TableTable of Contents

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] (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, 20172023
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
nustarlogoa02.jpg
NUSTAR ENERGYNuStar Energy L.P.
(Exact name of registrant as specified in its charter)
Delaware74-2956831
Delaware74-2956831
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
19003 IH-10 West78257
San Antonio, Texas(Zip Code)
(Address of principal executive offices)
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: Common units representing limited partner interests listed on the New York Stock Exchange. 8.50% Series A, 7.625% Series B and 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units representing limited partner interests listed on the New York Stock Exchange.
Title of each classTrading Symbol(s)Name of each exchange on
which registered
Common unitsNSNew York Stock Exchange
8.50% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred UnitsNSprANew York Stock Exchange
7.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred UnitsNSprBNew York Stock Exchange
9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred UnitsNSprCNew 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 [X]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
Yes [  ] No [X]
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 [X]þ No [  ]o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yes [X]þ No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”filer,” “smaller reporting company,” and “smaller reporting“emerging growth company” in Rule 12b-2 of the Exchange Act: 
Large accelerated filerþ[X]Accelerated filer[    ]☐
Non-accelerated filer☐[    ]  (Do not check if a smaller reporting company)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. ☑
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. o
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [    ]☐ No [X]þ
The aggregate market value of the common units held by non-affiliates was approximately $3,692 million$1.7 billion based on the last sales price quoted as of June 30, 2017,2023, the last business day of the registrant’s most recently completed second quarter.

The number of common units outstanding as of January 31, 20182024 was 93,182,018.126,532,875.

DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Proxy Statement for the registrant’s 2024 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.


TableTable of Contents

NUSTAR ENERGY L.P.
FORM 10-K


TABLE OF CONTENTS
 
PART I
PART I
Items 1., 1A.2. & 2.7
3
Overview
3
Recent DevelopmentsConsolidated Results of Operations
47
Organizational StructureSegments and Results of Operations
59
SegmentsLiquidity and Capital Resources
618
EmployeesHuman Capital
1527
Properties
28
Rate Regulation
1528
Environmental, Health, Safety and Security Regulation
1529
Critical Accounting Estimates
31
New Accounting Pronouncements
32
Available Information
32
Item 1A.
1833
Item 1B.
36
Item 1B.
Unresolved Staff Comments
3648
Item 1C.
48
Item 3.
3649
Item 4.
3649
PART II
PART II
Item 5.
3750
Item 6.
4051
Item 7.7A.
41
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
6452
Item 8.
6753
Item 9.
127102
Item 9A.
127102
Item 9B.
127102
Item 9C.
102
PART III
Item 10.
128103
Item 11.
132103
Item 12.
168103
Item 13.
171103
Item 14.
175103
PART IV
PART IV
Item 15.
176104
Item 16.
183111
184112





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PART I


Unless otherwise indicated, the terms “NuStar,” “NuStar Energy, L.P.,” “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, includingsuch as statements regarding our plans, strategies, objectives, expectations, estimates, predictions, projections, assumptions, intentions, resources and resources.the future impact of economic activity and the demand for or supply of crude oil, refined products, renewable fuel and anhydrous ammonia. 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,thatwhich may cause actual results to differ materially, including the possibility that the proposed merger described under “Recent Developments” below will not be completed prior to the August 8, 2018 outside termination date, the possibility that NuStar GP Holdings, LLC will not obtain the required approvals by its unitholders, the possibility that the anticipated benefits from the proposed merger cannot be fully realized, the possibility that costs or difficulties related to the proposed merger will be greater than expected and other risk factors. Please readmaterially. See 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.


ITEM 1., 1A. and 2.BUSINESS, RISK FACTORS AND PROPERTIES

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 publicly traded Delaware limited partnership, was formed in 1999 and completed its initial public offering of common units on April 16, 2001. Our common units trade on the New York Stock Exchange (NYSE) under the symbol “NS,” our fixed-to-floating rate cumulative redeemable perpetual preferred units trade on the NYSE under the symbol “NSprA” for our 8.50% Series A Preferred Units, “NSprB” for our 7.625% Series B Preferred Units and “NSprC” for our 9.00% Series C Preferred Units.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 Board of Directors). NuStar GP, LLC is the general partner of our general partner, Riverwalk Logistics, L.P., both of which are wholly owned subsidiaries of ours. As of December 31, 2023, our limited partner interests consisted of the following:
•common units (NYSE: NS); and
•8.50% Series A (NYSE: NSprA), 7.625% Series B (NYSE: NSprB) and 9.00% Series C (NYSE: NSprC) Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (collectively, the Series A, B and C Preferred Units).

We are primarily engaged in the transportation, terminalling and storage of petroleum products and anhydrous ammonia,renewable fuels and the terminalling, storage and marketingtransportation of anhydrous ammonia. We also market petroleum products. The term “throughput” as used in this document generally refers to barrels of crude oil, or 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, 2017,2023, our assets included approximately 9,4009,490 miles of pipeline and 8163 terminal and storage facilities, thatwhich provide approximately 9649 million barrels of storage capacity. The following table summarizes operating income for each of our business segments:
 
Year Ended
December 31, 2017
 (Thousands of Dollars)
Pipeline$231,795
Storage$219,439
Fuels marketing$5,983

We conduct our operations through our wholly owned subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics) and NuStar Pipeline Operating Partnership L.P. (NuPOP). Our revenues include:We generate revenue primarily from:
•tariffs for transporting crude oil, refined products and anhydrous ammoniatransportation through our pipelines;
•fees for the use of our terminal and storage facilities and related ancillary services; and
•sales of petroleum products.
We strive to

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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 unitholder value by:costs or impose restrictions on operations;
enhancing•factors that affect our existing assets through strategic internal growth projects that expand our business with current and new customers;
pursuing strategic expansion projects by constructing new assets;
improving our operations, including safety and environmental stewardship, cost control and asset reliability; and
identifying acquisition targets that meet our financial and strategic criteria.

Our internet website address is http://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 filed with (or furnished to) the Securities and Exchange Commission (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 officerscustomers and the chartersmarkets they serve, such as utilization rates and maintenance turnaround schedules of our board’s committeesrefining 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 we transport and/or store in our assets and the demand for products we sell.

See Item 1A. “Risk Factors” for additional discussion on how these factors could affect our website freeoperations.

The following map depicts our assets as of charge (select the “Investors” link, then the “Corporate Governance” link).December 31, 2023:

Map for 2023 10K - FINAL.jpg
Our governance documents are available in print to any unitholder that makes a written request to Corporate Secretary,
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Merger Agreement
On January 22, 2024, NuStar Energy L.P., 19003 IH-10 West, San Antonio, Texas 78257 or corporatesecretary@nustarenergy.com.

RECENT DEVELOPMENTS

Merger. On February 7, 2018, NuStar Energy, Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, a wholly owned subsidiary of NuStar Energy (Merger Sub), Riverwalk Holdings, LLC and NuStar GP Holdings, LLC (NuStar GP Holdings) entered into an Agreement and Plan of Merger (the Merger Agreement) pursuant to whichwith Sunoco LP, a Delaware limited partnership (Sunoco), Saturn Merger Sub, LLC, a Delaware limited liability company and a direct wholly owned subsidiary of Sunoco (Merger Sub), Riverwalk Logistics, L.P., NuStar GP, LLC, and Sunoco GP LLC, a Delaware limited liability company and sole general partner of Sunoco (the Sunoco GP). The Merger Agreement provides that, among other things and on the terms and subject to the conditions set forth therein, Sunoco will mergeacquire NuStar Energy in an all-equity transaction by means of a merger of Merger Sub with and into NuStar GP HoldingsEnergy (the Merger) with NuStar GP Holdings beingEnergy surviving the surviving entity (the Merger), such that NuStar Energy will beMerger as a subsidiary of Sunoco.

On the sole member of NuStar GP Holdings following the Merger. Pursuantterms and subject to the conditions set forth in the Merger Agreement, and at the effective time of the Merger our partnership agreement(the Effective Time), each NuStar Energy common unit issued and outstanding immediately prior to the Effective Time will be amendedconverted into and restatedshall thereafter represent the right to among other things, (i) cancelreceive 0.400 of a common unit of Sunoco and, if applicable, cash in lieu of fractional units. In addition, prior to the incentiveEffective Time, we will declare and pay a special cash distribution rights held byto our general partner, (ii) convertcommon unitholders in the 2% general partner interestamount of $0.212 per common unit (the Special Distribution) (in addition to continuing to pay our quarterly distributions in the ordinary course, subject to certain conditions, until the Effective Time).

Each Series A, B and C Preferred Unit issued and outstanding immediately prior to the Effective Time will remain issued and outstanding from and after the Effective Time as limited partnership interests of the surviving entity having the same terms as are applicable to the applicable series of NuStar Energy held by our general partner into a non-economic management interest and (iii) providepreferred unit immediately prior to the holdersEffective Time.

The completion of our common units with voting rights in the election of the members of the board of directors of NuStar GP, LLC at an annual meeting, beginning in 2019. The Merger is subject to the satisfactionfulfillment or waiver of certain conditions, including, among others: approval and adoption by NuStar Energy’s common unitholders of the Merger Agreement and the transactions contemplated thereby, including the Merger; expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; and the effectiveness of the registration statement on Form S-4 to be filed by Sunoco pursuant to which Sunoco common units to be issued in connection with the Merger are registered with the U.S. Securities and Exchange Commission (the SEC).

The Merger Agreement contains termination rights for each of NuStar Energy and Sunoco. Upon termination of the Merger Agreement under specified circumstances, including the termination by Sunoco in the event of an adverse recommendation change by our Board of Directors or by NuStar Energy to accept a Superior Proposal (as defined in the Merger Agreement), NuStar Energy would be required to pay Sunoco a termination fee of approximately $90.3 million.

Concurrently with the entry into the Merger Agreement, NuStar Energy and Sunoco entered into an agreement (the Support Agreement) with Energy Transfer LP (Energy Transfer), a Delaware limited partnership and the sole member of the Sunoco GP. The Support Agreement provides, among other things, that Energy Transfer will not transfer its ownership interest in the Sunoco GP, Holdings unitholders. Additionally, on February 8, 2018, we announced that our management anticipates recommendingany of the Sunoco incentive distribution rights owned by it or any material portion of the Sunoco common units owned by it prior to the boardEffective Time. Energy Transfer has also agreed to be bound by the terms of directors of NuStar GP, LLC,the non-solicitation provisions in the Merger Agreement with respect to competing proposals for Sunoco and the boardSunoco GP and to abide by certain covenants with respect to regulatory approvals, SEC filings, confidentiality and litigation, among other things.

The foregoing descriptions of directors expectsthe Merger Agreement and the Support Agreement and the transactions contemplated thereby, including the Merger, are summaries, do not purport to adopt, a resetbe complete and are qualified in their entirety by reference to the full text of the Merger Agreement and the Support Agreement, which are included in Item 15. “Exhibits and Financial Statement Schedules” as Exhibit 2.01 and Exhibit 10.54, respectively, and incorporated by reference herein.

Other Recent Developments
Redemptions of Series D Preferred Units. In the second and third quarters of 2023, we redeemed all of our quarterly distributionoutstanding Series D Cumulative Convertible Preferred Units (the Series D Preferred Units) for an aggregate net redemption price of $518.7 million. These redemptions were primarily funded with borrowings under our Revolving Credit Agreement, as defined below. Pursuant to our partnership agreement, the Series D Preferred Units were cancelled; therefore, the Series D Preferred Units no longer represent a limited partnership interest. For the year ended December 31, 2023, we recorded a loss of $0.55 per common unit attributable to $0.60 ($2.40 on an annualized basis), starting with the first-quarter distribution payable in May 2018. Please refer toredemptions. See Note 2817 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussionmore information.

Issuance of the Merger.

Hurricane Activity. In the third quarterCommon Units. On August 11, 2023, we issued 14,950,000 common units representing limited partner interests at a price of 2017, parts$15.35 per unit for net proceeds of the Caribbean and Gulf of Mexico experienced three major hurricanes. Several of our facilities were affected by the hurricanes, but our St. Eustatius terminal experienced the most damage and was temporarily shut down.approximately $222.0 million. We recorded a $5.0 million loss in 2017 for property damage at our St. Eustatius terminal, which represents the amount of our property deductibleused these proceeds to repay outstanding borrowings under our insurance policy. We received insurance proceedsRevolving Credit Agreement.

5

Table of $12.5Contents
Debt Amendments. On June 30, 2023, we amended our $1.0 billion unsecured revolving credit agreement (as amended, the Revolving Credit Agreement), primarily to extend the maturity date from April 27, 2025 to January 27, 2027. On June 29, 2023, we amended our $100.0 million in 2017 and $87.5 million inreceivables financing agreement (as amended, the Receivables Financing Agreement) to extend the scheduled termination date from January 2018 for property damage at our St. Eustatius terminal. We expect that the costs31, 2025 to repair the property damage at the terminal will not exceed the value of insurance proceeds received. Please refer toJuly 1, 2026. See Note 112 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion.more information.


Navigator AcquisitionSale-Leaseback Transaction. On March 21, 2023, we consummated a sale-leaseback (the Sale-Leaseback Transaction) of our corporate headquarters facility and Financing Transactions. On Mayapproximately 24 acres of underlying land located in San Antonio, Texas (the Corporate Headquarters) for $103.0 million and recognized a gain of $41.1 million. We used the proceeds to repay outstanding borrowings under our Revolving Credit Agreement. See Note 4 2017,of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for more information.

Trends and Outlook
For the full-year 2024, we completed the acquisitionexpect to fund all of Navigator Energy Services, LLC for approximately $1.5 billion (the Navigator Acquisition). Inour expenses, distribution requirements and capital expenditures using internally generated cash flows, as we did in 2021 through 2023. We plan to continue to manage our operations with fiscal discipline in order to best maximize unitholder value.

In 2024, we expect to continue to benefit from the positive revenue impact of the July 2023 tariff indexation increases on most of our pipeline systems, which serve as an important counterbalance to the impact of inflation on our business.

While many terminals in our storage segment are somewhat insulated from demand volatility by contracted rates for storage, index rate adjustments and minimum volume commitments, revenues at our St. James and Corpus Christi North Beach facilities continue to be negatively impacted by ongoing global economic uncertainty. Conversely, we expect our West Coast region to continue to benefit in 2024 from the completion of renewable fuels projects, which continue to expand the capacity of our renewable fuels distribution system.

In 2024, we expect our operations to continue to be impacted by inflation. We also expect to continue to be impacted by the high interest rate environment, which negatively affects the cost of our variable-rate debt, as well as our Series A, B and C Preferred Units, which have distribution rates that float along with interest rates. On the other hand, our ability to pass along rate increases reflecting changes in producer and/or consumer price indices to our customers, under tariffs and contracts, should help to counterbalance the impact of inflation on our costs. Additionally, we expect uncertain market conditions in 2024, stemming from the uncertainty regarding future actions by the U.S. Federal Reserve and the upcoming election year, among other factors, which could impact the cost of operating our assets and executing our capital projects in 2024 and beyond.

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. See Item 1A. “Risk Factors” for additional discussion on how these factors could affect our financial position, results of operations and cash flows.


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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 contains additional detailed financial information about our segments in Note 24 of the Notes to Consolidated Financial Statements. A comparative discussion of our 2022 to 2021 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, 2022 filed with the SEC on February 23, 2023.
The following table presents our consolidated financial results for the year ended December 31, 2023, compared to the year ended December 31, 2022:
 Year Ended December 31, 
 20232022Change
(Thousands of Dollars, Except Per Unit Data)
Statement of Income Data:
Revenues:
Service revenues$1,155,567 $1,120,249 $35,318 
Product sales478,620 562,974 (84,354)
Total revenues1,634,187 1,683,223 (49,036)
Costs and expenses:
Costs associated with service revenues622,671 616,867 5,804 
Costs associated with product sales407,793 486,947 (79,154)
Other impairment loss— 46,122 (46,122)
General and administrative expenses129,846 117,116 12,730 
Other depreciation and amortization expense4,728 7,358 (2,630)
Total costs and expenses1,165,038 1,274,410 (109,372)
Gain on sale of assets41,075 — 41,075 
Operating income510,224 408,813 101,411 
Interest expense, net(241,364)(209,009)(32,355)
Other income, net10,215 26,182 (15,967)
Income before income tax expense279,075 225,986 53,089 
Income tax expense5,412 3,239 2,173 
Net income$273,663 $222,747 $50,916 
Basic and diluted net income per common unit$0.72 $0.36 $0.36 

Consolidated Overview
Net income increased $50.9 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to higher operating income of $101.4 million, partially offset by an increase in interest expense, net of $32.4 million and a decrease in other income, net of $16.0 million. Operating income increased primarily due to a gain of $41.1 million related to the Sale-Leaseback Transaction in the first quarter of 2023, a non-cash pre-tax impairment loss of $46.1 million in the first quarter of 2022 and higher operating income from our pipeline segment in 2023. These increases were partially offset by lower operating income from our storage segment, excluding the 2022 impairment loss, and higher general and administrative expenses in 2023.

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Total revenues decreased $49.0 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to lower product sales in our fuels marketing segment resulting from lower fuel prices. Service revenues increased in 2023 due to higher revenues from our pipeline segment, primarily due to higher average tariff rates, partially offset by lower revenues from our storage segment, resulting from current unfavorable market conditions affecting certain of our terminals.

Total costs and expenses decreased $109.4 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to lower fuel costs associated with product sales in our fuels marketing segment and a non-cash, pre-tax impairment loss of $46.1 million in the first quarter of 2022, partially offset by an increase in general and administrative expenses.

General and administrative expenses increased $12.7 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to an increase in rent expense of $6.5 million, mainly related to the Sale-Leaseback Transaction of our Corporate Headquarters in the first quarter of 2023 and higher compensation expenses in 2023.

Interest expense, net increased $32.4 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to higher interest rates on our variable rate debt and higher balances on our Revolving Credit Agreement, which was used to fund a portion of the purchase price, we issued 14,375,000 common units for net proceeds of $657.5 million, issued $550.0Series D Preferred Unit redemptions. In addition, $4.8 million of 5.625% senior notesSeries D Preferred Unit distributions was classified in interest expense due to the redemptions.

Other income, net decreased $16.0 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to a gain of $16.4 million in 2022 for the amount by which the insurance recoveries related to the 2019 fire at our terminal facility in Selby, California exceeded our expenses incurred to date. The overall decrease was partially offset by higher foreign exchange rate gains of $4.5 million in 2023. See Notes 1 and 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for more information on the fire at our terminal facility in Selby, California and the sale of the Point Tupper terminal facility.

Basic and diluted net proceedsincome per common unit increased $0.36 per common unit for the year ended December 31, 2023, compared to the year ended December 31, 2022, due to higher net income, partially offset by a loss of $543.3 million and issued 15,400,000$0.55 per common unit related to the Series D Preferred Unit redemptions in 2023, compared to a loss of our 7.625%$0.31 per common unit related to the Series B Fixed-to-Floating Rate Cumulative Redeemable PerpetualD Preferred Units (Series B Preferred Units) for net proceeds of $371.8 million. Please refer toUnit repurchase in 2022. See Notes 4, 1217 and 19 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion.more information.



8
ORGANIZATIONAL STRUCTURE

Our operations are managed by NuStar GP, LLC, the general partnerTable of our general partner. NuStar GP, LLC, a Delaware limited liability company, is a consolidated subsidiaryContents
SEGMENTS AND RESULTS OF OPERATIONS

PIPELINE SEGMENT
As of NuStar GP Holdings (NYSE: NSH).

The following chart depicts a summary of our organizational structure at December 31, 2017:


SEGMENTS
Detailed financial information about2023, our segments is included in Note 25 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.” The following map depicts our assets at December 31, 2017:











PIPELINE
Our pipeline operations consist of the transportation of refined petroleum products, crude oil and anhydrous ammonia. As of December 31, 2017, we owned and operated:ammonia, including:
•refined product pipelines with an aggregate length of 3,1302,915 miles and crude oil pipelines with an aggregate length of 1,9302,070 miles in Texas, Oklahoma, Kansas, Colorado and New Mexico (collectively, the Central West System);
•a 1,920-mile2,045-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 Andeavor’sMarathon Petroleum Corporation’s (Marathon) Mandan, North Dakota refinery and terminating in Minneapolis, Minnesota (the North Pipeline); and
a•an approximately 2,000-mile anhydrous ammonia pipeline originating in the Louisiana delta area that travelsand then running north through the Midwestern United States to Missouri before forking east and west to terminate in NebraskaIndiana and IndianaNebraska (the Ammonia Pipeline).

The following table lists information about our pipeline assets as of December 31, 2017:
     
Throughput
 For the year ended December 31,
Region / Pipeline SystemLength Tank Capacity 2017 2016
 (Miles) (Barrels) (Barrels/Day)
Central West System:       
McKee System2,276
 —
 171,815
 178,373
Three Rivers System373
 —
 78,165
 79,502
Other481
 —
 53,829
 57,039
Central West Refined Products Pipelines3,130
 —
 303,809
 314,914
South Texas Crude System330
 2,157,000
 114,920
 124,363
Other200
 —
 52,969
 59,087
Eagle Ford System530
 2,157,000
 167,889
 183,450
McKee System598
 1,039,000
 137,675
 147,956
Ardmore System119
 824,000
 84,801
 60,775
Permian Crude System683
 1,000,000
 192,958
 —
Central West Crude Oil Pipelines1,930
 5,020,000
 583,323
 392,181
Total Central West System5,060
 5,020,000
 887,132
 707,095
        
Central East System:       
East Pipeline1,920
 5,261,000
 139,317
 143,446
North Pipeline450
 1,492,000
 41,438
 48,343
Ammonia Pipeline2,000
 —
 32,172
 29,243
Total Central East System4,370
 6,753,000
 212,927
 221,032
        
Total9,430
 11,773,000
 1,100,059
 928,127
assets:
As of December 31, 2023Throughput
For the Year Ended December 31,
Region / Pipeline SystemLengthTerminalsTank Capacity20232022
(Miles)(Barrels)(Barrels/Day)
Central West System:
McKee Refined Product System1,981 — — 182,840 160,490 
Three Rivers System378 — — 119,453 114,294 
Valley Pipeline System271 — 59,885 58,335 
Other285 — — 18,892 19,649 
Central West Refined Products Pipelines2,915 — — 381,070 352,768 
Corpus Christi Crude Pipeline System538 8 2,157,000 317,346 385,720 
McKee Crude System388 — 1,039,000 153,410 132,197 
Ardmore System119 — 824,000 77,883 88,664 
Permian Crude System1,025 3 1,583,000 685,412 712,779 
Central West Crude Oil Pipelines2,070 11 5,603,000 1,234,051 1,319,360 
Total Central West System4,985 11 5,603,000 1,615,121 1,672,128 
Central East System:
East Pipeline2,045 18 5,906,000 149,947 151,139 
North Pipeline450 4 1,503,000 45,739 48,148 
Ammonia Pipeline2,010 — — 26,157 27,185 
Total Central East System4,505 22 7,409,000 221,843 226,472 
Total9,490 33 13,012,000 1,836,964 1,898,600 
Description of Pipelines
Central West System. The Central West System covers a total of 5,0604,985 miles, including refined product and crude oil pipelines. The refined product pipelines have an aggregate length of 3,1302,915 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 1,9302,070 miles (Central West Crude Oil Pipelines). Our 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 regionregions to our North Beach marine export terminal andor to our customers’third-party refineries in Corpus Christi, Texas. Our Corpus Christi Crude Pipeline System is composed of pipelines that transport crude oil
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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 most of which we acquired with the Navigator Acquisition,

consists of crude oil transportation, pipeline connection and storage assets located in the Midland Basin of West Texas, including a pipelinethat 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. As of December 31, 2023, the system with more than 200 producer tank batteries covering overconsists of 1,025 miles of pipelines and covers approximately 500,000 dedicated acres.acres controlled by producers, with 369 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 aggregate storage capacity of 1.6 million barrels.


Central East System. The Central East System covers a total of 4,3704,505 miles and consists of the East Pipeline, the North Pipeline and the Ammonia Pipeline.

The East Pipeline covers 1,9202,045 miles and movestransports refined products and natural gas liquids north invia pipelines ranging in diameter from 6 inches to 16 inches to our terminals and third partythird-party terminals along the system and to receiving pipeline connections in Kansas. Shippers on the East Pipeline primarily obtain refined petroleum products from refineries in Kansas, Oklahoma and Texas. The East Pipeline system includes 1718 terminals, discussed below, with aggregate storage capacity of approximately 3.84.5 million barrels and two tank farms with aggregate storage capacity of approximately 1.4 million barrels at McPherson and El Dorado, Kansas.

The North Pipeline originates at Andeavor’sMarathon’s Mandan, North Dakota refinery and runs from west to eastwest-to-east for approximately 450 miles to its termination in the Minneapolis, Minnesota area.Minnesota. The North Pipeline systemis also connected to CHS Inc.’s (CHS) Laurel, Montana refinery via a connection in Fargo, North Dakota to their Laurel Pipeline. The North Pipeline includes four terminals discussed below, with aggregate storage capacity of approximately 1.5 million barrels.
The East and North Pipelines include 21 truck-loading terminals through which refined petroleum products are delivered to storage tanks and then loaded into petroleum product transport trucks. Revenues earned at these terminals predominately relate to the volumes transported on the pipeline through fees included in the pipeline tariff. As a result, these terminals are included in this segment instead of the storage segment.
The approximately 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 onlocated along the Mississippi River. The line then runs north through Louisiana and Arkansas into Missouri, where, at Hermann, Missouri, it splits andinto two branches, one branchof 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 Arkansas, imported product delivered through the marine terminals.terminals in Louisiana and a rail terminal in Iowa. Anhydrous ammonia is primarily used as agricultural fertilizer. It is also used as a feedstock to produce other nitrogen derivative fertilizers, Diesel Exhaust Fluid (DEF) and explosives.

Pipeline Operations
We charge tariffs on a per barrelper-barrel basis for transporting refined products, crude oil and other feedstocks in our refined product and crude oil pipelines and on a per tonper-ton basis for transporting anhydrous ammonia in the Ammonia Pipeline. Throughputs on the Ammonia Pipeline are converted from tons to barrels for reporting purposes only. 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. Other revenues include product sales of surplus pipeline loss allowance (PLA) volumes.

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 tovia marine vessels, pipelines or pipelines.trucks. We charge our shippers tariff rates based on transportation from the origination point on the pipeline to the point of delivery.

Our pipelines are subject to federal regulationregulated 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 (DOT)(the DOT), the Environmental Protection Agency (EPA)(the EPA) and the Department of Homeland Security. Additionally,In addition, our pipelines are subject to the respective state jurisdictions.jurisdictions of the states those lines traverse. See “Rate Regulation” and “Environmental, Health, Safety and Security Regulation” below.below for additional discussion.

The majority of our pipelines are common carrier.deemed to be “common carrier” lines. Common carrier activities are those for which transportation through our pipelines 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 petroleum productpipeline shipments and (ii) filed with the relevant state authority for intrastate petroleum product shipments or (iii) regulated by the STB for our Ammonia Pipeline.pipeline shipments.
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We operate our pipelines remotely through a computerizedan operational technology system called the Supervisory Control and Data Acquisition, or SCADA, system.
Demand for and Sources of Refined Products and Crude Oil
ThroughputsThroughput activity on our Central West Refined Product Pipelines and the East and North Pipelines dependpipelines depends on the level of demand for refined products and other products in the markets served by thethose pipelines, andas well as the ability and willingness of the refiners and marketers havingwith 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 these productsmotor 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 tend tousually 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.pipelines. The agricultural sector is also affected by government agricultural policies and crop commodity prices. Although periods of drought suppress agricultural demand for some refined products, particularly those used for fueling farm equipment, the demand for fuel forto 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 higherhighest 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. Valero Energy refineries connected directly to our pipelines obtain crude oil from a variety of foreign and domestic sources. 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 Andeavor’sMarathon’s Mandan, North Dakota refinery, which primarily runs North Dakotaregionally-sourced crude oil (although it has the ability to process other crude oils), and an interruption in operations at the AndeavorMarathon 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. 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 partythird-party connecting pipelines that receive products originating on thefrom Gulf Coast.Coast refineries.
Other than the Valero Energy refineries and the AndeavorMarathon refinery described above, if operations at any one refinery were discontinued, we believe (assuming unchangedstable 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 increase or decreasefluctuate with the change inprice of crude oil prices.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 Eagle FordCorpus Christi Crude Pipeline System and Permian Crude System. However,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.
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Demand for and Sources of Anhydrous Ammonia
TheOur Ammonia Pipeline is one of twocurrently the only major anhydrous ammonia pipelinespipeline 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 only one capable of receivingcapability to receive products from outside the United States directly into the system and transporting anhydrous ammonia into the nation’s corn belt.system.
Throughputs on our Ammonia Pipeline depend on overall demand for nitrogen fertilizer use, the price of natural gas, which is a feedstock for the primary componentproduction 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 if the groundwhen 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 steady and somewhat insulated from volume fluctuations due to continued strong agricultural demand in the Midwest. However, global conflicts, such as the Russia-Ukraine conflict, can increase export demand, which could reduce the supply of anhydrous ammonia transported on our Ammonia Pipeline.

Customers
As discussed above, our customers include integrated oil companies, refining companies and others. The largest customer of our pipeline segment was Valero Energy, which accounted for approximately 33%27% of the total segment revenues for the year ended December 31, 2017. In addition to Valero Energy, our customers include integrated oil companies, refining companies, farm cooperatives, railroads and others.2023. No other single customer accounted for 10% or more than 10% of the total revenues of theour pipeline segment for the year ended December 31, 2017.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 petroleum 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 the areas where we deliver products.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 competitively deliver products in some of the areas served by our pipelines;competitively for short-haul destinations; however, trucking costs render that mode of transportation uncompetitive with pipeline options for longer haulslong-haul destinations or for 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 impactedthat 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.
TheOur East Pipeline and North PipelinesPipeline compete with an independent common carrier pipeline system owned by Magellan Midstream Partners, L.P. (Magellan)ONEOK, Inc. (ONEOK) 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’sONEOK’s terminals. Competition with MagellanONEOK is based primarily on transportation charges, quality of customer service and proximity to end users.
Competitors of theour Ammonia Pipeline include the other major anhydrous ammonia pipeline, owned by Magellan, which originates in Oklahoma and Texas and terminates in Minnesota. The competing pipeline has the same Direct Application demand and weather issues as the Ammonia Pipeline but is restricted to domestically produced anhydrous ammonia. Midwest production facilities, nitrogen fertilizer substitutes and barge, truck and railroad transportation represent other forms of direct competition to the Ammonia Pipeline under certain market conditions.

Looking forward, we continue to see growing interest for utilization of ammonia as a source for renewable energy 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.

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Results of Operations
The following table presents operating highlights for the pipeline segment:
 Year Ended December 31, 
 20232022Change
(Thousands of Dollars, Except Barrel Data)
Pipeline Segment:
Crude oil pipelines throughput (barrels/day)1,234,051 1,319,360 (85,309)
Refined products and ammonia pipelines throughput (barrels/day)602,913 579,240 23,673 
Total throughput (barrels/day)1,836,964 1,898,600 (61,636)
Throughput and other revenues$873,869 $828,191 $45,678 
Operating expenses214,751 210,719 4,032 
Depreciation and amortization expense175,930 178,802 (2,872)
Segment operating income$483,188 $438,670 $44,518 

Tariff indexations effective July 2022 and July 2023 increased the average tariff rates on most of our pipeline systems and resulted in higher revenues for the year ended December 31, 2023, compared to the year ended December 31, 2022.
Pipeline segment revenues increased $45.7 million, and throughputs decreased 61,636 barrels per day for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to:
•an increase in revenues of $31.1 million and an increase in throughputs of 43,563 barrels per day on our McKee System pipelines, primarily due to operational issues and a planned turnaround at a customer’s refinery in 2022, as well as higher demand on our pipeline serving the Denver, Colorado market in 2023; additionally, higher average tariff rates contributed to $9.7 million of the overall increase;
•an increase in revenues of $12.1 million, despite a decrease in throughputs of 3,601 barrels per day on our East and North pipelines combined; revenues increased primarily due to higher average tariff rates, while throughputs decreased primarily due to unfavorable market conditions and planned turnarounds at customers’ refineries in 2023;
•an increase in revenues of $7.2 million and an increase in throughputs of 1,550 barrels per day on our Valley Pipeline, primarily due to higher average tariff rates;
•an increase in revenues of $5.9 million and an increase in throughputs of 5,159 barrels per day on our Three Rivers System, partially due to higher demand on certain of our pipelines within this system and pipeline expansions that were placed in service in July 2022. Also, higher average tariff rates contributed to $4.0 million of the overall increase;
•an increase in revenues of $3.4 million, despite slightly lower throughputs of 1,028 barrels per day on our Ammonia Pipeline; revenues increased primarily due to higher average tariff rates;
•a decrease in revenues of $2.2 million and a decrease in throughputs of 27,367 barrels per day on our Permian Crude System, primarily due to decreased customer production supplying this system. Revenues also decreased $7.9 million due to lower commodity prices on PLA volumes and other products sold; these decreases were partially offset by higher average tariff rates in 2023;
•a decrease in revenues of $2.4 million and a decrease in throughputs of 10,781 barrels per day on our Ardmore System due to a turnaround at a customer’s refinery in the second quarter of 2023 and lower demand in 2023; and
•a decrease in revenues of $10.9 million and a decrease in throughputs of 68,374 barrels per day on our Corpus Christi Crude Pipeline System, primarily due to unfavorable market conditions and changes to a customer contract.

Operating expenses increased $4.0 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to an increase of $2.8 million in maintenance and regulatory expenses across various pipelines.

Depreciation and amortization expense decreased $2.9 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to fully amortized definite-lived intangible assets.


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STORAGE SEGMENT
Our storage segment consistsis composed of our facilities that provide storage, handling and other services on a fee basis for petroleumrefined products, crude oil, specialty chemicals, renewable fuels and other liquids. As of December 31, 2017,2023, we owned and operated:
40operated 29 terminal and storage facilities in the United States and one terminal in Nuevo Laredo, Mexico, with totalan aggregate storage capacity of 53.336.4 million barrels;
A terminal on the island of St. Eustatius with tank capacity of 14.3 million barrels and a transshipment facility;
A terminal located in Point Tupper, Canada with tank capacity of 7.8 million barrels and a transshipment facility; and
Six terminals located in the United Kingdom and one terminal located in Amsterdam, the Netherlands, with total storage capacity of approximately 9.5 million barrels.

The following table sets forth information about our terminal and storage facilities as of December 31, 2017:
2023:
FacilityTank Capacity
Facility(Barrels)Tank Capacity
(Barrels)
Colorado Springs, CO328,000327,000 
Denver, CO110,000
Albuquerque, NM251,000250,000 
Rosario, NM166,000167,000 
Catoosa, OK358,000359,000 
Abernathy, TX160,000161,000 
Amarillo, TX269,000
Corpus Christi, TX491,000410,000 
Corpus Christi, TX (North Beach)3,339,0003,962,000 
Edinburg, TX340,000345,000 

FacilityTank Capacity
(Barrels)
El Paso, TX (b)(a)419,000415,000 
Harlingen, TX286,000
Laredo, TX215,000218,000 
San Antonio, TX (c)(b)
375,000379,000 
Southlake, TX569,000
Nuevo Laredo, Mexico35,000268,000 
Central West Terminals7,711,0008,495,000 
Jacksonville, FL2,593,000
St. James, LA9,917,0009,906,000 
Houston, TX86,00087,000 
Gulf Coast Terminals9,993,000 
Los Angeles, CA615,000 
Pittsburg, CA398,000 
Selby, CA2,672,000 
Stockton, CA818,000 
Portland, OR1,348,000 
Tacoma, WA391,000 
Vancouver, WA(b)
775,000 
West Coast Terminals7,017,000 
Benicia, CA3,698,000 
Corpus Christi, TX4,030,000 
Texas City, TX (c)2,964,0003,141,000 
Gulf Coast Terminals15,560,000
Blue Island, IL690,000
Andrews AFB, MD (a)75,000
Baltimore, MD813,000
Piney Point, MD5,402,000
Linden, NJ (c)4,637,000
Paulsboro, NJ74,000
Virginia Beach, VA (a)41,000
North East Terminals11,732,000
Los Angeles, CA608,000
Pittsburg, CA398,000
Selby, CA3,074,000
Stockton, CA816,000
Portland, OR1,345,000
Tacoma, WA391,000
Vancouver, WA (c)774,000
West Coast Terminals7,406,000
Benicia, CA3,683,000
Corpus Christi, TX4,030,000
Texas City, TX3,141,000
Refinery Storage Tanks10,854,00010,869,000 
Eastham, EnglandTotal2,096,00036,374,000 
Grays, England1,958,000
Runcorn, England149,000
Belfast, Northern Ireland408,000
Glasgow, Scotland353,000
Grangemouth, Scotland719,000
United Kingdom (UK) Terminals5,683,000

(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.
FacilityTank Capacity
(Barrels)
St. Eustatius, the Netherlands14,256,000
Amsterdam, the Netherlands3,834,000
Point Tupper, Canada7,778,000
International Terminals31,551,000
Total84,814,000
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(a)Terminal facility also includes pipelines to U.S. government military base locations.
(b)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.
(c)Location includes two terminal facilities.

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Description of Major Terminal and Storage Facilities
St. Eustatius. We ownCentral West Terminals. Our Central West Terminals include terminals located in Texas, Oklahoma, New Mexico and operate a 14.3Colorado, as well as one terminal located in Nuevo Laredo, Mexico, with an aggregate storage capacity of 8.5 million barrel petroleumbarrels. Most of these terminals are connected to our Central West Refined Product Pipelines. Our Corpus Christi North Beach terminal, located at the Port of Corpus Christi in Texas, has 4.0 million barrels of crude oil storage and terminallingsupports our Corpus Christi Crude Pipeline System that transports crude oil from the Eagle Ford and Permian Basin regions to Corpus Christi for export or refineries owned by third parties. This facility also provides our customers with the flexibility to segregate and deliver crude oil and processed condensate and has access to four docks, including two private docks. We can accommodate Suezmax-class vessels and load crude oil onto marine vessels simultaneously on all four docks.

We refer to our pipelines that transport crude oil from the Eagle Ford and Permian Basin regions to Corpus Christi, together with our Corpus Christi North Beach terminal, as the Corpus Christi Crude System.

Gulf Coast Terminals. Our Gulf Coast Terminals have an aggregate storage capacity of 10.0 million barrels and include our St. James terminal, which is located on the islandMississippi River near St. James, Louisiana, and one terminal located in Houston, Texas. Our St. James terminal has a total storage capacity of 9.9 million barrels and is located on almost 900 acres of land, some of which is undeveloped. The majority of the storage tanks and infrastructure are suited for light to medium crude oil, with certain tanks capable of fuel oil or heated crude oil storage. Additionally, the facility has one barge dock and two ship docks, and can accommodate exports up to Aframax-class vessels. Our St. EustatiusJames terminal is connected to (i) offshore pipelines in the Caribbean, which is located at a pointGulf of minimal deviation from major shipping routes. This facility is capable of handling a wide range of petroleum products, includingMexico, (ii) long-haul pipelines that can receive crude oil from the Eagle Ford, Permian Basin, other domestic shale plays and refined products,Canada, and it can accommodate heavily laden ultra large crude carriers, or ULCCs, for loading and discharging crude oil and other petroleum products. A two-berth jetty, a two-berth monopile with platform and buoy systems, a floating hose station and an offshore single point mooring (SPM) buoy with loading and unloading capabilities serve(iii) pipelines connecting to refineries in the terminal’s customers’ vessels.Gulf Coast. The fuel oil and petroleum productSt. James terminal also has two unit train rail facilities have in-tank and in-line blending capabilities, whilethat are served by the crude tanks have tank-to-tank blending capability and in-tank mixers. In addition to the storage and blending services at St. Eustatius, thisUnion Pacific Railroad. Each facility has the flexibilitycapacity to utilize certainsimultaneously off-load 120 railcars, at a minimum, in a 24-hour period.

West Coast Terminals. Our West Coast Terminals include terminals located in California, Oregon and Washington, with an aggregate storage capacity for both feedstock and refined products to supportof 7.0 million barrels. The largest of these terminals is our atmospheric distillation unit, which is capableSelby, California terminal, with a total storage capacity of handling up to 25,000 barrels per day of feedstock, ranging from condensates to heavy crude oil.2.7 million barrels. We own and operate all of the berthing facilities at the St. Eustatius terminal. Separate fees apply for use of the berthing facilities, as well as associated services, including pilotage, tug assistance, line handling, launch service, emergency response services and other ship services.

We are currently working on strategichave completed several renewable fuel storage projects at our West Coast Terminals over the St. Eustatius terminallast several years, and are able to make it more flexiblereceive and marketable. These projects include: (i) replacingdistribute renewable fuels across the existing SPM with a refurbished SPMWest Coast, including renewable diesel, sustainable aviation fuel, ethanol, biodiesel and the installation of two additional subsea pipelinesrenewable feedstock. Our West Coast Terminals are connected to supply from the SPM, which will give us the option to loadvarious domestic and unload two different products at the SPM and segregate various grades of crude and fuel oil to and from the SPM, (ii) pipeline improvements and (iii) tank upgrades, repairs and rebuilds. Upon completion of these projects, we will also have the capability to load or unload three crude vessels at a time. In September 2017, St. Eustatius sustained substantial damage during Hurricane Irma and the terminal was temporarily shut down. Although the terminal was fully operational by November, we expect repairs to continue into 2018 and beyond, thereby delaying the completion of certain of these strategic projects.foreign sources.

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, TXTexas and Benicia, CA. Effective January 1, 2017, weCalifornia. We lease our refinery storage tanks to Valero Energy in exchange for a fixed fee, whereas we previously earned fees based upon throughput.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 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. Our St. James terminal is connected to gathering pipelines in the Gulf of Mexico, lines that connect to Eagle Ford, Permian and other domestic shale plays, and pipelines to refineries in the Gulf Coast and Midwest. The St. James terminal also has two unit train rail facilities and a manifest rail facility, which are served by the Union Pacific Railroad and have a combined capacity of approximately 200,000 barrels per day.
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 independent, ice-free marine terminal on the North American Atlantic coast, with access to the East Coast, Canada and the Midwestern United States 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 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.
Linden, New Jersey. Our Linden terminal facility includes two terminals that provide deep-water terminalling capabilities in the New York Harbor and primarily stores petroleum products, including gasoline, jet fuel and fuel oils. The two terminals have a total storage capacity of 4.6 million barrels and can receive and deliver products via ship, barge and pipeline. The terminal facility includes two docks.

Amsterdam. Our Amsterdam terminal has a total storage capacity of 3.8 million barrels. This facility is located at the Port of Amsterdam and primarily stores petroleum products, including gasoline, diesel and fuel oil. This facility has two docks for vessels and five docks for inland barges.

Corpus Christi North Beach. We own and operate a 3.3 million barrel crude oil storage and terminalling facility located at the Port of Corpus Christi in Texas. The facility supports our South Texas Crude System and is connected to a third-party pipeline system. It also provides our customers with the flexibility to segregate and deliver crude oil and processed condensate. This facility has three docks, including one private dock, and can load crude oil onto ships simultaneously on all three docks at a maximum rate of 65,000 barrels per hour. This facility will have exclusive-use access to the Port of Corpus Christi’s new crude oil dock expected to be completed in 2018, which will give the terminal four docks. Once the new dock is complete, the Corpus Christi North Beach terminal will have the capacity to move on average between 650,000 and 700,000 barrels per day and will be able to accommodate Aframax-class vessels.
Storage Operations
Revenues for theWe generate storage segment includerevenues through fees for tank storage agreements, whereunder 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, whereunder which a customer pays a fee per barrel for volumes movingmoved through our terminals (throughput terminal revenues). Our terminals also provide blending, additive injections, handling and filtering services, for which we charge additional fees. We previously charged a fee for each barrel of crude oil and certain other feedstocks that we delivered to Valero Energy’s Benicia, Corpus Christi West and Texas City refineries from our crude oil refinery storage tanks. Effective January 1, 2017, we lease these refinery storage tanks in exchange for a fixed fee. 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 Refined Petroleum Products and Crude OilStorage 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. The majority of products stored in our terminals are refined petroleum products. Demand for our terminalling services will generally increase or decrease with demand for refined petroleum products, and demand for refined petroleum 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 a contango market (when the future at the higher price. On the other hand, when the current price of a commodity iscrude oil nears or exceeds the expected future market price, or “backwardation,” traders are no longer incentivized to exceed current prices),purchase and store product for future sale. Our storage terminal revenues are somewhat insulated from demand volatility due to contracted rates for storage services will generally increase.and minimum volume commitments.

Crude oil delivered to our St. James terminal through our unit train facilities, and crude oil delivered to our Corpus Christi North Beach terminalterminals will generally increase or decrease with crude oil production rates in western Canada and the Bakken, Permian and Eagle Ford shale plays, respectively.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. Although the Permian and Eagle Ford shale plays are partially insulated from negative economic conditions due to the low break-even point, our Corpus Christi exports have not returned to pre-pandemic levels due to lower global demand for refined products and crude oil and increased competition in crude oil export markets out of the U.S. Overall, refinery production rates,
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drilling activity and overall consumer demand in the U.S. rebounded in 2021, bringing demand for most of our terminal and storage facilities back to pre-pandemic levels. However, the detrimental impact of the pandemic, amplified by the Russia-Ukraine conflict, has continued to affect current global demand, resulting in a decline in crude oil exports from our Corpus Christi North Beach facility, and the current volatile and backwardated market has led to customers not renewing expiring contracts, primarily at our St. James terminal.

Demand for renewable diesel, renewable jet fuel, ethanol and other renewable fuels continues to grow in markets served by our West Coast terminals due to new regulations with aggressive carbon emissions reduction goals. As this demand growth is expected to continue, we have completed, and continue to develop, renewable fuel storage projects at our West Coast terminals to meet this demand.
Customers
We provide storage and terminalling services for crude oil, refined products and refined petroleumother products to many of the world’s largest producers of crude oil, integrated oil companies, chemical companies, oil traders and refiners. In addition, our blending capabilities in our storage assets have attracted customers who have leased capacity primarily for blending purposes. The largest customer of our storage segment is Valero Energy, which accounted for approximately 21%39% of the total revenues of the segment for the year ended December 31, 2017.2023. No other customer accounted for 10% or more than 10% of the total revenues of the storage segment for the year ended December 31, 2017.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 ownhave storage and terminalling facilities are also significant customers of independent terminal operators. Such companies typically have strong demand foroperators, especially terminals owned by independent operators when independent terminals have morelocated 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 ownedproprietary storage facilities are inadequate, either because ofdue 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. Although many products require modest terminal modification, operatorsOperators with versatile storage capabilities typically require less modification prior to usage, ultimately making the storage cost to the customer more attractive.
Our St. Eustatius and Point Tupper terminals have historically functioned as “break bulk” facilities, which handled imports of light crude from foreign sources into On the U.S.West Coast, regulatory priorities continue to satisfy U.S. East Coast and Gulf Coast refineryincrease demand for light crude. Light crude suppliers broughtrenewable fuels in the crude from the Middle East and other foreign regions on very large ships, which are efficient for long routes. These large ships, due to draft constraints, are unable to navigate far enough inland to deliver directly to U.S. shores, which necessitates unloading these ships to storage and subsequent loading onto smaller ships that can bring the crude to the refiners, a process referred to as “break bulk.” Both terminals are well-located to provide this service.
As the supply of light crude from various U.S. shale formations has increased, U.S. demand for foreign light crude oil, particularly on the U.S. Gulf Coast, has dropped. This reduced demand for imported light crude has, in turn, changed oil trade flow patterns around the world, thereby depressing the demand for break bulk services. Atregion, while at the same time, South American production of heavy crude has ramped up significantly. As demandobtaining permits for export of heavy crude out of South America has risen, so has the demand for “build bulk” services. In ordergreenfield projects remains difficult, which both add more value to reduce costs and increase efficiencies for long routes to customers abroad, exporting producers need to consolidate their heavy oil cargos from the small ships used to move the heavy crude off shore to a large vessel that is more efficient for long routes, a process referred to as “build bulk.” Our St. Eustatius terminal’s location is well-suited to build bulk for South American producers headed to customers overseas, primarily in Asia. However, recently, the combination of oversupply of storage capacity, decreased demand from backwardated markets and reduced North American crude imports has depressed storage rates in the region.our existing assets.
We may face increased competition from new and/or expanding terminals near our locations, if those facilities offer either break bulk or build bulk services, as demanded by the applicable oil trade flows, now and in the future.
Our crude oil refinery storage tanks are physically integrated with and serve refineries owned by Valero Energy. Additionally,Energy, and we have entered into various agreements with Valero Energy governing the usageuse of these tanks. As a result, we believe that we will not face significant competition for our services provided to those refineries.


FUELS MARKETINGResults of Operations
Point Tupper Terminal Disposition. In the first quarter of 2022, we recognized a non-cash pre-tax impairment loss of $46.1 million related to our Point Tupper terminal facility, which was sold on April 29, 2022 (the Point Tupper Terminal Disposition). See Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of this disposition.

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The following table presents operating highlights for the storage segment:
 Year Ended December 31, 
 20232022Change
(Thousands of Dollars, Except Barrel Data)
Storage Segment:
Throughput (barrels/day)448,331 480,129 (31,798)
Throughput terminal revenues$104,495 $110,591 $(6,096)
Storage terminal revenues215,104 223,958 (8,854)
Total revenues319,599 334,549 (14,950)
Operating expenses156,938 154,270 2,668 
Depreciation and amortization expense75,052 73,076 1,976 
Impairment loss— 46,122 (46,122)
Segment operating income$87,609 $61,081 $26,528 

Throughput terminal revenues decreased $6.1 million, and throughputs decreased 31,798 barrels per day for the year ended December 31, 2023, compared to the third quarteryear ended December 31, 2022, primarily due to a decrease in revenues of 2017,$13.2 million and a decrease in throughputs of 51,361 barrels per day at our fuels marketing operations involvedCorpus Christi North Beach terminal, due to unfavorable market conditions and changes to a customer contract. These decreases were partially offset by an increase in revenues of $7.1 million and an increase in throughputs of 19,563 barrels per day at our Central West Terminals, primarily due to higher demand.

Storage terminal revenues decreased $8.9 million for the purchaseyear ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to:
•a decrease in revenues of crude oil, fuel oil, bunker fuel, fuel oil blending components$29.7 million at our St. James terminal due to customers not renewing expiring contracts in the current backwardated market; and
•a decrease in revenues of $9.6 million due to the Point Tupper Terminal Disposition in April 2022.

These decreases were partially offset by the following:
•an increase in revenues of $26.4 million at our West Coast Terminals, primarily due to new contracts and rate escalations across various terminals, combined with higher throughput and handling fees, mainly at our Stockton terminal; and
•an increase in revenues of $4.3 million, primarily due to rate escalations at our Central West Terminals and at our refinery storage tanks.

Operating expenses increased $2.7 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to the following:
•an increase in maintenance and regulatory expenses of $3.1 million, across various terminals;
•an increase of $2.8 million in ad valorem taxes due to higher property valuations;
•increases in reimbursable and other refined products for resale. We ceased marketing crude oilexpenses of $2.5 million that have corresponding increases in revenue, primarily at our West Coast Terminals, partially offset by lower reimbursable expenses at our St. James terminal; and
•an increase of $1.8 million at our Corpus Christi North Beach terminal due to changes in a customer contract.

These increases were partially offset by a decrease in operating expenses of $7.9 million due to the sale of our Point Tupper Terminal Operations during the second quarter of 20172022.

Depreciation and exitedamortization expense increased $2.0 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to expansion projects at our heavyWest Coast Terminals.

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FUELS MARKETING SEGMENT
Our fuels tradingmarketing segment sells petroleum products primarily through our bunkering operations in the third quarter of 2017. These actions are in line with our goal of reducing our exposure to commodity margins,Gulf Coast and instead focusing on our core, fee-based pipeline and storage segments. The only operations remaining in our fuels marketing segment are our bunkering operations at our St. Eustatius and Texas City terminals, as well as certain of our blending operations.

operations associated with our Central East System. The results of operations for the fuels marketing segment depend largely on the margin between our costcosts 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 usWe 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 we enter into derivative instruments to mitigate the effectwere not material for any periods presented. Fluctuations in global demand for crude oil, which was caused by many economic factors outside of our control, has caused volatility in commodity price fluctuations on our operations. The derivative instruments we use consist primarily of commodity futuresprices and swap contracts.

Customersvolumes for our blending operations and bunker fuel sales are mainly ship owners, including cruise line companies. in 2022 and 2023.

Competition and Customers
In the sale of bunker fuel, we compete with ports offering bunker fuels that are along the route of travel of the vessel. Customers for bunker fuel sales are primarily ship owners, marketers and traders. One of our customers, a marketer of petroleum products, was the largest customer of our fuels marketing segment and accounted for approximately 11% of the total segment revenues for the year ended December 31, 2023. No other customer accounted for a significant portion of the total revenues of the fuels marketing segment for the year ended December 31, 2023.

Results of Operations

The following table presents operating highlights for the fuels marketing segment:
EMPLOYEES
 Year Ended December 31, 
 20232022Change
(Thousands of Dollars)
Fuels Marketing Segment:
Product sales$440,725 $520,486 $(79,761)
Cost of goods405,992 484,477 (78,485)
Gross margin34,733 36,009 (1,276)
Operating expenses1,807 2,473 (666)
Segment operating income$32,926 $33,536 $(610)


Product sales decreased $79.8 million, and cost of goods decreased $78.5 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to lower fuel prices for our bunkering operations. Gross margin decreased $1.3 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, as a decrease of $2.8 million in gross margin from our bunkering operations and a decrease of $2.8 million in gross margin from other product sales more than offset higher blending gross margins of $4.3 million, all primarily due to lower fuel prices.

Segment operating income decreased $0.6 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, due to the changes in gross margins described above, partially offset by a decrease in operating expenses of $0.7 million, primarily related to our bunkering operations.

LIQUIDITY AND CAPITAL RESOURCES

The following sections are included in Liquidity and Capital Resources:
•Overview
•Cash Flows
•Sources of Liquidity
•Material Cash Requirements

OVERVIEW
Our primary cash requirements include distributions to our limited partners, debt service, capital expenditures and operating expenses. Our partnership agreement requires that we distribute all Available Cash (as defined in our partnership agreement) to our common limited partners each quarter. Available Cash is generally defined as all cash receipts less cash disbursements, including distributions to our preferred unit holders, and cash reserves established by our general partner, in its sole discretion. 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 sale of assets.
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In the first quarter of 2023, we completed the Sale-Leaseback Transaction for $103.0 million, and in the third quarter of 2023, we issued 14,950,000 common units for net proceeds of approximately $222.0 million. We used the proceeds from these transactions to repay outstanding borrowings under our Revolving Credit Agreement, which facilitated the redemption of 16,346,650 of the Series D Preferred Units, representing all outstanding Series D Preferred Units. Additionally, in the second quarter of 2023, we extended the maturity date on our Revolving Credit Agreement to January 27, 2027, and extended the scheduled termination date on our Receivables Financing Agreement to July 1, 2026. Similarly, in 2022, we had reduced our leverage to position ourselves to repurchase 6,900,000 of the Series D Preferred Units in November 2022, representing approximately one-third of the outstanding units at that time, using borrowings under our Revolving Credit Agreement.

As illustrated in the chart below, in 2023 and 2022, we funded all our expenses, distribution requirements and capital expenditures using cash from operating activities.
Sources and Uses - 2-1-2024 - FINAL.jpg

For the full-year 2024, we expect to fund all our expenses, distribution requirements and capital expenditures using internally generated cash flows. We have no long-term debt maturities until 2025.
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CASH FLOWS
A discussion of our cash flows and other changes in financial position for 2021 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, 2022 filed with the SEC on February 23, 2023.

The following table summarizes our cash flows from operating, investing and financing activities (see also our Consolidated Statements of Cash Flows in Item 8. “Financial Statements and Supplementary Data”).
 Year Ended December 31,
 20232022
(Thousands of Dollars)
Net cash provided by (used in):
Operating activities$514,269 $527,549 
Investing activities(23,240)(84,365)
Financing activities(502,430)(434,953)
Effect of foreign exchange rate changes on cash40 707 
Net (decrease) increase in cash, cash equivalents and restricted cash$(11,361)$8,938 

Net cash provided by operating activities decreased $13.3 million for the year ended December 31, 2023, compared to the year ended December 31, 2022. The increase in net income of $50.9 million was more than offset by noncash adjustments to reconcile to net cash provided by operating activities. In addition, our working capital decreased by $10.6 million for the year ended December 31, 2023 and $0.7 million for the year ended December 31, 2022. Generally, working capital requirements are affected by our accounts receivable, accounts payable and accrued liability balances, which vary depending on the timing of payments.

Net cash used in investing activities decreased $61.1 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to proceeds of approximately $103.0 million from the Sale-Leaseback Transaction in the first quarter of 2023, compared to proceeds from asset sales of $59.3 million in 2022. Additionally, for the year ended December 31, 2023 compared to the year ended December 31, 2022, cash outflows related to capital expenditures decreased an aggregate $14.9 million. Investing activities also include insurance proceeds of $12.4 million for the year December 31, 2023, compared to insurance proceeds of $9.8 million for the December 31, 2022, both related to the 2019 Selby terminal fire.

Net cash used in financing activities increased $67.5 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to the redemption of the outstanding Series D Preferred Units for $518.7 million in 2023, compared to the repurchase of outstanding Series D Preferred Units for $222.4 million in 2022, partially offset by the issuance of common units in the third quarter of 2023 for approximately $222.0 million.

SOURCES OF LIQUIDITY
Revolving Credit Agreement
As of December 31, 2017,2023, our Revolving Credit Agreement had $652.4 million available for borrowing and $343.0 million of borrowings outstanding. Letters of credit issued under our Revolving Credit Agreement totaled $4.6 million as of December 31, 2023 and limit the amount we can borrow under our Revolving Credit Agreement. Obligations under our Revolving Credit Agreement are guaranteed by NuStar Energy and NuPOP.

Our 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, 2023, the Consolidated Debt Coverage Ratio (as defined in the Revolving Credit Agreement) may not exceed 5.00-to-1.00 and the Consolidated Interest Coverage Ratio (as defined in the Revolving Credit Agreement) must not be less than 1.75-to-1.00. Our 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, 2023, our Consolidated Debt Coverage Ratio was 3.85x and our Consolidated Interest Coverage Ratio was 2.18x.

On June 30, 2023, we amended our Revolving Credit Agreement, primarily to extend the maturity date from April 27, 2025 to January 27, 2027. The amendment also includes a requirement that we must demonstrate and certify, prior to using any borrowings under our Revolving Credit Agreement to redeem certain unsecured indebtedness or prior to their redemption/repurchase, the Series D Preferred Units, that the sum of our Revolving Credit Agreement availability and unrestricted cash
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balance is no less than $150.0 million on a pro forma basis both before and immediately after giving effect to the borrowing and the redemption. On January 28, 2022, we amended and restated our Revolving Credit Agreement to, among other items:
(i) increase the maximum amount of letters of credit capable of being issued from $400.0 million to $500.0 million; (ii) replace London Interbank Offering Rate, or LIBOR, benchmark provisions with customary secured overnight financing rate, or SOFR, benchmark provisions; (iii) 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 (iv) add baskets and exceptions to certain negative covenants.

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 the Receivables Financing Agreement with a third-party lender 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 June 29, 2023, we amended the Receivables Financing Agreement to extend the scheduled termination date from January 31, 2025 to July 1, 2026. On January 28, 2022, the Receivables Financing Agreement was amended to, among other items: (i) reduce the floor rate in the calculation of our borrowing rates; and (ii) replace provisions related to the LIBOR rate of interest with references to SOFR rates of interest.

See Note 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of our debt agreements.

Issuance of Common Units
We used the net proceeds of approximately $222.0 million from the issuance of common units on August 11, 2023 to repay outstanding borrowings under our Revolving Credit Agreement. See Note 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.

Asset Sales
We used the proceeds of approximately $103.0 million from the sale of our Corporate Headquarters on March 21, 2023 and approximately $60.0 million from the Point Tupper Terminal Disposition on April 29, 2022 to repay outstanding borrowings under our Revolving Credit Agreement. See Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of these asset sales.

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 ExpendituresReliability Capital ExpendituresTotal
(Thousands of Dollars)
For the year ended December 31:
2023$119,513 $27,995 $147,508 
2022$107,855 $32,775 $140,630 

Strategic capital expenditures for the years ended December 31, 2023 and December 31, 2022 primarily consisted of expansion projects on our Permian Crude System and Central West Refined Products Pipelines, and biofuel and other projects at our West Coast Terminals, as well as connection projects on our Ammonia Pipeline in 2023. Reliability capital expenditures primarily related to maintenance upgrade projects at our terminals and on our Ammonia Pipeline.
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We expect our strategic capital expenditures for the year ended December 31, 2024 to be concentrated on expansion projects to accommodate production growth in the Permian Basin and projects to expand our renewable fuels network on the West Coast. We continue to evaluate our capital budget and internal growth projects can be accelerated or scaled back depending on market conditions or customer demand.

Series D Preferred Units Redemption and Repurchase
We redeemed or repurchased all the Series D Preferred Units, as shown below:
TransactionTransaction DateNumber of UnitsPrice per Unit, including Accrued DistributionsTotal Price, including
Accrued Distributions
(Thousands of Dollars)
RedemptionSeptember 12, 20238,286,650$32.59 $270,062 
RedemptionJuly 31, 20232,560,000$32.18 $82,381 
RedemptionJune 30, 20235,500,000$31.88 $175,340 
RepurchaseNovember 22, 20226,900,000$32.73 $225,837 

See Note 17 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.

Distributions
Preferred Units. Distributions on our outstanding 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. See Notes 17 and 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.

Series D Preferred Units. Prior to their redemption and/or repurchase, the distribution rates on the outstanding Series D Preferred Units were as follows: (i) 9.75% per annum ($0.619 per unit per distribution period) for the first two years (beginning with the September 17, 2018 distribution); (ii) 10.75% per annum ($0.682 per unit per distribution period) for years three through five; and (iii) the greater of 13.75% per annum ($0.872 per unit per distribution period) or the distribution per common unit thereafter. The number of Series D Preferred Units outstanding as of December 31, 2022 was 16,346,650, and due to the redemptions and repurchase discussed above, the Series D Preferred Units were cancelled and no longer represent a limited partner interest.

The distribution rate on the Series D Preferred Units increased on June 15, 2023, to the greater of 13.75% per annum ($0.872 per unit per distribution period) or the distribution per common unit. Distributions accrued for redeemed Series D Preferred Units from the notification dates to the redemption dates are reported in “Interest expense, net” on the consolidated statements of income and are excluded from total distributions below for the applicable periods. Distribution information on the Series D Preferred Units was as follows:
 Distribution PeriodDistribution Rate per UnitTotal Distribution
(Thousands of Dollars)
June 15, 2023 - September 12, 2023$0.872 $5,134 
March 15, 2023 - June 14, 2023$0.682 $10,315 
December 15, 2022 - March 14, 2023$0.682 $11,148 
September 15, 2022 - December 14, 2022$0.682 $14,337 
June 15, 2022 - September 14, 2022$0.682 $15,854 
March 15, 2022 - June 14, 2022$0.682 $15,854 
December 15, 2021 - March 14, 2022$0.682 $15,854 

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Series A, B and C Preferred Units. Information on our Series A, B and C Preferred Units is shown below:
UnitsUnits Issued and Outstanding as of December 31, 2023Optional Redemption Date/Date When Distribution Rate Became FloatingFloating Annual Rate (as a Percentage of the $25.00 Liquidation Preference Per Unit)
Series A Preferred Units9,060,000December 15, 2021
Three-month LIBOR(a) plus 6.766%
Series B Preferred Units15,400,000June 15, 2022
Three-month LIBOR(a) plus 5.643%
Series C Preferred Units6,900,000December 15, 2022
Three-month LIBOR(a) plus 6.88%
(a)Beginning with the distribution period starting on September 15, 2023, LIBOR was replaced with the corresponding CME Term SOFR plus the applicable tenor spread adjustment of 0.26161%.

Distribution information on our Series A, B and C Preferred Units is as follows (thousands of dollars, except per unit data):
Series A Preferred UnitsSeries B Preferred UnitsSeries C Preferred Units
 Distribution PeriodDistribution Rate per UnitTotal DistributionDistribution Rate per UnitTotal DistributionDistribution Rate per UnitTotal Distribution
December 15, 2023 - March 14, 2024$0.77533 $7,024 $0.70515 $10,859 $0.78246 $5,399 
September 15, 2023 - December 14, 2023$0.77736 $7,043 $0.70717 $10,890 $0.78448 $5,413 
June 15, 2023 - September 14, 2023$0.76715 $6,950 $0.69696 $10,733 $0.77428 $5,343 
March 15, 2023 - June 14, 2023$0.73169 $6,629 $0.66150 $10,187 $0.73881 $5,098 
December 15, 2022 - March 14, 2023$0.71889 $6,513 $0.64871 $9,990 $0.72602 $5,010 
September 15, 2022 - December 14, 2022$0.64059 $5,804 $0.57040 $8,784 $0.56250 $3,881 
June 15, 2022 - September 14, 2022$0.54808 $4,966 $0.47789 $7,360 $0.56250 $3,881 
March 15, 2022 - June 14, 2022$0.47817 $4,332 $0.47657 $7,339 $0.56250 $3,881 
December 15, 2021 - March 14, 2022$0.43606 $3,951 $0.47657 $7,339 $0.56250 $3,881 

On January 25, 2024, our Board of Directors declared quarterly distributions with respect to the Series A, B and C Preferred Units to be paid on March 15, 2024 to holders of record as of March 1, 2024.

Common Units. Under our partnership agreement, distribution payments are required to be 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. On January 25, 2024, our Board of Directors declared distributions with respect to our common units for the quarter ended December 31, 2023. The following table summarizes information about cash distributions to our common limited partners applicable to the period in which the distributions were earned:
Quarter EndedCash Distributions
Per Unit		Total Cash DistributionsRecord DatePayment Date
(Thousands of Dollars)
December 31, 2023$0.40 $50,607 February 7, 2024February 13, 2024
September 30, 20230.40 50,358 November 7, 2023November 14, 2023
June 30, 20230.40 44,363 August 8, 2023August 14, 2023
March 31, 20230.40 44,396 May 8, 2023May 12, 2023
Year ended December 31, 2023$1.60 $189,724 
Year ended December 31, 2022$1.60 $176,746 

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Debt Obligations
The following table summarizes our debt obligations:
 MaturityOutstanding Obligations as of December 31, 2023
 (Thousands of Dollars)
5.75% senior notesOctober 1, 2025$600,000 
6.00% senior notesJune 1, 2026$500,000 
Receivables Financing Agreement, 7.0% as of December 31, 2023July 1, 2026$69,800 
Revolving Credit Agreement, 8.0% as of December 31, 2023January 27, 2027$343,000 
5.625% senior notesApril 28, 2027$550,000 
6.375% senior notesOctober 1, 2030$600,000 
GoZone Bonds, 5.85% - 6.35%2038thru2041$322,140 
Subordinated notes, 12.4% as of December 31, 2023January 15, 2043$402,500 

We believe that, as of December 31, 2023, we are in compliance with the financial 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.

Receivables Financing Agreement and Revolving Credit Agreement. 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. Borrowings under our Revolving Credit Agreement bear interest, at our option, at an alternate base rate or a SOFR rate, each as defined in the Revolving Credit Agreement. The interest rate on our Revolving Credit Agreement and certain fees under the Receivables Financing Agreement, 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 RatingsMoody’s Investor Service Inc.S&P Global Ratings
RatingsBBBa3BB-
OutlookStableStablePositive

Gulf Opportunity Zone Revenue Bonds. As reflected in the table below, 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 are expected to 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 following table summarizes the GoZone Bonds outstanding as of December 31, 2023:
SeriesDate IssuedAmount
Outstanding
Interest Rate		Mandatory
Purchase Date		Optional Redemption DateMaturity Date
 (Thousands of Dollars) 
Series 2008June 26, 2008$55,440 6.10 %June 1, 2030n/aJune 1, 2038
Series 2010July 15, 2010100,000 6.35 %n/aJune 1, 2030July 1, 2040
Series 2010AOctober 7, 201043,300 6.35 %n/aJune 1, 2030October 1, 2040
Series 2010BDecember 29, 201048,400 6.10 %June 1, 2030n/aDecember 1, 2040
Series 2011August 9, 201175,000 5.85 %June 1, 2025n/aAugust 1, 2041
Total$322,140 

NuStar Logistics Subordinated Notes.NuStar Logistics’ $402.5 million of fixed-to-floating rate subordinated notes (the Subordinated Notes). Effective with the quarterly interest periods starting after June 30, 2023, the interest rate on the Subordinated Notes is equal to the sum of the three-month CME term SOFR plus the applicable tenor spread adjustment of 0.26161% for the related quarterly interest period plus 6.734%, payable quarterly, 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
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cannot declare or make cash distributions with respect to, or redeem, purchase or make a liquidation payment with respect to, its equity securities during the period that interest payments are deferred.

Guarantor Summarized Financial Information. NuStar Energy has no operations, and its assets consist primarily 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 (i) ranks equally in right of payment with all other existing and future unsecured senior indebtedness of that guarantor, (ii) 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 (iii) ranks 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 is subordinated in right of payment and upon liquidation to the prior payment in full of all other existing and future senior indebtedness of that guarantor. NuPOP will be released from its guarantee when it no longer guarantees any obligations of NuStar Energy or any of its subsidiaries, including NuStar Logistics, under any bank credit facility or public debt instrument. The rights of holders of our senior and subordinated notes may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. See Note 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of our debt agreements.

The following tables present summarized combined balance sheet and income statement information for NuStar Energy, NuStar Logistics and NuPOP (collectively, the Guarantor Issuer Group). Intercompany items among the Guarantor Issuer Group have been eliminated in the summarized combined financial information below, as well as intercompany balances and activity for the Guarantor Issuer Group with non-guarantor subsidiaries, including the Guarantor Issuer Group’s investment balances in non-guarantor subsidiaries.
December 31, 2023
(Thousands of Dollars)
Summarized Combined Balance Sheet Information for the Guarantor Issuer Group:
Current assets$42,000 
Long-term assets$3,160,956 
Current liabilities (a)$135,366 
Long-term liabilities, including long-term debt$3,487,719 
(a)Excluding $1,894.0 million of net intercompany payables due to the non-guarantor subsidiaries from the Guarantor Issuer Group.

Long-term assets for the non-guarantor subsidiaries totaled $1,548.3 million as of December 31, 2023.

Year Ended December 31, 2023
(Thousands of Dollars)
Summarized Combined Income Statement Information for the Guarantor Issuer Group:
Revenues$830,406 
Operating income$333,986 
Interest expense, net$(239,113)
Net income$96,178 

Revenues and net income for the non-guarantor subsidiaries totaled $803.8 million and $177.5 million, respectively, for the year ended December 31, 2023.

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Contractual Obligations
The following table presents our contractual obligations and commitments as of December 31, 2023:
 CurrentLong-Term
 (Thousands of Dollars)
Long-term debt maturities$— $3,387,440 
Interest payments238,001 1,506,912 
Operating leases14,267 238,031 
Finance leases7,067 67,000 
Purchase obligations6,406 12,893 
Total$265,741 $5,212,276 

The interest payments calculated for our variable-rate, long-term debt are based on interest rates and the outstanding borrowings as of December 31, 2023. The interest payments on our fixed-rate debt are based on the stated interest rates and the outstanding borrowings as of December 31, 2023. See Note 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.
Our operating leases consist primarily of land and dock leases at various terminal facilities and the operating lease agreement to lease back the Corporate Headquarters in the first quarter of 2023 (the HQ Lease Agreement), as further discussed in Notes 4 and 15 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.” The HQ Lease Agreement has an initial term of 20 years, with two renewal options of ten years each.
Our finance leases consist primarily of a dock lease at our Corpus Christi North Beach terminal with a remaining term of approximately two years and three additional five-year renewal periods that also includes a commitment for minimum dockage and wharfage throughput volumes. See Note 15 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on our operating and finance leases.
A purchase obligation is an enforceable and legally binding agreement to purchase goods or services that specifies significant terms, including (i) fixed or minimum quantities to be purchased, (ii) fixed, minimum or variable price provisions and (iii) the approximate timing of the transaction. 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.

Pension and Other Postretirement Benefit Plan Contributions
During 2023, we contributed $11.2 million and $0.5 million to our pension and postretirement benefit plans, respectively. In 2024, we expect to contribute approximately $10.2 million to our pension and postretirement benefit plans and will monitor our funding status to determine if any contributions are required by regulations or laws, or with respect to unfunded plans, necessary to fund current benefits. Pension and postretirement benefit plans funding beyond 2024 is uncertain as the funding varies from year to year based upon changes in the fair value of the plan assets and actuarial assumptions.

A change of 0.25% in the specified assumptions would have the following effects to our pension and postretirement benefit obligations and costs:
Pension
Benefits		Other Postretirement Benefits
(Thousands of Dollars)
Increase in benefit obligation as of December 31, 2023 resulting from:
Discount rate decrease$3,300 $400 
Compensation rate increase$600 n/a
(Decrease) increase in net periodic benefit cost for the year ending December 31, 2024
resulting from:
Discount rate decrease$(200)$— 
Expected long-term rate of returns on plan assets decrease$400 n/a
Compensation rate increase$100 n/a

See Notes 2 and 21 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.
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Environmental, Health and Safety
As described below under “Environmental, Health, Safety and Security Regulation,” our operations in the U.S. and Mexico are subject to extensive international, federal, state and local environmental laws and regulations, including those relating to the discharge of materials into the environment, waste management, remediation, the characteristics and composition of fuels, climate change and greenhouse gases. Our operations are also subject to extensive health, safety and security laws and regulations, including those relating to worker and pipeline safety, pipeline and storage tank integrity and operations security. Because more stringent environmental and safety laws and regulations are continuously being enacted or proposed, the level of expenditures required for environmental, health and safety matters is expected to increase in the future.

The balance of and changes in our accruals for environmental matters as of and for the years ended December 31, 2023 and 2022 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.

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, 2023, we had 1,6941,184 employees, of which 1,173 are based in the United States and 11 are based in Mexico. Only 1.1 percent of our employees are represented under collective bargaining agreements. In the United States, 487 of our employees work at our headquarters in San Antonio, Texas, with the remaining 686 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, 2023:
•19.1% of all of our employees and 29.0% of our employees at senior manager level and above are female; and
•34.8% of our U.S. employees and 24.5% of our U.S. employees at senior manager level and above are minorities (as defined by the U.S. Equal Opportunity Employment Commission).

Employee Benefits and NuStar’s Culture
We provide opportunities for our employees to develop and enhance their skills through defined career paths, professional training, educational reimbursement and leadership and development programs, as well as regular training regarding safety, operations, ethics (including our Code of Business Conduct and Ethics), human resources topics and cybersecurity. In addition, we support our employees by providing competitive compensation and benefits.

We benchmark our compensation programs through market surveys to help offer competitive packages to attract and retain high-performing employees. Our compensation department also evaluates company-wide racial and gender equity by job-profile each time an employee is hired or recommended for a promotion. This helps to ensure that compensation levels are equitable for all employees regardless of race or gender.


Our benefits and health and wellness programs include life and health insurance (medical, dental and vision), prescription drug benefits, flexible spending accounts, paid sick leave, vacation, short- and long-term disability, mental and behavioral health resources, retirement benefits (including 401(k) and pension), educational reimbursement, a disaster relief fund that provides cash grants (that do not have to be repaid) to employees undergoing difficult circumstances, an employee assistance program and employee recognition programs. We also are committed to supporting the communities in which we operate, and we organize opportunities for our employees to participate in and enrich our communities through a variety of initiatives, such as fundraising activities, community clean-up projects and educational programs.

Our culture is driven by our nine guiding principles: safety; integrity; commitment; make a difference; teamwork; respect; communication; excellence; and pride. We believe that these principles are the building blocks for our success and have helped us to recruit and retain our employees and make NuStar a great place to work. We have been recognized on FORTUNE’S “100 Best Companies to Work For” list 13 times, FORTUNE’S “Best Workplaces for Millennials” list five times, the “Best Places For Working Parents” list three times, and Latino Leader Magazine’s “Best Companies for Latinos to Work” list three times. We also were recognized as a top employer by regional and local publications, including being recognized as a top employer in Texas by FORTUNE. In addition, we were recently recognized on Newsweek’s “America’s Most Trustworthy Companies” and “World’s Most Trustworthy Companies” lists. 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, 2023, our voluntary
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turnover rate over the last five years has averaged 3.8%, and 231 of our employees have been employed by NuStar or predecessor entities for at least 20 years.

Safety
Safety is our first priority. In managing our business, we focus on the safety of our employees and contractors, as well as the communities in which we operate. We have implemented safety programs and management practices to promote a culture of safety, including required training for field and office employees and contractors, as well as specific qualifications and certifications for field employees and contractors. To further emphasize the importance of safety at NuStar, our Board of Directors receives a comprehensive annual report and monthly updates regarding our health, safety and environmental performance. The Compensation Committee of our Board of Directors also evaluates our overall environmental, social and governance (ESG) performance and our health, safety and environmental performance together annually as one of the metrics used to determine the annual incentive bonus for all of our employees, including our executive officers, which we believe reinforces the importance of maintaining safe, responsible operations and focusing on ESG excellence.

We are proud of NuStar’s safety performance. Our 2023 total recordable incident rate (TRIR) of 0.55 was better than the 3.60 average most recently reported by the U.S. Bureau of Labor Statistics (BLS) for the bulk terminals industry and in line with the 0.50 average most recently reported by BLS for the pipeline transportation industry. Our 2023 days away, restricted or transferred rate (DART) of 0.39 was better than the 2.80 average most recently reported by BLS for the bulk terminals industry and in line with the 0.30 average most recently reported by BLS for the pipeline transportation industry. NuStar also participates in the Occupational Safety and Health Administration’s (OSHA) Voluntary Protection Program (VPP), which promotes effective worksite health and safety. Achieving VPP Star status requires rigorous OSHA review and audit, and requires recertification every three to five years. As of December 31, 2023, approximately 92% of our eligible U.S. terminals have attained VPP Star status. NuStar also has received the International Liquids Terminals Association’s Safety Excellence Award 13 times.

Sustainability Report
We publish a Sustainability Report, which covers topics similar to those described above, including our guiding principles; operations and economic impact; environmental and safety programs; sustainability; renewable fuels-related services; policies and statistics (including greenhouse gas emissions disclosures); employee development and training; diversity and inclusion; community involvement and development; recent awards; risk management; cybersecurity; and governance. Our Sustainability Report can be viewed at https://sustainability.nustarenergy.com. Our Sustainability Report and the information contained on our website are not part of this Annual Report on Form 10-K, are not “soliciting materials,” are not deemed filed with the SEC and are not to be incorporated by reference into any of NuStar Energy’s filings under the Securities Act of 1933 or the Securities Act of 1934, as amended, respectively.

PROPERTIES

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

RATE REGULATION


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


The Ammonia PipelineOur ammonia pipeline is subject to regulation by the STB pursuant to the Interstate Commerce ActICA applicable to such pipelines (which differs from the ICA applicable to interstate liquids pipelines). Under that regulation, the Ammonia Pipeline’sammonia pipeline’s rates, classifications, rules and practices related to the interstate transportation of anhydrous ammonia must be reasonable and, in providing interstate transportation, the Ammonia Pipelineammonia 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.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,Mexico, including those relating to the discharge of materials into the environment, waste management, remediation, the characteristics and composition of fuels, climate change and greenhouse gases. In 2023, our capital expenditures attributable to compliance with environmental regulations were $5.5 million, and we currently project environmental regulatory compliance spending of approximately $12.5 million in 2024.

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.

In 2017, our capital expenditures attributable to compliance with environmental regulations were $13.9 million, and we currently project spending to be approximately $17.8 million in this regard in 2018. However, future Future governmental actions could result in thesemore restrictive laws and regulations, becoming more restrictive, necessitating additionalwhich could increase required capital expenditures and operating expenses. At this time, we are unable to estimate either the effectimpact, 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. In addition, while we believe that we are in substantial compliance with the environmental, health, safety and security laws and regulations applicable to our operations, risksThe risk of additional compliance expenditures, expenses and liabilities are inherent within the industry.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

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
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Occupational Safety and Health Administration’s Process Safety Management regulations. These regulations apply to processes whichthat involve certain chemicals at or above specified thresholds.


FUEL STANDARDS AND RENEWABLE ENERGYFuel Standards and Renewable Energy

Federal,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 alternativerenewable fuels such as biodiesel.and blending additives, like ethanol, biodiesel and renewable diesel. These programs may over time offset projected increases or reduce the demand for refined petroleum products, particularly gasoline, in certain markets. However, the increased production and use of biofuelsrenewable fuels may also create opportunities for pipeline transportation and fuel blending. Other legislative changes in the future may similarly alter the expected demand and supply projections for refined petroleum products in ways that cannot be predicted.


HAZARDOUS SUBSTANCES & HAZARDOUS WASTE

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. Our current operating and disposal practices complyDespite our compliance with applicable laws, regulationsrequirements and industry standards, and we believe our past practices complied at the time. Despite our compliance, 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 regarding clean up levels,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.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

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.air, including greenhouse gas emissions. These laws and regulations generally require permits issued by applicable federal, state or statelocal 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

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
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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 safety,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’s Pipeline Security Guidelines. Administration.

We believetake proactive steps to protect our company, systems and data from cyberattacks. See Item 1C. “Cybersecurity” for our cybersecurity considerations.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with U.S. generally accepted accounting principles (GAAP) 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 following summary provides further information on our accounting policies that involve critical accounting estimates due to judgments made by management and the sensitivity of these estimates to deviations of actual results from management’s assumptions. The critical accounting estimates should be read in conjunction with Note 2 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data,” which summarizes our significant accounting policies.
Impairment of Long-Lived Assets
We test long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount of 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 are in material compliance with all applicable lawsperform 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 regulations regarding the security of our facilities.

While we are not currentlycriteria required to implement specific governmental regulatory protocolsclassify an asset as held for sale are met, we determine the protectionamount of our computer-based systems and technology from cyber threats and attacks, proposalsimpairment as the amount by which the net carrying amount exceeds its fair value less costs to do so are being considered bysell.

In determining the existence of an impairment of the carrying value of an asset, we make a number of U.S. governmental departmentssubjective 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 agencies, including
•if an impairment exists, the Departmentfair value of Homeland Security. We currently havethe 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 own cybersecurity programsassumptions and protocols in place; however, we cannot guarantee their effectiveness,estimates could differ significantly from actual results and successful penetrationcould cause a different conclusion about the recoverability of our critical systemsassets. If we determined one or more assets was impaired, the amount of impairment could be material to our results of operations.
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 material effectqualitative 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.
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We recognize an impairment of goodwill if the carrying value of a reporting unit that contains goodwill exceeds its estimated fair value. In order to estimate the fair value of the reporting unit, including goodwill, management must make certain estimates and assumptions that affect the total fair value of the reporting unit including, among other things, an assessment of market conditions, projected cash flows, discount rates and growth rates. Management’s estimates of projected cash flows related to the reporting unit include, but are not limited to, future earnings of the reporting unit, assumptions about the use or disposition of assets included in the reporting unit, estimated remaining lives of those assets, and future expenditures necessary to maintain the assets’ existing service potential.

