	$	11,212	$	531
2025	$	12,266	$	582
2026	$	12,109	$	640
2027-2031	$	65,477	$	4,003

Assumptions

The weighted-average assumptions used to determine the benefit obligations were as follows:

	Pension Plans				Other Postretirement Benefit Plans
	December 31,				December 31,
	2021		2020		2021		2020
Discount rate	3.10	%	2.84	%	3.08	%	2.83	%
Rate of compensation increase	3.99	%	3.51	%	n/a		n/a
Cash balance interest crediting rate	2.00	%	2.00	%	n/a		n/a

The weighted-average assumptions used to determine the net periodic benefit cost (income) were as follows:

	Pension Plans						Other Postretirement Benefit Plans
	Year Ended December 31,						Year Ended December 31,
	2021		2020		2019		2021		2020		2019
Discount rate	2.84	%	3.34	%	4.40	%	2.83	%	3.43	%	4.53	%
Expected long-term rate of return on plan assets	6.00	%	6.50	%	6.50	%	n/a		n/a		n/a
Rate of compensation increase	3.51	%	3.51	%	3.51	%	n/a		n/a		n/a
Cash balance interest crediting rate	2.00	%	2.00	%	2.90	%	n/a		n/a		n/a

The assumed health care cost trend rates were as follows:

	December 31,
	2021		2020
Health care cost trend rate assumed for next year	6.84	%	6.84	%
Rate to which the cost trend rate was assumed to decrease (the ultimate trend rate)	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2028		2028

We sponsor a contributory postretirement health care plan for employees who retired prior to April 1, 2014. The plan has an annual limitation (a cap) on the increase of the employer’s share of the cost of covered benefits. The cap on the increase in employer’s cost is 2.5% per year.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

22. UNIT-BASED COMPENSATION

Overview

2019 LTIP. In April 2019, our common unitholders approved the 2019 Long-Term Incentive Plan (2019 LTIP) for eligible employees, consultants and directors of NuStar Energy L.P., and of NuStar GP, LLC, and their respective affiliates who perform services for us and our subsidiaries. The 2019 LTIP allows for the awarding of (i) options; (ii) restricted units; (iii) distribution equivalent rights (DERs); (iv) performance cash; (v) performance units; and (vi) unit awards. DERs entitle the participant to receive cash equal to cash distributions made on any award prior to its vesting. The 2019 LTIP, as amended and restated on April 29, 2021, permits the granting of awards totaling an aggregate of 5,000,000 common units, and is subject to adjustment. The 2019 LTIP generally will be administered by the compensation committee of our board of directors. As of December 31, 2021, a total of 2,179,072 common units remained available to be awarded under the 2019 LTIP.

Other Plans. We sponsor the NuStar GP, LLC Fifth Amended and Restated 2000 Long-Term Incentive Plan, as amended (2000 LTIP), and the NuStar GP Holdings, LLC Long-Term Incentive Plan, as amended (2006 LTIP). Effective with the approval of the 2019 LTIP in April 2019, the 2000 LTIP and the 2006 LTIP terminated with respect to new grants; however, unvested restricted unit awards granted under the 2000 LTIP and the 2006 LTIP remain outstanding as of December 31, 2021.

The following table summarizes information pertaining to all of our long-term incentive plans:

	Units Outstanding December 31,			Compensation Expense Year Ended December 31,
	2021	2020	2019	2021		2020		2019
				(Thousands of Dollars)
Restricted units:
Domestic employees	2,520,436	2,235,125	1,223,143	$	11,892	$	10,205	$	9,437
Non-employee directors (NEDs)	129,312	98,769	61,349	856		631		774
International employees	21,760	19,987	10,243	139		58		711
Performance awards	33,695	87,122	161,561	3,047		1,291		4,172
Unit awards	—	—	—	4,645		—		22,941
Total	2,705,203	2,441,003	1,456,296	$	20,579	$	12,185	$	38,035

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Restricted Units

Our restricted unit awards are considered phantom units, as they represent the right to receive our common units upon vesting. We account for restricted units as either equity-classified awards or liability-classified awards, depending on expected method of settlement. Awards we settle with the issuance of common units upon vesting are equity-classified. Awards we settle in cash upon vesting are liability-classified. We record compensation expense ratably over the vesting period based on the fair value of the common units at the grant date (for domestic employees and NEDs) or the fair value of the common units measured at each reporting period (for international employees). DERs paid with respect to outstanding equity-classified unvested restricted units reduce equity, similar to cash distributions to unitholders, whereas DERs paid with respect to outstanding liability-classified unvested restricted units are expensed. In connection with the DERs for equity awards, we paid $2.4 million, $2.1 million and $2.7 million respectively, in cash, for the years ended December 31, 2021, 2020 and 2019.

Domestic Employees. The outstanding restricted units granted to domestic employees are equity-classified awards and generally vest over five years, beginning one year after the grant date. The fair value of these awards is measured at the grant date.

Non-Employee Directors. The outstanding restricted units granted to NEDs are equity-classified awards that vest over three years. On January 1, 2019 we adopted amended guidance that allows for the fair value of these awards to be measured at the grant date. The unvested restricted units granted to NEDs as of January 1, 2019 were measured at the fair value as of that date. Previously, the fair value of these awards was equal to the market price of our common units at each reporting period.

International Employees. The outstanding restricted units granted to international employees are cash-settled and accounted for as liability-classified awards. These awards vest over three years and the fair value is equal to the market price of our common units at each reporting period. For the year ended December 31, 2021, we granted 10,396 restricted units and 8,344 restricted units vested.