We calculate the estimated fair value of each of our reporting units using a weighted average of values calculated using an income approach and a market approach. The income approach involves estimating the fair value of each reporting unit by discounting its estimated future cash flows using a discount rate, consistent with a market participant’s assumption. The market approach bases the fair value measurement on information obtained from observed stock prices of public companies and recent merger and acquisition transaction data for 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.

NEW ACCOUNTING PRONOUNCEMENTS

See Note 3 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of new accounting pronouncements.

AVAILABLE INFORMATION
Our internet website address is www.nustarenergy.com. Information contained on our operationswebsite is not part of this report. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and thosecurrent 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 customers and vendors.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.


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ITEM 1A.    RISK FACTORS


RISKS RELATED TO THE POTENTIAL MERGER

While the Merger Agreement is in effect, we may be limited in our ability to pursue other attractive business opportunities.
While the Merger Agreement is in effect, we have agreed to refrain from taking certain actions with respect to our business and financial affairs pending the consummation of the Merger or termination of the Merger Agreement. These restrictions could be in effect for an extended period of time if the consummation of the Merger is delayed. These limitations do not preclude us from conducting our business in the ordinary or usual course or from acquiring assets or businesses so long as such activity does not have a “material adverse effect,” as such term is defined in the Merger Agreement, or exceed certain thresholds specifically provided in the Merger Agreement.

In addition to the economic costs associated with pursuing the Merger, the management of our general partner will continue to devote substantial time and other human resources to the proposed Merger, which could limit our ability to pursue other attractive business opportunities, including potential joint ventures, stand-alone projects and other transactions. If we are unable to pursue such other attractive business opportunities, our growth prospects and the long-term strategic position of our business following the Merger could be adversely affected.

Our existing unitholders will be diluted by the Merger.
The Merger will dilute the ownership position of our existing unitholders. Pursuant to the Merger Agreement, NuStar GP Holdings unitholders will receive approximately 23.6 million of our common units as a result of the Merger. Assuming the number of units outstanding as of January 31, 2018, immediately following the Merger, our common units would be owned approximately 78% by our current common unitholders and approximately 22% by former NuStar GP Holdings unitholders.

SUNOCO’S PROPOSED ACQUISITION OF NUSTAR
The Merger is subject to a number of conditions to the obligations of both NuStar and Sunoco to complete the Merger, including approval by NuStar’s common unitholders and regulatory clearance, which may not be consummated even ifimpose unacceptable conditions or could delay completion of the requiredMerger or result in termination of the Merger Agreement.
On January 22, 2024, NuStar GP Holdings unitholder approvalsentered into a definitive agreement (the Merger Agreement), whereby Sunoco will acquire NuStar in an all-equity transaction (the Merger). The respective obligations of each of NuStar and Sunoco to consummate the Merger are obtained.
The Merger is subject to the satisfaction at or waiver of certain conditions, some of which are out of the control of NuStar GP Holdings and NuStar Energy, including approval of the Merger Agreement by NuStar GP Holdings unitholders. The Merger Agreement also contains other conditions that, if not satisfied or waived, would result in the Merger not occurring, regardless of whether or not the NuStar GP Holdings unitholders have voted in favor of the Merger-related proposals presented to them. Satisfaction of some of these other conditionsprior to the Merger is not entirely in the controlclosing of either NuStar GP Holdings or NuStar Energy. In addition, NuStar GP Holdings and NuStar Energy can agree not to consummate the Merger even if all unitholder approvals have been received. The closingnumerous conditions, to the Merger may not be satisfied, and NuStar GP Holdings and NuStar Energy may choose not to, or may be unable to, waive an unsatisfied condition, which may cause the Merger not to occur.

The Merger Agreement contains provisions granting both NuStar Energy and NuStar GP Holdings the right to terminate the Merger Agreement for certain reasons, including, among others (1)other things, approval by mutual consentNuStar’s common unitholders, the absence of NuStar Energy and NuStar GP Holdings; (2) by either party if the Merger has not been consummated onany law or before August 8, 2018; (3) if certain changes in rules or regulations prohibitorder prohibiting the consummation of the Merger; (4) if NuStar GP Holdings fails to obtain NuStar GP Holdings unitholder approval;Merger, and the expiration or (5) if a breachtermination of or an inaccuracy in, the representations or warranties is not cured within thirty days. Furthermore, NuStar Energy may terminatewaiting period (and any extension of such period) under the Merger Agreement inHart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.Many of the event that, prior to NuStar GP Holdings unitholder approval, NuStar GP Holdings has intentionally and materially breached the non-solicitation covenants in the Merger Agreement or the NuStar GP Holdings board issues a change of recommendation pursuantconditions to the termscompletion of the Merger Agreement,are not within either NuStar’s or Sunoco’s control, and NuStar GP Holdings may terminatecannot predict when, or if, these conditions will be satisfied. Furthermore, the Merger Agreement in order to accept a Superior Proposal (as defined inrequirement for obtaining the Merger Agreement) so long as NuStar GP Holdings (1) has not intentionally and materially breached certain provisionsrequired regulatory clearances could delay the completion of the Merger Agreementfor a significant period of time or prevent it from occurring.Regulators may seek to enjoin the completion of the Merger, seek divestiture of substantial assets of the parties, or require the parties to license, or hold separate, assets or terminate existing relationships and (2) has paid NuStar Energy a termination fee.contractual rights.


Failure to complete the Merger or delays in completing the Merger could negatively impact the price of our common unit price.units and have a material adverse effect on our results of operations, cash flows and financial position.
If the Merger is not completed for any reason, including as a result of failure to obtain all requisite regulatory and unitholder approvals, our ongoing business may be materially and adversely affected and, without realizing any of the benefits of having completed the Merger, we maywould be subject to a number of material risks, including the following:
•we may experience negative reactions from the financial markets, including negative unit price impacts;
•we may experience negative reactions from commercial and business partners; and
•we will not realize the benefits expected from the Merger, including a potentially enhanced financial and competitive position;
the price of our common units may declinestill be required to the extent that the current market price of these securities reflects a market assumption that the Merger will be completed; and
somepay certain significant costs relating to the Merger, such as legal, accounting, financial advisor, and printing fees.

In addition, if the Merger Agreement is terminated under certain investment banking fees and legal and accounting fees, mustcircumstances specified therein, we may be paid even ifrequired to pay Sunoco a termination fee of approximately $90.3 million.

If the Merger is not completed.completed, the risks described above may materialize and they may have a material adverse effect on our results of operations, cash flows, financial position, and the price of our publicly-traded units.



The costsannouncement and pendency of the Merger may adversely affect our business, financial results and operations.
Whether or not the Merger is completed, its announcement and pendency could cause disruptions to our business, including:
•uncertainties associated with the Merger may cause us to lose management personnel and other key employees, which could adversely affect our future business and operations and cash flows available for distributionfollowing the Merger;
•our business relationships may be subject to our unitholders.
The total costs ofdisruption due to uncertainty associated with the Merger, which could have a material adverse effect on our results of operations, cash flows, and financial position;
•matters relating to the Merger (including integration planning) require substantial commitments of time and resources by our management, which may result in the distraction of our management from ongoing business operations and pursuing other opportunities that could be substantial, primarily consist of investment banking, legal counselbeneficial to us; and accounting fees, financial printing and other related costs. These costs could adversely affect
•the Merger Agreement places certain restrictions on how we conduct our operations, which may delay or prevent us from undertaking business opportunities that, absent the Merger Agreement, we may have pursued.

Sunoco may fail to realize the anticipated benefits of the Merger and cash flows available for distributionsfail to successfully integrate the businesses and operations of the parties in the expected time frame.
The success of the Merger, and the value that our unitholders.common unitholders who receive Sunoco common units following the Merger will realize, depends on, among other things, the successful combination of NuStar’s and Sunoco’s businesses in a manner that realizes anticipated synergies and benefits and meets or exceeds the forecasted stand-alone cost savings anticipated by the combined business. If the combined business is not able to successfully achieve these synergies, or the cost to achieve these synergies is greater than expected, then the anticipated benefits of the Merger may not be realized fully or at all or may take longer to realize than expected. If the transaction closes, it is possible that the integration process could result in the loss of key NuStar employees or key Sunoco employees, the loss of customers, providers, vendors, or business partners, the disruption of either or both parties’ ongoing businesses, inconsistencies in standards, controls, procedures, and policies, potential unknown liabilities and unforeseen expenses, delays, or regulatory conditions associated with and following completion of the Merger, or higher than expected integration costs and an overall post-completion integration process that takes longer than originally anticipated.

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In addition, at times the attention of certain members of our management team and resources may be focused on the completion of the Merger and planning the anticipated integration, and diverted from day-to-day business operations or other opportunities that may have been beneficial to NuStar, which may disrupt our ongoing business and the operations of the combined business.

We may be subject to litigation challenging the Merger, and an unfavorable judgment or ruling in any such lawsuits could prevent or delay the consummation of the Merger and/or result in substantial costs.
Lawsuits related to the Merger may be filed against us, Sunoco, and our respective affiliates, directors and officers. If dismissals are not obtained or a settlement is not reached, these lawsuits could prevent or delay completion of the Merger and/or result in substantial costs to us.

RISKS RELATED TO OUR BUSINESS

Changes in price levels could negatively impact our revenue, our expenses, or both, which could adversely affect our financial position, results of operations and cash flows.
The operation of our assets and the execution of capital projects require significant expenditures for labor, materials, property, equipment and services. As a result, such costs may increase during periods of high inflation, including as a result of rising commodity prices, supply chain disruptions and tight labor markets. Recent inflationary pressures affecting the general economy and the energy industry have increased our expenses and capital costs, and those costs may continue to increase. While we expect our pipeline systems to benefit from the positive revenue impact of our tariff indexation increases, we may not be able to pass all of these increased costs to our customers in the form of higher fees for our services, and, if so, our revenues and operating margins would be negatively impacted. Prior to adjustments to applicable rates, material cost increases may affect our operating margins, even if margins in subsequent periods may be normalized following applicable rate adjustments. Accordingly, increased costs during periods of high inflation that are not passed through to customers or offset by other factors may have a material adverse effect on our financial position, results of operations and cash flows.

We may not be able to generate sufficient cash from operations to enable us to pay quarterly distributions to our unitholders.
The amount of cash that we can distribute to our unitholders each quarter principally depends upon the amount of cash we generate from our operations, which fluctuates from quarter to quarter based on, among other things:
throughput •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;
storage contract renewals or throughput volumespipelines 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;
demand for and supply of crude oil, refined products and anhydrous ammonia;
the effect of worldwide energy conservation measures;
our operating costs;
the costs to comply with environmental, health, safety and security laws and regulations;
weather conditions;
•domestic and foreign governmental laws, regulations, sanctions, embargoes and taxes;
prevailing economic conditions;•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.


In addition,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 debtfinancing agreements;
the sources of cash used to fund our acquisitions;
•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;
issuances of•fluctuations in interest rates on our variable rate debt instruments and equity securities and ability to access the capital markets; andpreferred units;
•adjustments in cash reserves made by our board of directors, in its discretion.discretion;

•availability of and access to equity capital and debt markets; and
On February 8, 2018,•the sources of cash used to fund our acquisitions, if any.

Moreover, the total amount of cash that we announced that our management anticipates recommendinghave available for distribution to common unitholders is further reduced by the required distributions with respect to our board of directors, and our board of directors expects to adopt, a reset of our quarterly distribution per common unit to $0.60 ($2.40 on an annualized basis), starting with the first-quarter distribution payable in May 2018. In addition, it is possible that one or more of thepreferred units. The factors listed above, which may serve tobe further impacted by public health crises, international conflicts, actions of oil-producing nations and other factors beyond our control, may reduce our available cash to such an extent that we could be renderedare unable to pay distributions at the current level or at all in a given quarter. Furthermore, cashCash 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, anditems. 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.


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Extended periods of reduced demand for or supply of crude oil, refined products, renewable fuels and anhydrous ammonia 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, refined products, renewable fuels and anhydrous ammonia we transport in our pipelines and store in our terminals. Market prices for these products are subject to wide fluctuation in response to changes in global and regional supply and demand 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 crude oil, refined products, renewable fuels or anhydrous ammonia 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, high interest rates, 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;
•higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline;
•an increase in aggregate automotive engine fuel economy;
•new government and regulatory actions or court decisions requiring the phase out or reduced use of gasoline-fueled vehicles;
•the increased use of and public demand for use of alternative fuel sources or electric vehicles;
•an increase in the market price of crude oil that increases refined product prices, which may reduce demand for refined products and increase demand for alternative products; and
•adverse weather events resulting in decreased corn acres planted, which may reduce demand for anhydrous ammonia.

Similarly, any sustained decrease in the supply of crude oil, refined products, renewable fuels or anhydrous ammonia 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 the supply of and prices for crude oil and refined products;
•a lack of drilling services, equipment or skilled personnel available to producers to accommodate production needs;
•changes in laws, regulations, sanctions or taxation that directly or indirectly delay supply or production or increase the cost of production of refined products; and
•political unrest or hostilities, activist interference and the resulting governmental response thereto.

Failure to retain or replace current customers and renew existing contracts on comparable terms to maintain utilization of our pipeline and storage assets at current or more favorable rates could reduce our revenue and cash flows to levels that could 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 existing contracts or enter into new contracts on acceptable terms 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, renewable fuels or anhydrous ammonia 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 our customers and our ability to conduct our operations;
•competition for customers from companies with comparable assets and capabilities;
•scheduled turnarounds or unscheduled maintenance at refineries or production facilities of customers we serve;
•operational problems or catastrophic events affecting our assets or the 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;
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•a decision by our current customers to redirect products transported in our pipelines or stored in our terminals to markets not served by our pipelines or terminals, or to transport or store crude oil, refined products or anhydrous ammonia by means other than our pipelines or storage terminals; and
•a decision by our current customers to shut down, limit operations of or sell one or more of the refineries/production facilities we serve to a purchaser that elects not to use our pipelines or 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. In addition, there are fewer investors and lenders for master limited partnership debt and equity capital market issuances than there are for corporate issuances, and negative public sentiment toward the fossil fuel energy industry has led some investors and lenders to reduce or cease investing in and lending to fossil fuel energy companies. As a result, the cost of raising capital has increased, the availability of funds has diminished and certain lenders have, and others may, refuse to refinance existing debt on similar terms or at all and reduce, or in some cases cease to provide, funding to borrowers such as us.

In general, if we do not generate sufficient cash from operations to finance our expenditures and funding from external sources is not available when needed, or is available only on unfavorable terms, we may be unable to execute our growth strategy, complete future acquisitions or construction projects or take advantage of other business opportunities and may be required to reduce investments or capital expenditures or sell assets, which could have a material adverse effect on our revenues and results of operations, and we may not be able to satisfy our debt obligations or pay distributions to our unitholders.

Our future financial and operating flexibility may be adversely affected by our significant leverage, any future downgrades of our credit ratings, restrictions in our debt agreements and conditions in the financial markets.markets beyond our control.
As of December 31, 2017,2023, our consolidated debt was $3.6$3.4 billion, and we have the ability to incur more debt. We also may be required to post cash collateral under certain of our hedging arrangements, which we expect to fund with borrowings under our revolving credit agreement. In addition to any potential direct financial impact of our debt, it is possible that anya material increase to our debt or other negativeadverse financial factors maywould likely be viewed negatively by credit rating agencies, which could result in ratings downgrades, and increased costs or inability for us to access the capital markets. In November 2017, S&P Global Ratings downgraded our credit rating from BB+ Stable to BB Negative outlook, which raised themarkets, an increase in interest raterates on our 7.65% Senior Notes Due 2018 (the 2018 Senior Notes). In February 2018, Moody’s Investors Service, Inc. downgraded our credit rating from Ba1 to Ba2, which increased the interest rate on both the 2018 Senior Notes and amounts borrowed under our credit facilities. Any additional downgradesRevolving Credit Agreement and an increase in certain fees under our Receivables Financing Agreement.

Certain affirmative and restrictive covenants in our credit ratings in the future could result in further increases to the interest rate on the 2018 Senior Notes, significantly increase our capital costs, reduce our liquiditydebt agreements and other debt service obligations may adversely affect our ability to raise capital in the future.

future financial and operating flexibility. Our revolving credit agreementRevolving Credit Agreement contains customary restrictive covenants, such as limitations on indebtedness, liens, mergers, asset transfers and certain investing activities. In addition, the revolving credit agreement generally requires us toFor example, we must maintain as of the end of each rolling period (consisting of any period of four consecutive fiscal quarters) a consolidated debt coverage ratio (consolidated debt to consolidated EBITDA, each asConsolidated Debt Coverage Ratio (as defined in the revolving credit agreement)Revolving Credit Agreement) that does not to exceed 5.00-to-1.00

except and a minimum Consolidated Interest Coverage Ratio (as defined in specific circumstances, including acquisitions for aggregate net considerationthe Revolving Credit Agreement) of at least $50 million, when we are permitted to maintain a consolidated debt coverage ratio of up to 5.50-to-1.00 for two rolling periods, as provided in the revolving credit agreement. Our maximum permitted ratio was raised to 5.50-to-1.00 through March 31, 2018 due to our acquisition of Navigator Energy Services, LLC. We also amended our revolving credit agreement in November 2017 to exclude NuStar Logistics’ 7.625% Fixed-to-Floating Rate Subordinated Notes due 2043 (the Junior Sub Notes) from our calculation of consolidated debt through December 31, 2018.1.75-to-1.00. Failure to comply with any of the revolving credit agreement restrictive covenants or our requiredthe maximum consolidated debt coverage ratio will resultor minimum consolidated interest coverage ratio requirements would constitute an Event of Default (as defined in a defaultour Revolving Credit Agreement) and could result in acceleration of our obligations under our Revolving Credit Agreement and potentially other agreements. Our Receivables Financing Agreement, senior notes and other debt obligations also contain various customary affirmative and negative covenants, default, indemnification and termination provisions, which provide for acceleration of amounts owed upon the revolving credit agreement and possibly other indebtedness.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 financingdebt agreements.

Our accounts receivable securitization program contains various customary affirmative and negative covenants and default, indemnification and termination provisions, and the related receivables financing agreement (pursuant to which we are initial servicer and performance guarantor) provides for acceleration of amounts owed upon the occurrence of certain specified events.


Our debt service obligations, restrictive covenants, ratio requirements and maturities resulting from our leverage may adversely affect our ability to finance future operations, pursue acquisitions, fund our capital needs and pay cash distributions to our unitholders. For example, upon the occurrence of specified events under certain of our debt agreements, we would be prohibited from making 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. Also, if any of our lenders file for bankruptcy or experience severe financial hardship, they may not honor their pro rata share of our borrowing requests under the revolving credit agreement, which may significantly reduce our available borrowing capacity and, as a result, materially adversely affect our financial condition and ability to pay 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 the trading price of our units, as well as, our financial condition, results of operations, cash flows and ability to make distributions to unitholders, as well as the trading priceunitholders.

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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.
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 and uncertainty in the market. In addition, there are fewer investors and lenders for master limited partnership debt and equity capital market issuances than there are for corporate issuances. As a result, the cost of raising capital in the debt and equity capital markets could increase substantially, possibly at a time when the availability of funds from these markets has diminished. The cost of obtaining funds from the credit markets may increase as interest rates increase and tighter lending standards are enacted, and lenders may refuse to refinance existing debt on similar terms or at all and reduce, or in some cases cease to provide, funding to borrowers.

In addition, lending counterparties under our existing revolving credit facility and other debt instruments may be unwilling or unable to meet their funding obligations. Due to these factors, we cannot be certain that new financing or funding will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to execute our growth strategy, complete future acquisitions or construction projects or take advantage of other business opportunities, any of which could have a material adverse effect on our revenues and results of operations.

A significant portion of our debt matures over the next five years and will need to be paid or refinanced, and changes to the debt and equity markets could limit our refinancing options.
A significant portion of our debt is set to mature within the next five years, including our revolving credit facility. We may not be able to refinance our maturing debt on commercially reasonable terms, or at all, depending on numerous factors, including our financial condition and prospects at the time and the then-current state of the banking and capital markets in the United States.

IncreasesChanges in interest rates could adversely affect our business, access to credit and capital markets, 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.instruments and our Series A, Series B and Series C Preferred Units. At December 31, 2017,2023, we had approximately $3.6$3.4 billion of consolidated debt, of which $2.3$2.6 billion was at fixed interest rates

and $1.3$0.8 billion was at variable interest rates. Also, in January 2018 the interest rateThe distribution rates on our Junior Sub Notes shiftedSeries A, Series B and Series C Preferred Units have converted from a fixed rate to a floating annual rate equal to the sum of the three-month LIBOR rate for the related quarterly interest period, plus 6.734%. Additionally, at December 31, 2017, we had $600.0 million aggregate notional amount of interest rate swap arrangements, which may expose us to risk of financial loss. Prior ratings downgrades on our existing indebtedness caused interest rates under our revolving credit agreement and our 2018 Senior Notes to increase, and any future downgrades may further increase the interest rate on our 2018 Senior Notes.rates. Our results of operations, cash flows and financial position could be materially adversely affected by significant changes in interest rates. In addition, we historically have fundedrates and uncertainty regarding the floating rates referenced in our strategicvariable rate debt instruments and preferred units could adversely affect the value of those financing arrangements. Please see “Quantitative and Qualitative Disclosures about Market Risk” for discussion of our market risk related to interest rates.

We plan to self-fund all of our expenses, distribution requirements and capital expenditures for 2024 using internally generated cash flows as we did for the full-years 2023, 2022 and acquisitions from external sources, primarily borrowings under our revolving credit agreement or funds raised through debt or equity offerings.2021. An increase in interest rates may also have a negative impact on our ability to access the capital markets, refinance existing debt or incur new debt at economically attractive rates.rates, which could adversely affect our future growth by limiting our operational and financial flexibility.


Furthermore,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 aours. A rising interest rate environment could have an adverse impact on our unit price and impair our ability to issue additional equity, or incur new debt to fund growth, satisfy our existing debt obligations or for other purposes, including distributions.

Continued low crude oil prices could have an adverse impact on our results of operations, cash flows and ability to makepay distributions to our unitholders.
Since late 2014, the price of crude oil has been depressed, which has caused most crude oil producers to reduce their capital spending and drilling activity and narrow their focus to assets in the most cost-advantaged regions. On the other hand, refiners have benefited from lower crude prices, to the extent that lower feedstock price has been coupled with higher demand for certain refined products in some regional markets. While only a portion of our total business is directly affected by the price of crude, continued low crude oil prices and related overall economic downturn could have a negative impact on our cash flows and results of operations.

An extended period of reduced demand for or supply of crude oil and refined products could affect our results of operations and ability to make distributions to our unitholders.
Although we enter into throughput and deficiency agreements to protect against near-term fluctuations whenever possible, our business is ultimately dependent upon the long-term demand for and supply of the crude oil and refined products we transport in our pipelines and store in our 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 or other adverse economic condition that results in lower spending by consumers on gasoline, diesel and travel;
higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline;
an increase in automotive engine fuel economy, whether as a result of a shift by consumers to more fuel-efficient vehicles or technological advances by manufacturers;
new regulations or court decisions requiring the phase out or reduced use of gasoline-fueled vehicles;
the increased use of alternative fuel sources;
an increase in the market price of crude oil that leads to higher refined product prices, which may reduce demand for refined products and drive demand for alternative products. 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, and 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; 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, which could lead to a decrease in exploration and development activity and reduced production in markets served by our pipelines and storage terminals;
a lack of drilling services or equipment 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

macroeconomic forces affecting, or actions taken by, foreign oil and gas producing nations that impact supply of and prices for crude oil and refined products.


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 or anhydrous ammonia 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.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 acquire new assets, due either to high prices or a lack of attractive synergistic targets, our future growth will be limited. In addition, our future growth will be limited if we are unable to develop additionaland 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 adverselyhave 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 couldmay adversely affect our financial condition, results of operations and cash flows.
Delays or cost increases related to capital spending programs involving construction of new facilities (or improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted operating results. AlthoughWhile we evaluate and monitor each capital spending project and try to anticipate difficulties that may arise, such delays or cost increases may arise as a result of factors that are beyond our control, including:
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;
protests and other activist interference with planned or in-process projects;
unplanned increases in the cost of construction materials or labor;
disruptions in transportation of modular components and/or construction materials;
severe adverse weather conditions, natural disasters or other events (such as hurricanes, equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors and suppliers;
shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages; or
market-related increases in a project’s debt or equity financing costs.

We will incur financing costs during the planning and construction phases of our projects; however, theprojects, a project does not generate expected operating cash flows we expect these projects to generate will not materialize until sometime after the projects areit is at least substantially completed, if at all. Additionally, our forecasted operating results from capital spending projects are based upon our projections ofon future market fundamentals that are not within our control, including changes in general economic conditions, the supply and demand of crude oil, and refined products, renewable fuels and anhydrous ammonia, availability to our customers of attractively priced alternative solutions for storage, transportation or supplies of crude oil, and refined products, renewable fuels and anhydrous ammonia and overall customer demand.

If we are unable to retain As a result of these uncertainties, the anticipated benefits associated with our capital projects may not be achieved or replace current customers and existing contracts to maintain utilizationcould be delayed. In turn, this could have a negative impact on our results of our pipeline and storage assets at current or more favorable rates, our revenueoperations and cash flows could be reducedflow and our ability to levelsmake cash distributions to our unitholders.

Although we evaluate and monitor each capital spending project and try to anticipate difficulties that couldmay arise, unforeseen circumstances may adversely affect our ability to make quarterly distributionscomplete such projects as planned, if at all. 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 (such as extreme temperatures, hurricanes, tornadoes, storms, floods and earthquakes) or other events (such as equipment malfunctions, explosions, fires, spills or public health events) affecting our facilities or employees;
•denial or delay in issuing requisite regulatory approvals and/or permits;
•delay or increased costs to obtain right-of-way or other property rights;
•protests and other activist interference with planned or in-process projects;
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•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.

Any of the above factors may also adversely affect the facilities, operations or employees of counterparties, vendors, suppliers, contractors, sub-contractors or other third parties involved with 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 our storage customers’ material reduction of utilization under existing contractsprojects, which could result from many factors, including:in non-performance or delay by, or disputes with, such parties.
continued 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 another country impacting a customer based there;
competition for customers from companiesWe compete with comparable assets and capabilities;
scheduled turnarounds or unscheduled maintenance at refineries we serve;
operational problems or catastrophic events affecting our assets or a refinery we serve;
environmental proceedings or other litigation that compel the cessation of all or a portion of the operations at our assets or a refinery we serve;
increasingly stringent environmental, health, safety and security regulations;
a decision by our current customers to redirect refined 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; or

a decision by our current customers to sell one or more of the refineries we serve to a purchaser that elects not to use our pipelines and terminals.

Competing midstream service providers, including certain major energy and chemical companies, that 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 reduceadversely affect 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 may 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 of our 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 in the future.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 couldwould have a negative effect on our revenue, cash flows and ability to make quarterly distributions to our unitholders.


Our operations are subject to operational hazards and interruptions, and we cannot insure against and/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 such as natural disasters,due to adverse weather conditions, natural disasters (such as heat waves, freezing temperatures, hurricanes, tornadoes, storms, floods and floods)earthquakes), accidents, fires, explosions, hazardous materials releases, mechanical failures, cyberattacks, acts of terrorism and other events beyond our control. In addition, many scientists hypothesize that global climatic changes are occurring that are likely to cause an increase in hurricanes and other severe weather conditions. These events mighthave, 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. InAdditionally, 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 eventfuture. If 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 earnings, our other results of operations and our financial condition as a whole.

As a result of market conditions and losses experienced by us and other companies, the premiums and deductibles for certain of our insurance policies have increased substantially and could escalate further;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. CertainIn addition, certain insurance coverage couldis subject to broad exclusions, and may become subject to broadfurther exclusions, become unavailable altogether or become available only for reduced amounts of coverage and at higher rates. For example,We are not fully insured against all hazards and risks to our business, and the insurance carriers require broad exclusionswe carry requires us to meet deductibles before we collect for losses due to terrorist acts.we sustain. If we were to 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 could be subject to damages or lose customers due to failure to maintain certain quality specifications or other claims related to the operation of our assets and the services we provide to our customers.
Certain of the products we store and transport are produced to precise customer specifications. If we fail to maintain the quality and purity of the products we receive and/or a product fails to perform in a manner consistent with the quality specifications required by the customer, the customer could seek replacement of the product or damages for costs incurred as a result of the product failing to perform as guaranteed. We also could 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. A successful claim or series of claims against us could result in unforeseen expenditures and a loss of one or more customers.


We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, vendors or derivativeother counterparties could reducereduces our revenues increaseand increases our expenses, and otherwiseany significant level of nonpayment or 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 couldmay 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. Severe financialFinancial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements. For example, a substantial portion of our St. Eustatius facility revenue derives from our storage of petroleum products exported from Venezuela on behalf of Petróleos de Venezuela, S.A. (PDVSA), a state-owned Venezuelan oil company. Significant political, social and economic instability in Venezuela, including constraints on foreign currency transactions by the Venezuelan government, has caused PDVSA to utilize our assets significantly less than we forecasted and late-pay invoices from time to time. Our involvement with products exported from Venezuela also exposes us to the risk of trade restrictions and economic embargoes imposed by the United States and other countries.

In addition, nonperformance by vendors or their subcontractors, who have committed to provide us with critical products or services, could raiseincreases our costs and could result in significant disruptions or interfere with our ability to successfully conduct our business. Furthermore, nonpayment by the counterparties to any

of our outstanding derivatives could expose us to additional interest rate or commodity price risk. WhileAlthough we attempt to mitigate our risk through warehouseman’s liens and other security protections, anywe cannot fully eliminate counterparty credit risks. Any substantial increase in the nonpayment andor nonperformance by our customers, vendors or other counterparties, or our inability to enforce our 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.


Cybersecurity breaches and other disruptions could compromise our information and operations, and expose us to liability, which would cause our business and reputation to suffer.
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We rely on our information technology infrastructureand 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 electronic information, such as employee, customer and vendor data, and to conduct almost all aspects of our business, including informationsafely 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 usehave limited visibility and control, and that have access to safely operateor store certain of our assets. In recent years, there has beenemployee, 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 rise in thecyberattack. The number and sophistication of reported cyberattacks on other companies’ network and information systems by both state-sponsored and criminal organizations and as a result, the risks associated with such an event continue to increase.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, some of our employees and those of our service providers, vendors and customers may travel or work from home or other remote-work locations, where cybersecurity protections may be less robust and cybersecurity procedures and safeguards may be less effective. Moreover, certain attacker techniques and goals, such as surveillance, intelligence gathering or extended reconnaissance, may remain undetected for an extended period of time, which can increase the breadth and negative impact of an incident. A significant failure, compromise, breach or interruption in our systems or those of third parties critical to our operations could result in a disruption of our operations, customer dissatisfaction,operations; physical damage to our reputation, aassets or the environment; physical, financial, or other harm to employees or others; safety incidents; damage to our reputation; loss of customers or revenuesrevenues; increased costs for remedial actions; and potential litigation or regulatory fines. If any such failure, interruptionFailures, interruptions and similar events that result in the loss or similar event results in improper disclosure of information maintained in our information systems and networks or those of our vendors, including personnel, customer and vendor information, we could also be subject to liabilityhave in the past and may in the future require reporting under relevant contractual obligations and laws and regulations protecting personal data and privacy.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 operationalour systems are breached or an employee, vendor or customer causes our operational systems to fail, either as a result of inadvertent error or by deliberatelydeliberate tampering with or manipulatingmanipulation of our operational systems.


Due to the continued acceleration of cyberattacks, generally and against our industry, regulatory actions by federal, state and local governmental agencies in the United States and in Mexico have increased. Evolving laws and regulations governing cybersecurity and data privacy and protection pose increasingly complex compliance challenges. Although we believe that we have robust information securitycybersecurity procedures and other safeguards in place, as cyberthreatswe 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 may be requiredhave spent and expect to expendcontinue spending additional resources to continue to enhance our information securitycybersecurity, data protection, business continuity and incident response measures, and/or to investigate and remediate information security vulnerabilities.any vulnerabilities to, or consequences of, cyber incidents, as well as on regulatory compliance.


Acquisitions and expansions, if any, may increase substantiallyDisputes regarding a failure to maintain product quality specifications or other claims related to the leveloperation of our indebtedness and contingent liabilities or otherwise change our capital structure, and we may be unable to integrate acquisitions and expansions effectively into our existing operations.
From time to time, we evaluate and acquire assets and businesses that we believe complement or diversify our existing assets and operations. Acquisitions may require us to raise a substantial amount of equity or incur a substantial amount of indebtedness. If we consummate any future material acquisitions, our capitalization and results of operations may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in connection with any future acquisitions.

Part of our overall business strategy includes acquiring additional assets that complement our existing asset base and distribution capabilities or provide entry into new markets. We may not be able to identify suitable acquisitions, or we may not be able to purchase or finance any acquisitions on terms that we find acceptable. Additionally, we compete against other companies for acquisitions, and we may not be successful in the acquisition of any assets or businesses appropriate for our growth strategy.

Even if we do consummate acquisitions that we believe will increase distributable cash flow, these acquisitions may nevertheless result in a decrease in distributable cash flow. Any acquisition involves potential risks, including, among other things:
we may not be able to obtain the cost savings and financial improvements we anticipate or acquired assets may not perform as we expect;
we may not be able to successfully integrate the assets, management teams or employees of the businesses we acquire with our assets and management team, or such integrationthe services we provide to our customers may be significantly delayed;
we may fail or be unable to discover some of the liabilities of businesses that we acquire, including liabilities resulting from a prior owner’s noncompliance with applicable federal, state or local laws;
we may have assumed prior known or unknown liabilities for which we may not be indemnified or have adequate insurance;
acquisitions may divert the attention of our senior management from focusing on our core business;
we may experience a decreaseresult in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;unforeseen expenses and
we may face the risk that our existing financial controls, information systems, management resources and human resources will need to grow to support future growth.

We operate a global business that exposes us to additional risk.
We operate a global business. A significant portion of our revenues come from our business outside of the United States, and our operations are subject to various risks unique to each country 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, war and other armed conflict; inflation; and currency fluctuations, devaluation and conversion restrictions. We are also exposed to the risk of governmental actions that may: limit or disrupt markets for our operations, restrict payments or limit the movement of funds; impose sanctions on our ability to conduct business with certain customers or persons; or result in the deprivationloss of contract rights. Our operations outsidecustomers.
Certain of the United States may also be affectedproducts 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 changesour customers, customers have sought, and could in trade protection laws, policies and measures, and other regulatory requirements affecting trade and investment, including the Foreign Corrupt Practices Act,future seek, replacement of the United Kingdom Bribery Act and other foreign laws prohibiting corrupt payments,product or damages for costs incurred as wella result of the product failing to perform as import and export regulations. Additionally, negotiations are ongoing regarding the United Kingdom’s exit from the European Union, and any future effects from this are currently unknown.

guaranteed. We also have assets in, or do business with customers based in, certain emerging markets,faced, and the developing nature of these markets presents a number of risks. In addition, due to the unsettled political conditions in many oil-producing countries, our operations may be subject to the adverse consequences of war, civil unrest, strikes, currency controls and governmental actions.
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 and managing foreign operations, may adversely affect our operations or financial results. For example, PDVSA, a state-owned oil company in Venezuela, is a significant customer of our terminal facility in St. Eustatius, and recent political, social and economic instability in Venezuela seems to have had a negative impact on both PDVSA’s utilization of our facility and its ability to timely pay amounts invoiced.

We are subject to laws and sanctions implemented by the United States and foreign jurisdictions where we do business that may restrict the type of business we are permitted to conduct with certain entities, including PDVSA, restrict our activities in certain countries, or even restrict the services we may provide with respect to crude oil or other products produced in certain countries.   In 2017, the United States and the European Union imposed sanctions relating to Venezuela and PDVSA.  While these sanctions do not prohibit us from continuing to perform under our existing contracts with PDVSA, the sanctions may increase the likelihood that PDVSA will be unable to perform its obligations to us.  In addition, in the event additional sanctions are imposedcould in the future relating to Venezuelaface, other claims by our customers if our assets do not operate as expected by our customers or PDVSA, such future sanctions mayour services otherwise do not meet our customers’ expectations. Successful claims or a series of claims against us result in further deterioration of PDVSA’s ability to perform its obligations to usunforeseen expenditures and could prevent us from continuing to serve PDVSA in St. Eustatius.

We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of increased costs or the inability to retain necessary land use.
We obtain the rights to construct and operate our pipelines, storage terminals and other facilities on land owned by third parties and governmental agencies. 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. Our loss of property rights, through our inability to renew right-of-way contracts or leases or otherwise, could adversely affect our operations and cash flows available for distribution to unitholders.

In addition, the construction of additions to our existing assets may require us to obtain new rights-of-way or property rights prior to construction. We may be unable to obtain such rights-of-way or other property rights to connect new supplies to our existing pipelines, storage terminals or other facilities or to capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or other property rights or to renew existing rights-of-way or property rights. If the cost of obtaining new or renewing existing rights-of-way or other property rights increases, it may adversely affect our operations and cash flows available for distribution to unitholders.

We may be unable to obtain or renew permits necessary for our operations, which could inhibit our ability to do 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 impositionloss of fines, penalties and injunctive relief. In addition, public protest and responsive government intervention have recently made itone or more difficult for some energy companies to acquire the permits required to complete planned infrastructure projects. A decision by a government agency to deny or delay issuing a new or renewed permit, license or approval, or to revoke or substantially modify an existing permit, license or approval, could have a material adverse effect on our ability to continue operations and on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.customers.

We may have liabilities from our assets that preexist our acquisition of those assets, but that may not be covered by indemnification rights we may have against the sellers of the assets.
In some cases, we have indemnified the previous owners and operators of acquired assets. Some of our assets have been used for many years to transport and store crude oil and refined products, and releases may have occurred in the past that 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 future releases or other liabilities arise from assets we have sold, we could incur costs related to those liabilities if the buyer possesses valid indemnification rights against us with respect to those assets.


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, and increase our operating costs.costs or reduce our ability to expand our facilities.
In response to scientific studies asserting that emissions of certain “greenhouse gases” such as carbon dioxide and methane may be contributing to warming ofClimate change laws or regulations enacted by the Earth’s atmosphere, the U.S. Congress, European UnionUnited States and other political bodies that increase costs, reduce demand or otherwise impede our operations, could, directly or indirectly, have considered legislationan adverse effect on our business. Legislative and
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regulatory initiatives in the United States, as well as international efforts, have attempted to and will continue to address climate change and control or regulation to reducelimit emissions of greenhouse gases. Passage of climate change or fuels legislation or other regulatory initiatives in fuel efficiency, fuel additives, renewable fuels and other areas in which we conduct business could result in changesFor example, the United States is now a party to the demand forParis 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. Specifically, certain regulatory changes have restricted, and future changes could restrict, our ability to expand our operations and have increased, and in the products we store, transport and sell, andfuture could increase, the costs of our operations, including 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 greenhouse gas or other emissions, pay any taxes or fees related to our greenhouse gas or other emissions or administer and manage an emissions programs. 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 can result insubject us to potential requirements to purchase renewable energyfuels credits. Even though we attempt to mitigate such lost revenues or increased costs through the contracts we sign with our customers, we may be unablesometimes are not able to recover those revenues or mitigate the increased costs, and any such recovery may dependdepends on events beyond our control, including the outcome of future rate proceedings before the FERC, the STBFederal Energy Regulatory Commission (FERC) or other regulators and the provisions of any final legislation or regulations. Reductions in our revenues or increases in our expenses as a result of climate change legislation or other regulatory initiatives could have adverse effects on our business, financial position, results of operations and prospects.


Finally, increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. Such events have had and may in the future have an adverse effect on our assets and operations, especially those located in coastal regions.

Public sentiment towards climate change, fossil fuels and sustainability could adversely affect our business, operations and ability to attract capital.
Our business plans are based upon the assumption that public sentiment and the regulatory environment will continue to enable the future development, transportation and use of carbon-based fuels. Negative public perception of the industry in which we operate and the influence of environmental activists and initiatives aimed at limiting climate change could interfere with our business activities, operations and access to capital. Activists concerned about the potential effects of climate change have directed their attention towards sources of funding for fossil fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital reducing or ceasing lending to or investing in companies in the fossil fuel energy industry, such as us. Having a more limited pool of lenders and investors has resulted in an increase in costs to raise capital, a decrease in the availability of new funding and a diminished ability to refinance existing debt at favorable rates for businesses such as ours, which could have a material adverse effect on our ability to meet our future capital needs, satisfy our debt obligations or pay distributions to our unitholders.

Members of the lending and investment communities 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 lending and investment communities screen companies such as ours for sustainability performance before lending to us or investing in our units. In response to the increasing pressure regarding sustainability disclosures and practices, we and other companies in our industry publish sustainability reports that are made available to lenders and investors. Such reports are used by some lenders and investors to inform their lending, 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 lender and investor sentiment toward us or our customers and to the diversion of capital to other industries, which would have a negative impact on our unit price and/or our access to and costs of capital. Such negative sentiment regarding our industry could influence consumer preference and decrease demand for the products we transport and store and may 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.

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,Mexico, relating to environmental, health, safety and security that could 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 thatof releasing these products may be released 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, certain of our pipeline facilities may beare subject to the
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pipeline integrity and safety regulations of various federal and state regulatory agencies.agencies, as well as cybersecurity directives. In recent years, increased regulatory focus on pipeline integrity, safety and safetysecurity 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.


Current and future legislativeLegislative action and regulatory initiatives have resulted in, and could alsoin the future result in, changes to operating permits, imposition of carbon taxes or methane fees, material changes in operations, increased capital expenditures and operating costs, increased costs of the goods we transport andand/or decreased demand for products we handle thathandle. Future impacts cannot be assessed with certainty at this time. We may be required to makeRequired expenditures to modify operations or install pollution control equipment or release prevention and containment systems thator 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 may impose joint and several liability on us for the conduct of third parties or for actions that complied with applicable requirements when taken, regardless of negligence or fault. If we were to incur a significant liability pursuant to environmental, health, safety or security laws or regulations, such a liability could have a material adverse effect on our financial position.


We operate assets outside of the United States, which exposes us to different legal and regulatory requirements and additional risk.
A portion of our revenues are generated from our assets located in northern Mexico. Our operations are subject to various risks unique to Mexico that could have a material adverse effect on our business, results of operations and financial condition, including political and economic instability from civil unrest; labor strikes; war and other armed conflict; inflation; currency fluctuations, devaluation and conversion restrictions or other factors. Any deterioration of social, political, labor or economic conditions, including the increasing threat of terrorist organizations and drug cartels in Mexico, or affecting a customer with whom we do business, as well as difficulties in staffing, obtaining necessary equipment and supplies and managing foreign operations, may adversely affect our operations or financial results. We are also exposed to the risk of foreign and domestic governmental actions that may: impose additional costs on us; delay permits or otherwise impede our operations; limit or disrupt markets for our operations, restrict payments or limit the movement of funds; impose sanctions on or otherwise restrict our ability to conduct business with certain customers or persons or in certain countries; or result in the deprivation of contract rights. Our operations outside the United States may also be affected by changes in trade protection laws, policies and measures, and other regulatory requirements affecting trade and investment, including the Foreign Corrupt Practices Act and foreign laws prohibiting corrupt payments, as well as travel restrictions and import and export regulations.

We may be unable to obtain or renew permits necessary for our current or proposed operations, which could inhibit our ability to conduct or expand our business.
Our facilities operate under a number of federal, state and local permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. These limits and standards require a significant amount of monitoring, recordkeeping and reporting in order to demonstrate compliance with the underlying permit, license or approval. Noncompliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. In addition, public protest, political activism and responsive government intervention have made it more difficult for energy companies to acquire the permits required to complete planned infrastructure projects. A decision by a government agency to deny or delay issuing a new or renewed permit, license or approval, or to revoke or substantially modify an existing permit, license or approval, or to impose additional requirements on the renewal 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.

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Certain of our interstate common carrier pipelines are subject to regulation by the FERC.FERC and the Surface Transportation Board, 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.
ThePursuant to the Interstate Commerce Act (ICA) and various other laws, the FERC regulates the tariff rates and terms and conditions of service for interstate crude oil and refined products movements on our common carrier pipelines. The FERC regulations requirerequires that these rates must be just and reasonable and that the pipeline not engage in undue discrimination or undue preferenceunduly discriminatory with respect to any shipper. Under the ICA, theThe FERC or shippers may challenge ourrequired pipeline tariff filings, including rates and terms and conditions of service. Further, other than for rates set under market-based rate authority, if a new rate is challenged by protest and investigated by the FERC, the FERC may suspend collection ofrequire amounts refunded where such new rate for up to seven months. If such new rate is found to be unjust and unreasonable, the FERC may order refunds of amounts were collected in excess of amounts generated by the deemed just and reasonable rate determined by the FERC. A successful rate challenge could result in a common carrier paying refunds together with interest for the period that the rate was in effect.rate. In

addition, shippers may challenge by complaint tariff rates and terms and conditions of service even after the ratesthey take effect, and terms and conditions of service are in effect. If the FERC, in response to such a complaint or on its own initiative, initiates an investigation of rates that are already in effect, the FERC may order a carrier to change its rates prospectively. If existing rates are challenged and are determined by the FERCprospectively to be in excess of a just and reasonable level, anylevel. A complaining shipper also may obtain reparations for damages sustained during the two years prior to the date of the shipper filed a complaint.


We are able to use various FERC-authorized rate change methodologies for our interstate pipelines, including indexed rates, cost-of-service rates, market-based rates and settlementnegotiated rates. Typically, we adjust our rates annually in accordance with the FERC indexing methodology, which currently allows a pipeline to change its rates within prescribed ceiling levels that are tied to an inflation index. For the five-year period beginning July 1, 2011,It is possible that the index was measured by the year-over-year changemay result in the Bureau of Labor’s producer price index for finished goods, plus 2.65%. For the five-year period beginning July 1, 2016, the current index is measured by the year-over-year change in the Bureau of Labor’s producer price index for finished goods, plus 1.23%. Further, some of our newer projects that involved an open season include negotiated indexation rate caps.

In October 2016, the FERC initiated an Advance Notice of Proposed Rulemaking (ANOPR) to determine whether to require oil pipeline companies to file cost and revenue data for each of the company’s pipeline systems, with the definition of such systems also part of the ANOPR. Among other things, the ANOPR also proposed that indexnegative rate adjustments be cappedin some years, or prohibited under certain circumstances and that ceiling rates be capped under certain circumstances. These methodologies, if adopted, could result in changes in our revenue that do not fully reflect changes in costs we incur to operate and maintain our pipelines. For example, our costs could increase more quickly or by a greater amount than the negotiated or, if adopted, FERC-mandated indexation rate cap.

The reporting of system-based cost and revenue data, if adopted as a result of the ANOPR, could lead to an increase in rate litigation at the FERC. Currently, shippers may protest rate increases made within the ceiling levels, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s change in costs from the previous year. However, if the index results in a negative adjustment, we are required to reduce any rates that exceed the new maximum allowable rate. In addition, changes in the index might not be large enough to fully reflect actual increases in our costs. IfThe FERC’s indexing methodology is subject to review and revision every five years, with the FERC’s rate-making methodologies change, any such change or new methodologiesmost 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. The 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, which could result in a further change to the index. The FERC has granted us authority to charge market-based rates that generate loweron 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 flow and could adversely affect our ability to make distributions to our unitholders and to meet our debt service requirements.flows. Additionally, because competition constrains our rates in various markets, wewhich may from time to time be forcedforce us to reduce some of ourcertain rates to remain competitive.


ChangesPursuant to the ICC Termination Act of 1995 (ITA), the Surface Transportation Board (STB) regulates interstate pipelines carrying products other than gas, oil or water, including the anhydrous ammonia we transport. Unlike the ICA, which allows the FERC rate-making principlesto investigate a carrier’s rates on its own initiative, ITA prescribes the STB may only investigate issues in response to complaints by shippers and other interested parties. Further, carriers are not required by the ITA or pronouncementsthe STB to report rates charged to transport anhydrous ammonia or other commodities, and the STB does not routinely collect such information. Adverse changes in the FERC’s or STB’s rate change methodologies or challenges to our rates that result in significant damages could have an adverse impact onnegatively affect our ability to recover the full costcash flows, results of operating our pipeline facilitiesoperations and our ability to make distributions to our unitholders.
In May 2005, the FERC issued a statement of general policy stating it will permit pipelines to include in their costs of service a tax allowance to reflect actual or potential tax liability on their public utility income attributable to
We do not own all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liabilityland on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. Although this policy is generally favorable forwhich our pipelines thatand facilities are organized as pass-through entities, it still entails rate risk duelocated, and we are therefore subject to the case-by-case review requirement. This tax allowance policypossibility 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 FERC’s applicationright to utilize for these purposes through contract (rather than through outright purchase). Many of that policy were appealed to the D.C. Circuit and, on May 29, 2007, the D.C. Circuit issued an opinion upholding the FERC’s tax allowance policy.

In two proceedings involving SFPP, L.P., a refined products pipeline system, shippers again challenged the FERC’s income tax allowance policy, alleging that it is unlawfulour rights-of-way or other property rights are perpetual in duration, but others are for a pipeline organized as a tax-pass-through entityspecific period of time. In addition, some of our facilities are located on leased premises. A potential loss of property rights through our inability to be afforded an income tax allowancerenew 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 that the income tax allowance is unnecessary because an allowancecash flows available for income taxes for such pipelines is recovered indirectly through the rate of return on equity.  The FERC rejected these shipper arguments in multiple orders.  Petitions for review of the FERC’s rulings on the income tax allowance were filed with the D.C. Circuit.distribution to our unitholders.

On July 1, 2016, the D.C. Circuit issued an opinion granting the shippers’ petition for review of the FERC’s rulings on the income tax allowance, finding that the FERC had failed to demonstrate that there is no double recovery of taxes for partnerships that receive an income tax allowance in addition to the return they receive through the rate of return on equity. On this basis, the D.C. Circuit remanded the issue to the FERC, which established a pending industrywide Notice of Inquiry regarding this issue. Certain participants in the Notice of Inquiry made filings claiming that pipeline rates should be reduced based on anticipated income tax reductions related to the Tax Cuts and Jobs Act. Because the extent to which an interstate oil pipeline organized as a partnership is entitled to an income tax allowance is subject to a case-by-case review at the FERC and is a matter that remains under litigation and FERC review, the level of income tax allowance to which we would ultimately be entitled is not certain. The manner in which the FERC’s income tax allowance policy is applied to pipelines owned by publicly traded partnerships could limit our ability to include a full income tax allowance in our cost of service.


The rates that we may charge on our interstate ammonia pipeline are subject to regulation by the STB.
The Ammonia Pipeline is subject to regulation by the STB, which is part of the DOT. The Ammonia Pipeline’s rates, rules and practices related to the interstate transportation of anhydrous ammonia must be reasonable and, in providing interstate transportation, our ammonia pipeline may not subject a shipper to unreasonable discrimination.


Increases in natural gas and 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, 2017,2023, our power costs equaled approximately $46.0$48.2 million, or 10.2%13% of our operating expenses for the year. We use mainly electric power at our pipeline pump stations and terminals, and such electric power is furnished by various utility companies that primarilycompanies. Requirements for utilities to use natural gasless carbon intensive power or to generate electricity. Accordingly, our power costs typically fluctuate with natural gas prices, and increases in natural gas prices mayadd pollution control devices also could cause our power costs to increase further. If natural gas prices increase,and our cash flows may be adversely affected, which could adversely affect our ability to make distributions to our unitholders.


Terrorist attacksWe may be adversely affected by changes in the method of determining the London Interbank Offering Rate (LIBOR) or the replacement of LIBOR with an alternative reference rate, such as the Secured Overnight Financing Rate (SOFR).
The publication of non-U.S. dollar LIBOR rates ceased after publication on December 31, 2021 and the threatpublication of U.S. dollar LIBOR rates for the most common tenors (overnight and one, three, six and twelve months) is ceased after publication on June 30, 2023. In addition, in March 2022, the Adjustable Interest Rate (LIBOR) Act (the “LIBOR Act”) was signed into law. This law provides a statutory fallback mechanism to replace LIBOR with a benchmark rate that is selected by the Federal Reserve Board and based on SOFR for certain contracts that reference LIBOR without adequate fallback provisions providing for a clearly defined replacement benchmark. On December 16, 2022, the Federal Reserve Board adopted a final rule to
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implement the LIBOR Act and established benchmark rates based on SOFR to replace LIBOR contracts governed by U.S. law that reference certain tenors of U.S. dollar LIBOR after June 30, 2023. The regulations include provisions that (i) provide a mechanism for the automatic replacement of LIBOR with the benchmark rate selected by the Federal Reserve Board; (ii) clarify who may contractually select a benchmark replacement for LIBOR; and (iii) ensure that contracts transitioning to the replacement benchmark rate selected by the Federal Reserve Board will not be interrupted or terminated following the replacement of LIBOR. On June 30, 2023, the publication of U.S. dollar LIBOR rates ceased and, beginning with the distribution period starting on September 15, 2023, the distribution rates on our Series A, Series B and Series C preferred units converted from a floating rate based on three-month LIBOR to three-month CME Term SOFR plus the applicable tenor spread adjustment of 0.26161%, in accordance with the guidance and the applicable rules and regulations governing such transition. The consequences of the transition away from LIBOR and the use of SOFR cannot be entirely predicted but could include an increase in the cost of our variable-rate indebtedness, our Series A, Series B and Series C preferred units and other commercial arrangements tied to LIBOR.

An impairment of goodwill or long-lived assets could reduce our earnings.
As of December 31, 2023, we had $0.7 billion of goodwill and $3.8 billion of long-lived assets, including property, plant and equipment, net and intangible assets, net. GAAP 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. Any event that causes a reduction in demand for our services could result in a reduction of our estimates of future attacks worldwide, as well as continued hostilitiescash flows and growth rates in the Middle East or other sustained military campaigns, may adversely impact our results of operations.
The United States Department of Homeland Security has identified pipelines and other energy infrastructure assets as ones that might be specific targets of terrorist organizations. These potential targets might include our pipeline systems, storage facilities or operating systems and may affect our abilitybusiness, which could cause us to operate or control our pipeline and storage assets. Increased security measures we have taken as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products, instability in the financial markets that could restrict our ability to raise capital and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of,record an attack.

Hedging transactions may limit our potential gains or result in significant financial losses.
While intendedimpairment charge to reduce the effectsvalue of volatile commodity prices, hedging transactions, depending ongoodwill. Similarly, any event or change in circumstances that causes the hedging instrument used,carrying value of our long-lived assets to no longer be recoverable may limit our potential gains if petroleum product prices were to rise substantially over the price established by the hedge. In addition, such transactions may exposerequire us to record an impairment charge to reduce the risk of financial loss in certain circumstances, including instances in which there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices received.

The accounting standards regarding hedge accounting are complex and, even when we engage in hedging transactions that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our financial statements will reflect increased volatility due to these hedges, even when there is no underlying economic impact at that point. It is not possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices, and our financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into an effective hedge.

Our purchase and sale of crude oil and petroleum products may expose us to trading losses and hedging losses, and non-compliance with our risk management policies could result in significant financial losses.
Although our marketing and trading of crude oil and petroleum products represents a small percentagevalue of our overall business, these activities expose us to some commodity price volatility risk for the purchase and sale of crude oil and petroleum products, including distillates and fuel oil. We attempt to mitigate this volatility risk through hedging, but we are still exposed to basis risk and may be required to post cash collateral under our hedging arrangements. We also may be exposed to inventory and financial liquidity risk due to the inability to trade certain products or rising costs of carrying some inventories. Further, our marketing and trading activities, including any hedging activities, may cause volatility in our earnings. In addition, we will be exposed to credit risk in the event of non-performance by counterparties.

Our risk management policies may not eliminate all price risk since open trading positions will expose us to price volatility, and there is a risk that our risk management policies will not be complied with. Although we have designed procedures to anticipate and detect non-compliance, we cannot assure you that these steps will detect and prevent all violations of our trading policies and procedures, particularly if deception and other intentional misconduct are involved.

long-lived assets. If we fail to maintain an effective system of internal controls, we may not be able to reportdetermine that either our financial results accurately or prevent fraud, which could have a material and adverse impact on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.
Under Section 404 of the Sarbanes-Oxley Act of 2002, we are required to disclose material changes made in our internal controls over financial reporting on a quarterly basis and we are required to assess the effectiveness of our controls annually.

Effective internal controls are necessary for us to provide reliable and timely financial reports. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404.

For the foregoing reasons, we can provide no assurance as to our,goodwill or our independent registered public accounting firm’s, future conclusions aboutlong-lived assets are impaired, the effectiveness of our internal controls,resulting charge will reduce earnings and we may incur significant costs in our efforts to comply with Section 404. Any failure to maintain effective internal controls over financial reporting will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have a material adverse effect on our financial condition, results of operations and cash flows and our ability to make distributions to our unitholders.partners’ capital.


RISKS INHERENT IN AN INVESTMENT IN US

WeAs a master limited partnership, we do not have the same flexibility asthat corporations and other types ofbusiness organizations may have to accumulate cash and equity and protect againstprevent illiquidity in the future.future, which may 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, and debt service requirements. As a result, we do not accumulate equity in the form of retained earnings in a manner typical of many other forms of organizations, including most traditional public corporations.requirements and payments with respect to our preferred units. We are therefore more likely than those organizations to require issuances of additional capitaldebt and equity securities to finance our growth plans, meet unforeseen cash requirements and service our debt.

Additionally,debt and other obligations. To the extent we issue additional units, 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 moreadditional equity to recapitalize.

Our cash distribution policy may limit our growth.
Consistent with the terms of our partnership agreement, we distribute our available cash to our common unitholders and our general partner each quarter. In determining the amount of cash available for distribution, our management sets aside cash reserves which we use to fund our growth capital expenditures. Additionally, we historically have relied upon external financing sources, including commercial borrowings and other debt and equity issuances, to fund our acquisition capital expenditures. Accordingly, to the extent we do not have sufficient cash reserves or are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. 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 or increase our current per unit distribution level.

NuStar GP Holdings may currently have and, if the Merger is not consummated, may continue to have conflicts of interest and limited fiduciary responsibilities, which may permit it to favor its own interests to the detriment of our unitholders.
NuStar GP Holdings currently indirectly owns our general partner, our incentive distribution rights and, as of December 31, 2017, an aggregate 11.0% of our outstanding common units. Conflicts of interest may arise between NuStar GP Holdings and its affiliates, including our general partner, on the one hand, and us and our limited partners, on the other hand. As a result of these conflicts, the general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:
our general partner is allowed to take into account the interests of parties other than us, such as NuStar GP Holdings, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;
our general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to unitholders. As a result of purchasing our units, unitholders have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;
our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings and issuances of additional limited partner interests and reserves, each of which can affect the amount of cash that is paid to our unitholders;
our general partner determines in its sole discretion which costs incurred by NuStar GP Holdings and its affiliates are reimbursable by us;
our general partner may cause us to pay the general partner or its affiliates for any services rendered on terms that are fair and reasonable to us or enter into additional contractual arrangements with any of these entities on our behalf;
our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and

in some instances, our general partner may cause us to borrow funds in order to permit the payment of distributions.

Our partnership agreement gives the general partner broad discretion in establishing financial reserves for the proper conduct of our business, including interest payments. These reserves also affect the amount of cash available for distribution.

If the Merger is not consummated, the general partner interest, the control of our general partner and the incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.
If the merger is not consummated, our general partner may transfer its general partner interest and/or its incentive distribution rights to a third party without the consent of our unitholders. Any new owner of our general partner would be in a position to replace the officers of the general partner with its own choices and to control the decisions made by such officers. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights.


Unitholders have limited voting rights, and our partnership agreement further restricts the voting rights of certain unitholders owning 20% or more of any class of our units.
Unlike holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders’Our unitholders’ voting rights are further restricted by a provision in our partnership agreement providing that units held by certain persons that own 20% or more of any class of units then outstanding other than our general partner or its affiliates, cannot vote on any matter without the prior approval of our general partner.


We may issue an unlimited number of additional units,equity securities, including unitsequity securities that are senior to theour common units, and pari passu withwhich would dilute our 8.50% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units, 7.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units and 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (collectively, the Preferred Units); issuing new units dilutesunitholders’ existing unitholders and may increase the aggregate distribution we are required to pay each quarter under the terms of our partnership agreement.ownership interests.
Our partnership agreement allows us to issue an unlimited number of additional units and certain other equity securities on the terms and conditions established by our general partner and without the approval of other unitholders. There is no limit onunitholders as long as the total number of units and othernewly issued equity securities we may issue.  If we issue additional unitsare not senior to, or other equity securities, the proportionate partnership interest ofequally ranked with, our existing common unitholders and the relative voting strength of each of the previously outstanding common units will decrease.  Any additional issuance may increase the risk that we will be unable to maintain or increase our per common unit distribution level.

In addition, wepreferred units. We may issue an unlimited number of units that are senior to theour common units and equally ranked with our preferred units. However, in right of distribution, liquidation and voting, including additional Preferred Units and any securities in parity withcertain circumstances, we may be required to obtain the Preferred Units without any voteapproval of the holders of the Preferred Units (except where the cumulative distributions on the Preferred Units or any parity securities are in arrears and in certain other circumstances) and without the approvala majority of each class of our common unitholders. preferred units before we could issue equity securities that are equally ranked with our preferred units.

Our issuance of additional units or other equity interests of equal or senior rank will have the following effects:
•our unitholders’ proportionate ownership interest in us will decrease;
•the amount of cash available for distribution on each unit may decrease;
•the amount of cash available for redemption of, or payment of the liquidation preference on, each preferred unit may decrease;
•the ratio of taxable income to distributions may increase;
•the relative voting strength of each previously outstanding unit may be diminished; and
•the market price of our common units and Preferred Unitspreferred units may decline.

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Additionally, although holdersTable of the Preferred Units are entitled to limited voting rights, with respect to certain matters the Preferred Units generallyContents
In addition, our partnership agreement requires that unitholders vote separately as a separate class along with all other series of our parityequally ranked securities that we may issue upon which likebe issued and possess similar voting rights have been conferred and are exercisable.rights. As a result, the voting rights of holders of Preferred Unitsour preferred units may be significantly diluted, and the holders of such other seriesfuture securities of parity securities that we may issueequal rank may be able to control or significantly influence the outcome of any vote with respect to which the holders of the Preferred Unitsour preferred units are entitled to vote. The issuance of additional units on parity with or senior to the Preferred Units (including additional Preferred Units of the same series) would dilute the interests of the holders of the Preferred Units, and any issuance of equity securities of any class or series that ranks on parity with the Preferred Units as to the payment of distributions and amounts payable upon a liquidation event (including additional Preferred Units of the same series) or equity securities with terms expressly made senior to the Preferred Units as to the payment of distributions and amounts payable upon a liquidation event or additional indebtedness could affect our ability to pay distributions on, redeem or pay the liquidation preference on the Preferred Units. Our partnership agreement contains limited protections for the holders of the Preferred Units our preferred unitsin the event of a highly leveraged or other

transaction, including a merger, or the sale, lease or conveyance of all or substantially all of our assets or business, which might adversely affect the holders of the Preferred Units.our preferred units.


Future issuances and sales of parity securities that rank equally with our preferred units, or the perception that such issuances and sales could occur, may cause prevailing market prices for the Preferred Unitsour preferred units and our common units to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us.

Furthermore, the payment of distributions on any additional units may increase the risk that we will not be able to make distributions at our prior per unit distribution levels. To the extent new units are senior to our common units, their issuance will increase the uncertainty of the payment of distributions on our common units.


If we do not pay distributions on our Preferred Unitspreferred units in any fiscal quarter,distribution period, we willwould be unable to declare or pay distributions on our common units until all unpaid Preferred Unit distributionspreferred unit distribution obligations have been paid, and our common unitholders are not entitled to receive distributions for such prior period.
The Preferred UnitsOur preferred units rank senior to our common units with respect to distribution rights and rights upon liquidation. If we do not pay the required distributions on our Preferred Units,preferred units, we will be unable to declare or pay distributions on our common units. Additionally, because distributionsDistributions to our Preferred Unitholderspreferred unitholders are cumulative, so we will have tomust pay all unpaid accumulated preferred distributions before we can declare or pay any distributions to our common unitholders. Also, because distributionsDistributions to our common unitholders are not cumulative, therefore, 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.that would have accumulated in that quarter. The preferences and privileges granted to holders of the Preferred Unitsour preferred units could adversely affect the market price for our common units orand could make it more difficult for us to sell our common units in the future.


Unitholders may not have limited liability ifIf a court findswere to determine that a unitholder action constitutesconstituted control of our business, orthe unitholders may lose their legal protection from liability and be required to repay distributions wrongfully distributed to them.
Our partnership agreement is governed by the laws of the State of Delaware. If a Delaware court were to determine that we have not complied with applicable statutes, which may have an impact onactions of a unitholder constituted participation in the cash we have available to make distributions.
Under Delaware law, unitholders could“control” of our business, that unitholder would be held liable for our obligations to the same extent as a general partner if a court determined that actions of a unitholder constituted participation in the “control” of our business.

partner. Under Delaware law, thea general partner generally has unlimited liability for the obligations of the partnership, such as its debts and environmental liabilities, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. In addition, Section 17-607 of the

Furthermore, under Delaware Revised Uniform Limited Partnership Act (the Delaware Act) provides that, under some circumstances, a limited partner may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

Under certain circumstances, unitholders may have liability to repay distributions wrongfully distributed to them.
Under Section 17-607 of the Delaware Act,law, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are nonrecourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

Delaware law provides that, for a period of three years from the date of an impermissible distribution, limited partners, including a unitholder, who received thesuch impermissible 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, our unitholders may be required to repay impermissible distributions upon the winding up of our partnership in the event that (a) we doour assets are not distribute assetsdistributed in the following order: (1) to creditors in satisfaction of our debts; (2) to partnersaccordance with Delaware law and former partners in satisfaction of liabilities for distributions owed under our partnership agreement; (3) to partners for the return of their contributions; and finally (4) to the partners in the proportions in which the partners share in distributions and (b) a limited partner knows at the time that the distribution violated the Delaware Act,law. If a limited partner knowingly received an impermissible distribution, then such limited partner willcould be liable to repay the distribution for a period of three years from the impermissible distribution under Section 17-804 of theapplicable Delaware Act.law.

A purchaser of 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.

Unitholders may be required to sell their units to our general partner at an undesirable time or price.
If at any time less than 20% of the outstanding units of any class are held by persons other than the general partner and its affiliates, the general partner will have the right to acquire all, but not less than all, of those units at a price no less than their then-current market price. As a consequence, a unitholder may be required to sell his common units at an undesirable time or price. The general partner may assign this purchase right to any of its affiliates or to us.



The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.
We currently list our common units on the NYSE under the symbol “NS” and our Preferred Unitspreferred units on the NYSE under the symbols “NSprA,” “NSprB” and “NSprC,” respectively. Although our general partner has maintained a majority of independent directors on its board and all members of its board’s audit committee, compensation committee and nominating/governance & conflicts committee are independent directors, because we are a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to have a compensation committee or a nominating committee consisting of independent directors. Additionally, any future issuance of additional common or Preferred Unitspreferred units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules that apply to a corporation. Accordingly, the NYSE does not mandate the same protections for our unitholders as are required for certain corporations that are subject to all of the NYSE corporate governance requirements. See “Director Independence” under Item 13

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Table of this annual report on Form 10-K for additional information regarding the independence of our general partner’s directors and the committees of our general partner’s board.Contents

TAX RISKS TO OUR UNITHOLDERSPROPERTIES


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

RATE REGULATION

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

Our ammonia pipeline is subject to regulation by the STB pursuant to the ICA applicable to such pipelines (which differs from the ICA applicable to interstate liquids pipelines). Under that regulation, the ammonia pipeline’s rates, classifications, rules and practices related to the interstate transportation of anhydrous ammonia must be reasonable and, in providing interstate transportation, the ammonia pipeline may not subject a person, place, port or type of traffic to unreasonable discrimination.Similar to the crude and refined products pipelines, the rates for transportation services on the ammonia pipeline are required to be in a tariff which is posted publicly on our website, however, that tariff is not required to be on file with the STB. The STB does not prescribe an indexing approach similar to the EP Act but rates under the STB must be reasonable and the pipeline may not subject a person, place, port or type of traffic to unreasonable discrimination.

In addition to federal regulatory body oversight, various states, including Colorado, Kansas, Louisiana, North Dakota and Texas, maintain commissions focused on the rates and practices of common carrier pipelines offering services within their borders. Although the applicable state statutes and regulations vary, they generally require that intrastate pipelines publish tariffs setting forth all rates, rules and regulations applying to intrastate service, and generally require that pipeline rates and practices be just, reasonable and nondiscriminatory.

Shippers may challenge tariff rates, rules and regulations on our pipelines. In most instances, state commissions have not initiated investigations of the rates or practices of pipelines in the absence of shipper complaints. There are no pending challenges or complaints regarding our tariffs or tariff rates.

ENVIRONMENTAL, HEALTH, SAFETY AND SECURITY REGULATION

Our operations are subject to extensive international, federal, state and local environmental laws and regulations, in the U.S. and in Mexico, including those relating to the discharge of materials into the environment, waste management, remediation, the characteristics and composition of fuels, climate change and greenhouse gases. In 2023, our capital expenditures attributable to compliance with environmental regulations were $5.5 million, and we currently project environmental regulatory compliance spending of approximately $12.5 million in 2024.

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
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Occupational Safety and Health Administration’s Process Safety Management regulations. These regulations apply to processes that involve certain chemicals at or above specified thresholds.

Fuel Standards and Renewable Energy
International, federal, state and local laws and regulations regulate the fuels we transport and store for our customers. Changes in these laws or regulations could affect our earnings, including by reducing our throughput volumes, or require capital expenditures and expenses to segregate and separately store fuels. In addition, several federal and state programs require, subsidize or encourage the purchase and use of competing fuels or energy, renewable energy, electric battery-powered motor vehicle engines and renewable fuels and blending additives, like ethanol, biodiesel and renewable diesel. These programs may over time offset projected increases or reduce the demand for refined products, particularly gasoline, in certain markets. However, the increased production and use of renewable fuels may also create opportunities for pipeline transportation and fuel blending. Other legislative changes in the future may similarly alter the expected demand and supply projections for refined products in ways that cannot be predicted.

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

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

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

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

Water
The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, the federal Spill Prevention, Control, and Countermeasure and Facility Response Plan Rules and analogous or more stringent international, state and local laws and regulations impose restrictions and strict controls regarding the discharge of pollutants into state waters or waters of the United States. The discharge of pollutants into waters is generally prohibited, except in accordance with a permit issued by applicable federal or state 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.

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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.

We take proactive steps to protect our company, systems and data from cyberattacks. See Item 1C. “Cybersecurity” for our cybersecurity considerations.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with U.S. generally accepted accounting principles (GAAP) 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 following summary provides further information on our accounting policies that involve critical accounting estimates due to judgments made by management and the sensitivity of these estimates to deviations of actual results from management’s assumptions. The critical accounting estimates should be read in conjunction with Note 2 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data,” which summarizes our significant accounting policies.
Impairment of Long-Lived Assets
We test long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount of 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.
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.
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We recognize an impairment of goodwill if the carrying value of a reporting unit that contains goodwill exceeds its estimated fair value. In order to estimate the fair value of the reporting unit, including goodwill, management must make certain estimates and assumptions that affect the total fair value of the reporting unit including, among other things, an assessment of market conditions, projected cash flows, discount rates and growth rates. Management’s estimates of projected cash flows related to the reporting unit include, but are not limited to, future earnings of the reporting unit, assumptions about the use or disposition of assets included in the reporting unit, estimated remaining lives of those assets, and future expenditures necessary to maintain the assets’ existing service potential.

We calculate the estimated fair value of each of our reporting units using a weighted average of values calculated using an income tax purposesapproach 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 for 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.

NEW ACCOUNTING PRONOUNCEMENTS

See Note 3 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of new accounting pronouncements.

AVAILABLE INFORMATION
Our internet website address is www.nustarenergy.com. Information contained on our website is not part of this report. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and any amendments thereto, filed with (or furnished to) the SEC are available on our website, free of charge, as soon as reasonably practicable after we file or we were otherwisefurnish 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.

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ITEM 1A.    RISK FACTORS

RISKS RELATED TO SUNOCO’S PROPOSED ACQUISITION OF NUSTAR
The Merger is subject to a number of conditions to the obligations of both NuStar and Sunoco to complete the Merger, including approval by NuStar’s common unitholders and regulatory clearance, which may impose unacceptable conditions or could delay completion of the Merger or result in termination of the Merger Agreement.
On January 22, 2024, NuStar entered into a definitive agreement (the Merger Agreement), whereby Sunoco will acquire NuStar in an all-equity transaction (the Merger). The respective obligations of each of NuStar and Sunoco to consummate the Merger are subject to the satisfaction at or prior to the closing of numerous conditions, including, among other things, approval by NuStar’s common unitholders, the absence of any law or order prohibiting the consummation of the Merger, and the expiration or termination of the waiting period (and any extension of such period) under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.Many of the conditions to the completion of the Merger are not within either NuStar’s or Sunoco’s control, and NuStar cannot predict when, or if, these conditions will be satisfied. Furthermore, the requirement for obtaining the required regulatory clearances could delay the completion of the Merger for a significant period of time or prevent it from occurring.Regulators may seek to enjoin the completion of the Merger, seek divestiture of substantial assets of the parties, or require the parties to license, or hold separate, assets or terminate existing relationships and contractual rights.

Failure to complete the Merger could negatively impact the price of our units and have a material adverse effect on our results of operations, cash flows and financial position.
If the Merger is not completed for any reason, including as a result of failure to obtain all requisite regulatory and unitholder approvals, our ongoing business may be materially and adversely affected and, without realizing any of the benefits of having completed the Merger, we would be subject to a number of risks, including the following:
•we may experience negative reactions from the financial markets, including negative unit price impacts;
•we may experience negative reactions from commercial and business partners; and
•we will still be required to pay certain significant costs relating to the Merger, such as legal, accounting, financial advisor, and printing fees.

In addition, if the Merger Agreement is terminated under certain circumstances specified therein, we may be required to pay Sunoco a termination fee of approximately $90.3 million.

If the Merger is not completed, the risks described above may materialize and they may have a material adverse effect on our results of operations, cash flows, financial position, and the price of our publicly-traded units.

The announcement and pendency of the Merger may adversely affect our business, financial results and operations.
Whether or not the Merger is completed, its announcement and pendency could cause disruptions to our business, including:
•uncertainties associated with the Merger may cause us to lose management personnel and other key employees, which could adversely affect our future business and operations following the Merger;
•our business relationships may be subject to disruption due to uncertainty associated with the Merger, which could have a material adverse effect on our results of operations, cash flows, and financial position;
•matters relating to the Merger (including integration planning) require substantial commitments of time and resources by our management, which may result in the distraction of our management from ongoing business operations and pursuing other opportunities that could be beneficial to us; and
•the Merger Agreement places certain restrictions on how we conduct our operations, which may delay or prevent us from undertaking business opportunities that, absent the Merger Agreement, we may have pursued.

Sunoco may fail to realize the anticipated benefits of the Merger and fail to successfully integrate the businesses and operations of the parties in the expected time frame.
The success of the Merger, and the value that our common unitholders who receive Sunoco common units following the Merger will realize, depends on, among other things, the successful combination of NuStar’s and Sunoco’s businesses in a manner that realizes anticipated synergies and benefits and meets or exceeds the forecasted stand-alone cost savings anticipated by the combined business. If the combined business is not able to successfully achieve these synergies, or the cost to achieve these synergies is greater than expected, then the anticipated benefits of the Merger may not be realized fully or at all or may take longer to realize than expected. If the transaction closes, it is possible that the integration process could result in the loss of key NuStar employees or key Sunoco employees, the loss of customers, providers, vendors, or business partners, the disruption of either or both parties’ ongoing businesses, inconsistencies in standards, controls, procedures, and policies, potential unknown liabilities and unforeseen expenses, delays, or regulatory conditions associated with and following completion of the Merger, or higher than expected integration costs and an overall post-completion integration process that takes longer than originally anticipated.
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In addition, at times the attention of certain members of our management team and resources may be focused on the completion of the Merger and planning the anticipated integration, and diverted from day-to-day business operations or other opportunities that may have been beneficial to NuStar, which may disrupt our ongoing business and the operations of the combined business.

We may be subject to litigation challenging the Merger, and an unfavorable judgment or ruling in any such lawsuits could prevent or delay the consummation of the Merger and/or result in substantial costs.
Lawsuits related to the Merger may be filed against us, Sunoco, and our respective affiliates, directors and officers. If dismissals are not obtained or a settlement is not reached, these lawsuits could prevent or delay completion of the Merger and/or result in substantial costs to us.

RISKS RELATED TO OUR BUSINESS
Changes in price levels could negatively impact our revenue, our expenses, or both, which could adversely affect our financial position, results of operations and cash flows.
The operation of our assets and the execution of capital projects require significant expenditures for labor, materials, property, equipment and services. As a result, such costs may increase during periods of high inflation, including as a result of rising commodity prices, supply chain disruptions and tight labor markets. Recent inflationary pressures affecting the general economy and the energy industry have increased our expenses and capital costs, and those costs may continue to increase. While we expect our pipeline systems to benefit from the positive revenue impact of our tariff indexation increases, we may not be able to pass all of these increased costs to our customers in the form of higher fees for our services, and, if so, our revenues and operating margins would be negatively impacted. Prior to adjustments to applicable rates, material cost increases may affect our operating margins, even if margins in subsequent periods may be normalized following applicable rate adjustments. Accordingly, increased costs during periods of high inflation that are not passed through to customers or offset by other factors may have a material adverse effect on our financial position, results of operations and cash flows.

We may not be able to generate sufficient cash from operations to enable us to pay quarterly distributions to our unitholders.
The amount of entity-level taxation, thencash 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;
•fluctuations in interest rates on our variable rate debt instruments and preferred units;
•adjustments in cash reserves made by our board of directors, in its discretion;
•availability of and access to equity capital and debt markets; and
•the sources of cash used to fund our acquisitions, if any.

Moreover, the total amount of cash that we have available for distribution to common unitholders wouldis further reduced by the required distributions with respect to our preferred units. The factors listed above, which may be substantially reduced.
The anticipated after-tax benefitfurther impacted by public health crises, international conflicts, actions of oil-producing nations and other factors beyond our control, may reduce our available cash to such an investment in our units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service (the IRS) on this matter.

Despite the factextent that we are unable to pay distributions at the current level or at all in a given quarter. Cash distributions to our unitholders depend primarily upon our cash flows, including cash flows from reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. In other words, we may be able to make cash distributions during periods in which we record net losses and may not be able to make cash distributions during periods in which we record net income.

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Extended periods of reduced demand for or supply of crude oil, refined products, renewable fuels and anhydrous ammonia 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, refined products, renewable fuels and anhydrous ammonia we transport in our pipelines and store in our terminals. Market prices for these products are subject to wide fluctuation in response to changes in global and regional supply and demand 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 crude oil, refined products, renewable fuels or anhydrous ammonia 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, high interest rates, 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;
•higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline;
•an increase in aggregate automotive engine fuel economy;
•new government and regulatory actions or court decisions requiring the phase out or reduced use of gasoline-fueled vehicles;
•the increased use of and public demand for use of alternative fuel sources or electric vehicles;
•an increase in the market price of crude oil that increases refined product prices, which may reduce demand for refined products and increase demand for alternative products; and
•adverse weather events resulting in decreased corn acres planted, which may reduce demand for anhydrous ammonia.

Similarly, any sustained decrease in the supply of crude oil, refined products, renewable fuels or anhydrous ammonia 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 the supply of and prices for crude oil and refined products;
•a lack of drilling services, equipment or skilled personnel available to producers to accommodate production needs;
•changes in laws, regulations, sanctions or taxation that directly or indirectly delay supply or production or increase the cost of production of refined products; and
•political unrest or hostilities, activist interference and the resulting governmental response thereto.

Failure to retain or replace current customers and renew existing contracts on comparable terms to maintain utilization of our pipeline and storage assets at current or more favorable rates could reduce our revenue and cash flows to levels that could 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 existing contracts or enter into new contracts on acceptable terms 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, renewable fuels or anhydrous ammonia 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 our customers and our ability to conduct our operations;
•competition for customers from companies with comparable assets and capabilities;
•scheduled turnarounds or unscheduled maintenance at refineries or production facilities of customers we serve;
•operational problems or catastrophic events affecting our assets or the 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;
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•a decision by our current customers to redirect products transported in our pipelines or stored in our terminals to markets not served by our pipelines or terminals, or to transport or store crude oil, refined products or anhydrous ammonia by means other than our pipelines or storage terminals; and
•a decision by our current customers to shut down, limit operations of or sell one or more of the refineries/production facilities we serve to a purchaser that elects not to use our pipelines or 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. In addition, there are fewer investors and lenders for master limited partnership debt and equity capital market issuances than there are for corporate issuances, and negative public sentiment toward the fossil fuel energy industry has led some investors and lenders to reduce or cease investing in and lending to fossil fuel energy companies. As a result, the cost of raising capital has increased, the availability of funds has diminished and certain lenders have, and others may, refuse to refinance existing debt on similar terms or at all and reduce, or in some cases cease to provide, funding to borrowers such as us.

In general, if we do not generate sufficient cash from operations to finance our expenditures and funding from external sources is not available when needed, or is available only on unfavorable terms, we may be unable to execute our growth strategy, complete future acquisitions or construction projects or take advantage of other business opportunities and may be required to reduce investments or capital expenditures or sell assets, which could have a material adverse effect on our revenues and results of operations, and we may not be able to satisfy our debt obligations or pay distributions to our unitholders.

Our future financial and operating flexibility may be adversely affected by our significant leverage, any future downgrades of our credit ratings, restrictions in our debt agreements and conditions in the financial markets beyond our control.
As of December 31, 2023, our consolidated debt was $3.4 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, an increase in interest rates on amounts borrowed under Delaware law,our Revolving Credit Agreement and an increase in certain fees under our Receivables Financing Agreement.

Certain affirmative and restrictive covenants in our debt agreements and other debt service obligations may adversely affect our future financial and operating flexibility. Our Revolving Credit Agreement contains customary restrictive covenants, such as limitations on indebtedness, liens, mergers, asset transfers and certain investing activities. For example, we must maintain a Consolidated Debt Coverage Ratio (as defined in the Revolving Credit Agreement) that does not exceed 5.00-to-1.00 and a minimum Consolidated Interest Coverage Ratio (as defined in the Revolving Credit 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 (as defined in our Revolving Credit Agreement) and could result in acceleration of our obligations under our Revolving Credit Agreement and potentially other agreements. Our Receivables Financing Agreement, senior notes and other debt obligations also contain various customary affirmative and negative covenants, default, indemnification and termination provisions, which 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 debt 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. For example, upon the occurrence of specified events under certain of our debt agreements, we would be prohibited from making 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.

Our ability to service our debt will depend on, among other things, our future financial and operating performance and our ability to access the capital markets, which will be treatedaffected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our indebtedness and we are unable to access the capital markets or otherwise refinance our indebtedness, we may be required to reduce our distributions, reduce or delay our business activities, investments or capital expenditures, sell assets or issue additional equity, which could materially and adversely affect the trading price of our units, as well as, our financial condition, results of operations, cash flows and ability to make distributions to unitholders.

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Changes in interest rates could adversely affect our business, access to credit and capital markets, and the trading price of our units.
We have significant exposure to increases in interest rates through variable rate provisions in certain of our debt instruments and our Series A, Series B and Series C Preferred Units. At December 31, 2023, we had approximately $3.4 billion of consolidated debt, of which $2.6 billion was at fixed interest rates and $0.8 billion was at variable interest rates. The distribution rates on our Series A, Series B and Series C Preferred Units have converted from fixed to floating rates. Our results of operations, cash flows and financial position could be materially adversely affected by significant changes in interest rates and uncertainty regarding the floating rates referenced in our variable rate debt instruments and preferred units could adversely affect the value of those financing arrangements. Please see “Quantitative and Qualitative Disclosures about Market Risk” for discussion of our market risk related to interest rates.

We plan to self-fund all of our expenses, distribution requirements and capital expenditures for 2024 using internally generated cash flows as we did for the full-years 2023, 2022 and 2021. An increase in interest rates may have a corporationnegative impact on our ability to access the capital markets, refinance existing debt or incur new debt at economically attractive rates, which could adversely affect our future growth by limiting our operational and financial flexibility.

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 federal income tax purposes unless weinvestment 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. A rising interest rate environment could have an adverse impact on our unit price and impair our ability to issue additional equity, incur new debt to fund growth, satisfy our existing debt obligations or pay distributions to our unitholders.

Our inability to develop, fund and execute growth projects and acquire new assets could limit our ability to maintain and grow quarterly distributions to our unitholders.
Our ability to maintain and grow our distributions to unitholders depends on the growth of our existing businesses and strategic acquisitions. Decisions regarding new growth projects rely on numerous estimates, including, among other factors, the ability to secure a “qualifying income” requirement. Based uponcommitment from a customer that sufficiently exceeds our current operations, we believe we satisfycost of capital to justify the qualifying income requirement. Failing to meetproject cost, predictions of future demand for our services, future supply shifts, crude oil or anhydrous ammonia production estimates, commodity price environments, economic conditions, both domestic and foreign, and potential changes in the qualifying income requirement or a change in current lawfinancial condition of our customers. Our predictions of such factors could cause us to be treated as a corporation for federal income tax purposesforego certain investments and to lose opportunities to competitors who make investments based on different predictions or otherwise subjecthave greater access to financial resources. In addition, volatile market conditions have caused us to taxation as an entity.

reevaluate the estimates underlying certain planned projects and delay the timing of certain projects until conditions improve. If we were treated asare unable to develop and execute expansion projects, implement business development opportunities, acquire new assets and finance such activities on economically acceptable terms, our future growth will be limited, which could have a corporation for federal income tax purposes, we would pay federal income taxsignificant adverse impact on our taxable income atresults of operations and cash flows and, accordingly, result in reduced distributions over time.

Failure to complete capital projects as planned may adversely affect our financial condition, results of operations and cash flows.
While we incur financing costs during the corporate tax rateplanning and would likely pay state and local income tax at varying rates. Distributions to unitholders who are treated as holders of corporate stock would generally be taxed again as corporate dividends (to the extentconstruction phases of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to unitholders. Becauseprojects, a tax would be imposed upon us as a corporation,project does not generate expected operating cash flows until it is at least substantially completed, if at all. Additionally, our distributable cash flow would be substantially reduced.

Moreover,forecasted operating results from capital spending projects are based on future market fundamentals that are not within our control, including changes in current state law may subject us to entity-level taxation by individual states. Becausegeneral economic conditions, the supply and demand of widespread state budget deficitscrude oil, refined products, renewable fuels and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes or an increase in the existing tax rates would substantially reduce the cash available for distributionanhydrous ammonia, availability to our unitholders. Therefore, if we were treated ascustomers of attractively priced alternative solutions for storage, transportation or supplies of crude oil, refined products, renewable fuels and anhydrous ammonia and overall customer demand. As a corporation for federal income tax purposesresult of these uncertainties, the anticipated benefits associated with our capital projects may not be achieved or otherwise subjected tocould be delayed. In turn, this could have a material amountnegative impact on our results of entity-level taxation, there would be a material reduction in the anticipatedoperations and cash flow and after-tax returnour ability to make cash distributions to our unitholders, likely causing a substantial reduction in the value of our units.unitholders.


The tax treatment of publicly traded partnerships or an investment in our units could be subjectAlthough we evaluate and monitor each capital spending project and try 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 unitsanticipate difficulties that may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Further, final Treasury regulations under Section 7704(d)(1)(E) of the Code published in the Federal Register interpret the scope of qualifying income requirements for publicly traded partnerships by providing industry-specific guidance. We do not believe the final Treasury regulationsarise, unforeseen circumstances may adversely affect our ability to be treatedcomplete such projects as planned, if at all. Delays or cost increases arise as a partnershipresult of many factors that are beyond our control, including:
•adverse economic conditions;
•market-related increases in a project’s debt or equity financing costs;
•severe adverse weather conditions, natural disasters (such as extreme temperatures, hurricanes, tornadoes, storms, floods and earthquakes) or other events (such as equipment malfunctions, explosions, fires, spills or public health events) affecting our facilities or employees;
•denial or delay in issuing requisite regulatory approvals and/or permits;
•delay or increased costs to obtain right-of-way or other property rights;
•protests and other activist interference with planned or in-process projects;
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•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.

Any of the above factors may also adversely affect the facilities, operations or employees of counterparties, vendors, suppliers, contractors, sub-contractors or other third parties involved with our projects, which could result in non-performance or delay by, or disputes with, such parties.

We compete with other midstream service providers, including certain major energy and chemical companies, that 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 adversely affect our revenues and cash flows, thereby reducing our ability to make our quarterly distributions to unitholders.
We face competition in all aspects of our business and can give no assurances that we will be able to compete effectively against our competitors. Our competitors include major energy and chemical companies, some of which have greater financial resources, more pipelines or storage terminals, greater capacity pipelines or storage terminals and greater access to supply than we do. Certain of our competitors also have advantages in competing for U.S.acquisitions or other new business opportunities because of their financial resources and synergies in operations. As a consequence of increased competition in the industry or market conditions, some customers are and others may be in the future reluctant to renew or enter into long-term contracts or contracts that provide for minimum throughput amounts. Our inability to renew or replace a significant portion of our current contracts as they expire, to enter into contracts for newly acquired, constructed or expanded assets and to respond appropriately to changing market conditions would have a negative effect on our revenue, cash flows and ability to make quarterly distributions to our unitholders.

Our operations are subject to operational hazards and interruptions, and we cannot insure against or predict all potential losses and liabilities that might result therefrom.
Our operations and those of our customers and suppliers are subject to operational hazards and unforeseen interruptions due to adverse weather conditions, natural disasters (such as heat waves, freezing temperatures, 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. 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. If 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.

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 or 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 may 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 cannot fully eliminate counterparty credit risks. Any substantial increase in the nonpayment or nonperformance by our customers, vendors or other counterparties, or our inability to enforce our 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.

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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, some of our employees and those of our service providers, vendors and customers may travel or work from home or other remote-work locations, where cybersecurity protections may be less robust and cybersecurity procedures and safeguards may be less effective. Moreover, certain attacker techniques and goals, such as surveillance, intelligence gathering or extended reconnaissance, may remain undetected for an extended period of time, which can increase the breadth and negative impact of an incident. A significant failure, compromise, breach or interruption in our systems or those of third parties critical to our operations could result in a disruption of our operations; physical damage to our assets or the environment; physical, financial, or other harm to employees or others; safety incidents; damage to our reputation; loss of customers or revenues; increased costs for remedial actions; and potential litigation or regulatory fines. Failures, interruptions and similar events that result in the loss or improper disclosure of information maintained in our systems and networks or those of our vendors, including personnel, customer and vendor information, have in the past and may in the future require reporting under relevant contractual obligations and laws and regulations protecting personal data and privacy and could also subject us to litigation or other liability under relevant contractual obligations, laws and regulations. Our financial results could also be adversely affected if our systems are breached or an employee, vendor or customer causes our systems to fail, either as a result of inadvertent error or deliberate tampering with or manipulation of our systems.

Due to the continued acceleration of cyberattacks, generally and against our industry, regulatory actions by federal, income tax purposes.state and local governmental agencies in the United States and in Mexico have increased. Evolving laws and regulations governing cybersecurity and data privacy and protection pose increasingly complex compliance challenges. Although we believe that we have robust cybersecurity procedures and other safeguards in place, we cannot guarantee their effectiveness, and a significant failure, compromise, breach or interruption in our systems or those of our customers or vendors could have a material effect on our operations and the operations of our customers and vendors. As threats continue to evolve and cybersecurity and data privacy and protection laws and regulations continue to develop, we have spent and expect to continue spending additional resources to continue to enhance our cybersecurity, data protection, business continuity and incident response measures, to investigate and remediate any vulnerabilities to, or consequences of, cyber incidents, as well as on regulatory compliance.


Disputes regarding a failure to maintain product quality specifications or other claims related to the operation of our assets and the services we provide to our customers may 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, 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.
Climate change laws or regulations enacted by the United States and other political bodies that increase costs, reduce demand or otherwise impede our operations, could, directly or indirectly, have an adverse effect on our business. Legislative and
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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. Specifically, certain regulatory changes have restricted, and future changes could restrict, our ability to expand our operations and have increased, and in the future could increase, our costs to operate and maintain our existing facilities by requiring that we measure and report our emissions, install new emission controls on our facilities, acquire allowances to authorize our emissions, pay taxes or fees related to our emissions or administer and manage an emissions program, among other things. The passage of climate change legislation and interpretation and action of federal and state regulatory bodies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to greenhouse gases, or restrictions on their use, may reduce volumes available to us for transportation and storage. These developments could have adverse effects on our business, financial position, results of operations and prospects.

In addition, certain of our blending operations subject us to potential requirements to purchase renewable fuels credits. Even though we attempt to mitigate such lost revenues or increased costs through the Tax Cutscontracts we sign with our customers, we sometimes are not able to recover those revenues or mitigate the increased costs, and Jobs Act enacted December 22, 2017, makesany such recovery depends on events beyond our control, including the outcome of future rate proceedings before the Federal Energy Regulatory Commission (FERC) or other regulators and the provisions of any final legislation or regulations. Reductions in our revenues or increases in our expenses as a result of climate change legislation or other regulatory initiatives could have adverse effects on our business, financial position, results of operations and prospects.

Finally, increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. Such events have had and may in the future have an adverse effect on our assets and operations, especially those located in coastal regions.

Public sentiment towards climate change, fossil fuels and sustainability could adversely affect our business, operations and ability to attract capital.
Our business plans are based upon the assumption that public sentiment and the regulatory environment will continue to enable the future development, transportation and use of carbon-based fuels. Negative public perception of the industry in which we operate and the influence of environmental activists and initiatives aimed at limiting climate change could interfere with our business activities, operations and access to capital. Activists concerned about the potential effects of climate change have directed their attention towards sources of funding for fossil fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital reducing or ceasing lending to or investing in companies in the fossil fuel energy industry, such as us. Having a more limited pool of lenders and investors has resulted in an increase in costs to raise capital, a decrease in the availability of new funding and a diminished ability to refinance existing debt at favorable rates for businesses such as ours, which could have a material adverse effect on our ability to meet our future capital needs, satisfy our debt obligations or pay distributions to our unitholders.

Members of the lending and investment communities 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 lending and investment communities screen companies such as ours for sustainability performance before lending to us or investing in our units. In response to the increasing pressure regarding sustainability disclosures and practices, we and other companies in our industry publish sustainability reports that are made available to lenders and investors. Such reports are used by some lenders and investors to inform their lending, 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 lender and investor sentiment toward us or our customers and to the diversion of capital to other industries, which would have a negative impact on our unit price and/or our access to and costs of capital. Such negative sentiment regarding our industry could influence consumer preference and decrease demand for the products we transport and store and may 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.

Our operations are subject to federal, state and local laws and regulations, in the U.S. and in Mexico, relating to environmental, health, safety and security that require us to make substantial expenditures.
Our operations are subject to increasingly stringent international, federal, state and local environmental, health, safety and security laws and regulations. Transporting, storing and distributing hazardous materials, including petroleum products, entails the risk of releasing these products into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies including for damages to natural resources, personal injury or property damages to private parties and significant business interruption. Further, our pipeline facilities are subject to the
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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, imposition of carbon taxes or methane fees, material changes in operations, increased capital expenditures and operating costs, increased costs of the U.S. federal income tax rules applicablegoods we transport and/or decreased demand for products we handle. Future impacts cannot be assessed with certainty at this time. Required expenditures to both individualsmodify operations or install pollution control equipment or release prevention and entities, including changes to the tax rate on a unitholder’s allocable share of income from the publicly traded partnership. The Tax Cutscontainment systems or other environmental, health, safety or security measures could materially and Jobs Act is complex and lacks administrative guidance. Thus, the impact of certain aspects of its provisions on us or an investment in our units is currently unclear. Unitholders should consult their tax advisor regarding the Tax Cuts and Jobs Act and its effect on us or an investment in our units.


Any changes to the federal income tax laws and interpretations thereof (including administrative guidance relating to the Tax Cuts and Jobs Act) may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for federal income tax purposes or otherwise adversely affect our business, financial condition, results of operations and liquidity if these expenditures, as with all costs, are not ultimately reflected in the tariffs and other fees we receive for our services.

We own or lease a number of properties that were used to transport, store or distribute products for many years before we acquired them; therefore, such properties were operated by third parties whose handling, disposal or release of products and wastes was not under our control. Environmental laws and regulations could impose obligations to conduct assessment or remediation efforts at our facilities, third-party sites where we take wastes for disposal, or where wastes have migrated. Environmental laws and regulations also may impose joint and several liability on us for the conduct of third parties or for actions that complied with applicable requirements when taken, regardless of negligence or fault. If we were to incur a significant liability pursuant to environmental, health, safety or security laws or regulations, such a liability could have a material adverse effect on our financial position.

We operate assets outside of the United States, which exposes us to different legal and regulatory requirements and additional risk.
A portion of our revenues are generated from our assets located in northern Mexico. Our operations are subject to various risks unique to Mexico that could have a material adverse effect on our business, results of operations and financial condition, including political and economic instability from civil unrest; labor strikes; war and other armed conflict; inflation; currency fluctuations, devaluation and conversion restrictions or other factors. Any deterioration of social, political, labor or economic conditions, including the increasing threat of terrorist organizations and drug cartels in Mexico, or affecting a customer with whom we do business, as well as difficulties in staffing, obtaining necessary equipment and supplies and managing foreign operations, may adversely affect our operations or financial results. We are also exposed to the risk of foreign and domestic governmental actions that may: impose additional costs on us; delay permits or otherwise impede our operations; limit or disrupt markets for our operations, restrict payments or limit the movement of funds; impose sanctions on or otherwise restrict our ability to conduct business with certain customers or persons or in certain countries; or result in the deprivation of contract rights. Our operations outside the United States may also be affected by changes in trade protection laws, policies and measures, and other regulatory requirements affecting trade and investment, including the Foreign Corrupt Practices Act and foreign laws prohibiting corrupt payments, as well as travel restrictions and import and export regulations.

We may be unable to obtain or renew permits necessary for our current or proposed operations, which could inhibit our ability to conduct or expand our business.
Our facilities operate under a number of federal, state and local permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. These limits and standards require a significant amount of monitoring, recordkeeping and reporting in order to demonstrate compliance with the underlying permit, license or approval. Noncompliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. In addition, public protest, political activism and responsive government intervention have made it more difficult for energy companies to acquire the permits required to complete planned infrastructure projects. A decision by a government agency to deny or delay issuing a new or renewed permit, license or approval, or to revoke or substantially modify an existing permit, license or approval, or to impose additional requirements on the renewal 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.

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Certain of our interstate common carrier pipelines are subject to regulation by the FERC and the Surface Transportation Board, 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.
Pursuant to the Interstate Commerce Act (ICA) and various other laws, the FERC regulates tariff rates and terms and conditions of service for interstate crude oil and refined products movements on common carrier pipelines. The FERC requires that these rates be just and reasonable and not unduly discriminatory 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 amounts refunded where such amounts were collected in excess of the deemed just and reasonable rate. In addition, shippers may challenge by complaint tariff rates and terms and conditions of service even after they take effect, and the FERC may order a carrier to change its rates prospectively to a just and reasonable level. A complaining shipper also may obtain reparations for damages sustained during the two years prior to the date of the complaint.

We are unableable to predict whether any additionaluse various FERC-authorized rate change methodologies for our interstate pipelines, including indexed rates, cost-of-service rates, market-based rates and negotiated rates. Typically, we adjust our rates annually in accordance with the FERC indexing methodology, which currently allows a pipeline to change its rates within prescribed ceiling levels that are tied to an inflation index. It is possible that the index may result in negative rate adjustments in some years, or that changes in the index might not be large enough to fully reflect actual increases in our costs. The FERC’s indexing methodology is subject to review and revision every five years, with the most recent five-year review occurring in 2020. On December 17, 2020, the FERC established the index level for the five-year period commencing July 1, 2021, which will end on June 30, 2026, at the Bureau of Labor’s producer price index for finished goods (PPI-FG) plus 0.78%. On January 20, 2022, the FERC granted rehearing of certain aspects of the final rule and revised the index level to PPI-FG minus 0.21%, effective March 1, 2022 through June 30, 2026. The 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, which could result in a further change to the index. The 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, competition constrains our rates in various markets, which may force us to reduce certain rates to remain competitive.

Pursuant to the ICC Termination Act of 1995 (ITA), the Surface Transportation Board (STB) regulates interstate pipelines carrying products other than gas, oil or water, including the anhydrous ammonia we transport. Unlike the ICA, which allows the FERC to investigate a carrier’s rates on its own initiative, ITA prescribes the STB may only investigate issues in response to complaints by shippers and other interested parties. Further, carriers are not required by the ITA or the STB to report rates charged to transport anhydrous ammonia or other proposals will ultimately be enacted. Anycommodities, and the STB does not routinely collect such information. Adverse changes in the FERC’s or STB’s rate change methodologies or challenges to our rates that result in significant damages could negatively impact the valueaffect our cash flows, results of an investment inoperations and our units.ability to make distributions to our unitholders.


A successful IRS contestWe do not own all of the federal income tax positionsland on which our pipelines and facilities are located, and we take mayare 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 impact the market foraffect our units,financial condition, results of operations and the costs of any contest will reduce cash flows available for distribution to our unitholders.

Increases in power prices could adversely affect 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, 2023, our power costs equaled approximately $48.2 million, or 13% of our operating expenses for the year. We use mainly electric power at our pipeline pump stations and terminals, and such electric power is furnished by various utility companies. Requirements for utilities to use less carbon intensive power or to add pollution control devices also could cause our power costs to increase and our cash flows may be adversely affected, which could adversely affect our ability to make distributions to our unitholders.

We may be adversely affected by changes in the method of determining the London Interbank Offering Rate (LIBOR) or the replacement of LIBOR with an alternative reference rate, such as the Secured Overnight Financing Rate (SOFR).
The IRS may adopt positionspublication of non-U.S. dollar LIBOR rates ceased after publication on December 31, 2021 and the publication of U.S. dollar LIBOR rates for the most common tenors (overnight and one, three, six and twelve months) is ceased after publication on June 30, 2023. In addition, in March 2022, the Adjustable Interest Rate (LIBOR) Act (the “LIBOR Act”) was signed into law. This law provides a statutory fallback mechanism to replace LIBOR with a benchmark rate that differ fromis selected by the positions we take, even positions takenFederal Reserve Board and based on SOFR for certain contracts that reference LIBOR without adequate fallback provisions providing for a clearly defined replacement benchmark. On December 16, 2022, the Federal Reserve Board adopted a final rule to
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implement the LIBOR Act and established benchmark rates based on SOFR to replace LIBOR contracts governed by U.S. law that reference certain tenors of U.S. dollar LIBOR after June 30, 2023. The regulations include provisions that (i) provide a mechanism for the automatic replacement of LIBOR with the advicebenchmark rate selected by the Federal Reserve Board; (ii) clarify who may contractually select a benchmark replacement for LIBOR; and (iii) ensure that contracts transitioning to the replacement benchmark rate selected by the Federal Reserve Board will not be interrupted or terminated following the replacement of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or allLIBOR. On June 30, 2023, the publication of the positions we take. A court may not agree with all of the positions we take. Any contestU.S. dollar LIBOR rates ceased and, beginning with the IRS may affect adverselydistribution period starting on September 15, 2023, the taxable income reporteddistribution rates on our Series A, Series B and Series C preferred units converted from a floating rate based on three-month LIBOR to our unitholders andthree-month CME Term SOFR plus the income taxes they are required to pay. As a result, any such contest with the IRS may materially and adversely impact the market for our units and the prices at which they trade. In addition, the costsapplicable tenor spread adjustment of any contest between us and the IRS will be borne indirectly by our unitholders and our general partner because such costs will reduce our cash available for distribution.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case we may elect to either pay the taxes directly to the IRS or to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes. If we bear such payment our cash available for distribution to our unitholders might be substantially reduced.
Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest)0.26161%, in accordance with their interests in us during the tax year under audit, there can be no assurance thatguidance and the applicable rules and regulations governing such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or alltransition. The consequences of the tax liability resultingtransition away from such audit adjustment, even if such unitholders did not own commonLIBOR and the use of SOFR cannot be entirely predicted but could include an increase in the cost of our variable-rate indebtedness, our Series A, Series B and Series C preferred units inand other commercial arrangements tied to LIBOR.

An impairment of goodwill or long-lived assets could reduce our earnings.
As of December 31, 2023, we had $0.7 billion of goodwill and $3.8 billion of long-lived assets, including property, plant and equipment, net and intangible assets, net. GAAP requires us during the tax year under audit. If, as a result of any such audit adjustment, we make payments of taxes, penaltiesto test both goodwill and interest, our cash availablelong-lived assets for distribution to our unitholdersimpairment when events or circumstances occur indicating that either goodwill or long-lived assets might be substantially reduced.

Even if unitholders do not receive any cash distributions from us, they will be required to pay taxes on their respective share of our taxable income.
Unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their respective share of our taxable income, whether or not the unitholders receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their respective share of our taxable income or even equal to the actual tax liability that results from their respective share of our taxable income.

Tax gain or loss on the disposition of our units could be different than expected.
If a unitholder sells units, the selling unitholder will recognize a gain or loss equal to the difference between the amount realized and the unitholder’s tax basis in those units. Prior distributions to the selling unitholder in excess of the total net taxable income the unitholder was allocated for a unit, which decreased the unitholder’s tax basis in that unit, will, in effect, become taxable income to the selling unitholder if the unit is sold at a price greater than the unitholder’s tax basis in that unit, even if the price the unitholder receives is less than the unit’s original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to the selling unitholder.

Unitholders may be subject to limitations on their ability to deduct interest expense incurred by us.
In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, a deduction for “business interest” is limited to the sum of our business interest income plus 30% of our “adjusted taxable income.” This limitation is applied at the entity level for partnerships. For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income,impaired and, in the case of taxable years beginning before January 1, 2022, any deduction allowablegoodwill, at least annually. Any event that causes a reduction in demand for depreciation, amortization, or depletion. Any interest disallowed at the partnership level may be carried forward and deductedour services could result in future years by a unitholder from his sharereduction of our “excess taxable income,”estimates of future cash flows and growth rates in our business, which is generally equalcould cause us to record an impairment charge to reduce the excessvalue of 30%goodwill. Similarly, any event or change in circumstances that causes the carrying value of our adjusted taxable income over the amount of our deduction for business interest for such future taxable year, subjectlong-lived assets to certain restrictions.


Tax-exempt entities face unique tax issues from owning our units thatno longer be recoverable may result in adverse tax consequences to them.
Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Further, with respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trades or businesses) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment inrequire us to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our units.
Non-U.S. unitholders will be subjectrecord an impairment charge to U.S. taxes and withholding with respect to their income and gain from owning our units.
Non-U.S. unitholders are subject to U.S. federal income tax on income effectively connected with a U.S. trade or business (“effectively connected income”). A unitholder’s share of our income, gain, loss and deduction, and any gain from the sale or disposition of our units will generally be considered to be “effectively connected” with a U.S. trade or business and subject to U.S. federal income tax. Additionally, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate.

The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a non-U.S. unitholder’s sale or disposition of units. The IRS has temporarily suspended the application of the withholding requirements on sales of publicly traded interests, including our units, pending promulgation of regulations or other guidance. It is not clear if or when such regulations or other guidances will be issued. Non-U.S. unitholders should consult a tax advisor before investing in our units.

We will treat each purchaser of our common units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affectreduce the value of our common units.long-lived assets. If we determine that either our goodwill or our long-lived assets are impaired, the resulting charge will reduce earnings and partners’ capital.
Because
RISKS INHERENT IN AN INVESTMENT IN US
As a master limited partnership, we cannot match transferorsdo not have the same flexibility that corporations and transferees ofother business organizations may have to accumulate cash and prevent illiquidity in the future, which may 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. To the extent we issue additional units, the payment of distributions on those additional units may increase the risk that we will adopt depreciationbe unable to maintain our current per unit distribution level and amortization positions that may not conform with all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of our common units or resultand other limited partner interests may decrease in audit adjustmentscorrelation with any reduction in our cash distributions per unit. Accordingly, if we experience a liquidity shortage in the future, we may not be able to the unitholder’s tax returns.issue additional equity to recapitalize.


Unitholders will likely be subject to statehave limited voting rights, and local taxes and return filing requirements as a resultour partnership agreement restricts the voting rights of investing incertain unitholders owning 20% or more of any class of our units.
In additionUnlike holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to federal income taxes, unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritanceinfluence management’s decisions regarding our business. Our unitholders’ voting rights are further restricted by a provision in our partnership agreement providing that units held by certain persons that own 20% or intangible taxesmore of any class of units then outstanding cannot vote on any matter without the prior approval of our general partner.

We may issue additional equity securities, including equity securities that are imposed bysenior 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 various jurisdictionsapproval of other unitholders as long as the newly issued equity securities are not senior to, or equally ranked with, our 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 whichcertain circumstances, we do business or own property. Unitholders will likelymay be required to file state and localobtain 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 tax returns and pay state and local income taxes in some or allto distributions may increase;
•the relative voting strength of these various jurisdictions. Further, unitholderseach previously outstanding unit 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 diminished; and
•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 transfereesmarket price of our common units each month basedand preferred units may decline.
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In addition, our partnership agreement requires that unitholders 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 unitsin the event of a transaction, including a merger, sale, lease or conveyance of all or substantially all of our assets or business, which might adversely affect the holders of our preferred units.

Future issuances and sales of securities that rank equally with our preferred units, or the perception that such issuances and sales could occur, may cause prevailing market prices for our preferred units and our common units to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us. Furthermore, the payment of distributions on any additional units may increase the risk that we will not be able to make distributions at our prior per unit distribution levels. To the extent new units are senior to our common units, their issuance will increase the uncertainty of the payment of distributions on our common units.

If we do not pay distributions on our preferred units in any distribution period, we would be unable to declare or pay distributions on our common units until all unpaid preferred unit distribution obligations have been paid, and our common unitholders are not entitled to receive distributions for such prior period.
Our preferred units rank senior to our common units with respect to distribution rights and rights upon liquidation. If we do not pay the required distributions on our preferred units, we will be unable to declare or pay distributions on our common units. Distributions to our preferred unitholders are cumulative, so we must pay all unpaid accumulated preferred distributions before we can declare or pay any distributions to our common unitholders. Distributions to our common unitholders are not cumulative, therefore, 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 that would have accumulated in that quarter. The preferences and privileges granted to holders of our preferred units could adversely affect the market price for our common units and 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.
Our partnership agreement is governed by the laws of the State of Delaware. If a Delaware court were to determine that actions of a unitholder constituted participation in the “control” of our business, that unitholder would be held liable for our obligations to the same extent as a general partner. Under Delaware law, a 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, including a unitholder, who received such impermissible 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, our unitholders may be required to repay impermissible distributions upon the ownershipwinding up of our partnership in the event that our assets are not distributed in accordance with Delaware law and a limited partner knows at the time that the distribution violated Delaware law. If a limited partner knowingly received an impermissible distribution, then such limited partner could be liable to repay the distribution for a period of three years from the impermissible distribution under applicable Delaware law.

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 first day of each month, instead of onNYSE under 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, losssymbol “NS” 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 commonpreferred units on the first dayNYSE under the symbols “NSprA,” “NSprB” and “NSprC,” respectively. Although our general partner has maintained a majority of each month, insteadindependent directors on its board and all members of on the basis of the date a particular common unit is transferred. The U.S. Treasury Departmentits board’s audit committee, compensation committee and the IRS issued final regulations pursuant to whichnominating/governance & conflicts committee are independent directors, because we are a publicly traded limited partnership, may use a similar monthly simplifying conventionthe NYSE does not require us to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis and the regulations do not specifically authorize all aspects of the proration method we have currently adopted. If the IRS were to challenge our proration method, 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 impactmajority of independent directors on the valueour general partner’s board of thedirectors 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 result in audit adjustmentsother securities, including 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” to cover a short sale of units) may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units mayaffiliates, will 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 may not be 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. Although a holder of Preferred Units could recognize taxable income from the accrual of such a guaranteed payment even in the absence of a contemporaneous distribution, we anticipate accruing and making the guaranteed payment distributions quarterly. Otherwise, the holders of Preferred Units are 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.

The Tax Cuts and Jobs Act allows individuals and other non-corporate owners of interests in a publicly traded partnership to take a deduction equal to 20% of their allocable share of “qualified publicly traded partnership income.” Although we expect that much of the income we earn is generally eligible for the 20% deduction for qualified publicly traded partnership income, it is uncertain whether a guaranteed payment for the use of capital may constitute an allocable or distributive share of such income. As a result, the guaranteed payment for use of capital received by the holders of our Preferred Units may not be eligible for the 20% deduction for qualified publicly traded partnership income.

A holder of Preferred Units will be required to recognize gain or loss on a sale of Preferred Units equal to the difference between the amount realized by such holder and tax basis in the Preferred Units sold. The amount realized generally will equal the sum of the cash and the fair market value of other property such holder receives in exchange for such Preferred Units. Subject to general rules requiring a blended basis among multiple partnership interests, the tax basis of a Preferred Unit will generally be equal to the sum of the cash and the fair market value of other property paid by the holder of Preferred Units to acquire such Preferred Unit. Gain or loss recognized by a holder of Preferred Units on the sale or exchange of a Preferred Unit held for more than one year generally will be taxable as long-term capital gain or loss. Because holders of Preferred Units will generally not be allocated a share of our items of depreciation, depletion or amortization, it is not anticipated that such holders would be required to recharacterize any portion of their gain as ordinary income as a result of the recapture rules.

Investment in the Preferred Units by tax-exempt investors, such as employee benefit plans and IRAs, and non-U.S. persons raises issues unique to them. A non-U.S. holder’s income from guaranteed payments and any gain from the sale or disposition

of our units will generally be considered to be effectively connected income and subject to U.S. federal income tax. Distributions to non-U.S. holders of Preferred Units will be subject to withholding taxes. If the amount of withholding exceedsNYSE’s shareholder approval rules that apply to a corporation. Accordingly, the amount of U.S. federal income tax actually due, non-U.S. holders of Preferred Units may beNYSE does not mandate the same protections for our unitholders as are required for certain corporations that are subject to file U.S. federal income tax returns in order to seek a refund of such excess. The Tax Cuts and Jobs Act imposes a withholding obligation of 10%all of the amount realized upon a non-U.S. unitholder’s sale or dispositionNYSE corporate governance requirements.

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Table of Preferred Units. The IRS has temporarily suspended the application of the withholding requirements on sales of publicly traded interests, including our Preferred Units, pending promulgation of regulations or other guidance. It is not clear if or when such regulations or other guidance will be issued. Additionally, the treatment of guaranteed payments for the use of capital to tax exempt investors is not certain and such payments may be treated as unrelated business taxable income for federal income tax purposes.Contents

All holders of our Preferred Units are urged to consult a tax advisor with respect to the consequences of owning our Preferred Units.

PROPERTIESResults of Operations

The following table presents operating highlights for the pipeline segment:
 Year Ended December 31, 
 20232022Change
(Thousands of Dollars, Except Barrel Data)
Pipeline Segment:
Crude oil pipelines throughput (barrels/day)1,234,051 1,319,360 (85,309)
Refined products and ammonia pipelines throughput (barrels/day)602,913 579,240 23,673 
Total throughput (barrels/day)1,836,964 1,898,600 (61,636)
Throughput and other revenues$873,869 $828,191 $45,678 
Operating expenses214,751 210,719 4,032 
Depreciation and amortization expense175,930 178,802 (2,872)
Segment operating income$483,188 $438,670 $44,518 

Tariff indexations effective July 2022 and July 2023 increased the average tariff rates on most of our pipeline systems and resulted in higher revenues for the year ended December 31, 2023, compared to the year ended December 31, 2022.
Pipeline segment revenues increased $45.7 million, and throughputs decreased 61,636 barrels per day for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to:
•an increase in revenues of $31.1 million and an increase in throughputs of 43,563 barrels per day on our McKee System pipelines, primarily due to operational issues and a planned turnaround at a customer’s refinery in 2022, as well as higher demand on our pipeline serving the Denver, Colorado market in 2023; additionally, higher average tariff rates contributed to $9.7 million of the overall increase;
•an increase in revenues of $12.1 million, despite a decrease in throughputs of 3,601 barrels per day on our East and North pipelines combined; revenues increased primarily due to higher average tariff rates, while throughputs decreased primarily due to unfavorable market conditions and planned turnarounds at customers’ refineries in 2023;
•an increase in revenues of $7.2 million and an increase in throughputs of 1,550 barrels per day on our Valley Pipeline, primarily due to higher average tariff rates;
•an increase in revenues of $5.9 million and an increase in throughputs of 5,159 barrels per day on our Three Rivers System, partially due to higher demand on certain of our pipelines within this system and pipeline expansions that were placed in service in July 2022. Also, higher average tariff rates contributed to $4.0 million of the overall increase;
•an increase in revenues of $3.4 million, despite slightly lower throughputs of 1,028 barrels per day on our Ammonia Pipeline; revenues increased primarily due to higher average tariff rates;
•a decrease in revenues of $2.2 million and a decrease in throughputs of 27,367 barrels per day on our Permian Crude System, primarily due to decreased customer production supplying this system. Revenues also decreased $7.9 million due to lower commodity prices on PLA volumes and other products sold; these decreases were partially offset by higher average tariff rates in 2023;
•a decrease in revenues of $2.4 million and a decrease in throughputs of 10,781 barrels per day on our Ardmore System due to a turnaround at a customer’s refinery in the second quarter of 2023 and lower demand in 2023; and
•a decrease in revenues of $10.9 million and a decrease in throughputs of 68,374 barrels per day on our Corpus Christi Crude Pipeline System, primarily due to unfavorable market conditions and changes to a customer contract.

Operating expenses increased $4.0 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to an increase of $2.8 million in maintenance and regulatory expenses across various pipelines.

Depreciation and amortization expense decreased $2.9 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to fully amortized definite-lived intangible assets.


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STORAGE SEGMENT
Our principal propertiesstorage segment is composed of our facilities that provide storage, handling and other services on a fee basis for refined products, crude oil, specialty chemicals, renewable fuels and other liquids. As of December 31, 2023, we owned and operated 29 terminal and storage facilities in the United States and one terminal in Nuevo Laredo, Mexico, with an aggregate storage capacity of 36.4 million barrels. The following table sets forth information about our terminal and storage facilities as of December 31, 2023:
FacilityTank Capacity
(Barrels)
Colorado Springs, CO327,000 
Denver, CO110,000 
Albuquerque, NM250,000 
Rosario, NM167,000 
Catoosa, OK359,000 
Abernathy, TX161,000 
Amarillo, TX269,000 
Corpus Christi, TX410,000 
Corpus Christi, TX (North Beach)3,962,000 
Edinburg, TX345,000 
El Paso, TX(a)
415,000 
Harlingen, TX286,000 
Laredo, TX218,000 
San Antonio, TX(b)
379,000 
Southlake, TX569,000 
Nuevo Laredo, Mexico268,000 
Central West Terminals8,495,000 
St. James, LA9,906,000 
Houston, TX87,000 
Gulf Coast Terminals9,993,000 
Los Angeles, CA615,000 
Pittsburg, CA398,000 
Selby, CA2,672,000 
Stockton, CA818,000 
Portland, OR1,348,000 
Tacoma, WA391,000 
Vancouver, WA(b)
775,000 
West Coast Terminals7,017,000 
Benicia, CA3,698,000 
Corpus Christi, TX4,030,000 
Texas City, TX3,141,000 
Refinery Storage Tanks10,869,000 
Total36,374,000 
(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 Terminal and Storage Facilities
Central West Terminals. Our Central West Terminals include terminals located in Texas, Oklahoma, New Mexico and Colorado, as well as one terminal located in Nuevo Laredo, Mexico, with an aggregate storage capacity of 8.5 million barrels. Most of these terminals are described aboveconnected to our Central West Refined Product Pipelines. Our Corpus Christi North Beach terminal, located at the Port of Corpus Christi in Texas, has 4.0 million barrels of crude oil storage and supports our Corpus Christi Crude Pipeline System that transports crude oil from the Eagle Ford and Permian Basin regions to Corpus Christi for export or refineries owned by third parties. This facility also provides our customers with the flexibility to segregate and deliver crude oil and processed condensate and has access to four docks, including two private docks. We can accommodate Suezmax-class vessels and load crude oil onto marine vessels simultaneously on all four docks.

We refer to our pipelines that transport crude oil from the Eagle Ford and Permian Basin regions to Corpus Christi, together with our Corpus Christi North Beach terminal, as the Corpus Christi Crude System.

Gulf Coast Terminals. Our Gulf Coast Terminals have an aggregate storage capacity of 10.0 million barrels and include our St. James terminal, which is located on the Mississippi River near St. James, Louisiana, and one terminal located in Houston, Texas. Our St. James terminal has a total storage capacity of 9.9 million barrels and is located on almost 900 acres of land, some of which is undeveloped. The majority of the storage tanks and infrastructure are suited for light to medium crude oil, with certain tanks capable of fuel oil or heated crude oil storage. Additionally, the facility has one barge dock and two ship docks, and can accommodate exports up to Aframax-class vessels. Our St. James terminal is connected to (i) offshore pipelines in the Gulf of Mexico, (ii) long-haul pipelines that can receive crude oil from the Eagle Ford, Permian Basin, other domestic shale plays and Canada, and (iii) pipelines connecting to refineries in the Gulf Coast. The St. James terminal also has two unit train rail facilities that are served by the Union Pacific Railroad. Each facility has the capacity to simultaneously off-load 120 railcars, at a minimum, in a 24-hour period.

West Coast Terminals. Our West Coast Terminals include terminals located in California, Oregon and Washington, with an aggregate storage capacity of 7.0 million barrels. The largest of these terminals is our Selby, California terminal, with a total storage capacity of 2.7 million barrels. We have completed several renewable fuel storage projects at our West Coast Terminals over the last several years, and are able to receive and distribute renewable fuels across the West Coast, including renewable diesel, sustainable aviation fuel, ethanol, biodiesel and renewable feedstock. Our West Coast Terminals are connected to supply from various domestic and foreign sources.

Refinery Storage Tanks. We own crude oil storage tanks with an aggregate storage capacity of 10.9 million barrels that are physically integrated with and serve refineries owned by Valero Energy at Corpus Christi and Texas City, Texas and Benicia, California. We lease our refinery storage tanks to Valero Energy in exchange for a fixed fee.

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

Demand for Storage Services
The operations of our refined product terminals depend in large part on the caption “Segments,level of demand for products stored in our terminals in the markets served by those assets. Demand for our terminalling services will generally increase or decrease with demand for refined products, and demand for refined products tends to increase or decrease with the relative strength of the economy. In addition, the forward pricing curve can have an impact on demand. For example, crude oil traders focus less on the current market commodity price than on whether that price is higher or lower than expected future market prices: if the future price for a product is believed to be higher than the current market price, or a “contango market,” traders are more likely to purchase and that informationstore products to sell in the future at the higher price. On the other hand, when the current price of crude oil nears or exceeds the expected future market price, or “backwardation,” traders are no longer incentivized to purchase and store product for future sale. Our storage terminal revenues are somewhat insulated from demand volatility due to contracted rates for storage and minimum volume commitments.

Crude oil delivered to our St. James and Corpus Christi North Beach terminals will generally increase or decrease with crude oil production rates in western Canada and the Bakken, Permian and Eagle Ford shale plays. In addition, the market price relationship between various grades of crude oil impacts the demand for our unit train facilities at our St. James terminal. Although the Permian and Eagle Ford shale plays are partially insulated from negative economic conditions due to the low break-even point, our Corpus Christi exports have not returned to pre-pandemic levels due to lower global demand for refined products and crude oil and increased competition in crude oil export markets out of the U.S. Overall, refinery production rates,
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drilling activity and overall consumer demand in the U.S. rebounded in 2021, bringing demand for most of our terminal and storage facilities back to pre-pandemic levels. However, the detrimental impact of the pandemic, amplified by the Russia-Ukraine conflict, has continued to affect current global demand, resulting in a decline in crude oil exports from our Corpus Christi North Beach facility, and the current volatile and backwardated market has led to customers not renewing expiring contracts, primarily at our St. James terminal.

Demand for renewable diesel, renewable jet fuel, ethanol and other renewable fuels continues to grow in markets served by our West Coast terminals due to new regulations with aggressive carbon emissions reduction goals. As this demand growth is incorporated herein by reference. We believe thatexpected to continue, we have satisfactory titlecompleted, and continue to develop, renewable fuel storage projects at our West Coast terminals to meet this demand.
Customers
We provide storage and terminalling services for crude oil, refined products and other products to many of the world’s largest producers of crude oil, integrated oil companies, chemical companies, oil traders and refiners. In addition, our blending capabilities in our storage assets have attracted customers who have leased capacity primarily for blending purposes. The largest customer of our storage segment accounted for approximately 39% of the total revenues of the segment for the year ended December 31, 2023. No other customer accounted for 10% or more of the total revenues of the storage segment.

Competition and Other Business Considerations
Many major energy and chemical companies own extensive terminal storage facilities. Although such terminals often have the same capabilities as terminals owned by independent operators, they generally do not provide terminalling services to third parties. In many instances, even major energy and chemical companies that have storage and terminalling facilities are also significant customers of independent terminal operators, especially terminals located in cost-effective locations near key transportation links, such as deep-water ports. Major energy and chemical companies also need independent terminal storage when their proprietary storage facilities are inadequate, due to size constraints, the nature of the stored material or specialized handling requirements.

Independent terminal owners generally compete on the basis of the location and versatility of terminals, service and price. A favorably located terminal will have access to various cost-effective transportation modes both to and from the terminal. Transportation modes typically include waterways, railroads, roadways and pipelines.

Terminal versatility is a function of the operator’s ability to offer complex handling requirements for diverse products. The services typically provided by the terminal include, among other things, the safe storage of the product at specified temperature, moisture and other conditions, as well as receipt at and delivery from the terminal, all of our properties. Although titlewhich must comply with applicable environmental regulations. A terminal operator’s ability to these propertiesobtain attractive pricing is subjectoften dependent on the quality, versatility and reputation of the facilities owned by the operator. Operators with versatile storage capabilities typically require less modification prior to encumbrancesusage, ultimately making the storage cost to the customer more attractive. On the West Coast, regulatory priorities continue to increase demand for renewable fuels in some cases, such as customary interests generally retained in connection with the acquisition of real property, liens for current taxes and other burdens and easements, and restrictions or other encumbrances, including those related to environmental liabilities associated with historical operations, to which the underlying properties were subjectregion, while at the same time, of acquisitionobtaining permits for greenfield projects remains difficult, which both add more value to our existing assets.

Our crude oil refinery storage tanks are physically integrated with and serve refineries owned by us or our predecessors,Valero Energy, and we believe that nonehave entered into various agreements with Valero Energy governing the use of these burdens will materially detract from the value of these properties or from our interest in these properties or will materially interfere with their use in the operation of our business. In addition,tanks. As a result, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private partieswill not face significant competition for usour services provided to operate our business in all material respects as described in this report. We perform scheduled maintenance on allthose refineries.

Results of our pipelines, terminals, crude oil tanks andOperations
Point Tupper Terminal Disposition. In the first quarter of 2022, we recognized a non-cash pre-tax impairment loss of $46.1 million related equipment and make repairs and replacements when necessary or appropriate. We believe that our pipelines, terminals, crude oil tanks and related equipment have been constructed and are maintained in all material respects in accordance with applicable federal, state and local laws and the regulations and standards prescribed by the American Petroleum Institute, the DOT and accepted industry practice.

ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

ITEM 3.    LEGAL PROCEEDINGS

We are named as a defendant in litigation and are a party to other claims and legal proceedings relating to our 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 effectPoint Tupper terminal facility, which was sold 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 as a result of our ordinary business activity.

ITEM 4.    MINE SAFETY DISCLOSURES
Not applicable.

PART II

ITEM 5.MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Common Unit Distributions
Our common units are listed and traded on the New York Stock Exchange under the symbol “NS.” At the close of business on February 8, 2018, we had 464 holders of record of our common units. The following table presents the high and low sales prices for our common units during the periods presented (composite transactions as reported by the New York Stock Exchange) and the amount, record date and payment date of the quarterly cash distributions on our common units with respect to such periods:
 Price Range per Common Unit Cash Distributions
 High Low 
Amount Per
Common Unit
 Record Date Payment Date
Year 2017         
4th Quarter (a)$41.00
 $26.21
 $1.095
 February 8, 2018 February 13, 2018
3rd Quarter$47.99
 $37.30
 $1.095
 November 9, 2017 November 14, 2017
2nd Quarter$52.68
 $42.40
 $1.095
 August 7, 2017 August 11, 2017
1st Quarter$55.64
 $49.09
 $1.095
 May 8, 2017 May 12, 2017
Year 2016         
4th Quarter$50.87
 $43.41
 $1.095
 February 8, 2017 February 13, 2017
3rd Quarter$50.72
 $43.91
 $1.095
 November 8, 2016 November 14, 2016
2nd Quarter$53.47
 $37.90
 $1.095
 August 9, 2016 August 12, 2016
1st Quarter$42.87
 $25.65
 $1.095
 May 9, 2016 May 13, 2016
(a)The distribution was announced on January 29, 2018.

Our partnership agreement requires that we distribute all “Available Cash” to our common limited partners and general partner each quarter, and this term 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.April 29, 2022 (the Point Tupper Terminal Disposition). See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for further information regarding our distributions.

On February 7, 2018, NuStar Energy, Riverwalk Logistics, L.P., NuStar GP, LLC, Merger Sub, Riverwalk Holdings, LLC and NuStar GP Holdings entered into the Merger Agreement pursuant to which Merger Sub will merge with and into NuStar GP Holdings with NuStar GP Holdings being the surviving entity, such that NuStar Energy will be the sole member of NuStar GP Holdings following the Merger. Additionally, on February 8, 2018, we announced that our management anticipates recommending to the board of directors of NuStar GP, LLC, and the board of directors expects to adopt, a reset of our quarterly distribution per common unit to $0.60 ($2.40 on an annualized basis), starting with the first-quarter distribution payable in May 2018. Please refer to Note 284 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the Merger.

General Partner Distributions
Our general partner is entitled to distributions as shown below:this disposition.
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  Percentage of Distribution
Quarterly Distribution Amount per Common Unit 
Common
Unitholders
 
General 
Partner Including Incentive Distributions
Up to $0.60 98% 2%
Above $0.60 up to $0.66 90% 10%
Above $0.66 75% 25%
The following table presents operating highlights for the storage segment:

 Year Ended December 31, 
 20232022Change
(Thousands of Dollars, Except Barrel Data)
Storage Segment:
Throughput (barrels/day)448,331 480,129 (31,798)
Throughput terminal revenues$104,495 $110,591 $(6,096)
Storage terminal revenues215,104 223,958 (8,854)
Total revenues319,599 334,549 (14,950)
Operating expenses156,938 154,270 2,668 
Depreciation and amortization expense75,052 73,076 1,976 
Impairment loss— 46,122 (46,122)
Segment operating income$87,609 $61,081 $26,528 
Our general partner’s incentive distributions totaled $45.7
Throughput terminal revenues decreased $6.1 million, and $43.4throughputs decreased 31,798 barrels per day for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to a decrease in revenues of $13.2 million and a decrease in throughputs of 51,361 barrels per day at our Corpus Christi North Beach terminal, due to unfavorable market conditions and changes to a customer contract. These decreases were partially offset by an increase in revenues of $7.1 million and an increase in throughputs of 19,563 barrels per day at our Central West Terminals, primarily due to higher demand.

Storage terminal revenues decreased $8.9 million for the yearsyear ended December 31, 2017 and 2016, respectively. The general partner’s share of our distributions for2023, compared to the yearsyear ended December 31, 20172022, primarily due to:
•a decrease in revenues of $29.7 million at our St. James terminal due to customers not renewing expiring contracts in the current backwardated market; and2016 was 11.9% and 13.0%, respectively,
•a decrease in revenues of $9.6 million due to the impactPoint Tupper Terminal Disposition in April 2022.

These decreases were partially offset by the following:
•an increase in revenues of $26.4 million at our West Coast Terminals, primarily due to new contracts and rate escalations across various terminals, combined with higher throughput and handling fees, mainly at our Stockton terminal; and
•an increase in revenues of $4.3 million, primarily due to rate escalations at our Central West Terminals and at our refinery storage tanks.

Operating expenses increased $2.7 million for the incentive distributions. Inyear ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to the following:
•an increase in maintenance and regulatory expenses of $3.1 million, across various terminals;
•an increase of $2.8 million in ad valorem taxes due to higher property valuations;
•increases in reimbursable and other expenses of $2.5 million that have corresponding increases in revenue, primarily at our West Coast Terminals, partially offset by lower reimbursable expenses at our St. James terminal; and
•an increase of $1.8 million at our Corpus Christi North Beach terminal due to changes in a customer contract.

These increases were partially offset by a decrease in operating expenses of $7.9 million due to the sale of our Point Tupper Terminal Operations during the second quarter of 2017,2022.

Depreciation and amortization expense increased $2.0 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to expansion projects at our West Coast Terminals.

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FUELS MARKETING SEGMENT
Our fuels marketing segment sells petroleum products primarily through our bunkering operations in the Gulf Coast and certain of our blending operations associated with our Central East System. The results of operations for the fuels marketing segment depend largely on the margin between our costs and the sales prices of the products we market. Therefore, the results of operations for this segment are more sensitive to changes in commodity prices compared to the operations of the pipeline and storage segments. We enter into derivative contracts to attempt to mitigate the effects of commodity price fluctuations. The financial impacts of the derivative financial instruments associated with commodity price risk were not material for any periods presented. Fluctuations in global demand for crude oil, which was caused by many economic factors outside of our control, has caused volatility in commodity prices and volumes for our blending operations and bunker fuel sales in 2022 and 2023.

Competition and Customers
In the sale of bunker fuel, we compete with ports offering bunker fuels that are along the route of travel of the vessel. Customers for bunker fuel sales are primarily ship owners, marketers and traders. One of our customers, a marketer of petroleum products, was the largest customer of our fuels marketing segment and accounted for approximately 11% of the total segment revenues for the year ended December 31, 2023. No other customer accounted for a significant portion of the total revenues of the fuels marketing segment for the year ended December 31, 2023.
Results of Operations
The following table presents operating highlights for the fuels marketing segment:
 Year Ended December 31, 
 20232022Change
(Thousands of Dollars)
Fuels Marketing Segment:
Product sales$440,725 $520,486 $(79,761)
Cost of goods405,992 484,477 (78,485)
Gross margin34,733 36,009 (1,276)
Operating expenses1,807 2,473 (666)
Segment operating income$32,926 $33,536 $(610)

Product sales decreased $79.8 million, and cost of goods decreased $78.5 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to lower fuel prices for our bunkering operations. Gross margin decreased $1.3 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, as a decrease of $2.8 million in gross margin from our bunkering operations and a decrease of $2.8 million in gross margin from other product sales more than offset higher blending gross margins of $4.3 million, all primarily due to lower fuel prices.

Segment operating income decreased $0.6 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, due to the changes in gross margins described above, partially offset by a decrease in operating expenses of $0.7 million, primarily related to our bunkering operations.

LIQUIDITY AND CAPITAL RESOURCES

The following sections are included in Liquidity and Capital Resources:
•Overview
•Cash Flows
•Sources of Liquidity
•Material Cash Requirements

OVERVIEW
Our primary cash requirements include distributions to our limited partners, debt service, capital expenditures and operating expenses. Our partnership agreement requires that we distribute all Available Cash (as defined in our partnership agreement) to our common limited partners each quarter. Available Cash is generally defined as all cash receipts less cash disbursements, including distributions to our preferred unit holders, and cash reserves established by our general partner, in its sole discretion. 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 sale of assets.
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In the first quarter of 2023, we completed the Sale-Leaseback Transaction for $103.0 million, and in the third quarter of 2023, we issued 14,950,000 common units for net proceeds of approximately $222.0 million. We used the proceeds from these transactions to repay outstanding borrowings under our Revolving Credit Agreement, which facilitated the redemption of 16,346,650 of the Series D Preferred Units, representing all outstanding Series D Preferred Units. Additionally, in the second quarter of 2023, we extended the maturity date on our Revolving Credit Agreement to January 27, 2027, and extended the scheduled termination date on our Receivables Financing Agreement to July 1, 2026. Similarly, in 2022, we had reduced our leverage to position ourselves to repurchase 6,900,000 of the Series D Preferred Units in November 2022, representing approximately one-third of the outstanding units at that time, using borrowings under our Revolving Credit Agreement.

As illustrated in the chart below, in 2023 and 2022, we funded all our expenses, distribution requirements and capital expenditures using cash from operating activities.
Sources and Uses - 2-1-2024 - FINAL.jpg

For the full-year 2024, we expect to fund all our expenses, distribution requirements and capital expenditures using internally generated cash flows. We have no long-term debt maturities until 2025.
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CASH FLOWS
A discussion of our cash flows and other changes in financial position for 2021 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, 2022 filed with the SEC on February 23, 2023.

The following table summarizes our cash flows from operating, investing and financing activities (see also our Consolidated Statements of Cash Flows in Item 8. “Financial Statements and Supplementary Data”).
 Year Ended December 31,
 20232022
(Thousands of Dollars)
Net cash provided by (used in):
Operating activities$514,269 $527,549 
Investing activities(23,240)(84,365)
Financing activities(502,430)(434,953)
Effect of foreign exchange rate changes on cash40 707 
Net (decrease) increase in cash, cash equivalents and restricted cash$(11,361)$8,938 

Net cash provided by operating activities decreased $13.3 million for the year ended December 31, 2023, compared to the year ended December 31, 2022. The increase in net income of $50.9 million was more than offset by noncash adjustments to reconcile to net cash provided by operating activities. In addition, our working capital decreased by $10.6 million for the year ended December 31, 2023 and $0.7 million for the year ended December 31, 2022. Generally, working capital requirements are affected by our accounts receivable, accounts payable and accrued liability balances, which vary depending on the timing of payments.

Net cash used in investing activities decreased $61.1 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to proceeds of approximately $103.0 million from the Sale-Leaseback Transaction in the first quarter of 2023, compared to proceeds from asset sales of $59.3 million in 2022. Additionally, for the year ended December 31, 2023 compared to the year ended December 31, 2022, cash outflows related to capital expenditures decreased an aggregate $14.9 million. Investing activities also include insurance proceeds of $12.4 million for the year December 31, 2023, compared to insurance proceeds of $9.8 million for the December 31, 2022, both related to the 2019 Selby terminal fire.

Net cash used in financing activities increased $67.5 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to the redemption of the outstanding Series D Preferred Units for $518.7 million in 2023, compared to the repurchase of outstanding Series D Preferred Units for $222.4 million in 2022, partially offset by the issuance of common units in the third quarter of 2023 for approximately $222.0 million.

SOURCES OF LIQUIDITY
Revolving Credit Agreement
As of December 31, 2023, our Revolving Credit Agreement had $652.4 million available for borrowing and $343.0 million of borrowings outstanding. Letters of credit issued under our Revolving Credit Agreement totaled $4.6 million as of December 31, 2023 and limit the amount we can borrow under our Revolving Credit Agreement. Obligations under our Revolving Credit Agreement are guaranteed by NuStar Energy and NuPOP.

Our 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, 2023, the Consolidated Debt Coverage Ratio (as defined in the Revolving Credit Agreement) may not exceed 5.00-to-1.00 and the Consolidated Interest Coverage Ratio (as defined in the Revolving Credit Agreement) must not be less than 1.75-to-1.00. Our 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, 2023, our Consolidated Debt Coverage Ratio was 3.85x and our Consolidated Interest Coverage Ratio was 2.18x.

On June 30, 2023, we amended our Revolving Credit Agreement, primarily to extend the maturity date from April 27, 2025 to January 27, 2027. The amendment also includes a requirement that we must demonstrate and certify, prior to using any borrowings under our Revolving Credit Agreement to redeem certain unsecured indebtedness or prior to their redemption/repurchase, the Series D Preferred Units, that the sum of our Revolving Credit Agreement availability and unrestricted cash
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balance is no less than $150.0 million on a pro forma basis both before and immediately after giving effect to the borrowing and the redemption. On January 28, 2022, we amended and restated our partnership agreementRevolving Credit Agreement to, among other items:
(i) increase the maximum amount of letters of credit capable of being issued from $400.0 million to $500.0 million; (ii) replace London Interbank Offering Rate, or LIBOR, benchmark provisions with customary secured overnight financing rate, or SOFR, benchmark provisions; (iii) remove the 0.50x increase permitted in connectionour Consolidated Debt Coverage Ratio for certain rolling periods in which an acquisition for aggregate net consideration of at least $50.0 million occurs; and (iv) add baskets and exceptions to certain negative covenants.

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 the Receivables Financing Agreement with a third-party lender 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 June 29, 2023, we amended the Receivables Financing Agreement to extend the scheduled termination date from January 31, 2025 to July 1, 2026. On January 28, 2022, the Receivables Financing Agreement was amended to, among other items: (i) reduce the floor rate in the calculation of our borrowing rates; and (ii) replace provisions related to the LIBOR rate of interest with references to SOFR rates of interest.

See Note 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of our debt agreements.

Issuance of Common Units
We used the net proceeds of approximately $222.0 million from the issuance of the Series B Preferred Units described below andcommon units on August 11, 2023 to repay outstanding borrowings under our acquisition of Navigator Energy Services, LLC to waive up to an aggregate $22.0 millionRevolving Credit Agreement. See Note 18 of the quarterly incentive distributionsNotes to our general partnerConsolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for any NS common units issuedadditional information.

Asset Sales
We used the proceeds of approximately $103.0 million from the datesale of our Corporate Headquarters on March 21, 2023 and approximately $60.0 million from the acquisition agreement (other than those attributablePoint Tupper Terminal Disposition on April 29, 2022 to NS common units issuedrepay outstanding borrowings under any equity compensation plan) for ten consecutive quarters, starting with the distributions for the second quarter of 2017.

Pursuant to the Merger Agreement and at the effective time of the Merger, our partnership agreement will be amended and restated to, among other things, cancel the incentive distribution rights held by our general partner and convert the 2% general partner interest in NuStar Energy held by our general partner into a non-economic management interest. As a result, after the Merger, our general partner will no longer receive incentive distributions or quarterly cash distributions related to its ownership interest, from us. Please refer toRevolving Credit Agreement. See Note 284 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of these asset sales.

MATERIAL CASH REQUIREMENTS
Capital Expenditures
Our operations require significant investments to maintain, upgrade or enhance the Merger.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
Preferred Unit Distributions•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 providessummarizes our capital expenditures:
Strategic Capital ExpendituresReliability Capital ExpendituresTotal
(Thousands of Dollars)
For the year ended December 31:
2023$119,513 $27,995 $147,508 
2022$107,855 $32,775 $140,630 

Strategic capital expenditures for the termsyears ended December 31, 2023 and December 31, 2022 primarily consisted of expansion projects on our Permian Crude System and Central West Refined Products Pipelines, and biofuel and other projects at our West Coast Terminals, as well as connection projects on our Ammonia Pipeline in 2023. Reliability capital expenditures primarily related to distributionsmaintenance upgrade projects at our terminals and on our Ammonia Pipeline.
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We expect our strategic capital expenditures for the year ended December 31, 2024 to be concentrated on expansion projects to accommodate production growth in the Permian Basin and projects to expand our renewable fuels network on the West Coast. We continue to evaluate our capital budget and internal growth projects can be accelerated or scaled back depending on market conditions or customer demand.

Series A, Series B and Series C Fixed-to-Floating Rate Cumulative Redeemable PerpetualD Preferred Units (collectively,Redemption and Repurchase
We redeemed or repurchased all the Series D Preferred Units):Units, as shown below:
TransactionTransaction DateNumber of UnitsPrice per Unit, including Accrued DistributionsTotal Price, including
Accrued Distributions
(Thousands of Dollars)
RedemptionSeptember 12, 20238,286,650$32.59 $270,062 
RedemptionJuly 31, 20232,560,000$32.18 $82,381 
RedemptionJune 30, 20235,500,000$31.88 $175,340 
RepurchaseNovember 22, 20226,900,000$32.73 $225,837 

Units Fixed Distribution Rate per Annum (as a Percentage of the $25.00 Liquidation Preference per Unit) Fixed Distribution Rate per Unit per Annum Optional Redemption Date/Date at Which Distribution Rate Becomes Floating Floating Annual Rate (as a Percentage of the $25.00 Liquidation Preference per Unit)
Series A Preferred Units 8.50% $2.125
 December 15, 2021 Three-month LIBOR plus 6.766%
Series B Preferred Units 7.625% $1.90625
 June 15, 2022 Three-month LIBOR plus 5.643%
Series C Preferred Units 9.00% $2.25
 December 15, 2022 Three-month LIBOR plus 6.88%
See Note 17 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.


Distributions
Preferred Units. Distributions on the Preferred Unitsour outstanding 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 equalSee Notes 17 and 18 of the Notes to each other and senior to all of our other classes of equity securities with respect to distribution rights and rights upon liquidation.


The following table summarizes information related to our quarterly cash distributions on our Preferred Units:
Period 
Cash
Distributions
Per Unit
 Record Date Payment Date
       
Series A Preferred Units:      
December 15, 2017 - March 14, 2018 (a) $0.53125
 March 1, 2018 March 15, 2018
September 15, 2017 - December 14, 2017 $0.53125
 December 1, 2017 December 15, 2017
June 15, 2017 - September 14, 2017 $0.53125
 September 1, 2017 September 15, 2017
March 15, 2017 - June 14, 2017 $0.53125
 June 1, 2017 June 15, 2017
November 25, 2016 - March 14, 2017 $0.64930556
 March 1, 2017 March 15, 2017
       
Series B Preferred Units:      
December 15, 2017 - March 14, 2018 (a) $0.47657
 March 1, 2018 March 15, 2018
September 15, 2017 - December 14, 2017 $0.47657
 December 1, 2017 December 15, 2017
April 28, 2017 - September 14, 2017 $0.725434028
 September 1, 2017 September 15, 2017
       
Series C Preferred Units:      
November 30, 2017 - March 14, 2018 (a) $0.65625
 March 1, 2018 March 15, 2018
(a)The distribution was announced on January 29, 2018.


ITEM 6.    SELECTED FINANCIAL DATA
The following table contains selected financial data derived from our audited financial statements:
 Year Ended December 31,
 2017 2016 2015 2014 2013 (a)
 (Thousands of Dollars, Except Per Unit Data)
Statement of Income Data:         
Revenues (b)$1,814,019
 $1,756,682
 $2,084,040
 $3,075,118
 $3,463,732
Operating income (loss)$336,278
 $359,109
 $390,704
 $346,901
 $(19,121)
Income (loss) from continuing operations (c)$147,964
 $150,003
 $305,946
 $214,169
 $(185,509)
Income (loss) from continuing operations per
common unit (c)
$0.64
 $1.27
 $3.29
 $2.14
 $(2.89)
Cash distributions per unit applicable
to common limited partners
$4.38
 $4.38
 $4.38
 $4.38
 $4.38
          
 December 31,
 2017 (d) 2016 2015 2014 2013
 (Thousands of Dollars)
Balance Sheet Data:         
Property, plant and equipment, net$4,300,933
 $3,722,283
 $3,683,571
 $3,460,732
 $3,310,653
Total assets$6,535,233
 $5,030,545
 $5,125,525
 $4,918,796
 $5,032,186
Long-term debt, less current portion$3,263,069
 $3,014,364
 $3,055,612
 $2,749,452
 $2,655,553
Total partners’ equity$2,480,089
 $1,611,617
 $1,609,844
 $1,716,210
 $1,903,794
(a)The losses for the year ended December 31, 2013 are mainly due to goodwill impairment charges.
(b)DeclinesConsolidated Financial Statements in revenues from 2013 through 2017 are mainly from a reduction in marketing activity and lower commodity prices. We ceased marketing crude oil in the second quarter of 2017 and exited our heavy fuels trading operations in the third quarter of 2017.
(c)Includes the impact of a $58.7 million non-cash impairment charge on the Axeon term loan in 2016 and a $56.3 million non-cash gain associated with the Linden terminal acquisition in 2015.
(d)
The significant increases in balance sheet data are primarily due to our acquisition of Navigator Energy Services, LLC for approximately $1.5 billion in May 2017.


ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following review of our results of operations and financial condition should be read in conjunction with “Cautionary Statement Regarding Forward-Looking Information,” Items 1., 1A. and 2. “Business, Risk Factors and Properties” and Item 8. “Financial Statements and Supplementary Data” includedfor additional information.

Series D Preferred Units. Prior to their redemption and/or repurchase, the distribution rates on the outstanding Series D Preferred Units were as follows: (i) 9.75% per annum ($0.619 per unit per distribution period) for the first two years (beginning with the September 17, 2018 distribution); (ii) 10.75% per annum ($0.682 per unit per distribution period) for years three through five; and (iii) the greater of 13.75% per annum ($0.872 per unit per distribution period) or the distribution per common unit thereafter. The number of Series D Preferred Units outstanding as of December 31, 2022 was 16,346,650, and due to the redemptions and repurchase discussed above, the Series D Preferred Units were cancelled and no longer represent a limited partner interest.

The distribution rate on the Series D Preferred Units increased on June 15, 2023, to the greater of 13.75% per annum ($0.872 per unit per distribution period) or the distribution per common unit. Distributions accrued for redeemed Series D Preferred Units from the notification dates to the redemption dates are reported in this report.“Interest expense, net” on the consolidated statements of income and are excluded from total distributions below for the applicable periods. Distribution information on the Series D Preferred Units was as follows:
OVERVIEW
 Distribution PeriodDistribution Rate per UnitTotal Distribution
(Thousands of Dollars)
June 15, 2023 - September 12, 2023$0.872 $5,134 
March 15, 2023 - June 14, 2023$0.682 $10,315 
December 15, 2022 - March 14, 2023$0.682 $11,148 
September 15, 2022 - December 14, 2022$0.682 $14,337 
June 15, 2022 - September 14, 2022$0.682 $15,854 
March 15, 2022 - June 14, 2022$0.682 $15,854 
December 15, 2021 - March 14, 2022$0.682 $15,854 

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Series A, B and C Preferred Units. Information on our Series A, B and C Preferred Units is shown below:
UnitsUnits Issued and Outstanding as of December 31, 2023Optional Redemption Date/Date When Distribution Rate Became FloatingFloating Annual Rate (as a Percentage of the $25.00 Liquidation Preference Per Unit)
Series A Preferred Units9,060,000December 15, 2021
Three-month LIBOR(a) plus 6.766%
Series B Preferred Units15,400,000June 15, 2022
Three-month LIBOR(a) plus 5.643%
Series C Preferred Units6,900,000December 15, 2022
Three-month LIBOR(a) plus 6.88%
(a)Beginning with the distribution period starting on September 15, 2023, LIBOR was replaced with the corresponding CME Term SOFR plus the applicable tenor spread adjustment of 0.26161%.

Distribution information on our Series A, B and C Preferred Units is as follows (thousands of dollars, except per unit data):
Series A Preferred UnitsSeries B Preferred UnitsSeries C Preferred Units
 Distribution PeriodDistribution Rate per UnitTotal DistributionDistribution Rate per UnitTotal DistributionDistribution Rate per UnitTotal Distribution
December 15, 2023 - March 14, 2024$0.77533 $7,024 $0.70515 $10,859 $0.78246 $5,399 
September 15, 2023 - December 14, 2023$0.77736 $7,043 $0.70717 $10,890 $0.78448 $5,413 
June 15, 2023 - September 14, 2023$0.76715 $6,950 $0.69696 $10,733 $0.77428 $5,343 
March 15, 2023 - June 14, 2023$0.73169 $6,629 $0.66150 $10,187 $0.73881 $5,098 
December 15, 2022 - March 14, 2023$0.71889 $6,513 $0.64871 $9,990 $0.72602 $5,010 
September 15, 2022 - December 14, 2022$0.64059 $5,804 $0.57040 $8,784 $0.56250 $3,881 
June 15, 2022 - September 14, 2022$0.54808 $4,966 $0.47789 $7,360 $0.56250 $3,881 
March 15, 2022 - June 14, 2022$0.47817 $4,332 $0.47657 $7,339 $0.56250 $3,881 
December 15, 2021 - March 14, 2022$0.43606 $3,951 $0.47657 $7,339 $0.56250 $3,881 

On January 25, 2024, our Board of Directors declared quarterly distributions with respect to the Series A, B and C Preferred Units to be paid on March 15, 2024 to holders of record as of March 1, 2024.

Common Units. Under our partnership agreement, distribution payments are required to be 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. On January 25, 2024, our Board of Directors declared distributions with respect to our common units for the quarter ended December 31, 2023. The following table summarizes information about cash distributions to our common limited partners applicable to the period in which the distributions were earned:
Quarter EndedCash Distributions
Per Unit		Total Cash DistributionsRecord DatePayment Date
(Thousands of Dollars)
December 31, 2023$0.40 $50,607 February 7, 2024February 13, 2024
September 30, 20230.40 50,358 November 7, 2023November 14, 2023
June 30, 20230.40 44,363 August 8, 2023August 14, 2023
March 31, 20230.40 44,396 May 8, 2023May 12, 2023
Year ended December 31, 2023$1.60 $189,724 
Year ended December 31, 2022$1.60 $176,746 

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Debt Obligations
The following table summarizes our debt obligations:
 MaturityOutstanding Obligations as of December 31, 2023
 (Thousands of Dollars)
5.75% senior notesOctober 1, 2025$600,000 
6.00% senior notesJune 1, 2026$500,000 
Receivables Financing Agreement, 7.0% as of December 31, 2023July 1, 2026$69,800 
Revolving Credit Agreement, 8.0% as of December 31, 2023January 27, 2027$343,000 
5.625% senior notesApril 28, 2027$550,000 
6.375% senior notesOctober 1, 2030$600,000 
GoZone Bonds, 5.85% - 6.35%2038thru2041$322,140 
Subordinated notes, 12.4% as of December 31, 2023January 15, 2043$402,500 

We believe that, as of December 31, 2023, we are in compliance with the financial 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.

Receivables Financing Agreement and Revolving Credit Agreement. Borrowings under the Receivables Financing Agreement bear interest, at NuStar Energy L.P. (NYSE: NS) is engagedFinance’s option, at a base rate or a SOFR rate, each as defined in the transportationReceivables Financing Agreement. Borrowings under our Revolving Credit Agreement bear interest, at our option, at an alternate base rate or a SOFR rate, each as defined in the Revolving Credit Agreement. The interest rate on our Revolving Credit Agreement and certain fees under the Receivables Financing Agreement, 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 RatingsMoody’s Investor Service Inc.S&P Global Ratings
RatingsBBBa3BB-
OutlookStableStablePositive

Gulf Opportunity Zone Revenue Bonds. As reflected in the table below, the holders of petroleum productsthe Series 2008, Series 2010B and anhydrous ammonia,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 are expected to be remarketed with a new interest rate established. Each of the terminalling, storageSeries 2010 and marketingSeries 2010A GoZone Bonds is subject to redemption on or after June 1, 2030 by the Parish of petroleum products. Unless otherwise indicated,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 following table summarizes the GoZone Bonds outstanding as of December 31, 2023:
SeriesDate IssuedAmount
Outstanding
Interest Rate		Mandatory
Purchase Date		Optional Redemption DateMaturity Date
 (Thousands of Dollars) 
Series 2008June 26, 2008$55,440 6.10 %June 1, 2030n/aJune 1, 2038
Series 2010July 15, 2010100,000 6.35 %n/aJune 1, 2030July 1, 2040
Series 2010AOctober 7, 201043,300 6.35 %n/aJune 1, 2030October 1, 2040
Series 2010BDecember 29, 201048,400 6.10 %June 1, 2030n/aDecember 1, 2040
Series 2011August 9, 201175,000 5.85 %June 1, 2025n/aAugust 1, 2041
Total$322,140 

NuStar Logistics Subordinated Notes.NuStar Logistics’ $402.5 million of fixed-to-floating rate subordinated notes (the Subordinated Notes). Effective with the quarterly interest periods starting after June 30, 2023, the interest rate on the Subordinated Notes is equal to the sum of the three-month CME term SOFR plus the applicable tenor spread adjustment of 0.26161% for the related quarterly interest period plus 6.734%, payable quarterly, unless payment is deferred in accordance with the terms “NuStar Energy,” “NS,” “the Partnership,” “we,” “our” and “us” are used in this reportof the notes. NuStar Logistics may elect to refer to NuStar Energy L.P., todefer 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
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cannot declare or make cash distributions with respect to, or redeem, purchase or make a liquidation payment with respect to, its equity securities during the period that interest payments are deferred.

Guarantor Summarized Financial Information. NuStar Energy has no operations, and its assets consist primarily 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 (i) ranks equally in right of payment with all other existing and future unsecured senior indebtedness of that guarantor, (ii) 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 (iii) ranks senior to its guarantee of our consolidatedsubordinated 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 is subordinated in right of payment and upon liquidation to the prior payment in full of all other existing and future senior indebtedness of that guarantor. NuPOP will be released from its guarantee when it no longer guarantees any obligations of NuStar Energy or any of its subsidiaries, including NuStar Logistics, under any bank credit facility or public debt instrument. The rights of holders of our senior and subordinated notes may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. See Note 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of our debt agreements.

The following tables present summarized combined balance sheet and income statement information for NuStar Energy, NuStar Logistics and NuPOP (collectively, the Guarantor Issuer Group). Intercompany items among the Guarantor Issuer Group have been eliminated in the summarized combined financial information below, as well as intercompany balances and activity for the Guarantor Issuer Group with non-guarantor subsidiaries, including the Guarantor Issuer Group’s investment balances in non-guarantor subsidiaries.
December 31, 2023
(Thousands of Dollars)
Summarized Combined Balance Sheet Information for the Guarantor Issuer Group:
Current assets$42,000 
Long-term assets$3,160,956 
Current liabilities (a)$135,366 
Long-term liabilities, including long-term debt$3,487,719 
(a)Excluding $1,894.0 million of net intercompany payables due to the non-guarantor subsidiaries from the Guarantor Issuer Group.

Long-term assets for the non-guarantor subsidiaries totaled $1,548.3 million as of December 31, 2023.

Year Ended December 31, 2023
(Thousands of Dollars)
Summarized Combined Income Statement Information for the Guarantor Issuer Group:
Revenues$830,406 
Operating income$333,986 
Interest expense, net$(239,113)
Net income$96,178 

Revenues and net income for the non-guarantor subsidiaries totaled $803.8 million and $177.5 million, respectively, for the year ended December 31, 2023.

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Contractual Obligations
The following table presents our contractual obligations and commitments as of December 31, 2023:
 CurrentLong-Term
 (Thousands of Dollars)
Long-term debt maturities$— $3,387,440 
Interest payments238,001 1,506,912 
Operating leases14,267 238,031 
Finance leases7,067 67,000 
Purchase obligations6,406 12,893 
Total$265,741 $5,212,276 

The interest payments calculated for our variable-rate, long-term debt are based on interest rates and the outstanding borrowings as of December 31, 2023. The interest payments on our fixed-rate debt are based on the stated interest rates and the outstanding borrowings as of December 31, 2023. See Note 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.
Our operating leases consist primarily of land and dock leases at various terminal facilities and the operating lease agreement to lease back the Corporate Headquarters in the first quarter of 2023 (the HQ Lease Agreement), as further discussed in Notes 4 and 15 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.” The HQ Lease Agreement has an initial term of 20 years, with two renewal options of ten years each.
Our finance leases consist primarily of a dock lease at our Corpus Christi North Beach terminal with a remaining term of approximately two years and three additional five-year renewal periods that also includes a commitment for minimum dockage and wharfage throughput volumes. See Note 15 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on our operating and finance leases.
A purchase obligation is an enforceable and legally binding agreement to purchase goods or services that specifies significant terms, including (i) fixed or minimum quantities to be purchased, (ii) fixed, minimum or variable price provisions and (iii) the approximate timing of the transaction. 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.

Pension and Other Postretirement Benefit Plan Contributions
During 2023, we contributed $11.2 million and $0.5 million to our pension and postretirement benefit plans, respectively. In 2024, we expect to contribute approximately $10.2 million to our pension and postretirement benefit plans and will monitor our funding status to determine if any contributions are required by regulations or laws, or with respect to unfunded plans, necessary to fund current benefits. Pension and postretirement benefit plans funding beyond 2024 is uncertain as the funding varies from year to year based upon changes in the fair value of the plan assets and actuarial assumptions.

A change of 0.25% in the specified assumptions would have the following effects to our pension and postretirement benefit obligations and costs:
Pension
Benefits		Other Postretirement Benefits
(Thousands of Dollars)
Increase in benefit obligation as of December 31, 2023 resulting from:
Discount rate decrease$3,300 $400 
Compensation rate increase$600 n/a
(Decrease) increase in net periodic benefit cost for the year ending December 31, 2024
resulting from:
Discount rate decrease$(200)$— 
Expected long-term rate of returns on plan assets decrease$400 n/a
Compensation rate increase$100 n/a

See Notes 2 and 21 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.
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Environmental, Health and Safety
As described below under “Environmental, Health, Safety and Security Regulation,” our operations in the U.S. and Mexico are subject to extensive international, federal, state and local environmental laws and regulations, including those relating to the discharge of materials into the environment, waste management, remediation, the characteristics and composition of fuels, climate change and greenhouse gases. Our operations are also subject to extensive health, safety and security laws and regulations, including those relating to worker and pipeline safety, pipeline and storage tank integrity and operations security. Because more stringent environmental and safety laws and regulations are continuously being enacted or proposed, the level of expenditures required for environmental, health and safety matters is expected to increase in the future.

The balance of and changes in our accruals for environmental matters as of and for the years ended December 31, 2023 and 2022 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.

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, 2023, we had 1,184 employees, of which 1,173 are based in the United States and 11 are based in Mexico. Only 1.1 percent of our employees are represented under collective bargaining agreements. In the United States, 487 of our employees work at our headquarters in San Antonio, Texas, with the remaining 686 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, 2023:
•19.1% of all of them takenour employees and 29.0% of our employees at senior manager level and above are female; and
•34.8% of our U.S. employees and 24.5% of our U.S. employees at senior manager level and above are minorities (as defined by the U.S. Equal Opportunity Employment Commission).

Employee Benefits and NuStar’s Culture
We provide opportunities for our employees to develop and enhance their skills through defined career paths, professional training, educational reimbursement and leadership and development programs, as well as regular training regarding safety, operations, ethics (including our Code of Business Conduct and Ethics), human resources topics and cybersecurity. In addition, we support our employees by providing competitive compensation and benefits.

We benchmark our compensation programs through market surveys to help offer competitive packages to attract and retain high-performing employees. Our compensation department also evaluates company-wide racial and gender equity by job-profile each time an employee is hired or recommended for a promotion. This helps to ensure that compensation levels are equitable for all employees regardless of race or gender.

Our benefits and health and wellness programs include life and health insurance (medical, dental and vision), prescription drug benefits, flexible spending accounts, paid sick leave, vacation, short- and long-term disability, mental and behavioral health resources, retirement benefits (including 401(k) and pension), educational reimbursement, a disaster relief fund that provides cash grants (that do not have to be repaid) to employees undergoing difficult circumstances, an employee assistance program and employee recognition programs. We also are committed to supporting the communities in which we operate, and we organize opportunities for our employees to participate in and enrich our communities through a variety of initiatives, such as fundraising activities, community clean-up projects and educational programs.

Our culture is driven by our nine guiding principles: safety; integrity; commitment; make a difference; teamwork; respect; communication; excellence; and pride. We believe that these principles are the building blocks for our success and have helped us to recruit and retain our employees and make NuStar a great place to work. We have been recognized on FORTUNE’S “100 Best Companies to Work For” list 13 times, FORTUNE’S “Best Workplaces for Millennials” list five times, the “Best Places For Working Parents” list three times, and Latino Leader Magazine’s “Best Companies for Latinos to Work” list three times. We also were recognized as a whole. NuStar GP Holdings, LLC (NuStar GP Holdings or NSH) (NYSE: NSH) ownstop employer by regional and local publications, including being recognized as a top employer in Texas by FORTUNE. In addition, we were recently recognized on Newsweek’s “America’s Most Trustworthy Companies” and “World’s Most Trustworthy Companies” lists. Many of these awards are based on confidential surveys of our general partner, Riverwalk Logistics, L.P.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, 2023, our voluntary
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turnover rate over the last five years has averaged 3.8%, and owns an approximate 11% common limited partner interest231 of our employees have been employed by NuStar or predecessor entities for at least 20 years.

Safety
Safety is our first priority. In managing our business, we focus on the safety of our employees and contractors, as well as the communities in uswhich we operate. We have implemented safety programs and management practices to promote a culture of safety, including required training for field and office employees and contractors, as well as specific qualifications and certifications for field employees and contractors. To further emphasize the importance of safety at NuStar, our Board of Directors receives a comprehensive annual report and monthly updates regarding our health, safety and environmental performance. The Compensation Committee of our Board of Directors also evaluates our overall environmental, social and governance (ESG) performance and our health, safety and environmental performance together annually as one of the metrics used to determine the annual incentive bonus for all of our employees, including our executive officers, which we believe reinforces the importance of maintaining safe, responsible operations and focusing on ESG excellence.