A summary of our equity-classified restricted unit awards is as follows:

	Measured at Grant Date Fair Value
	Number of Units	Weighted-Average Fair Value Per Unit
Nonvested units as of January 1, 2019 (a)	1,088,236	$	29.00
Granted	596,881	26.46
Vested	(328,386)	30.11
Forfeited	(72,239)	28.05
Nonvested units as of December 31, 2019	1,284,492	27.48
Granted	1,454,998	12.10
Vested	(374,847)	28.47
Forfeited	(30,749)	26.75
Nonvested units as of December 31, 2020	2,333,894	17.70
Granted	1,049,081	16.28
Vested	(630,888)	20.07
Forfeited	(102,339)	14.28
Nonvested units as of December 31, 2021	2,649,748	16.57

(a) Upon adoption of amended guidance, nonvested units include 59,752 units issued to NEDs which were measured at a fair value per unit of $20.93.

The total fair value of our equity-classified restricted unit awards vested for the years ended December 31, 2021, 2020 and 2019 was $10.3 million, $4.6 million and $9.3 million, respectively. We issued 460,076, 275,146 and 242,199 common units in connection with these award vestings, net of employee tax withholding requirements, for the years ended December 31, 2021, 2020 and 2019, respectively. Unrecognized compensation cost related to our equity-classified employee awards totaled $42.0 million as of December 31, 2021, which we expect to recognize over a weighted-average period of 3.7 years.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Performance Awards

Performance awards are issued to certain of our key employees and represent either rights to receive our common units or cash upon achieving performance measures for the performance period established by the NuStar GP, LLC Compensation Committee. Achievement of the performance measures determines the rate at which the performance awards convert into our common units or cash, which ranges from zero to 200% for certain awards.

Performance awards vest in three annual increments (tranches), based upon our achievement of the performance measures set by the Compensation Committee during the performance periods that end on December 31 of each applicable year. Therefore, the performance awards are not considered granted for accounting purposes until the Compensation Committee has set the performance measures for each tranche of awards. Performance unit awards are equity-classified awards measured at the grant date fair value. In addition, since the performance unit awards granted do not receive DERs, the grant date fair value of these awards is reduced by the per unit distributions expected to be paid to common unitholders during the vesting period. Performance cash awards are accounted for as a liability but may be settled in common units. We record compensation expense ratably for each vesting tranche over its requisite service period (one year) if it is probable that the specified performance measures will be achieved. Additionally, changes in the actual or estimated outcomes that affect the quantity of performance awards expected to be converted into common units or paid in cash, are recognized as a cumulative adjustment. Performance units vested relate to the performance for the performance period ended December 31 of the previous year.

A summary of our performance awards is shown below:

			Performance Unit Awards
				Granted for Accounting Purposes
	Performance Cash Awards		Total Performance Unit Awards Granted	Performance Unit Awards	Weighted-Average Grant Date Fair Value per Unit
	(Thousands of Dollars)
Outstanding as of January 1, 2019	$	—	158,326	80,690	$	23.43
Granted	—		95,969	74,439	28.01
Vested	—		(80,690)	(80,690)	23.43
Forfeitures	—		(12,044)	—	—
Outstanding as of December 31, 2019	—		161,561	74,439	28.01
Granted	2,167		—	57,448	13.21
Performance adjustment (a)	—		72,951	72,951	28.01
Vested	—		(147,390)	(147,390)	28.01
Outstanding as of December 31, 2020	2,167		87,122	57,448	13.21
Granted	2,254		4,021	33,695	15.79
Vested (b)	(672)		(53,427)	(53,427)	13.21
Forfeitures	(51)		(4,021)	(4,021)	13.21
Outstanding as of December 31, 2021	$	3,698	33,695	33,695	15.79

(a) For the year ended December 31, 2020, common units granted and issued upon vesting of performance units earned at 198% of the 2019 target.

(b) For the year ended December 31, 2021, we settled performance cash awards in common units and issued 26,704 common units, net of employee tax withholding requirements.

The total fair value of our performance unit awards vested for the years ended December 31, 2021, 2020 and 2019 was $0.8 million, $4.2 million and $2.1 million, respectively. For the years ended December 31, 2021, 2020, and 2019 we issued 31,366, 93,440 and 50,054 common units in connection with the performance unit award vestings, net of employee tax withholding requirements, respectively.

On January 27, 2022, we settled performance cash awards in common units, and together with the performance unit awards, we issued 114,618 common units, net of employee tax withholding requirements, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Unit Awards

Unit awards are equity-classified awards of fully vested common units. We accrued compensation expense in 2021 and 2019 that was paid in unit awards in the first quarters of the respective subsequent years. We base the number of unit awards granted on the fair value of the common units at the grant date. A summary of our unit awards is shown below:

Date of Grant	Grant Date Fair Value		Unit Awards Granted	Common Units Issued, Net of Employee Withholding Tax
	(Thousands of Dollars)
February 2022	$	4,645	280,685	186,190
February and March 2020	$	22,941	834,224	571,735

23. INCOME TAXES

Components of income tax expense related to certain of our continuing operations conducted through separate taxable wholly owned corporate subsidiaries were as follows:

	Year Ended December 31,
	2021		2020		2019
	(Thousands of Dollars)
Current:
U.S.	$	3,755	$	36	$	3,741
Foreign	221		2,415		1,489
Foreign withholding tax	1,281		—		101
Total current	5,257		2,451		5,331
Deferred:
U.S.	(93)		300		(490)
Foreign	(531)		(621)		(168)
Foreign withholding tax	(745)		533		182
Total deferred	(1,369)		212		(476)
Less: amounts reported in discontinued operations	—		—		101
Income tax expense	$	3,888	$	2,663	$	4,754