We are proud of NuStar’s safety performance. Our 2023 total recordable incident rate (TRIR) of 0.55 was better than the 3.60 average most recently reported by the U.S. Bureau of Labor Statistics (BLS) for the bulk terminals industry and in line with the 0.50 average most recently reported by BLS for the pipeline transportation industry. Our 2023 days away, restricted or transferred rate (DART) of 0.39 was better than the 2.80 average most recently reported by BLS for the bulk terminals industry and in line with the 0.30 average most recently reported by BLS for the pipeline transportation industry. NuStar also participates in the Occupational Safety and Health Administration’s (OSHA) Voluntary Protection Program (VPP), which promotes effective worksite health and safety. Achieving VPP Star status requires rigorous OSHA review and audit, and requires recertification every three to five years. As of December 31, 2017.2023, approximately 92% of our eligible U.S. terminals have attained VPP Star status. NuStar also has received the International Liquids Terminals Association’s Safety Excellence Award 13 times.

Sustainability Report
We publish a Sustainability Report, which covers topics similar to those described above, including our guiding principles; operations and economic impact; environmental and safety programs; sustainability; renewable fuels-related services; policies and statistics (including greenhouse gas emissions disclosures); employee development and training; diversity and inclusion; community involvement and development; recent awards; risk management; cybersecurity; and governance. Our Management’s DiscussionSustainability Report can be viewed at https://sustainability.nustarenergy.com. Our Sustainability Report and Analysisthe information contained on our website are not part of Financial Conditionthis Annual Report on Form 10-K, are not “soliciting materials,” are not deemed filed with the SEC and Resultsare not to be incorporated by reference into any of Operations is presented in seven sections:NuStar Energy’s filings under the Securities Act of 1933 or the Securities Act of 1934, as amended, respectively.
Overview
Results of Operations
TrendsThe following table presents operating highlights for the pipeline segment:
 Year Ended December 31, 
 20232022Change
(Thousands of Dollars, Except Barrel Data)
Pipeline Segment:
Crude oil pipelines throughput (barrels/day)1,234,051 1,319,360 (85,309)
Refined products and ammonia pipelines throughput (barrels/day)602,913 579,240 23,673 
Total throughput (barrels/day)1,836,964 1,898,600 (61,636)
Throughput and other revenues$873,869 $828,191 $45,678 
Operating expenses214,751 210,719 4,032 
Depreciation and amortization expense175,930 178,802 (2,872)
Segment operating income$483,188 $438,670 $44,518 

Tariff indexations effective July 2022 and Outlook
Liquidity and Capital Resources
Related Party Transactions
Critical Accounting Policies
New Accounting Pronouncements

Recent Developments
Merger. On February 7, 2018, NuStar Energy, Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, a wholly owned subsidiary of NuStar Energy (Merger Sub), Riverwalk Holdings, LLC and NuStar GP Holdings, LLC (NuStar GP Holdings) entered into an Agreement and Plan of Merger (the Merger Agreement) pursuant to which Merger Sub will merge with and into NuStar GP Holdings with NuStar GP Holdings beingJuly 2023 increased the surviving entity (the Merger), such that NuStar Energy will be the sole member of NuStar GP Holdings following the Merger. Pursuant to the Merger Agreement and at the effective time of the Merger, our partnership agreement will be amended and restated to, among other things, (i) cancel the incentive distribution rights held by our general partner, (ii) convert the 2% general partner interest in NuStar Energy held by our general partner into a non-economic management interest and (iii) provide the holdersaverage tariff rates on most of our common units with voting rightspipeline systems and resulted in the election of the members of the board of directors of NuStar GP, LLC at an annual meeting, beginning in 2019. The Merger is subject to the satisfaction or waiver of certain conditions, including approval of the Merger Agreement by NuStar GP Holdings unitholders. Please refer to Note 28 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the Merger.

Hurricane Activity. In the third quarter of 2017, parts of the Caribbean and Gulf of Mexico experienced three major hurricanes. Several of our facilities were affected by the hurricanes, but our St. Eustatius terminal experienced the most damage and was temporarily shut down. We incurred approximately $2.6 million of operating expenses to repair minor property damage at several of our domestic terminals. Additionally, we recorded a $5.0 million loss in “Other (expense) income, net” in the consolidated statements of income in the third quarter of 2017 for property damage at our St. Eustatius terminal, which represents the amount of our property deductible under our insurance policy. The hurricane impacts loweredhigher revenues for our bunker fuel operations in our fuels marketing segment and lowered throughput and associated handling fees in our storage segment in the third and fourth quarters of 2017. We received insurance proceeds of $12.5 million in 2017 for damages at our St. Eustatius terminal, of which $3.8 million was for business interruption and the remainder was used for repairs and cleanup. Proceeds from business interruption insurance are included in “Operating expenses” in the consolidated statements of income and in “Cash flows from operating activities” in the consolidated statements of cash flows. In January 2018, we received $87.5 million of insurance proceeds in settlement of our property damage claim for our St. Eustatius terminal. We expect that the costs to repair the property damage at the terminal will not exceed the value of insurance proceeds received.

Navigator Acquisition and Financing Transactions. On May 4, 2017, we completed the acquisition of Navigator Energy Services, LLC for approximately $1.5 billion (the Navigator Acquisition). In order to fund the purchase price, we issued 14,375,000 common units for net proceeds of $657.5 million, issued $550.0 million of 5.625% senior notes for net proceeds of $543.3 million and issued 15,400,000 of our 7.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (Series B Preferred Units) for net proceeds of $371.8 million. We collectively refer to the acquired assets as our

Permian Crude System. Please refer to Notes 4, 12 and 19 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion.

Axeon Term Loan. On February 22, 2017, we settled and terminated the $190.0 million term loan to Axeon Specialty Products, LLC (the Axeon Term Loan), pursuant to which we also provided credit support, such as guarantees, letters of credit and cash collateral, as applicable, of up to $125.0 million to Axeon Specialty Products, LLC (Axeon). We received $110.0 million in settlement of the Axeon Term Loan, and our obligation to provide ongoing credit support to Axeon ceased. In 2016, we recognized an impairment charge on the Axeon Term Loan of $58.7 million which is included in “Other (expense) income, net” in the consolidated statements of income. Please refer to Notes 7 and 15 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on the Axeon Term Loan and related credit support.

Other Events
Martin Terminal Acquisition. On December 21, 2016, we acquired crude oil and refined product storage assets in Corpus Christi, TX for $95.7 million, including $2.1 million of capital expenditure reimbursements, from Martin Operating Partnership L.P. (the Martin Terminal Acquisition). The assets acquired are in our storage segment and include 900,000 barrels of crude oil storage capacity, 250,000 barrels of refined product storage capacity and exclusive use of the Port of Corpus Christi’s new crude oil dock.The acquired assets, which are adjacent to our existing Corpus Christi North Beach terminal, increased our storage capacity in the Corpus Christi region and have direct connectivity to Eagle Ford crude oil production.

Employee Transfer from NuStar GP, LLC. On March 1, 2016, NuStar GP, LLC, the general partner of our general partner and a wholly owned subsidiary of NuStar GP Holdings, transferred and assigned to NuStar Services Company LLC (NuStar Services Co), a wholly owned subsidiary of NuStar Energy, all of NuStar GP, LLC’s employees and related benefit plans, programs, contracts and policies (the Employee Transfer). As a result of the Employee Transfer, we pay employee costs directly and sponsor the long-term incentive plan and other employee benefit plans. Please refer to the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for the following: Note 17 for further discussion of the Employee Transfer and our related party agreements, Note 22 for a discussion of our employee benefit plans and Note 23 for a discussion of our long-term incentive plan.

Linden Acquisition. On January 2, 2015, we acquired full ownership of ST Linden Terminal, LLC (Linden), which owns a refined products terminal in Linden, NJ with 4.3 million barrels of storage capacity, for $142.5 million (the Linden Acquisition). Prior to the Linden Acquisition, Linden operated as a joint venture between Linden Holding Corp. and us, with each party owning 50%. On the acquisition date, we remeasured our existing 50% equity investment in Linden to its fair value of $128.0 million and we recognized a gain of $56.3 million in “Other (expense) income, net” in the consolidated statements of income for the year ended December 31, 2015. Please refer2023, compared to Note 4the year ended December 31, 2022.
Pipeline segment revenues increased $45.7 million, and throughputs decreased 61,636 barrels per day for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to:
•an increase in revenues of the Notes$31.1 million and an increase in throughputs of 43,563 barrels per day on our McKee System pipelines, primarily due to Consolidated Financial Statementsoperational issues and a planned turnaround at a customer’s refinery in Item 8. “Financial Statements and Supplementary Data” for further discussion of the Linden Acquisition.

Operations
We conduct our operations through our subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics) and NuStar Pipeline Operating Partnership L.P. (NuPOP). Our operations are divided into three reportable business segments: pipeline, storage and fuels marketing. For a more detailed description of our segments, please refer to “Segments” under Item 1. “Business.”

Pipeline. We own 3,130 miles of refined product pipelines and 1,930 miles of crude oil pipelines,2022, as well as approximately 5.0higher demand on our pipeline serving the Denver, Colorado market in 2023; additionally, higher average tariff rates contributed to $9.7 million barrels of storage capacity, which comprise our Central West System. In addition, we own 2,370 miles of refined product pipelines, consisting of the overall increase;
•an increase in revenues of $12.1 million, despite a decrease in throughputs of 3,601 barrels per day on our East and North Pipelines,pipelines combined; revenues increased primarily due to higher average tariff rates, while throughputs decreased primarily due to unfavorable market conditions and planned turnarounds at customers’ refineries in 2023;
•an increase in revenues of $7.2 million and an increase in throughputs of 1,550 barrels per day on our Valley Pipeline, primarily due to higher average tariff rates;
•an increase in revenues of $5.9 million and an increase in throughputs of 5,159 barrels per day on our Three Rivers System, partially due to higher demand on certain of our pipelines within this system and pipeline expansions that were placed in service in July 2022. Also, higher average tariff rates contributed to $4.0 million of the overall increase;
•an increase in revenues of $3.4 million, despite slightly lower throughputs of 1,028 barrels per day on our Ammonia Pipeline; revenues increased primarily due to higher average tariff rates;
•a decrease in revenues of $2.2 million and a 2,000-mile ammonia pipeline (the Ammonia Pipeline), which comprisedecrease in throughputs of 27,367 barrels per day on our Central East System. The EastPermian Crude System, primarily due to decreased customer production supplying this system. Revenues also decreased $7.9 million due to lower commodity prices on PLA volumes and North Pipelines haveother products sold; these decreases were partially offset by higher average tariff rates in 2023;
•a decrease in revenues of $2.4 million and a decrease in throughputs of 10,781 barrels per day on our Ardmore System due to a turnaround at a customer’s refinery in the second quarter of 2023 and lower demand in 2023; and
•a decrease in revenues of $10.9 million and a decrease in throughputs of 68,374 barrels per day on our Corpus Christi Crude Pipeline System, primarily due to unfavorable market conditions and changes to a customer contract.

Operating expenses increased $4.0 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to an increase of $2.8 million in maintenance and regulatory expenses across various pipelines.

Depreciation and amortization expense decreased $2.9 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to fully amortized definite-lived intangible assets.


13

STORAGE SEGMENT
Our storage capacitysegment is composed of approximately 6.8 million barrels.

Storage. We own terminalsour facilities that provide storage, handling and other services on a fee basis for refined products, crude oil, specialty chemicals, renewable fuels and other liquids. As of December 31, 2023, we owned and operated 29 terminal and storage facilities in the United States Canada,and one terminal in Nuevo Laredo, Mexico, the Netherlands, including St. Eustatiuswith an aggregate storage capacity of 36.4 million barrels. The following table sets forth information about our terminal and storage facilities as of December 31, 2023:
FacilityTank Capacity
(Barrels)
Colorado Springs, CO327,000 
Denver, CO110,000 
Albuquerque, NM250,000 
Rosario, NM167,000 
Catoosa, OK359,000 
Abernathy, TX161,000 
Amarillo, TX269,000 
Corpus Christi, TX410,000 
Corpus Christi, TX (North Beach)3,962,000 
Edinburg, TX345,000 
El Paso, TX(a)
415,000 
Harlingen, TX286,000 
Laredo, TX218,000 
San Antonio, TX(b)
379,000 
Southlake, TX569,000 
Nuevo Laredo, Mexico268,000 
Central West Terminals8,495,000 
St. James, LA9,906,000 
Houston, TX87,000 
Gulf Coast Terminals9,993,000 
Los Angeles, CA615,000 
Pittsburg, CA398,000 
Selby, CA2,672,000 
Stockton, CA818,000 
Portland, OR1,348,000 
Tacoma, WA391,000 
Vancouver, WA(b)
775,000 
West Coast Terminals7,017,000 
Benicia, CA3,698,000 
Corpus Christi, TX4,030,000 
Texas City, TX3,141,000 
Refinery Storage Tanks10,869,000 
Total36,374,000 
(a)We own a 67% undivided interest in the Caribbean,El Paso refined product terminal. The tank capacity represents the proportionate share of capacity attributable to our ownership interest.
(b)Location includes two terminal facilities.
14

Description of Terminal and Storage Facilities
Central West Terminals. Our Central West Terminals include terminals located in Texas, Oklahoma, New Mexico and Colorado, as well as one terminal located in Nuevo Laredo, Mexico, with an aggregate storage capacity of 8.5 million barrels. Most of these terminals are connected to our Central West Refined Product Pipelines. Our Corpus Christi North Beach terminal, located at the United Kingdom (UK), with approximately 84.8Port of Corpus Christi in Texas, has 4.0 million barrels of crude oil storage capacity.and supports our Corpus Christi Crude Pipeline System that transports crude oil from the Eagle Ford and Permian Basin regions to Corpus Christi for export or refineries owned by third parties. This facility also provides our customers with the flexibility to segregate and deliver crude oil and processed condensate and has access to four docks, including two private docks. We can accommodate Suezmax-class vessels and load crude oil onto marine vessels simultaneously on all four docks.


Fuels Marketing. WithinWe refer to our fuels marketing operations, we purchase petroleum products for resale. The resultspipelines that transport crude oil from the Eagle Ford and Permian Basin regions to Corpus Christi, together with our Corpus Christi North Beach terminal, as the Corpus Christi Crude System.

Gulf Coast Terminals. Our Gulf Coast Terminals have an aggregate storage capacity of operations for the fuels marketing segment depend largely10.0 million barrels and include our St. James terminal, which is located on the margin between our costsMississippi River near St. James, Louisiana, and the sales pricesone terminal located in Houston, Texas. Our St. James terminal has a total storage capacity of 9.9 million barrels and is located on almost 900 acres of land, some of which is undeveloped. The majority of the products we market. Therefore, the results of operationsstorage tanks and infrastructure are suited for this segment are more sensitivelight to changes in commodity prices compared to the operations of the pipeline and storage segments. We enter into derivative contracts to attempt to mitigate the effects of commodity price fluctuations. The derivative instruments we use consist primarily of commodity futures and swap contracts. Not all of our derivative instruments qualify for hedge accounting treatment under U.S. generally accepted accounting principles. In such cases, our earnings for a period may include the gain or loss related to derivative instruments without including the offsetting effect of the hedged item, which could result in greater earnings volatility.

We ceased marketingmedium crude oil, with certain tanks capable of fuel oil or heated crude oil storage. Additionally, the facility has one barge dock and two ship docks, and can accommodate exports up to Aframax-class vessels. Our St. James terminal is connected to (i) offshore pipelines in the second quarterGulf of 2017Mexico, (ii) long-haul pipelines that can receive crude oil from the Eagle Ford, Permian Basin, other domestic shale plays and exited our heavy fuels trading operationsCanada, and (iii) pipelines connecting to refineries in the third quarterGulf Coast. The St. James terminal also has two unit train rail facilities that are served by the Union Pacific Railroad. Each facility has the capacity to simultaneously off-load 120 railcars, at a minimum, in a 24-hour period.

West Coast Terminals. Our West Coast Terminals include terminals located in California, Oregon and Washington, with an aggregate storage capacity of 2017. These actions are in line7.0 million barrels. The largest of these terminals is our Selby, California terminal, with our goala total storage capacity of reducing our exposure to commodity margins, and instead focusing on our core, fee-based pipeline and2.7 million barrels. We have completed several renewable fuel storage segments. The only operations remaining in our fuels marketing segment are our bunkering operationsprojects at our St. EustatiusWest Coast Terminals over the last several years, and are able to receive and distribute renewable fuels across the West Coast, including renewable diesel, sustainable aviation fuel, ethanol, biodiesel and renewable feedstock. Our West Coast Terminals are connected to supply from various domestic and foreign sources.

Refinery Storage Tanks. We own crude oil storage tanks with an aggregate storage capacity of 10.9 million barrels that are physically integrated with and serve refineries owned by Valero Energy at Corpus Christi and Texas City, Texas and Benicia, California. We lease our refinery storage tanks to Valero Energy in exchange for a fixed fee.

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

Demand for Storage Services
The operations of our blending operations.

Factors That Affect Resultsrefined product terminals depend in large part on the level of Operations
The following factors affect the results of our operations:
company-specific factors, such as facility integrity issues and maintenance requirements that impact the throughput rates of our assets;
seasonal factors that affect the demand for products transported by and/or stored in our assets andterminals in the markets served by those assets. Demand for our terminalling services will generally increase or decrease with demand for refined products, we sell;
industry factors, such as changes in the prices of petroleum products that affect demand and operations of our competitors;
economic factors, such as commodity price volatility that impact our fuels marketing segment; and
factors that impact the operations served by our pipeline and storage assets, such as utilization rates and maintenance turnaround schedules of our refining company customers and drilling activity by our crude oil production customers.

Current Market Conditions
The price of crude oil has recovered somewhat since its sharp initial decline in 2014 and subsequent historic lows during 2015 and 2016. In 2017, global supply and demand moved into balance, which seemsfor refined products tends to increase or decrease with the relative strength of the economy. In addition, the forward pricing curve can have reduced crude price volatility, but crude prices remain stalled at approximately 50% of their 2014 levels. Most energy industry experts now project a modest price recovery in 2018, but the duration and degree of price improvements will dependan impact on among other things, changes in global supply and demand.

Increases or decreases in the price of crude oil affect sectors across the energy industry, including our customers in crude oil production, refining and trading, in different ways at different points in any given price cycle. For example, U.S. crude oil producers reduced their capital spending relatively early in this sustained low price cycle, which reduced drilling activity and lowered production, particularly in shale play regions with higher relative drilling costs. As this cycle has continued, producers focused their trimmed-back spending on the most capital-efficient regions, such as, notably, the Permian Basin. Refiners, on the other hand, have benefitted from lower crude oil prices, to the extent they have been able to take advantage of lower feedstock prices, especially those positioned for healthy regional demand for their refined products; however, as refined product inventories increase, refiners are incentivized to reduce their production levels, which in turn may reduce their ability to benefit from low crude prices. Crude oil traders focus less on the current market commodity price than on whether that price is higher or lower than expected future market prices: if the future price for a product is believed to be higher than the current market price, or a “contango market,” traders are more likely to purchase and store products to sell in the future at the higher price. On the other hand, when the current price of crude oil nears or exceeds the expected future market price, or “backwardation,” as is currently the case, traders are no longer incentivized to purchase and store product for future sale. Our storage terminal revenues are somewhat insulated from demand volatility due to contracted rates for storage and minimum volume commitments.



RESULTS OF OPERATIONS
Year Ended December 31, 2017 ComparedCrude oil delivered to Year Ended December 31, 2016
Financial Highlights
(Thousandsour St. James and Corpus Christi North Beach terminals will generally increase or decrease with crude oil production rates in western Canada and the Bakken, Permian and Eagle Ford shale plays. In addition, the market price relationship between various grades of Dollars, Except Unitcrude oil impacts the demand for our unit train facilities at our St. James terminal. Although the Permian and Per Unit Data)Eagle Ford shale plays are partially insulated from negative economic conditions due to the low break-even point, our Corpus Christi exports have not returned to pre-pandemic levels due to lower global demand for refined products and crude oil and increased competition in crude oil export markets out of the U.S. Overall, refinery production rates,
15

 Year Ended December 31,  
 2017 2016 Change
Statement of Income Data:   
Revenues:     
Service revenues$1,128,726
 $1,083,165
 $45,561
Product sales685,293
 673,517
 11,776
Total revenues1,814,019
 1,756,682
 57,337
      
Costs and expenses:     
Cost of product sales651,599
 633,653
 17,946
Operating expenses449,670
 448,367
 1,303
General and administrative expenses112,240
 98,817
 13,423
Depreciation and amortization expense264,232
 216,736
 47,496
Total costs and expenses1,477,741
 1,397,573
 80,168
      
Operating income336,278
 359,109
 (22,831)
Interest expense, net(173,083) (138,350) (34,733)
Other expense, net(5,294) (58,783) 53,489
Income before income tax expense157,901
 161,976
 (4,075)
Income tax expense9,937
 11,973
 (2,036)
Net income$147,964
 $150,003
 $(2,039)
Basic and diluted net income per common unit$0.64
 $1.27
 $(0.63)
Basic weighted-average common units outstanding88,825,964
 78,080,484
 10,745,480
drilling activity and overall consumer demand in the U.S. rebounded in 2021, bringing demand for most of our terminal and storage facilities back to pre-pandemic levels. However, the detrimental impact of the pandemic, amplified by the Russia-Ukraine conflict, has continued to affect current global demand, resulting in a decline in crude oil exports from our Corpus Christi North Beach facility, and the current volatile and backwardated market has led to customers not renewing expiring contracts, primarily at our St. James terminal.
Annual Overview
Net income slightly decreasedDemand for renewable diesel, renewable jet fuel, ethanol and other renewable fuels continues to grow in markets served by our West Coast terminals due to new regulations with aggressive carbon emissions reduction goals. As this demand growth is expected to continue, we have completed, and continue to develop, renewable fuel storage projects at our West Coast terminals to meet this demand.
Customers
We provide storage and terminalling services for crude oil, refined products and other products to many of the world’s largest producers of crude oil, integrated oil companies, chemical companies, oil traders and refiners. In addition, our blending capabilities in our storage assets have attracted customers who have leased capacity primarily for blending purposes. The largest customer of our storage segment accounted for approximately 39% of the total revenues of the segment for the year ended December 31, 2017, compared2023. No other customer accounted for 10% or more 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 year ended December 31, 2016. The decrease in other expense, net, mainly resulting from a $58.7 million impairment chargenature of the stored material or specialized handling requirements.

Independent terminal owners generally compete on the Axeon Term Loan in 2016, was offset by increased interest expense, increased general and administrative expenses and decreased segment operating income.


Segment Operating Highlights
(Thousands of Dollars, Except Barrel/Day Information)
 Year Ended December 31,  
 2017 2016 Change
Pipeline:     
Refined products pipelines throughput (barrels/day)516,736
 535,946
 (19,210)
Crude oil pipelines throughput (barrels/day)583,323
 392,181
 191,142
Total throughput (barrels/day)1,100,059
 928,127
 171,932
Throughput revenues$516,288
 $485,650
 $30,638
Operating expenses156,432
 147,858
 8,574
Depreciation and amortization expense128,061
 89,554
 38,507
Segment operating income$231,795
 $248,238
 $(16,443)
      
Storage:     
Throughput (barrels/day)325,194
 789,065
 (463,871)
Throughput terminal revenues$85,927
 $117,586
 $(31,659)
Storage terminal revenues531,026
 492,456
 38,570
Total revenues616,953
 610,042
 6,911
Operating expenses270,041
 276,578
 (6,537)
Depreciation and amortization expense127,473
 118,663
 8,810
Segment operating income$219,439
 $214,801
 $4,638
      
Fuels Marketing:     
Product sales and other revenue$692,884
 $681,934
 $10,950
Cost of product sales660,844
 645,355
 15,489
Gross margin32,040
 36,579
 (4,539)
Operating expenses26,057
 33,173
 (7,116)
Segment operating income$5,983
 $3,406
 $2,577
      
Consolidation and Intersegment Eliminations:     
Revenues$(12,106) $(20,944) $8,838
Cost of product sales(9,245) (11,702) 2,457
Operating expenses(2,860) (9,242) 6,382
Total$(1) $—
 $(1)
      
Consolidated Information:     
Revenues$1,814,019
 $1,756,682
 $57,337
Cost of product sales651,599
 633,653
 17,946
Operating expenses449,670
 448,367
 1,303
Depreciation and amortization expense255,534
 208,217
 47,317
Segment operating income457,216
 466,445
 (9,229)
General and administrative expenses112,240
 98,817
 13,423
Other depreciation and amortization expense8,698
 8,519
 179
Consolidated operating income$336,278
 $359,109
 $(22,831)


Pipeline
Total revenues increased $30.6 million and total throughputs increased 171,932 barrels per day for the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to:
an increase in revenues of $42.6 million and an increase in throughputs of 192,958 barrels per day from our Permian Crude System acquired in May 2017;
an increase in revenues of $5.5 million and an increase in throughputs of 2,929 barrels per day due to maintenance downtime in 2016 on a portionbasis of the Ammonia Pipeline,location and versatility of terminals, service and price. A favorably located terminal will have access to various cost-effective transportation modes both to and from the terminal. Transportation modes typically include waterways, railroads, roadways and pipelines.

Terminal versatility is a function of the operator’s ability to offer complex handling requirements for diverse products. The services typically provided by the terminal include, among other things, the safe storage of the product at specified temperature, moisture and other conditions, as well as operational issues in 2016receipt at certain plants servedand delivery from the terminal, all of which must comply with applicable environmental regulations. A terminal operator’s ability to obtain attractive pricing is often dependent on the quality, versatility and reputation of the facilities owned by the pipeline; and
an increase in revenues of $3.4 million, despite a decrease in throughputs of 4,129 barrels per day, on our East Pipeline dueoperator. Operators with versatile storage capabilities typically require less modification prior to usage, ultimately making the storage cost to the completion of various storage projects alongcustomer more attractive. On the pipeline, as well as anWest Coast, regulatory priorities continue to increase demand for renewable fuels in long-haul deliveries resulting in higher average tariffs. A turnaround and operational issuesthe region, while at the same time, obtaining permits for greenfield projects remains difficult, which both add more value to our existing assets.

Our crude oil refinery storage tanks are physically integrated with and serve refineries servedowned by Valero Energy, and we have entered into various agreements with Valero Energy governing the East Pipeline in 2017 contributeduse of these tanks. As a result, we believe that we will not face significant competition for our services provided to those refineries.

Results of Operations
Point Tupper Terminal Disposition. In the decrease in throughputs.

These increases in revenues and throughputs were partially offset by:
a decrease in revenues of $10.4 million and a decrease in throughputs of 16,839 barrels per day due to a turnaround in the fourthfirst quarter of 2017 at the refinery served by our McKee System pipelines;
2022, we recognized a decrease in revenuesnon-cash pre-tax impairment loss of $6.8$46.1 million and a decrease in throughputs of 15,561 barrels per day on our Eagle Ford System, mainly duerelated to reduced production in this sustained low crude oil price environment; and
a decrease in revenues of $4.8 million and a decrease in throughputs of 6,905 barrels per day due to a turnaround in the second quarter of 2017 at the refinery served by the North Pipeline.
Operating expenses increased $8.6 million for the year ended December 31, 2017, compared to the year ended December 31, 2016. Operating expenses increased $9.9 million as a result of our acquisition of the Permian Crude System, which was partially offset by a decrease of $2.1 million from product imbalances on the East Pipeline.
Depreciation and amortization expense increased $38.5 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, due to our acquisition of the Permian Crude System and the completion of various pipeline projects.

Storage
Beginning January 1, 2017, our agreements for our refinery crude storage tanks at Corpus Christi, TX, Texas City, TX and Benicia, CA changed from throughput-based to storage-based. Excluding the effect of the change to these agreements, throughput terminal revenues would have increased $9.5 million and throughputs would have increased 14,360 barrels per day for the year ended December 31, 2017, compared to the year ended December 31, 2016. Throughput terminal revenues increased at our Corpus Christi North Beach terminal by $15.1 million due to an increase in throughputs of 26,359 barrels per day, mainly resulting from the Martin Terminal Acquisition. The benefit of the Martin Terminal Acquisition was partially offset by lower revenues and throughputs resulting from a decrease in Eagle Ford Shale crude oil being shipped to Corpus Christi due to reduced production in this sustained low crude oil price environment. Throughputs increased 16,309 barrels per day, despite only a slight increase in revenues of $0.3 million, at our Central West Terminals, mainly due to a new customer contract and increased marine activity, mostly offset by decreased revenues from ancillary services. These increases in revenues and throughputs were partially offset by decreased revenues of $5.8 million and decreased throughputs of 28,308 barrels per day at our Paulsboro, NJ terminal as a customer diverted barrels to other terminals.

Storage terminal revenues would have decreased $0.6 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, excluding the effect of the change to the refinery storage tank agreements described above. Revenues at our Gulf Coast Terminals decreased $19.2 million, mainly at our St. James, LA terminal due to reduced unit train activity and at our Texas City, TX terminal as a result of the exit from our heavy fuels trading operations. These decreases were partially offset by increases in revenues of $8.2 million at our North East Terminals and $4.5 million at our West Coast Terminals, mainly due to new customer contracts and rate escalations.

Storage terminal revenues also increased $5.5 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, at our International Terminals. Revenues increased $10.2 million at our St. Eustatius terminal, mainly due to new customer contracts and rate escalations, partially offset by lower throughput and associated handling fees as a result of the temporary shutdown of the terminal and damage caused by hurricane activity in the third quarter of 2017. This increase was partially offset by a decrease in revenues of $4.2 million at our Point Tupper terminal mainly resulting from a decrease in customer base, tanks out of service and lower reimbursable revenues.


Operating expenses decreased $6.5 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to:
a decrease of $8.7 million in maintenance and regulatory expenses, primarily at our St. Eustatius, North East andfacility, which was sold on April 29, 2022 (the Point Tupper terminals; and
a decrease of $6.1 million in reimbursable expenses, mainly at our Texas City, TX and Point Tupper terminals, consistent with the decrease in reimbursable revenues;

These decreases were partially offset by increased operating expenses of $8.5 million as a result of the Martin Terminal Acquisition.

Depreciation and amortization expense increased $8.8 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, due to the Martin Terminal Acquisition and other various projects.

Fuels Marketing
Segment operating income increased $2.6 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to a reduction in losses of $9.1 million from our heavy fuels trading operations following our exit of that business in 2017. Segment operating income from our bunker fuel operations at our St. Eustatius terminal decreased $6.4 million, resulting from lower gross margins and the temporary shutdown of the terminal caused by hurricane activity in the third quarter of 2017.

Consolidation and Intersegment Eliminations
Revenue and operating expense eliminations primarily relate to storage fees charged to the fuels marketing segment by the storage segment. Cost of product sales eliminations represent expenses charged to the fuels marketing segment for costs associated with inventory that are expensed once the inventory is sold.

General
General and administrative expenses increased $13.4 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to transaction costs related to the Navigator Acquisition.
Interest expense, net increased $34.7 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, mainly due to the issuance of $550.0 million of 5.625% senior notes in April 2017 and as a result of fees for a bridge loan commitment to potentially assist with the financing of the Navigator Acquisition. We did not enter into or borrow under the bridge loan. Interest expense, net also increased as a result of lower interest income due to the termination of the Axeon Term Loan in February 2017. Please refer toDisposition). See Note 74 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for afurther discussion of the Axeon Term Loan and related credit support.this disposition.
For the year ended December 31, 2017, we recorded other expense, net
16

Income tax expense decreased $2.0 millionThe following table presents operating highlights for the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to reductions in withholding taxes related to certain of our foreign subsidiaries. This decrease was partially offset by increased tax expense resulting from the enactment of the Tax Cuts and Jobs Act in December 2017 (the Act), pursuant to which we recorded a one-time mandatory tax on previously deferred earnings of certain foreign subsidiaries. Please refer to Note 24 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion on income taxes, including the impact of the Act.storage segment:

 Year Ended December 31, 
 20232022Change
(Thousands of Dollars, Except Barrel Data)
Storage Segment:
Throughput (barrels/day)448,331 480,129 (31,798)
Throughput terminal revenues$104,495 $110,591 $(6,096)
Storage terminal revenues215,104 223,958 (8,854)
Total revenues319,599 334,549 (14,950)
Operating expenses156,938 154,270 2,668 
Depreciation and amortization expense75,052 73,076 1,976 
Impairment loss— 46,122 (46,122)
Segment operating income$87,609 $61,081 $26,528 


Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
Financial Highlights
(Thousands of Dollars, Except Unit and Per Unit Data)
 Year Ended December 31,  
 2016 2015 Change
Statement of Income Data: 
Revenues:     
Service revenues$1,083,165
 $1,114,153
 $(30,988)
Product sales673,517
 969,887
 (296,370)
Total revenues1,756,682
 2,084,040
 (327,358)
      
Costs and expenses:     
Cost of product sales633,653
 907,574
 (273,921)
Operating expenses448,367
 473,031
 (24,664)
General and administrative expenses98,817
 102,521
 (3,704)
Depreciation and amortization expense216,736
 210,210
 6,526
Total costs and expenses1,397,573
 1,693,336
 (295,763)
      
Operating income359,109
 390,704
 (31,595)
Interest expense, net(138,350) (131,868) (6,482)
Other (expense) income, net(58,783) 61,822
 (120,605)
Income from continuing operations before income tax expense161,976
 320,658
 (158,682)
Income tax expense11,973
 14,712
 (2,739)
Income from continuing operations150,003
 305,946
 (155,943)
Income from discontinued operations, net of tax—
 774
 (774)
Net income$150,003
 $306,720
 $(156,717)
Basic and diluted net income per common unit:    

Continuing operations$1.27
 $3.29
 $(2.02)
Discontinued operations—
 0.01
 (0.01)
Total$1.27
 $3.30
 $(2.03)
Basic weighted-average common units outstanding78,080,484
 77,886,078
 194,406

Annual Overview
Net income decreased $156.7 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to a $58.7 million impairment charge on the Axeon Term Loan in 2016 and a $56.3 million gain associated with the Linden Acquisition in 2015. In addition, segment operating income decreased $35.3 million, resulting mainly from reductions in operating income for the pipeline and fuels marketing segments.


Segment Operating Highlights
(Thousands of Dollars, Except Barrel/Day Information)
 Year Ended December 31,  
 2016 2015 Change
Pipeline:     
Refined products pipelines throughput (barrels/day)535,946
 522,146
 13,800
Crude oil pipelines throughput (barrels/day)392,181
 471,632
 (79,451)
Total throughput (barrels/day)928,127
 993,778
 (65,651)
Throughput revenues$485,650
 $508,522
 $(22,872)
Operating expenses147,858
 153,222
 (5,364)
Depreciation and amortization expense89,554
 84,951
 4,603
Segment operating income$248,238
 $270,349
 $(22,111)
      
Storage:     
Throughput (barrels/day)789,065
 899,606
 (110,541)
Throughput terminal revenues$117,586
 $130,127
 $(12,541)
Storage terminal revenues492,456
 494,781
 (2,325)
Total revenues610,042
 624,908
 (14,866)
Operating expenses276,578
 290,322
 (13,744)
Depreciation and amortization expense118,663
 116,768
 1,895
Segment operating income$214,801
 $217,818
 $(3,017)
��     
Fuels Marketing:     
Product sales and other revenue$681,934
 $976,216
 $(294,282)
Cost of product sales645,355
 922,906
 (277,551)
Gross margin36,579
 53,310
 (16,731)
Operating expenses33,173
 39,803
 (6,630)
Segment operating income$3,406
 $13,507
 $(10,101)
      
Consolidation and Intersegment Eliminations:     
Revenues$(20,944) $(25,606) $4,662
Cost of product sales(11,702) (15,332) 3,630
Operating expenses(9,242) (10,316) 1,074
Total$—
 $42
 $(42)
      
Consolidated Information:     
Revenues$1,756,682
 $2,084,040
 $(327,358)
Cost of product sales633,653
 907,574
 (273,921)
Operating expenses448,367
 473,031
 (24,664)
Depreciation and amortization expense208,217
 201,719
 6,498
Segment operating income466,445
 501,716
 (35,271)
General and administrative expenses98,817
 102,521
 (3,704)
Other depreciation and amortization expense8,519
 8,491
 28
Consolidated operating income$359,109
 $390,704
 $(31,595)


Pipeline
TotalThroughput terminal revenues decreased $22.9$6.1 million, and total throughputs decreased 65,65131,798 barrels per day for the year ended December 31, 2016,2023, compared to the year ended December 31, 2015,2022, primarily due to:
to a decrease in revenues of $36.3$13.2 million and a decrease in throughputs of 81,779 barrels per day on our Eagle Ford System due to reduced production resulting from a sustained low crude oil price environment;
a decrease in revenues of $7.1 million and a decrease in throughputs of 6,586 barrels per day on our Ammonia Pipeline partly due to a shipper’s facility reconfiguration, resulting in fewer barrels available for transportation, and maintenance downtime on a portion of the pipeline; and
a decrease in revenues of $3.9 million and a decrease in throughputs of 1,551 barrels per day on our Ardmore System due to operational issues and a turnaround at our customer’s Ardmore refinery in 2016, as well as increased short-haul deliveries resulting in lower average tariffs.

Those decreases in pipeline revenues and throughputs were partially offset by:
an increase in revenues of $12.1 million and an increase in throughputs of 14,803 barrels per day on our McKee and Three Rivers System pipelines due to higher demand in those markets, increased production at our customer’s McKee refinery and increased volumes on pipelines with higher average tariffs;
an increase in revenues of $9.6 million and an increase in throughputs of 11,441 barrels per day on our East Pipeline, mainly due to the completion of various expansion projects beginning in the fourth quarter of 2015, unfavorable pricing differentials in 2015 in markets served by the East Pipeline and lower throughputs in 2015 due to maintenance downtime on a portion of the pipeline; and
an increase in revenues of $3.4 million and an increase in throughputs of 1,392 barrels per day on our North Pipeline due to increased refinery production shipped via pipeline and increased long-haul deliveries resulting in higher average tariffs.
Operating expenses decreased $5.4 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to lower operating expenses of $8.7 million on our Eagle Ford System, consistent with the decrease in throughputs. The decrease in pipeline operating expenses was partially offset by higher maintenance and regulatory expenses of $3.2 million, mainly on our Central West Refined Products Pipelines.
Depreciation and amortization expense increased $4.6 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, mainly due to the completion of pipeline projects.

Storage
Throughput terminal revenues decreased $12.5 million and throughputs decreased 110,541 barrels per day for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to:
a decrease in revenues of $10.9 million and a decrease in throughputs of 82,17751,361 barrels per day at our Corpus Christi North Beach terminal, due to (i)unfavorable market conditions and changes to a decrease in Eagle Ford Shale crude oil being shipped to Corpus Christi, consistent with the decrease in pipeline throughputs and (ii) the completion of a pipeline expansion project in the first quarter of 2016, in which we transport volumes from North Beach to our customer’s refineries, thus reducing volumes moved over our docks; and
a decrease in revenues of $3.3 million and a decrease in throughputs of 35,497 barrels per day due to turnarounds at the refineries served by our Benicia and Corpus Christi crude oil storage tank facilities, as well as operational issues at a customer’s Corpus Christi refinery in 2016.

Thecustomer contract. These decreases were partially offset by an increase in revenuerevenues of $3.0$7.1 million and an increase in throughputs of 9,04419,563 barrels per day at our McKee and Three Rivers System terminalsCentral West Terminals, primarily due to higher demand in those markets, as well as increased production at our customer’s McKee refinery.demand.


Storage terminal revenues decreased $2.3$8.9 million for the year ended December 31, 2016,2023, compared to the year ended December 31, 2015. Revenues from our International Terminals decreased $17.7 million,2022, primarily due to a decrease in revenues at our St. Eustatius terminal of $8.3 million, resulting mainly from lower throughput and related handling fees, as well as to:
•a decrease in revenues of $5.9$29.7 million at our UK Terminals, mainlySt. James terminal due to fluctuationscustomers not renewing expiring contracts in foreign exchange rates. the current backwardated market; and
•a decrease in revenues of $9.6 million due to the Point Tupper Terminal Disposition in April 2022.

These decreases were partially offset by the following:
•an increase in revenues of $15.3$26.4 million in domestic revenues. Domestic revenues increased $10.1 million fromat our West Coast Terminals, primarily due to new contracts and rate escalations across various terminals, combined with higher throughput and new customer contractshandling fees, mainly at our Selby, CA, Linden, NJ, Blue Island, ILStockton terminal; and Piney Point, MD terminals. In addition,
•an increase in revenues at our St. James, LA terminal increased $3.1of $4.3 million, primarily due to completed terminal expansion projects.

Operating expenses decreased $13.7 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to:
a decrease of $11.8 million in operating expenses at our International Terminals, mainly at our St. Eustatius terminal facility due to higher property taxes in 2015, and lower employee related costs and reimbursable expenses in 2016;
a decrease of $3.1 million resulting from an insurance settlement for environmental remediation expenses incurred on a previously sold terminal; and
a decrease of $2.0 million resulting from lower wharfage and dockage costs at our Corpus Christi North Beach terminal.

The decreases in storage operating expenses were partially offset by a $3.9 million increase in regulatory and maintenance expenses mainlyrate escalations at our Central West terminal facilitiesTerminals and $1.6 million in cancelled capital project costs.at our refinery storage tanks.


Fuels Marketing
Segment operating income decreased $10.1 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to a decrease in gross margin of $7.9 million and $6.6 million from our fuel oil trading and bunker fuel operations, respectively. The lower gross margins were partially offset by a reduction in operatingOperating expenses of $6.6 million mainly from our bunker fuel operations due to lower bad debt expense and decreased product inspection and marine vessel costs.

Consolidation and Intersegment Eliminations
Revenue and operating expense eliminations primarily relate to storage fees charged to the fuels marketing segment by the storage segment. Cost of product sales eliminations represent expenses charged to the fuels marketing segment for costs associated with inventory that are expensed once the inventory is sold.

General
General and administrative expenses decreased $3.7 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to a decrease in employee benefit costs which was partially offset by increased compensation expense associated with our long-term incentive plan.
Interest expense, net increased $6.5 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to increased interest costs associated with higher borrowings under our revolving credit agreement, as well as lower capitalized interest resulting from fewer capital projects.
For the year ended December 31, 2016, we recorded other expense, net of $58.8 million, mainly due to an impairment charge of $58.7 million recognized on the Axeon Term Loan. For the year ended December 31, 2015, we recorded other income, net of $61.8 million, mainly due to the $56.3 million gain associated with the Linden Acquisition.
Income tax expense decreased $2.7 million for the year ended December 31, 2016,2023, compared to the year ended December 31, 2015,2022, primarily due to the following:
•an increase in maintenance and regulatory expenses of $3.1 million, across various terminals;
•an increase of $2.8 million in ad valorem taxes due to higher property valuations;
•increases in reimbursable and other expenses of $2.5 million that have corresponding increases in revenue, primarily at our West Coast Terminals, partially offset by lower reimbursable expenses at our St. James terminal; and
•an increase of $1.8 million at our Corpus Christi North Beach terminal due to changes in a customer contract.

These increases were partially offset by a decrease in operating expenses of $7.9 million due to the sale of our Point Tupper Terminal Operations during the second quarter of 2022.

Depreciation and amortization expense increased $2.0 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to expansion projects at our West Coast Terminals.

17

FUELS MARKETING SEGMENT
Our fuels marketing segment sells petroleum products primarily through our bunkering operations in the Gulf Coast and certain of our blending operations associated with our Central East System. The results of operations for the fuels marketing segment depend largely on the margin between our costs and the sales prices of the products we market. Therefore, the results of operations for this segment are more sensitive to changes in commodity prices compared to the operations of the pipeline and storage segments. We enter into derivative contracts to attempt to mitigate the effects of commodity price fluctuations. The financial impacts of the derivative financial instruments associated with commodity price risk were not material for any periods presented. Fluctuations in global demand for crude oil, which was caused by many economic factors outside of our control, has caused volatility in commodity prices and volumes for our blending operations and bunker fuel sales in 2022 and 2023.

Competition and Customers
In the sale of bunker fuel, we compete with ports offering bunker fuels that are along the route of travel of the vessel. Customers for bunker fuel sales are primarily ship owners, marketers and traders. One of our customers, a marketer of petroleum products, was the largest customer of our fuels marketing segment and accounted for approximately 11% of the total segment revenues for the year ended December 31, 2023. No other customer accounted for a significant portion of the total revenues of the fuels marketing segment for the year ended December 31, 2023.
Results of Operations
The following table presents operating highlights for the fuels marketing segment:
 Year Ended December 31, 
 20232022Change
(Thousands of Dollars)
Fuels Marketing Segment:
Product sales$440,725 $520,486 $(79,761)
Cost of goods405,992 484,477 (78,485)
Gross margin34,733 36,009 (1,276)
Operating expenses1,807 2,473 (666)
Segment operating income$32,926 $33,536 $(610)

Product sales decreased $79.8 million, and cost of goods decreased $78.5 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to lower fuel prices for our bunkering operations. Gross margin taxdecreased $1.3 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, as a decrease of $2.8 million in Texas,gross margin from our bunkering operations and a decrease of $2.8 million in gross margin from other product sales more than offset higher blending gross margins of $4.3 million, all primarily due to lower fuel prices.

Segment operating income decreased $0.6 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, due to the changes in gross margins described above, partially offset by a decrease in the UK tax rate and a reduction in our St. Eustatius and Canada withholding tax. Please refer to Note 24operating expenses of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion on income taxes.


TRENDS AND OUTLOOK
As discussed in more detail in Note 28 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data,” we and NuStar GP Holdings entered into the Merger Agreement to simplify our corporate structure. At the closing of the Merger, which is subject to, among other things, approval of the NSH unitholders: (i) NuStar Energy will issue 0.55 of an NS common unit for each outstanding NSH unit; (ii) NSH’s economic rights in the 2% general partner interest, the incentive distribution rights (the IDRs) in NS and the NS common units held by NSH will be cancelled; and (iii) NS will pay off and cancel NSH’s obligations under its revolving credit agreement.

We believe simplifying our corporate structure and eliminating the IDRs will lower our cost of capital and create a more efficient and transparent structure. In addition, management anticipates recommending, and the NuStar Energy board of directors indicated it intends to approve, resetting NuStar Energy’s quarterly distribution from $1.095 per common unit to $0.60 per common unit, effective with the first quarter 2018 distribution. We expect that resetting our distribution will improve our ability to fund cash requirements immediately, and, in the longer-term, will also serve to improve our leverage metrics and reduce our future need to access the capital markets.

Historically, master limited partnerships (MLPs), like NuStar Energy, have typically funded strategic capital expenditures and acquisitions from external sources,$0.7 million, primarily through borrowings under revolving credit agreements and issuance of equity and debt securities. In the past few years, the total number of, and aggregate amount raised by, MLP common equity issuances has dropped dramatically, and MLPs with low coverage and high leverage have found it increasingly difficult to issue common equity. Through the combination of the simplification and distribution reset discussed above, we expect to be able to fund a larger proportion of our capital projects with the cash generated by our operations, which should, over time, reduce our need to access capital markets to finance future growth opportunities.

During 2017, our legacy pipeline systems and storage assets, other than our Permian Crude System, faced several unanticipated challenges, on top of the continuing burden of the third year of sustained low crude prices. In September, hurricanes caused damage in the Gulf of Mexico and significant destruction in the Caribbean. Hurricane Harvey’s heavy rainfall caused only minimal damagerelated to our six affected Gulf Coast facilities, but Hurricane Irma passed almost directly over our facility at St. Eustatius, causing a temporary shutdown and inflicting substantial damage. We received hurricane insurance proceeds of $12.5 million in the fourth quarter of 2017 and $87.5 million in January 2018. We expect to recognize a gain in our first quarter 2018 results equal to the amount by which the insurance proceeds received exceed our actual expense incurred during the period, or approximately $85 million. At this time, we expect that costs incurred, over and above our deductible amount, will be covered by the insurance proceeds we have already received. We expect these repairs to continue through next year and into 2020.bunkering operations.


Due to that fact that some of our current committed shippers’ contracts on our South Texas Crude System expire in the second half of 2018, as well as our assessment of the current market conditions in the Eagle Ford, our 2018 forecast reflects our expectation that some of those customers will decline to renew their commitments and demand rates lower than previously contracted rates. As a result, we are projecting lower throughput and rates for the South Texas Crude System in the second half of 2018, which we expect to result in lower revenues for that system during 2018 as compared to 2017.

Since we agree with the many energy experts who currently predict that backwardation, which tends to decrease demand for storage capacity, will continue through 2018, our 2018 forecast reflects lower storage rates and contract renewals at certain of our facilities, which we expect to result in lower revenues for those facilities during 2018 as compared to 2017.

In January 2018, as a result of the widely reported economic strife in Venezuela and the mounting financial and operational challenges facing our St. Eustatius anchor tenant, Petróleos de Venezuela, S.A. (PDVSA), we reduced our expectations for their utilization of the terminal during 2018 to reflect a more conservative outlook. In 2017 and this year so far, news outlets around the world have reported the dramatic deterioration of economic conditions in Venezuela, and during 2017, we saw PDVSA’s activity at the terminal decrease to levels well below their historical levels. In addition, in August 2017, the United States imposed sanctions against Venezuela intended to limit PDVSA’s access to credit, and the Trump Administration has announced it may also ban imports of Venezuelan crude into the U.S. and export of U.S. refined products to Venezuela. If implemented, these additional sanctions, together with the current sanctions, could have a significant negative impact on Venezuela and on PDVSA.

Largely due to the impact we believe those negative factors may have on PDVSA and their utilization of our facility, our current forecast reflects our expectation that our 2018 results of operations of our storage segment will be lower than 2017 and that it properly reflects our conservative assessment of significant uncertainty and risk surrounding PDVSA’s ability to perform this year. That being said, since early January PDVSA’s activity at the terminal has increased, and, if they are able to continue this trend through all or a portion of the year, all other factors remaining constant, we could see improvement in our revenue generated for St. Eustatius, in comparison with our current forecast for 2018, as the year progresses. While we are hopeful that

PDVSA will maintain its current activity and we continue to work to retain them as an important customer, we also continue to closely monitor PDVSA’s activity and financial well-being and are working to diversify our St. Eustatius facility customer base.

While our outlook for 2018 reflects all the challenges we have described, we believe that the consummation of the Merger and our board of director’s approval of our recommended reset to our distribution will immediately increase our cash available to pay for capital expenditures, and, over time, will improve our leverage metrics. We expect these steps to strengthen our balance sheet in 2018 and beyond. We also project that the Permian Crude System will continue to grow, and we expect its positive contributions to our pipeline segment’s overall results to grow accordingly.

Our outlook for the partnership, both overall and for any of our segments, may change, as we base our expectations on our continuing evaluation of a number of factors, many of which are outside our control. These factors include, but are not limited to, the state of the economy and the capital markets, changes to our customers’ refinery maintenance schedules and unplanned refinery downtime, crude oil prices, the supply of and demand for crude oil, refined products and anhydrous ammonia, demand for our transportation and storage services and changes in laws or regulations affecting our assets.









































LIQUIDITY AND CAPITAL RESOURCES


The following sections are included in Liquidity and Capital Resources:
•Overview
•Cash Flows
•Sources of Liquidity
•Material Cash Requirements

OVERVIEW
Our primary cash requirements are forinclude distributions to our limited partners, debt service, capital expenditures acquisitions and operating expenses.

Our partnership agreement requires that we distribute all “Available Cash”Available Cash (as defined in our partnership agreement) to our common limited partners and general partner each quarter, and this termquarter. Available Cash is generally defined in the partnership agreement generally as all cash on hand at the end of the quarter, plus certain permitted borrowings made subsequent to the end of the quarter,receipts less cash disbursements, including distributions to our preferred unit holders, and cash reserves determinedestablished by our board of directors. After the Merger, our general partner, will no longer receive incentive distributions or quarterly cash distributions, related toin its ownership interest, from us. Additionally, on February 8, 2018, we announced that our management anticipates recommending to the board of directors of NuStar GP, LLC, and the board of directors expects to adopt, a reset of our quarterly distribution per common unit to $0.60 ($2.40 on an annualized basis), starting with the first-quarter distribution payable in May 2018. Please refer to Note 28 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the Merger.

Each year, our objective is to fund our reliability capital expenditures and distribution requirements with our net cash provided by operating activities during that year. If we do not generate sufficient cash from operations to meet that objective, we utilize cash on hand or other sources of cash flow, which in the past have primarily included borrowings under our revolving credit agreement, sales of non-strategic assets and, to the extent necessary, funds raised through equity or debt offerings under our shelf registration statements.sole discretion. We have typically funded our strategic capital expenditures and acquisitions from external sources, primarily borrowings under our revolving credit agreement or funds raised through equity or debt offerings. However, our ability to raise funds by issuing debt or equity depends on many factors beyond our control. Our risk factors in Item 1A. “Risk Factors” describe the risks inherent to these sources of funding and the availability thereof.

During periods when our cash flow from operations is less than our distribution and reliability capital requirements, we may maintain our distribution level because we can usewith other sources of Available Cash, as provided in our partnership agreement, including borrowings under our revolving credit agreementRevolving Credit Agreement and proceeds from the salessale of assets. Our risk factors
18

In the first quarter of 2023, we completed the Sale-Leaseback Transaction for $103.0 million, and in Item 1A. “Risk Factors” describe the risks inherentthird quarter of 2023, we issued 14,950,000 common units for net proceeds of approximately $222.0 million. We used the proceeds from these transactions to repay outstanding borrowings under our Revolving Credit Agreement, which facilitated the redemption of 16,346,650 of the Series D Preferred Units, representing all outstanding Series D Preferred Units. Additionally, in the second quarter of 2023, we extended the maturity date on our Revolving Credit Agreement to January 27, 2027, and extended the scheduled termination date on our Receivables Financing Agreement to July 1, 2026. Similarly, in 2022, we had reduced our leverage to position ourselves to repurchase 6,900,000 of the Series D Preferred Units in November 2022, representing approximately one-third of the outstanding units at that time, using borrowings under our Revolving Credit Agreement.

As illustrated in the chart below, in 2023 and 2022, we funded all our expenses, distribution requirements and capital expenditures using cash from operating activities.
Sources and Uses - 2-1-2024 - FINAL.jpg

For the full-year 2024, we expect to fund all our expenses, distribution requirements and capital expenditures using internally generated cash flows. We have no long-term debt maturities until 2025.
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CASH FLOWS
A discussion of our cash flows and other changes in financial position for 2021 can be found in Items 1., 2. and 7. “Business, Properties and Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our ability to maintain or grow our distribution.

ForAnnual Report on Form 10-K for the year ended December 31, 2017, our cash flow from operations did not exceed our distributions to our partners and our reliability capital expenditures. See below for discussion. For 2018, we expect to generate sufficient cash from operations to exceed our distribution and reliability capital requirements. Although we expect higher interest costs due to our issuances of debt and equity securities in 2017, we expect a decrease in distributions as a result of2022 filed with the distribution reset and the Merger discussed above. See below for additional discussion of our 2017 equity and debt issuances.SEC on February 23, 2023.

Cash Flows for the Years Ended December 31, 2017, 2016 and 2015
The following table summarizes our cash flows from operating, investing and financing activities (please refer to(see also our Consolidated Statements of Cash Flows in Item 8. “Financial Statements and Supplementary Data”):.
 Year Ended December 31,
 20232022
(Thousands of Dollars)
Net cash provided by (used in):
Operating activities$514,269 $527,549 
Investing activities(23,240)(84,365)
Financing activities(502,430)(434,953)
Effect of foreign exchange rate changes on cash40 707 
Net (decrease) increase in cash, cash equivalents and restricted cash$(11,361)$8,938 
 Year Ended December 31,
 2017 2016 2015
 (Thousands of Dollars)
Net cash provided by (used in):     
Operating activities$406,799
 $436,761
 $524,937
Investing activities(1,696,441) (311,078) (452,029)
Financing activities1,276,272
 (211,324) (29,229)
Effect of foreign exchange rate changes on cash1,720
 2,721
 (12,729)
Net (decrease) increase in cash and cash equivalents$(11,650) $(82,920) $30,950

Net cash provided by operating activities for the year ended December 31, 2017 was $406.8 million, compared to $436.8decreased $13.3 million for the year ended December 31, 2016, primarily due2023, compared to changesthe year ended December 31, 2022. The increase in working capital. Ournet income of $50.9 million was more than offset by noncash adjustments to reconcile to net cash provided by operating activities. In addition, our working capital increaseddecreased by $26.5$10.6 million for the year ended December 31, 2017, compared to a decrease of $3.72023 and $0.7 million for the year ended December 31, 2016. Please refer to2022. Generally, working capital requirements are affected by our accounts receivable, accounts payable and accrued liability balances, which vary depending on the “Working Capital Requirements” section belowtiming of payments.

Net cash used in investing activities decreased $61.1 million for a discussion of the changes in working capital.
For the year ended December 31, 2017, net cash provided by operating activities, the proceeds from the termination of the Axeon Term Loan of $110.0 million and cash on hand were used2023, compared to fund our distributions to unitholders and our general partner in the aggregate amount of $485.1 million and reliability capital expenditures of $57.5 million. Proceeds from our debt and

equity issuances of approximately $1.5 billion were used to fund the purchase price of the Navigator Acquisition. The proceeds from debt borrowings, net of repayments, remaining proceeds from our equity issuances and cash on hand were used to fund our other strategic capital expenditures.

For the year ended December 31, 2016, net cash provided by operating activities2022, primarily was useddue to fund our distributions to
unitholders and our general partnerproceeds of approximately $103.0 million from the Sale-Leaseback Transaction in the aggregate amountfirst quarter of $393.02023, compared to proceeds from asset sales of $59.3 million and reliability capital expenditures of $38.2
million. Proceeds from the issuance of common and preferred units and cash on hand were used to fund our strategic capital expenditures, including the Martin Terminal Acquisition.
Forin 2022. Additionally, for the year ended December 31, 2015,2023 compared to the majorityyear ended December 31, 2022, cash outflows related to capital expenditures decreased an aggregate $14.9 million. Investing activities also include insurance proceeds of net$12.4 million for the year December 31, 2023, compared to insurance proceeds of $9.8 million for the December 31, 2022, both related to the 2019 Selby terminal fire.

Net cash providedused in financing activities increased $67.5 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to the redemption of the outstanding Series D Preferred Units for $518.7 million in 2023, compared to the repurchase of outstanding Series D Preferred Units for $222.4 million in 2022, partially offset by operating activities was used to fund our distributions to unitholders and our general partnerthe issuance of common units in the aggregate amountthird quarter of $392.2 million and to fund $40.0 million of reliability capital expenditures. The proceeds from debt borrowings, net of repayments, combined with a portion of net cash provided by operating activities, were used to fund our strategic capital expenditures, including the Linden Acquisition.2023 for approximately $222.0 million.
Debt Sources of Liquidity
SOURCES OF LIQUIDITY
Revolving Credit Agreement.On August 22, 2017, NuStar Logistics amended its revolving credit agreement (the Revolving Credit Agreement), mainly to extend the maturity date from October 29, 2019 to October 29, 2020, and to increase the borrowing capacity from $1.50 billion to $1.75 billion. TheAgreement
As of December 31, 2023, our Revolving Credit Agreement includeshad $652.4 million available for borrowing and $343.0 million of borrowings outstanding. Letters of credit issued under our Revolving Credit Agreement totaled $4.6 million as of December 31, 2023 and limit the ability toamount we can borrow up to the equivalent of $250.0 million in Euros and up to the equivalent of $250.0 million in British Pounds Sterling.under our Revolving Credit Agreement. Obligations under theour Revolving Credit Agreement are guaranteed by NuStar Energy and NuPOP.


TheOur Revolving Credit Agreement was also amendedis subject to increase the maximum allowed 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, 2023, the Consolidated Debt Coverage Ratio (as defined in the Revolving Credit Agreement) from 5.00-to-1.00 to 5.50-to-1.00 through the rolling period ending March 31, 2018. Subsequently, the maximum allowed consolidated debt coverage ratio may not exceed 5.00-to-1.00 for any rolling period ending on or after June 30, 2018. If we complete one or more acquisitions for aggregate net consideration of at least $50.0 million, our maximum consolidated debt coverage ratio will increase to 5.50-to-1.00 for two rolling periods. On November 22, 2017,and the Consolidated Interest Coverage Ratio (as defined in the Revolving Credit Agreement was amended to continue to exclude our $402.5 million fixed-to-floating rate subordinated notes from the definition of consolidated debt for purposes of calculating our consolidated debt coverage ratio through December 31, 2018. TheAgreement) must not be less than 1.75-to-1.00. Our 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, 2023, our Consolidated Debt Coverage Ratio was 3.85x and our Consolidated Interest Coverage Ratio was 2.18x.


On June 30, 2023, we amended our Revolving Credit Agreement, primarily to extend the maturity date from April 27, 2025 to January 27, 2027. The amendment also includes a requirement notthat we must demonstrate and certify, prior to exceed a maximum consolidated debt coverage ratio may limit the amount we can borrowusing any borrowings under theour Revolving Credit Agreement to an amount less thanredeem certain unsecured indebtedness or prior to their redemption/repurchase, the total amount available for borrowing. AsSeries D Preferred Units, that the sum of December 31, 2017, our consolidated debt coverage ratio was 4.9x and we had $853.0 million available for borrowing.
Letters of credit issued under the Revolving Credit Agreement totaled $3.7availability and unrestricted cash
20

balance is no less than $150.0 million ason a pro forma basis both before and immediately after giving effect to the borrowing and the redemption. On January 28, 2022, we amended and restated our Revolving Credit Agreement to, among other items:
(i) increase the maximum amount of December 31, 2017. Lettersletters of credit are limited tocapable of being issued from $400.0 million (including up to $500.0 million; (ii) replace London Interbank Offering Rate, or LIBOR, benchmark provisions with customary secured overnight financing rate, or SOFR, benchmark provisions; (iii) remove the equivalent0.50x increase permitted in our Consolidated Debt Coverage Ratio for certain rolling periods in which an acquisition for aggregate net consideration of $25.0at least $50.0 million in Eurosoccurs; and up(iv) add baskets and exceptions to the equivalent of $25.0 million in British Pounds Sterling) and also may restrict the amount we can borrow under the Revolving Credit Agreement.certain negative covenants.


Receivables Financing Agreement. Agreement
NuStar Energy and NuStar Finance LLC (NuStar Finance), a special purpose entity and wholly owned subsidiary of NuStar Energy, are parties to a $125.0 million receivables financing agreement with third-party lenders (thethe Receivables Financing Agreement)Agreement with a third-party lender and agreements with certain of NuStar Energy’s wholly owned subsidiaries (collectively(together with the Receivables Financing Agreement, the Securitization Program). On September 20, 2017, the Securitization Program was amended to add certain of NuStar Energy’s wholly owned subsidiaries resulting from the Navigator Acquisition and to extend the Securitization Program’s scheduled termination date from June 15, 2018 to September 20, 2020, with the option to renew for additional 364-day periods thereafter. The amount available for borrowing under the Receivables Financing Agreement is based on the availability of eligible receivables and other customary factors and conditions. The Securitization Program contains various customary affirmative and negative covenants and default, indemnification and termination provisions, and the Receivables Financing Agreement provides for acceleration of amounts owed upon the occurrence of certain specified events.

Issuance On June 29, 2023, we amended the Receivables Financing Agreement to extend the scheduled termination date from January 31, 2025 to July 1, 2026. On January 28, 2022, the Receivables Financing Agreement was amended to, among other items: (i) reduce the floor rate in the calculation of 5.625% Senior Notes. On April 28, 2017, NuStar Logistics issued $550.0 million of 5.625% senior notes due April 28, 2027. We used the net proceeds of $543.3 million from the offering to fund a portion of the purchase price for the Navigator Acquisitionour borrowing rates; and to pay(ii) replace provisions related fees and expenses. Interest on the 5.625% senior notes is payable semi-annually in arrears on April 28 and October 28 of each year beginning on October 28, 2017. The 5.625% senior notes do not have sinking fund requirements. These notes rank equally with existing senior unsecured indebtedness and senior to existing subordinated indebtedness of NuStar Logistics. The 5.625% senior notes contain restrictions on NuStar Logistics’ ability to incur secured indebtedness unless the same security is also provided for the benefit of holders of the senior notes. In addition, the senior notes

limit NuStar Logistics’ ability to incur indebtedness secured by certain liens, engage in certain sale-leaseback transactions and engage in certain consolidations, mergers or asset sales.

Other Debt Sources of Liquidity. Other sources of liquidity consist of the following:
$365.4 million in revenue bonds pursuant to the Gulf Opportunity Zone ActLIBOR rate of 2005 (the GoZone Bonds),interest with $42.5 million remaining in trust asreferences to SOFR rates of December 31, 2017, supported by $370.2 million in letters of credit; andinterest.
two short-term line of credit agreements with an aggregate uncommitted borrowing capacity of up to $85.0 million, with $35.0 million of borrowings outstanding as of December 31, 2017.

Please refer toSee Note 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of our debt agreements.


LOC Agreement
NuStar Logistics is a party to a $100.0 million uncommitted letterIssuance of credit agreement, which provides for standby letters of credit or guarantees with a term of up to one year (LOC Agreement). Any letters of credit issued under the LOC Agreement do not reduce availability under the Revolving Credit Agreement. As of December 31, 2017, we had no letters of credit issued under the LOC Agreement.

Repatriation
We may repatriate a portion of undistributed foreign earnings in order to provide greater flexibility to meet cash flow needs. During the years ended December 31, 2017 and 2016, we repatriated $9.5 million and $110.8 million, respectively, of cash from our foreign subsidiaries. We will continue to evaluate our cash flow needs and may repatriate funds from our foreign subsidiaries as a source of liquidity.

Issuances ofCommon Units
In the fourth quarter of 2017, we issued 6,900,000 of our 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (Series C Preferred Units) representing limited partner interests at a price of $25.00 per unit. We used the net proceeds of $166.7approximately $222.0 million from the issuance of the Series C Preferred Units for general partnership purposes, including the funding of capital expenditures and repayments ofcommon units on August 11, 2023 to repay outstanding borrowings under theour Revolving Credit Agreement.

OnApril 28, 2017, we issued 15,400,000 of our Series B Preferred Units representing limited partner interests at a price of $25.00 per unit. We used the net proceeds of $371.8 million from the issuance of the Series B Preferred Units to fund a portion of the purchase price for the Navigator Acquisition and to pay related fees and expenses.

On April See Note 18 2017, we issued 14,375,000 common units representing limited partner interests at a price of $46.35 per unit. We used the net proceeds from this offering of $657.5 million, including a contribution of $13.6 million from our general partner to maintain its 2% general partner interest, to fund a portion of the purchase price for the Navigator Acquisition. Beginning with the distribution earned for the second quarter of 2017, our general partner will not receive incentive distributions with respect to these common units. Our general partner amended and restated our partnership agreement to waive up to an aggregate $22.0 million of the quarterly incentive distributions to our general partner for any NS common units issued from the date of the Navigator Acquisition agreement (other than those attributable to NS common units issued under any equity compensation plan) for ten consecutive quarters.

In the fourth quarter of 2016, we issued 9,060,000 of our 8.50% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (Series A Preferred Units) representing limited partner interests at a price of $25.00 per unit. We used the net proceeds of $218.4 million from this issuance for general partnership purposes, including the funding of capital expenditures and repayments of outstanding borrowings under the Revolving Credit Agreement.

During the year ended December 31, 2016, we issued 595,050 common units representing limited partner interests at an average price of $47.39 per unit for proceeds of $28.3 million, net of $0.5 million of issuance costs. We used these proceeds, which include a contribution of $0.6 million from our general partner to maintain its 2% general partner interest, for general partnership purposes, including repayments of outstanding borrowings under the Revolving Credit Agreement.

Please refer to Note 19 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional informationinformation.

Asset Sales
We used the proceeds of approximately $103.0 million from the sale of our Corporate Headquarters on March 21, 2023 and approximately $60.0 million from the Point Tupper Terminal Disposition on April 29, 2022 to repay outstanding borrowings under our Revolving Credit Agreement. See Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of these issuances.asset sales.



MATERIAL CASH REQUIREMENTS
Capital RequirementsExpenditures
Our operations require significant investments to maintain, upgrade or enhance the operating capacity of our existing assets. Our capital expenditures consist of:
•strategic capital expenditures, such as those to expand or upgrade the operating capacity, increase efficiency or increase the earnings potential of existing assets, whether through construction or acquisition, as well as certain capital expenditures related to support functions; and
•reliability capital expenditures, such as those required to maintain the existingcurrent operating capacity of existing assets or extend their useful lives, as well as those required to maintain equipment reliability and safety.


The following table summarizes our capital expenditures:
Strategic Capital ExpendituresReliability Capital ExpendituresTotal
(Thousands of Dollars)
For the year ended December 31:
2023$119,513 $27,995 $147,508 
2022$107,855 $32,775 $140,630 

Strategic capital expenditures for the years ended December 31, 2023 and the amount we expectDecember 31, 2022 primarily consisted of expansion projects on our Permian Crude System and Central West Refined Products Pipelines, and biofuel and other projects at our West Coast Terminals, as well as connection projects on our Ammonia Pipeline in 2023. Reliability capital expenditures primarily related to spend for 2018:maintenance upgrade projects at our terminals and on our Ammonia Pipeline.
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 Strategic    
 Acquisitions and Investments in Other Long-Term Assets Capital Expenditures (a) 
Reliability Capital
Expenditures (b)
 Total
 (Thousands of Dollars)
For the year ended December 31:       
2017$1,461,719
 $327,141
 $57,497
 $1,846,357
2016$95,657
 $166,203
 $38,155
 $300,015
2015$146,064
 $284,806
 $40,002
 $470,872
        
Expected for the year ended December 31, 2018  $ 360,000 - 390,000
 $ 80,000 - 100,000
 $ 440,000 - 490,000
(a)StrategicWe expect our strategic capital expenditures for 2015, 2016 and 2017 mainly consists of terminal expansions. In addition, strategic capital in 2015 includes the reactivation and conversion of our 200-mile pipeline between Mont Belvieu and Corpus Christi, Texas and strategic capital in 2017 includes pipeline expansions on our Permian Crude System.
(b)Reliability capital expenditures primarily relate to maintenance upgrade projects at our terminals.

For the year ended December 31, 2018, we expect a significant portion of2024 to be concentrated on expansion projects to accommodate production growth in the Permian Basin and projects to expand our strategic capital spending to relate to our Permian Crude System and a significant portion of reliability capital spending to relate to hurricane damage repairs at our St. Eustatius facility.renewable fuels network on the West Coast. We continue to evaluate our capital budget and make changes as economic conditions warrant, and our actual capital expenditures for 2018 may increase or decrease from the budgeted amounts. We believe cash on hand, combined with the sources of liquidity previously described, will be sufficient to fund our capital expenditures in 2018, and our internal growth projects can be accelerated or scaled back depending on market conditions or customer demand.
Working Capital Requirements
Working capital requirements, particularly in our fuels marketing segment, may vary withSeries D Preferred Units Redemption and Repurchase
We redeemed or repurchased all the seasonality of demand and the volatility of commodity prices for the products we market. This seasonality in demand and the volatility of commodity prices affect our accounts receivable and accounts payable balances, which vary depending on timing of payments.Series D Preferred Units, as shown below:
TransactionTransaction DateNumber of UnitsPrice per Unit, including Accrued DistributionsTotal Price, including
Accrued Distributions
(Thousands of Dollars)
RedemptionSeptember 12, 20238,286,650$32.59 $270,062 
RedemptionJuly 31, 20232,560,000$32.18 $82,381 
RedemptionJune 30, 20235,500,000$31.88 $175,340 
RepurchaseNovember 22, 20226,900,000$32.73 $225,837 


During the year ended December 31, 2017, accounts payable decreased $30.4 million and inventories decreased $11.9 million, primarily due to our exit from our heavy fuels trading and crude oil marketing operations in 2017.

During the year ended December 31, 2016, accounts receivable increased $23.2 million and accounts payable increased $14.1 million, primarily due to the timing of payments related to our bunker fuel operations and crude oil trading activity.

During the year ended December 31, 2015, inventories decreased $16.8 million, mainly due to the continued decline in crude oil prices. In addition, inventory volumes decreased in 2015 primarily due to decreased bunker fuel operations activity. During the year ended December 31, 2015, accounts receivable decreased $67.3 million and accounts payable decreased $32.2 million, primarily due to decreased bunker fuel operations and crude oil trading activity.

Axeon Term Loan and Credit Support
On February 22, 2017, we settled and terminated the $190.0 million Axeon Term Loan, pursuant to which we also provided credit support, such as guarantees, letters of credit and cash collateral, as applicable, of up to $125.0 million to Axeon. We received $110.0 million in settlement of the Axeon Term Loan, and our obligation to provide ongoing credit support to Axeon ceased. In 2016, we recognized an impairment charge on the Axeon Term Loan of $58.7 million which is included in “Other (expense) income, net” in the consolidated statements of income. Please refer to Notes 7 and 15 of the Notes to Consolidated

Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on the Axeon Term Loan and related credit support.

Defined Benefit Plans Funding
During 2017, we contributed $11.2 million to our pension and postretirement benefit plans. We expect to contribute approximately $11.6 million to our pension and postretirement benefit plans in 2018, which principally represents contributions either required by regulations or laws or, with respect to unfunded plans, necessary to fund current benefits. Pension and postretirement benefit plans funding beyond 2018 is uncertain as the funding varies from year to year based upon changes in the fair value of the plan assets and actuarial assumptions.
Distributions
General Partner and Common Limited Partners. NuStar Energy’s partnership agreement determines the amount and priority of cash distributions that our unitholders and general partner may receive. The general partner receives a 2% distribution with respect to its general partner interest. The general partner is also entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds $0.60 per unit. For a detailed discussion of the incentive distribution targets, please read Item 5. “Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities.”

The following table reflects the allocation of total cash distributions to the general partner and common limited partners applicable to the period in which the distributions were earned:
 Year Ended December 31,
 2017 2016 2015
 (Thousands of Dollars, Except Per Unit Data)
General partner interest$9,252
 $7,877
 $7,844
General partner incentive distribution45,669
 43,407
 43,220
Total general partner distribution54,921
 51,284
 51,064
Common limited partners’ distribution407,681
 342,598
 341,140
Total cash distributions$462,602
 $393,882
 $392,204
      
Cash distributions per unit applicable to common limited partners$4.38
 $4.38
 $4.38

Distribution payments to our general partner and common limited partners are made within 45 days after the end of each quarter as of a record date that is set after the end of each quarter. The following table summarizes information related to our quarterly cash distributions to our general partner and common limited partners:
Quarter Ended Cash Distributions Per Unit Total Cash Distributions Record Date Payment Date
    (Thousands of Dollars)    
December 31, 2017 (a) $1.095
 $115,267
 February 8, 2018 February 13, 2018
September 30, 2017 $1.095
 $115,084
 November 9, 2017 November 14, 2017
June 30, 2017 $1.095
 $115,083
 August 7, 2017 August 11, 2017
March 31, 2017 $1.095
 $117,168
 May 8, 2017 May 12, 2017
(a)The distribution was announced on January 29, 2018.

Pursuant to the Merger Agreement and at the effective time of the Merger, our partnership agreement will be amended and restated to, among other things, cancel the incentive distribution rights held by our general partner and convert the 2% general partner interest in NuStar Energy held by our general partner into a non-economic management interest. As a result, after the Merger, our general partner will no longer receive incentive distributions or quarterly cash distributions related to its ownership interest from us. Please refer toSee Note 2817 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the Merger.additional information.



Distributions
Preferred Units. The following table provides the terms related to distributions for our Series A, Series B and Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (collectively, the Preferred Units):
Units Fixed Distribution Rate per Annum (as a Percentage of the $25.00 Liquidation Preference per Unit) Fixed Distribution Rate per Unit per Annum Optional Redemption Date/Date at Which Distribution Rate Becomes Floating Floating Annual Rate (as a Percentage of the $25.00 Liquidation Preference per Unit)
Series A Preferred Units 8.50% $2.125
 December 15, 2021 Three-month LIBOR plus 6.766%
Series B Preferred Units 7.625% $1.90625
 June 15, 2022 Three-month LIBOR plus 5.643%
Series C Preferred Units 9.00% $2.25
 December 15, 2022 Three-month LIBOR plus 6.88%

Distributions on the Preferred Unitsour outstanding 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. See Notes 17 and 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.


Series D Preferred Units. Prior to their redemption and/or repurchase, the distribution rates on the outstanding Series D Preferred Units were as follows: (i) 9.75% per annum ($0.619 per unit per distribution period) for the first two years (beginning with the September 17, 2018 distribution); (ii) 10.75% per annum ($0.682 per unit per distribution period) for years three through five; and (iii) the greater of 13.75% per annum ($0.872 per unit per distribution period) or the distribution per common unit thereafter. The number of Series D Preferred Units outstanding as of December 31, 2022 was 16,346,650, and due to the redemptions and repurchase discussed above, the Series D Preferred Units were cancelled and no longer represent a limited partner interest.

The distribution rate on the Series D Preferred Units increased on June 15, 2023, to the greater of 13.75% per annum ($0.872 per unit per distribution period) or the distribution per common unit. Distributions accrued for redeemed Series D Preferred Units from the notification dates to the redemption dates are reported in “Interest expense, net” on the consolidated statements of income and are excluded from total distributions below for the applicable periods. Distribution information on the Series D Preferred Units was as follows:
 Distribution PeriodDistribution Rate per UnitTotal Distribution
(Thousands of Dollars)
June 15, 2023 - September 12, 2023$0.872 $5,134 
March 15, 2023 - June 14, 2023$0.682 $10,315 
December 15, 2022 - March 14, 2023$0.682 $11,148 
September 15, 2022 - December 14, 2022$0.682 $14,337 
June 15, 2022 - September 14, 2022$0.682 $15,854 
March 15, 2022 - June 14, 2022$0.682 $15,854 
December 15, 2021 - March 14, 2022$0.682 $15,854 

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Series A, B and C Preferred Units. Information on our Series A, B and C Preferred Units is shown below:
UnitsUnits Issued and Outstanding as of December 31, 2023Optional Redemption Date/Date When Distribution Rate Became FloatingFloating Annual Rate (as a Percentage of the $25.00 Liquidation Preference Per Unit)
Series A Preferred Units9,060,000December 15, 2021
Three-month LIBOR(a) plus 6.766%
Series B Preferred Units15,400,000June 15, 2022
Three-month LIBOR(a) plus 5.643%
Series C Preferred Units6,900,000December 15, 2022
Three-month LIBOR(a) plus 6.88%
(a)Beginning with the distribution period starting on September 15, 2023, LIBOR was replaced with the corresponding CME Term SOFR plus the applicable tenor spread adjustment of 0.26161%.

Distribution information on our Series A, B and C Preferred Units is as follows (thousands of dollars, except per unit data):
Series A Preferred UnitsSeries B Preferred UnitsSeries C Preferred Units
 Distribution PeriodDistribution Rate per UnitTotal DistributionDistribution Rate per UnitTotal DistributionDistribution Rate per UnitTotal Distribution
December 15, 2023 - March 14, 2024$0.77533 $7,024 $0.70515 $10,859 $0.78246 $5,399 
September 15, 2023 - December 14, 2023$0.77736 $7,043 $0.70717 $10,890 $0.78448 $5,413 
June 15, 2023 - September 14, 2023$0.76715 $6,950 $0.69696 $10,733 $0.77428 $5,343 
March 15, 2023 - June 14, 2023$0.73169 $6,629 $0.66150 $10,187 $0.73881 $5,098 
December 15, 2022 - March 14, 2023$0.71889 $6,513 $0.64871 $9,990 $0.72602 $5,010 
September 15, 2022 - December 14, 2022$0.64059 $5,804 $0.57040 $8,784 $0.56250 $3,881 
June 15, 2022 - September 14, 2022$0.54808 $4,966 $0.47789 $7,360 $0.56250 $3,881 
March 15, 2022 - June 14, 2022$0.47817 $4,332 $0.47657 $7,339 $0.56250 $3,881 
December 15, 2021 - March 14, 2022$0.43606 $3,951 $0.47657 $7,339 $0.56250 $3,881 

On January 25, 2024, our Board of Directors declared quarterly distributions with respect to the Series A, B and C Preferred Units to be paid on March 15, 2024 to holders of record as of March 1, 2024.

Common Units. Under our partnership agreement, distribution payments are required to be 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. On January 25, 2024, our Board of Directors declared distributions with respect to our common units for the quarter ended December 31, 2023. The following table summarizes information relatedabout cash distributions to our quarterly cashcommon limited partners applicable to the period in which the distributions on our Preferred Units:were earned:
Quarter EndedCash Distributions
Per Unit		Total Cash DistributionsRecord DatePayment Date
(Thousands of Dollars)
December 31, 2023$0.40 $50,607 February 7, 2024February 13, 2024
September 30, 20230.40 50,358 November 7, 2023November 14, 2023
June 30, 20230.40 44,363 August 8, 2023August 14, 2023
March 31, 20230.40 44,396 May 8, 2023May 12, 2023
Year ended December 31, 2023$1.60 $189,724 
Year ended December 31, 2022$1.60 $176,746 

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Period 
Cash
Distributions
Per Unit
 
Total Cash
Distributions
 Record Date Payment Date
    (Thousands of Dollars)    
Series A Preferred Units:        
December 15, 2017 - March 14, 2018 (a) $0.53125
 $4,813
 March 1, 2018 March 15, 2018
September 15, 2017 - December 14, 2017 $0.53125
 $4,813
 December 1, 2017 December 15, 2017
June 15, 2017 - September 14, 2017 $0.53125
 $4,813
 September 1, 2017 September 15, 2017
March 15, 2017 - June 14, 2017 $0.53125
 $4,813
 June 1, 2017 June 15, 2017
November 25, 2016 - March 14, 2017 $0.64930556
 $5,883
 March 1, 2017 March 15, 2017
         
Series B Preferred Units:        
December 15, 2017 - March 14, 2018 (a) $0.47657
 $7,339
 March 1, 2018 March 15, 2018
September 15, 2017 - December 14, 2017 $0.47657
 $7,339
 December 1, 2017 December 15, 2017
April 28, 2017 - September 14, 2017 $0.725434028
 $11,172
 September 1, 2017 September 15, 2017
         
Series C Preferred Units:        
November 30, 2017 - March 14, 2018 (a) $0.65625
 $4,528
 March 1, 2018 March 15, 2018

(a)The distribution was announced on January 29, 2018.
Debt Obligations
As of December 31, 2017, we were a party to theThe following table summarizes our debt agreements:obligations:
 MaturityOutstanding Obligations as of December 31, 2023
 (Thousands of Dollars)
5.75% senior notesOctober 1, 2025$600,000 
6.00% senior notesJune 1, 2026$500,000 
Receivables Financing Agreement, 7.0% as of December 31, 2023July 1, 2026$69,800 
Revolving Credit Agreement, 8.0% as of December 31, 2023January 27, 2027$343,000 
5.625% senior notesApril 28, 2027$550,000 
6.375% senior notesOctober 1, 2030$600,000 
GoZone Bonds, 5.85% - 6.35%2038thru2041$322,140 
Subordinated notes, 12.4% as of December 31, 2023January 15, 2043$402,500 
Revolving Credit Agreement due October 29, 2020, with $893.3 million of borrowings outstanding as of December 31, 2017;

7.65% senior notes due April 15, 2018 with a face value of $350.0 million; 4.80% senior notes due September 1, 2020 with a face value of $450.0 million; 6.75% senior notes due February 1, 2021 with a face value of $300.0 million; 4.75% senior notes due February 1, 2022 with a face value of $250.0 million; 5.625% senior notes due April 28, 2027 with a face value of $550.0 million; and 7.625% fixed-to-floating subordinated notes due January 15, 2043 with a face value of $402.5 million;
$365.4 million in GoZone Bonds due from 2038 to 2041;
Line of credit agreements with $35.0 million of borrowings outstanding as of December 31, 2017; and
Receivables Financing Agreement due September 20, 2020, with $62.3 million of borrowings outstanding as of December 31, 2017.