The difference between income tax expense recorded in our consolidated statements of income (loss) and income taxes computed by applying the applicable statutory federal income tax rate to income before income tax expense is due to the fact that the majority of our income is not subject to federal income tax due to our status as a limited partnership. We record a tax provision related to the amount of undistributed earnings of our foreign subsidiaries expected to be repatriated.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The tax effects of significant temporary differences representing deferred income tax assets and liabilities were as follows:

	December 31,
	2021		2020
	(Thousands of Dollars)
Deferred income tax assets:
Net operating losses	$	20,005	$	18,459
Employee benefits	83		134
Environmental and legal reserves	47		105
Capital loss	3,735		10,813
Other	495		834
Total deferred income tax assets	24,365		30,345
Less: Valuation allowance	(23,718)		(28,211)
Net deferred income tax assets	647		2,134
Deferred income tax liabilities:
Property, plant and equipment	(11,884)		(13,772)
Foreign withholding tax	(272)		(1,002)
Other	(322)		(371)
Total deferred income tax liabilities	(12,478)		(15,145)
Net deferred income tax liability	$	(11,831)	$	(13,011)

As of December 31, 2021, our U.S. and foreign corporate operations have net operating loss carryforwards for tax purposes totaling $63.4 million and $6.9 million, respectively, which are subject to various limitations on use and expire in years 2025 through 2034 for U.S. losses and in years 2021 through 2031 for foreign losses. However, U.S. losses generated after December 31, 2017, totaling $9.4 million, can be carried forward indefinitely. As of December 31, 2021, our U.S. corporate operations have a capital loss carryforward for tax purposes totaling $17.7 million, which is subject to limitations on use and expires in 2024. The capital loss carryforward decreased $33.8 million for the year ended December 31, 2021 due to changes in our estimates of loss carryforwards following the Texas City Sale.

As of December 31, 2021 and 2020, we have a valuation allowance of $23.7 million and $28.2 million, respectively, related to our deferred tax assets on net operating losses and capital losses. We estimate the amount of valuation allowance based upon our expectations of taxable income in the various jurisdictions in which we operate and the period over which we can utilize those future deductions. The valuation allowance reflects uncertainties related to our ability to utilize certain net operating loss carryforwards before they expire. In 2021, there was a $4.9 million decrease in the valuation allowance for the U.S. net operating loss and a $0.4 million increase in the foreign net operating loss valuation allowance due to changes in our estimates of the amount of loss carryforwards that will be realized, based upon future taxable income.

The realization of net deferred income tax assets recorded as of December 31, 2021 is dependent upon our ability to generate future taxable income in the United States. We believe it is more likely than not that the net deferred income tax assets as of December 31, 2021 will be realized, based on expected future taxable income.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

24. SEGMENT INFORMATION

Our reportable business segments consist of the pipeline, storage and fuels marketing segments. Our segments represent strategic business units that offer different services and products. We evaluate the performance of each segment based on its respective operating income, before general and administrative expenses and certain non-segmental depreciation and amortization expense. General and administrative expenses are not allocated to the operating segments since those expenses relate primarily to the overall management at the entity level. We are primarily engaged in the transportation, terminalling and storage of petroleum products and renewable fuels and the transportation of anhydrous ammonia. We also market petroleum products.

Results of operations for the reportable segments were as follows:

	Year Ended December 31,
	2021		2020		2019
	(Thousands of Dollars)
Revenues:
Pipeline	$	762,238	$	718,823	$	701,830
Storage	427,668		494,442		454,001
Fuels marketing	428,608		268,345		342,215
Consolidation and intersegment eliminations	(14)		(46)		(25)
Total revenues	$	1,618,500	$	1,481,564	$	1,498,021
Depreciation and amortization expense:
Pipeline	$	179,088	$	177,384	$	166,991
Storage	87,500		99,092		97,573
Total segment depreciation and amortization expense	266,588		276,476		264,564
Other depreciation and amortization expense	7,792		8,625		8,360
Total depreciation and amortization expense	$	274,380	$	285,101	$	272,924
Operating income:
Pipeline	$	321,472	$	118,429	$	332,480
Storage	24,800		189,781		154,105
Fuels marketing	11,181		12,233		20,578
Consolidation and intersegment eliminations	—		—		(32)
Total segment operating income	357,453		320,443		507,131
General and administrative expenses	113,207		102,716		107,855
Other depreciation and amortization expense	7,792		8,625		8,360
Total operating income	$	236,454	$	209,102	$	390,916

Revenues by geographic area are shown in the table below:

	Year Ended December 31,
	2021		2020		2019
	(Thousands of Dollars)
United States	$	1,582,672	$	1,441,892	$	1,465,135
Foreign	35,828		39,672		32,886
Consolidated revenues	$	1,618,500	$	1,481,564	$	1,498,021

For the years ended December 31, 2021, 2020 and 2019, Valero Energy Corporation accounted for approximately 19%, or $308.5 million, 20%, or $295.1 million, and 21%, or $307.2 million, of our revenues, respectively. These revenues were included in all of our reportable business segments. No other single customer accounted for 10% or more of our consolidated revenues.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Total amounts of property, plant and equipment, net by geographic area were as follows:

	December 31,
	2021		2020
	(Thousands of Dollars)
United States	$	3,428,441	$	3,837,550
Foreign	113,201		119,962
Consolidated property, plant and equipment, net	$	3,541,642	$	3,957,512

Total assets by reportable segment were as follows:

	December 31,
	2021		2020
	(Thousands of Dollars)
Pipeline	$	3,441,272	$	3,609,508
Storage	1,537,037		1,897,167
Fuels marketing	41,562		31,967
Total segment assets	5,019,871		5,538,642
Other partnership assets	136,461		278,376
Total consolidated assets	$	5,156,332	$	5,817,018

Capital expenditures by reportable segment were as follows:

	Year Ended December 31,
	2021		2020		2019
	(Thousands of Dollars)
Pipeline	$	67,340	$	122,512	$	387,702
Storage	112,043		71,788		141,972
Other partnership assets	1,750		3,779		3,894
Total capital expenditures	$	181,133	$	198,079	$	533,568

Capital expenditures have not been adjusted to separately disclose those capital expenditures related to discontinued operations, which are included in the storage segment totaling $28.0 million for the year ended December 31, 2019.