Management believesWe believe that, as of December 31, 2017,2023, we are in compliance with the ratios andfinancial covenants contained inapplicable to our debt instruments.obligations. A default under certain of our debt agreements would be considered an event of default under other of our debt instruments. Please referobligations.

Receivables Financing Agreement and Revolving Credit Agreement. 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. Borrowings under our Revolving Credit Agreement bear interest, at our option, at an alternate base rate or a SOFR rate, each as defined in the Revolving Credit Agreement. The interest rate on our Revolving Credit Agreement and certain fees under the Receivables Financing Agreement, 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 RatingsMoody’s Investor Service Inc.S&P Global Ratings
RatingsBBBa3BB-
OutlookStableStablePositive

Gulf Opportunity Zone Revenue Bonds. As reflected in the table below, 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 are expected to 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 following table summarizes the GoZone Bonds outstanding as of December 31, 2023:
SeriesDate IssuedAmount
Outstanding
Interest Rate		Mandatory
Purchase Date		Optional Redemption DateMaturity Date
 (Thousands of Dollars) 
Series 2008June 26, 2008$55,440 6.10 %June 1, 2030n/aJune 1, 2038
Series 2010July 15, 2010100,000 6.35 %n/aJune 1, 2030July 1, 2040
Series 2010AOctober 7, 201043,300 6.35 %n/aJune 1, 2030October 1, 2040
Series 2010BDecember 29, 201048,400 6.10 %June 1, 2030n/aDecember 1, 2040
Series 2011August 9, 201175,000 5.85 %June 1, 2025n/aAugust 1, 2041
Total$322,140 

NuStar Logistics Subordinated Notes.NuStar Logistics’ $402.5 million of fixed-to-floating rate subordinated notes (the Subordinated Notes). Effective with the quarterly interest periods starting after June 30, 2023, the interest rate on the Subordinated Notes is equal to the sum of the three-month CME term SOFR plus the applicable tenor spread adjustment of 0.26161% for the related quarterly interest period plus 6.734%, payable quarterly, 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
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cannot declare or make cash distributions with respect to, or redeem, purchase or make a liquidation payment with respect to, its equity securities during the period that interest payments are deferred.

Guarantor Summarized Financial Information. NuStar Energy has no operations, and its assets consist primarily 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 (i) ranks equally in right of payment with all other existing and future unsecured senior indebtedness of that guarantor, (ii) 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 (iii) ranks 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 is subordinated in right of payment and upon liquidation to the prior payment in full of all other existing and future senior indebtedness of that guarantor. NuPOP will be released from its guarantee when it no longer guarantees any obligations of NuStar Energy or any of its subsidiaries, including NuStar Logistics, under any bank credit facility or public debt instrument. The rights of holders of our senior and subordinated notes may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. See Note 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of our debt agreements.
Credit Ratings
The following tables present summarized combined balance sheet and income statement information for NuStar Energy, NuStar Logistics and NuPOP (collectively, the Guarantor Issuer Group). Intercompany items among the Guarantor Issuer Group have been eliminated in the summarized combined financial information below, as well as intercompany balances and activity for the Guarantor Issuer Group with non-guarantor subsidiaries, including the Guarantor Issuer Group’s investment balances in non-guarantor subsidiaries.
December 31, 2023
(Thousands of Dollars)
Summarized Combined Balance Sheet Information for the Guarantor Issuer Group:
Current assets$42,000 
Long-term assets$3,160,956 
Current liabilities (a)$135,366 
Long-term liabilities, including long-term debt$3,487,719 
(a)Excluding $1,894.0 million of net intercompany payables due to the non-guarantor subsidiaries from the Guarantor Issuer Group.

Long-term assets for the non-guarantor subsidiaries totaled $1,548.3 million as of December 31, 2023.

Year Ended December 31, 2023
(Thousands of Dollars)
Summarized Combined Income Statement Information for the Guarantor Issuer Group:
Revenues$830,406 
Operating income$333,986 
Interest expense, net$(239,113)
Net income$96,178 

Revenues and net income for the non-guarantor subsidiaries totaled $803.8 million and $177.5 million, respectively, for the year ended December 31, 2023.

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Contractual Obligations
The following table reflects the current outlookpresents our contractual obligations and ratings that have been assigned to our debtcommitments as of December 31, 2017:2023:
 CurrentLong-Term
 (Thousands of Dollars)
Long-term debt maturities$— $3,387,440 
Interest payments238,001 1,506,912 
Operating leases14,267 238,031 
Finance leases7,067 67,000 
Purchase obligations6,406 12,893 
Total$265,741 $5,212,276 
Standard & Poor’s
 Ratings Services
Moody’s Investor 
Service Inc.
Fitch, Inc.
RatingsBBBa1BB
OutlookNegativeNegativeStable

The interest rates payablepayments calculated for our variable-rate, long-term debt are based on the $350.0 million of 7.65% senior notes due 2018 (the 7.65% Senior Notes)interest rates and the Revolving Credit Agreement are subject to adjustment if our debt rating is downgraded (or upgraded) by certain credit rating agencies. In November 2017, Standard & Poor’s Rating Services lowered our credit rating from BB+ to BB, and the outlook was changed from stable to negative. The rating downgrade caused the interest rate on the 7.65% Senior Notes to increase from 8.15% to 8.4% and had no impact on the interest rate payable on our Revolving Credit Agreement. In February 2018, Moody’s Investor Service Inc. (Moody’s) lowered our credit rating from Ba1 to Ba2, which caused the interest rate on the 7.65% Senior Notes to also increase by 0.25%, resulting in an interest rate of 8.65% applicable to the interest payment due April 15, 2018. This Moody’s downgrade also caused the interest rate on our Revolving Credit Agreement to increase by 0.25%.
Interest Rate Swaps
Asoutstanding borrowings as of December 31, 20172023. The interest payments on our fixed-rate debt are based on the stated interest rates and 2016, we were a party to forward-starting interest rate swap agreements for the purpose of hedging interest rate risk. Asoutstanding borrowings as of December 31, 2017 and 2016, the aggregate notional amount of these forward-starting interest rate swaps was $600.0 million. Please refer to Notes 2 and 162023. See Note 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.
Our operating leases consist primarily of land and Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” for a more detailed discussion of our interest rate swaps.
Long-Term Contractual Obligations
The following table presents our long-term contractual obligations and commitmentsdock leases at various terminal facilities and the related payments due,operating lease agreement to lease back the Corporate Headquarters in totalthe first quarter of 2023 (the HQ Lease Agreement), as further discussed in Notes 4 and by period, as of December 31, 2017:
 Payments Due by Period    
 2018 2019 2020 2021 2022 Thereafter Total
 (Thousands of Dollars)
Long-term debt maturities$350,000
 $—
 $1,405,611
 $300,000
 $250,000
 $1,317,940
 $3,623,551
Interest payments (a)174,937
 169,162
 165,124
 102,586
 86,715
 1,150,198
 1,848,722
Operating leases (b)39,236
 34,203
 19,541
 13,324
 7,295
 68,386
 181,985
Purchase obligations (c)6,963
 6,133
 4,686
 4,690
 4,480
 300
 27,252
Total$571,136
 $209,498
 $1,594,962
 $420,600
 $348,490
 $2,536,824
 $5,681,510
(a)The interest payments calculated for our variable-rate debt are based on forward LIBOR interest rates and the outstanding borrowings as of December 31, 2017. The interest payments on our fixed-rate debt are based on the stated interest rates and the outstanding borrowings as of December 31, 2017.
(b)Our operating leases consist primarily of leases for tugs and barges utilized at our St. Eustatius facility and land leases at various terminal facilities.
(c)A purchase obligation is an enforceable and legally binding agreement to purchase goods or services that specifies significant terms, including (i) fixed or minimum quantities to be purchased, (ii) fixed, minimum or variable price provisions and (iii) the approximate timing of the transaction.

We also have pension and other postretirement benefit obligations recorded in “Other long-term liabilities” on our consolidated balance sheets which have been excluded from the contractual obligations table above due to the uncertainty in timing as to the future cash flows related to these obligations. For additional information on our pension and other postretirement benefit obligations see Note 2215 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.” The HQ Lease Agreement has an initial term of 20 years, with two renewal options of ten years each.

Our finance leases consist primarily of a dock lease at our Corpus Christi North Beach terminal with a remaining term of approximately two years and three additional five-year renewal periods that also includes a commitment for minimum dockage and wharfage throughput volumes. See Note 15 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on our operating and finance leases.

A purchase obligation is an enforceable and legally binding agreement to purchase goods or services that specifies significant terms, including (i) fixed or minimum quantities to be purchased, (ii) fixed, minimum or variable price provisions and (iii) the approximate timing of the transaction. 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.

Pension and Other Postretirement Benefit Plan Contributions
During 2023, we contributed $11.2 million and $0.5 million to our pension and postretirement benefit plans, respectively. In 2024, we expect to contribute approximately $10.2 million to our pension and postretirement benefit plans and will monitor our funding status to determine if any contributions are required by regulations or laws, or with respect to unfunded plans, necessary to fund current benefits. Pension and postretirement benefit plans funding beyond 2024 is uncertain as the funding varies from year to year based upon changes in the fair value of the plan assets and actuarial assumptions.

A change of 0.25% in the specified assumptions would have the following effects to our pension and postretirement benefit obligations and costs:
Pension
Benefits		Other Postretirement Benefits
(Thousands of Dollars)
Increase in benefit obligation as of December 31, 2023 resulting from:
Discount rate decrease$3,300 $400 
Compensation rate increase$600 n/a
(Decrease) increase in net periodic benefit cost for the year ending December 31, 2024
resulting from:
Discount rate decrease$(200)$— 
Expected long-term rate of returns on plan assets decrease$400 n/a
Compensation rate increase$100 n/a

See Notes 2 and 21 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.
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Environmental, Health and Safety
OurAs described below under “Environmental, Health, Safety and Security Regulation,” our operations in the U.S. and Mexico are subject to extensive international, federal, state and local environmental laws and regulations, in the U.S. and in the other countries in which we operate, including those relating to the discharge of materials into the environment, waste management, remediation, the characteristics and composition of fuels, climate change and greenhouse gases. Our operations are also subject to extensive health, safety and security laws and regulations, including those relating to worker and pipeline safety, pipeline and storage tank integrity and operations security. Because more stringent environmental and safety laws and regulations are continuously being enacted or proposed, the level of expenditures required for environmental, health and safety matters is expected to increase in the future.

The balance of and changes in our accruals for environmental matters as of and for the years ended December 31, 20172023 and 20162022 are included in Note 13 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.” We believe that we have adequately accrued for our environmental exposures.
Contingencies
HUMAN CAPITAL

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

Our Employees
As of December 31, 2023, we had 1,184 employees, of which 1,173 are based in the United States and 11 are based in Mexico. Only 1.1 percent of our employees are represented under collective bargaining agreements. In the United States, 487 of our employees work at our headquarters in San Antonio, Texas, with the remaining 686 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, 2023:
•19.1% of all of our employees and 29.0% of our employees at senior manager level and above are female; and
•34.8% of our U.S. employees and 24.5% of our U.S. employees at senior manager level and above are minorities (as defined by the U.S. Equal Opportunity Employment Commission).

Employee Benefits and NuStar’s Culture
We provide opportunities for our employees to develop and enhance their skills through defined career paths, professional training, educational reimbursement and leadership and development programs, as well as regular training regarding safety, operations, ethics (including our Code of Business Conduct and Ethics), human resources topics and cybersecurity. In addition, we support our employees by providing competitive compensation and benefits.

We benchmark our compensation programs through market surveys to help offer competitive packages to attract and retain high-performing employees. Our compensation department also evaluates company-wide racial and gender equity by job-profile each time an employee is hired or recommended for a promotion. This helps to ensure that compensation levels are equitable for all employees regardless of race or gender.

Our benefits and health and wellness programs include life and health insurance (medical, dental and vision), prescription drug benefits, flexible spending accounts, paid sick leave, vacation, short- and long-term disability, mental and behavioral health resources, retirement benefits (including 401(k) and pension), educational reimbursement, a disaster relief fund that provides cash grants (that do not have to be repaid) to employees undergoing difficult circumstances, an employee assistance program and employee recognition programs. We also are committed to supporting the communities in which we operate, and we organize opportunities for our employees to participate in and enrich our communities through a variety of initiatives, such as fundraising activities, community clean-up projects and educational programs.

Our culture is driven by our nine guiding principles: safety; integrity; commitment; make a difference; teamwork; respect; communication; excellence; and pride. We believe that these principles are the building blocks for our success and have helped us to recruit and retain our employees and make NuStar a great place to work. We have been recognized on FORTUNE’S “100 Best Companies to Work For” list 13 times, FORTUNE’S “Best Workplaces for Millennials” list five times, the “Best Places For Working Parents” list three times, and Latino Leader Magazine’s “Best Companies for Latinos to Work” list three times. We also were recognized as a top employer by regional and local publications, including being recognized as a top employer in Texas by FORTUNE. In addition, we were recently recognized on Newsweek’s “America’s Most Trustworthy Companies” and “World’s Most Trustworthy Companies” lists. 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, 2023, our voluntary
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turnover rate over the last five years has averaged 3.8%, and 231 of our employees have been employed by NuStar or predecessor entities for at least 20 years.

Safety
Safety is our first priority. In managing our business, we focus on the safety of our employees and contractors, as well as the communities in which we operate. We have implemented safety programs and management practices to promote a culture of safety, including required training for field and office employees and contractors, as well as specific qualifications and certifications for field employees and contractors. To further emphasize the importance of safety at NuStar, our Board of Directors receives a comprehensive annual report and monthly updates regarding our health, safety and environmental performance. The Compensation Committee of our Board of Directors also evaluates our overall environmental, social and governance (ESG) performance and our health, safety and environmental performance together annually as one of the metrics used to determine the annual incentive bonus for all of our employees, including our executive officers, which we believe reinforces the importance of maintaining safe, responsible operations and focusing on ESG excellence.

We are proud of NuStar’s safety performance. Our 2023 total recordable incident rate (TRIR) of 0.55 was better than the 3.60 average most recently reported by the U.S. Bureau of Labor Statistics (BLS) for the bulk terminals industry and in line with the 0.50 average most recently reported by BLS for the pipeline transportation industry. Our 2023 days away, restricted or transferred rate (DART) of 0.39 was better than the 2.80 average most recently reported by BLS for the bulk terminals industry and in line with the 0.30 average most recently reported by BLS for the pipeline transportation industry. NuStar also participates in the Occupational Safety and Health Administration’s (OSHA) Voluntary Protection Program (VPP), which promotes effective worksite health and safety. Achieving VPP Star status requires rigorous OSHA review and audit, and requires recertification every three to five years. As of December 31, 2023, approximately 92% of our eligible U.S. terminals have attained VPP Star status. NuStar also has received the International Liquids Terminals Association’s Safety Excellence Award 13 times.

Sustainability Report
We publish a Sustainability Report, which covers topics similar to those described above, including our guiding principles; operations and economic impact; environmental and safety programs; sustainability; renewable fuels-related services; policies and statistics (including greenhouse gas emissions disclosures); employee development and training; diversity and inclusion; community involvement and development; recent awards; risk management; cybersecurity; and governance. Our Sustainability Report can be viewed at https://sustainability.nustarenergy.com. Our Sustainability Report and the information contained on our website are not part of this Annual Report on Form 10-K, are not “soliciting materials,” are not deemed filed with the SEC and are not to be incorporated by reference into any of NuStar Energy’s filings under the Securities Act of 1933 or the Securities Act of 1934, as amended, respectively.

PROPERTIES

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

RATE REGULATION

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

Our ammonia pipeline is subject to regulation by the STB pursuant to the ICA applicable to such pipelines (which differs from the ICA applicable to interstate liquids pipelines). Under that regulation, the ammonia pipeline’s rates, classifications, rules and practices related to the interstate transportation of anhydrous ammonia must be reasonable and, in providing interstate transportation, the ammonia pipeline may not subject a person, place, port or type of traffic to unreasonable discrimination.Similar to the crude and refined products pipelines, the rates for transportation services on the ammonia pipeline are required to be in a tariff which is posted publicly on our website, however, that tariff is not required to be on file with the STB. The STB does not prescribe an indexing approach similar to the EP Act but rates under the STB must be reasonable and the pipeline may not subject a person, place, port or type of traffic to unreasonable discrimination.

In addition to federal regulatory body oversight, various states, including Colorado, Kansas, Louisiana, North Dakota and Texas, maintain commissions focused on the rates and practices of common carrier pipelines offering services within their borders. Although the applicable state statutes and regulations vary, they generally require that intrastate pipelines publish tariffs setting forth all rates, rules and regulations applying to intrastate service, and generally require that pipeline rates and practices be just, reasonable and nondiscriminatory.

Shippers may challenge tariff rates, rules and regulations on our pipelines. In most instances, state commissions have not initiated investigations of the rates or practices of pipelines in the absence of shipper complaints. There are no pending challenges or complaints regarding our tariffs or tariff rates.

ENVIRONMENTAL, HEALTH, SAFETY AND SECURITY REGULATION

Our operations are subject to extensive international, federal, state and local environmental laws and regulations, in the U.S. and in Mexico, including those relating to the discharge of materials into the environment, waste management, remediation, the characteristics and composition of fuels, climate change and greenhouse gases. In 2023, our capital expenditures attributable to compliance with environmental regulations were $5.5 million, and we currently project environmental regulatory compliance spending of approximately $12.5 million in 2024.

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
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Occupational Safety and Health Administration’s Process Safety Management regulations. These regulations apply to processes that involve certain loss contingencies,chemicals at or above specified thresholds.

Fuel Standards and Renewable Energy
International, federal, state and local laws and regulations regulate the outcomesfuels we transport and store for our customers. Changes in these laws or regulations could affect our earnings, including by reducing our throughput volumes, or require capital expenditures and expenses to segregate and separately store fuels. In addition, several federal and state programs require, subsidize or encourage the purchase and use of which couldcompeting fuels or energy, renewable energy, electric battery-powered motor vehicle engines and renewable fuels and blending additives, like ethanol, biodiesel and renewable diesel. These programs may over time offset projected increases or reduce the demand for refined products, particularly gasoline, in certain markets. However, the increased production and use of renewable fuels may also create opportunities for pipeline transportation and fuel blending. Other legislative changes in the future may similarly alter the expected demand and supply projections for refined products in ways that cannot be predicted.

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

We currently own, lease, and operate on, and have an adversein 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 cash flows andfinancial 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 further disclosedamended, 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 Note 14the 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 NotesUnited 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 Consolidated Financial Statementsand liability for oil spills, and the Rivers and Harbors Act regulates pipelines crossing navigable waters.

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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 Item 8. “Financial Statements and Supplementary Data.”

RELATED PARTY TRANSACTIONS
Please refer to Note 17Title 49 of the NotesU.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 Consolidated Financial Statements inCoast 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.

We take proactive steps to protect our company, systems and data from cyberattacks. See Item 8. “Financial Statements and Supplementary Data”1C. “Cybersecurity” for a discussion of our related party transactions.cybersecurity considerations.


CRITICAL ACCOUNTING POLICIESESTIMATES

The preparation of financial statements in accordance with U.S. generally accepted accounting principles (GAAP) 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 following summary provides further information on our accounting policies below are consideredthat involve critical accounting estimates due to judgments made by management and the sensitivity of these estimates to deviations of actual results from management’s assumptions. The critical accounting policiesestimates should be read in conjunction with Note 2 of the Notes to the Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data,” which summarizes our significant accounting policies.
Depreciation
We calculate depreciation expense using the straight-line method over the estimated useful lives of our property, plant and equipment. Due to the expected long useful lives of our property, plant and equipment, we depreciate our property, plant and equipment over periods ranging from 5 years to 40 years. Changes in the estimated useful lives of our property, plant and equipment could have a material adverse effect on our results of operations.
Impairment of Long-Lived Assets
We test long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. We evaluate recoverability using undiscounted estimated net cash flows generated by the related asset or asset group. If the results of that evaluation indicate that the undiscounted cash flows are less than the carrying amount of the asset (i.e., the asset is not recoverable), we perform an impairment analysis. If our intent is to hold the asset for continued use, we determine the amount of impairment as the amount by which the net carrying value exceeds its fair value. If our intent is to sell the asset, and the criteria required to classify an asset as held for sale are met, we determine the amount of impairment as the amount by which the net carrying amount exceeds its fair value less costs to sell.

In determining the existence of an impairment of the carrying value of an asset, we make a number of subjective assumptions as to:
•whether there is an event or circumstance that may indicate that the carrying amount of an asset may not be recoverable;
•the grouping of assets;
•the intention of holding, abandoning or selling an asset;
•the forecast of undiscounted expected future cash flows with respect to an asset or asset group; and
•if an impairment exists, the fair value of the asset or asset group.

Our estimates of undiscounted future cash flows include: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) estimates of useful lives of the assets. The identification of impairment indicators and the estimates of future undiscounted cash flows are highly subjective and are based on numerous assumptions about future operations and market conditions, which we believe to be reasonable but are inherently uncertain. The uncertainties underlying our assumptions and estimates could differ significantly from actual results and could cause a different conclusion about the recoverability of our assets. If we determined one or more assets was impaired, the amount of impairment could be material to our results of operations.
Impairment of Goodwill
We perform an assessment of goodwill annually or more frequently if events or changes in circumstances warrant. We have the option to first perform a qualitative annual assessment to determine whether it is necessary to perform a quantitative goodwill impairment test. A qualitative assessment includes, among other things, industry and market considerations, overall financial performance, other entity-specific events and events affecting individual reporting units. If, after assessing the totality of events or circumstances for each reporting unit, we determine that it is more likely than not that the carrying value exceeds its fair value, then we would perform ana quantitative impairment test for that reporting unit. However, we chose to perform a quantitative goodwill impairment test for all reporting units as
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We recognize an impairment of goodwill if the carrying value of a reporting unit that contains goodwill exceeds its estimated fair value. In order to estimate the fair value of the reporting unit, including goodwill, management must make certain estimates and assumptions that affect the total fair value of the reporting unit including, among other things, an assessment of market conditions, projected cash flows, discount rates and

growth rates. Management’s estimates of projected cash flows related to the reporting unit include, but are not limited to, future earnings of the reporting unit, assumptions about the use or disposition of assets included in the asset,reporting unit, estimated remaining lifelives of the asset,those assets, and future expenditures necessary to maintain the asset’sassets’ existing service potential.


We calculate the estimated fair value of each of our reporting units using a weighted-averageweighted 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 offor comparable entities.
We determined that no impairment charges resulted from our October 1, 2017 impairment assessment. Furthermore, our assessment did not reflect any reporting units at risk of failing step one of the goodwill impairment test, which compares the Our fair value of the reporting unitestimates are sensitive to its carrying value including goodwill.
Derivative Financial Instruments
We utilize various derivative instruments to managetypical valuation assumptions, particularly our exposure to interest rate risk and commodity price risk. We record derivative instruments in the consolidated balance sheets at fair value, and apply hedge accounting when appropriate. We record changes to the fair values of derivative instruments in earnings for fair value hedges or as part of accumulated other comprehensive income (AOCI)estimates for the effective portionweighted-average cost of cash flow hedges. We reclassifycapital used for the effective portion of cash flow hedges from AOCI to earnings when the underlying forecasted transaction occurs or becomes probable not to occur. We recognize ineffectiveness resulting from our derivatives immediately in earnings. With respect to cash flow hedges, we must exercise judgment to assess the probability of the forecasted transaction, which, among other things, depends upon market factors and our ability to reliably operate our assets.
Defined Benefit Plans
We estimate pension and other postretirement benefit obligations and costs based on actuarial valuations. The annual measurement date for our pension and other postretirement benefit plans is December 31. The actuarial valuations require the use of certain assumptions including discount rates, expected long-term rates of return on plan assets and expected rates of compensation increase. Changes in these assumptions are primarily influenced by factors outside our control. The discount rate is based on a hypothetical yield curve represented by a series of annualized individual discount rates. Each bond issue underlying the hypothetical yield curve required an average rating of double-A, when averaging all available ratings by Moody’s Investor Service Inc., Standard & Poor’s Ratings Services and Fitch, Inc. The resulting discount rates were 3.72% and 3.82% for our pension and other postretirement benefit plans, respectively, as of December 31, 2017. The expected long-term rate of return on plan assets is based on the weighted averages of the expected long-term rates of return for each asset class of investments held in our plans as determined using historical dataincome approach and the assumption that capital markets are informationally efficient. The expected rate of compensation increase represents average long-term salary increases.guideline public company and guideline transaction multiples used for the market approach.


These assumptions can have an effect on the amounts reported in our consolidated financial statements. The effect of a 0.25% change in the specified assumptions would have the following effects (thousands of dollars):
 
Pension 
Benefits
 
Other
Postretirement
Benefits
Increase in benefit obligation as of December 31, 2017 from:   
Discount rate decrease$5,200
 $500
Compensation rate increase$1,500
 n/a
Increase in net periodic benefit cost for the year ending
December 31, 2018 resulting from:
   
Discount rate decrease$400
 $100
Expected long-term rate of returns on plan assets decrease$300
 n/a
Compensation rate increase$400
 n/a

Please refer to Note 22 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 adequately accrued for our environmental exposures.
Contingencies
We accrue for costs relating to litigation, claims and other contingent matters when such liabilities become probable and reasonably estimable. Such estimates may be based on advice from third parties or on management’s judgment, as appropriate. Due to the inherent uncertainty of litigation, actual amounts paid may differ from amounts estimated, and such differences will be charged to income in the period when final determination is made.

NEW ACCOUNTING PRONOUNCEMENTS
Please refer to
See Note 3 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of new accounting pronouncements.



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

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

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ITEM 1A.    RISK FACTORS

RISKS RELATED TO SUNOCO’S PROPOSED ACQUISITION OF NUSTAR
The Merger is subject to a number of conditions to the obligations of both NuStar and Sunoco to complete the Merger, including approval by NuStar’s common unitholders and regulatory clearance, which may impose unacceptable conditions or could delay completion of the Merger or result in termination of the Merger Agreement.
On January 22, 2024, NuStar entered into a definitive agreement (the Merger Agreement), whereby Sunoco will acquire NuStar in an all-equity transaction (the Merger). The respective obligations of each of NuStar and Sunoco to consummate the Merger are subject to the satisfaction at or prior to the closing of numerous conditions, including, among other things, approval by NuStar’s common unitholders, the absence of any law or order prohibiting the consummation of the Merger, and the expiration or termination of the waiting period (and any extension of such period) under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.Many of the conditions to the completion of the Merger are not within either NuStar’s or Sunoco’s control, and NuStar cannot predict when, or if, these conditions will be satisfied. Furthermore, the requirement for obtaining the required regulatory clearances could delay the completion of the Merger for a significant period of time or prevent it from occurring.Regulators may seek to enjoin the completion of the Merger, seek divestiture of substantial assets of the parties, or require the parties to license, or hold separate, assets or terminate existing relationships and contractual rights.

Failure to complete the Merger could negatively impact the price of our units and have a material adverse effect on our results of operations, cash flows and financial position.
If the Merger is not completed for any reason, including as a result of failure to obtain all requisite regulatory and unitholder approvals, our ongoing business may be materially and adversely affected and, without realizing any of the benefits of having completed the Merger, we would be subject to a number of risks, including the following:
•we may experience negative reactions from the financial markets, including negative unit price impacts;
•we may experience negative reactions from commercial and business partners; and
•we will still be required to pay certain significant costs relating to the Merger, such as legal, accounting, financial advisor, and printing fees.

In addition, if the Merger Agreement is terminated under certain circumstances specified therein, we may be required to pay Sunoco a termination fee of approximately $90.3 million.

If the Merger is not completed, the risks described above may materialize and they may have a material adverse effect on our results of operations, cash flows, financial position, and the price of our publicly-traded units.

The announcement and pendency of the Merger may adversely affect our business, financial results and operations.
Whether or not the Merger is completed, its announcement and pendency could cause disruptions to our business, including:
•uncertainties associated with the Merger may cause us to lose management personnel and other key employees, which could adversely affect our future business and operations following the Merger;
•our business relationships may be subject to disruption due to uncertainty associated with the Merger, which could have a material adverse effect on our results of operations, cash flows, and financial position;
•matters relating to the Merger (including integration planning) require substantial commitments of time and resources by our management, which may result in the distraction of our management from ongoing business operations and pursuing other opportunities that could be beneficial to us; and
•the Merger Agreement places certain restrictions on how we conduct our operations, which may delay or prevent us from undertaking business opportunities that, absent the Merger Agreement, we may have pursued.

Sunoco may fail to realize the anticipated benefits of the Merger and fail to successfully integrate the businesses and operations of the parties in the expected time frame.
The success of the Merger, and the value that our common unitholders who receive Sunoco common units following the Merger will realize, depends on, among other things, the successful combination of NuStar’s and Sunoco’s businesses in a manner that realizes anticipated synergies and benefits and meets or exceeds the forecasted stand-alone cost savings anticipated by the combined business. If the combined business is not able to successfully achieve these synergies, or the cost to achieve these synergies is greater than expected, then the anticipated benefits of the Merger may not be realized fully or at all or may take longer to realize than expected. If the transaction closes, it is possible that the integration process could result in the loss of key NuStar employees or key Sunoco employees, the loss of customers, providers, vendors, or business partners, the disruption of either or both parties’ ongoing businesses, inconsistencies in standards, controls, procedures, and policies, potential unknown liabilities and unforeseen expenses, delays, or regulatory conditions associated with and following completion of the Merger, or higher than expected integration costs and an overall post-completion integration process that takes longer than originally anticipated.
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In addition, at times the attention of certain members of our management team and resources may be focused on the completion of the Merger and planning the anticipated integration, and diverted from day-to-day business operations or other opportunities that may have been beneficial to NuStar, which may disrupt our ongoing business and the operations of the combined business.

We may be subject to litigation challenging the Merger, and an unfavorable judgment or ruling in any such lawsuits could prevent or delay the consummation of the Merger and/or result in substantial costs.
Lawsuits related to the Merger may be filed against us, Sunoco, and our respective affiliates, directors and officers. If dismissals are not obtained or a settlement is not reached, these lawsuits could prevent or delay completion of the Merger and/or result in substantial costs to us.

RISKS RELATED TO OUR BUSINESS
Changes in price levels could negatively impact our revenue, our expenses, or both, which could adversely affect our financial position, results of operations and cash flows.
The operation of our assets and the execution of capital projects require significant expenditures for labor, materials, property, equipment and services. As a result, such costs may increase during periods of high inflation, including as a result of rising commodity prices, supply chain disruptions and tight labor markets. Recent inflationary pressures affecting the general economy and the energy industry have increased our expenses and capital costs, and those costs may continue to increase. While we expect our pipeline systems to benefit from the positive revenue impact of our tariff indexation increases, we may not be able to pass all of these increased costs to our customers in the form of higher fees for our services, and, if so, our revenues and operating margins would be negatively impacted. Prior to adjustments to applicable rates, material cost increases may affect our operating margins, even if margins in subsequent periods may be normalized following applicable rate adjustments. Accordingly, increased costs during periods of high inflation that are not passed through to customers or offset by other factors may have a material adverse effect on our financial position, results of operations and cash flows.

We may not be able to generate sufficient cash from operations to enable us to pay quarterly distributions to our unitholders.
The amount of cash that we can distribute to our unitholders each quarter principally depends upon the amount of cash we generate from our operations, based on, among other things:
•prevailing macroeconomic conditions as well as economic conditions in and specific to our primary markets;
•demand for and supply of crude oil, refined products, renewable fuels and anhydrous ammonia;
•volumes transported in our pipelines and stored in our terminals and storage facilities;
•the financial stability and strength of our customers;
•tariff and/or contractually determined rates and fees we charge and the revenue we realize for our services;
•domestic and foreign governmental laws, regulations, sanctions, embargoes and taxes;
•the effect of energy conservation, efficiency and other evolving priorities;
•the effect of weather events on our operations and demand for our services; and
•the results of our marketing, trading and hedging activities, which fluctuate depending upon the relationship between refined product prices and prices of crude oil and other feedstocks.

Furthermore, the amount of cash that we will have available for distribution depends on a number of other factors, including:
•our debt service requirements and restrictions on distributions contained in our current or future financing agreements;
•our capital expenditures;
•our operating costs;
•the costs to comply with environmental, health, safety and security laws and regulations;
•fluctuations in our working capital needs;
•fluctuations in interest rates on our variable rate debt instruments and preferred units;
•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. The factors listed above, which may be further impacted by public health crises, international conflicts, actions of oil-producing nations and other factors beyond our control, 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.

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Extended periods of reduced demand for or supply of crude oil, refined products, renewable fuels and anhydrous ammonia 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, refined products, renewable fuels and anhydrous ammonia we transport in our pipelines and store in our terminals. Market prices for these products are subject to wide fluctuation in response to changes in global and regional supply and demand 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 crude oil, refined products, renewable fuels or anhydrous ammonia 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, high interest rates, 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;
•higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline;
•an increase in aggregate automotive engine fuel economy;
•new government and regulatory actions or court decisions requiring the phase out or reduced use of gasoline-fueled vehicles;
•the increased use of and public demand for use of alternative fuel sources or electric vehicles;
•an increase in the market price of crude oil that increases refined product prices, which may reduce demand for refined products and increase demand for alternative products; and
•adverse weather events resulting in decreased corn acres planted, which may reduce demand for anhydrous ammonia.

Similarly, any sustained decrease in the supply of crude oil, refined products, renewable fuels or anhydrous ammonia 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 the supply of and prices for crude oil and refined products;
•a lack of drilling services, equipment or skilled personnel available to producers to accommodate production needs;
•changes in laws, regulations, sanctions or taxation that directly or indirectly delay supply or production or increase the cost of production of refined products; and
•political unrest or hostilities, activist interference and the resulting governmental response thereto.

Failure to retain or replace current customers and renew existing contracts on comparable terms to maintain utilization of our pipeline and storage assets at current or more favorable rates could reduce our revenue and cash flows to levels that could 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 existing contracts or enter into new contracts on acceptable terms 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, renewable fuels or anhydrous ammonia 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 our customers and our ability to conduct our operations;
•competition for customers from companies with comparable assets and capabilities;
•scheduled turnarounds or unscheduled maintenance at refineries or production facilities of customers we serve;
•operational problems or catastrophic events affecting our assets or the 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;
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•a decision by our current customers to redirect products transported in our pipelines or stored in our terminals to markets not served by our pipelines or terminals, or to transport or store crude oil, refined products or anhydrous ammonia by means other than our pipelines or storage terminals; and
•a decision by our current customers to shut down, limit operations of or sell one or more of the refineries/production facilities we serve to a purchaser that elects not to use our pipelines or 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. In addition, there are fewer investors and lenders for master limited partnership debt and equity capital market issuances than there are for corporate issuances, and negative public sentiment toward the fossil fuel energy industry has led some investors and lenders to reduce or cease investing in and lending to fossil fuel energy companies. As a result, the cost of raising capital has increased, the availability of funds has diminished and certain lenders have, and others may, refuse to refinance existing debt on similar terms or at all and reduce, or in some cases cease to provide, funding to borrowers such as us.

In general, if we do not generate sufficient cash from operations to finance our expenditures and funding from external sources is not available when needed, or is available only on unfavorable terms, we may be unable to execute our growth strategy, complete future acquisitions or construction projects or take advantage of other business opportunities and may be required to reduce investments or capital expenditures or sell assets, which could have a material adverse effect on our revenues and results of operations, and we may not be able to satisfy our debt obligations or pay distributions to our unitholders.

Our future financial and operating flexibility may be adversely affected by our significant leverage, any future downgrades of our credit ratings, restrictions in our debt agreements and conditions in the financial markets beyond our control.
As of December 31, 2023, our consolidated debt was $3.4 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, an increase in interest rates on amounts borrowed under our Revolving Credit Agreement and an increase in certain fees under our Receivables Financing Agreement.

Certain affirmative and restrictive covenants in our debt agreements and other debt service obligations may adversely affect our future financial and operating flexibility. Our Revolving Credit Agreement contains customary restrictive covenants, such as limitations on indebtedness, liens, mergers, asset transfers and certain investing activities. For example, we must maintain a Consolidated Debt Coverage Ratio (as defined in the Revolving Credit Agreement) that does not exceed 5.00-to-1.00 and a minimum Consolidated Interest Coverage Ratio (as defined in the Revolving Credit 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 (as defined in our Revolving Credit Agreement) and could result in acceleration of our obligations under our Revolving Credit Agreement and potentially other agreements. Our Receivables Financing Agreement, senior notes and other debt obligations also contain various customary affirmative and negative covenants, default, indemnification and termination provisions, which 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 debt 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. For example, upon the occurrence of specified events under certain of our debt agreements, we would be prohibited from making 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.

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 the trading price of our units, as well as, our financial condition, results of operations, cash flows and ability to make distributions to unitholders.

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Changes in interest rates could adversely affect our business, access to credit and capital markets, and the trading price of our units.
We have significant exposure to increases in interest rates through variable rate provisions in certain of our debt instruments and our Series A, Series B and Series C Preferred Units. At December 31, 2023, we had approximately $3.4 billion of consolidated debt, of which $2.6 billion was at fixed interest rates and $0.8 billion was at variable interest rates. The distribution rates on our Series A, Series B and Series C Preferred Units have converted from fixed to floating rates. Our results of operations, cash flows and financial position could be materially adversely affected by significant changes in interest rates and uncertainty regarding the floating rates referenced in our variable rate debt instruments and preferred units could adversely affect the value of those financing arrangements. Please see “Quantitative and Qualitative Disclosures about Market Risk” for discussion of our market risk related to interest rates.

We plan to self-fund all of our expenses, distribution requirements and capital expenditures for 2024 using internally generated cash flows as we did for the full-years 2023, 2022 and 2021. An increase in interest rates may have a negative impact on our ability to access the capital markets, refinance existing debt or incur new debt at economically attractive rates, which could adversely affect our future growth by limiting our operational and financial flexibility.

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. A rising interest rate environment could have an adverse impact on our unit price and impair our ability to issue additional equity, incur new debt to fund growth, satisfy our existing debt obligations or pay distributions to our unitholders.

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 or anhydrous ammonia 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 may adversely affect 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, renewable fuels and anhydrous ammonia, availability to our customers of attractively priced alternative solutions for storage, transportation or supplies of crude oil, refined products, renewable fuels and anhydrous ammonia 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, unforeseen circumstances may adversely affect our ability to complete such projects as planned, if at all. 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 (such as extreme temperatures, hurricanes, tornadoes, storms, floods and earthquakes) or other events (such as equipment malfunctions, explosions, fires, spills or public health events) affecting our facilities or employees;
•denial or delay in issuing requisite regulatory approvals and/or permits;
•delay or increased costs to obtain right-of-way or other property rights;
•protests and other activist interference with planned or in-process projects;
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•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.

Any of the above factors may also adversely affect the facilities, operations or employees of counterparties, vendors, suppliers, contractors, sub-contractors or other third parties involved with our projects, which could result in non-performance or delay by, or disputes with, such parties.

We compete with other midstream service providers, including certain major energy and chemical companies, that 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 adversely affect our revenues and cash flows, thereby reducing our ability to make our quarterly distributions to unitholders.
We face competition in all aspects of our business and can give no assurances that we will be able to compete effectively against our competitors. Our competitors include major energy and chemical companies, some of which have greater financial resources, more pipelines or storage terminals, greater capacity pipelines or storage terminals and greater access to supply than we do. Certain of our competitors also have advantages in competing for acquisitions or other new business opportunities because of their financial resources and synergies in operations. As a consequence of increased competition in the industry or market conditions, some customers are and others may be in the future reluctant to renew or enter into long-term contracts or contracts that provide for minimum throughput amounts. Our inability to renew or replace a significant portion of our current contracts as they expire, to enter into contracts for newly acquired, constructed or expanded assets and to respond appropriately to changing market conditions would have a negative effect on our revenue, cash flows and ability to make quarterly distributions to our unitholders.

Our operations are subject to operational hazards and interruptions, and we cannot insure against or predict all potential losses and liabilities that might result therefrom.
Our operations and those of our customers and suppliers are subject to operational hazards and unforeseen interruptions due to adverse weather conditions, natural disasters (such as heat waves, freezing temperatures, 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. 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. If 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.

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 or 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 may 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 cannot fully eliminate counterparty credit risks. Any substantial increase in the nonpayment or nonperformance by our customers, vendors or other counterparties, or our inability to enforce our 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.

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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, some of our employees and those of our service providers, vendors and customers may travel or work from home or other remote-work locations, where cybersecurity protections may be less robust and cybersecurity procedures and safeguards may be less effective. Moreover, certain attacker techniques and goals, such as surveillance, intelligence gathering or extended reconnaissance, may remain undetected for an extended period of time, which can increase the breadth and negative impact of an incident. A significant failure, compromise, breach or interruption in our systems or those of third parties critical to our operations could result in a disruption of our operations; physical damage to our assets or the environment; physical, financial, or other harm to employees or others; safety incidents; damage to our reputation; loss of customers or revenues; increased costs for remedial actions; and potential litigation or regulatory fines. Failures, interruptions and similar events that result in the loss or improper disclosure of information maintained in our systems and networks or those of our vendors, including personnel, customer and vendor information, have in the past and may in the future require reporting under relevant contractual obligations and laws and regulations protecting personal data and privacy and could also subject us to litigation or other liability under relevant contractual obligations, laws and regulations. Our financial results could also be adversely affected if our systems are breached or an employee, vendor or customer causes our systems to fail, either as a result of inadvertent error or deliberate tampering with or manipulation of our systems.

Due to the continued acceleration of cyberattacks, generally and against our industry, regulatory actions by federal, state and local governmental agencies in the United States and in Mexico have increased. Evolving laws and regulations governing cybersecurity and data privacy and protection pose increasingly complex compliance challenges. Although we believe that we have robust cybersecurity procedures and other safeguards in place, we cannot guarantee their effectiveness, and a significant failure, compromise, breach or interruption in our systems or those of our customers or vendors could have a material effect on our operations and the operations of our customers and vendors. As threats continue to evolve and cybersecurity and data privacy and protection laws and regulations continue to develop, we have spent and expect to continue spending additional resources to continue to enhance our cybersecurity, data protection, business continuity and incident response measures, to investigate and remediate any vulnerabilities to, or consequences of, cyber incidents, as well as on regulatory compliance.

Disputes regarding a failure to maintain product quality specifications or other claims related to the operation of our assets and the services we provide to our customers may 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, 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.
Climate change laws or regulations enacted by the United States and other political bodies that increase costs, reduce demand or otherwise impede our operations, could, directly or indirectly, have an adverse effect on our business. Legislative and
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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. Specifically, certain regulatory changes have restricted, and future changes could restrict, our ability to expand our operations and have increased, and in the future could increase, our costs to operate and maintain our existing facilities by requiring that we measure and report our emissions, install new emission controls on our facilities, acquire allowances to authorize our emissions, pay taxes or fees related to our emissions or administer and manage an emissions program, among other things. The passage of climate change legislation and interpretation and action of federal and state regulatory bodies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to greenhouse gases, or restrictions on their use, may reduce volumes available to us for transportation and storage. These developments could have adverse effects on our business, financial position, results of operations and prospects.

In addition, certain of our blending operations subject us to potential requirements to purchase renewable fuels credits. Even though we attempt to mitigate such lost revenues or increased costs through the contracts we sign with our customers, we sometimes are not able to recover those revenues or mitigate the increased costs, and any such recovery depends on events beyond our control, including the outcome of future rate proceedings before the Federal Energy Regulatory Commission (FERC) or other regulators and the provisions of any final legislation or regulations. Reductions in our revenues or increases in our expenses as a result of climate change legislation or other regulatory initiatives could have adverse effects on our business, financial position, results of operations and prospects.

Finally, increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. Such events have had and may in the future have an adverse effect on our assets and operations, especially those located in coastal regions.

Public sentiment towards climate change, fossil fuels and sustainability could adversely affect our business, operations and ability to attract capital.
Our business plans are based upon the assumption that public sentiment and the regulatory environment will continue to enable the future development, transportation and use of carbon-based fuels. Negative public perception of the industry in which we operate and the influence of environmental activists and initiatives aimed at limiting climate change could interfere with our business activities, operations and access to capital. Activists concerned about the potential effects of climate change have directed their attention towards sources of funding for fossil fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital reducing or ceasing lending to or investing in companies in the fossil fuel energy industry, such as us. Having a more limited pool of lenders and investors has resulted in an increase in costs to raise capital, a decrease in the availability of new funding and a diminished ability to refinance existing debt at favorable rates for businesses such as ours, which could have a material adverse effect on our ability to meet our future capital needs, satisfy our debt obligations or pay distributions to our unitholders.

Members of the lending and investment communities 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 lending and investment communities screen companies such as ours for sustainability performance before lending to us or investing in our units. In response to the increasing pressure regarding sustainability disclosures and practices, we and other companies in our industry publish sustainability reports that are made available to lenders and investors. Such reports are used by some lenders and investors to inform their lending, 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 lender and investor sentiment toward us or our customers and to the diversion of capital to other industries, which would have a negative impact on our unit price and/or our access to and costs of capital. Such negative sentiment regarding our industry could influence consumer preference and decrease demand for the products we transport and store and may 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.

Our operations are subject to federal, state and local laws and regulations, in the U.S. and in Mexico, relating to environmental, health, safety and security that require us to make substantial expenditures.
Our operations are subject to increasingly stringent international, federal, state and local environmental, health, safety and security laws and regulations. Transporting, storing and distributing hazardous materials, including petroleum products, entails the risk of releasing these products into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies including for damages to natural resources, personal injury or property damages to private parties and significant business interruption. Further, our pipeline facilities are subject to the
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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, imposition of carbon taxes or methane fees, 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 may impose joint and several liability on us for the conduct of third parties or for actions that complied with applicable requirements when taken, regardless of negligence or fault. If we were to incur a significant liability pursuant to environmental, health, safety or security laws or regulations, such a liability could have a material adverse effect on our financial position.

We operate assets outside of the United States, which exposes us to different legal and regulatory requirements and additional risk.
A portion of our revenues are generated from our assets located in northern Mexico. Our operations are subject to various risks unique to Mexico that could have a material adverse effect on our business, results of operations and financial condition, including political and economic instability from civil unrest; labor strikes; war and other armed conflict; inflation; currency fluctuations, devaluation and conversion restrictions or other factors. Any deterioration of social, political, labor or economic conditions, including the increasing threat of terrorist organizations and drug cartels in Mexico, or affecting a customer with whom we do business, as well as difficulties in staffing, obtaining necessary equipment and supplies and managing foreign operations, may adversely affect our operations or financial results. We are also exposed to the risk of foreign and domestic governmental actions that may: impose additional costs on us; delay permits or otherwise impede our operations; limit or disrupt markets for our operations, restrict payments or limit the movement of funds; impose sanctions on or otherwise restrict our ability to conduct business with certain customers or persons or in certain countries; or result in the deprivation of contract rights. Our operations outside the United States may also be affected by changes in trade protection laws, policies and measures, and other regulatory requirements affecting trade and investment, including the Foreign Corrupt Practices Act and foreign laws prohibiting corrupt payments, as well as travel restrictions and import and export regulations.

We may be unable to obtain or renew permits necessary for our current or proposed operations, which could inhibit our ability to conduct or expand our business.
Our facilities operate under a number of federal, state and local permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. These limits and standards require a significant amount of monitoring, recordkeeping and reporting in order to demonstrate compliance with the underlying permit, license or approval. Noncompliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. In addition, public protest, political activism and responsive government intervention have made it more difficult for energy companies to acquire the permits required to complete planned infrastructure projects. A decision by a government agency to deny or delay issuing a new or renewed permit, license or approval, or to revoke or substantially modify an existing permit, license or approval, or to impose additional requirements on the renewal 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.

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Certain of our interstate common carrier pipelines are subject to regulation by the FERC and the Surface Transportation Board, 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.
Pursuant to the Interstate Commerce Act (ICA) and various other laws, the FERC regulates tariff rates and terms and conditions of service for interstate crude oil and refined products movements on common carrier pipelines. The FERC requires that these rates be just and reasonable and not unduly discriminatory 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 amounts refunded where such amounts were 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. The 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, which could result in a further change to the index. The 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, competition constrains our rates in various markets, which may force us to reduce certain rates to remain competitive.

Pursuant to the ICC Termination Act of 1995 (ITA), the Surface Transportation Board (STB) regulates interstate pipelines carrying products other than gas, oil or water, including the anhydrous ammonia we transport. Unlike the ICA, which allows the FERC to investigate a carrier’s rates on its own initiative, ITA prescribes the STB may only investigate issues in response to complaints by shippers and other interested parties. Further, carriers are not required by the ITA or the STB to report rates charged to transport anhydrous ammonia or other commodities, and the STB does not routinely collect such information. Adverse changes in the FERC’s or STB’s rate change methodologies or challenges to our rates that result in significant damages could negatively affect our cash flows, results of operations and our ability to make distributions to our unitholders.

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 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, 2023, our power costs equaled approximately $48.2 million, or 13% of our operating expenses for the year. We use mainly electric power at our pipeline pump stations and terminals, and such electric power is furnished by various utility companies. Requirements for utilities to use less carbon intensive power or to add pollution control devices also could cause our power costs to increase and our cash flows may be adversely affected, which could adversely affect our ability to make distributions to our unitholders.

We may be adversely affected by changes in the method of determining the London Interbank Offering Rate (LIBOR) or the replacement of LIBOR with an alternative reference rate, such as the Secured Overnight Financing Rate (SOFR).
The publication of non-U.S. dollar LIBOR rates ceased after publication on December 31, 2021 and the publication of U.S. dollar LIBOR rates for the most common tenors (overnight and one, three, six and twelve months) is ceased after publication on June 30, 2023. In addition, in March 2022, the Adjustable Interest Rate (LIBOR) Act (the “LIBOR Act”) was signed into law. This law provides a statutory fallback mechanism to replace LIBOR with a benchmark rate that is selected by the Federal Reserve Board and based on SOFR for certain contracts that reference LIBOR without adequate fallback provisions providing for a clearly defined replacement benchmark. On December 16, 2022, the Federal Reserve Board adopted a final rule to
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implement the LIBOR Act and established benchmark rates based on SOFR to replace LIBOR contracts governed by U.S. law that reference certain tenors of U.S. dollar LIBOR after June 30, 2023. The regulations include provisions that (i) provide a mechanism for the automatic replacement of LIBOR with the benchmark rate selected by the Federal Reserve Board; (ii) clarify who may contractually select a benchmark replacement for LIBOR; and (iii) ensure that contracts transitioning to the replacement benchmark rate selected by the Federal Reserve Board will not be interrupted or terminated following the replacement of LIBOR. On June 30, 2023, the publication of U.S. dollar LIBOR rates ceased and, beginning with the distribution period starting on September 15, 2023, the distribution rates on our Series A, Series B and Series C preferred units converted from a floating rate based on three-month LIBOR to three-month CME Term SOFR plus the applicable tenor spread adjustment of 0.26161%, in accordance with the guidance and the applicable rules and regulations governing such transition. The consequences of the transition away from LIBOR and the use of SOFR cannot be entirely predicted but could include an increase in the cost of our variable-rate indebtedness, our Series A, Series B and Series C preferred units and other commercial arrangements tied to LIBOR.

An impairment of goodwill or long-lived assets could reduce our earnings.
As of December 31, 2023, we had $0.7 billion of goodwill and $3.8 billion of long-lived assets, including property, plant and equipment, net and intangible assets, net. GAAP 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. Any event that causes a reduction in demand for our services could result in a reduction of our estimates of future cash flows and growth rates in our business, which could cause us to record an impairment charge to reduce the value of goodwill. Similarly, any event or change in circumstances that causes the carrying value of our long-lived assets to no longer be recoverable may require us to record an impairment charge to reduce the value of our long-lived assets. If we determine that either our goodwill or our long-lived assets are impaired, the resulting charge will reduce earnings and partners’ capital.

RISKS INHERENT IN AN INVESTMENT IN US
As a master limited partnership, we do not have the same flexibility that corporations and other business organizations may have to accumulate cash and prevent illiquidity in the future, which may 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. To the extent we issue additional units, 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 additional 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, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our 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. 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.
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In addition, our partnership agreement requires that unitholders 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 unitsin the event of a transaction, including a merger, sale, lease or conveyance of all or substantially all of our assets or business, which might adversely affect the holders of our preferred units.

Future issuances and sales of securities that rank equally with our preferred units, or the perception that such issuances and sales could occur, may cause prevailing market prices for our preferred units and our common units to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us. Furthermore, the payment of distributions on any additional units may increase the risk that we will not be able to make distributions at our prior per unit distribution levels. To the extent new units are senior to our common units, their issuance will increase the uncertainty of the payment of distributions on our common units.

If we do not pay distributions on our preferred units in any distribution period, we would be unable to declare or pay distributions on our common units until all unpaid preferred unit distribution obligations have been paid, and our common unitholders are not entitled to receive distributions for such prior period.
Our preferred units rank senior to our common units with respect to distribution rights and rights upon liquidation. If we do not pay the required distributions on our preferred units, we will be unable to declare or pay distributions on our common units. Distributions to our preferred unitholders are cumulative, so we must pay all unpaid accumulated preferred distributions before we can declare or pay any distributions to our common unitholders. Distributions to our common unitholders are not cumulative, therefore, 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 that would have accumulated in that quarter. The preferences and privileges granted to holders of our preferred units could adversely affect the market price for our common units and 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.
Our partnership agreement is governed by the laws of the State of Delaware. If a Delaware court were to determine that actions of a unitholder constituted participation in the “control” of our business, that unitholder would be held liable for our obligations to the same extent as a general partner. Under Delaware law, a 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, including a unitholder, who received such impermissible 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, our unitholders may be required to repay impermissible distributions upon the winding up of our partnership in the event that our assets are not distributed in accordance with Delaware law and a limited partner knows at the time that the distribution violated Delaware law. If a limited partner knowingly received an impermissible distribution, then such limited partner could be liable to repay the distribution for a period of three years from the impermissible distribution under applicable Delaware law.

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 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.

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TAX RISKS TO OUR UNITHOLDERS
If we were treated as a corporation for federal or state income tax purposes or we were otherwise subject to a material amount of entity-level taxation, then our cash available for distribution to unitholders would be substantially reduced.
The anticipated after-tax benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes. Despite the fact that we are a limited partnership under Delaware law, we will be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement.

If we were treated as a corporation, we would pay federal income tax at the corporate tax rate and would likely pay state and local income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our distributable cash flow would be substantially reduced. Additionally, at the state level, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. If we were treated as a corporation for federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, then our cash available for distribution to unitholders would be substantially reduced and there would be a material reduction in the after-tax return to our unitholders, likely causing a substantial reduction in the value of our units.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, and 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, which may be further interpreted by federal courts, 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 any such changes that are adverse to our interests 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. 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 or otherwise adversely affect our business, financial condition or results of operations.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes, penalties and interest directly from us. If we bear such payment, our cash available for distribution to our unitholders might be substantially reduced.
For tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes, penalties and interest resulting from such audit adjustment directly from us. To the extent possible under applicable rules, our general partner may pay such amounts directly to the IRS or, if we are eligible, elect to issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. No assurances can be made that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own common units in us during the tax year under audit. If, as a result of any such audit adjustment, we make payments of taxes, penalties and interest, our cash available for distribution to our unitholders could be substantially reduced.

Unitholders will be required to pay taxes on their share of our taxable income even if they do not receive cash distributions from us.
Unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their respective share of our taxable income, whether or not the unitholders receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their respective share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

Tax gain or loss on the disposition of our common units could be different than expected.
A unitholder who sells units will recognize a gain or loss equal to the difference between the amount realized and the unitholder’s tax basis in those units. Prior distributions to the unitholder in excess of the total net taxable income with respect to a common unit will reduce the unitholder’s tax basis in that unit. As a result, the selling unitholder can recognize a gain if such unit is sold at a price greater than the unitholder’s tax basis in that unit, even if the price the unitholder receives is less than the unit’s original cost. A substantial portion of the amount realized, even if there is a net taxable loss realized on the sale, may be ordinary income to the selling unitholder. In addition, because the amount realized will include a unitholder’s share of our nonrecourse liabilities, a unitholder may incur a tax liability upon a sale of common units in excess of the amount of cash it receives from the sale.

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Unitholders may be subject to limitations on their ability to deduct interest expense incurred by us.
Our ability to deduct interest paid or accrued on indebtedness properly allocable to a trade or business (business interest), may be limited in certain circumstances. Should our ability to deduct business interest be limited, the amount of taxable income allocated to our unitholders in the taxable year in which the limitation is in effect may increase. However, in certain circumstances, a unitholder may be able to utilize a portion of a business interest deduction subject to this limitation in future taxable years. Prospective unitholders should consult their tax advisors regarding the impact of this business interest deduction limitation on an investment in our units.

Tax-exempt entities face unique tax issues from owning our units that may result in adverse tax consequences to them.
Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (IRAs) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Tax-exempt entities should consult a tax advisor before investing in our units.

Non-U.S. unitholders will be subject to U.S. taxes and withholding on 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 effectively connected income and subject to U.S. federal income tax. Additionally, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate.

Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person. Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor. Quarterly distributions made to our non-U.S. unitholders will also be subject to withholding under these rules to the extent a portion of a distribution is attributable to an amount in excess of our cumulative net income that has not previously been distributed. We intend to treat all of our distributions as being in excess of our cumulative net income for such purposes and subject to the additional 10% withholding tax. The Treasury regulations further provide that these rules will generally not apply to transfers of, or distributions on, interests in a publicly traded partnership occurring before January 1, 2023, and after that date, if effected through a broker, the obligation to withhold is imposed on the transferor’s broker. Current and prospective non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common and preferred units.

We will treat each purchaser of our common units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
Because we cannot match transferors and transferees of our common units, we have adopted depreciation and amortization positions that may not conform with all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the unitholder’s tax returns.

Unitholders will likely be subject to state and local taxes and return filing requirements as a result of investing in our units.
In addition to federal income taxes, unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. Unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We may own property or conduct business in other states or foreign countries in the future. It is each unitholder’s responsibility to file all federal, state and local tax returns.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our common unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. Treasury regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our common unitholders.

We have adopted certain valuation methodologies in determining a common unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methods or the resulting allocations and such a challenge could adversely affect the value of our common units.
In determining the items of income, gain, loss and deduction allocable to our common unitholders, we must routinely determine
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the fair market value of our respective assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our respective assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of taxable income or loss being allocated to our common unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our common unitholders’ tax returns without the benefit of additional deductions.

A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller”) may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

Treatment of distributions on our preferred units as guaranteed payments for the use of capital is uncertain 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 (currently available for taxable years beginning after December 31, 2017, and ending on or before December 31, 2025), Treasury regulations provide that income attributable to a guaranteed payment for the use of capital is not eligible for the 20% deduction for qualified business income. As a result, income attributable to a guaranteed payment for use of capital recognized by holders of our preferred units is not eligible for the 20% deduction for qualified business income.

A holder of preferred units will be required to recognize gain or loss on a sale of preferred units equal to the difference between the amount realized by such holder and such holder’s tax basis in the preferred units sold. The amount realized generally will equal the sum of the cash and the fair market value of other property such holder receives in exchange for such preferred units. Subject to general rules requiring a blended basis among multiple partnership interests, the tax basis of a preferred unit will generally be equal to the sum of the cash and the fair market value of other property paid to acquire such preferred unit. Gain or loss recognized on the sale or exchange of a preferred unit held for more than one year generally will be taxable as long-term capital gain or loss. Because holders of preferred units will generally not be allocated a share of our items of depreciation or amortization, it is not anticipated that such holders would be required to re-characterize any portion of their gain as ordinary income as a result of the recapture rules.

Investment in the preferred units by tax-exempt investors, such as employee benefit plans and IRAs, and non-U.S. persons raises issues unique to them. The treatment of guaranteed payments for the use of capital to tax-exempt investors is not certain and the income resulting from such payments may be treated as unrelated business taxable income for U.S. federal income tax purposes. A non-U.S. holder’s income from guaranteed payments and any gain from the sale or disposition of our units may be considered to be effectively connected income and subject to U.S. federal income tax. Distributions and any gain from the sale or disposition of our preferred units to non-U.S. holders of preferred units may be subject to withholding taxes. If the amount of withholding exceeds the amount of U.S. federal income tax actually due, non-U.S. holders of preferred units may be required to file U.S. federal income tax returns in order to seek a refund of such excess.

All holders of our preferred units are urged to consult a tax advisor with respect to the consequences of owning and selling our preferred units.

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ITEM 1B.    UNRESOLVED STAFF COMMENTS
None.

ITEM 1C.    CYBERSECURITY
Risk Management and Strategy
We have developed an information security program to assess, identify and manage material risks from cybersecurity threats. Our program includes policies and procedures that identify how security measures and controls are developed, implemented and maintained. We have aligned our cybersecurity program to the NIST Cybersecurity Framework and we assess our program against this standard annually. We are regulated by the Transportation Security Administration (TSA) as a pipeline infrastructure company and are required to comply with all TSA cybersecurity regulations. We use industry standard metrics to assess the criticality of software, data assets and operational technology.

We conduct periodic cyber risk assessments and assessments of our operational-technology network. We use these risk assessments together with risk-based analysis and judgment to determine which security controls to use to address identified risks. We also complete internal and external testing of software, hardware, defensive capabilities and other information security systems as advised by industry standards, and we use the test results to address identified vulnerabilities. We regularly conduct cyber threat exercises, which help us identify and address any gaps in our incident response plan. These exercises also help us practice sound decision-making skills to enhance our ability to react effectively during a material cyber event.

We rely on third-party software, third-party service providers and third-party applications to run certain aspects of our business and to aid in the development, implementation and maintenance of our security measures and controls. We regularly conduct third-party security audits and use vendor management programs to ensure that third-party software, service providers and applications comply with our vendor management program.

We consider the following factors, among others, to identify and manage material risks: (i) the likelihood of a risk occurring; (ii) the impact of a risk on us and others, including the likelihood of enforcement actions alleging potential regulatory violations, sanctions, litigation and other legal risks; and (iii) the controls we have applied to mitigate a risk’s likelihood and impact. When selecting controls, we consider the likelihood and impact of identified risks, regulatory and other legal requirements, the feasibility of implementing a control and the potential impact of a control on our operations.

We use the following controls, among others, to mitigate the material cyber risks that we face: endpoint threat detection and response (EDR), identity and access management (IAM), logging and monitoring involving the use of security information and event management (SIEM), multi-factor authentication (MFA), firewalls and intrusion detection and prevention, a vendor management program (VMP) and vulnerability and patch management.

We use third-party security firms to provide or operate certain controls and technology systems. We use third parties to conduct assessments, such as monitoring vulnerability scans and penetration testing. We address cybersecurity threats related to our third-party technology and services through several processes, including pre-acquisition due diligence, contractual obligations and performance monitoring.

We have a written incident response plan and we conduct tabletop exercises to enhance incident response preparedness. We use business continuity and disaster recovery plans to prepare for a potential disruption in the technology we rely on. We train our employees on cybersecurity awareness when they are hired and conduct additional training annually thereafter.

Our executive management team has the day-to-day responsibility of assessing and managing our overall risk exposure, and our Board of Directors oversees those efforts. We have integrated cybersecurity risk into our overall risk management systems and processes. Our full Board has direct oversight over our cybersecurity risk management. The Board interfaces regularly with management and receives periodic reports on our areas of risk, including cybersecurity. Management interacts regularly with our Cyber Risk Governance Committee (CRGC), which meets regularly and oversees the effectiveness of our cybersecurity program. We make additional disclosures regarding our assessment, identification and management of cybersecurity risks below under the caption “Governance,” and we hereby incorporate by reference those disclosures into this discussion of “Risk Management and Strategy.”

We (or third parties we rely on) may not be able to fully, continuously and effectively implement security controls as designed or intended. We use a risk-based approach and the judgment of our CRGC, management and third parties with extensive expertise in cyber risk management to determine which security controls we implement. It is possible we may not implement appropriate controls if we do not properly identify or inadvertently underestimate a particular risk. In addition, security controls, no matter how well designed or implemented, may only mitigate but not fully eliminate risks. Further, when security tools or third parties detect events, it may take us and our third parties time to analyze and understand the risks — and to determine the proper procedural steps to mitigate the effects of such risks — before we can effectively act upon the events.

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Impacts of Material Risk.
Pipeline operators have faced and continue to face risks from threat actors that focus their attacks on critical infrastructure assets and disruption to operations. We also face risks from ransomware groups that steal data, encrypt systems and demand a payment. We have cybersecurity protocols and procedures in place—and we rely on third-party software, hardware and vendors—to manage critical aspects of our operations. While we have controls in place to address these risks, if these risks occur, the impact could be material, such as in the event of a cybersecurity incident causing the loss of operational control, disruption of our operations, a demand for ransomware payment or physical damage to our assets or the environment.

Additionally, in Item 1A. “Risk Factors” under the caption “Risks Related to our Business,” we discuss forward-looking cybersecurity risks that could have a material impact on us. Our disclosures in Item 1A. “Risk Factors” should be read in conjunction with this Item 1C.

Governance
Our Board of Directors has direct oversight over key risks that are broadly applicable across NuStar’s businesses, including cybersecurity risk management. At each regularly scheduled meeting of the Board, the Board receives reports from our President and Chief Executive Officer (CEO) and Senior Vice President–Chief Information Officer and Controller (CIO) regarding our cybersecurity program. These reports include (i) regulatory updates, which include information on regulatory initiatives promulgated by governmental agencies and our compliance with such initiatives, and (ii) quarterly metrics and data, which include information on employee training, threats, incidents, preventive practices (e.g., patch installation), tabletop exercises, cybersecurity policies and cybersecurity program resources, risks and controls.

Our CIO is the management position with primary responsibility for the development, operation and maintenance of our information security program. He reports directly to our CEO. Certain of the CIO’s direct reports have extensive expertise in the area of cyber risk management.

Our CRGC is composed of management representatives from key functions across our company. Our CIO serves as the Chair of the CRGC. The CRGC meets regularly and oversees the effectiveness of our cybersecurity program. The CRGC operates to deliver management-level oversight of cybersecurity matters. The CRGC reports regularly to our executive management team. The Chair of our CRGC reports regularly to our Board of Directors.

We use governance, risk and compliance tools to assess, identify and manage cybersecurity risks. To address potential cybersecurity events, we have developed an incident response plan that defines protocols and processes for effectively managing our response to an event, including protocols for the escalation of critical information to management, key company personnel and the Board.

ITEM 3.    LEGAL PROCEEDINGS

We incorporate by reference into this Item 3. our disclosures in Note 14 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” under the caption, “Contingencies.”

ITEM 4.    MINE SAFETY DISCLOSURES
Not applicable.
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PART II

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

Series A, B and C Preferred Units
Information on our 8.50% Series A, 7.625% Series B and 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (collectively the Series A, B and C Preferred Units) is shown below:
UnitsUnits Issued and Outstanding as of December 31, 2023Optional Redemption Date/Date When Distribution Rate Became FloatingFloating Annual Rate (as a Percentage of the $25.00 Liquidation Preference Per Unit)
ITEM 7A.Series A Preferred UnitsQUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK9,060,000December 15, 2021
Three-month LIBOR(a) plus 6.766%
Series B Preferred Units15,400,000June 15, 2022
Three-month LIBOR(a) plus 5.643%
Series C Preferred Units6,900,000December 15, 2022
Three-month LIBOR(a) plus 6.88%
Interest Rate Risk(a)Beginning with the distribution period from September 15, 2023 to December 14, 2023, LIBOR was replaced with the corresponding CME Term SOFR plus the applicable tenor spread adjustment of 0.26161%.

Common Units
Our common units are listed and traded on the New York Stock Exchange under the symbol “NS.” At the close of business on February 7, 2024, we had 344 holders of record of our common units.

Our partnership agreement requires that we distribute all Available Cash to our common limited partners each quarter. Available Cash is generally defined in the partnership agreement as all cash receipts less cash disbursements, including distributions to our preferred unit holders, and cash reserves established by our general partner, in its sole discretion.

See Note 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on our Series A, B and C Preferred Units and common units.
50

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.

2514
*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, 2018, and its relative performance is tracked through December 31, 2023.
As of December 31,
201820192020202120222023
NuStar Energy L.P.$100.00 $135.03 $84.77 $103.03 $114.84 $147.51 
S&P 500 Index100.00 131.49 155.68 200.37 164.08 207.21 
Alerian MLP Index100.00 106.56 75.99 106.51 139.44 176.47 

Sales of Unregistered Securities
During the fourth quarters of 2022 and 2021, NuStar Energy issued an aggregate of 3,120 common units and 5,509 common units, respectively, in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof, upon the vesting of outstanding awards under a long-term incentive plan.

ITEM 6.    RESERVED


51

ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

INTEREST RATE RISK
Debt
We manage our exposure to changing interest rates principally through the use of a combination of fixed-rate debt and variable-rate debt. In addition, we utilize forward-starting interest rate swap agreements to lock in the rate on the interest payments related to forecasted debt issuances. Borrowings under our variable-rate debt expose us to increases in interest rates.


Please referOn June 30, 2023, we amended our $1.0 billion unsecured revolving credit agreement (as amended, the Revolving Credit Agreement), primarily to extend the maturity date from April 27, 2025 to January 27, 2027. On June 29, 2023, we amended our $100.0 million receivables financing agreement (as amended, the Receivables Financing Agreement) to extend the scheduled termination date from January 31, 2025 to July 1, 2026. See Note 2 and Note 1612 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a more detailed discussion of our interest rate swaps. information.

The following tables present principal cash flows and related weighted-average interest rates by expected maturity dates for our long-term debt:
debt, excluding finance leases:
 December 31, 2023
 Expected Maturity Dates  
 20242025202620272028There-
after		TotalFair
Value
 (Thousands of Dollars, Except Interest Rates)
Fixed-rate debt$— $600,000 $500,000 $550,000 $— $922,140 $2,572,140 $2,595,857 
Weighted-average rate— 5.8 %6.0 %5.6 %— 6.3 %6.0 %— 
Variable-rate debt$— $— $69,800 $343,000 $— $402,500 $815,300 $830,450 
Weighted-average rate— — 7.0 %8.0 %— 12.4 %10.1 %— 
 December 31, 2017
 Expected Maturity Dates    
 2018 2019 2020 2021 2022 
There-
after
 Total 
Fair
Value
 (Thousands of Dollars, Except Interest Rates)
Long-term Debt:               
Fixed-rate$350,000
 $—
 $450,000
 $300,000
 $250,000
 $952,500
 $2,302,500
 $2,355,535
Weighted-average
interest rate
8.4% —
 4.8% 6.8% 4.8% 6.5% 6.3%  
Variable-rate$—
 $—
 $955,611
 $—
 $—
 $365,440
 $1,321,051
 $1,322,087
Weighted-average
interest rate
—
 —
 3.1% —
 —
 1.7% 2.7%  


 December 31, 2022
 Expected Maturity Dates  
 20232024202520262027There-
after		TotalFair
Value
 (Thousands of Dollars, Except Interest Rates)
Fixed-rate debt$— $— $600,000 $500,000 $550,000 $922,140 $2,572,140 $2,478,720 
Weighted-average rate— — 5.8 %6.0 %5.6 %6.3 %6.0 %— 
Variable-rate debt$— $— $300,900 $— $— $402,500 $703,400 $690,944 
Weighted-average rate— — 6.7 %— — 10.8 %9.0 %— 

 December 31, 2016
 Expected Maturity Dates    
 2017 2018 2019 2020 2021 
There-
after
 Total 
Fair
Value
 (Thousands of Dollars, Except Interest Rates)
Long-term Debt:               
Fixed-rate$—
 $350,000
 $—
 $450,000
 $300,000
 $652,500
 $1,752,500
 $1,821,261
Weighted-average
interest rate
—
 8.2% —
 4.8% 6.8% 6.5% 6.4%  
Variable-rate$—
 $58,400
 $838,992
 $—
 $—
 $365,440
 $1,262,832
 $1,263,501
Weighted-average
interest rate
—
 1.6% 2.5% —
 —
 0.7% 1.9%  
Series A, B and C Preferred Units
Distributions on our 8.50% Series A, 7.625% Series B and 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (collectively the Series A, B and C Preferred Units) are payable out of any legally available funds, accrue and are cumulative from the original issuance dates, and are payable on the 15th day (or the next business day) of each of March, June, September and December of each year to holders of record on the first business day of each payment month. The following table presentsSeries A, B and C Preferred Units expose us to changes in interest rates as the distribution rates on these units converted to a floating rate on December 15, 2021, June 15, 2022 and December 15, 2022, respectively. Based upon the 9,060,000 Series A Preferred Units, 15,400,000 Series B Preferred Units and 6,900,000 Series C Preferred Units outstanding as of December 31, 2023 and the $25.00 liquidation preference per unit, a change of 1.0% in interest rates would increase or decrease the annual distributions on our Series A, B and C Preferred Units by an aggregate amount of $7.8 million. See Note 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information regardingon our forward-starting interest rate swap agreements:Series A, B and C Preferred Units.

Notional Amount as of December 31, Period of Hedge Weighted-Average Fixed Rate Fair Value as of December 31,
2017 2016   2017 2016
(Thousands of Dollars)     (Thousands of Dollars)
$350,000
 $350,000
 04/2018 - 04/2028 2.6% $(5,394) $(1,333)
250,000
 250,000
 09/2020 - 09/2030 2.8% (4,594) 15
$600,000
 $600,000
   2.7% $(9,988) $(1,318)
Commodity Price RiskCOMMODITY PRICE RISK
Since the operations of our fuels marketing segment expose us to commodity price risk, we also use derivative instruments to attempt to mitigate the effects of commodity price fluctuations. The derivative instruments we use consist primarily of commodity futures and swap contracts. Please refer to our derivativeDerivative financial instruments accounting policy in Note 2 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further information on our various types of derivatives.
We have a risk management committee that oversees our trading policies and procedures and certain aspects of risk management. Our risk management committee also reviews all new risk management strategies in accordanceassociated with our risk management policy, as approved by our board of directors.

The commodity contracts disclosed below represent only those contracts exposed to commodity price risk at the endwere not material for any periods presented.
52

 December 31, 2017
 
Contract
Volumes
 Weighted Average 
Fair Value of
Current
Asset (Liability)
Pay Price Receive Price 
 
(Thousands
of Barrels)
     
(Thousands of
Dollars)
Fair Value Hedges:       
Futures – long:       
     (refined products)2
 $86.88
 N/A
 $—
Futures – short:
 
 
 
     (refined products)5
 N/A
 $85.59
 $(6)
Swaps – short:
 
 
 
     (refined products)149
 N/A
 $55.79
 $(106)
 
 
 
 
Economic Hedges and Other Derivatives:
 
 
 
Futures – long:
 
 
 
     (refined products)10
 $86.13
 N/A
 $7
Futures – short:
 
 
 
     (refined products)14
 N/A
 $85.76
 $(16)
Swaps – long:
 
 
 
     (refined products)196
 $55.05
 N/A
 $264
Swaps – short:
 
 
 
     (refined products)199
 N/A
 $53.76
 $(525)
        
Total fair value of open positions exposed to
commodity price risk
      $(382)



 December 31, 2016
 
Contract
Volumes
 Weighted Average 
Fair Value of
Current
Asset (Liability)
Pay Price Receive Price 
 
(Thousands
of Barrels)
     
(Thousands of
Dollars)
Fair Value Hedges:       
Futures – long:       
     (crude oil and refined products)47
 $55.53
 N/A
 $2
Futures – short:
 
 
 
     (crude oil and refined products)107
 N/A
 $58.79
 $(243)
Swaps – long:
 
 
 
     (refined products)84
 $45.99
 N/A
 $141
Swaps – short:
 
 
 
     (refined products)573
 N/A
 $41.87
 $(3,322)
 
 
 
 
Economic Hedges and Other Derivatives:
 
 
 
Futures – long:
 
 
 
     (crude oil and refined products)18
 $72.06
 N/A
 $10
Futures – short:
 
 
 
     (crude oil and refined products)9
 N/A
 $71.88
 $(7)
Swaps – long:
 
 
 
     (refined products)869
 $42.20
 N/A
 $4,737
Swaps – short:
 
 
 
     (refined products)874
 N/A
 $41.40
 $(5,459)
Forward purchase contracts:
 
 
 
     (crude oil)310
 $52.78
 N/A
 $499
Forward sales contracts:
 
 
 
     (crude oil)310
 N/A
 $52.76
 $(507)
        
Total fair value of open positions exposed to
commodity price risk
      $(4,149)








ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


INDEX
54
55
58
59
60
61
62
63
1. Organization and Operations
63
2. Summary of Significant Accounting Policies
64
3. New Accounting Pronouncements
70
4. Dispositions and Impairments
70
5. Revenue from Contracts with Customers
72
6. Allowance for Credit Losses
73
7. Inventories
73
8. Property, Plant and Equipment
74
9. Intangible Assets
74
10. Goodwill
74
11. Accrued Liabilities
75
12. Debt
75
13. Health, Safety and Environmental Matters
78
14. Commitments and Contingencies
79
15. Lease Assets and Liabilities
79
16. Derivatives and Fair Value Measurements
81
17. Series D Cumulative Convertible Preferred Units
82
18. Partners’ Equity
85
19. Net Income (Loss) per Common Unit
87
20. Supplemental Cash Flow Information
88
21. Employee Benefit Plans
89
22. Unit-based Compensation
94
23. Income Taxes
97
24. Segment Information
99
25. Subsequent Event
100

53

Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining effective internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934. Our management assessed the effectiveness of NuStar Energy L.P.’s internal control over financial reporting as of December 31, 2017.2023. In its evaluation, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (2013). Based on this assessment, management believes that, as of December 31, 2017,2023, our internal control over financial reporting was effective based on those criteria.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Management’s evaluation of and conclusion regarding the effectiveness of our internal control over financial reporting excludes the internal control over Navigator Energy Services, LLC acquired on May 4, 2017 (as described in Note 4), which contributed approximately 2% of our total revenues for the year ended December 31, 2017 and accounted for approximately 23% of our total assets as of December 31, 2017. We plan to fully integrate these assets and operations into our internal control over financial reporting in 2018.
The effectiveness of internal control over financial reporting as of December 31, 20172023 has been audited by KPMG LLP, the independent registered public accounting firm who audited our consolidated financial statements included in this Form 10-K. KPMG LLP’s attestation on the effectiveness of our internal control over financial reporting appears on page 69.57.

54

Report of Independent Registered Public Accounting Firm


TheTo the Board of Directors of NuStar GP, LLC
and Unitholders of
NuStar Energy L.P.:


Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of NuStar Energy L.P. (a Delaware limited partnership) and subsidiaries (the “Partnership”)Partnership) as of December 31, 20172023 and 2016,2022, the related consolidated statements of income, comprehensive income, cash flows, and partners’ equity and cash flowsmezzanine equity for each of the years in the three‑yearthree-year period ended December 31, 2017,2023, and the related notes (collectively, the “consolidatedconsolidated financial statements”)statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 20172023 and 2016,2022, and the results of its operations and its cash flows for each of the years in the three‑yearthree-year period ended December 31, 2017,2023, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”)(PCAOB), the Partnership’s internal control over financial reporting as of December 31, 2017,2023, based on criteria established in Internal Control -– Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 28, 201822, 2024 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, 2023 was $3,283 million, or 67% 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
55

the evaluation of subjective qualitative considerations, such as alternative customers and alternative uses for the asset or asset group, and the Partnership's intent for the asset or asset group.

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

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

/s/ KPMG LLP

San Antonio, Texas
February 28, 201822, 2024

56


Report of Independent Registered Public Accounting Firm
The
To the Board of Directors of NuStar GP, LLC
and Unitholders of
NuStar Energy L.P.:


Opinion on Internal Control Over Financial Reporting
We have audited NuStar Energy L.P. (a Delaware limited partnership) and subsidiaries’subsidiaries' (the “Partnership”)Partnership) internal control over financial reporting as of
December 31, 2017,2023, based on criteria established in Internal Control -– Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2023, based on criteria established in Internal Control -– Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”)(PCAOB), the consolidated balance sheets of the Partnership as of December 31, 20172023 and 2016,2022, the related consolidated statements of income, comprehensive income, cash flows, and partners’ equity and cash flowsmezzanine equity for each of the years in the three-year period ended December 31, 2017,2023, and the related notes (collectively, the “consolidatedconsolidated financial statements”)statements), and our report dated February 28, 201822, 2024 expressed an unqualified opinion on those consolidated financial statements.
The Partnership acquired Navigator Energy Services, LLC during 2017, and management excluded from its assessment of the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2017, Navigator Energy Services, LLC’s internal control over financial reporting whose financial statements reflect 23 percent of total assets and 2 percent of total revenues of the related consolidated financial statement amounts of NuStar Energy L.P. as of and for the year ended December 31, 2017. Our audit of internal control over financial reporting of the Partnership also excluded an evaluation of the internal control over financial reporting of Navigator Energy Services, LLC.
Basis for Opinion
The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’sManagement's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

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

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

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

/s/ KPMG LLP
San Antonio, Texas
February 28, 201822, 2024

57

NUSTAR ENERGY L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars, Except Unit Data)
December 31, December 31,
2017 2016 20232022
Assets   
Current assets:   
Current assets:
Current assets:
Cash and cash equivalents$24,292
 $35,942
Accounts receivable, net of allowance for doubtful accounts of $9,948 and $7,756
as of December 31, 2017 and 2016, respectively
176,570
 170,293
Receivable from related party205
 317
Cash and cash equivalents
Cash and cash equivalents
Accounts receivable, net
Inventories26,857
 37,945
Other current assets22,508
 132,686
Inventories
Inventories
Prepaid and other current assets
Prepaid and other current assets
Prepaid and other current assets
Total current assets
Total current assets
Total current assets250,432
 377,183
Property, plant and equipment, at cost6,243,481
 5,435,278
Accumulated depreciation and amortization(1,942,548) (1,712,995)
Property, plant and equipment, net4,300,933
 3,722,283
Intangible assets, net784,479
 127,083
Goodwill1,097,475
 696,637
Deferred income tax asset233
 2,051
Other long-term assets, net
Other long-term assets, net
Other long-term assets, net101,681
 105,308
Total assets$6,535,233
 $5,030,545
Liabilities and Partners’ Equity   
Liabilities, Mezzanine Equity and Partners’ Equity
Liabilities, Mezzanine Equity and Partners’ Equity
Liabilities, Mezzanine Equity and Partners’ Equity
Current liabilities:
Current liabilities:
Current liabilities:   
Accounts payable$145,932
 $118,686
Short-term debt35,000
 54,000
Current portion of long-term debt349,990
 —
Accounts payable
Accounts payable
Current portion of finance leases
Current portion of finance leases
Current portion of finance leases
Accrued interest payable
Accrued interest payable
Accrued interest payable40,449
 34,030
Accrued liabilities61,578
 60,485
Taxes other than income tax14,385
 15,685
Income tax payable4,172
 6,510
Total current liabilities651,506
 289,396
Long-term debt, less current portion3,263,069
 3,014,364
Total current liabilities
Total current liabilities
Long-term debt, less current portion of finance leases
Deferred income tax liability
Deferred income tax liability
Deferred income tax liability22,272
 22,204
Other long-term liabilities118,297
 92,964
Total liabilities
Commitments and contingencies (Note 14)
 
Partners’ equity (Note 19):   
Preferred limited partners756,603
 218,400
Common limited partners (93,176,683 and 78,616,228 common units outstanding
as of December 31, 2017 and 2016, respectively)
1,770,587
 1,455,642
General partner37,826
 31,752
Commitments and contingencies (Note 14)
Commitments and contingencies (Note 14)
Series D preferred limited partners (0 and 16,346,650 units outstanding as of
December 31, 2023 and 2022, respectively) (Note 17)
Series D preferred limited partners (0 and 16,346,650 units outstanding as of
December 31, 2023 and 2022, respectively) (Note 17)
Series D preferred limited partners (0 and 16,346,650 units outstanding as of
December 31, 2023 and 2022, respectively) (Note 17)
Partners’ equity (Note 18):
Partners’ equity (Note 18):
Partners’ equity (Note 18):
Preferred limited partners:
Preferred limited partners:
Preferred limited partners:
Series A (9,060,000 units outstanding as of December 31, 2023 and 2022)
Series A (9,060,000 units outstanding as of December 31, 2023 and 2022)
Series A (9,060,000 units outstanding as of December 31, 2023 and 2022)
Series B (15,400,000 units outstanding as of December 31, 2023 and 2022)
Series C (6,900,000 units outstanding as of December 31, 2023 and 2022)
Common limited partners (126,516,713 and 110,818,718 units outstanding
as of December 31, 2023 and 2022, respectively)
Accumulated other comprehensive loss(84,927) (94,177)
Accumulated other comprehensive loss
Accumulated other comprehensive loss
Total partners’ equity2,480,089
 1,611,617
Total liabilities and partners’ equity$6,535,233
 $5,030,545
Total partners’ equity
Total partners’ equity
Total liabilities, mezzanine equity and partners’ equity
See Notes to Consolidated Financial Statements.