25. SUBSEQUENT EVENT

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. During February 2022, sale negotiations with the potential buyer progressed significantly and management with appropriate authority agreed to the sale. 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 utilize the sales proceeds to improve our debt metrics. The book value at closing is expected to exceed the agreed purchase price and result in an estimated non-cash loss in the range of $40.0 million to $50.0 million, primarily due to foreign currency translation losses accumulated since the acquisition of the Point Tupper facility in 2005.

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ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.CONTROLS AND PROCEDURES

DISCLOSURE CONTROLS AND PROCEDURES

Our management has evaluated, with the participation of the principal executive officer and principal financial officer of NuStar GP, LLC, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures were effective as of December 31, 2021.

INTERNAL CONTROL OVER FINANCIAL REPORTING

(a)Management’s Report on Internal Control over Financial Reporting.

Management’s report on NuStar Energy L.P.’s internal control over financial reporting appears in Item 8. of this Form 10-K, and is incorporated herein by reference.

(b)Attestation Report of the Registered Public Accounting Firm.

The report of KPMG LLP on NuStar Energy L.P.’s internal control over financial reporting appears in Item 8. of this Form 10-K, and is incorporated herein by reference.

(c)Changes in Internal Control over Financial Reporting.

There has been no change in our internal control over financial reporting that occurred during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B.OTHER INFORMATION

None.

ITEM 9C.DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

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PART III

ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information required to be disclosed under this Item 10 is incorporated by reference to the following sections of our Proxy Statement for the 2022 annual meeting of unitholders, which is expected to be filed within 120 days after the end of the fiscal year covered by this Form 10-K (Proxy Statement): “Corporate Governance-Board Leadership and Governance;” “Corporate Governance-Committees of the Board;” “Corporate Governance-Governance Documents and Codes of Ethics;” “Corporate Governance-Director Candidates;” “Corporate Governance-Communications with the Board of Directors;” “Proposal No. 1 Election of Directors;” and “Information About Our Executive Officers.”

ITEM 11.    EXECUTIVE COMPENSATION

Information required to be disclosed under this Item 11 is incorporated by reference to the following sections of our Proxy Statement: “Corporate Governance-Compensation Committee Interlocks and Insider Participation;” “Compensation Committee Report;” “Compensation Discussion and Analysis;” “Evaluation of Compensation Risk;” “Summary Compensation Table;” “Pay Ratio;” “Grants of Plan-Based Awards During the Year Ended December 31, 2021;” “Outstanding Equity Awards at December 31, 2021;” “Option Exercises and Units Vested During the Year Ended December 31, 2021;” “Pension Benefits for the Year Ended December 31, 2021;” “Nonqualified Deferred Compensation for the Year Ended December 31, 2021;” “Potential Payments Upon Termination or Change of Control;” and “Director Compensation.”

ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

Information required to be disclosed under this Item 12 is incorporated by reference to the following sections of our Proxy Statement: “Security Ownership-Security Ownership of Management and Directors;” “Security Ownership-Security Ownership of Certain Beneficial Owners;” and “Security Ownership-Equity Compensation Plan Information.”

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Information required to be disclosed under this Item 13 is incorporated by reference to the following sections of our Proxy Statement: “Corporate Governance-Director Independence;” “Corporate Governance-Board Leadership and Governance;” and “Certain Relationships and Related Party Transactions.”

ITEM 14.    PRINCIPAL ACCOUNTANT FEES AND SERVICES

Our independent registered public accounting firm is KPMG LLP, San Antonio, Texas, Auditor Firm ID: 185.

Information required to be disclosed under this Item 14 is incorporated by reference to the following sections of our Proxy Statement: “KPMG Fees;” and “Audit Committee Pre-Approval Policy.”

104

PART IV

ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)	(1)	Financial Statements. The following consolidated financial statements of NuStar Energy L.P. and its subsidiaries are included in Part II, Item 8 of this Form 10-K:
		Management’s Report on Internal Control over Financial Reporting Reports of Independent Registered Public Accounting Firm (KPMG LLP) Consolidated Balance Sheets as of December 31, 2021 and 2020 Consolidated Statements of Income (Loss) for the Years Ended December 31, 2021, 2020 and 2019 Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2021, 2020 and 2019 Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020 and 2019 Consolidated Statements of Partners’ Equity and Mezzanine Equity for the Years Ended December 31, 2021, 2020 and 2019 Notes to Consolidated Financial Statements
	(2)	Financial Statement Schedules and Other Financial Information. No financial statement schedules are submitted because either they are inapplicable or because the required information is included in the consolidated financial statements or notes thereto.
	(3)	Exhibits.
		The following are filed or furnished, as applicable, as part of this Form 10-K:

Exhibit Number	Description	Incorporated by Reference to the Following Document
3.01	Amended and Restated Certificate of Limited Partnership of Shamrock Logistics, L.P. (n/k/a NuStar Energy L.P.), effective January 1, 2002	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.3
3.02	Amendment to Certificate of Limited Partnership of Valero L.P. (n/k/a NuStar Energy L.P.), dated March 21, 2007 and effective April 1, 2007	NuStar Energy L.P.’s Current Report on Form 8-K filed March 27, 2007 (File No. 001-16417), Exhibit 3.01
3.03	Eighth Amended and Restated Agreement of Limited Partnership of NuStar Energy L.P., dated as of July 20, 2018	NuStar Energy L.P.’s Current Report on Form 8-K filed July 20, 2018 (File No. 001-16417), Exhibit 3.1
3.04	Amended and Restated Certificate of Limited Partnership of Shamrock Logistics Operations, L.P. (n/k/a NuStar Logistics, L.P.), dated as of January 7, 2002 and effective January 8, 2002	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.8
3.05	Certificate of Amendment to Certificate of Limited Partnership of Valero Logistics Operations, L.P. (n/k/a NuStar Logistics, L.P.), dated March 21, 2007 and effective April 1, 2007	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2007 (File No. 001-16417), Exhibit 3.03
3.06	Certificate of Amendment to Certificate of Limited Partnership of NuStar Logistics, L.P., dated and effective as of March 18, 2014	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2014 (File No. 001-16417), Exhibit 3.09
3.07	Second Amended and Restated Agreement of Limited Partnership of Shamrock Logistics Operations, L.P. (n/k/a NuStar Logistics, L.P.), dated as of April 16, 2001	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.9
3.08	First Amendment to Second Amended and Restated Agreement of Limited Partnership of Shamrock Logistics Operations, L.P. (n/k/a NuStar Logistics, L.P.), effective as of April 16, 2001	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2001 (File No. 001-16417), Exhibit 4.1
3.09	Second Amendment to Second Amended and Restated Agreement of Limited Partnership of Shamrock Logistics Operations, L.P. (n/k/a NuStar Logistics, L.P.), dated as of January 7, 2002	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.10

105

Exhibit Number	Description	Incorporated by Reference to the Following Document
3.10	Certificate of Limited Partnership of Riverwalk Logistics, L.P., dated as of June 5, 2000	NuStar Energy L.P.’s Registration Statement on Form S-1 filed August 14, 2000 (File No. 333-43668), Exhibit 3.7
3.11	First Amended and Restated Limited Partnership Agreement of Riverwalk Logistics, L.P., dated as of April 16, 2001	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.16
3.12	Certificate of Formation of Shamrock Logistics GP, LLC (n/k/a NuStar GP, LLC), dated as of December 7, 1999	NuStar Energy L.P.’s Registration Statement on Form S-1 filed August 14, 2000 (File No. 333-43668), Exhibit 3.9
3.13	Certificate of Amendment to Certificate of Formation of Shamrock Logistics GP, LLC (n/k/a NuStar GP, LLC), dated as of December 31, 2001	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.14
3.14	Certificate of Amendment to Certificate of Formation of Valero GP, LLC (n/k/a NuStar GP, LLC), dated March 21, 2007 and effective April 1, 2007	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2007 (File No. 001-16417), Exhibit 3.02
3.15	Second Amended and Restated Limited Liability Company Agreement of NuStar GP, LLC, dated as of July 20, 2018	NuStar Energy L.P.’s Current Report on Form 8-K filed July 20, 2018 (File No. 001-16417), Exhibit 3.2
4.01	Description of Securities	*
4.02	Indenture, dated as of July 15, 2002, among Valero Logistics Operations, L.P., as Issuer, Valero L.P., as Guarantor, and The Bank of New York, as Trustee, relating to Senior Debt Securities	NuStar Energy L.P.’s Current Report on Form 8-K filed July 15, 2002 (File No. 001-16417), Exhibit 4.1
4.03	Third Supplemental Indenture, dated as of July 1, 2005, to Indenture dated as of July 15, 2002, as amended and supplemented, among Valero Logistics Operations, L.P., Valero L.P., Kaneb Pipe Line Operating Partnership, L.P., and The Bank of New York Trust Company, N.A.	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.02
4.04	Instrument of Resignation, Appointment and Acceptance, dated March 31, 2008, among NuStar Logistics, L.P., NuStar Energy L.P., Kaneb Pipeline Operating Partnership, L.P., The Bank of New York Trust Company N.A., and Wells Fargo Bank, National Association	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2008 (File No. 001-16417), Exhibit 4.05
4.05	Eighth Supplemental Indenture, dated as of April 28, 2017, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, and Wells Fargo Bank, National Association, as Successor Trustee	NuStar Energy L.P.’s Current Report on Form 8-K filed April 28, 2017 (File No. 001-16417), Exhibit 4.4
4.06	Ninth Supplemental Indenture, dated as of May 22, 2019, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, and Wells Fargo Bank, National Association, as Successor Trustee	NuStar Energy L.P.’s Current Report on Form 8-K filed May 22, 2019 (File No. 001-16417), Exhibit 4.3
4.07	Tenth Supplemental Indenture, dated as of September 14, 2020, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, and Wells Fargo Bank, National Association, as Successor Trustee	NuStar Energy L.P.’s Current Report on Form 8-K filed September 14, 2020 (File No. 001-16417), Exhibit 4.3

106

Exhibit Number	Description	Incorporated by Reference to the Following Document
4.08	Indenture, dated as of January 22, 2013, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee, relating to Subordinated Debt Securities	NuStar Energy L.P.’s Current Report on Form 8-K filed January 22, 2013 (File No. 001-16417), Exhibit 4.1
4.09	First Supplemental Indenture, dated as of January 22, 2013, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Parent Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, and Wells Fargo Bank, National Association, as Trustee	NuStar Energy L.P.’s Current Report on Form 8-K filed January 22, 2013 (File No. 001-16417), Exhibit 4.2
4.10	Registration Rights Agreement, dated as of June 29, 2018, by and among NuStar Energy L.P. and the Purchasers party thereto	NuStar Energy L.P.’s Current Report on Form 8-K filed June 29, 2018 (File No. 001-16417), Exhibit 4.2
10.01	Second Amended and Restated 5-Year Revolving Credit Agreement, dated as of January 28, 2022, among NuStar Logistics, L.P., NuStar Energy L.P., NuStar Pipeline Operating Partnership L.P., Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto	NuStar Energy L.P.’s Current Report on Form 8-K filed January 31, 2022 (File No. 001-16417), Exhibit 10.01
10.02	Lease Agreement between the Parish of St. James, State of Louisiana and NuStar Logistics, L.P. dated as of June 1, 2008	NuStar Energy L.P.’s Current Report on Form 8-K filed June 5, 2020 (File No. 001-16417), Exhibit 10.1
10.03	First Supplement and Amendment to Lease Agreement (Series 2008), dated June 1, 2020, among the Parish of St. James, State of Louisiana, NuStar Logistics, L.P., NuStar Energy L.P. and NuStar Pipeline Operating Partnership L.P.	NuStar Energy L.P.’s Current Report on Form 8-K filed June 5, 2020 (File No. 001-16417), Exhibit 10.2
10.04	Lease Agreement Between Parish of St. James, State of Louisiana and NuStar Logistics, L.P. dated as of July 1, 2010	NuStar Energy L.P.’s Current Report on Form 8-K filed July 21, 2010 (File No. 001-16417), Exhibit 10.01
10.05	First Supplement and Amendment to Lease Agreement (Series 2010), dated June 1, 2020, among the Parish of St. James, State of Louisiana, NuStar Logistics, L.P., NuStar Energy L.P. and NuStar Pipeline Operating Partnership L.P.	NuStar Energy L.P.’s Current Report on Form 8-K filed June 5, 2020 (File No. 001-16417), Exhibit 10.4
10.06	Lease Agreement between the Parish of St. James, State of Louisiana and NuStar Logistics, L.P. dated as of October 1, 2010	NuStar Energy L.P.’s Current Report on Form 8-K filed June 5, 2020 (File No. 001-16417), Exhibit 10.5
10.07	First Supplement and Amendment to Lease Agreement (Series 2010A), dated June 1, 2020, among the Parish of St. James, State of Louisiana, NuStar Logistics, L.P., NuStar Energy L.P. and NuStar Pipeline Operating Partnership L.P.	NuStar Energy L.P.’s Current Report on Form 8-K filed June 5, 2020 (File No. 001-16417), Exhibit 10.6
10.08	Lease Agreement between Parish of St. James, State of Louisiana and NuStar Logistics, L.P. dated as of December 1, 2010	NuStar Energy L.P.’s Current Report on Form 8-K filed December 30, 2010 (File No. 001-16417), Exhibit 10.01

107

Exhibit Number	Description	Incorporated by Reference to the Following Document
10.09	First Supplement and Amendment to Lease Agreement (Series 2010B), dated June 1, 2020, among the Parish of St. James, State of Louisiana, NuStar Logistics, L.P., NuStar Energy L.P. and NuStar Pipeline Operating Partnership L.P.	NuStar Energy L.P.’s Current Report on Form 8-K filed June 5, 2020 (File No. 001-16417), Exhibit 10.8
10.10	Lease Agreement between Parish of St. James, State of Louisiana and NuStar Logistics, L.P. dated as of August 1, 2011	NuStar Energy L.P.’s Current Report on Form 8-K filed August 10, 2011 (File No. 001-16417), Exhibit 10.01
10.11	First Supplement and Amendment to Lease Agreement (Series 2011), dated June 1, 2020, among the Parish of St. James, State of Louisiana, NuStar Logistics, L.P., NuStar Energy L.P. and NuStar Pipeline Operating Partnership L.P.	NuStar Energy L.P.’s Current Report on Form 8-K filed June 5, 2020 (File No. 001-16417), Exhibit 10.10
10.12	Purchase and Sale Agreement, dated as of June 15, 2015, among NuStar Energy Services, Inc., NuStar Logistics, L.P., NuStar Pipeline Operating Partnership L.P. and NuStar Supply & Trading LLC, as Originators, NuStar Energy L.P., as Servicer, and NuStar Finance LLC, as Buyer	NuStar Energy L.P.'s Current Report on Form 8-K filed June 19, 2015 (File No. 001-16417), Exhibit 10.1
10.13	Receivables Financing Agreement, dated as of June 15, 2015, by and among NuStar Finance LLC, as Borrower, the persons from time to time party thereto as Lenders and Group Agents, PNC Bank, National Association, as Administrative Agent, and NuStar Energy L.P., as initial Servicer	NuStar Energy L.P.'s Current Report on Form 8-K filed June 19, 2015 (File No. 001-16417), Exhibit 10.2
10.14	Omnibus Amendment, dated as of January 15, 2016, which is the First Amendment to the Purchase and Sale Agreement referenced above and the First Amendment to the Receivables Financing Agreement referenced above among the respective parties thereto	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2015 (File No. 001-16417), Exhibit 10.26
10.15	Second Amendment to Purchase and Sale Agreement, dated as of September 20, 2017, by and among the Originators listed therein, NuStar Energy L.P., NuStar Finance LLC, Mizuho Bank, Ltd. and PNC Bank, National Association	NuStar Energy L.P.’s Current Report on Form 8-K filed September 20, 2017 (File No. 001-16417), Exhibit 10.01
10.16	Second Amendment to Receivables Financing Agreement, dated as of September 20, 2017, by and among NuStar Finance, LLC, as Borrower, NuStar Energy L.P., as initial Servicer, Mizuho Bank, Ltd. and PNC Bank, National Association	NuStar Energy L.P.’s Current Report on Form 8-K filed September 20, 2017 (File No. 001-16417), Exhibit 10.02
10.17	Third Amendment to Receivables Financing Agreement, dated as of March 28, 2018, by and among NuStar Finance, LLC, as Borrower, NuStar Energy L.P., as initial Servicer, Mizuho Bank, Ltd. and PNC Bank, National Association	NuStar Energy L.P.’s Current Report on Form 8-K filed March 28, 2018 (File No. 001-16417), Exhibit 10.01
10.18	Fourth Amendment to Receivables Financing Agreement, dated as of April 29, 2019, by and among NuStar Finance, LLC, as Borrower, NuStar Energy L.P., as initial Servicer, Mizuho Bank, Ltd. and PNC Bank, National Association	NuStar Energy L.P.’s Current Report on Form 8-K filed April 29, 2019 (File No. 001-16417), Exhibit 10.1