58


NUSTAR ENERGY L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of Dollars, Except Unit and Per Unit Data)

 Year Ended December 31,
 2017 2016 2015
Revenues:     
Service revenues$1,128,726
 $1,083,165
 $1,114,153
Product sales685,293
 673,517
 969,887
Total revenues1,814,019
 1,756,682
 2,084,040
Costs and expenses:     
Cost of product sales651,599
 633,653
 907,574
Operating expenses (excluding depreciation and amortization expense):     
Third parties449,670
 426,686
 337,466
Related party—
 21,681
 135,565
Total operating expenses449,670
 448,367
 473,031
General and administrative expenses (excluding depreciation and amortization expense):     
Third parties112,240
 88,324
 35,752
Related party—
 10,493
 66,769
Total general and administrative expenses112,240
 98,817
 102,521
Depreciation and amortization expense264,232
 216,736
 210,210
Total costs and expenses1,477,741
 1,397,573
 1,693,336
Operating income336,278
 359,109
 390,704
Interest expense, net(173,083) (138,350) (131,868)
Other (expense) income, net(5,294) (58,783) 61,822
Income from continuing operations before income tax expense157,901
 161,976
 320,658
Income tax expense9,937
 11,973
 14,712
Income from continuing operations147,964
 150,003
 305,946
Income from discontinued operations, net of tax—
 —
 774
Net income$147,964
 $150,003
 $306,720
Basic and diluted net income per common unit:     
Continuing operations$0.64
 $1.27
 $3.29
Discontinued operations—
 —
 0.01
Total (Note 20)$0.64
 $1.27
 $3.30
Basic weighted-average common units outstanding88,825,964
 78,080,484
 77,886,078
      
Diluted weighted-average common units outstanding88,825,964
 78,113,002
 77,886,078
 Year Ended December 31,
 202320222021
Revenues:
Service revenues$1,155,567 $1,120,249 $1,157,410 
Product sales478,620 562,974 461,090 
Total revenues1,634,187 1,683,223 1,618,500 
Costs and expenses:
Costs associated with service revenues:
Operating expenses (excluding depreciation and amortization expense)371,689 364,989 388,078 
Depreciation and amortization expense250,982 251,878 266,588 
Total costs associated with service revenues622,671 616,867 654,666 
Costs associated with product sales407,793 486,947 417,413 
Goodwill impairment loss— — 34,060 
Other impairment losses— 46,122 154,908 
General and administrative expenses (excluding depreciation and amortization expense)129,846 117,116 113,207 
Other depreciation and amortization expense4,728 7,358 7,792 
Total costs and expenses1,165,038 1,274,410 1,382,046 
Gain on sale of assets41,075 — — 
Operating income510,224 408,813 236,454 
Interest expense, net(241,364)(209,009)(213,985)
Other income, net10,215 26,182 19,644 
Income before income tax expense279,075 225,986 42,113 
Income tax expense5,412 3,239 3,888 
Net income$273,663 $222,747 $38,225 
Basic and diluted net income (loss) per common unit (Note 19)$0.72 $0.36 $(0.99)
Basic and diluted weighted-average common units outstanding116,851,373 110,341,206 109,585,635 
See Notes to Consolidated Financial Statements.



59

NUSTAR ENERGY L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Thousands of Dollars)

 Year Ended December 31,
 2017 2016 2015
Net income$147,964
 $150,003
 $306,720
Other comprehensive income (loss):     
Foreign currency translation adjustment17,466
 (8,243) (31,987)
Net loss on pension and other postretirement benefit adjustments, net of income tax benefit of $184, $60 and $0(6,170) (2,850) —
Net (loss) gain on cash flow hedges(2,046) 5,710
 11,105
Total other comprehensive income (loss)9,250
 (5,383) (20,882)
Comprehensive income$157,214
 $144,620
 $285,838
Year Ended December 31,
202320222021
Net income$273,663 $222,747 $38,225 
Other comprehensive income (loss) (Note 18):
Foreign currency translation adjustment728 41,823 601 
Net gain (loss) on pension and other postretirement benefit adjustments, net of income tax expense of $69, $24 and $615,371 (1,556)16,413 
Reclassification of loss on cash flow hedges2,581 2,106 5,664 
Total other comprehensive income8,680 42,373 22,678 
Comprehensive income$282,343 $265,120 $60,903 
See Notes to Consolidated Financial Statements.

60


NUSTAR ENERGY L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Dollars)
 Year Ended December 31,
 2017 2016 2015
Cash Flows from Operating Activities:     
Net income$147,964
 $150,003
 $306,720
Adjustments to reconcile net income to net cash provided by
operating activities:
     
Depreciation and amortization expense264,232
 216,736
 210,210
Unit-based compensation expense8,132
 7,579
 —
Amortization of debt related items6,147
 7,477
 8,840
Loss (gain) from sale or disposition of assets4,984
 64
 (1,617)
Gain associated with the Linden Acquisition—
 —
 (56,277)
Impairment loss—
 58,655
 —
Deferred income tax expense (benefit)6
 (469) 2,058
Distributions of equity in earnings of joint ventures—
 —
 2,500
Changes in current assets and current liabilities (Note 21)(26,493) 3,716
 50,559
Other, net1,827
 (7,000) 1,944
Net cash provided by operating activities406,799
 436,761
 524,937
Cash Flows from Investing Activities:     
Capital expenditures(384,638) (204,358) (324,808)
Change in accounts payable related to capital expenditures36,903
 (11,063) (3,156)
Acquisitions(1,461,719) (95,657) (142,500)
Proceeds from Axeon term loan110,000
 —
 —
Proceeds from insurance recoveries977
 —
 4,867
Proceeds from sale or disposition of assets2,036
 —
 17,132
Investment in other long-term assets—
 —
 (3,564)
Net cash used in investing activities(1,696,441) (311,078) (452,029)
Cash Flows from Financing Activities:     
Proceeds from long-term debt borrowings1,465,767
 752,729
 860,131
Proceeds from short-term debt borrowings1,051,000
 654,000
 823,500
Proceeds from note offering, net of issuance costs543,333
 —
 —
Long-term debt repayments(1,417,539) (772,152) (500,410)
Short-term debt repayments(1,070,000) (684,000) (816,500)
Proceeds from issuance of preferred units, net of issuance costs538,560
 218,400
 —
Proceeds from issuance of common units, net of issuance costs643,878
 27,710
 —
Contributions from general partner13,737
 680
 —
Distributions to preferred unitholders(38,833) —
 —
Distributions to common unitholders and general partner(446,306) (392,962) (392,204)
Increase (decrease) in cash book overdrafts1,736
 (11,237) (2,954)
Other, net(9,061) (4,492) (792)
Net cash provided by (used in) financing activities1,276,272
 (211,324) (29,229)
Effect of foreign exchange rate changes on cash1,720
 2,721
 (12,729)
Net (decrease) increase in cash and cash equivalents(11,650) (82,920) 30,950
Cash and cash equivalents as of the beginning of the period35,942
 118,862
 87,912
Cash and cash equivalents as of the end of the period$24,292
 $35,942
 $118,862
 Year Ended December 31,
 202320222021
Cash flows from operating activities:
Net income$273,663 $222,747 $38,225 
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization expense255,710 259,236 274,380 
Amortization of unit-based compensation15,547 13,781 14,209 
Amortization of debt related items11,026 10,267 12,490 
Gain from sale or disposition of assets(40,946)(2,785)(61)
Gain from insurance recoveries— (16,366)(14,860)
Goodwill impairment loss— — 34,060 
Other impairment losses— 46,122 154,908 
Changes in current assets and current liabilities (Note 20)10,618 737 (14,147)
Decrease in other long-term assets, net1,199 1,091 9,867 
Decrease in other long-term liabilities(4,226)(1,579)(6,636)
Other, net(8,322)(5,702)(957)
Net cash provided by operating activities514,269 527,549 501,478 
Cash flows from investing activities:
Capital expenditures(147,508)(140,630)(181,133)
Change in accounts payable related to capital expenditures8,969 (12,786)1,264 
Proceeds from insurance recoveries12,395 9,777 9,372 
Proceeds from sale or disposition of assets102,904 59,274 246,475 
Net cash (used in) provided by investing activities(23,240)(84,365)75,978 
Cash flows from financing activities:
Proceeds from long-term debt borrowings1,006,900 989,900 977,000 
Long-term debt repayments(895,000)(883,300)(1,389,700)
Redemption/repurchase of Series D preferred units(518,680)(222,387)— 
Proceeds from issuance of common units, net of issuance costs221,843 — — 
Distributions to preferred unitholders(116,396)(127,299)(127,551)
Distributions to common unitholders(183,444)(176,413)(175,263)
Payment of tax withholding for unit-based compensation(5,694)(6,012)(3,384)
Other, net(11,959)(9,442)(6,681)
Net cash used in financing activities(502,430)(434,953)(725,579)
Effect of foreign exchange rate changes on cash40 707 136 
Net (decrease) increase in cash, cash equivalents and restricted cash(11,361)8,938 (147,987)
Cash, cash equivalents and restricted cash as of the beginning of the period23,377 14,439 162,426 
Cash, cash equivalents and restricted cash as of the end of the period$12,016 $23,377 $14,439 
See Notes to Consolidated Financial Statements.


61

NUSTAR ENERGY L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY
Years Ended December 31, 2017, 2016 and 2015 AND MEZZANINE EQUITY
(Thousands of Dollars, Except Per Unit Data)
 Limited Partners      
 Preferred (Note 19) Common 
General
Partner
 
Accumulated
Other
Comprehensive
Loss (Note 19)
 Total Partners’ Equity
 Units Amount Units Amount 
Balance as of January 1, 2015—
 $—
 77,886,078
 $1,744,810
 $39,312
 $(67,912) $1,716,210
Net income—
 —
 —
 258,230
 48,490
 —
 306,720
Other comprehensive loss—
 —
 —
 —
 —
 (20,882) (20,882)
Distributions to partners—
 —
 —
 (341,140) (51,064) —
 (392,204)
Balance as of December 31, 2015—
 —
 77,886,078
 1,661,900
 36,738
 (88,794) 1,609,844
Net income—
 1,925
 —
 102,580
 45,498
 —
 150,003
Other comprehensive loss—
 —
 —
 —
 —
 (5,383) (5,383)
Distributions to partners—
 (1,925) —
 (341,798) (51,164) —
 (394,887)
Issuance of common units, including contribution from general partner—
 —
 595,050
 27,710
 575
 —
 28,285
Issuance of preferred units9,060,000
 218,400
 —
 —
 —
 —
 218,400
Unit-based compensation—
 —
 135,100
 5,250
 105
 —
 5,355
Balance as of December 31, 20169,060,000
 218,400
 78,616,228
 1,455,642
 31,752
 (94,177) 1,611,617
Net income—
 40,448
 —
 60,610
 46,906
 —
 147,964
Other comprehensive income—
 —
 —
 —
 —
 9,250
 9,250
Distributions to partners—
 (40,448) —
 (391,737) (54,569) —
 (486,754)
Issuance of common units, including contribution from general partner—
 —
 14,375,000
 643,878
 13,597
 —
 657,475
Issuance of preferred units22,300,000
 538,560
 —
 —
 —
 —
 538,560
Unit-based compensation—
 —
 185,455
 2,516
 140
 —
 2,656
Other—
 (357) —
 (322) —
 —
 (679)
Balance as of December 31, 201731,360,000
 $756,603
 93,176,683
 $1,770,587
 $37,826
 $(84,927) $2,480,089
Limited PartnersMezzanine Equity
PreferredCommonAccumulated Other
Comprehensive Loss
Total Partners’ Equity
(Note 18)
Series D Preferred Limited Partners (Note 17)Total
Balance as of January 1, 2021$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, 2021756,301 299,502 (73,978)981,825 616,439 1,598,264 
Net income66,526 95,158 — 161,684 61,063 222,747 
Other comprehensive income— — 42,373 42,373 — 42,373 
Distributions to partners:
Series A, B and C preferred(66,526)— — (66,526)— (66,526)
Common ($1.60 per unit)— (176,413)— (176,413)— (176,413)
Series D preferred— — — — (61,063)(61,063)
Unit-based compensation— 12,302 — 12,302 — 12,302 
Series D Preferred Unit accretion— (18,538)— (18,538)18,538 — 
Series D Preferred Unit repurchase— (34,382)— (34,382)(188,005)(222,387)
Other— (9)— (9)(2)(11)
Balance as of December 31, 2022756,301 177,620 (31,605)902,316 446,970 1,349,286 
Net income90,114 158,934 — 249,048 24,615 273,663 
Other comprehensive income— — 8,680 8,680 — 8,680 
Distributions to partners:
Series A, B and C preferred(90,114)— — (90,114)— (90,114)
Common ($1.60 per unit)— (183,444)— (183,444)— (183,444)
Series D preferred— — — — (24,615)(24,615)
Issuance of common units— 221,773 — 221,773 — 221,773 
Unit-based compensation— 9,800 — 9,800 — 9,800 
Series D Preferred Unit accretion— (7,171)— (7,171)7,171 — 
Series D Preferred Unit redemptions— (64,542)— (64,542)(454,138)(518,680)
Other— (65)— (65)(3)(68)
Balance as of December 31, 2023$756,301 $312,905 $(22,925)$1,046,281 $— $1,046,281 
See Notes to Consolidated Financial Statements.

62

NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 20162023, 2022 and 20152021


1. ORGANIZATION AND OPERATIONS
Organization
NuStar Energy L.P. (NYSE: NS)(NuStar Energy) is engaged in the transportation of petroleum products and anhydrous ammonia, and the terminalling, storage and marketing of petroleum products.a publicly traded Delaware limited partnership. 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, Holdings, LLC (NuStar GP Holdings or NSH) (NYSE: NSH) owns(the Board of Directors), the general partner of our general partner, Riverwalk Logistics, L.P., and owns an approximate 11% common limited partner interest in us asboth of which are indirectly wholly owned subsidiaries of ours. As of December 31, 2017.2023, our limited partner interests consisted of the following:

•common units (NYSE: NS); and
Employee Transfer from•8.50% Series A (NYSE: NSprA), 7.625% Series B (NYSE: NSprB) and 9.00% Series C (NYSE: NSprC) Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units.

Operations
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 conduct our operations through our subsidiaries, primarily NuStar GP, LLC. On March 1, 2016,Logistics, L.P. (NuStar Logistics) and NuStar GP, LLC,Pipeline Operating Partnership L.P. (NuPOP). We have three business segments: pipeline, storage and fuels marketing.

Pipeline. Our assets included 9,490 miles of pipeline with aggregate storage capacity of 13.0 million barrels. Our Central West System includes 2,915 miles of refined product pipelines and 2,070 miles of crude oil pipelines, as well as 5.6 million barrels of crude oil storage capacity, while our Central East System includes 2,495 miles of refined product pipelines, consisting of the general partnerEast and North pipelines, and an approximately 2,000-mile ammonia pipeline (the Ammonia Pipeline). The East and North pipelines have aggregate 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 and Mexico, with aggregate storage capacity of 36.4 million barrels. 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 primarily includes our bunkering operations in the Gulf Coast, as well as certain of our general partner and a wholly owned subsidiary of NuStar GP Holdings, transferred and assigned to NuStar Services Company LLC (NuStar Services Co), a wholly owned subsidiary of NuStar Energy, all of NuStar GP, LLC’s employees and related benefit plans, programs, contracts and policies (the Employee Transfer). As a result of the Employee Transfer, we pay employee costs directly and sponsor the long-term incentive plan and other employee benefit plans. Please refer to Note 17 for further discussion of the Employee Transfer andblending operations associated with our related party agreements, Note 22 for a discussion of our employee benefit plans and Note 23 for a discussion of our long-term incentive plan.Central East System.


Recent Developments
Merger. Merger Agreement. On February 7, 2018, NuStar Energy, Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, a wholly owned subsidiary of NuStar Energy (Merger Sub), Riverwalk Holdings, LLC and NuStar GP Holdings, LLC (NuStar GP Holdings)January 22, 2024, we entered into a merger agreement with Sunoco LP and its affiliates, in an Agreement and Plan of Merger (the Merger Agreement) pursuant toall-equity transaction, which Merger Sub will merge with and into NuStar GP Holdings with NuStar GP Holdings being the surviving entity (the Merger), such that NuStar Energy will be the sole member of NuStar GP Holdings following the Merger. Pursuant to the Merger Agreement and at the effective time of the Merger, our partnership agreement will be amended and restated to, among other things, (i) cancel the incentive distribution rights held by our general partner, (ii) convert the 2% general partner interestresult in NuStar Energy held by our general partnersurviving the merger as a subsidiary of Sunoco LP. At closing of the merger, each NuStar Energy common unit issued and outstanding immediately prior to closing will be converted into the right to receive 0.400 of a non-economic management interestcommon unit of Sunoco and, (iii) provideif applicable, cash in lieu of fractional units. See Note 25 for further information on the holdersmerger.

Redemptions of Series D Preferred Units. In the second and third quarters of 2023, we redeemed all of our common units with voting rights in the election of the members of the board of directors of NuStar GP, LLC at an annual meeting, beginning in 2019. The Merger is subject to the satisfaction or waiver of certain conditions, including approval of the Merger Agreement by NuStar GP Holdings unitholders. Please refer to Note 28 for further discussion of the Merger.

Hurricane Activity. In the third quarter of 2017, parts of the Caribbean and Gulf of Mexico experienced three major hurricanes. Several of our facilities were affected by the hurricanes, but our St. Eustatius terminal experienced the most damage and was temporarily shut down. We incurred approximately $2.6 million of operating expenses to repair minor property damage at several of our domestic terminals. Additionally, we recorded a $5.0 million loss in “Other (expense) income, net” in the consolidated statements of income in the third quarter of 2017 for property damage at our St. Eustatius terminal, which represents the amount of our property deductible under our insurance policy. The hurricane impacts lowered revenues for our bunker fuel operations in our fuels marketing segment and lowered throughput and associated handling fees in our storage segment in the third and fourth quarters of 2017. We received insurance proceeds of $12.5 million in 2017 for damages at our St. Eustatius terminal, of which $3.8 million was for business interruption and the remainder was used for repairs and cleanup. Proceeds from business interruption insurance are included in “Operating expenses” in the consolidated statements of income and in “Cash flows from operating activities” in the consolidated statements of cash flows. In January 2018, we received $87.5 million of insurance proceeds in settlement of our property damage claim for our St. Eustatius terminal. We expect that the costs to repair the property damage at the terminal will not exceed the value of insurance proceeds received.

Navigator Acquisition and Financing Transactions. On May 4, 2017, we completed the acquisition of Navigator Energy Services, LLC for approximately $1.5 billion (the Navigator Acquisition). In order to fund the purchase price, we issued 14,375,000 common units for net proceeds of $657.5 million, issued $550.0 million of 5.625% senior notes for net proceeds of $543.3 million and issued 15,400,000 of our 7.625%outstanding Series B Fixed-to-Floating Rate Cumulative Redeemable PerpetualD Preferred Units, (Series B Preferred Units)as defined in Note 17, for an aggregate net proceedsredemption price of $371.8$518.7 million. Please refer to Notes 4, 12 and 19See Note 17 for further discussion.additional information on these redemptions.

Axeon Term Loan. On February 22, 2017, we settled and terminated the $190.0 million term loan to Axeon Specialty Products, LLC (the Axeon Term Loan), pursuant to which we also provided credit support, such as guarantees, letters of credit and cash collateral, as applicable, of up to $125.0 million to Axeon Specialty Products, LLC (Axeon). We received $110.0 million in


75
63
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


Issuance of Common Units. On August 11, 2023, we issued 14,950,000 common units representing limited partner interests at a price of $15.35 per unit for net proceeds of approximately $222.0 million. See Note 18 for more information.


Debt Amendments. On June 30, 2023, we amended our Revolving Credit Agreement, as defined in Note 12, primarily to extend the maturity date from April 27, 2025 to January 27, 2027. On June 29, 2023, we amended our Receivables Financing Agreement, as defined in Note 12,to extend the scheduled termination date from January 31, 2025 to July 1, 2026. See Note 12 for more information.

Sale-Leaseback Transaction. On March 21, 2023, we consummated the Sale-Leaseback Transaction, as defined in Note 4, of our Corporate Headquarters, also as defined in Note 4, for approximately $103.0 million and recognized a gain of $41.1 million. See Note 4 for more information.

Other Event
Selby Terminal Fire. On October 15, 2019, a fire at our terminal facility in Selby, California destroyed two storage tanks and temporarily shut down the terminal. We received insurance proceeds of $12.4 million, $11.1 million and $28.5 million for the years ended December 31, 2023, 2022 and 2021, respectively. The amount received in 2023 represented the remaining proceeds from the settlement of the Axeon Term Loan,property loss claim. For the years ended December 31, 2022 and 2021, we recorded gains of $16.4 million and $14.9 million, respectively, for the amount by which the insurance recoveries exceeded our obligationexpenses incurred to provide ongoing credit support to Axeon ceased. Please refer to Notes 7 and 15 for further discussion of the Axeon Term Loan and related credit support.

Operations
We conduct our operations through our subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics) and NuStar Pipeline Operating Partnership L.P. (NuPOP). We have three business segments: pipeline, storage and fuels marketing.
Pipeline. We own 3,130 miles of refined product pipelines and 1,930 miles of crude oil pipelines, as well as approximately 5.0 million barrels of storage capacity,date, which comprise our Central West System. In addition, we own 2,370 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 approximately 6.8 million barrels. We charge tariffs on a per barrel basis for transporting refined products, crude oil and other feedstocksare included in our refined product and crude oil pipelines and on a per ton basis for transporting anhydrous ammonia“Other income, net” in the Ammonia Pipeline.
Storage.consolidated statements of income. We own terminal and storage facilitiesrecorded a gain from business interruption insurance of $4.0 million for the year ended December 31, 2021, which is included in “Operating expenses” in the United States, Canada, Mexico, the Netherlands, including St. Eustatius in the Caribbean, and the United Kingdom, with approximately 84.8 million barrelsconsolidated statements of storage capacity. Our terminal and storage facilities provide storage, handling and other services on a fee basis for petroleum products, crude oil, specialty chemicals and other liquids.income.
Fuels Marketing. Within our fuels marketing operations, we purchase petroleum products for resale. The activities of the fuels marketing segment expose us to the risk of fluctuations in commodity prices, which has a direct impact on the segment’s results of operations. We enter into derivative contracts to attempt to mitigate the effect of commodity price fluctuations.
We ceased marketing crude oil in the second quarter of 2017 and exited our heavy fuels trading operations in the third quarter of 2017. These actions are in line with our goal of reducing our exposure to commodity margins, and instead focusing on our core, fee-based pipeline and storage segments. The only operations remaining in our fuels marketing segment are our bunkering operations at our St. Eustatius and Texas City terminals, as well as certain of our blending operations.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Consolidation
The accompanying consolidated financial statements represent the consolidated operations of the Partnership and our subsidiaries. Inter-partnership balances and transactions have been eliminated in consolidation. The operations of certain pipelines and terminals in which we own an undivided interest are proportionately consolidated in the accompanying consolidated financial statements.
Use of Estimates
The preparation of consolidated financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. On an ongoing basis, management reviews its estimates based on currently available information. Management may revise estimates due to changes in facts and circumstances.
Cash and Cash Equivalents
Cash equivalents are all highly liquid investments with an original maturity of three months or less when acquired.


Accounts Receivable
Accounts receivable represent valid claims against non-affiliated customersTrade receivables are carried at amortized cost, net of a valuation allowance for products sold or services rendered.current expected credit losses. We extend credit terms to certain customers after review of various credit indicators, including the customer’s credit rating. Outstandingrating, and obtain letters of credit, guarantees or collateral as deemed necessary. We monitor our ongoing credit exposure through active review of customer receivable balances are regularly reviewed for possible non-payment indicatorsagainst contract terms and allowances for doubtful accounts are recordeddue dates and pool customer receivables based upon management’s estimate of collectability at the time of its review.days outstanding, which is our primary credit risk indicator. Our review activities include timely account reconciliations, dispute resolution and payment confirmations.

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

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basis. Inventories associated with qualifying fair value hedges are valued at current market prices. Materials and supplies are valued at the lower of average cost or net realizable value.

Restricted Cash
As of December 31, 2023 and 2022, we have restricted cash representing legally restricted funds that are unavailable for general use totaling $9.3 million and $8.9 million, respectively, which is included in “Other long-term assets, net” on the consolidated balance sheets.
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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 (expense) income, net” in the consolidated statements of income in the year of disposition.

income. We capitalize overhead costs and interest costs incurred on funds used to construct property, plant and equipment while the asset is under construction. The overhead costs and capitalized interest are recorded as part of the asset to which they relate and are amortized over the asset’s estimated useful life as a component of depreciation expense.
Leases
We lease assets used in our operations, including land and docks, as well as the Corporate Headquarters. We record all leases on our consolidated balance sheets except for those leases with an initial term of 12 months or less, which are expensed on a straight-line basis over the lease term. We use judgment in determining the reasonably certain lease term and consider factors such as the nature and utility of the leased asset, as well as the importance of the leased asset to our operations. We calculate the present value of our lease liabilities based upon our incremental borrowing rate unless the rate implicit in the lease is readily determinable. For all 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:
•ad valorem taxes assessed on our Corporate Headquarters;
•dockage and wharfage charges, which are based on volumes moved over leased docks and are included in our calculation of our lease payments based on minimum throughput volume requirements. We recognize charges on excess throughput volumes in profit or loss in the period in which the obligation for those payments is incurred; and
•consumer price index (CPI) adjustments, which are measured and included in the calculation of our lease payments based on the CPI at the commencement date. We recognize changes in lease payments as a result of changes in the CPI in profit or loss in the period in which those payments are made.

See Note 15 for further discussion of our lease arrangements.

Goodwill
As of December 31, 2023 and 2022, our reporting units to which goodwill has been allocated consisted of the following:
•crude oil pipelines;
•refined product pipelines; and
•terminals, excluding our refinery crude storage tanks.

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

We assess goodwill for impairment annually on October 1, or more frequently if events or changes in circumstances indicate it might be impaired. We have the option to first assess qualitative factors to determine whether it is necessary to perform a quantitative goodwill impairment test. We performed a quantitative goodwill impairment testelected to bypass the qualitative assessment for all reporting units as of October 1, 20172023 and 2016,October 1, 2022 and determinedperformed quantitative assessments, resulting in the determination that nogoodwill was not impaired.

We measure goodwill impairment charges occurred.as the excess of each reporting unit’s carrying value over its fair value, not to exceed the carrying amount of goodwill for that reporting unit. The carrying value of each reporting unit equals the total identified assets (including goodwill) less the sum of each reporting unit’s identified liabilities. We used reasonable and supportable methods to assign the assets and liabilities to the appropriate reporting units in a consistent manner.


We recognize an impairment of goodwill if the carrying value of a reporting unit that contains goodwill exceeds its estimated fair value. In order to estimate the fair value of the reporting unit, including goodwill, management must make certain estimates and assumptions that affect the total fair value of the reporting unit including, among other things, an assessment of market conditions, projected cash flows, discount rates and growth rates. Management’s estimates of projected cash flows related to the reporting unit include, but are not limited to, future earnings of the reporting unit, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and future expenditures necessary to maintain the asset’s existing service potential. We calculate the estimated fair value of each of our reporting units using a weighted-averageweighted average of values calculated using an income approach and a market approach. The income approach involves estimating the fair value of each reporting
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unit by discounting its estimated future cash flows using a discount rate that would be consistent with a market participant’s assumption. The market approach bases the fair value measurement on information obtained from observed stock prices of public companies and recent merger and acquisition transaction data of comparable entities.
Our reporting units
Management’s estimates are based on numerous assumptions about future operations and market conditions, which we believe to be reasonable but are inherently uncertain. The uncertainties underlying our assumptions and estimates could differ significantly from actual results, which goodwill has been allocated consistcould lead to a different determination of the following:
crude oil pipelines;
refined product pipelines;
terminals, excluding our St. Eustatius and Point Tupper facilities and our refinery crude storage tanks; and
bunkering activity at our St. Eustatius and Point Tupper facilities.

The quantitative impairment test for goodwill consists of a two-step process. Step 1 compares the fair value of the reporting unit to its carrying value including goodwill. The carrying value of each reporting unit equals the total identified assets (including goodwill) less the sum of each reporting unit’s identified liabilities. We used reasonable and supportable methods to assign the assets and liabilities to the appropriate reporting units in a consistent manner. If the carrying value exceeds fair value, there is a potential impairment and step 2 must be performed to determine the amount of goodwill impairment. Step 2 compares the carrying value of the reporting unit’s goodwill to its implied fair value using a hypothetical allocation of the reporting unit’s fair value. If the goodwill carrying value exceeds its implied fair value, the excess is reported as impairment.our assets.
Impairment of Long-Lived Assets
We review long-lived assets, including property, plant and equipment, for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. We evaluate recoverability using undiscounted estimated net cash flows generated by the related asset or asset group. If the results of that evaluation indicate that the undiscounted cash flows are less than the carrying amount of the asset (i.e., the asset is not recoverable) we perform an impairment analysis. If our intent is to hold the asset for continued use, we determine the amount of impairment as the amount by which the net carrying value exceeds its fair value. If our intent is to sell the asset, and the criteria required to classify an asset as held for sale are met, we determine the amount of impairment as the amount by which the net carrying amount exceeds its fair value less costs to sell. See Note 4 for a discussion of our long-lived asset impairment charges. We believe that the carrying amounts of our long-lived assets as of December 31, 20172023 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,

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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, 20172023 and 2016.2022.

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 20132018 through 2016,2022, 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.


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We also have legal obligations in the form of leases and right-of-way agreements, which require us to remove certain of our assets upon termination of the agreement. However, these lease or right-of-way agreements generally contain automatic renewal provisions that extend our rights indefinitely or we have other legal means available to extend our rights. We have recorded a liability of $0.7 million and $0.6 million as of December 31, 2017 and 2016, respectively, which is included in “Other long-term liabilities” in the consolidated balance sheets,Liabilities for conditional asset retirement obligations related to the retirement of terminal assets with lease and right-of-way agreements.agreements were not material as of December 31, 2023 and 2022.
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.

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Product Imbalances
We incur product imbalances as a result of variances in pipeline meter readings Environmental liabilities are difficult to assess and volume fluctuationsestimate due to pressureunknown factors, such as the timing and temperature changes. We use quoted market prices asextent of remediation, the reporting datedetermination of our liability in proportion to value our assetsother parties, improvements in cleanup technologies and liabilities relatedthe extent to product imbalances. Product imbalance liabilities are included in “Accrued liabilities”which environmental laws and product imbalance assets are included in “Other current assets”regulations may change in the consolidated balance sheets.future. We believe that we have adequately accrued for our environmental exposures. See Note 13 for the amount of accruals for environmental matters.

Revenue Recognition
Revenue-Generating Activities.Revenues for the pipeline segment are derived from interstate and intrastate pipeline transportation of refined products, crude oil and anhydrous ammonia. Transportation revenues (basedammonia and the applicable pipeline tariff on pipeline tariffs) are recognized as the refined product,a per barrel basis for crude oil or anhydrous ammonia is delivered out ofrefined products and on a per ton basis for ammonia. Revenues generated from product sales in the pipelines.pipeline segment relate to surplus pipeline loss allowance volumes.


Revenues for the storage segment include fees for tank storage agreements, wherebyunder which a customer agrees to pay for a certain amount of storage in a tank over a period of time (storage terminal revenues), and throughput agreements, wherebyunder which a customer pays a fee per barrel for volumes moving through our terminals (throughput terminal revenues). Our terminals also provide blending, additive injections, handling and filtering services for which we charge additional fees. Certain of our facilities charge fees to provide marine services such as pilotage, tug assistance, line handling, launch service, emergency response services and other ship services. Storage terminal revenues are recognized when services are provided to the customer. Throughput revenues are recognized as refined products or crude oil are received in or delivered out of our terminal.

Revenues for marine servicesthe fuels marketing segment are recognized as those services are provided.
Revenuesderived from the sale of petroleum products.

Within both our pipeline and storage segments, we provide services on uninterruptible and interruptible bases. Uninterruptible services within our pipeline segment typically result from contracts that contain take-or-pay minimum volume commitments (MVCs) from the customer. Contracts with MVCs obligate the customer to pay for that minimum amount. If a customer fails to meet its MVC for the applicable service period, the customer is obligated to pay a deficiency fee based upon the shortfall between the actual volumes transported or stored and the MVC for that service period (deficiency payments). In exchange, those contracts with MVCs obligate us to stand ready to transport volumes up to the customer’s MVC.

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

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

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

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

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

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

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

In certain instances, our customers reimburse us for capital projects, in arrangements referred to as contributions in aid of construction, or CIAC. Typically, in these instances, we receive upfront payments for future services, which are included in our fuels marketing segment, are recognized when product is delivered to the customer and title and risk pass totransaction price of the customer.underlying service contract.

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

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

Some of our MVC contracts include provisions that allow the customer to apply deficiency payments to future service periods (the carryforward period). In those instances, we have not satisfied our performance obligation as we still have the obligation to perform those services, subject to contractual and/or capacity constraints, at the customer’s request. At least quarterly, we assess the customer’s ability to utilize any deficiency payments during the carryforward period. If we receive a deficiency payment from a customer that we expect the customer to utilize during the carryforward period, we defer that amount as a contract liability. We will consider the performance obligation satisfied and allocate any deferred deficiency payments to our performance obligation when the customer utilizes the deficiency payment, the carryforward period ends or we determine the customer cannot or will not utilize the deficiency payment (i.e., breakage).If our contract does not allow the customer to apply deficiency payments to future service periods, we allocate the deficiency payment to the already satisfied portion of the performance obligation.
Income Allocation
Our partnership agreement as amended, sets forth the calculation to be used to determine the amount and priority of cash distributions that the unitholders and general partner will receive. The partnership agreement also contains provisions for the allocation of net income to the unitholders and the general partner; however, losses are only allocated to the common unitholders and the general partner.unitholders. Our net income for each quarterly reporting period is first allocated to the preferred limited partner unitholders in an amount equal to the earned distributions for the respective reporting period and then to the general partner in an amount equal to the general partner’s incentive distribution calculated based upon the declared distribution for the respective reporting period. We allocate the remaining net income or loss among the common unitholders (98%) and general partner (2%), as set forth in our partnership agreement.unitholders.
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Basic and Diluted Net Income (Loss) Per Common Unit
Basic and diluted net income (loss) per common unit areis determined pursuant to the two-class method. Under this method, all earnings are allocated to our common limited partners and participating securities based on their respective rights to receive distributions earned during the period. Participating securities include our general partner interest and restricted units awarded under our long-term incentive plan.

plans and, from June 15, 2023 to their redemption on September 12, 2023, the Series D Preferred Units. We compute basic net income (loss) per common unit by dividing net income (loss) attributable to our common limited partners by the weighted-average number of common units outstanding during the period. We compute diluted net income (loss) per common unit by dividing net income (loss) attributable to our common limited partners by the sum of (i) the weighted-average number of common units outstanding during the period and (ii) the effect of dilutive potential common units outstanding during the period. Dilutive potential common units include contingently issuable performance units awarded under our long-term incentive plan.and the Series D Preferred Units, prior to their redemption and/or repurchase. See Note 2322 for additional information on our performance units.units, Note 17 for additional information on the Series D Preferred Units and Note 19 for the calculation of basic and diluted net income (loss) per common unit.
Derivative Financial Instruments
WeWhen we apply hedge accounting, we formally document all relationships between hedging instruments and hedged items. This process includes identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. To qualify for hedge accounting, at inception of the hedge we assess whether the derivative instruments that are used in our hedging transactions are expected to be highly effective in offsetting changes in cash flows or the fair value of the hedged items.flows. Throughout the designated hedge period and at least quarterly, we assess whether the derivative instruments are highly effective and continue to qualify for hedge accounting. To assess the effectiveness of the hedging relationship both prospectively and retrospectively, we use regression analysis to calculate the correlation of the changes in the fair values of the derivative instrument and related hedged item.

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We record commodity derivative instruments in the consolidated balance sheets at fair value. We recognize mark-to-market adjustments for derivative instruments designated and qualifying as fair value hedges (Fair Value Hedges) and the related change in the fair value of the associated hedged physical inventory or firm commitment within “Cost of product sales.” For derivative instruments designated and qualifying as cash flow hedges (Cash Flow Hedges), we record the effective portion of mark-to-market adjustments aswere a component of accumulated other comprehensive income (loss) (AOCI) until the underlying hedged forecasted transactions occur. Any hedge ineffectiveness is recognized immediately in “Cost of product sales.” Once a hedged transaction occurs, we reclassify the effective portion from AOCIparty to “Cost of product sales.” If it becomes probable that a hedged transaction will not occur, then the associated gains or losses are reclassified from AOCI to “Cost of product sales” immediately. For derivative instruments that have associated underlying physical inventory but do not qualify for hedge accounting (Economic Hedges and Other Derivatives), we record the mark-to-market adjustments in “Cost of product sales.”
Under the terms of our forward-starting interest rate swap agreements, we pay a fixed rate and receive a variable rate. We entered into the forward-starting swaps in order to hedge the risk of changes in the interest payments attributable to changes in the benchmark interest rate during the period from the effective date of the swap to the issuance of the forecasted debt. We account for theThese forward-starting interest rate swaps qualified as Cash Flow Hedges,cash flow hedges, and we recognizedesignated them as such; therefore, we recognized the fair value of each interest rate swap in the consolidated balance sheets. We recordrecorded changes in the effective portionfair value of mark-to-market adjustmentsthe hedge as a component of AOCI, andaccumulated other comprehensive income (loss) (AOCI), on the consolidated balance sheets, to the extent those cash flow hedges remained highly effective. If at any point a cash flow hedge ineffectiveness isceased to qualify for hedge accounting, changes in the fair value of the hedge were recognized immediately in “Interest expense, net.”net” from that date forward. The amount accumulated in AOCI is amortized into “Interest expense, net” on the consolidated statements of income as the forecasted interest payments occur or if the interest payments are probable not to occur.
We classify cash flows associated with our derivative instruments as operating cash flows in the consolidated statements of cash flows, except for receipts or payments associated with terminated forward-starting interest rate swap agreements, which are included in cash flows from financing activities. See Note 16 for additional information regarding our derivative financial instruments.
Operating LeasesDefined Benefit Plans
We recognize rent expenseestimate pension and other postretirement benefit obligations and costs based on a straight-line basis overactuarial valuations. The annual measurement date for our pension and other postretirement benefit plans is December 31. The actuarial valuations require the lease term,use of certain assumptions including the impactdiscount rates, expected long-term rates of both scheduled rent increasesreturn on plan assets and free or reduced rents (commonly referred to as “rent holidays”).expected rates of compensation increase. Changes in these assumptions are primarily influenced by factors outside our control. See Note 21 for further discussion of our pension and other postretirement benefit obligations.
Unit-based CompensationRevenue Recognition
Unit-based compensationRevenue-Generating Activities.Revenues for the pipeline segment are derived from interstate and intrastate pipeline transportation of refined products, crude oil and anhydrous ammonia and the applicable pipeline tariff on a per barrel basis for crude oil or refined products and on a per ton basis for ammonia. Revenues generated from product sales in the pipeline segment relate to surplus pipeline loss allowance volumes.

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

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

Within both our pipeline and storage segments, we provide services on uninterruptible and interruptible bases. Uninterruptible services within our pipeline segment typically result from contracts that contain take-or-pay minimum volume commitments (MVCs) from the customer. Contracts with MVCs obligate the customer to pay for that minimum amount. If a customer fails to meet its MVC for the applicable service period, the customer is recordedobligated to pay a deficiency fee based upon the shortfall between the actual volumes transported or stored and the MVC for that service period (deficiency payments). In exchange, those contracts with MVCs obligate us to stand ready to transport volumes up to the customer’s MVC.

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

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

Performance Obligations. The majority of our consolidated balance sheets based oncontracts contain a single performance obligation. For our pipeline segment, the fair valuesingle 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 awards granted and recognized as compensation expense primarily on a straight-line basis over the requisite service period. Forfeiturespipelines. Certain of our unit-based compensation awards are recognized aspipeline segment customer contracts include 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. See Note 23incentive pricing structure, which provides a discounted rate for additional information regarding our unit-based compensation.
Margin Deposits
Margin deposits relate to our exchange-traded derivative contracts and generally vary based on changes in the valueremainder of the contracts. Margin deposits are includedcontract once the customer exceeds a cumulative volume. The ability to receive discounted future services represents a material right to the customer, which results in “Other current assets”a second performance obligation in the consolidated balance sheets.those contracts.
Foreign Currency Translation
The functional currencies of our foreign subsidiaries are the local currencies of the countries in which the subsidiaries are located, except for our subsidiaries located in St. Eustatius in the Caribbean (formerly the Netherlands Antilles), whose functional currency is the U.S. dollar. The assets and liabilities of our foreign subsidiaries with local functional currencies are translated to U.S. dollars at period-end exchange rates, and income and expense items are translated to U.S. dollars at weighted-average exchange rates in effect during the period. These translation adjustments are included in “Accumulated other comprehensive loss” in the equity section of the consolidated balance sheets. Gains and losses on foreign currency transactions are included in “Other (expense) income, net” in the consolidated statements of income.

3. NEW ACCOUNTING PRONOUNCEMENTS

Derivatives and Hedging
In August 2017, the Financial Accounting Standards Board (FASB) issued amended guidance intended to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. The amended guidance also makes certain targeted improvements to simplify the application of current hedge accounting guidance. The guidance is effective for annual and interim periods beginning after December 15, 2018, with early adoption permitted. Certain of the new requirements should be applied prospectively while others should be applied using a modified retrospective transition method. We currently expect to adopt the amended guidance on January 1, 2019. We do not


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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 from a customer that we expect the guidancecustomer to haveutilize during the carryforward period, we defer that amount as a material impact oncontract liability. We will consider the performance obligation satisfied and allocate any deferred deficiency payments to our financial positionperformance obligation when the customer utilizes the deficiency payment, the carryforward period ends or results of operations, and we are assessingdetermine the impact oncustomer cannot or will not utilize the deficiency payment (i.e., breakage).If our disclosures.

Unit-Based Payments
In May 2017,contract does not allow the FASB issued amended guidance that clarifies when a changecustomer to apply deficiency payments to future service periods, we allocate the deficiency payment to the terms and conditions of a unit-based payment award is accounted for as a modification. Under the amended guidance, an entity will apply modification accounting if the value, vesting or classificationalready satisfied portion of the unit-based payment award changes. The guidance is effectiveperformance obligation.
Income Allocation
Our partnership agreement contains provisions for annual and interim periods beginning after December 15, 2017, and amendments should be applied prospectively. We adopted these provisions January 1, 2018, and the guidance did not have a material impact on our financial position, results of operations or disclosures.

Defined Benefit Plans
In March 2017, the FASB issued amended guidance that changes the presentationallocation of net periodic pension cost relatedincome to defined benefit plans. Under the amended guidance,unitholders. Our net income for each quarterly reporting period is first allocated to the service cost component of net periodic benefit cost will be presentedpreferred limited partner unitholders in an amount equal to the same income statement line items as other current employee compensation costs, butearned distributions for the respective reporting period. We allocate the remaining components of net periodic benefit cost will be presented outside of operating income. The changes are effective for annual and interim periods beginning after December 15, 2017, and amendments should be applied retrospectively. We adopted these provisions January 1, 2018, andincome or loss among the guidance did not have a material impact on our financial position, results of operations or disclosures.

Goodwill
In January 2017, the FASB issued amended guidance that simplifies the accounting for goodwill impairment by eliminating step 2 of the goodwill impairment test. Under the amended guidance, goodwill impairment will be measured as the excess of the reporting unit’s carrying value over its fair value, not to exceed the carrying amount of goodwill for that reporting unit. The changes are effective for annual and interim periods beginning after December 15, 2019, and amendments should be applied prospectively. Early adoption is permitted for any impairment tests performed after January 1, 2017, and we are currently evaluating whether we will adopt these provisions early. Regardless of our decision, we do not expect the guidance to have a material impact on our financial position, results of operations or disclosures.

Definition of a Business
In January 2017, the FASB issued amended guidance that clarifies the definition of a business used in evaluating whether a set of transferred assets and activities constitutes a business. Under the amended guidance, if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets, the set of transferred assets and activities would not represent a business. To be considered a business, the set of assets transferred is also required to include at least one substantive process that together significantly contribute to the ability to create outputs. In addition, the amended guidance narrows the definition of outputs to be consistent with how outputs are described in the new revenue recognition standard. The changes are effective for annual and interim periods beginning after December 15, 2017, and amendments should be applied prospectively. We adopted these provisions January 1, 2018, and they did not have an impact on our financial position, results of operations or disclosures.

Statement of Cash Flows
In August 2016, the FASB issued amended guidance that clarifies how entities should present certain cash receipts and cash payments on the statement of cash flows, including, but not limited to, debt prepayment or debt extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims and distributions received from equity method investees. The changes are effective for annual and interim periods beginning after December 15, 2017, and amendments should be applied retrospectively. We adopted these provisions January 1, 2018, and they did not have an impact on our statements of cash flows or disclosures.

Credit Losses
In June 2016, the FASB issued amended guidance that requires the use of a “current expected loss” model for financial assets measured at amortized cost and certain off-balance sheet credit exposures. Under this model, entities will be required to estimate the lifetime expected credit losses on such instruments based on historical experience, current conditions, and reasonable and supportable forecasts. This amended guidance also expands the disclosure requirements to enable users of financial statements to understand an entity’s assumptions, models and methods for estimating expected credit losses. The changes are effective for annual and interim periods beginning after December 15, 2019, and amendments should be applied using a modified retrospective approach. We currently expect to adopt the amended guidance on January 1, 2020 and are assessing the impact of this amended guidance on our financial position, results of operations and disclosures. We plan to provide additional information about the expected financial impact at a future date.


common unitholders.
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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 and, from June 15, 2023 to their redemption on September 12, 2023, the Series D Preferred Units. 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, prior to their redemption and/or repurchase. See Note 22 for additional information on our performance units, Note 17 for additional information on the Series D Preferred Units and Note 19 for the calculation of basic and diluted net income (loss) per common unit.
LeasesDerivative Financial Instruments
In February 2016,When we apply hedge accounting, we formally document all relationships between hedging instruments and hedged items. This process includes identification of the FASB issued amended guidancehedging 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 requires lesseesare used in our hedging transactions are expected to recognizebe 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 were a party to 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. These forward-starting interest rate swaps qualified as cash flow hedges, and we designated them as such; therefore, we recognized the fair value of each interest rate swap in the consolidated balance sheets. We recorded changes in the fair value of the hedge as a component of accumulated other comprehensive income (loss) (AOCI), on the consolidated balance sheets, to the extent those cash flow hedges remained highly effective. If at any point a cash flow hedge ceased to qualify for hedge accounting, changes in the fair value of the hedge were recognized in “Interest expense, net” from that date forward. The amount accumulated in AOCI is amortized into “Interest expense, net” on the consolidated statements of income as the forecasted interest payments occur or if the interest payments are probable not to occur.
We classify cash flows associated with our derivative instruments as operating cash flows in the consolidated statements of cash flows, except for receipts or payments associated with terminated forward-starting interest rate swap agreements, which are included in cash flows from financing activities. See Note 16 for additional information regarding our derivative financial instruments.
Defined Benefit Plans
We estimate pension and other postretirement benefit obligations and costs based on actuarial valuations. The 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 liabilities that arise from most leases on the balance sheet. For lessors, this amended guidance modifies the classification criteriaexpected rates of compensation increase. Changes in these assumptions are primarily influenced by factors outside our control. See Note 21 for further discussion of our pension and the accounting for sales-type and direct financing leases. The changes are effective for annual and interim periods beginning after December 15, 2018, and amendments should be applied using a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements, with the option to use certain expedients. In January 2018, the FASB issued additional guidance that provides an optional transition practical expedient for land easements. We currently expect to adopt these provisions on January 1, 2019 using the modified retrospective approach of adoption. We are working to identify our lease arrangements and have begun the process of system implementation. We are continuing to evaluate the impact of this amended guidance on our financial position, results of operations, disclosures and internal controls and plan to provide additional information about the expected financial impact at a future date.other postretirement benefit obligations.

Financial Instruments
In January 2016, the FASB issued new guidance that addresses certain aspects of recognition, measurement, presentation and disclosure of financial instruments. The changes are effective for annual and interim periods beginning after December 15, 2017, and amendments should be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. We adopted these provisions January 1, 2018, and they did not have an impact on our financial position, results of operations or disclosures.

Revenue Recognition
In May 2014,Revenue-Generating Activities.Revenues for the FASBpipeline segment are derived from interstate and intrastate pipeline transportation of refined products, crude oil and anhydrous ammonia and the International Accounting Standards Board jointly issuedapplicable pipeline tariff on a comprehensive new revenue recognition standard that requires an entityper 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 recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The standard is effective for public entities for annual and interim periods beginning after December 15, 2017, using one of two retrospective transition methods. We adopted these provisions January 1, 2018 using the modified retrospective approach. The transition adjustment related to the adoption was immaterial (less than 1% of total revenuessurplus pipeline loss allowance volumes.

Revenues for the year ended December 31, 2017 and total partners’ equity asstorage segment include fees for tank storage agreements, under which a customer agrees to pay for a certain amount of December 31, 2017)storage in a tank over a period of time (storage terminal revenues), and we do not expect the adoption of this standard to materially impact the amount or timing ofthroughput agreements, under which a customer pays a fee per barrel for volumes moving through our revenue going forward. Under the new guidance, we will no longer recognize the fair value of product imbalance assets or liabilities on our consolidated balance sheets. We intend toterminals (throughput terminal revenues). Our terminals also provide additional disclosures as required by the new standard,blending, additive injections, handling and filtering services for which we are currently assessing, in our quarterly report on Form 10-Qcharge additional fees.

Revenues for the first quarterfuels marketing segment are derived from the sale of 2018.petroleum products.


4. ACQUISITIONS

Navigator Acquisition
On April 11, 2017, we entered into a Membership Interest Purchase and Sale Agreement (the Acquisition Agreement) with FR Navigator Holdings LLC to acquire all of the issued and outstanding limited liability company interests in Navigator Energy Services, LLC (Navigator) for approximately $1.5 billion. We closed the Navigator Acquisition on May 4, 2017 and funded the purchase price with the net proceeds of the equity and debt issuances described in Notes 12 and 19. We acquired crude oil transportation,Within both our pipeline gathering and storage assets located in the Midland Basin of West Texas consisting of: (i) more than 500 miles of crude oil gatheringsegments, we provide services on uninterruptible and transportation pipelines with approximately 92,000 barrels per day ship-or-pay volume commitments and deliverability of approximately 412,000 barrels per day; (ii) a pipeline gathering system with more than 200 connected producer tank batteries capable of more than 400,000 barrels per day of pumping capacity covering over 500,000 dedicated acres with fixed fee contracts; and (iii) approximately 1.0 million barrels of crude oil storage capacity with 440,000 barrels contracted to third parties. We collectively refer to the acquired assets as our Permian Crude System. The assets acquired are included ininterruptible bases. Uninterruptible services within our pipeline segment typically result from contracts that contain take-or-pay minimum volume commitments (MVCs) from the customer. Contracts with MVCs obligate the customer to pay for that minimum amount. If a customer fails to meet its MVC for the applicable service period, the customer is obligated to pay a deficiency fee based upon the shortfall between the actual volumes transported or stored and the MVC for that service period (deficiency payments). In exchange, those contracts with MVCs obligate us to stand ready to transport volumes up to the customer’s MVC.

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


The Navigator Acquisition broadensFor the majority of our geographic footprint by marking our entry into the Permian Basin and complements our existing asset base. We believe the Permian Crude System will provide a strong growth platform that, when coupled with our assetscontracts, we recognize revenue in the Eagle Ford region, serveamount to solidifywhich we have a right to invoice. Generally, payment terms do not exceed 30 days.

Performance Obligations. The majority of our presencecontracts 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 twoor out of the most prolific basinspipelines. 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 the United States.a second performance obligation in those contracts.


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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.
We accounted
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 Navigator Acquisition usingvalue of services provided to the acquisition method. The fair value estimates of the assets acquired and liabilities assumed are based on preliminary assumptions, pending the completion of an independent appraisal and other evaluations as information becomes available to us. The following table reflects the preliminary purchase price allocation as of December 31, 2017:
 Preliminary Purchase Price Allocation
 (Thousands of Dollars)
Accounts receivable$4,747
Other current assets2,359
Property, plant and equipment, net376,690
Intangible assets (a)700,000
Goodwill (b)400,838
Other long-term assets, net2,199
Current liabilities(25,114)
Preliminary purchase price allocation, net of cash acquired$1,461,719
(a)Intangible assets, which consist of customer contracts and relationships, are expected to be amortized on a straight-line basis over a period of 20 years.
(b)The goodwill acquired represents the expected benefit from entering new geographic areas and the anticipated opportunities to generate future cash flows from the assets acquired and potential future projects.

The values used in the purchase price allocation above are preliminary and subject to change after we finalize our review of certain of Navigator’s pre-acquisition liabilities, and pending the completion of an independent appraisal. Although a change in the value used for the assets acquired and liabilities assumed would cause a corresponding increaseapplicable period.

In certain instances, our customers reimburse us for capital projects, in arrangements referred to as contributions in aid of construction, or decreaseCIAC. Typically, in goodwill,these instances, we do not expect any change to be significant.

The consolidated statements of income include the results of operationsreceive upfront payments for Navigator commencing on May 4, 2017. The table below presents certain financial informationfuture services, which are included in the consolidated statementstransaction price of income relatedthe 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 Navigator Acquisition:single performance obligation that exists in the vast majority of our contracts with customers. For the few contracts that have a second performance obligation, such as those that include an incentive pricing structure, we calculate an average rate based on the estimated total volumes to be delivered over the term of the contract and the resulting estimated total revenue to be billed using the applicable rates in the contract. We allocate the transaction price to the two performance obligations by applying the average rate to product volumes as they are delivered to the customer over the term of the contract. Determining the timing and amount of volumes subject to these incentive pricing contracts requires judgment that can impact the amount of revenue allocated to the two separate performance obligations. We base our estimates on our analysis of expected future production information available from our customers or other sources, which we update at least quarterly.

Some of our MVC contracts include provisions that allow the customer to apply deficiency payments to future service periods (the carryforward period). In those instances, we have not satisfied our performance obligation as we still have the obligation to perform those services, subject to contractual and/or capacity constraints, at the customer’s request. At least quarterly, we assess the customer’s ability to utilize any deficiency payments during the carryforward period. If we receive a deficiency payment from a customer that we expect the customer to utilize during the carryforward period, we defer that amount as a contract liability. We will consider the performance obligation satisfied and allocate any deferred deficiency payments to our performance obligation when the customer utilizes the deficiency payment, the carryforward period ends or we determine the customer cannot or will not utilize the deficiency payment (i.e., breakage).If our contract does not allow the customer to apply deficiency payments to future service periods, we allocate the deficiency payment to the already satisfied portion of the performance obligation.
Income Allocation
Our partnership agreement contains provisions for the allocation of net income to the unitholders. Our net income for each quarterly reporting period is first allocated to the preferred limited partner unitholders in an amount equal to the earned distributions for the respective reporting period. We allocate the remaining net income or loss among the common unitholders.
68
 Year Ended December 31, 2017
 (Thousands of Dollars)
Permian Crude System: 
Revenues$42,620
Operating loss$(1,724)
  
Transaction costs: 
General and administrative expenses$10,391
Interest expense, net3,688
Total transaction costs$14,079


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


Basic and Diluted Net Income (Loss) Per Common Unit

The unaudited pro formaBasic 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 and, from June 15, 2023 to their redemption on September 12, 2023, the Series D Preferred Units. 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, prior to their redemption and/or repurchase. See Note 22 for additional information on our performance units, Note 17 for additional information on the Series D Preferred Units and Note 19 for the years ended December 31, 2017calculation of basic and 2016 presented below combinesdiluted 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 historical financial information for Navigatorhedging instrument and the Partnershiphedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. To qualify for those periods. The information assumeshedge accounting, at inception of the hedge we completedassess whether the Navigator Acquisition on January 1, 2016derivative 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 following:derivative instruments are highly effective and continue to qualify for hedge accounting.
We were a party to 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. These forward-starting interest rate swaps qualified as cash flow hedges, and we issued approximately 14.4 million common units;
designated them as such; therefore, we received a contribution from our general partner of $13.6 million to maintain its 2% interest;
we issued 15.4 million Series B Preferred Units;
we issued $550.0 million of 5.625% senior notes;
additional depreciation and amortization that would have been incurred assumingrecognized the fair value adjustments to property, plant and equipment and intangible assets reflectedof each interest rate swap in the preliminary purchase price allocation above; and
we satisfied Navigator’s outstanding obligations under its revolving credit agreement.
 
Pro Forma
Year Ended December 31,
 2017 2016
 (Thousands of Dollars, Except Per Unit Data)
Revenues$1,828,418
 $1,782,932
Net income$127,433
 $78,664
    
Basic and diluted net income per common unit$0.31
 $0.01

The pro forma information forconsolidated balance sheets. We recorded changes in the year ended December 31, 2017 includes transaction costsfair value of $14.1 million, which were directly attributablethe hedge as a component of accumulated other comprehensive income (loss) (AOCI), on the consolidated balance sheets, to the Navigator Acquisition. The pro forma information is unaudited and is not necessarily indicativeextent those cash flow hedges remained highly effective. If at any point a cash flow hedge ceased to qualify for hedge accounting, changes in the fair value of the results of operationshedge were recognized in “Interest expense, net” from that would have resulted haddate forward. The amount accumulated in AOCI is amortized into “Interest expense, net” on the Navigator Acquisition occurred on January 1, 2016 or that may result in the future.

Martin Terminal Acquisition. On December 21, 2016, we acquired crude oil and refined product storage assets in Corpus Christi, TX for $95.7 million, including $2.1 million of capital expenditure reimbursements, from Martin Operating Partnership L.P. (the Martin Terminal Acquisition). The assets acquired are in our storage segment and include 900,000 barrels of crude oil storage capacity, 250,000 barrels of refined product storage capacity and exclusive use of the Port of Corpus Christi’s new crude oil dock.

Linden Acquisition. On January 2, 2015, we acquired full ownership of ST Linden Terminal, LLC (Linden), which owns a refined products terminal in Linden, NJ with 4.3 million barrels of storage capacity (the Linden Acquisition). Linden is located on a 44-acre facility that provides deep-water terminalling capabilities in the New York Harbor and primarily stores petroleum products, including gasoline, jet fuel and fuel oils. Prior to the Linden Acquisition, Linden operated as a joint venture between Linden Holding Corp. and us, with each party owning 50%.

In connection with the Linden Acquisition, we ceased applying the equity method of accounting and consolidated Linden, which is included in our storage segment. The consolidated statements of income includeas the resultsforecasted 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 operationscash flows, except for Linden commencingreceipts or payments associated with terminated forward-starting interest rate swap agreements, which are included in cash flows from financing activities. See Note 16 for additional information regarding our derivative financial instruments.
Defined Benefit Plans
We estimate pension and other postretirement benefit obligations and costs based on January 2, 2015. Onactuarial valuations. The annual measurement date for our pension and other postretirement benefit plans is December 31. The actuarial valuations require the acquisition date, we remeasureduse 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 existing 50% equity investmentcontrol. See Note 21 for further discussion of our pension and other postretirement benefit obligations.
Unit-based Compensation
Unit-based compensation for our long-term incentive plans is recorded in Linden to itsour consolidated balance sheets based on the fair value of $128.0 millionthe awards granted and we recognized as compensation expense primarily on a gainstraight-line basis over the requisite service period. Forfeitures of $56.3 millionour unit-based compensation awards are recognized as an adjustment to compensation expense when they occur. Unit-based compensation expense is included in “Other (expense)“General and administrative expenses” on our consolidated statements of income. See Note 22 for additional information regarding our unit-based compensation.

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 net”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 statementbalance sheets. Upon the sale or liquidation of income for the year ended December 31, 2015. We estimated the fair value usingour investment in a market approachforeign subsidiary, translation adjustments that have historically accumulated in AOCI related to that subsidiary are released from AOCI and an income approach. The market approach estimates the enterprise value based on an earnings multiple. The income approach calculates fair value by discounting the estimated net cash flows. We funded the acquisition with borrowings under our revolving credit agreement. The acquisition complements our existing storage operations, and having sole ownership of Linden strengthens our presence in the New York Harbor and the East Coast market.


reported as part
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


of the gain or loss on sale. Gains and losses on foreign currency transactions are included in “Other income, net” in the consolidated statements of income.


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

3. NEW ACCOUNTING PRONOUNCEMENTS

Improvements to Income Tax Disclosures
In December 2023, the Financial Accounting Standards Board (FASB) issued guidance intended to enhance the transparency and decision usefulness of income tax disclosures, primarily through changes to the rate reconciliation and income taxes paid information. The amendments are effective for annual periods beginning after December 15, 2024, and early adoption is permitted. The amendments should be applied prospectively; however, retrospective application is permitted. We plan to adopt the amended guidance on January 1, 2025, and are currently evaluating our method of adoption and the impact of this amended guidance on our disclosures.

Improvements to Reportable Segment Disclosures
In November 2023, the FASB issued guidance intended to improve reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. Among other changes, the amendments will require disclosure of significant segment expenses that are regularly provided to the chief operating decision maker and included within each reported measure of segment profit or loss. The amendments are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, and should be applied on a retrospective basis. Early adoption is permitted. We plan to adopt the annual and interim disclosure requirements on January 1, 2024 and January 1, 2025, respectively, and are currently evaluating the impact of this amended guidance on our disclosures.

4. DISPOSITIONS AND IMPAIRMENTS

Sale-Leaseback Transaction
On March 21, 2023, we sold our corporate headquarters facility and approximately 24 acres of underlying land located in San Antonio, Texas (the Corporate Headquarters) for an aggregate cash sales price of $103.0 million and immediately entered into an operating lease agreement (the HQ Lease Agreement) to lease back the Corporate Headquarters for an initial term of 20 years, with two renewal options of ten years each (the Sale-Leaseback Transaction). Upon closing of the sale in the first quarter of 2023, the Sale-Leaseback Transaction qualified as a completed sale, and we recognized a gain of $41.1 million, which is presented in “Gain on sale of assets” on the consolidated statements of income. We entered into the Sale-Leaseback Transaction in order to monetize the Corporate Headquarters, and used the proceeds to repay outstanding borrowings under our Revolving Credit Agreement in order to position ourselves to redeem the Series D Preferred Units.

Point Tupper Terminal Disposition
On April 29, 2022, we sold the equity interests in our wholly owned subsidiaries that owned our Point Tupper terminal facility in Nova Scotia, Canada (the Point Tupper Terminal Operations) to EverWind Fuels for $60.0 million (the Point Tupper Terminal Disposition). The terminal facility had a storage capacity of 7.8 million barrels and was included in the storage segment. We utilized the sales proceeds to repay outstanding borrowings under our Revolving Credit Agreement and improve our debt metrics.

During the first quarter of 2022, we determined that the Point Tupper Terminal Operations met the criteria to be classified as held for sale. We compared the carrying value of the Point Tupper Terminal Operations, which included $42.2 million in cumulative foreign currency translation losses accumulated since our acquisition of the Point Tupper terminal facility in 2005, to its fair value less costs to sell, and we recognized a pre-tax impairment loss of $46.1 million in the first quarter of 2022, which is presented in “Other impairment losses” on the consolidated statements of income. We believe that the sales price of $60.0 million provided a reasonable indication of the fair value of the Point Tupper Terminal Operations as it represented an exit price in an orderly transaction between market participants. The sales price was a quoted price for identical assets and liabilities in a market that was not active and, thus, our fair value estimate fell within Level 2 of the fair value hierarchy. Upon closing in the second quarter of 2022, we released $39.6 million of foreign currency translation losses from AOCI and finalized our sales price, resulting in a gain of $1.6 million, which is presented in “Other income, net” on the consolidated statements of income.

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Eastern U.S. Terminals Disposition
On August 1, 2021, we entered into an agreement (the Purchase Agreement) to sell nine U.S. terminal and storage facilities, including all our North East Terminals and one terminal in Florida (the Eastern U.S. Terminal Operations) to Sunoco LP for $250.0 million (the Eastern U.S. Terminals Disposition). The Eastern U.S. Terminal Operations included terminals in the following locations; Jacksonville, Florida; Andrews Air Force Base, Maryland; Baltimore, Maryland; Piney Point, Maryland; Virginia Beach, Virginia; Paulsboro, New Jersey; and Blue Island, Illinois, as well as both Linden, New Jersey terminals. The Eastern U.S. Terminal Operations had an aggregate storage capacity of 14.8 million barrels and were included in the storage segment. We closed the sale on October 8, 2021 and used the proceeds from the sale to reduce debt and improve our debt metrics.

The Eastern U.S. Terminal Operations met the criteria to be classified as held for sale upon our entrance into the Purchase Agreement during the third quarter of 2021. At that time, we allocated goodwill of $34.1 million to the Eastern U.S. Terminal Operations based on its fair value relative to the terminals reporting unit, with which it had been fully integrated. We tested the allocated goodwill for impairment by comparing the fair value of the Eastern U.S. Terminal Operations to its carrying value. The results of our goodwill impairment test indicated that the carrying value of the Eastern U.S. Terminal Operations exceeded its fair value, and we recognized a related goodwill impairment charge of $34.1 million in the third quarter of 2021 to reduce the allocated goodwill to $0. The goodwill impairment loss is reported in “Goodwill impairment loss” on the consolidated statements of income. We believe that the sales price of $250.0 million provided a reasonable indication of the fair value of the Eastern U.S. Terminal Operations as it represented an exit price in an orderly transaction between market participants. The sales price was a quoted price for identical assets and liabilities in a market that was not active and, thus, our fair value estimate fell within Level 2 of the fair value hierarchy.

We 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 “Other impairment losses” on the consolidated statements of income. The asset impairment loss included $23.9 million related to intangible assets representing customer contracts and relationships.

We determined the assets included in the Point Tupper Terminal Disposition and the Eastern U.S. Terminals Disposition were no longer synergistic with our core assets, and these dispositions did not qualify, either individually or in the aggregate, for reporting as discontinued operations, as the sales did not represent strategic shifts that would have a major effect on our operations or financial results.

Houston Pipeline Impairment
In the third quarter of 2021, we recorded a long-lived asset impairment charge of $59.2 million within our pipeline segment related to our refined product pipeline extending from Mt. Belvieu, Texas to Corpus Christi, Texas (the Houston Pipeline). During the third quarter of 2021, we identified an indication of impairment related to the southern section of the 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 “Other impairment losses” on the consolidated statements of income. We determined that the northern portion of the pipeline was not impaired.

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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:
202320222021
Contract AssetsContract LiabilitiesContract AssetsContract LiabilitiesContract AssetsContract Liabilities
(Thousands of Dollars)
Balances as of January 1:
Current portion$2,612 $(17,647)$2,336 $(15,443)$2,694 $(22,019)
Noncurrent portion304 (41,405)504 (46,027)932 (47,537)
Total2,916 (59,052)2,840 (61,470)3,626 (69,556)
Activity:
Additions6,621 (66,796)6,137 (45,200)3,888 (41,121)
Transfer to accounts receivable(5,699)— (5,978)— (3,977)— 
Transfer to revenues— 57,439 (83)47,618 (697)49,207 
Total922 (9,357)76 2,418 (786)8,086 
Balances as of December 31:
Current portion3,109 (27,131)2,612 (17,647)2,336 (15,443)
Noncurrent portion729 (41,278)304 (41,405)504 (46,027)
Total$3,838 $(68,409)$2,916 $(59,052)$2,840 $(61,470)

Contract assets relate to performance obligations satisfied in advance of scheduled billings. Current contract assets are included in “Prepaid and other current assets” and noncurrent contract assets are included in “Other long-term assets, net” on the consolidated balance sheets. Contract liabilities relate to payments received in advance of satisfying performance obligations under a contract, which primarily result from contracts with an incentive pricing structure, CIAC payments and contracts with MVCs. The current portion of contract liabilities is included in “Accrued liabilities” and the noncurrent portion of contract liabilities is 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, 2023:
Remaining Performance Obligations
(Thousands of Dollars)
2024$373,630 
2025242,776 
2026173,095 
202782,500 
202845,412 
Thereafter82,143 
Total$999,556 

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

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Disaggregation of Revenues
The following table disaggregates our revenues:
Year Ended December 31,
202320222021
(Thousands of Dollars)
Pipeline segment:
Crude oil pipelines$388,301 $391,176 $331,485 
Refined products and ammonia pipelines485,568 437,015 430,753 
Total pipeline segment revenues from contracts with customers873,869 828,191 762,238 
Storage segment:
Throughput terminals104,495 110,591 122,331 
Storage terminals (excluding lessor revenues)169,810 180,903 263,883 
Total storage segment revenues from contracts with customers274,305 291,494 386,214 
Lessor revenues45,294 43,055 41,454 
Total storage segment revenues319,599 334,549 427,668 
Fuels marketing segment:
Revenues from contracts with customers440,725 520,486 428,608 
Consolidation and intersegment eliminations(6)(3)(14)
Total revenues$1,634,187 $1,683,223 $1,618,500 

6. ALLOWANCE FOR CREDIT LOSSES

As of and for the Linden Acquisition using the acquisition method. The purchase price has been allocated based on the estimated fair values of the individual assets acquiredyears ended December 31, 2023, 2022 and liabilities assumed at the date of the acquisition.

The final purchase price allocation was as follows (in thousands of dollars):
Cash paid for the Linden Acquisition$142,500
Fair value of liabilities assumed22,865
Consideration165,365
Acquisition date fair value of previously held equity interest128,000
Total$293,365
  
Current assets (a)$9,513
Property, plant and equipment134,484
Goodwill79,208
Intangible assets (b)70,050
Other long-term assets110
Purchase price allocation$293,365
(a)Current assets include a receivable of $7.8 million related to a pre-acquisition insurance claim, for which proceeds were received in 2015.
(b)Intangible assets primarily consist of customer contracts and relationships and are being amortized over 10 years.

5. ALLOWANCE FOR DOUBTFUL ACCOUNTS
The changes in the2021, balances and activity related to our allowance for doubtful accounts consisted of the following:credit losses were immaterial.

 Year Ended December 31,
 2017 2016 2015
 (Thousands of Dollars)
Balance as of beginning of year$7,756
 $8,473
 $7,808
Increase in allowance, net2,217
 24
 965
Accounts charged against the allowance(25) (741) (300)
Balance as of end of year$9,948
 $7,756
 $8,473

6.7. INVENTORIES

Inventories consisted of the following:
 December 31,
 20232022
 (Thousands of Dollars)
Petroleum products$13,533 $11,291 
Materials and supplies5,090 4,106 
Total$18,623 $15,397 

 December 31,
 2017 2016
 (Thousands of Dollars)
Petroleum products$17,027
 $28,044
Materials and supplies9,830
 9,901
Total$26,857
 $37,945

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



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7. OTHER CURRENT ASSETS
Other current assets consisted of the following:
 December 31,
 2017 2016
 (Thousands of Dollars)
Axeon Term Loan$—
 $110,000
Prepaid expenses15,982
 14,894
Derivative assets—
 155
Other6,526
 7,637
Other current assets$22,508
 $132,686

Axeon Term Loan. In December 2016, Lindsay Goldberg LLC, the private investment firm that owned Axeon, informed us that they entered into an agreement to sell Axeon’s retail asphalt sales and distribution business (the Axeon Sale), and we entered into an agreement with Axeon (the Axeon Letter Agreement) to settle and terminate the Axeon Term Loan for a $110.0 million payment to us upon closing of the Axeon Sale. Therefore, we recorded a charge of $58.7 million, included in “Other (expense) income, net” in the consolidated statements of income, to reduce the carrying amount of the Axeon Term Loan to $110.0 million and reclassified the Axeon Term Loan from “Other long-term assets, net” to “Other current assets” on the consolidated balance sheet as of December 31, 2016. The Axeon Sale closed on February 22, 2017, at which time we received the $110.0 million payment in accordance with the Axeon Letter Agreement. Furthermore, the Axeon Term Loan and our obligation to provide ongoing credit support to Axeon all terminated concurrently on February 22, 2017. Please refer to Note 15 for a discussion of the guarantees. In addition, in connection with the closing of the Axeon Sale, the terminal storage agreements that Axeon has with our Jacksonville, FL and Baltimore, MD terminal facilities were amended to increase the storage fees.

Prior to the closing of the Axeon Sale, we reviewed the financial information of Axeon monthly for possible credit loss indicators. We recognized interest income associated with the Axeon Term Loan ratably over the term of the loan in “Interest expense, net” on the consolidated statements of income.

8. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment at cost, consisted of the following:
Estimated Useful LivesDecember 31,
 20232022
 (Years)(Thousands of Dollars)
Land, buildings and improvements0-40$290,103 $362,444 
Pipelines, storage and terminals15-405,018,249 4,936,780 
Rights-of-way15-40371,568 365,171 
Construction in progress110,007 69,290 
Property plant and equipment, at cost5,789,927 5,733,685 
Less accumulated depreciation and amortization(2,507,390)(2,330,602)
Property, plant and equipment, net$3,282,537 $3,403,083 

 Estimated Useful Lives December 31,
  2017 2016
 (Years) (Thousands of Dollars)
Land -  $143,527
 $138,224
Land and leasehold improvements5-40 203,085
 187,930
Buildings15-40 151,702
 144,773
Pipelines, storage and terminals20-40 5,080,795
 4,647,718
Rights-of-way20-40 264,170
 202,311
Construction in progress -  400,202
 114,322
Total    6,243,481
 5,435,278
Less accumulated depreciation and amortization    (1,942,548) (1,712,995)
Property, plant and equipment, net    $4,300,933
 $3,722,283
Capitalized interest costs added to property, plant and equipment totaled $5.5$4.3 million, $3.4$3.9 million and $5.5$3.9 million for the years ended December 31, 2017, 20162023, 2022 and 2015,2021, respectively. Depreciation and amortization expense for property, plant and equipment totaled $222.5$217.9 million, $200.7$215.0 million and $192.3$225.7 million for the years ended December 31, 2017, 20162023, 2022 and 2015, respectively.2021, respectively, which includes amortization of finance leases.



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9. INTANGIBLE ASSETS


Intangible assets consisted of the following:
 Weighted-Average Amortization PeriodDecember 31, 2023December 31, 2022
 CostAccumulated
Amortization		CostAccumulated
Amortization
 (Years)(Thousands of Dollars)
Customer contracts and relationships20$726,000 $(251,301)$793,900 $(281,618)
Other472,360 (996)2,359 (945)
Total$728,360 $(252,297)$796,259 $(282,563)

   December 31, 2017 December 31, 2016
 Weighted-Average Amortization Period Cost 
Accumulated
Amortization
 Cost 
Accumulated
Amortization
 (Years) (Thousands of Dollars)
Customer contracts and relationships18 $863,950
 $(81,136) $166,950
 $(41,582)
Other47 2,359
 (694) 2,359
 (644)
Total  $866,309
 $(81,830) $169,309
 $(42,226)
Intangible assets are recorded at fair value as of the date acquired. All of our intangible assets are amortized on a straight-line basis. Amortization expense for intangible assets was $39.6$37.6 million, $13.9$44.1 million and $16.7$48.5 million for the years ended December 31, 2017, 20162023, 2022 and 2015,2021, respectively. The estimated aggregate amortization expense is approximately $51.0$38.0 million for each of the years 20182024 through 2022.2026 and $35.0 million for 2027 and 2028.


10. GOODWILL


Changes in theAs of December 31, 2023, December 31, 2022 and January 1, 2022, carrying amountamounts of goodwill by segment were as follows:
PipelineStorageTotal
 (Thousands of Dollars)
Goodwill$704,231 $253,125 $957,356 
Accumulated impairment loss(225,000)— (225,000)
Net goodwill$479,231 $253,125 $732,356 

We had no activity for the years ended December 31, 2023 or2022.

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 Pipeline Storage 
Fuels
Marketing
 Total
 (Thousands of Dollars)
Balances as of January 1, 2016 and December 31, 2016:       
Goodwill$306,207
 $691,220
 $53,255
 $1,050,682
Accumulated impairment losses—
 (331,913) (22,132) (354,045)
Net goodwill306,207
 359,307
 31,123
 696,637
        
Activity for the year ended December 31, 2017:       
Navigator Acquisition preliminary purchase price allocation (a)400,838
 —
 —
 400,838
        
Balances as of December 31, 2017:       
Goodwill707,045
 691,220
 53,255
 1,451,520
Accumulated impairment losses—
 (331,913) (22,132) (354,045)
Net goodwill$707,045
 $359,307
 $31,123
 $1,097,475
(a)See Note 4 for discussion of the Navigator Acquisition.

11. ACCRUED LIABILITIES
Accrued liabilities consisted of the following:
 December 31,
 2017 2016
 (Thousands of Dollars)
Employee wages and benefit costs$16,963
 $30,807
Unearned income18,243
 14,355
Other26,372
 15,323
Accrued liabilities$61,578
 $60,485


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11. ACCRUED LIABILITIES

Accrued liabilities consisted of the following:
 December 31,
 20232022
 (Thousands of Dollars)
Employee wages and benefit costs$41,290 $40,249 
Revenue contract liabilities27,131 17,647 
Operating lease liabilities6,188 5,541 
Environmental costs4,059 3,122 
Other9,394 9,513 
Accrued liabilities$88,062 $76,072 

12. DEBT


Long-termOur debt consisted of the following:
 December 31,
 Maturity20232022
 (Thousands of Dollars)
Current portion of finance leasesn/a$4,951 $4,416 
5.75% senior notesOctober 1, 2025600,000 600,000 
6.00% senior notesJune 1, 2026500,000 500,000 
Receivables Financing AgreementJuly 1, 202669,800 80,900 
Revolving Credit AgreementJanuary 27, 2027343,000 220,000 
5.625% senior notesApril 28, 2027550,000 550,000 
6.375% senior notesOctober 1, 2030600,000 600,000 
GoZone Bonds2038thru2041322,140 322,140 
Subordinated NotesJanuary 15, 2043402,500 402,500 
Unamortized debt issuance costsn/a(27,809)(33,251)
Long-term debt, excluding finance leases3,359,631 3,242,289 
Long-term portion of finance leases (Note 15)50,707 51,126 
Long-term debt, less current portion of finance leases$3,410,338 $3,293,415 
     December 31,
 Maturity 2017 2016
     (Thousands of Dollars)
Revolving Credit Agreement 2020  $893,311
 $838,992
7.65% senior notes 2018  350,000
 350,000
4.80% senior notes 2020  450,000
 450,000
6.75% senior notes 2021  300,000
 300,000
4.75% senior notes 2022  250,000
 250,000
5.625% senior notes 2027  550,000
 —
Subordinated Notes 2043  402,500
 402,500
GoZone Bonds2038thru2041 365,440
 365,440
Receivables Financing Agreement 2020  62,300
 58,400
Net fair value adjustments, unamortized discounts and unamortized debt issuance costs N/A  (10,492) (968)
Total long-term debt    3,613,059
 3,014,364
 Less current portion    349,990
 —
Long-term debt, less current portion    $3,263,069
 $3,014,364


The long-term debt repayments (excluding finance leases) as of December 31, 2023 are due as follows (in thousands of dollars):follows:
Long-Term Debt Repayments
(Thousands of Dollars)
2024$— 
2025600,000 
2026569,800 
2027893,000 
2028— 
Thereafter1,324,640 
Total repayments3,387,440 
Unamortized debt issuance costs(27,809)
Long-term debt, excluding finance leases$3,359,631 

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2018$350,000
2019—
20201,405,611
2021300,000
2022250,000
Thereafter1,317,940
Total repayments3,623,551
Net fair value adjustments, unamortized discounts and unamortized debt issuance costs(10,492)
Total long-term debt$3,613,059
Interest payments totaled $163.6 million, $146.1 million and $138.9 million for the years ended December 31, 2017, 2016 and 2015, respectively. We amortized an aggregate of $5.0 million, $4.4 million and $4.0 million of debt issuance costs and debt discount for the years ended December 31, 2017, 2016 and 2015, respectively.
Revolving Credit Agreement
On August 22, 2017, NuStar Logistics amended its revolving credit agreement (the Revolving Credit Agreement), mainly to extend the maturity date from October 29, 2019 to October 29, 2020, and to increase the borrowing capacity from $1.50 billion to $1.75 billion. The Revolving Credit Agreement includes the ability to borrow up to the equivalent of $250.0 million in Euros and up to the equivalent of $250.0 million in British Pounds Sterling. Obligations under the Revolving Credit Agreement are guaranteed by NuStar Energy and NuPOP. For the year ended December 31, 2017, we recorded deferred issuance costs of $3.1 million associated with the Revolving Credit Agreement to “Other long-term assets, net” on the consolidated balance sheet.

The Revolving Credit Agreement was also amended to increase the maximum allowed consolidated debt coverage ratio (as defined in the Revolving Credit Agreement) from 5.00-to-1.00 to 5.50-to-1.00 through the rolling period ending March 31, 2018. Subsequently, the maximum allowed consolidated debt coverage ratio may not exceed 5.00-to-1.00 for any rolling period ending on or after June 30, 2018. If we complete one or more acquisitions for aggregate net consideration of at least $50.0 million, our maximum consolidated debt coverage ratio will increase to 5.50-to-1.00 for two rolling periods. On November 22, 2017, the Revolving Credit Agreement was amended to continue to exclude our $402.5 million fixed-to-floating rate subordinated notes from the definition of consolidated debt for purposes of calculating our consolidated debt coverage ratio

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throughInterest payments related to debt obligations (excluding finance leases) totaled $226.9 million, $197.3 million and $220.0 million for the years ended December 31, 2018. The2023, 2022 and 2021, respectively. We amortized $8.4 million, $8.2 million and $7.9 million of debt issuance costs for the years ended December 31, 2023, 2022 and 2021, respectively.

Revolving Credit Agreement
As of December 31, 2023, NuStar Logistics’ $1.0 billion unsecured revolving credit agreement (as amended, the Revolving Credit Agreement) had $652.4 million available for borrowing and $343.0 million borrowings outstanding. Letters of credit issued under our Revolving Credit Agreement totaled $4.6 million as of December 31, 2023. Letters of credit limit the amount we can borrow under our Revolving Credit Agreement. Obligations under our Revolving Credit Agreement are guaranteed by NuStar Energy and NuPOP.

Our 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, 2023, the Consolidated Debt Coverage Ratio (as defined in the Revolving Credit Agreement) may not exceed 5.00-to-1.00 and the Consolidated Interest Coverage Ratio (as defined in the Revolving Credit Agreement), must not be less than 1.75-to-1.00. As of December 31, 2023, we believe that we are in compliance with these financial covenants. Our Revolving Credit Agreement also contains customary restrictive covenants, such as limitations on indebtedness, liens, mergers, asset transfers and certain investing activities.


The requirement not to exceed a maximum consolidated debt coverage ratio may limit the amount we can borrow under the Revolving Credit Agreement to an amount less than the total amount available for borrowing. As of December 31, 2017, we had $853.0 million available for borrowing.
TheOur Revolving Credit Agreement bears interest, at our option, based on an alternative base rate a LIBOR-based rate or a EURIBOR-basedsecured overnight financing rate (SOFR) based rate. The interest rate on theour Revolving Credit Agreement is subject to adjustment if our debt rating is downgraded (or upgraded)or upgraded by certain credit rating agencies. The interest rate on our Revolving Credit Agreement and certain fees under the Receivables Financing Agreement 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, 2017,2023, our weighted-average interest rate under our Revolving Credit Agreement was 3.2%8.0%. During the year ended December 31, 2017,2023, the weighted-average interest rate related to borrowings under theour Revolving Credit Agreement was 2.8%7.8%.
Letters of credit issued under the
On June 30, 2023, we amended our Revolving Credit Agreement, totaled $3.7 million as of December 31, 2017. Letters of credit are limitedprimarily to $400.0 million (including upextend the maturity date from April 27, 2025 to the equivalent of $25.0 million in EurosJanuary 27, 2027. The amendment also includes a requirement that we must demonstrate and upcertify, prior to the equivalent of $25.0 million in British Pounds Sterling) and also may restrict the amount we can borrowusing any borrowings under the Revolving Credit Agreement.
In February 2018, Moody’s Investor Service Inc. (Moody’s) lowered our credit rating from Ba1 to Ba2. This rating downgrade caused the interest rate on our Revolving Credit Agreement to redeem certain unsecured indebtedness or prior to their redemption/repurchase, the Series D Preferred Units, that the sum of our Revolving Credit Agreement availability and unrestricted cash balance is no less than $150.0 million on a pro forma basis both before and immediately after giving effect to the borrowing and the redemption. On January 28, 2022, we amended and restated our Revolving Credit Agreement to, among other items:
(i) increase by 0.25% effective February 2018.the maximum amount of letters of credit capable of being issued from $400.0 million to $500.0 million; (ii) replace London Interbank Offering Rate (LIBOR) benchmark provisions with customary SOFR benchmark provisions; (iii) 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 (iv) add baskets and exceptions to certain negative covenants.

Notes
NuStar Logistics Senior Notes.On April 28, 2017, NuStar Logistics issued $550.0November 1, 2021, we repaid our $250.0 million of 5.625%4.75% senior notes due April 28, 2027. We used the netFebruary 1, 2022 with proceeds of $543.3 million from the offering to fund a portionEastern U.S. Terminals Disposition. We repaid our $300.0 million of the purchase price for the Navigator Acquisition and to pay related fees and expenses. The interest on the 5.625%6.75% senior notes is payable semi-annually in arrears on April 28 and October 28 of each year beginning on October 28, 2017.due February 1, 2021 with borrowings under our Revolving Credit Agreement.


Interest is payable semi-annually in arrears for the $350.0$600.0 million of 7.65%5.75% senior notes, $450.0$500.0 million of 4.80%6.0% senior notes, $300.0$550.0 million of 6.75% senior notes, $250.0 million of 4.75%5.625% senior notes and $550.0$600.0 million of 5.625%6.375% senior notes (collectively, the NuStar Logistics Senior Notes). The interest rate payable on the 7.65% senior notes is subject to adjustment if our debt rating is downgraded (or upgraded) by certain credit rating agencies and was 8.40% as of December 31, 2017. In November 2017, Standard & Poor’s Rating Services lowered our credit rating from BB+ to BB. Additionally, the outlook was changed from stable to negative. The rating downgrade caused the interest rate on the 7.65% senior notes due 2018 to increase from 8.15% to 8.40%. The credit rating downgrade by Moody’s in February 2018 also increased the interest rate by 0.25%, resulting in an interest rate of 8.65% applicable to the interest payment due April 15, 2018.


The NuStar Logistics Senior Notes do not have sinking fund requirements. These notes rank equally with existing senior unsecured indebtedness and senior to existing subordinated indebtedness of NuStar Logistics and contain restrictions on NuStar Logistics’ ability to incur additional secured indebtedness unless the same security is also provided for the benefit of holders of the NuStar Logistics Senior Notes. In addition, the NuStar Logistics Senior Notes limit the ability of NuStar Logistics’ abilityLogistics and its subsidiaries to, among other things, incur indebtedness secured by certain liens, and to engage in certain sale-leaseback transactions.transactions and engage in certain consolidations, mergers or asset sales. At the option of NuStar Logistics, the NuStar Logistics Senior Notes may be redeemed in whole or in part at any time at a redemption price, which includes a make-whole premium, plus accrued and unpaid interest to the redemption date. If we undergo a change of control as defined inthat is followed by a ratings decline that occurs within 60 days of the supplemental indentures for the 6.75% senior notes or the 5.625% senior notes,change of control, each holder of the 6.75% senior notes or the 5.625%applicable senior notes may require us to repurchase all or a portion of its notes at a price equal to 101% of the principal amount of the notes repurchased, plus any accrued and unpaid interest to the date of repurchase. The NuStar Logistics Senior Notes are fully and unconditionally guaranteed by NuStar Energy and NuPOP.
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NuStar Logistics 7.625% Fixed-to-Floating Rate Subordinated Notes.NuStar Logistics’ $402.5 million of 7.625% fixed-to-floating rate subordinated notes are due January 15, 2043 (the Subordinated Notes). The Subordinated Notes are fully and unconditionally guaranteed on an unsecured and subordinated basis by NuStar Energy and NuPOP. The Subordinated Notes bore interest at a fixed annual rate of 7.625%, payable quarterly in arrears beginning on April 15, 2013 and ending onEffective January 15, 2018. Thereafter,2018, the interest rate on the Subordinated Notes bear interest atconverted from a fixed rate to an annual rate equal to the sum of the three-month LIBOR rate for the related quarterly interest period plus 6.734%, payable quarterly, commencing April 15, 2018, unless payment is deferred in accordance with the terms of the notes. Effective with the quarterly interest periods starting after June 30, 2023, three-month LIBOR was replaced with three-month CME term SOFR plus the applicable tenor spread adjustment of 0.26161%. 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 with respect to, or redeem, purchase or make a liquidation payment with respect to, its unitholdersequity securities during the period that interest payments are deferred. As of December 31, 2023, the interest rate was 12.4% on the Subordinated Notes.

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The Subordinated Notes do not have sinking fund requirements and are subordinated to existing senior unsecured indebtedness of NuStar Logistics and NuPOP. The Subordinated Notes do not contain restrictions on NuStar Logistics’ ability to incur additional indebtedness, including debt that ranks senior in priority of payment to the notes. In addition, the Subordinated Notes do not limit NuStar Logistics’ ability to incur indebtedness secured by liens or to engage in certain sale-leaseback transactions. Effective January 15, 2018, we may redeem the Subordinated Notes in whole or in part at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest to the redemption date.
Gulf Opportunity Zone Revenue Bonds
In 2008, 2010 and 2011, the Parish of St. James, Louisiana issued Revenue Bonds Series 2008, Series 2010, Series 2010A, Series 2010B and Series 2011 associated with our St. James terminal expansions pursuant to the Gulf Opportunity Zone Act of 2005 for an aggregate $365.4 million (collectively, the GoZone Bonds). The interest rates on these bonds are based on a weekly tax-exempt bond market interest rate, and interest is paid monthly. Following the issuances, the proceeds were deposited with a trustee and arewere disbursed to us upon our request for reimbursement of expenditures related to our St. James terminal expansions. We includeterminal. On March 4, 2020, NuStar Logistics repaid $43.3 million of GoZone Bonds with unused funds, which had been held in trust. Also in 2020, we completed the amount remainingreoffering and conversion of the GoZone Bonds which, among other things, converted the interest rate from a weekly rate to a long-term rate.

As reflected in the trusttable below, 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 “Other long-term assets, net,” and we include the amountexchange for 100% of bonds issued in “Long-term debt” in our consolidated balance sheets. We did not receive any proceeds from the trustee for the year ended December 31, 2017, and for the year ended December 31, 2016, we received $12.5 million from the trustee.
NuStar Logistics is solely obligated to service the principal plus accrued and unpaid interest, payments associatedafter which these bonds are expected to 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 and unpaid interest. Interest on the GoZone Bonds. LettersBonds is payable semi-annually on June 1 and December 1 of credit were issued by various individual banks on our behalf to guarantee the payment of interest and principal on the bonds. All letters of credit rank equally with existing senior unsecured indebtedness of NuStar Logistics. Obligations under the letters of credit issued are guaranteed by NuStar Energy and NuPOP. The letters of credit issued by individual banks do not restrict the amount we can borrow under the Revolving Credit Agreement.each year.

The following table summarizes the GoZone Bonds outstanding as of December 31, 2017:2023:
SeriesDate IssuedAmount
Outstanding
Interest Rate		Mandatory
Purchase Date		Optional Redemption DateMaturity Date
 (Thousands of Dollars) 
Series 2008June 26, 2008$55,440 6.10 %June 1, 2030n/aJune 1, 2038
Series 2010July 15, 2010100,000 6.35 %n/aJune 1, 2030July 1, 2040
Series 2010AOctober 7, 201043,300 6.35 %n/aJune 1, 2030October 1, 2040
Series 2010BDecember 29, 201048,400 6.10 %June 1, 2030n/aDecember 1, 2040
Series 2011August 9, 201175,000 5.85 %June 1, 2025n/aAugust 1, 2041
Total$322,140 

NuStar Logistics’ agreements with the Parish of St. James related to the GoZone Bonds contain: (i) customary restrictive covenants that limit the ability of NuStar Logistics and its subsidiaries, to, among other things, create liens, enter into certain sale-leaseback transactions, and engage in certain consolidations, mergers or asset sales; and (ii) a repurchase provision which provides that if we undergo a change of control that is followed by a ratings decline that occurs within 60 days of the change of control, then each holder may require the trustee, with funds provided by NuStar Logistics, to repurchase all or a portion of that holder’s GoZone Bonds at a price equal to 101% of the aggregate principal amount repurchased, plus any accrued and unpaid interest.


77
Date Issued Maturity Date 
Amount
Outstanding
 
Amount of
Letter of
Credit
 
Amount Received from
Trustee
 
Amount Remaining in
Trust (a)
 

Interest Rate (b)
    (Thousands of Dollars)  
June 26, 2008 June 1, 2038 $55,440
 $56,169
 $55,440
 $—
 1.8%
July 15, 2010 July 1, 2040 100,000
 101,315
 100,000
 —
 1.7%
October 7, 2010 October 1, 2040 50,000
 50,658
 43,741
 6,546
 1.7%
December 29, 2010 December 1, 2040 85,000
 86,118
 49,782
 35,997
 1.7%
August 29, 2011 August 1, 2041 75,000
 75,986
 75,000
 —
 1.8%
  Total $365,440
 $370,246
 $323,963
 $42,543
  
(a)Amount remaining in trust includes accrued interest.
(b)For the year ended December 31, 2017, our weighted-average interest rate on borrowings was 0.9%.

NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Receivables Financing Agreement
NuStar Energy and NuStar Finance LLC (NuStar Finance), a special purpose entity and wholly owned subsidiary of NuStar Logistics,Energy, are parties to a $125.0$100.0 million receivables financing agreement with a third-party lenders (thelender (as amended, the Receivables Financing Agreement) and agreements with certain of NuStar Energy’s wholly owned subsidiaries (collectively(together with the Receivables Financing Agreement, the Securitization Program). Under the Securitization Program, certain of NuStar Energy’s wholly owned subsidiaries (collectively, the Originators), sell their accounts receivable to NuStar Finance on an ongoing basis, and NuStar Finance provides the newly acquired accounts receivable as collateral for its revolving borrowings under the Receivables Financing Agreement. NuStar Energy provides a performance guarantee in connection with the Securitization Program. The maximum amount available for borrowing by NuStar Finance under the Receivables Financing Agreement is $125.0 million, with an option for NuStar Finance to request an increase of up to $75.0 million from the lenders (for aggregate total borrowings not to exceed $200.0 million). The amount available for borrowing is based on the availability of eligible receivables and other customary factors and conditions. The Securitization Program contains various customary affirmative and negative covenants and default, indemnification and termination provisions, and the Receivables Financing Agreement provides for acceleration of amounts owed upon the occurrence of certain specified events. NuStar Finance’s sole activity consists of purchasing such receivables and providing them as collateral under the Securitization Program. NuStar Finance is a separate legal entity and the assets of NuStar Finance, including these accounts receivable, are not available to satisfy the claims of creditors of NuStar Energy, the Originators or their affiliates.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)




On September 20, 2017,June 29, 2023, we amended the Securitization Program was amended to add certain of NuStar Energy’s wholly owned subsidiaries resulting from the Navigator Acquisition andReceivables Financing Agreement to extend the Securitization Program’s scheduled termination date from June 15, 2018January 31, 2025 to September 20, 2020,July 1, 2026. On January 28, 2022, the Receivables Financing Agreement was amended to, among other items: (i) reduce the floor rate in the calculation of our borrowing rates; and (ii) replace provisions related to the LIBOR rate of interest with the optionreferences to renew for additional 364-day periods thereafter. SOFR rates of interest.

Borrowings by NuStar Finance under the Receivables Financing Agreement bear interest, at the applicable bankNuStar Finance’s option, at a base rate or a SOFR rate, each as defined underin the Receivables Financing Agreement. As of December 31, 20172023 and 2016,2022, accounts receivable totaling $92.6$121.0 million and $104.5$121.5 million, respectively, were included in the Securitization Program. As of December 31, 2023, our interest rate under the Securitization Program was 7.0%. The weighted averageweighted-average interest rate related to outstanding borrowings under the Securitization Program during the year ended December 31, 20172023 was 2.0%6.7%.


Short-Term Lines of Credit
NuStar Logistics is party to two short-term line of credit agreements with an aggregate uncommitted borrowing capacity of up to $85.0 million, which allow us to better manage fluctuations in our daily cash requirements and minimize our excess cash balances. The interest rate and maturity vary and are determined at the time of borrowing. We had $35.0 million outstanding under these lines of credit as of December 31, 2017. Obligations under these short-term line of credit agreements are guaranteed by NuStar Energy. The weighted-average interest rate related to outstanding borrowings under our short-term lines of credit during the years ended December 31, 2017 and 2016, was 2.7% and 2.0%, respectively.

13. HEALTH, SAFETY AND ENVIRONMENTAL MATTERS


Our operations are subject to extensive international, federal, state and local environmental laws and regulations, in the U.S. and in the other countries in which we operate,Mexico, including those relating to the discharge of materials into the environment, waste management, remediation, the characteristics and composition of fuels, climate change and greenhouse gases. Our operations are also subject to extensive health, safety and security laws and regulations, including those relating to worker and pipeline safety, pipeline and storage tank integrity and operations security. The principal environmental, health, safety and security risks associated with our operations relate to unauthorized emissions into the air, releases into soil, surface water or groundwater, personal injury and property damage. We have adopted policies, practices, systems and procedures designed to comply with the laws and regulations, and to help minimize and mitigate these risks, limit the liability that could result from such events, prevent material environmental or other damage, ensure the safety of our employees and the public and secure our pipelines, terminals and operations.

Compliance with environmental, health, safety and security laws, regulations and related permits increases our capital expenditures and operating expenses, and violation of these laws, regulations or permits could result in significant civil and criminal liabilities, injunctions or other penalties. Future governmental action and regulatory initiatives could result in more restrictive laws and regulations, which could increase required capital expenditures and operating expenses. The risk of additional compliance expenditures, expenses and liabilities are inherent to government-regulated industries, including midstream energy. As a result, there can be no assurances that significant expenditures, expenses and liabilities will not be incurred in the future.

Most of our pipelines are subject to federal regulation by one or more of the following governmental agencies: the Federal Energy Regulatory Commission (the FERC), the Surface Transportation Board (the STB), the Department of Transportation (DOT)(the DOT), the Environmental Protection Agency (EPA)(the EPA) and the Department of Homeland Security. Additionally, the operations and integrity of theour pipelines are subject to the respective state jurisdictions along the routes of the systems.states those lines traverse.
We have adopted policies, practices and procedures to address pollution control, pipeline integrity, operator qualifications, public relations and education, process safety management, risk management planning, hazard communication, emergency response planning, community right-to-know, occupational health and the handling, storage, use and disposal of hazardous materials. Our policies are designed to comply with applicable federal, state and local regulations and to prevent material environmental or other damage, to ensure the safety of our pipelines, our employees, the public and the environment and to limit the financial liability that could result from such events. Future governmental action and regulatory initiatives could necessitate changes to expected operating permits and procedures, additional remedial actions or increased capital expenditures and operating costs. Risks of additional costs and liabilities are inherent within the industry, and there can be no assurances that significant costs and liabilities will not be incurred in the future.
Environmental and safety exposures and liabilities are difficult to assess and estimate due to unknown factors such as the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental and safety laws and regulations may change in the future. Although environmental and safety costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.


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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)



The balance of and changes in the accruals for environmental matters were as follows:
 Year Ended December 31,
 20232022
 (Thousands of Dollars)
Balance as of the beginning of year$8,369 $7,748 
Additions to accrual3,153 2,640 
Payments(2,049)(2,019)
Balance as of the end of year$9,473 $8,369 

 Year Ended December 31,
 2017 2016
 (Thousands of Dollars)
Balance as of the beginning of year$5,120
 $7,667
Additions to accrual3,186
 870
Payments(2,675) (3,302)
Foreign currency translation52
 (115)
Balance as of the end of year$5,683
 $5,120
Accruals for environmental matters are included in the consolidated balance sheets as follows:
 December 31,
 20232022
 (Thousands of Dollars)
Accrued liabilities$4,059 $3,122 
Other long-term liabilities5,414 5,247 
Accruals for environmental matters$9,473 $8,369 

 December 31,
 2017 2016
 (Thousands of Dollars)
Accrued liabilities$3,054
 $3,281
Other long-term liabilities2,629
 1,839
Accruals for environmental matters$5,683
 $5,120

14. COMMITMENTS AND CONTINGENCIES
Commitments
Future minimum payments applicable to all noncancellable purchase obligations as of December 31, 2023 are as follows:
 Payments Due by Period
 20242025202620272028ThereafterTotal
 (Thousands of Dollars)
Purchase obligations$6,406 $5,003 $1,851 $1,134 $867 $4,038 $19,299 

Our purchase obligations primarily consist of various service agreements with information technology providers, as well as right-of-way and easement agreements with government agencies and other landowners.

Contingencies
We have contingent liabilities resulting from various litigation, claims and commitments. We record accruals for loss contingencies when losses are considered probable and can be reasonably estimated. Legal fees associated with defending the Partnership in legal matters are expensed as incurred. We accrued $7.3$1.3 million and $0.3 million for contingent losses as of December 31, 2017,2023 and had no accrual for contingent losses as of December 31, 2016.2022, respectively. The amount that will ultimately be paid related to such matters may differ from the recorded accruals, and the timing of such payments is uncertain. In addition, due to the inherent uncertainty of litigation, there can be no assuranceWe evaluate each contingent loss at least quarterly, and more frequently as each matter progresses and develops over time, and we do not believe that the resolution of any particular claim or proceeding, or all matters in the aggregate, would not have a material adverse effect on our results of operations, financial position or liquidity.
Commitments
15. LEASE ASSETS AND LIABILITIES

Lessee Commitments. Future minimum rental payments applicable to all noncancellable operating leases and purchase obligations as of December 31, 2017 are as follows:Arrangements
 Payments Due by Period
 2018 2019 2020 2021 2022 
There-
after
 Total
 (Thousands of Dollars)
Operating leases$39,236
 $34,203
 $19,541
 $13,324
 $7,295
 $68,386
 $181,985
Purchase obligations$6,963
 $6,133
 $4,686
 $4,690
 $4,480
 $300
 $27,252
Rental expense for all operating leases totaled $36.2 million, $37.0 million and $39.7 million for the years ended December 31, 2017, 2016 and 2015, respectively. Our operating leases consist primarily of the following:
a ten-year lease for tugsland and barges utilized at our St. Eustatius facility for bunker fuel sales, with two five-year renewal options; and
landdock leases at various terminal facilities and the HQ Lease Agreement. As of December 31, 2023, land and dock leases generally have remaining terms of about five years and include options to extend for five to 25 years, which we are reasonably certain to exercise. Pursuant to the HQ Lease Agreement, which we entered into in the first quarter of 2023, rent for the initial term starts at $6.4 million per year, increasing annually by 2.5%. The HQ Lease Agreement has an initial term of 20 years, with original terms ranging from 10two renewal options of ten years each. At inception of the HQ Lease Agreement, we assumed a reasonably certain term of 20 years and we recorded additional lease liabilities and right-of-use assets totaling $82.2 million.

The primary component of our finance lease portfolio is a dock at our Corpus Christi North Beach terminal, which includes a commitment for minimum dockage and wharfage throughput volumes. The dock lease has a remaining term of approximately two years and three additional five-year renewal periods, all of which we are reasonably certain to 100 years.exercise.

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Our purchase obligations primarily consistNUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Right-of-use assets and lease liabilities included in our consolidated balance sheet were as follows:
December 31,
Balance Sheet Location20232022
(Thousands of Dollars)
Right-of-use assets:
OperatingOther long-term assets, net$143,937 $62,745 
Finance
Property, plant and equipment, net of accumulated amortization of $25,628 and $19,295
$66,840 $68,219 
Lease liabilities:
Operating:
CurrentAccrued liabilities$6,188 $5,541 
NoncurrentOther long-term liabilities137,945 56,577 
Total operating lease liabilities$144,133 $62,118 
Finance:
CurrentCurrent portion of finance leases$4,951 $4,416 
NoncurrentLong-term debt, less current portion of finance leases50,707 51,126 
Total finance lease liabilities$55,658 $55,542 

As of an eleven-year chemical supply agreement related toDecember 31, 2023, maturities of our pipelines.operating and finance lease liabilities were as follows:
Operating LeasesFinance Leases
(Thousands of Dollars)
2024$14,267 $7,067 
202514,221 6,250 
202613,810 5,703 
202713,791 4,934 
202813,554 4,311 
Thereafter182,655 45,802 
Total lease payments$252,298 $74,067 
Less: Interest108,165 18,409 
Present value of lease liabilities$144,133 $55,658 


Costs incurred for leases were as follows:
Year Ended December 31,
202320222021
(Thousands of Dollars)
Operating lease cost$15,754 $11,777 $15,323 
Finance lease cost:
Amortization of right-of-use assets6,378 5,770 5,251 
Interest expense on lease liability2,109 2,023 2,081 
Short-term lease cost11,811 10,345 14,198 
Variable lease cost4,640 4,830 4,939 
Total lease cost$40,692 $34,745 $41,792 

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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The table below presents additional information regarding our leases.
202320222021
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$12,670$2,095$11,156$2,019$12,829$2,090
Cash outflows from financing activities$—$4,882$—$4,222$—$4,244
Right-of-use assets obtained in exchange for lease liabilities$88,226$5,064$10,060$3,004$3,278$3,173
As of December 31:
Weighted-average remaining lease term (in years)181516161318
Weighted-average discount rate6.2 %3.9 %3.8 %3.6 %3.2 %3.6 %

Lessor Revenues. Arrangements
We have entered into certain revenue arrangements where we are considered to be the lessor in accordance with GAAP.lessor. Under the largest of these arrangements, we lease certain of our storage tanks in exchange for a fixed fee, subject to an annual consumer price indexCPI adjustment. The arrangementsoperating leases commenced on January 1, 2017, and have initial terms of ten years with successive ten-year automatic renewal terms. We recognized $39.1 million of lease revenues from these leases of $45.3 million, $43.1 million, and $41.5 million for the yearyears ended December 31, 2017,2023, 2022 and 2021, respectively, which isare included in “Service revenues”“Service revenues” in the consolidated statements of income. FutureAs of December 31, 2023, we expect to receive minimum lease payments totaling $117.4 million, based upon the CPI as of the adoption date. We will recognize these payments ratably over the remaining initial lease term.


The table below presents cost, accumulated depreciation and useful life information related to our storage lease assets, which are included in our “Pipeline, storage and terminals” asset class within property, plant and equipment:
Estimated Useful LifeDecember 31,
 20232022
 (Years)(Thousands of Dollars)
Lease storage assets, at cost30$257,666 $251,801 
Less accumulated depreciation(157,836)(148,899)
Lease storage assets, net$99,830 $102,902 

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.
The remaining fair value amounts associated with unwound forward-starting interest rate swap agreements and included in “Accumulated other comprehensive loss” on the consolidated balance sheets are $31.8 million and $34.4 million as of December 31, 2023 and 2022, respectively. These amounts are amortized ratably over the remaining life of the related debt
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


instrument into “Interest expense, net” on the consolidated statements of income. 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” on the consolidated statements of income.


revenues we expect to receive under these lease arrangements as of December 31, 2017 total $352.2 million, which we will recognize ratably overOur forward-starting interest rate swaps had the following nine years. impact on earnings:
Year Ended December 31,
202320222021
(Thousands of Dollars)
Reclassification of loss on cash flow hedges to interest expense, net$2,581 $2,106 $5,664 

As of December 31, 2017,2023, we expect to reclassify a loss of $3.6 million to “Interest expense, net” within the cost and accumulated depreciation of leased storage assets totaled $229.8 million and $104.9 million, respectively.next twelve months associated with unwound forward-starting interest rate swap agreements.


15. FAIR VALUE MEASUREMENTSFair Value Measurements
We segregate the inputs used in measuring fair value into three levels: Level 1, defined as observable inputs such as quoted prices for identical assets or liabilities in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable, such as quoted prices for similar assets or liabilities in active markets or quoted prices for identical assets or liabilities in markets that are not active; and Level 3, defined as unobservable inputs for which little or no market data exists. We consider counterparty credit risk and our own credit risk in the determination of all estimated fair values.
Recurring Fair Value Measurements
The following assets and liabilities are measured at fair value on a recurring basis:
 December 31, 2017
 Level 1 Level 2 Level 3 Total
 (Thousands of Dollars)
Assets:       
Other current assets:       
Product imbalances$3,890
 $—
 $—
 $3,890
Liabilities:       
Accrued liabilities:       
Product imbalances$(1,534) $—
 $—
 $(1,534)
Commodity derivatives(878) —
 —
 (878)
Interest rate swaps—
 (5,394) —
 (5,394)
Other long-term liabilities:       
Interest rate swaps—
 (4,594) —
 (4,594)
Total$(2,412) $(9,988) $—
 $(12,400)

 December 31, 2016
 Level 1 Level 2 Level 3 Total
 (Thousands of Dollars)
Assets:       
Other current assets:       
Product imbalances$1,551
 $—
 $—
 $1,551
Commodity derivatives—
 155
 —
 155
Other long-term assets, net:       
Interest rate swaps—
 1,314
 —
 1,314
Total$1,551
 $1,469
 $—
 $3,020
Liabilities:       
Accrued liabilities:       
Product imbalances$(1,577) $—
 $—
 $(1,577)
Commodity derivatives(4,887) (165) —
 (5,052)
Other long-term liabilities:       
Guarantee liability—
 —
 (1,230) (1,230)
Interest rate swaps—
 (2,632) —
 (2,632)
Total$(6,464) $(2,797) $(1,230) $(10,491)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)



Product Imbalances.Since we value our assets and liabilities related to product imbalances using quoted market prices in active markets as of the reporting date, we include these product imbalances in Level 1 of the fair value hierarchy.
Commodity Derivatives. We base the fair value of certain of our commodity derivative instruments on quoted prices on an exchange; accordingly, we include these items in Level 1 of the fair value hierarchy. We also had derivative instruments for which we determined fair value using industry pricing services and other observable inputs, such as quoted prices on an exchange for similar derivative instruments, and we included these derivative instruments in Level 2 of the fair value hierarchy. See Note 16 for a discussion of our derivative instruments.
Interest Rate Swaps.Because we estimate the fair value of our forward-starting interest rate swaps using discounted cash flows, which use observable inputs such as time to maturity and market interest rates, we include these interest rate swaps in Level 2 of the fair value hierarchy.

Guarantees. We previously provided guarantees for commodity purchases, lease obligations and certain utilities for Axeon. As of December 31, 2016, we provided guarantees totaling $54.1 million, and one guarantee that did not specify a maximum amount. We estimated the fair value based on the guarantees outstanding and an estimate of the amount we would be obligated to pay under the guarantees at the time of default and considering the probability of default by Axeon. Our estimate of the fair value was based on significant inputs not observable in the market and thus fell within Level 3 of the fair value hierarchy. In conjunction with the termination of the Axeon Term Loan on February 22, 2017, our obligation to provide credit support to Axeon ceased. See Note 7 for additional information on the Axeon Term Loan.

Fair Value of Financial Instruments
We recognize cash equivalents, receivables, payables and debt in our consolidated balance sheets at their carrying amounts. The fair values of these financial instruments, except for long-term debt other than finance leases, approximate their carrying amounts. The estimated fair values and carrying amounts of the long-term debt, including the current portion, and the Axeon Term Loanexcluding finance leases, were as follows:
December 31,
20232022
 (Thousands of Dollars)
Fair value$3,426,307 $3,169,664 
Carrying amount$3,359,631 $3,242,289 
 December 31, 2017 December 31, 2016
 Long-term Debt Long-term Debt Axeon Term Loan
 (Thousands of Dollars)
Fair value$3,677,622
 $3,084,762
 $110,000
Carrying amount$3,613,059
 $3,014,364
 $110,000


We have estimated the fair value of our publicly traded senior notes based upon quoted prices in active markets; therefore, we determined that the fair value of our publicly traded senior notes falls in Level 1 of the fair value hierarchy. ForWith regard to our other debt, for which a quoted market price is not available, we have estimated the fair value using a discounted cash flow analysis using current incremental borrowing rates for similar types of borrowing arrangements and determined that the fair value falls in Level 2 of the fair value hierarchy. We determined that the fair value of the Axeon Term Loan approximated itsThe carrying value as of December 31, 2016, which is included in “Other current assets” on the consolidated balance sheet. See Note 7 for additional information on the Axeon Term Loan.includes unamortized debt issuance costs.


16. DERIVATIVES AND RISK MANAGEMENT ACTIVITIES17. SERIES D CUMULATIVE CONVERTIBLE PREFERRED UNITS
We utilize various derivative instruments to manage our exposure to interest rate risk
Units Issued 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 volumes, grades, locations and delivery schedules, to help ensure that our hedging activities address our market risks.Outstanding

Interest Rate Risk
We are a party to certain interest rate swap agreements to manage our exposure to changes in interest rates, which include forward-starting interest rate swap agreements related to forecasted debt issuances inIn 2018, and 2020. Wewe entered into these swaps during the year ended December 31, 2015,an agreement with investment funds, accounts and entities managed by EIG Management Company, LLC and FS/EIG Advisors, LLC to issue and sell Series D Cumulative Convertible Preferred Units (the Series D Preferred Units) in order to hedge the riska private placement. The Partnership issued a total 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. Under the terms of the swaps, we pay a fixed rate and receive a rate based on the three-month USD LIBOR. These swaps qualify as cash flow hedges, and we designate them as such. We record the effective portion of mark-to-market adjustments as a component of AOCI, and the amount in AOCI will be recognized in “Interest expense, net” as the forecasted interest payments occur or if the interest payments are probable not to occur. As of December 31, 2017 and 2016, the aggregate notional amount of forward-starting interest rate swaps totaled $600.0 million.23,246,650 Series D Preferred Units.



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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


The following is a summary of the Series D Preferred Units issued and outstanding:
Transaction DatePrice per UnitNumber of Units
IssuanceJune 29, 2018$25.3815,760,441 
IssuanceJuly 13, 2018$25.387,486,209 
Total units issued23,246,650 
Units outstanding as of January 1, 202223,246,650 
RepurchaseNovember 22, 2022$32.73(6,900,000)
Units outstanding as of December 31, 202216,346,650 
RedemptionJune 30, 2023$31.88(5,500,000)
RedemptionJuly 31, 2023$32.18(2,560,000)
RedemptionSeptember 12, 2023$32.59(8,286,650)
Units outstanding as of December 31, 2023— 


TheRedemptions and Repurchase
In the fourth quarter of 2022, we repurchased 6,900,000 Series D Preferred Units with borrowings under our Revolving Credit Agreement. In the second and third quarters of 2023, we redeemed all the remaining fairoutstanding Series D Preferred Units at the then applicable redemption price of $31.73 per Series D Preferred Unit plus accrued and unpaid distributions. We funded the redemptions primarily with borrowings under our Revolving Credit Agreement, which had been partially paid down with proceeds from the Sale-Leaseback Transaction in the first quarter of 2023 and with proceeds from the issuance of common units in the third quarter of 2023.

On the notification dates for each redemption or repurchase, those Series D Preferred Units became mandatorily redeemable; therefore, we reclassified those Series D Preferred Units from mezzanine equity to liability-classified mandatorily redeemable Series D Preferred Units valued at the redemption or repurchase price, excluding accrued distributions (Net Redemption/Repurchase Price). We recorded the difference between the carrying value amount associated with unwound fixed-to-floating interest rate swap agreementsat each notification date and the Net Redemption/Repurchase Price as a deemed distribution, which reduced our common equity and was subtracted from net income to arrive at net income attributable to common units in the calculation of basic and diluted net income per common unit. At each closing, we accounted for the redemptions and repurchase as extinguishments of debt. Pursuant to our partnership agreement, the Series D Preferred Units were cancelled; therefore, the Series D Preferred Units no longer represent a limited partnership interest.

Distributions accrued for redeemed Series D Preferred Units from the notification dates to the redemption dates for the year ended December 31, 2023 totaled a $15.6$4.8 million, and a $21.1 million gain as of December 31, 2017 and 2016, respectively, and is includedare reported in “Long-term debt” on the consolidated balance sheets. The remaining fair value amount associated with unwound forward-starting interest rate swap agreements totaled a $14.3 million and a $20.9 million loss as of December 31, 2017 and 2016, respectively, and is included in AOCI on the consolidated balance sheets. These amounts are amortized ratably over the remaining life of the related debt instrument into “Interest expense, net” on the consolidated statements of income.


Commodity Price Risk
We are exposed to market risks related to the volatility of petroleum product prices. In order to reduce the risk of commodity price fluctuations with respect to our petroleum product inventories and related firm commitments to purchase and/or sell such inventories, we utilize commodity futures and swap contracts, which qualify and we designate as fair value hedges. Derivatives that are intended to hedge our commodity price risk, but fail to qualify as fair value or cash flow hedges, are considered economic hedges, and we record associated gains and losses in net income. Our risk management committee oversees our trading controls and procedures and certain aspects of commodity and trading risk management. Our risk management committee also reviews all new commodity and trading risk management strategies in accordance with our risk management policy, as approved by our board of directors. We ceased marketing crude oil in the second quarter of 2017 and exited our heavy fuels trading operations in the third quarter of 2017, thereby reducing our overall hedging activity.
The volume of commodity contracts is based on open derivative positions and represents the combined volume of our long and short open positions on an absolute basis, which totaled 1.2 million barrels and 4.7 million barrels as of December 31, 2017 and 2016, respectively. We had $0.3 million and $1.8 million of margin deposits as of December 31, 2017 and December 31, 2016, respectively.
The fair values of our derivative instruments included in our consolidated balance sheets were as follows:

   Asset Derivatives Liability Derivatives
 Balance Sheet Location December 31,
  2017 2016 2017 2016
   (Thousands of Dollars)
Derivatives Designated as
Hedging Instruments:
         
Interest rate swapsOther long-term assets, net $—
 $1,314
 $—
 $—
Commodity contractsAccrued liabilities —
 144
 (112) (3,566)
Interest rate swapsAccrued liabilities —
 —
 (5,394) —
Interest rate swapsOther long-term liabilities —
 —
 (4,594) (2,632)
Total  —
 1,458
 (10,100) (6,198)
          
Derivatives Not Designated
as Hedging Instruments:
         
Commodity contractsOther current assets —
 265
 —
 (110)
Commodity contractsAccrued liabilities 742
 9,128
 (1,508) (10,758)
Total  742
 9,393
 (1,508) (10,868)
          
Total Derivatives  $742
 $10,851
 $(11,608) $(17,066)


Certain of our derivative instruments are eligible for offset in the consolidated balance sheets and subject to master netting arrangements. Under our master netting arrangements, there is a legally enforceable right to offset amounts, and we intend to settle such amounts on a net basis. The following are the net amounts presented on the consolidated balance sheets:













83
  December 31,
Commodity Contracts 2017 2016
  (Thousands of Dollars)
Net amounts of assets presented in the consolidated balance sheets $—
 $155
Net amounts of liabilities presented in the consolidated balance sheets $(878) $(5,052)


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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


Information related to the Series D Preferred Unit redemptions and repurchase is shown below (thousands of dollars, except unit and per unit data):

September 12, 2023
Redemption		July 31, 2023 RedemptionJune 30, 2023 RedemptionNovember 22, 2022 Repurchase
Notification dateAugust 14, 2023June 29, 2023May 25, 2023November 16, 2022
Units redeemed/repurchased8,286,6502,560,0005,500,0006,900,000
Redemption/repurchase price per unit, including accrued distributions$32.59 $32.18 $31.88 $32.73 
Redemption/repurchase price, including accrued distributions$270,062 $82,381 $175,340 $225,837 
Accrued distributions7,126 1,152 825 3,450 
Net Redemption/Repurchase Price$262,936 $81,229 $174,515 $222,387 
Carrying value at notification date$230,461 $71,210 $152,467 $188,005 
Net Redemption/Repurchase Price262,936 81,229 174,515 222,387 
Loss to common limited partners attributable to redemption/repurchase$(32,475)$(10,019)$(22,048)$(34,382)
We recognize
For the impactyears ended December 31, 2023 and 2022, we recorded losses of our commodity contracts on earnings in “Cost of product sales”$0.55 and $0.31 per common unit, respectively, attributable to the Series D Preferred Unit redemptions and repurchase.

Distributions
Distributions on the consolidated income statements,Series D Preferred Units were payable out of any legally available funds, accrued and that impactwere cumulative from the issuance dates and were 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 were as follows: (i) 9.75% per annum ($0.619 per unit per distribution period) for the first two years; (ii) 10.75% per annum ($0.682 per unit per distribution period) for years three through five; and (iii) the greater of 13.75% per annum ($0.872 per unit per distribution period) or the distribution per common unit thereafter. While the Series D Preferred Units were outstanding, we were 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) had been, or contemporaneously were being, paid or set aside for payment through the most recent Series D Preferred Unit distribution payment date.

The distribution rate on the Series D Preferred Units increased on June 15, 2023, to the greater of 13.75% per annum ($0.872 per unit per distribution period) or the distribution per common unit. The total distribution for the applicable periods in the table below excludes amounts reported in “Interest expense, net” as described above under “Redemptions and Repurchase.”

Distribution information on the Series D Preferred Units was as follows:
 Distribution PeriodDistribution Rate per UnitTotal Distribution
(Thousands of Dollars)
June 15, 2023 - September 12, 2023$0.872 $5,134 
March 15, 2023 - June 14, 2023$0.682 $10,315 
December 15, 2022 - March 14, 2023$0.682 $11,148 
September 15, 2022 - December 14, 2022$0.682 $14,337 
June 15, 2022 - September 14, 2022$0.682 $15,854 
March 15, 2022 - June 14, 2022$0.682 $15,854 
December 15, 2021 - March 14, 2022$0.682 $15,854 
  Year Ended December 31,
  2017 2016 2015
  (Thousands of Dollars)
Derivatives Designated as Fair Value Hedging Instruments:      
Gain (loss) recognized in income on derivative $806
 $(11,254) $21,589
(Loss) gain recognized in income on hedged item (656) 15,295
 (18,047)
Gain recognized in income for ineffective portion $150
 $4,041
 $3,542
       
Derivatives Not Designated as Hedging Instruments:      
(Loss) gain recognized in income on derivative $(668) $225
 $2,208

Our interest rate swaps had the following impact on earnings:
84
  Year Ended December 31,
  2017 2016 2015
  (Thousands of Dollars)
Derivatives Designated as Cash Flow Hedging Instruments:      
(Loss) gain recognized in other comprehensive (loss) income on
     derivative (effective portion)
 $(8,670) $(2,621) $1,303
Loss reclassified from AOCI into interest expense, net
    (effective portion)
 (6,624) (8,331) (9,802)

As of December 31, 2017, we expect to reclassify a loss of $5.1 million to “Interest expense, net” within the next twelve months associated with unwound forward-starting interest rate swaps.

17. RELATED PARTY TRANSACTIONS

Please refer to Note 28 for a discussion of the merger of a subsidiary of ours with and into NuStar GP Holdings, pursuant to which we will become the sole member of NuStar GP Holdings.

GP Services Agreement. Prior to the Employee Transfer discussed in Note 1, our operations were managed by NuStar GP, LLC under a services agreement effective January 1, 2008 pursuant to which employees of NuStar GP, LLC performed services for our U.S. operations. Employees of NuStar GP, LLC provided services to us and NuStar GP Holdings; therefore, we reimbursed NuStar GP, LLC for all employee costs incurred prior to the Employee Transfer, other than the expenses allocated to NuStar GP Holdings. The following table summarizes information pertaining to our related party transactions prior to the Employee Transfer:
 Year Ended December 31,
 2016 2015
 (Thousands of Dollars)
Operating expenses$21,681
 $135,565
General and administrative expenses$10,493
 $66,769
Expenses included in discontinued operations, net of tax$—
 $2

In conjunction with the Employee Transfer, we entered into an Amended and Restated Services Agreement with NuStar GP, LLC, effective March 1, 2016 (the Amended GP Services Agreement). The Amended GP Services Agreement provides that we will furnish administrative services necessary to conduct the business of NuStar GP Holdings. NuStar GP Holdings will compensate us for these services through an annual fee of $1.0 million, subject to adjustment based on the annual merit increase percentage applicable to our employees for the most recently completed fiscal year and for changes in level of service. The Amended GP Services Agreement will terminate on March 1, 2020 and will automatically renew for successive two-year terms, unless terminated by either party.


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Accounting Treatment

Assignment and Assumption Agreement. Also on March 1, 2016 and in connection withThe Series D Preferred Units included redemption provisions at the Employee Transfer, we entered into an Assignment and Assumption Agreement with NuStar GP, LLC (the Assignment Agreement). Under the Assignment Agreement, NuStar GP, LLC assigned all of its employee benefit plans, programs, contracts, policies, and various of its other agreements and contracts with certain employees, affiliates and third-party service providers (collectively, the Assigned Programs) to NuStar Services Co. In addition, NuStar Services Co agreed to assume the sponsorship of and all obligations relating to the ongoing maintenance and administration of eachoption of the plans and agreements in the Assigned Programs. Certain of our officers are also officers of NuStar GP Holdings and are considered dual employees of ours and NuStar GP Holdings.

The following table summarizes the related party transactions and changes to amounts reported on our consolidated balance sheet as a result of the Employee Transfer on March 1, 2016 (thousands of dollars):
Decrease in related party payable: 
Current$16,014
Long-term32,656
Decrease in related party payable$48,670
  
Changes to our consolidated balance sheet: 
Current and long-term assets$2,154
Current liabilities5,609
Other long-term liabilities34,042
Limited partners’ equity2,664
Accumulated other comprehensive loss4,201
Changes to our consolidated balance sheet$48,670

Non-Compete Agreement. On July 19, 2006, we entered into a non-compete agreement with NuStar GP Holdings, Riverwalk Logistics, L.P. and NuStar GP, LLC (the Non-Compete Agreement). The Non-Compete Agreement became effective on December 22, 2006 when NuStar GP Holdings ceased to be subject to the Amended and Restated Omnibus Agreement, dated March 31, 2006. Under the Non-Compete Agreement, we will have a right of first refusal with respect to the potential acquisition of assets that relate to the transportation, storage or terminalling of crude oil, feedstocks or refined petroleum products (including petrochemicals) in the United States and internationally. NuStar GP Holdings will have a right of first refusal with respect to the potential acquisition of general partner and other equity interests in publicly traded partnerships under common ownership with the general partner interest. With respect to any other business opportunities, neither the Partnership nor NuStar GP Holdings are prohibited from engaging in any business, even if the Partnership and NuStar GP Holdings would have a conflict of interest with respect to such other business opportunity.

18. OTHER (EXPENSE) INCOME
Other (expense) income consisted of the following:
 Year Ended December 31,
 2017 2016 2015
 (Thousands of Dollars)
(Loss) gain from sale or disposition of assets$(4,984) $(64) $1,617
Impairment loss on Axeon Term Loan—
 (58,655) —
Gain associated with Linden Acquisition—
 —
 56,277
Foreign exchange (losses) gains(344) (660) 3,891
Other, net34
 596
 37
Other (expense) income, net$(5,294) $(58,783) $61,822


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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)



19. PARTNERS’ EQUITY

Please refer to Note 28 for a discussion of the merger of a subsidiary of ours with and into NuStar GP Holdings, pursuant to which we will become the sole member of NuStar GP Holdings.

Amendment of Partnership Agreement
In the second quarter of 2017, our general partner amended and restated our partnership agreement in connection with the issuanceholders of the Series BD Preferred Units as described below and upon a Series D Change of Control (as defined in the Navigator Acquisition to waive up to an aggregate $22.0 millionpartnership agreement), which were outside the Partnership’s control. Therefore, the Series D Preferred Units were presented in the mezzanine section of the quarterly incentive distributionsconsolidated balance sheets. The Series D Preferred Units were recorded at their issuance date fair value, net of issuance costs.

The Series D Preferred Units were subject to our general partner for any NS common units issuedaccretion from their carrying value at the issuance date to the redemption value of $29.19 per Series D Preferred Unit, which was based on the redemption right of the Acquisition Agreement (other than thoseSeries D Preferred Unit holders that may have been 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 accretion was treated in the same manner as a distribution and deducted from net income to arrive at net income attributable to NS common units issued under any equity compensation plan) for ten consecutive quarters, starting with the distributions for the second quarter of 2017. The partnership agreement was amendedunits.

18. PARTNERS’ EQUITY

Series A, B and restated again in connection with the issuance ofC Preferred Units
Information on our 8.50% Series A, 7.625% Series B and 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units described below.

Issuance of Common Units
On April 18, 2017, we issued 14,375,000 common units representing limited partner interests at a price of $46.35 per unit. We used(collectively the net proceeds from this offering of $657.5 million, including a contribution of $13.6 million from our general partner to maintain its 2% general partner interest, to fund a portion of the purchase price for the Navigator Acquisition.

During the year ended December 31, 2016, we issued 595,050 common units representing limited partner interests at an average price of $47.39 per unit for proceeds of $28.3 million, net of $0.5 million of issuance costs. We used these proceeds, which include a contribution of $0.6 million from our general partner to maintain its 2% general partner interest, for general partnership purposes, including repayments of outstanding borrowings under the Revolving Credit Agreement.

For the years ended December 31, 2017Series A, B and 2016, we issued 185,455 and 135,100 common units, respectively, representing limited partner interests in connection with the vestings of awards issued under our long-term incentive plan.

C Preferred Units
The following is a summary of our fixed-to-floating rate cumulative redeemable perpetual preferred unitsUnits) issued and outstanding as of December 31, 2017:2023 is shown below:
UnitsOriginal
Issuance Date		Units Issued and OutstandingPrice per UnitFixed Distribution Rate per Unit per AnnumFixed Distribution per AnnumOptional Redemption Date/Date When Distribution Rate Became FloatingFloating Annual Rate (as a Percentage of the $25.00 Liquidation Preference per Unit)
(Thousands of Dollars)
Series A Preferred UnitsNovember 25, 20169,060,000 $25.00 $2.125 $19,252 December 15, 2021
Three-month LIBOR(a) plus 6.766%
Series B Preferred UnitsApril 28, 201715,400,000 $25.00 $1.90625 $29,357 June 15, 2022
Three-month LIBOR(a) plus 5.643%
Series C Preferred UnitsNovember 30, 20176,900,000 $25.00 $2.25 $15,525 December 15, 2022
Three-month LIBOR(a) plus 6.88%
(a)Beginning with the distribution period starting on September 15, 2023, LIBOR was replaced with the corresponding CME Term SOFR plus the applicable tenor spread adjustment of 0.26161%.
Units 
Original
Issuance Date
 Number of Units Issued and Outstanding Price per Unit Net Proceeds (in millions) Fixed Distribution Rate per Annum (as a Percentage of the $25.00 Liquidation Preference per Unit) Fixed Distribution Rate per Unit per Annum Optional Redemption Date/Date at Which Distribution Rate Becomes Floating Floating Annual Rate (as a Percentage of the $25.00 Liquidation Preference per Unit)
Series A
Preferred Units
 November 25, 2016 9,060,000 $25.00
 $218.4
 8.50% $2.125
 December 15, 2021 Three-month LIBOR plus 6.766%
Series B
Preferred Units
 April 28, 2017 15,400,000 $25.00
 $371.8
 7.625% $1.90625
 June 15, 2022 Three-month LIBOR plus 5.643%
Series C
Preferred Units
 November 30, 2017 6,900,000 $25.00
 $166.7
 9.00% $2.25
 December 15, 2022 Three-month LIBOR plus 6.88%


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


On January 25, 2024, our Board of Directors declared quarterly distributions with respect to the Series A, B and C Preferred Units to be paid on March 15, 2024 to holders of record as of March 1, 2024.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Distribution information on our Series A, B and C Preferred Units is as follows (thousands of dollars, except per unit data):
Series A Preferred UnitsSeries B Preferred UnitsSeries C Preferred Units
 Distribution PeriodDistribution Rate per UnitTotal DistributionDistribution Rate per UnitTotal DistributionDistribution Rate per UnitTotal Distribution
December 15, 2023 - March 14, 2024$0.77533 $7,024 $0.70515 $10,859 $0.78246 $5,399 
September 15, 2023 - December 14, 2023$0.77736 $7,043 $0.70717 $10,890 $0.78448 $5,413 
June 15, 2023 - September 14, 2023$0.76715 $6,950 $0.69696 $10,733 $0.77428 $5,343 
March 15, 2023 - June 14, 2023$0.73169 $6,629 $0.66150 $10,187 $0.73881 $5,098 
December 15, 2022 - March 14, 2023$0.71889 $6,513 $0.64871 $9,990 $0.72602 $5,010 
September 15, 2022 - December 14, 2022$0.64059 $5,804 $0.57040 $8,784 $0.56250 $3,881 
June 15, 2022 - September 14, 2022$0.54808 $4,966 $0.47789 $7,360 $0.56250 $3,881 
March 15, 2022 - June 14, 2022$0.47817 $4,332 $0.47657 $7,339 $0.56250 $3,881 
December 15, 2021 - March 14, 2022$0.43606 $3,951 $0.47657 $7,339 $0.56250 $3,881 

We may redeem any of our outstanding Series A, B and C Preferred Units at any time on or after the optional redemption date set forth above for each series of the Series A, B and C Preferred Units, in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions to, but not including, the date of redemption, whether or not declared. We may also redeem the Series A, B and C Preferred Units upon the occurrence of certain rating events or a change of control as defined in our partnership agreement. In the case of the latter instance, if we choose not to redeem the Series A, B and C Preferred Units, thethose preferred unitholders may have the ability to convert their Series A, B and C Preferred Units to common units at the then applicablethen-applicable conversion rate.rate, which are subject to caps of 1.0915, 1.04297 and 1.7928, respectively. Holders of the Series A, B and C Preferred Units have no voting rights except for certain exceptions set forth in our partnership agreement.


Common Units
The following table shows the balance of and changes in the number of our common units outstanding:
Year Ended December 31,
202320222021
Balance as of January 1110,818,718 109,986,273 109,468,127 
Issuance of units14,950,000 — — 
Unit-based compensation (Note 22)747,995 832,445 518,146 
Balance as of December 31126,516,713 110,818,718 109,986,273 

Issuance of Common Units. On August 11, 2023, we issued 14,950,000 common units representing limited partner interests at a price of $15.35 per unit for proceeds of approximately $222.0 million, net of approximately $7.5 million of issuance costs. We used these proceeds to repay outstanding borrowings under our Revolving Credit Agreement.

Cash Distributions. We are required by our partnership agreement to make quarterly distributions to common limited partners of 100% of our Available Cash (as defined in our partnership agreement), which is generally defined as all cash receipts less cash disbursements, including distributions to our preferred unit holders, and cash reserves established by our general partner, in its sole discretion. We are required under our partnership agreement to declare and pay these quarterly distributions within
45 days subsequent to each quarter-end. The common unitholders will receive a distribution each quarter as determined by the Board of Directors, subject to limitation by distributions in arrears, if any, on our preferred units. On January 25, 2024, our Board of Directors declared distributions with respect to our common units for the quarter ended December 31, 2023.

98
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)




The following table summarizes financial information relatedabout cash distributions to our preferred units:
 Preferred Limited Partners  
 Series A Series B Series C Total
Balance as of January 1, 2016$—
 $—
 $—
 $—
Issuance of units218,400
 —
 —
 218,400
Net income1,925
 —
 —
 1,925
Distributions to partners(1,925) —
 —
 (1,925)
Balance as of December 31, 2016218,400
 —
 —
 218,400
Issuance of units—
 371,823
 166,737
 538,560
Net income19,253
 19,815
 1,380
 40,448
Distributions to partners(19,253) (19,815) (1,380) (40,448)
Other(93) (189) (75) (357)
Balance as of December 31, 2017$218,307
 $371,634
 $166,662
 $756,603

Net Income Applicable to the General Partner
The following table details the calculation of net incomecommon limited partners applicable to the general partner:period in which the distributions were earned:
Quarter EndedCash Distributions Per UnitTotal Cash DistributionsRecord DatePayment Date
(Thousands of Dollars)
December 31, 2023$0.40 $50,607 February 7, 2024February 13, 2024
September 30, 20230.40 50,358 November 7, 2023November 14, 2023
June 30, 20230.40 44,363 August 8, 2023August 14, 2023
March 31, 20230.40 44,396 May 8, 2023May 12, 2023
Year ended December 31, 2023$1.60 $189,724 
Year ended December 31, 2022$1.60 $176,746 
Year ended December 31, 2021$1.60 $175,470 
 Year Ended December 31,
 2017 2016 2015
 (Thousands of Dollars)
Net income attributable to NuStar Energy L.P.$147,964
 $150,003
 $306,720
Less preferred limited partner interest40,448
 1,925
 —
Less general partner incentive distribution45,669
 43,407
 43,220
Net income after general partner incentive distribution and preferred
limited partner interest
61,847
 104,671
 263,500
General partner interest allocation2% 2% 2%
General partner interest allocation of net income1,237
 2,091
 5,270
General partner incentive distribution45,669
 43,407
 43,220
Net income applicable to general partner$46,906
 $45,498
 $48,490


Accumulated Other Comprehensive Income (Loss)
Cash DistributionsThe balance of and changes in the components included in AOCI were as follows:
Foreign
Currency
Translation		Cash Flow HedgesPension and
Other
Postretirement
Benefits		Total
(Thousands of Dollars)
Balance as of January 1, 2021$(42,362)$(42,150)$(12,144)$(96,656)
Other comprehensive income before reclassifications601 — 17,721 18,322 
Net gain reclassified into other income, net— — (1,308)(1,308)
Net loss reclassified into interest expense, net— 5,664 — 5,664 
Other comprehensive income601 5,664 16,413 22,678 
Balance as of December 31, 2021(41,761)(36,486)4,269 (73,978)
Other comprehensive income (loss) before reclassifications2,177 — (516)1,661 
Sale of Point Tupper Terminal Operations reclassified into net income (Note 4)39,646 — — 39,646 
Net gain reclassified into other income, net— — (1,040)(1,040)
Net loss reclassified into interest expense, net— 2,106 — 2,106 
Other comprehensive income (loss)41,823 2,106 (1,556)42,373 
Balance as of December 31, 202262 (34,380)2,713 (31,605)
Other comprehensive income before reclassifications728 — 8,317 9,045 
Net gain reclassified into other income, net— — (2,946)(2,946)
Net loss reclassified into interest expense, net— 2,581 — 2,581 
Other comprehensive income728 2,581 5,371 8,680 
Balance as of December 31, 2023$790 $(31,799)$8,084 $(22,925)
General Partner
19. NET INCOME (LOSS) PER COMMON UNIT

The Series D Preferred Units contained certain unitholder conversion and Common Limited Partners. We make quarterly distributionsredemption features, and we used the if-converted method to common unitholders andcalculate the general partnerdilutive effect of 100% of our available cash, generally defined as cash receipts less cash disbursements (including distributionsthe conversion or redemption feature that would have been most advantageous to the Series D preferred unitholders. The effect of the assumed conversion or redemption of the Series D Preferred Units)Units outstanding, prior to their redemption and/or repurchase, was antidilutive for each of the years ended December 31, 2023, 2022 and cash reserves established by2021; therefore, we did not include such conversion or redemption in the general partner, in its sole discretion. These quarterly distributionscomputation of diluted net income (loss) per common unit.

Contingently issuable performance units are declaredincluded 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, 2023 and paid within 45 days subsequent to each quarter-end. The common unitholders receive a distribution each quarter as2022, there were no performance unit awards outstanding. For the year ended December 31, 2021, we determined bythat it was probable that the board of directors, subject to limitation by the distributions in arrears, if any, to the Preferred Units. Our available cash is distributed based on the percentages shown below:
87
  Percentage of Distribution
Quarterly Distribution Amount per Common Unit 
Common
 Unitholders
 
General Partner
Including Incentive Distributions
Up to $0.60 98% 2%
Above $0.60 up to $0.66 90% 10%
Above $0.66 75% 25%


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The following table reflectsperformance measures would be achieved, but the allocation of total cash distributions to the general partner andeffect would be antidilutive; therefore, we did not include any contingently issuable performance units as dilutive common limited partners applicable to the period in which the distributions were earned:
 Year Ended December 31,
 2017 2016 2015
 (Thousands of Dollars, Except Per Unit Data)
General partner interest$9,252
 $7,877
 $7,844
General partner incentive distribution45,669
 43,407
 43,220
Total general partner distribution54,921
 51,284
 51,064
Common limited partners’ distribution407,681
 342,598
 341,140
Total cash distributions$462,602
 $393,882
 $392,204
      
Cash distributions per unit applicable to common limited partners$4.38
 $4.38
 $4.38
The following table summarizes information related to our quarterly cash distributions to our general partner and common limited partners:
Quarter Ended Cash Distributions Per Unit Total Cash Distributions Record Date Payment Date
    (Thousands of Dollars)    
December 31, 2017 (a) $1.095
 $115,267
 February 8, 2018 February 13, 2018
September 30, 2017 $1.095
 $115,084
 November 9, 2017 November 14, 2017
June 30, 2017 $1.095
 $115,083
 August 7, 2017 August 11, 2017
March 31, 2017 $1.095
 $117,168
 May 8, 2017 May 12, 2017
(a)The distribution was announced on January 29, 2018.

Preferred Units. The following table summarizes information related to our quarterly cash distributions on our Preferred Units:
Period 
Cash
Distributions
Per Unit
 
Total Cash
Distributions
 Record Date Payment Date
    (Thousands of Dollars)    
Series A Preferred Units:        
December 15, 2017 - March 14, 2018 (a) $0.53125
 $4,813
 March 1, 2018 March 15, 2018
September 15, 2017 - December 14, 2017 $0.53125
 $4,813
 December 1, 2017 December 15, 2017
June 15, 2017 - September 14, 2017 $0.53125
 $4,813
 September 1, 2017 September 15, 2017
March 15, 2017 - June 14, 2017 $0.53125
 $4,813
 June 1, 2017 June 15, 2017
November 25, 2016 - March 14, 2017 $0.64930556
 $5,883
 March 1, 2017 March 15, 2017
         
Series B Preferred Units:        
December 15, 2017 - March 14, 2018 (a) $0.47657
 $7,339
 March 1, 2018 March 15, 2018
September 15, 2017 - December 14, 2017 $0.47657
 $7,339
 December 1, 2017 December 15, 2017
April 28, 2017 - September 14, 2017 $0.725434028
 $11,172
 September 1, 2017 September 15, 2017
         
Series C Preferred Units:        
November 30, 2017 - March 14, 2018 (a) $0.65625
 $4,528
 March 1, 2018 March 15, 2018
(a)The distribution was announced on January 29, 2018.




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Accumulated Other Comprehensive Income (Loss)
The balance of and changesunits in the components included in “Accumulated other comprehensive income (loss)” were as follows:computation below.

 
Foreign
Currency
Translation
 Cash Flow Hedges 
Pension and
Other
Postretirement
Benefits
 Total
 (Thousands of Dollars)
Balance as of January 1, 2015$(28,839) $(39,073) $—
 $(67,912)
Other comprehensive (loss) income before
   reclassification adjustments
(31,987) 1,303
 —
 (30,684)
Net loss on cash flow hedges reclassified into interest
   expense, net
—
 9,802
 —
 9,802
Other comprehensive (loss) income(31,987) 11,105
 —
 (20,882)
Balance as of December 31, 2015(60,826) (27,968) —
 (88,794)
Employee Transfer—
 —
 4,201
 4,201
Deferred income tax adjustments—
 —
 2,414
 2,414
Other comprehensive loss before
   reclassification adjustments
(8,243) (2,621) (7,852) (18,716)
Net gain on pension costs reclassified into operating
   expense
—
 —
 (1,200) (1,200)
Net gain on pension costs reclassified into general and
   administrative expense
—
 —
 (413) (413)
Net loss on cash flow hedges reclassified into interest
   expense, net
—
 8,331
 —
 8,331
Other comprehensive (loss) income(8,243) 5,710
 (2,850) (5,383)
Balance as of December 31, 2016(69,069) (22,258) (2,850) (94,177)
Other comprehensive income (loss) before
   reclassification adjustments
17,466
 (8,670) (4,641) 4,155
Net gain on pension costs reclassified into operating
expense		—
 —
 (1,143) (1,143)
Net gain on pension costs reclassified into general and
administrative expense		—
 —
 (386) (386)
Net loss on cash flow hedges reclassified into interest
   expense, net
—
 6,624
 —
 6,624
Other comprehensive income (loss)17,466
 (2,046) (6,170) 9,250
Balance as of December 31, 2017$(51,603) $(24,304) $(9,020) $(84,927)


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20. NET INCOME PER COMMON UNIT
The following table details the calculation of basic and diluted net income (loss) per common unit:
 Year Ended December 31,
 202320222021
 (Thousands of Dollars, Except Unit and Per Unit Data)
Net income$273,663 $222,747 $38,225 
Distributions to preferred limited partners(114,729)(127,589)(127,399)
Distributions to common limited partners(189,724)(176,746)(175,470)
Distribution equivalent rights to restricted units(2,685)(2,534)(2,396)
Distributions in excess of income$(33,475)$(84,122)$(267,040)
Distributions to common limited partners$189,724 $176,746 $175,470 
Allocation of distributions in excess of income to common
limited partners
(33,475)(84,122)(267,040)
Series D Preferred Unit accretion(7,171)(18,538)(16,903)
Series D Preferred Unit redemptions/repurchase(64,542)(34,382)— 
Net income (loss) attributable to common units$84,536 $39,704 $(108,473)
Basic and diluted weighted-average common units outstanding116,851,373 110,341,206 109,585,635 
Basic and diluted net income (loss) per common unit$0.72 $0.36 $(0.99)

20. SUPPLEMENTAL CASH FLOW INFORMATION
 Year Ended December 31,
 2017 2016 2015
 (Thousands of Dollars, Except Per Unit Data)
Net income attributable to NuStar Energy L.P.$147,964
 $150,003
 $306,720
Less: Distributions to general partner (including incentive
    distribution rights)
54,921
 51,284
 51,064
Less: Distributions to common limited partners407,681
 342,598
 341,140
Less: Distributions to preferred limited partners40,448
 1,925
 —
Less: Distribution equivalent rights to restricted units2,965
 2,697
 —
Distributions in excess of earnings$(358,051) $(248,501) $(85,484)
      
Net income attributable to common units:     
Distributions to common limited partners$407,681
 $342,598
 $341,140
Allocation of distributions in excess of earnings(350,890) (243,530) (83,774)
Total$56,791
 $99,068
 $257,366
      
Basic weighted-average common units outstanding88,825,964
 78,080,484
 77,886,078
      
Diluted common units outstanding:     
Basic weighted-average common units outstanding88,825,964
 78,080,484
 77,886,078
Effect of dilutive potential common units—
 32,518
 —
Diluted weighted-average common units outstanding88,825,964
 78,113,002
 77,886,078
      
Basic and diluted net income per common unit$0.64
 $1.27
 $3.30



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21. STATEMENTS OF CASH FLOWS
Changes in current assets and current liabilities were as follows:
 Year Ended December 31,
 2017 2016 2015
 (Thousands of Dollars)
Decrease (increase) in current assets:     
Accounts receivable$(865) $(23,234) $67,257
Receivable from related parties112
 (317) —
Inventories11,936
 940
 16,776
Other current assets3,393
 8,128
 4,414
Increase (decrease) in current liabilities:     
Accounts payable(30,409) 14,071
 (32,152)
Payable to related party, net—
 894
 (872)
Accrued interest payable6,489
 (256) 941
Accrued liabilities(11,157) 161
 (7,834)
Taxes other than income tax(3,529) 2,690
 (1,522)
Income tax payable(2,463) 639
 3,551
Changes in current assets and current liabilities$(26,493) $3,716
 $50,559
 Year Ended December 31,
 202320222021
 (Thousands of Dollars)
Decrease (increase) in current assets:
Accounts receivable$1,923 $(6,762)$(2,105)
Inventories(3,226)836 (5,585)
Prepaid and other current assets(5,833)768 (1,710)
Increase (decrease) in current liabilities:
Accounts payable534 (2,960)10,202 
Accrued interest payable2,368 3,468 (16,708)
Accrued liabilities13,642 9,018 4,448 
Taxes other than income tax1,210 (3,631)(2,689)
Changes in current assets and current liabilities$10,618 $737 $(14,147)
The above changes in current assets and current liabilities differ from changes between amounts reflected in the applicable consolidated balance sheets due to:
current assets and current liabilities acquired and disposed of during the period;
•the change in the amount accrued for capital expenditures;
•the effect of foreign currency translation;
reclassification•the effect of the Axeon Term Loan to other accrued compensation expense paid with fully vested common unit awards; and
•current assets from other long-term assets, net;
changes inand current liabilities disposed of during the fair values of our interest rate swap agreements;
reclassification of our 7.65% senior notes due April 15, 2018 from long-term debt to current portion of long-term debt; and
non-cash related party transactions associated with the Employee Transfer (see Note 17 for further information).
Cash flows related to interest and income taxes were as follows:period.
88
 Year Ended December 31,
 2017 2016 2015
 (Thousands of Dollars)
Cash paid for interest, net of amount capitalized$158,089
 $142,663
 $133,388
Cash paid for income taxes, net of tax refunds received$11,338
 $11,847
 $9,971


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Cash flows related to interest and income taxes were as follows:
 Year Ended December 31,
 202320222021
 (Thousands of Dollars)
Cash paid for interest, net of amount capitalized$229,528 $195,697 $218,181 
Cash paid for income taxes, net of tax refunds received$2,188 $4,368 $5,491 


22.Restricted cash is included in “Other long-term assets, net” on the consolidated balance sheets. “Cash, cash equivalents and restricted cash” on the consolidated statements of cash flows was included in the consolidated balance sheets as follows:
December 31,
20232022
(Thousands of Dollars)
Cash and cash equivalents$2,765 $14,489 
Other long-term assets, net9,251 8,888 
Cash, cash equivalents and restricted cash$12,016 $23,377 

21. EMPLOYEE BENEFIT PLANS

Employee Transfer
On March 1, 2016, and in conjunction with the Employee Transfer, we assumed $22.5 million and $10.2 million in benefit obligations associated with the pension plans and other postretirement benefit plans, respectively. Prior to the Employee Transfer, we reimbursed all costs incurred by NuStar GP, LLC related to these employee benefit plans at cost. For comparability purposes this footnote presents information related to these benefit plans on a combined basis for periods prior to the Employee Transfer and after the Employee Transfer, including changes in the benefit obligation and fair value of plan assets, components of net periodic benefit cost (income), and adjustments to other comprehensive income (loss). Consequently, certain amounts presented below will differ from amounts reflected in our consolidated financial statements. See Note 17 for additional discussion on the Employee Transfer.


Thrift Plans
The NuStar Thrift Plan (the Thrift Plan) is a qualified defined contribution plan that became effective June 26, 2006. Participation in the Thrift Plan is voluntary and open to substantially all our domestic employees upon their dates of hire. Thrift Plan participants can contribute from 1% up to 30% of their total annual compensation to the Thrift Plan in the form of pre-tax and/or after taxafter-tax employee contributions. We make matching contributions in an amount equal to 100% of each participant’s employee contributions up to a maximum of 6% of the participant’s total annual compensation. The matching contributions to the Thrift Plan for the years ended December 31, 2017, 20162023, 2022 and 20152021 totaled $6.9$7.3 million, $6.6$7.3 million and $6.3$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 several other defined contribution plans for certain international employees located in Canada, the Netherlands and the United Kingdom. For the years ended December 31, 2017, 2016 and 2015, our costs for these plans totaled $2.5 million, $2.4 million and $2.6 million, respectively.


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

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


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






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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)



The changes in the benefit obligation, the changes in fair value of plan assets, the funded status and the amounts recognized in the consolidated balance sheets for our Pension Plans and other postretirement benefit plans as of and for the years ended December 31, 20172023 and 20162022 were as follows:
 Pension PlansOther Postretirement
Benefit Plans
 2023202220232022
(Thousands of Dollars)
Change in benefit obligation:
Benefit obligation as of January 1$144,311 $179,907 $11,983 $16,270 
Service cost9,041 9,752 359 605 
Interest cost7,224 4,619 602 423 
Benefits paid (a)(8,962)(15,949)(532)(603)
Participant contributions— — 71 66 
Actuarial loss (gain)6,999 (34,221)404 (4,778)
Other— 203 — — 
Benefit obligation as of December 31$158,613 $144,311 $12,887 $11,983 
Change in plan assets:
Plan assets at fair value as of January 1$148,496 $189,838 $— $— 
Actual return on plan assets25,448 (30,405)— — 
Employer contributions11,203 5,012 461 537 
Benefits paid (a)(8,962)(15,949)(532)(603)
Participant contributions— — 71 66 
Plan assets at fair value as of December 31$176,185 $148,496 $— $— 
Reconciliation of funded status as of December 31:
Fair value of plan assets$176,185 $148,496 $— $— 
Less: Benefit obligation158,613 144,311 12,887 11,983 
Funded status$17,572 $4,185 $(12,887)$(11,983)
Amounts recognized in the consolidated balance sheets
as of December 31 (b):
Other long-term assets, net$22,720 $9,130 $— $— 
Accrued liabilities(648)(552)(580)(507)
Other long-term liabilities(4,500)(4,393)(12,307)(11,476)
Net pension asset (liability)$17,572 $4,185 $(12,887)$(11,983)
Accumulated benefit obligation$153,318 $141,517 $12,887 $11,983 
(a)Benefit payments for the year ended December 31, 2022 include lump-sum payments of $2.9 million to participants of the Pension Plans following the Eastern U.S. Terminals Disposition, as discussed in Note 4.
 Pension Plans 
Other Postretirement
Benefit Plans
 2017 2016 2017 2016
 (Thousands of Dollars)
Change in benefit obligation:       
Benefit obligation, January 1$127,402
 $109,202
 $11,061
 $10,042
Service cost8,955
 7,703
 456
 419
Interest cost4,507
 4,023
 430
 401
Benefits paid(5,941) (2,554) (342) (422)
Participant contributions—
 —
 215
 253
Actuarial loss14,894
 9,028
 590
 368
Benefit obligation, December 31$149,817
 $127,402
 $12,410
 $11,061
Change in plan assets:       
Plan assets at fair value, January 1$107,644
 $87,706
 $—
 $—
Actual return on plan assets17,070
 6,891
 —
 —
Employer contributions11,105
 15,601
 127
 169
Benefits paid(5,941) (2,554) (342) (422)
Participant contributions—
 —
 215
 253
Plan assets at fair value, December 31$129,878
 $107,644
 $—
 $—
Reconciliation of funded status:       
Fair value of plan assets at December 31$129,878
 $107,644
 $—
 $—
Less: Benefit obligation at December 31149,817
 127,402
 12,410
 11,061
Funded status at December 31$(19,939) $(19,758) $(12,410) $(11,061)
Amounts recognized in the consolidated balance sheets (a):       
Accrued liabilities$(210) $(162) $(376) $(321)
Other long-term liabilities(19,729) (19,596) (12,034) (10,740)
Net pension liability$(19,939) $(19,758) $(12,410) $(11,061)
(a)For the Pension Plan, since assets exceed the present value of expected benefit payments for the next 12 months, all of the liability(b)For the Pension Plan, since assets exceed the present value of expected benefit payments for the next 12 months, the asset is noncurrent. For the Excess Pension Plan and the other postretirement benefit plans, since there are no assets, the current liability is the present value of expected benefit payments for the next 12 months; the remainder is noncurrent.
The accumulated benefit obligation is the present value of benefits earnedexpected benefit payments for the next 12 months; the remainder is noncurrent.

The actuarial loss (gain) related to date, assuming no future salary increases. The aggregate accumulatedthe benefit obligation for our Pension Plans as of December 31, 2017 and 2016pension plans was $146.3 million and $125.0 million, respectively. As of December 31, 2017 and 2016,primarily attributable to a decrease in the aggregate accumulateddiscount rates used to determine the benefit obligation forfrom 5.26% to 5.08% in 2023 and an increase from 3.10% to 5.26% in 2022. The fair value of our plan assets is affected by the Pension Plans exceededreturn on plan assets.assets resulting primarily from the performance of equity and bond markets during the period.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


The Excess Pension Plan has no plan assets and an accumulated benefit obligation of $4.8 million and $4.6 million as of December 31, 2023 and 2022, 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 $5.1 million and $4.9 million as of December 31, 2023 and 2022, respectively.


The components of net periodic benefit cost (income) related to our Pension Plans and other postretirement benefit plans were as follows:
 Pension PlansOther Postretirement Benefit Plans
Year Ended December 31,Year Ended December 31,
 202320222021202320222021
 (Thousands of Dollars)
Service cost$9,041 $9,752 $9,978 $359 $605 $593 
Interest cost7,224 4,619 4,084 602 423 326 
Expected return on plan assets(9,660)(9,087)(9,233)— — — 
Amortization of prior service credit(1,876)(1,876)(2,057)(1,145)(1,145)(1,145)
Amortization of net actuarial loss75 1,129 2,279 — 209 176 
Other— 846 (561)— — — 
Net periodic benefit cost (income)$4,804 $5,383 $4,490 $(184)$92 $(50)

 Pension Plans 
Other Postretirement
Benefit Plans
 Year Ended December 31, Year Ended December 31,
 2017 2016 2015 2017 2016 2015
 (Thousands of Dollars)
Service cost$8,955
 $7,703
 $7,676
 $456
 $419
 $470
Interest cost4,507
 4,023
 4,389
 430
 401
 448
Expected return on plan assets(6,411) (5,407) (5,018) —
 —
 —
Amortization of prior service credit(2,059) (2,063) (2,063) (1,145) (1,145) (1,145)
Amortization of net actuarial loss1,484
 1,091
 1,845
 191
 181
 269
Net periodic benefit cost (income)$6,476
 $5,347
 $6,829
 $(68) $(144) $42

We amortize prior service costs and credits on a straight-line basis over the average remaining service period of employees expected to receive benefits under our Pension Plans and other postretirement benefit plans (“Amortization of prior service credit” in table above). We amortize the actuarial gains and losses that exceed 10 percent10% of the greater of the projected benefit obligation or market-related value of plan assets (smoothed asset value) over the average remaining service period of active employees expected to receive benefits under our Pension Plans and other postretirement benefit plans (“Amortization of net actuarial loss” in table above).


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

Adjustments to other comprehensive (loss) income related to our Pension Plans and other postretirement benefit plans were as follows:
 Pension PlansOther Postretirement Benefit Plans
Year Ended December 31,Year Ended December 31,
 202320222021202320222021
 (Thousands of Dollars)
Net unrecognized gain (loss) arising during the year:
Net actuarial gain (loss)$8,790 $(5,271)$18,666 $(404)$4,779 $(884)
Net (gain) loss reclassified into income:
Amortization of prior service credit(1,876)(1,876)(2,057)(1,145)(1,145)(1,145)
Amortization of net actuarial loss75 1,129 2,279 — 209 176 
Other— 643 (561)— — — 
Net gain reclassified into income(1,801)(104)(339)(1,145)(936)(969)
Income tax expense(69)(24)(61)— — — 
Total changes to other comprehensive income$6,920 $(5,399)$18,266 $(1,549)$3,843 $(1,853)

91
 Pension Plans 
Other Postretirement
Benefit Plans
 Year Ended December 31, Year Ended December 31,
 2017 2016 2015 2017 2016 2015
 (Thousands of Dollars)
Net unrecognized (loss) gain arising during the year:           
Net actuarial (loss) gain$(4,235) $(7,544) $1,000
 $(590) $(368) $1,056
Net (gain) loss reclassified into income:           
Amortization of prior service credit(2,059) (2,063) (2,063) (1,145) (1,145) (1,145)
Amortization of net actuarial loss1,484
 1,091
 1,845
 191
 181
 269
Net gain reclassified into income(575) (972) (218) (954) (964) (876)
            
Income tax benefit (expense)162
 57
 (362) 22
 3
 (382)
Total changes to other
comprehensive (loss) income
$(4,648) $(8,459) $420
 $(1,522) $(1,329) $(202)



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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 PlansOther Postretirement
Benefit Plans
December 31,December 31,
 2023202220232022
 (Thousands of Dollars)
Unrecognized actuarial gain (loss)$1,618 $(7,247)$30 $434 
Prior service credit3,878 5,754 2,594 3,739 
Other(36)33 — — 
Accumulated other comprehensive income (loss),
net of tax
$5,460 $(1,460)$2,624 $4,173 
 Pension Plans 
Other Postretirement
Benefit Plans
 December 31, December 31,
 2017 2016 2017 2016
 (Thousands of Dollars)
Unrecognized actuarial loss$(31,178) $(28,427) $(4,154) $(3,755)
Prior service credit16,604
 18,663
 9,464
 10,609
Deferred tax asset219
 57
 25
 3
Accumulated other comprehensive (loss) income,
net of tax
$(14,355) $(9,707) $5,335
 $6,857

The following pre-tax amounts in accumulated other comprehensive loss as of December 31, 2017 are expected to be recognized as components of net periodic benefit cost (income) in 2018:
 Pension Plans 
Other
Postretirement
Benefit Plans
 (Thousands of Dollars)
Actuarial loss$2,174
 $214
Prior service credit$(2,057) $(1,145)


Investment Policies and Strategies
The investment policies and strategies for the assets of our qualified Pension Plan incorporate a well-diversified approach that is expected to earn long-term returns from capital appreciation and a growing stream of current income. This approach recognizes that assets are exposed to risk, and the market value of the Pension Plan’s assets may fluctuate from year to year. Risk tolerance is determined based on our financial ability to withstand risk within the investment program and the willingness to accept return volatility. In line with the investment return objective and risk parameters, the Pension Plan’s mix of assets includes a diversified portfolio of equity and fixed-income instruments. The aggregate asset allocation is reviewed on an annual basis. As of December 31, 2017,2023, the target allocations for plan assets arewere approximately 65% equity securities and 35% fixed income investments, with certain fluctuations permitted.


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


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


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The major classes of plan assets measured at fair value for the Pension Plan were as follows:
 December 31, 2023
 Level 1Level 2Level 3Total
 (Thousands of Dollars)
Cash equivalent securities$373 $— $— $373 
Equity securities:
U.S. large cap equity fund (a)— 99,301 — 99,301 
International stock index fund (b)17,715 — — 17,715 
Fixed income securities:
Bond market index fund (c)58,796 — — 58,796 
Total$76,884 $99,301 $— $176,185 
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December 31, 2022
December 31, 2017 Level 1Level 2Level 3Total
Level 1 Level 2 Level 3 Total
(Thousands of Dollars)
(Thousands of Dollars)(Thousands of Dollars)
Cash equivalent securities$381
 $—
 $—
 $381
Equity securities:       
U.S. large cap equity fund (a)
U.S. large cap equity fund (a)
U.S. large cap equity fund (a)—
 75,353
 —
 75,353
International stock index fund (b)14,480
 —
 —
 14,480
Fixed income securities:       
Bond market index fund (c)39,664
 —
 —
 39,664
Bond market index fund (c)
Bond market index fund (c)
Total$54,525
 $75,353
 $—
 $129,878

(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.
 December 31, 2016
 Level 1 Level 2 Level 3 Total
 (Thousands of Dollars)
Cash equivalent securities$738
 $—
 $—
 $738
Equity securities:       
U.S. large cap equity fund (a)—
 64,813
 —
 64,813
International stock index fund (b)10,459
 —
 —
 10,459
Fixed income securities:       
Bond market index fund (c)31,634
 —
 —
 31,634
Total$42,831
 $64,813
 $—
 $107,644
(c)This fund tracks the performance of the Barclays Capital U.S. Aggregate Bond Index.
(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, 2017,2023, we contributed $11.1$11.2 million and $0.1$0.5 million to our Pension Plan and other postretirement benefit plans, respectively. During 2024, we expect to contribute approximately $9.6 million and $0.6 million to the Pension Plans and other postretirement benefit plans, respectively. During 2018, we expectWe will monitor our funding status in 2024 to contribute approximately $11.2 million and $0.4 million to the Pension Plans and other postretirement benefit plans, respectively, which principally representsdetermine if any contributions eitherare required by regulations or laws, or with respect to unfunded plans, necessary to fund current benefits.