108

Exhibit Number	Description	Incorporated by Reference to the Following Document
10.19	Fifth Amendment to Receivables Financing Agreement, dated as of September 3, 2020, by and among NuStar Finance, LLC, as Borrower, NuStar Energy L.P., as initial Servicer, and PNC Bank, National Association	NuStar Energy L.P.’s Current Report on Form 8-K filed September 3, 2020 (File No. 001-16417), Exhibit 10.01
10.20	Sixth Amendment to Receivables Financing Agreement, dated as of January 28, 2022, by and among NuStar Finance, LLC, as Borrower, NuStar Energy L.P., as initial Servicer, and PNC Bank, National Association	NuStar Energy L.P.’s Current Report on Form 8-K filed January 31, 2022 (File No. 001-16417), Exhibit 10.02
+10.21	NuStar GP, LLC Fifth Amended and Restated 2000 Long-Term Incentive Plan, amended and restated as of January 28, 2016	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2017 (File No. 001-16417), Exhibit 10.30
+10.22	First Amendment to the NuStar GP, LLC Fifth Amended and Restated 2000 Long-Term Incentive Plan, dated as of February 7, 2018	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2017 (File No. 001-16417), Exhibit 10.31
+10.23	Form of Restricted Unit Award Agreement under the NuStar GP, LLC Fifth Amended and Restated 2000 Long-Term Incentive Plan	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2016 (File No. 001-16417), Exhibit 10.28
+10.24	Form of 2018 Non-employee Director Restricted Unit Award Agreement under the NuStar GP, LLC Fifth Amended and Restated 2000 Long-Term Incentive Plan	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2018 (File No. 001-16417), Exhibit 10.08
+10.25	NuStar GP Holdings, LLC Long-Term Incentive Plan, amended and restated as of April 1, 2007	NuStar GP Holdings, LLC’s Quarterly Report on Form 10-Q for quarter ended June 30, 2007 (File No. 001-32040), Exhibit 10.04
+10.26	First Amendment to the NuStar GP Holdings, LLC Long-Term Incentive Plan, dated as of February 7, 2018	NuStar GP Holdings, LLC’s Annual Report on Form 10-K for year ended December 31, 2017 (File No. 001-32040), Exhibit 10.46
+10.27	Form of Converted Award Agreement under the NuStar GP Holdings, LLC Amended and Restated Long-Term Incentive Plan	NuStar Energy L.P.’s Current Report on Form 8-K filed July 20, 2018 (File No. 001-16417), Exhibit 10.1
+10.28	Form of Restricted Unit Award Agreement under the NuStar GP Holdings, LLC Amended and Restated Long-Term Incentive Plan	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2018 (File No. 001-16417), Exhibit 10.06
+10.29	Form of Restricted Unit Award Agreement under the NuStar Energy L.P. 2019 Long-Term Incentive Plan	NuStar Energy L.P.’s Current Report on Form 8-K filed April 23, 2019 (File No. 001-16417), Exhibit 10.2
+10.30	Form of Non-employee Director Restricted Unit Award Agreement under the NuStar Energy L.P. 2019 Long-Term Incentive Plan	NuStar Energy L.P.’s Current Report on Form 8-K filed April 23, 2019 (File No. 001-16417), Exhibit 10.3
+10.31	Form of 2020 Performance Cash Award Agreement under the NuStar Energy L.P. 2019 Long-Term Incentive Plan	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2020 (File No. 001-16417), Exhibit 10.11
+10.32	Form of 2020 Restricted Unit Award Agreement under the NuStar Energy L.P. 2019 Long-Term Incentive Plan	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2020 (File No. 001-16417), Exhibit 10.43
+10.33	Amended and Restated NuStar Energy L.P. 2019 Long-Term Incentive Plan	NuStar Energy L.P.’s Current Report on Form 8-K filed April 30, 2021 (File No. 001-16417), Exhibit 10.1

109

Exhibit Number	Description	Incorporated by Reference to the Following Document
+10.34	Form of 2021 Performance Cash Award Agreement under the Amended and Restated NuStar Energy L.P. 2019 Long-Term Incentive Plan	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2021 (File No. 001-16417), Exhibit 10.02
+10.35	Form of 2021 Restricted Unit Award Agreement under the Amended and Restated NuStar Energy L.P. 2019 Long-Term Incentive Plan	*
+10.36	Form of 2021 Non-employee Director Restricted Unit Award Agreement under the NuStar Energy L.P. 2019 Long-Term Incentive Plan	*
+10.37	NuStar Energy L.P. Annual Bonus Plan	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2006 (File No. 001-16417), Exhibit 10.18
+10.38	Form of NuStar Energy L.P. Amended and Restated Change of Control Severance Agreement	NuStar Energy L.P.’s Current Report on Form 8-K filed August 4, 2016 (File No. 001-16417), Exhibit 10.1
+10.39	NuStar Excess Pension Plan, amended and restated effective as of January 1, 2014	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2015 (File No. 001-16417), Exhibit 10.45
+10.40	Amendment to NuStar Excess Pension Plan, effective October 9, 2018	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2018 (File No. 001-16417), Exhibit 10.04
+10.41	NuStar Excess Thrift Plan, amended and restated effective as of January 1, 2008	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2008 (File No. 001-16417), Exhibit 10.30
+10.42	Amendment to NuStar Excess Thrift Plan, effective as of January 1, 2017	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2017 (File No. 001-16417), Exhibit 10.02
+10.43	Amendment No. 2 to NuStar Excess Thrift Plan, effective October 9, 2018	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2018 (File No. 001-16417), Exhibit 10.05
10.44	Amended and Restated Aircraft Time Sharing Agreement, dated as of September 4, 2009, between NuStar Logistics, L.P. and William E. Greehey	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2009 (File No. 001-16417), Exhibit 10.24
10.45	First Amendment to Amended and Restated Aircraft Time Sharing Agreement, dated as of August 18, 2017, between NuStar Logistics, L.P. and William E. Greehey	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2017 (File No. 001-16417), Exhibit 10.02
21.01	List of subsidiaries of NuStar Energy L.P.	*
22.01	Subsidiary Guarantors and Issuers of Guaranteed Securities	*
23.01	Consent of KPMG LLP dated February 24, 2022	*
24.01	Powers of Attorney (included in signature page of this Form 10-K)	*
31.01	Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal executive officer	*
31.02	Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal financial officer	*

110

Exhibit Number	Description	Incorporated by Reference to the Following Document
32.01	Section 1350 Certification (under Section 906 of the Sarbanes-Oxley Act of 2002) of principal executive officer	**
32.02	Section 1350 Certification (under Section 906 of the Sarbanes-Oxley Act of 2002) of principal financial officer	**
101.INS	Inline XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.	*
101.SCH	Inline XBRL Taxonomy Extension Schema Document	*
101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase Document	*
101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase Document	*
101.LAB	Inline XBRL Taxonomy Extension Label Linkbase Document	*
101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase Document	*
104	Cover page Interactive Data File - Formatted in Inline XBRL and contained in Exhibit 101	*

*	Filed herewith.
**	Furnished herewith.
+	Identifies management contracts or compensatory plans or arrangements required to be filed as an exhibit hereto pursuant to Item 15 of Form 10-K.

An electronic copy of this Form 10-K is available on our website, free of charge, at www.nustarenergy.com

(select the “Investors” link, then the “SEC Filings” link). A paper copy of the Form 10-K also is available without charge to unitholders upon written request at the address below. Copies of exhibits filed as a part of this Form 10-K may be obtained by unitholders of record at a charge of $0.15 per page, minimum $5.00 each request. Direct inquiries to Corporate Secretary, NuStar Energy L.P., 19003 IH-10 West, San Antonio, Texas 78257 or

corporatesecretary@nustarenergy.com.

ITEM 16.    FORM 10-K SUMMARY

Not applicable.

111

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

NUSTAR ENERGY L.P.
(Registrant)
By:	Riverwalk Logistics, L.P., its general partner
	By: NuStar GP, LLC, its general partner
By:	/s/ Bradley C. Barron
	Bradley C. Barron
	President and Chief Executive Officer
	February 24, 2022
By:	/s/ Thomas R. Shoaf
	Thomas R. Shoaf
	Executive Vice President and Chief Financial Officer
	February 24, 2022
By:	/s/ Jorge A. del Alamo
	Jorge A. del Alamo
	Senior Vice President and Controller
	February 24, 2022

112

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints Bradley C. Barron, Thomas R. Shoaf and Amy L. Perry, or any of them, each with power to act without the other, his or her true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any or all subsequent amendments and supplements to this Annual Report on Form 10-K, and to file the same, or cause to be filed the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto each said attorney-in-fact and agent full power to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he or she might or could do in person, hereby qualifying and confirming all that said attorney-in-fact and agent or his or her substitute or substitutes may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ William E. Greehey	Chairman of the Board	February 24, 2022
William E. Greehey
/s/ Bradley C. Barron	President, Chief Executive	February 24, 2022
Bradley C. Barron	Officer and Director (Principal Executive Officer)
/s/ Thomas R. Shoaf	Executive Vice President	February 24, 2022
Thomas R. Shoaf	and Chief Financial Officer (Principal Financial Officer)
/s/ Jorge A. del Alamo	Senior Vice President and Controller	February 24, 2022
Jorge A. del Alamo	(Principal Accounting Officer)
/s/ J. Dan Bates	Director	February 24, 2022
J. Dan Bates
/s/ Jelynne LeBlanc Burley	Director	February 24, 2022
Jelynne LeBlanc Burley
/s/ William B. Burnett	Director	February 24, 2022
William B. Burnett
/s/ Ed A. Grier	Director	February 24, 2022
Ed A. Grier
/s/ Dan J. Hill	Director	February 24, 2022
Dan J. Hill
/s/ Robert J. Munch	Director	February 24, 2022
Robert J. Munch
/s/ W. Grady Rosier	Director	February 24, 2022
W. Grady Rosier
/s/ Martin Salinas, Jr.	Director	February 24, 2022
Martin Salinas, Jr.

113