Estimated Future Benefit Payments
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid for the years ending December 31:
Pension PlansOther Postretirement Benefit Plans
 (Thousands of Dollars)
2024$10,023 $580 
2025$11,151 $621 
2026$11,286 $665 
2027$11,619 $708 
2028$12,339 $753 
2029-2033$69,178 $4,363 

Assumptions
The discount rate is based on a hypothetical yield curve represented by a series of annualized individual discount rates. Each bond issue underlying the hypothetical yield curve required an average rating of double-A, when averaging all available ratings by Moody’s Investor Service Inc., S&P Global Ratings and Fitch Ratings. The expected long-term rate of return on plan assets is based on the weighted averages of the expected long-term rates of return for each asset class of investments held in our plans as determined using historical data and the assumption that capital markets are informationally efficient. The expected rate of compensation increase represents average long-term salary increases.

The weighted-average assumptions used to determine the benefit obligations were as follows:
 Pension PlansOther Postretirement Benefit Plans
December 31,December 31,
 2023202220232022
Discount rate5.08 %5.26 %5.06 %5.25 %
Rate of compensation increase3.99 %3.99 %n/an/a
Cash balance interest crediting rate3.58 %3.76 %n/an/a

93
 Pension Plans 
Other
Postretirement
Benefit Plans
 (Thousands of Dollars)
2018$8,823
 $376
2019$9,699
 $416
2020$10,432
 $434
2021$11,050
 $464
2022$11,650
 $497
Years 2023-2027$64,799
 $3,090



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Assumptions
The weighted-average assumptions used to determine the benefit obligations were as follows:
 Pension Plans 
Other
Postretirement
Benefit Plans
 December 31, December 31,
 2017 2016 2017 2016
Discount rate3.72% 4.33% 3.82% 4.49%
Rate of compensation increase3.51% 3.51% n/a  
 n/a  

The weighted-average assumptions used to determine the net periodic benefit cost (income) were as follows:
 Pension PlansOther Postretirement Benefit Plans
Year Ended December 31,Year Ended December 31,
 202320222021202320222021
Discount rate5.26 %3.10 %2.84 %5.25 %3.08 %2.83 %
Expected long-term rate of
return on plan assets
6.50 %6.00 %6.00 %n/an/an/a
Rate of compensation increase3.99 %3.99 %3.51 %n/an/an/a
Cash balance interest crediting rate3.76 %2.00 %2.00 %n/an/an/a
 Pension Plans 
Other Postretirement
Benefit Plans
 Year Ended December 31, Year Ended December 31,
 2017 2016 2015 2017 2016 2015
Discount rate4.33% 4.61% 4.22% 4.49% 4.75% 4.34%
Expected long-term rate of
return on plan assets
6.00% 6.25% 6.50% n/a  
 n/a  
 n/a  
Rate of compensation increase3.51% 3.51% 3.51% n/a  
 n/a  
 n/a  


The assumed health care cost trend rates were as follows:
 December 31,
 2017 2016
Health care cost trend rate assumed for next year6.84% 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 rate2028
 2028

Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. We sponsor a contributory postretirement health care plan for employees thatwho retired prior to April 1, 2014. The plan has an annual limitation (a cap) on the increase of the employer’s share of the cost of covered benefits. The cap on the increase in employer’s cost is 2.5% per year. The assumed increase in total health care cost exceeds the 2.5% indexed cap, so increasing or decreasing the health care cost trend rate by 1% does not materially change our obligation or expense for the postretirement health care plan.rates were as follows:
 December 31,
 20232022
Health care cost trend rate assumed for next year6.88 %7.00 %
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 rate20322032


23.22. UNIT-BASED COMPENSATION

Please refer to Note 28 for a discussion of the merger of a subsidiary of ours with and into NuStar GP Holdings, pursuant to which we will become the sole member of NuStar GP Holdings.


Overview
On January 28, 2016,2019 LTIP. In April 2019, our common unitholders approved the Fifth Amended and Restated 20002019 Long-Term Incentive Plan (the 2000(2019 LTIP) which, among other items, provides that we may use newly issued common units fromfor eligible employees, consultants and directors of NuStar Energy to satisfy unit awardsL.P., and extends the term of the 2000 LTIP to January 28, 2026. Prior to the Employee Transfer, NuStar GP, LLC sponsored the 2000 LTIP, and we reimbursed NuStar GP, LLC for awards under this plan. Following the approval of the 2000 LTIP and the Employee Transfer in 2016, most of our currently outstanding awards are now classified as equity awards as we intend to settle these awards through the issuance of our common units.

Effective March 1, 2016, we assumed sponsorship of the 2000 LTIP, which provides the Compensation Committee of the Board of Directors of NuStar GP, LLC, (the Compensation Committee) withand their respective affiliates who perform services for us and our subsidiaries. The 2019 LTIP allows for the right to issue and award up to 3,250,000awarding of our common units to employees and non-employee directors (NEDs). Awards available under the 2000 LTIP include(i) options; (ii) restricted units, performance units, unit options, unit awards andunits;
(iii) distribution equivalent rights (DERs). The Compensation Committee may also include a tandem grant of a DER that will; (iv) performance cash; (v) performance units; and (vi) unit awards. DERs entitle the participant to receive cash equal to cash distributions made on any award prior to its vesting. The 2019 LTIP, as amended and restated on April 27, 2023, permits the granting of awards totaling an aggregate of 7,500,000 common units, subject to adjustment as provided by the terms of the 2019 LTIP. The 2019 LTIP generally will be administered by the compensation committee of our Board of Directors. As of December 31, 2023, a total of 2,651,315 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, 2023.

The following table summarizes information pertaining to all our long-term incentive plans:
Units Outstanding
December 31,		Compensation Expense
Year Ended December 31,
202320222021202320222021
(Thousands of Dollars)
Restricted units:
Domestic employees3,017,060 2,859,189 2,520,436 $14,580 $12,759 $11,892 
Non-employee directors (NEDs)143,374 133,604 129,312 967 1,021 856 
International employees— — 21,760 — (20)139 
Performance awards— — 33,695 2,815 2,442 3,047 
Unit awards— — — — — 4,645 
Total3,160,434 2,992,793 2,705,203 $18,362 $16,202 $20,579 

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any award prior to its vesting. As of December 31, 2017, commonCommon units that remained available to be awardedissued under the 2000 LTIP totaled 679,045.

On March 1, 2016, we assumed all outstanding awards under the 2000 LTIP. The transfer of the outstanding awards qualifies as a plan modification. Therefore, we measured the fair value of the outstanding awards based on the common unit price on the transfer date.

The following table summarizes information pertaining to our long-term incentive plan compensation expense:plans, net of employee tax withholding requirements, were as follows:
Year Ended December 31,
202320222021
Restricted units661,050 531,637 460,076 
Performance awards86,945 114,618 58,070 
Unit awards— 186,190 — 
Total747,995 832,445 518,146 
 Units Outstanding December 31, Transferred Units Compensation Expense Year Ended December 31,
 2017 2016 March 1, 2016 2017 2016
       (Thousands of Dollars)
Restricted Units:         
Domestic employees736,746
 647,340
 586,524
 $7,881
 $5,980
Non-employee directors (NEDs)27,097
 18,134
 17,629
 251
 388
International employees58,107
 50,609
 49,121
 595
 715
Performance Units80,961
 77,014
 77,014
 —
 1,211
Total902,911
 793,097
 730,288
 $8,727
 $8,294

Prior to the Employee Transfer, we reimbursed NuStar GP, LLC for our long-term incentive plan compensation expense which totaled $6.4 million for the year ended December 31, 2015.


Restricted Units
Our restricted unit awards are considered phantom units, as they represent the right to receive our common units upon vesting.
We account for restricted units as either equity-classified awards or liability-classified awards, depending on expected method of settlement. Awards we settle with the issuance of common units upon vesting are equity-classified. Awards we settle in cash upon vesting are liability-classified. We record compensation expense ratably over the vesting period based on the fair value of the common units at the grant date (for domestic employees)employees and NEDs), or, prior to the sale of our Point Tupper Terminal Operations on April 29, 2022, the fair value of the common units measured at each reporting period (for NEDs and international employees). DERs paid with respect to outstanding equity-classified unvested restricted units reduce equity, similar to cash distributions to unitholders, whereas DERs paid with respect to outstanding liability-classified unvested restricted units are expensed.were expensed prior to the sale of our Point Tupper Terminal Operations on April 29, 2022. In connection with the DERs for equity awards, we paid or expect to pay $3.0$2.7 million, $2.5 million and $2.7$2.4 million respectively, in cash, for the years ended December 31, 20172023, 2022 and 2016. A summary of our restricted unit activity is as follows:2021.

 Domestic Employees    
 
Number of Restricted
Units
 
Weighted-
Average
Grant-Date
Fair Value
Per Unit
 
Number of Restricted
Units to
NEDs
 
Number of Restricted
Units to International Employees
Nonvested units as of January 1, 2016—
 $—
 —
 —
Transferred586,524
 35.03
 17,629
 49,121
Granted246,070
 47.70
 8,730
 20,107
Vested(180,724) 35.50
 (8,225) (14,812)
Forfeited(4,530) 35.03
 —
 (3,807)
Nonvested units as of December 31, 2016647,340
 39.72
 18,134
 50,609
Granted307,009
 29.56
 17,110
 24,533
Vested(201,466) 38.74
 (8,147) (16,440)
Forfeited(16,137) 40.00
 —
 (595)
Nonvested units as of December 31, 2017736,746
 $35.95
 27,097
 58,107

The total fair value of our equity-classified awards vested for the years ended December 31, 2017 and 2016 was $6.5 million and $9.0 million, respectively. We issued 152,017 common units in connection with these award vestings, net of employee tax withholding requirements, for the year ended December 31, 2017. Unrecognized compensation cost related to our equity-

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classified employee awards totaled $25.5 million as of December 31, 2017, which we expect to recognize over a weighted-average period of 3.7 years.

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


Non-Employee Directors. The outstanding restricted units granted to NEDs are equity-classified awards that vest over three years. The fair value of these awards is measured at the grant date.

International Employees. Prior to the sale of our Point Tupper Terminal Operations on April 29, 2022, the outstanding restricted units granted to international employees were cash-settled and accounted for as liability-classified awards. These awards vested over three years and the fair value was equal to the market price of our common units at each reporting period.

International Employees. The outstanding For the year ended December 31, 2022, 11,364 restricted units grantedvested, and 10,396 restricted units were forfeited related to our international employees are cash-settled and accounted foremployees.

A summary of our equity-classified restricted unit awards is as liability-classified awards. These awards vest over three to five years and thefollows:
Measured at Grant Date Fair Value
Number of UnitsWeighted-Average Fair Value Per Unit
Nonvested units as of January 1, 20212,333,894 $17.70 
Granted1,049,081 16.28 
Vested(630,888)20.07 
Forfeited(102,339)14.28 
Nonvested units as of December 31, 20212,649,748 16.57 
Granted1,206,824 16.09 
Vested(738,701)17.79 
Forfeited(125,078)16.23 
Nonvested units as of December 31, 20222,992,793 16.08 
Granted1,112,965 17.49 
Vested(921,890)16.81 
Forfeited(23,434)15.93 
Nonvested units as of December 31, 20233,160,434 16.39 

The total fair value is equal to the market price of our equity-classified restricted unit awards vested for the years ended December 31, 2023, 2022 and 2021 was $16.1 million, $11.9 million and $10.3 million, respectively. We issued 661,050, 531,637 and 460,076 common units at each reporting period.in

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connection with these award vestings, net of employee tax withholding requirements, for the years ended December 31, 2023, 2022 and 2021, respectively. Unrecognized compensation cost related to our equity-classified employee awards totaled $49.2 million as of December 31, 2023, which we expect to recognize over a weighted-average period of 3.6 years.

Performance UnitsAwards
Performance unitsawards are issued to certain of our key employees and represent either rights to receive our common units or cash upon achieving an objective performance measuremeasures for the performance period. The objective performance measure is determined each yearperiod established by the NuStar GP, LLC Compensation Committee for the following year.(the Compensation Committee). Achievement of the performance measuremeasures determines the rate at which the performance unitsawards convert into our common units or cash, which can rangeranges from zero to 200%. for certain awards.


Performance unitsawards vest in three annual increments (tranches), based upon our achievement of the performance measuremeasures set by the Compensation Committee during the one-year performance periods that end on December 31 of each year following the date of grant.applicable year. Therefore, the performance unitsawards are not considered granted for accounting purposes until the Compensation Committee has set the performance measuremeasures for each tranche of awards. Performance unitsunit awards are equity-classified awards measured at the grant date fair value. In addition, since the performance unitsunit awards granted do not receive DERs, the grant date fair value of these awards is reduced by the per unit distributions expected to be paid to common unitholders during the vesting period. Performance cash awards are accounted for as a liability but may be settled in common units. We record compensation expense ratably for each vesting tranche over its requisite service period (one year) if it is probable that the specified performance measuremeasures will be achieved. Additionally, changes in the actual or estimated outcomes that affect the quantity of performance unitsawards expected to be converted into common units or paid in cash, are recognized as a cumulative adjustment. 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 AwardsTotal Performance
Unit Awards Granted		Performance Unit AwardsWeighted-Average Grant Date Fair Value per Unit
(Thousands of Dollars)
Outstanding as of January 1, 2021$2,167 87,122 57,448 $13.21 
Granted2,254 4,021 33,695 15.79 
Vested (a)(672)(53,427)(53,427)13.21 
Forfeited(51)(4,021)(4,021)13.21 
Outstanding as of December 31, 20213,698 33,695 33,695 15.79 
Granted2,954 — — — 
Performance adjustment (b)— 14,839 14,839 15.79 
Vested (a)(1,507)(48,534)(48,534)15.79 
Outstanding as of December 31, 20225,145 — — — 
Granted3,287 — — — 
Vested (a)(2,575)— — — 
Forfeited(141)— — — 
Outstanding as of December 31, 2023$5,716 — — — 
(a)For the period from the Employee Transfer date toyears ended December 31, 2016, no2023, 2022 and 2021, we settled performance cash awards with 149,608, 137,931 and 43,733 common units, were granted or forfeited. respectively, and issued 86,945, 84,778 and 26,704 common units, net of employee tax withholding requirements, respectively.
(b)For the year ended December 31, 2017,2022, common units granted and issued upon vesting resulted from performance units earned at 150% of the 2021 target.

The total fair value of our performance unit awards vested for the years ended December 31, 2022 and 2021 was $0.8 million and $0.8 million, respectively. For the years ended December 31, 2022 and 2021 we issued 33,43829,840 and 31,366 common units in connection with the performance unit award vestings, related to 2016 performance, net of employee tax withholding requirements. For 2017,requirements, respectively. In January 2024, we did not achieve thesettled performance measure.

A summarycash awards, net of our performance units is shown below:employee tax withholding requirements, in cash for $1.6 million.
96
   Granted for Accounting Purposes
 
Total Performance
Units Awarded
 Performance Units Weighted-Average Grant Date Fair Value per Unit
Outstanding as of January 1, 201777,014
 35,373
 $31.75
Granted39,320
 38,865
 50.04
Vested(35,373) (35,373) 31.75
Outstanding as of December 31, 201780,961
 38,865
 $50.04

Performance units vested during the year ended December 31, 2017 with respect to 2016 performance were as follows:
 Vested Units Actual Conversion Rate Gross Number of Units Issued
2014 awards9,613
 150% 14,420
2015 awards9,878
 150% 14,818
2016 awards15,882
 150% 23,825
Total35,373
   53,063


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Unit Awards

Unit awards are equity-classified awards of fully vested common units. We accrued compensation expense in 2021 that was paid in unit awards in the first quarter of 2022. 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 GrantGrant Date Fair ValueUnit Awards GrantedCommon Units Issued, Net of Employee Withholding Tax
(Thousands of Dollars)
February 2022$4,645 280,685 186,190 
24.
23. INCOME TAXES

On December 22, 2017, the U.S. enacted the Tax Cuts and Jobs Act (“the Act”). The Act, which is also commonly referred to as “U.S. tax reform,” significantly changes U.S. corporate income tax laws by, among other things, reducing the U.S. corporate tax rate from 35% to 21%, starting in 2018, and creating a territorial tax system with a one-time mandatory tax on previously deferred foreign earnings of U.S. subsidiaries. As a result, we recorded an expense of $0.8 million in the fourth quarter of 2017. This amount, which is included in “Income tax expense” on the consolidated statements of income, consists of two components: (i) $0.7 million relating to the one-time mandatory tax on previously deferred earnings of certain non-U.S. subsidiaries that are wholly owned by one of our U.S. subsidiaries and (ii) $0.1 million resulting from the revaluation of our net deferred tax assets in the U.S. based on the new lower corporate income tax rate.

Although the $0.8 million expense represents what we believe to be a reasonable estimate of the impact of the income tax effects of the Act on our consolidated financial statements as of December 31, 2017, it should be considered provisional. We are continuing to gather additional information to more precisely compute our deferred tax assets balance in the U.S., as well as the income tax expense associated with the one-time mandatory tax. Any adjustments to these provisional amounts will be reported as a component of “Income tax expense” on the consolidated statements of income in the reporting period in which any such adjustments are determined, which will be no later than the fourth quarter of 2018, and are not expected to be significant.

Due to the complexity of the new Global Intangible Low-Tax Income (GILTI) tax rules, we are continuing to evaluate this provision of the Act and the application of FASB’s Accounting Standards Codification 740 (ASC 740). Under U.S. GAAP, we are allowed to make an accounting policy choice of either (i) treating taxes due on future U.S. inclusions in taxable income related to GILTI as a current-period expense when incurred (the “period cost method”) or (ii) factoring such amounts into a company’s measurement of its deferred taxes (the “deferred method”). Our selection of an accounting policy with respect to the new GILTI tax rules will depend, in part, on analyzing our global income to determine whether we expect to have future U.S. inclusions in taxable income related to GILTI and, if so, what the impact is expected to be. Because whether we expect to have future U.S. inclusions in taxable income related to GILTI depends on not only our current structure and estimated future results of global operations, but also our intent and ability to modify our structure and/or our business, we are not yet able to reasonably estimate the effect of this provision of the Tax Act. Therefore, we have not made any adjustments related to potential GILTI tax in our consolidated financial statements as of December 31,2017, and have not made a policy decision regarding whether to record deferred taxes on GILTI.

Due to the complexity of the new Base Erosion Anti-Abuse Tax (BEAT) rules, we are continuing to evaluate this provision of the Act and the application of ASC 740. Under U.S. GAAP, because the BEAT provisions are designed to be an “incremental tax,” BEAT is treated as a current-period expense when incurred (the period cost method). Therefore, we have not made any adjustments related to the potential BEAT in our consolidated financial statements.
Components of income tax expense related to certain of our continuing operations conducted through separate taxable wholly owned corporate subsidiaries were as follows:
 Year Ended December 31,
 202320222021
 (Thousands of Dollars)
Current:
U.S.$4,292 $3,558 $3,755 
Foreign— 272 221 
Foreign withholding tax519 355 1,281 
Total current4,811 4,185 5,257 
Deferred:
U.S.601 341 (93)
Foreign— (1,287)(531)
Foreign withholding tax— — (745)
Total deferred601 (946)(1,369)
Income tax expense$5,412 $3,239 $3,888 
 Year Ended December 31,
 2017 2016 2015
 (Thousands of Dollars)
Current:     
U.S.$3,117
 $2,280
 $908
Foreign6,335
 6,329
 9,820
Foreign withholding tax479
 3,833
 1,926
Total current9,931
 12,442
 12,654
      
Deferred:     
U.S.1,468
 2,680
 1,022
Foreign(1,065) (1,122) (1,464)
Foreign withholding tax(397) (2,027) 2,500
Total deferred6
 (469) 2,058
      
Total income tax expense$9,937
 $11,973
 $14,712

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The difference between income tax expense recorded in our consolidated statements of income and income taxes computed by applying the applicable statutory federal income tax rate (35% for all years presented) to income before income tax expense is due to the fact that the majority of our income is not subject to federal income tax due to our status as a limited partnership. We record a tax provision related to the amount of undistributed earnings of our foreign subsidiaries expected to be repatriated.

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The tax effects of significant temporary differences representing deferred income tax assets and liabilities were as follows:
December 31,
 20232022
 (Thousands of Dollars)
Deferred income tax assets:
Net operating losses$19,340 $17,710 
Capital loss3,714 3,714 
Other701 793 
Total deferred income tax assets23,755 22,217 
Less: Valuation allowance(22,866)(21,573)
Net deferred income tax assets889 644 
Deferred income tax liabilities:
Property, plant and equipment(4,420)(3,534)
Foreign withholding tax(330)(286)
Other(72)(43)
Total deferred income tax liabilities(4,822)(3,863)
Net deferred income tax liability$(3,933)$(3,219)
 December 31,
 2017 2016
 (Thousands of Dollars)
Deferred income tax assets:   
Net operating losses$20,688
 $31,539
Employee benefits483
 697
Environmental and legal reserves185
 148
Allowance for bad debt1,982
 2,697
Other2,050
 1,697
Total deferred income tax assets25,388
 36,778
Less: Valuation allowance(11,251) (12,759)
Net deferred income tax assets14,137
 24,019
    
Deferred income tax liabilities:   
Property, plant and equipment(36,176) (43,788)
Foreign withholding tax—
 (384)
Total deferred income tax liabilities(36,176) (44,172)
    
Net deferred income tax liability$(22,039) $(20,153)
    
Reported on the consolidated balance sheets as:   
Deferred income tax asset$233
 $2,051
Deferred income tax liability(22,272) (22,204)
Net deferred income tax liability$(22,039) $(20,153)

As of December 31, 2017,2023, our U.S. and foreign corporate operations have net operating loss carryforwards for tax purposes totaling $79.9$49.2 million and $13.1$30.1 million, respectively, which are subject to various limitations on use and expire in years 20252032 through 20362034 for U.S. losses and in years 20182024 through 20262034 for foreign losses.
As of However, U.S. losses generated after
December 31, 2017, totaling $5.1 million, can be carried forward indefinitely. As of December 31, 2023, 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 2016,expires in 2024.

As of December 31, 2023 and 2022, we recordedhave a valuation allowance of $11.3$22.9 million and $12.8$21.6 million, respectively, related to our deferred tax assets.assets on net operating losses and capital losses. We estimate the amount of valuation allowance based upon our expectations of taxable income in the various jurisdictions in which we operate and the period over which we can utilize those future deductions. The valuation allowance reflects uncertainties related to our ability to utilize certain net operating loss carryforwards before they expire. In 2017,2023, there was a $1.9$0.4 million decrease in the valuation allowance for the U.S. net operating loss and a $0.4$1.7 million increase in the foreign net operating loss valuation allowance due to changes in our estimates of the amount of those loss carryforwards that will be realized, based upon future taxable income.

The realization of net deferred income tax assets recorded as of December 31, 20172023 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, 20172023 will be realized, based on expected future taxable income.



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25.24. SEGMENT INFORMATION


Our reportable business segments consist of the pipeline, storage and fuels marketing.marketing segments. Our segments represent strategic business units that offer different services and products. We evaluate the performance of each segment based on its respective operating income, before general and administrative expenses and certain non-segmental depreciation and amortization expense. General and administrative expenses are not allocated to the operating segments since those expenses relate primarily to the overall management at the entity level. Our principal operations includeWe are primarily engaged in the transportation, of petroleum products and anhydrous ammonia, the terminalling and storage of petroleum products and renewable fuels and the marketingtransportation of anhydrous ammonia. We also market petroleum products. Intersegment revenues result from storage agreements with wholly owned subsidiaries of NuStar Energy at rates consistent with the rates charged to third parties for storage.
Results of operations for the reportable segments were as follows:
 Year Ended December 31,
 202320222021
 (Thousands of Dollars)
Revenues:
Pipeline$873,869 $828,191 $762,238 
Storage319,599 334,549 427,668 
Fuels marketing440,725 520,486 428,608 
Consolidation and intersegment eliminations(6)(3)(14)
Total revenues$1,634,187 $1,683,223 $1,618,500 
Depreciation and amortization expense:
Pipeline$175,930 $178,802 $179,088 
Storage75,052 73,076 87,500 
Segment depreciation and amortization expense250,982 251,878 266,588 
Other depreciation and amortization expense4,728 7,358 7,792 
Total depreciation and amortization expense$255,710 $259,236 $274,380 
Reconciliation of segment operating income to income before income tax expense:
Pipeline$483,188 $438,670 $321,472 
Storage87,609 61,081 24,800 
Fuels marketing32,926 33,536 11,181 
Segment operating income603,723 533,287 357,453 
Gain on sale of assets41,075 — — 
General and administrative expenses129,846 117,116 113,207 
Other depreciation and amortization expense4,728 7,358 7,792 
Operating income510,224 408,813 236,454 
Interest expense, net(241,364)(209,009)(213,985)
Other income, net10,215 26,182 19,644 
Income before income tax expense$279,075 $225,986 $42,113 

Revenues by geographic area are shown in the table below:
 Year Ended December 31,
 202320222021
 (Thousands of Dollars)
United States$1,628,215 $1,667,672 $1,582,672 
Foreign5,972 15,551 35,828 
Total revenues$1,634,187 $1,683,223 $1,618,500 

99
 Year Ended December 31,
 2017
2016 2015
 (Thousands of Dollars)
Revenues:     
Pipeline$516,288
 $485,650
 $508,522
Storage:     
Third parties604,847
 589,098
 599,302
Intersegment12,106
 20,944
 25,606
Total storage616,953
 610,042
 624,908
Fuels marketing692,884
 681,934
 976,216
Consolidation and intersegment eliminations(12,106) (20,944) (25,606)
Total revenues$1,814,019
 $1,756,682
 $2,084,040
      
Depreciation and amortization expense:     
Pipeline$128,061
 $89,554
 $84,951
Storage127,473
 118,663
 116,768
Total segment depreciation and amortization expense255,534
 208,217
 201,719
Other depreciation and amortization expense8,698
 8,519
 8,491
Total depreciation and amortization expense$264,232
 $216,736
 $210,210
      
Operating income:     
Pipeline$231,795
 $248,238
 $270,349
Storage219,439
 214,801
 217,818
Fuels marketing5,983
 3,406
 13,507
Consolidation and intersegment eliminations(1) —
 42
Total segment operating income457,216
 466,445
 501,716
General and administrative expenses112,240
 98,817
 102,521
Other depreciation and amortization expense8,698
 8,519
 8,491
Total operating income$336,278
 $359,109
 $390,704

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Revenues by geographic area are shown in the table below:
 Year Ended December 31,
 2017 2016 2015
 (Thousands of Dollars)
United States$1,406,626
 $1,352,936
 $1,599,088
Netherlands322,251
 313,395
 386,282
Other85,142
 90,351
 98,670
Consolidated revenues$1,814,019
 $1,756,682
 $2,084,040

For the years ended December 31, 2017, 20162023, 2022 and 2015,2021, Valero Energy Corporation accounted for approximately 17%22%, or $300.0$360.4 million, 18%, or $310.0$307.3 million,, and 16%19%, or $331.7$308.5 million, of our consolidated revenues, respectively. These revenues were included in our pipeline and storage segments for the year ended December 31, 2023, and in all of our reportable business segments.segments for the years ended December 31, 2022 and 2021. No other single customer accounted for 10% or more of our consolidated revenues.


Total amounts of property, plant and equipment, net by geographic area were as follows:
 December 31,
 20232022
 (Thousands of Dollars)
United States$3,234,544 $3,359,427 
Foreign47,993 43,656 
Property, plant and equipment, net$3,282,537 $3,403,083 

 December 31,
 2017 2016
 (Thousands of Dollars)
United States$3,519,965
 $3,086,337
Netherlands572,817
 469,061
Other208,151
 166,885
Consolidated long-lived assets$4,300,933
 $3,722,283

Total assets by reportable segment were as follows:
 December 31,
 20232022
 (Thousands of Dollars)
Pipeline$3,292,546 $3,360,685 
Storage1,398,929 1,438,609 
Fuels marketing46,151 37,763 
Total segment assets4,737,626 4,837,057 
Other partnership assets158,766 136,629 
Total assets$4,896,392 $4,973,686 

 December 31,
 2017 2016
 (Thousands of Dollars)
Pipeline$3,492,417
 $2,024,633
Storage2,735,563
 2,522,586
Fuels marketing118,746
 168,347
Total segment assets6,346,726
 4,715,566
Other partnership assets188,507
 314,979
Total consolidated assets$6,535,233
 $5,030,545

Capital expenditures including acquisitions and investments in other noncurrent assets, by reportable segment were as follows:
 Year Ended December 31,
 202320222021
 (Thousands of Dollars)
Pipeline$100,759 $90,430 $67,340 
Storage43,584 47,222 112,043 
Other partnership assets3,165 2,978 1,750 
Capital expenditures$147,508 $140,630 $181,133 

25. SUBSEQUENT EVENT

On January 22, 2024, NuStar Energy entered into an Agreement and Plan of Merger (the Merger Agreement) with Sunoco LP, a Delaware limited partnership (Sunoco), Saturn Merger Sub, LLC, a Delaware limited liability company and a direct wholly owned subsidiary of Sunoco (Merger Sub), Riverwalk Logistics, L.P., NuStar GP, LLC, and Sunoco GP LLC, a Delaware limited liability company and sole general partner of Sunoco (the Sunoco GP). The Merger Agreement provides that, among other things and on the terms and subject to the conditions set forth therein, Sunoco will acquire NuStar Energy in an all-equity transaction by means of a merger of Merger Sub with and into NuStar Energy (the Merger) with NuStar Energy surviving the Merger as a subsidiary of Sunoco.

On the terms and subject to the conditions set forth in the Merger Agreement, at the effective time of the Merger (the Effective Time), each NuStar Energy common unit issued and outstanding immediately prior to the Effective Time will be converted into and shall thereafter represent the right to receive 0.400 of a common unit of Sunoco and, if applicable, cash in lieu of fractional units. In addition, prior to the Effective Time, we will declare and pay a special cash distribution to our common unitholders in the amount of $0.212 per common unit (the Special Distribution) (in addition to continuing to pay our quarterly distributions in the ordinary course, subject to certain conditions, until the Effective Time).

100
 Year Ended December 31,
 2017 2016 2015
 (Thousands of Dollars)
Pipeline$1,596,311
 $88,373
 $175,657
Storage244,398
 206,641
 285,258
Other partnership assets5,648
 5,001
 9,957
Total capital expenditures$1,846,357
 $300,015
 $470,872

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26. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS
NuStar Energy has no operations,Each Series A, B and its assets consist mainlyC Preferred Unit issued and outstanding immediately prior to the Effective Time will remain issued and outstanding from and after the Effective Time as limited partnership interests of its 100% indirectly owned subsidiaries, NuStar Logistics and NuPOP. The senior and subordinated notes issued by NuStar Logisticsthe surviving entity having the same terms as are fully and unconditionally guaranteed by NuStar Energy and NuPOP. As a result,applicable to the following condensed consolidating financial statements are presented as an alternative to providing separate financial statements for NuStar Logistics and NuPOP.
Condensed Consolidating Balance Sheets
December 31, 2017
(Thousands of Dollars)
 
NuStar
Energy
 
NuStar
Logistics
 NuPOP 
Non-Guarantor
Subsidiaries
 Eliminations Consolidated
Assets           
Cash and cash equivalents$885
 $29
 $—
 $23,378
 $—
 $24,292
Receivables, net—
 280
 —
 176,495
 —
 176,775
Inventories—
 1,686
 8,611
 16,560
 —
 26,857
Other current assets61
 11,412
 4,191
 6,844
 —
 22,508
Intercompany receivable—
 3,112,164
 —
 —
 (3,112,164) —
Total current assets946
 3,125,571
 12,802
 223,277
 (3,112,164) 250,432
Property, plant and equipment, net—
 1,893,720
 591,070
 1,816,143
 —
 4,300,933
Intangible assets, net—
 58,530
 —
 725,949
 —
 784,479
Goodwill—
 149,453
 170,652
 777,370
 —
 1,097,475
Investment in wholly owned
subsidiaries
2,891,371
 24,162
 1,301,717
 790,882
 (5,008,132) —
Deferred income tax asset—
 —
 —
 233
 —
 233
Other long-term assets, net303
 65,684
 27,493
 8,201
 —
 101,681
Total assets$2,892,620
 $5,317,120
 $2,103,734
 $4,342,055
 $(8,120,296) $6,535,233
Liabilities and Partners’ Equity           
Current portion of long-term debt$—
 $349,990
 $—
 $—
 $—
 $349,990
Payables4,078
 27,642
 13,160
 101,052
 —
 145,932
Short-term debt—
 35,000
 —
 —
 —
 35,000
Accrued interest payable—
 40,402
 —
 47
 —
 40,449
Accrued liabilities1,105
 17,628
 9,450
 33,395
 —
 61,578
Taxes other than income tax125
 7,110
 3,794
 3,356
 —
 14,385
Income tax payable—
 732
 4
 3,436
 —
 4,172
Intercompany payable322,296
 —
 1,277,691
 1,512,177
 (3,112,164) —
Total current liabilities327,604
 478,504
 1,304,099
 1,653,463
 (3,112,164) 651,506
Long-term debt, less current portion—
 3,201,220
 —
 61,849
 —
 3,263,069
Deferred income tax liability—
 1,262
 12
 20,998
 —
 22,272
Other long-term liabilities—
 58,806
 8,861
 50,630
 —
 118,297
Total partners’ equity2,565,016
 1,577,328
 790,762
 2,555,115
 (5,008,132) 2,480,089
Total liabilities and
partners’ equity
$2,892,620
 $5,317,120
 $2,103,734
 $4,342,055
 $(8,120,296) $6,535,233


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Condensed Consolidating Balance Sheets
December 31, 2016
(Thousands of Dollars)
 
NuStar
Energy
 
NuStar
Logistics
 NuPOP 
Non-Guarantor
Subsidiaries
 Eliminations Consolidated
Assets           
Cash and cash equivalents$870
 $5
 $—
 $35,067
 $—
 $35,942
Receivables, net—
 3,040
 —
 167,570
 —
 170,610
Inventories—
 2,216
 2,005
 33,724
 —
 37,945
Other current assets61
 120,350
 1,829
 10,446
 —
 132,686
Intercompany receivable—
 1,308,415
 —
 57,785
 (1,366,200) —
Total current assets931
 1,434,026
 3,834
 304,592
 (1,366,200) 377,183
Property, plant and equipment, net—
 1,935,172
 589,139
 1,197,972
 —
 3,722,283
Intangible assets, net—
 71,033
 —
 56,050
 —
 127,083
Goodwill—
 149,453
 170,652
 376,532
 —
 696,637
Investment in wholly owned
subsidiaries
1,964,736
 34,778
 1,221,717
 874,649
 (4,095,880) —
Deferred income tax asset—
 —
 —
 2,051
 —
 2,051
Other long-term assets, net1,255
 63,586
 28,587
 11,880
 —
 105,308
Total assets$1,966,922
 $3,688,048
 $2,013,929
 $2,823,726
 $(5,462,080) $5,030,545
Liabilities and Partners’ Equity           
Payables$2,436
 $24,272
 $7,124
 $84,854
 $—
 $118,686
Short-term debt—
 54,000
 —
 —
 —
 54,000
Accrued interest payable—
 34,008
 —
 22
 —
 34,030
Accrued liabilities1,070
 7,118
 10,766
 41,531
 —
 60,485
Taxes other than income tax125
 6,854
 3,253
 5,453
 —
 15,685
Income tax payable—
 1,326
 5
 5,179
 —
 6,510
Intercompany payable257,497
 —
 1,108,703
 —
 (1,366,200) —
Total current liabilities261,128
 127,578
 1,129,851
 137,039
 (1,366,200) 289,396
Long-term debt—
 2,956,338
 —
 58,026
 —
 3,014,364
Deferred income tax liability—
 1,862
 13
 20,329
 —
 22,204
Other long-term liabilities—
 34,358
 9,436
 49,170
 —
 92,964
Total partners’ equity1,705,794
 567,912
 874,629
 2,559,162
 (4,095,880) 1,611,617
Total liabilities and
partners’ equity
$1,966,922
 $3,688,048
 $2,013,929
 $2,823,726
 $(5,462,080) $5,030,545

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Condensed Consolidating Statements of Income (Loss)
For the Year Ended December 31, 2017
(Thousands of Dollars)
 
NuStar
Energy
 
NuStar
Logistics
 NuPOP 
Non-Guarantor
Subsidiaries
 Eliminations Consolidated
Revenues$—
 $496,454
 $221,125
 $1,097,458
 $(1,018) $1,814,019
Costs and expenses1,868
 317,871
 146,243
 1,012,777
 (1,018) 1,477,741
Operating (loss) income(1,868) 178,583
 74,882
 84,681
 —
 336,278
Equity in earnings (loss)
of subsidiaries
149,775
 (10,616) 89,405
 158,700
 (387,264) —
Interest income (expense), net57
 (176,897) (5,587) 9,344
 —
 (173,083)
Other income (expense), net—
 145
 3
 (5,442) —
 (5,294)
Income (loss) before income tax
(benefit) expense
147,964
 (8,785) 158,703
 247,283
 (387,264) 157,901
Income tax (benefit) expense—
 (820) 2
 10,755
 —
 9,937
Net income (loss)$147,964
 $(7,965) $158,701
 $236,528
 $(387,264) $147,964

Condensed Consolidating Statements of Income (Loss)
For the Year Ended December 31, 2016
(Thousands of Dollars)
 
NuStar
Energy
 
NuStar
Logistics
 NuPOP 
Non-Guarantor
Subsidiaries
 Eliminations Consolidated
Revenues$—
 $511,650
 $224,966
 $1,021,804
 $(1,738) $1,756,682
Costs and expenses1,806
 302,099
 150,384
 945,022
 (1,738) 1,397,573
Operating (loss) income(1,806) 209,551
 74,582
 76,782
 —
 359,109
Equity in earnings (loss)
of subsidiaries
151,794
 (13,769) 82,202
 156,036
 (376,263) —
Interest (expense) income, net—
 (139,827) (744) 2,221
 —
 (138,350)
Other income (expense), net18
 (58,264) (26) (511) —
 (58,783)
Income (loss) before income
tax expense (benefit)
150,006
 (2,309) 156,014
 234,528
 (376,263) 161,976
Income tax expense (benefit)3
 1,607
 (23) 10,386
 —
 11,973
Net income (loss)$150,003
 $(3,916) $156,037
 $224,142
 $(376,263) $150,003


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Condensed Consolidating Statements of Income
For the Year Ended December 31, 2015
(Thousands of Dollars)
 
NuStar
Energy
 
NuStar
Logistics
 NuPOP 
Non-Guarantor
Subsidiaries
 Eliminations Consolidated
Revenues$—
 $547,959
 $215,469
 $1,322,675
 $(2,063) $2,084,040
Costs and expenses1,717
 293,708
 140,081
 1,259,935
 (2,105) 1,693,336
Operating (loss) income(1,717) 254,251
 75,388
 62,740
 42
 390,704
Equity in earnings (loss)
of subsidiaries
308,437
 (7,257) 120,768
 197,760
 (619,708) —
Interest (expense) income, net—
 (137,847) 1,611
 4,368
 —
 (131,868)
Other income, net—
 1,179
 5
 60,638
 —
 61,822
Income from continuing
operations before income
tax (benefit) expense
306,720
 110,326
 197,772
 325,506
 (619,666) 320,658
Income tax (benefit) expense—
 (392) 23
 15,081
 —
 14,712
Income from continuing
operations
306,720
 110,718
 197,749
 310,425
 (619,666) 305,946
Income from discontinued
operations, net of tax
—
 —
 —
 774
 —
 774
Net income$306,720
 $110,718
 $197,749
 $311,199
 $(619,666) $306,720



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Condensed Consolidating Statements of Comprehensive Income (Loss)
For the Year Ended December 31, 2017
(Thousands of Dollars)
 
NuStar
Energy
 
NuStar
Logistics
 NuPOP 
Non-Guarantor
Subsidiaries
 Eliminations Consolidated
Net income (loss)$147,964
 $(7,965) $158,701
 $236,528
 $(387,264) $147,964
            
Other comprehensive income (loss):           
Foreign currency translation
adjustment
—
 —
 —
 17,466
 —
 17,466
Net loss on pension and other postretirement benefit adjustments, net of tax benefit—
 —
 —
 (6,170) —
 (6,170)
Net loss on cash flow hedges—
 (2,046) —
 —
 —
 (2,046)
Total other comprehensive
(loss) income
—
 (2,046) —
 11,296
 —
 9,250
Comprehensive income (loss)$147,964
 $(10,011) $158,701
 $247,824
 $(387,264) $157,214

Condensed Consolidating Statements of Comprehensive Income
For the Year Ended December 31, 2016
(Thousands of Dollars)
 
NuStar
Energy
 
NuStar
Logistics
 NuPOP 
Non-Guarantor
Subsidiaries
 Eliminations Consolidated
Net income (loss)$150,003
 $(3,916) $156,037
 $224,142
 $(376,263) $150,003
            
Other comprehensive income (loss):           
Foreign currency translation
adjustment
—
 —
 —
 (8,243) —
 (8,243)
Net loss on pension and other postretirement benefit adjustments, net of tax benefits—
 —
 —
 (2,850) —
 (2,850)
Net gain on cash flow hedges—
 5,710
 —
 —
 —
 5,710
Total other comprehensive
income (loss)
—
 5,710
 —
 (11,093) —
 (5,383)
Comprehensive income$150,003
 $1,794
 $156,037
 $213,049
 $(376,263) $144,620

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Condensed Consolidating Statements of Comprehensive Income
For the Year Ended December 31, 2015
(Thousands of Dollars)
 
NuStar
Energy
 
NuStar
Logistics
 NuPOP 
Non-Guarantor
Subsidiaries
 Eliminations Consolidated
Net income$306,720
 $110,718
 $197,749
 $311,199
 $(619,666) $306,720
            
Other comprehensive income (loss):           
Foreign currency translation
adjustment
—
 —
 —
 (31,987) —
 (31,987)
Net gain on cash flow hedges—
 11,105
 —
 —
 —
 11,105
Total other comprehensive
income (loss)
—
 11,105
 —
 (31,987) —
 (20,882)
Comprehensive income$306,720
 $121,823
 $197,749
 $279,212
 $(619,666) $285,838


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Condensed Consolidating Statements of Cash Flows
For the Year Ended December 31, 2017
(Thousands of Dollars)
 
NuStar
Energy
 
NuStar
Logistics
 NuPOP 
Non-Guarantor
Subsidiaries
 Eliminations Consolidated
Net cash provided by operating
activities
$483,481
 $152,101
 $102,405
 $405,950
 $(737,138) $406,799
Cash flows from investing activities:           
Capital expenditures—
 (47,600) (35,041) (301,997) —
 (384,638)
Change in accounts payable
related to capital expenditures
—
 (1,988) 5,964
 32,927
 —
 36,903
Acquisitions—
 —
 —
 (1,461,719) —
 (1,461,719)
Proceeds from Axeon term loan—
 110,000
 —
 —
 —
 110,000
Proceeds from insurance recoveries—
 —
 —
 977
 —
 977
Proceeds from sale or disposition
of assets
—
 1,955
 18
 63
 —
 2,036
Investment in subsidiaries(1,262,000) —
 —
 (126) 1,262,126
 —
Net cash (used in) provided by investing activities(1,262,000) 62,367
 (29,059) (1,729,875) 1,262,126
 (1,696,441)
Cash flows from financing activities:           
Debt borrowings—
 2,969,400
 —
 90,700
 —
 3,060,100
Debt repayments—
 (2,400,739) —
 (86,800) —
 (2,487,539)
Issuance of preferred units, net of issuance costs538,560
 —
 —
 —
 —
 538,560
Issuance of common units, net of
issuance costs
643,878
 —
 —
 —
 —
 643,878
General partner contribution13,737
 —
 —
 —
 —
 13,737
Distributions to preferred unitholders(38,833) (19,417) (19,416) (19,418) 58,251
 (38,833)
Distributions to common unitholders
   and general partner
(446,306) (223,153) (223,153) (223,176) 669,482
 (446,306)
Contributions from
(distributions to) affiliates
—
 1,262,000
 —
 (9,279) (1,252,721) —
Net intercompany activity73,206
 (1,801,218) 169,223
 1,558,789
 —
 —
Other, net(5,708) (1,317) —
 (300) —
 (7,325)
Net cash provided by (used in)
financing activities
778,534
 (214,444) (73,346) 1,310,516
 (524,988) 1,276,272
Effect of foreign exchange rate
changes on cash
—
 —
 —
 1,720
 —
 1,720
Net increase (decrease) in cash and cash equivalents15
 24
 —
 (11,689) —
 (11,650)
Cash and cash equivalents as of the
beginning of the period
870
 5
 —
 35,067
 —
 35,942
Cash and cash equivalents as of the
end of the period
$885
 $29
 $—
 $23,378
 $—
 $24,292


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Condensed Consolidating Statements of Cash Flows
For the Year Ended December 31, 2016
(Thousands of Dollars)
 
NuStar
Energy
 
NuStar
Logistics
 NuPOP 
Non-Guarantor
Subsidiaries
 Eliminations Consolidated
Net cash provided by operating
activities
$391,773
 $167,900
 $211,816
 $359,283
 $(694,011) $436,761
Cash flows from investing activities:           
Capital expenditures—
 (64,334) (52,637) (87,387) —
 (204,358)
Change in accounts payable
related to capital expenditures
—
 (10,076) (285) (702) —
 (11,063)
Acquisitions—
 (95,657) —
 —
 —
 (95,657)
Investment in subsidiaries—
 —
 (212,900) —
 212,900
 —
Net cash used in investing activities—
 (170,067) (265,822) (88,089) 212,900
 (311,078)
Cash flows from financing activities:           
Debt borrowings—
 1,365,529
 —
 41,200
 —
 1,406,729
Debt repayments—
 (1,419,852) —
 (36,300) —
 (1,456,152)
Issuance of preferred units, net of
issuance costs		218,400
 —
 —
 —
 —
 218,400
Issuance of common units, net of
issuance costs		27,710
 —
 —
 —
 —
 27,710
General partner contribution680
 —
 —
 —
 —
 680
Distributions to common unitholders
   and general partner
(392,962) (196,481) (196,481) (196,501) 589,463
 (392,962)
Contributions from affiliates—
 —
 —
 108,352
 (108,352) —
Net intercompany activity(241,131) 255,326
 250,487
 (264,682) —
 —
Other, net(4,485) (2,354) —
 (8,890) —
 (15,729)
Net cash (used in) provided by financing activities(391,788) 2,168
 54,006
 (356,821) 481,111
 (211,324)
Effect of foreign exchange rate
changes on cash
—
 —
 —
 2,721
 —
 2,721
Net (decrease) increase in cash and
cash equivalents
(15) 1
 —
 (82,906) —
 (82,920)
Cash and cash equivalents as of the
beginning of the period
885
 4
 —
 117,973
 —
 118,862
Cash and cash equivalents as of the
end of the period
$870
 $5
 $—
 $35,067
 $—
 $35,942


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Condensed Consolidating Statements of Cash Flows
For the Year Ended December 31, 2015
(Thousands of Dollars)
 
NuStar
Energy
 
NuStar
Logistics
 NuPOP 
Non-Guarantor
Subsidiaries
 Eliminations Consolidated
Net cash provided by operating
activities
$389,967
 $237,780
 $119,928
 $365,588
 $(588,326) $524,937
Cash flows from investing activities:           
Capital expenditures—
 (201,388) (39,533) (83,887) —
 (324,808)
Change in accounts payable
related to capital expenditures
—
 (4,950) 33
 1,761
 —
 (3,156)
Acquisitions—
 —
 —
 (142,500) —
 (142,500)
Proceeds from insurance recoveries—
 —
 —
 4,867
 —
 4,867
Proceeds from sale or disposition
of assets
—
 10,320
 22
 6,790
 —
 17,132
Investment in other long-term assets—
 —
 —
 (3,564) —
 (3,564)
Net cash used in investing activities—
 (196,018) (39,478) (216,533) —
 (452,029)
Cash flows from financing activities:           
Debt borrowings—
 1,589,131
 —
 94,500
 —
 1,683,631
Debt repayments—
 (1,275,910) —
 (41,000) —
 (1,316,910)
Distributions to common unitholders
   and general partner
(392,204) (196,102) (196,102) (196,122) 588,326
 (392,204)
Net intercompany activity2,199
 (155,278) 115,652
 37,427
 —
 —
Other, net—
 (3,605) —
 (141) —
 (3,746)
Net cash used in financing activities(390,005) (41,764) (80,450) (105,336) 588,326
 (29,229)
Effect of foreign exchange rate
changes on cash
—
 —
 —
 (12,729) —
 (12,729)
Net (decrease) increase in cash and
cash equivalents
(38) (2) —
 30,990
 —
 30,950
Cash and cash equivalents as of the
beginning of the period
923
 6
 —
 86,983
 —
 87,912
Cash and cash equivalents as of the
end of the period
$885
 $4
 $—
 $117,973
 $—
 $118,862


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)



27. QUARTERLY FINANCIAL DATA (UNAUDITED)

The following table summarizes quarterly financial data for the years ended December 31, 2017 and 2016:
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 Total
 (Thousands of Dollars, Except Per Unit Data)
2017:         
Revenues$487,430
 $435,488
 $440,566
 $450,535
 $1,814,019
Operating income$97,139
 $73,404
 $91,717
 $74,018
 $336,278
Net income$57,940
 $26,250
 $38,592
 $25,182
 $147,964
Basic and diluted net income per common unit$0.49
 $0.05
 $0.15
 $—
 $0.64
Cash distributions per unit applicable to common limited partners$1.095
 $1.095
 $1.095
 $1.095
 $4.380
          
2016:         
Revenues$405,703
 $437,804
 $441,418
 $471,757
 $1,756,682
Operating income$94,565
 $91,217
 $87,954
 $85,373
 $359,109
Net income (loss)$57,401
 $52,517
 $51,141
 $(11,056) $150,003
Basic and diluted net income (loss) per common unit$0.57
 $0.52
 $0.49
 $(0.31) $1.27
Cash distributions per unit applicable to common limited partners$1.095
 $1.095
 $1.095
 $1.095
 $4.380

The quarterly financial data in the table above includes the impact of a $58.7 million non-cash impairment charge on the Axeon Term Loan in the fourth quarter of 2016.

28. SUBSEQUENT EVENTS

On February 7, 2018, NuStar Energy, Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, a wholly owned subsidiaryapplicable series of NuStar Energy (Merger Sub), Riverwalk Holdings, LLCpreferred unit immediately prior to the Effective Time.

The completion of the Merger is subject to the fulfillment or waiver of certain conditions, including, among others: approval and adoption by NuStar GP Holdings entered into an Agreement and PlanEnergy’s common unitholders of Merger (the Merger Agreement) pursuant to which Merger Sub will merge with and into NuStar GP Holdings with NuStar GP Holdings being the surviving entity (the Merger), such that NuStar Energy will be the sole member of NuStar GP Holdings following the Merger. Pursuant to the Merger Agreement and at the effective timetransactions contemplated thereby, including the Merger; expiration or termination of the Merger, NuStar Energy’s partnership agreement will be amended and restated to, among other things, (i) cancelapplicable waiting period under the incentive distribution rights held by our general partner, (ii) convert the 2% general partner interest in NuStar Energy held by our general partner into a non-economic management interest and (iii) provide the holdersHart-Scott-Rodino Antitrust Improvements Act of our common units with voting rights in the election of the members of the board of directors of NuStar GP, LLC at an annual meeting, beginning in 2019.

At the effective time of the Merger, each outstanding NuStar GP Holdings common unit, other than those held by NuStar GP Holdings or its subsidiaries, will be converted into the right to receive 0.55 of a NuStar Energy common unit. All NuStar GP Holdings common units, when converted, will cease to be outstanding and will automatically be cancelled and no longer exist. No fractional NuStar Energy common units will be issued in the Merger; instead, each holder of NuStar GP Holdings’ common units otherwise entitled to receive a fractional NuStar Energy common unit will receive cash in lieu thereof. Furthermore, the 10,214,626 NuStar Energy common units currently owned by NuStar GP Holdings will be cancelled and will cease to exist.

At the effective time of the Merger, each outstanding award of NuStar GP Holdings restricted units will be converted, on the same terms and conditions as were applicable to the awards immediately prior to the Merger, into an award of NuStar Energy restricted units. The number of NuStar Energy restricted units subject to the converted awards will be determined as provided in the Merger Agreement. Each of our executive officers and directors has agreed and acknowledged that the Merger will not be deemed to trigger a “change of control” as defined under any NuStar Energy or NuStar GP Holdings plan or award, and has waived any rights to vesting, payment or other benefit thereunder that would arise upon a “change of control,” to which he or she might otherwise have been entitled.

The Merger Agreement contains customary representations and warranties and covenants by each of the parties. Completion of the Merger is conditioned upon, among other things: (i) approval of the Merger Agreement by the affirmative vote of holders of

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a Unit Majority, as defined in the Second Amended and Restated Limited Liability Company Agreement of NuStar GP Holdings,1976, as amended; (ii)and the effectiveness of athe registration statement on Form S-4 with respect to the issuancebe filed by NuStar Energy of its common units in connection with the Merger; (iii) the absence of certain legal injunctions or impediments prohibiting the transactions; (iv) the receipt of certain tax opinions from a nationally recognized tax counsel; and (v) the approval for the listing of NuStar Energy’sSunoco pursuant to which Sunoco common units to be issued in connection with the Merger onare registered with the New York Stock Exchange.U.S. Securities and Exchange Commission (the SEC).


The Merger Agreement contains termination rights for each of NuStar Energy entered into a Support Agreement, dated as of February 7, 2018 (the Support Agreement), with Merger Sub, WLG Holdings, LLC, a Texas limited liability company controlled by Mr. Greehey (WLG Holdings), Mr. Greehey (together, WLG Holdings and Mr. Greehey are referred to as the Greehey Unitholders), and, for limited purposes, NuStar GP Holdings, pursuant to which the Greehey Unitholders have agreed to vote in favor of the approval and adoption of the Merger Agreement, the approval of the Merger and any other action required in furtherance thereof submitted for the vote or written consent of NuStar GP Holdings unitholders. The Greehey Unitholders collectively own approximately 21% of the outstanding NuStar GP Holdings units. The Support Agreement will terminate (i) at the effective time of the Merger, (ii) upon theSunoco. Upon termination of the Merger Agreement as provided therein,under specified circumstances, including the termination by Sunoco in the event of an adverse recommendation change by our Board of Directors or (iii) at such time asby NuStar Energy to accept a Superior Proposal (as defined in the Merger Agreement), NuStar Energy would be required to pay Sunoco a termination fee of approximately $90.3 million.

Concurrently with the entry into the Merger Agreement, NuStar Energy and Sunoco entered into an agreement (the Support Agreement) with Energy Transfer LP (Energy Transfer), a Delaware limited partnership and the Greehey Unitholders agreesole member of the Sunoco GP. The Support Agreement provides, among other things, that Energy Transfer will not transfer its ownership interest in writingthe Sunoco GP, any of the Sunoco incentive distribution rights owned by it or any material portion of the Sunoco common units owned by it prior to terminatethe Effective Time. Energy Transfer has also agreed to be bound by the terms of the non-solicitation provisions in the Merger Agreement with respect to competing proposals for Sunoco and the Sunoco GP and to abide by certain covenants with respect to regulatory approvals, SEC filings, confidentiality and litigation, among other things.

The foregoing descriptions of the Merger Agreement and the Support Agreement and the transactions contemplated thereby, including the Merger, are summaries, do not purport to be complete and are qualified in their entirety by reference to the full text of the Merger Agreement and the Support Agreement.

101
After the Merger, the NuStar GP, LLC board

ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Additionally, on February 8, 2018, we announced that our management anticipates recommending to the board of directors of NuStar GP, LLC, and the board of directors expects to adopt, a reset of our quarterly distribution per common unit to $0.60 ($2.40 on an annualized basis), starting with the first-quarter distribution payable in May 2018.

ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
 
ITEM 9A.CONTROLS AND PROCEDURES
ITEM 9A.CONTROLS AND PROCEDURES
DISCLOSURE CONTROLS AND PROCEDURES
Our management has evaluated, with the participation of the principal executive officer and principal financial officer of NuStar GP, LLC, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, (the Exchange Act))as amended) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures were effective as of December 31, 2017.2023.
INTERNAL CONTROL OVERRestricted 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, prior to the sale of our Point Tupper Terminal Operations on April 29, 2022, the fair value of the common units measured at each reporting period (for international employees). DERs paid with respect to outstanding equity-classified unvested restricted units reduce equity, similar to cash distributions to unitholders, whereas DERs paid with respect to outstanding liability-classified unvested restricted units were expensed prior to the sale of our Point Tupper Terminal Operations on April 29, 2022. In connection with the DERs for equity awards, we paid $2.7 million, $2.5 million and $2.4 million respectively, in cash, for the years ended December 31, 2023, 2022 and 2021.

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. The fair value of these awards is measured at the grant date.

International Employees. Prior to the sale of our Point Tupper Terminal Operations on April 29, 2022, the outstanding restricted units granted to international employees were cash-settled and accounted for as liability-classified awards. These awards vested over three years and the fair value was equal to the market price of our common units at each reporting period. For the year ended December 31, 2022, 11,364 restricted units vested, and 10,396 restricted units were forfeited related to our international employees.

A summary of our equity-classified restricted unit awards is as follows:
Measured at Grant Date Fair Value
Number of UnitsWeighted-Average Fair Value Per Unit
Nonvested units as of January 1, 20212,333,894 $17.70 
Granted1,049,081 16.28 
Vested(630,888)20.07 
Forfeited(102,339)14.28 
Nonvested units as of December 31, 20212,649,748 16.57 
Granted1,206,824 16.09 
Vested(738,701)17.79 
Forfeited(125,078)16.23 
Nonvested units as of December 31, 20222,992,793 16.08 
Granted1,112,965 17.49 
Vested(921,890)16.81 
Forfeited(23,434)15.93 
Nonvested units as of December 31, 20233,160,434 16.39 

The total fair value of our equity-classified restricted unit awards vested for the years ended December 31, 2023, 2022 and 2021 was $16.1 million, $11.9 million and $10.3 million, respectively. We issued 661,050, 531,637 and 460,076 common units in
95
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NOTES TO CONSOLIDATED FINANCIAL REPORTINGSTATEMENTS – (Continued)
(a)Management’s Report on Internal Control over Financial Reporting.
Management’s report on NuStar Energy L.P.’s internal controlconnection with these award vestings, net of employee tax withholding requirements, for the years ended December 31, 2023, 2022 and 2021, respectively. Unrecognized compensation cost related to our equity-classified employee awards totaled $49.2 million as of December 31, 2023, which we expect to recognize over financial reporting requireda weighted-average period of 3.6 years.

Performance Awards
Performance awards are issued to certain of our key employees and represent either rights to receive our common units or cash upon achieving performance measures for the performance period established by Item 9A. 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.


PART III

ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
DIRECTORS AND EXECUTIVE OFFICERS OF NUSTAR GP, LLC
We do not have directors or officers. The directors and officers of NuStar GP, LLC Compensation Committee (the Compensation Committee). Achievement of the general partnerperformance 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 AwardsTotal Performance
Unit Awards Granted		Performance Unit AwardsWeighted-Average Grant Date Fair Value per Unit
(Thousands of Dollars)
Outstanding as of January 1, 2021$2,167 87,122 57,448 $13.21 
Granted2,254 4,021 33,695 15.79 
Vested (a)(672)(53,427)(53,427)13.21 
Forfeited(51)(4,021)(4,021)13.21 
Outstanding as of December 31, 20213,698 33,695 33,695 15.79 
Granted2,954 — — — 
Performance adjustment (b)— 14,839 14,839 15.79 
Vested (a)(1,507)(48,534)(48,534)15.79 
Outstanding as of December 31, 20225,145 — — — 
Granted3,287 — — — 
Vested (a)(2,575)— — — 
Forfeited(141)— — — 
Outstanding as of December 31, 2023$5,716 — — — 
(a)For the years ended December 31, 2023, 2022 and 2021, we settled performance cash awards with 149,608, 137,931 and 43,733 common units, respectively, and issued 86,945, 84,778 and 26,704 common units, net of employee tax withholding requirements, respectively.
(b)For the year ended December 31, 2022, common units granted and issued upon vesting resulted from performance units earned at 150% of the 2021 target.

The total fair value of our performance unit awards vested for the years ended December 31, 2022 and 2021 was $0.8 million and $0.8 million, respectively. For the years ended December 31, 2022 and 2021 we issued 29,840 and 31,366 common units in connection with the performance unit award vestings, net of employee tax withholding requirements, respectively. In January 2024, we settled performance cash awards, net of employee tax withholding requirements, in cash for $1.6 million.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
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 that was paid in unit awards in the first quarter of 2022. 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 GrantGrant Date Fair ValueUnit Awards GrantedCommon Units Issued, Net of Employee Withholding Tax
(Thousands of Dollars)
February 2022$4,645 280,685 186,190 

23. INCOME TAXES
Components of income tax expense related to certain of our operations conducted through separate taxable wholly owned corporate subsidiaries were as follows:
 Year Ended December 31,
 202320222021
 (Thousands of Dollars)
Current:
U.S.$4,292 $3,558 $3,755 
Foreign— 272 221 
Foreign withholding tax519 355 1,281 
Total current4,811 4,185 5,257 
Deferred:
U.S.601 341 (93)
Foreign— (1,287)(531)
Foreign withholding tax— — (745)
Total deferred601 (946)(1,369)
Income tax expense$5,412 $3,239 $3,888 

The difference between income tax expense recorded in our consolidated statements of income 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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NUSTAR ENERGY L.P. AND SUBSIDIARIES
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,
 20232022
 (Thousands of Dollars)
Deferred income tax assets:
Net operating losses$19,340 $17,710 
Capital loss3,714 3,714 
Other701 793 
Total deferred income tax assets23,755 22,217 
Less: Valuation allowance(22,866)(21,573)
Net deferred income tax assets889 644 
Deferred income tax liabilities:
Property, plant and equipment(4,420)(3,534)
Foreign withholding tax(330)(286)
Other(72)(43)
Total deferred income tax liabilities(4,822)(3,863)
Net deferred income tax liability$(3,933)$(3,219)

As of December 31, 2023, our U.S. and foreign corporate operations have net operating loss carryforwards for tax purposes totaling $49.2 million and $30.1 million, respectively, which are subject to various limitations on use and expire in years 2032 through 2034 for U.S. losses and in years 2024 through 2034 for foreign losses. However, U.S. losses generated after
December 31, 2017, totaling $5.1 million, can be carried forward indefinitely. As of December 31, 2023, 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.

As of December 31, 2023 and 2022, we have a valuation allowance of $22.9 million and $21.6 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 2023, there was a $0.4 million decrease in the valuation allowance for the U.S. net operating loss and a $1.7 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, 2023 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, 2023 will be realized, based on expected future taxable income.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES
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 partner, Riverwalk Logistics,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,
 202320222021
 (Thousands of Dollars)
Revenues:
Pipeline$873,869 $828,191 $762,238 
Storage319,599 334,549 427,668 
Fuels marketing440,725 520,486 428,608 
Consolidation and intersegment eliminations(6)(3)(14)
Total revenues$1,634,187 $1,683,223 $1,618,500 
Depreciation and amortization expense:
Pipeline$175,930 $178,802 $179,088 
Storage75,052 73,076 87,500 
Segment depreciation and amortization expense250,982 251,878 266,588 
Other depreciation and amortization expense4,728 7,358 7,792 
Total depreciation and amortization expense$255,710 $259,236 $274,380 
Reconciliation of segment operating income to income before income tax expense:
Pipeline$483,188 $438,670 $321,472 
Storage87,609 61,081 24,800 
Fuels marketing32,926 33,536 11,181 
Segment operating income603,723 533,287 357,453 
Gain on sale of assets41,075 — — 
General and administrative expenses129,846 117,116 113,207 
Other depreciation and amortization expense4,728 7,358 7,792 
Operating income510,224 408,813 236,454 
Interest expense, net(241,364)(209,009)(213,985)
Other income, net10,215 26,182 19,644 
Income before income tax expense$279,075 $225,986 $42,113 

Revenues by geographic area are shown in the table below:
 Year Ended December 31,
 202320222021
 (Thousands of Dollars)
United States$1,628,215 $1,667,672 $1,582,672 
Foreign5,972 15,551 35,828 
Total revenues$1,634,187 $1,683,223 $1,618,500 

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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
For the years ended December 31, 2023, 2022 and 2021, Valero Energy Corporation accounted for approximately 22%, performor $360.4 million, 18%, or $307.3 million, and 19%, or $308.5 million, of our revenues, respectively. These revenues were included in our pipeline and storage segments for the year ended December 31, 2023, and in all of our management functions.reportable business segments for the years ended December 31, 2022 and 2021. No other single customer accounted for 10% or more of our consolidated revenues.

Total amounts of property, plant and equipment, net by geographic area were as follows:
 December 31,
 20232022
 (Thousands of Dollars)
United States$3,234,544 $3,359,427 
Foreign47,993 43,656 
Property, plant and equipment, net$3,282,537 $3,403,083 

Total assets by reportable segment were as follows:
 December 31,
 20232022
 (Thousands of Dollars)
Pipeline$3,292,546 $3,360,685 
Storage1,398,929 1,438,609 
Fuels marketing46,151 37,763 
Total segment assets4,737,626 4,837,057 
Other partnership assets158,766 136,629 
Total assets$4,896,392 $4,973,686 

Capital expenditures by reportable segment were as follows:
 Year Ended December 31,
 202320222021
 (Thousands of Dollars)
Pipeline$100,759 $90,430 $67,340 
Storage43,584 47,222 112,043 
Other partnership assets3,165 2,978 1,750 
Capital expenditures$147,508 $140,630 $181,133 

25. SUBSEQUENT EVENT

On January 22, 2024, NuStar GP Holdings, the sole member of NuStar GP, LLC, selects the directors of NuStar GP, LLC (the Board) annually. Officers of NuStar GP, LLC are appointed annually by its directors.
As described below in Item 13, on February 7, 2018, NuStar Energy Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, a wholly owned subsidiary of NuStar Energy (Merger Sub), Riverwalk Holdings, LLC and NuStar GP Holdings entered into an Agreement and Plan of Merger (the Merger Agreement) pursuant to whichwith Sunoco LP, a Delaware limited partnership (Sunoco), Saturn Merger Sub, LLC, a Delaware limited liability company and a direct wholly owned subsidiary of Sunoco (Merger Sub), Riverwalk Logistics, L.P., NuStar GP, LLC, and Sunoco GP LLC, a Delaware limited liability company and sole general partner of Sunoco (the Sunoco GP). The Merger Agreement provides that, among other things and on the terms and subject to the conditions set forth therein, Sunoco will mergeacquire NuStar Energy in an all-equity transaction by means of a merger of Merger Sub with and into NuStar GP HoldingsEnergy (the Merger) with NuStar GP Holdings beingEnergy surviving the surviving entity (the Merger), such that NuStar Energy will beMerger as a subsidiary of Sunoco.

On the sole member of NuStar GP Holdings following the Merger. Pursuantterms and subject to the conditions set forth in the Merger Agreement, and at the effective time of the Merger (the Effective Time), each NuStar Energy’s partnership agreementEnergy common unit issued and outstanding immediately prior to the Effective Time will be amendedconverted into and restatedshall thereafter represent the right to among other things, providereceive 0.400 of a common unit of Sunoco and, if applicable, cash in lieu of fractional units. In addition, prior to the holdersEffective Time, we will declare and pay a special cash distribution to our common unitholders in the amount of $0.212 per common unit (the Special Distribution) (in addition to continuing to pay our quarterly distributions in the ordinary course, subject to certain conditions, until the Effective Time).

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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Each Series A, B and C Preferred Unit issued and outstanding immediately prior to the Effective Time will remain issued and outstanding from and after the Effective Time as limited partnership interests of the surviving entity having the same terms as are applicable to the applicable series of NuStar Energy common units with voting rights inpreferred unit immediately prior to the electionEffective Time.

The completion of the members of the Board of NuStar GP, LLC at an annual meeting, beginning in 2019. After the Merger, the NuStar GP, LLC Board is expected to consist of nine members, initially composed of the six members of the NuStar GP, LLC Board and the three independent directors of the board of directors of NuStar GP Holdings, LLC. The Merger is subject to the satisfactionfulfillment or waiver of certain conditions, including, among others: approval and adoption by NuStar Energy’s common unitholders of the Merger Agreement by NuStar GP Holdings unitholders. Please refer to Item 13 for further discussionand the transactions contemplated thereby, including the Merger; expiration or termination of the Merger.
Set forth below is certain information concerningapplicable waiting period under the directorsHart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; and executive officers of NuStar GP, LLC, effective as of February 20, 2018.

NameAgePosition Held with NuStar GP, LLC
William E. Greehey81Chairman of the Board
Bradley C. Barron52President, Chief Executive Officer and Director
J. Dan Bates73Director
Dan J. Hill77Director
Robert J. Munch66Director
W. Grady Rosier69Director
Mary Rose Brown61Executive Vice President and Chief Administrative Officer
Thomas R. Shoaf59Executive Vice President and Chief Financial Officer
Jorge A. del Alamo48Senior Vice President and Controller
Daniel S. Oliver51Senior Vice President-Marketing and Business Development
Amy L. Perry49Senior Vice President, General Counsel-Corporate & Commercial Law and Corporate Secretary
Karen M. Thompson50Senior Vice President and General Counsel-Litigation, Regulatory & Environmental
Michael Truby58Senior Vice President-Operations
As a limited partnership, we are not required by the NYSE rules to have a nominating committee. However, in 2013, the Board created a Nominating/Governance & Conflicts Committee to identify candidates for membership on the Board. The memberseffectiveness of the Nominating/Governance & Conflicts Committeeregistration statement on Form S-4 to be filed by Sunoco pursuant to which Sunoco common units to be issued in connection with the Merger are Mr. Rosier (Chairman), Mr. Bates, Mr. Hillregistered with the U.S. Securities and Mr. Munch. In accordance with our Corporate Governance Guidelines, individuals are consideredExchange Commission (the SEC).

The Merger Agreement contains termination rights for membership on the Board based on their character, judgment, integrity, diversity, age, skills (including financial literacy), independence and experience in the context of the overall needs of the Board. Our directors are also selected based on their knowledge about our industry and their respective experience leading or advising large companies. We require that our directors have the ability to work collegially, exercise good judgment and think critically. The Nominating/Governance & Conflicts Committee strives to find the best possible candidates to represent the interestseach of NuStar Energy and its unitholders. As part of its annual self-assessment process, the Nominating/Governance & Conflicts Committee evaluates the mix of independent and non-independent directors, the selection and functionsSunoco. Upon termination of the presiding director and whetherMerger Agreement under specified circumstances, including the Board has the appropriate range of talents, expertise and backgrounds.

The Board is ledtermination by its Chairman, Mr. Greehey. Although the Board believes that separating the roles of Chairman and Chief Executive Officer is appropriateSunoco in the current circumstances,event of an adverse recommendation change by our Corporate Governance Guidelines do not establish this approach asBoard of Directors or by NuStar Energy to accept a policy. The Board also has appointed Mr. Hill as its presiding directorSuperior Proposal (as defined in the Merger Agreement), NuStar Energy would be required to serve aspay Sunoco a pointtermination fee of contact for unitholders wishing to communicateapproximately $90.3 million.

Concurrently with the Boardentry into the Merger Agreement, NuStar Energy and to lead executive sessionsSunoco entered into an agreement (the Support Agreement) with Energy Transfer LP (Energy Transfer), a Delaware limited partnership and the sole member of the non-management directors.
Mr. Greehey became ChairmanSunoco GP. The Support Agreement provides, among other things, that Energy Transfer will not transfer its ownership interest in the Sunoco GP, any of the Board in January 2002. He also has been the ChairmanSunoco incentive distribution rights owned by it or any material portion of the board of directors of NuStar GP Holdings since March 2006. Mr. Greehey served as ChairmanSunoco common units owned by it prior to the Effective Time. Energy Transfer has also agreed to be bound by the terms of the board of directors of Valero Energy Corporation (Valero Energy) from 1979 through January 2007. Mr. Greehey was Chief Executive Officer of Valero Energy from 1979 through December 2005, and President of Valero Energy from 1998 until January 2003.
Mr. Barron became President, Chief Executive Officer and a director of NuStar GP, LLC and NuStar GP Holdingsnon-solicitation provisions in January 2014. He served as Executive Vice President and General Counsel of NuStar GP, LLC and NuStar GP Holdings from February 2012 until his promotion in January 2014. From April 2007 to February 2012, he served as Senior Vice President and General Counsel of NuStar GP, LLC and NuStar GP Holdings. Mr. Barron also served as Secretary of NuStar GP, LLC and NuStar GP Holdings from April 2007 to February 2009. He served as Vice President, General Counsel and Secretary of NuStar GP, LLC from January 2006 until April 2007 and as Vice President, General Counsel and Secretary of NuStar GP Holdings from March 2006 until his promotion in April 2007. He has been with NuStar GP, LLC since July 2003 and, prior to that, was with Valero Energy from January 2001 to July 2003.
Mr. Bates became a director of NuStar GP, LLC in April 2006. He served as President and CEO of the Southwest Research Institute from 1997 until October 2014 and continues to serve as a director and as President Emeritus of the Southwest Research Institute. Mr. Bates also serves as a director of Signature Science L.L.C., Broadway Bank and Broadway Bankshares, Inc. He served as Chairman or Vice Chairman of the board of directors of the Federal Reserve Bank of Dallas’ San Antonio Branch from January 2005 through December 2009.
Mr. Hill became a director of NuStar GP, LLC in July 2004. From February 2001 through May 2004, he served as a consultant to El Paso Corporation. Prior to that, he served as President and CEO of Coastal Refining and Marketing Company. In 1978, Mr. Hill was named as Senior Vice President of the Coastal Corporation and President of Coastal States Crude Gathering. In 1971, he began managing Coastal’s NGL business. Previously, Mr. Hill worked for Amoco and Mobil.
Mr. Munch became a director of NuStar GP, LLC in January 2016. He served as General Manager and Head of Corporate & Investment Banking of Mizuho Bank, Ltd. from 2006 to 2013 and as Deputy General Manager, Origination, of Mizuho Bank, Ltd. from 2005 to 2006. Prior to his service with Mizuho Bank Ltd., Mr. Munch also served in several senior management positions with Canadian Imperial Bank of Commerce and CIBC World Markets from 1980 to 2001 and Fidelity Union Bancorporation (now Wells Fargo) from 1973 to 1980.
Mr. Rosier became a director of NuStar GP, LLC in March 2013. He has been the President and Chief Executive Officer of McLane Company, Inc., a leading supply chain services company and subsidiary of Berkshire Hathaway, Inc., since February 1995. Mr. Rosier has been with McLane Company, Inc. since 1984, serving in various senior management positions prior to his current position. Mr. Rosier also has served as a director of NVR, Inc. since December 2008. He was formerly a director of Tandy Brands Accessories, Inc. from February 2006 to October 2011, serving as the lead director from October 2009 to October 2010.
Ms. Brown became Executive Vice President and Chief Administrative Officer of NuStar GP, LLC and NuStar GP Holdings in April 2013. She served as Executive Vice President - Administration of NuStar GP, LLC and NuStar GP Holdings from February 2012 until her promotion in April 2013. Ms. Brown served as Senior Vice President - Administration of NuStar GP, LLC from April 2008 through February 2012. She served as Senior Vice President - Corporate Communications of NuStar GP, LLC from April 2007 through April 2008. Prior to her service to NuStar GP, LLC, Ms. Brown served as Senior Vice President - Corporate Communications for Valero Energy from September 1997 to April 2007.
Mr. Shoaf became Executive Vice President and Chief Financial Officer of NuStar GP, LLC and NuStar GP Holdings in January 2014. He served as Senior Vice President and Controller of NuStar GP, LLC and NuStar GP Holdings from February 2012 until his promotion in January 2014. Mr. Shoaf served as Vice President and Controller of NuStar GP, LLC from July 2005 to February 2012 and Vice President and Controller of NuStar GP Holdings from March 2006 until February 2012. He served as Vice President - Structured Finance for Valero Corporate Services Company, a subsidiary of Valero Energy, from 2001 until joining NuStar GP, LLC.

Mr. del Alamo became Senior Vice President and Controller of NuStar GP, LLC and NuStar GP Holdings in July 2014. Prior thereto, he served as Vice President and Controller of NuStar GP, LLC and NuStar GP Holdings since January 2014. He served as Vice President and Assistant Controller of NuStar GP, LLC from July 2010 until his promotion in January 2014. From April 2008 to July 2010 he served as Assistant Controller of NuStar GP, LLC. Prior to his service at NuStar GP, LLC, Mr. del Alamo served as Director-Sarbanes Oxley Compliance for Valero Energy.
Mr. Oliver became Senior Vice President - Marketing and Business Development of NuStar GP, LLC and NuStar GP Holdings in May 2014. Prior thereto, he served as Senior Vice President - Business and Corporate Development of NuStar GP, LLC and NuStar GP Holdings since March 2011. He served as Senior Vice President - Marketing and Business Development of NuStar GP, LLC and NuStar GP Holdings from May 2010 to March 2011 and as Vice President - Marketing and Business Development of NuStar GP, LLC from October 2008 until May 2010 and of NuStar GP Holdings from December 2009 until May 2010. Prior to that, Mr. Oliver served as Vice President for NuStar Marketing LLC. Previously, Mr. Oliver served as Vice President - Product Supply & Distribution for Valero Energy from May 1997 to July 2007.
Ms. Perry became Senior Vice President, General Counsel-Corporate & Commercial Law and Corporate Secretary of NuStar GP, LLC and NuStar GP Holdings in January 2014. She served as Vice President, Assistant General Counsel and Corporate Secretary of NuStar GP, LLC and as Corporate Secretary of NuStar GP Holdings from February 2010 until her promotion in January 2014. From June 2005 to February 2010 she served as Assistant General Counsel and Assistant Secretary of NuStar GP, LLC and, from March 2006 to February 2010, Assistant Secretary of NuStar GP Holdings. Prior to her service at NuStar GP, LLC, Ms. Perry served as Counsel to Valero Energy.
Ms. Thompson became Senior Vice President, General Counsel-Litigation, Regulatory & Environmental of NuStar GP, LLC and NuStar GP Holdings in January 2014. She served as Vice President, Assistant General Counsel and Assistant Secretary of NuStar GP, LLC from February 2010 until her promotion in January 2014. From May 2007 to February 2010 she served as Assistant General Counsel and Assistant Secretary of NuStar GP, LLC. Prior to her service at NuStar GP, LLC, Ms. Thompson served as Managing Counsel to Valero Energy.
Mr. Truby became Senior Vice President - Operations of NuStar GP, LLC in February 2013 and of NuStar GP Holdings in November 2015. Prior thereto, he served as Vice President - Pipeline Operations of NuStar GP, LLC since April 2012 and as Vice President - Health, Safety and Environmental of NuStar GP, LLC from January 2012 until April 2012. Previously he served as Vice President and General Manager of NuStar GP, LLC’s former San Antonio Refinery from May 2011 until January 2012 and led NuStar GP, LLC’s East Region from November 2009 until May 2011.

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Exchange Act requires directors, executive officers and persons who beneficially own more than 10% of NuStar Energy’s equity securities to file certain reports with the Securities and Exchange Commission (SEC) concerning their beneficial ownership of NuStar Energy’s equity securities. We believe that our directors, executive officers and greater than 10% unitholders have filed all Section 16(a) reports by the applicable deadlinesMerger Agreement with respect to competing proposals for Sunoco and the year ended December 31, 2017.Sunoco GP and to abide by certain covenants with respect to regulatory approvals, SEC filings, confidentiality and litigation, among other things.


CODE OF ETHICS OF SENIORThe foregoing descriptions of the Merger Agreement and the Support Agreement and the transactions contemplated thereby, including the Merger, are summaries, do not purport to be complete and are qualified in their entirety by reference to the full text of the Merger Agreement and the Support Agreement.
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ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL OFFICERSDISCLOSURE
NuStar GP, LLCNone.
ITEM 9A.CONTROLS AND PROCEDURES
DISCLOSURE CONTROLS AND PROCEDURES
Our management has adopted a Codeevaluated, with the participation of Ethics for Senior Financial Officers that applies to NuStar GP, LLC’sthe principal executive officer and principal financial officer and controller. A copy of the code is available on NuStar Energy’s website at www.nustarenergy.com. This code charges the senior financial officers with responsibilities regarding honest and ethical conduct, the preparation and quality of the disclosures in documents and reports we file with or submit to the SEC, compliance with applicable laws, rules and regulations, adherence to the code and reporting of violations of the code. We also have a Code of Business Conduct and Ethics that applies to all of our employees and directors.


CORPORATE GOVERNANCE
AUDIT COMMITTEE
The Audit Committee reviews and reports to the Board on various auditing and accounting matters, including the quality, objectivity and performance of NuStar Energy’s internal and external accountants and auditors, the adequacy of its financial controls and the reliability of financial information reported to the public. The Audit Committee also monitors NuStar Energy’s compliance with environmental laws and regulations. The Board has adopted a written charter for the Audit Committee, a copy of which is available on NuStar Energy’s website at www.nustarenergy.com. The members of the Audit Committee are Mr. Bates (Chairman), Mr. Hill, Mr. Munch and Mr. Rosier. The Board has determined that Mr. Bates is an “audit committee financial expert” (as defined by the SEC), and that each member of the Audit Committee is “independent” as that term is used in the NYSE Listing Standards and described below in Item 13. The Audit Committee met eight times during 2017. For further information, see the Audit Committee Report below.
AUDIT COMMITTEE REPORT
Management of NuStar GP, LLC is responsible for NuStar Energy’s internal controls and the financial reporting process. KPMG LLP (KPMG), NuStar Energy’s independent registered public accounting firm for the year ended December 31, 2017, is responsible for performing an independent audit of NuStar Energy’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (PCAOB) and generally accepted auditing standards, and an audit of NuStar Energy’s internal control over financial reporting in accordance with the standards of the PCAOB, and issuing a report thereon. The Audit Committee monitors and oversees these processes and approves the selection and appointment of NuStar Energy’s independent registered public accounting firm and recommends the ratification of such selection and appointment to the Board.
The Audit Committee has reviewed and discussed NuStar Energy’s audited consolidated financial statements with management and KPMG. The Audit Committee has discussed with KPMG the matters required to be discussed by Auditing Standard 1301, “Communications with Audit Committees,” issued by the PCAOB. The Audit Committee has received written disclosures and the letter from KPMG required by applicable requirements of the PCAOB concerning independence and has discussed with KPMG its independence.
Based on the foregoing review and discussions and such other matters the Audit Committee deemed relevant and appropriate, the Audit Committee recommended to the Board that the audited consolidated financial statements of NuStar Energy be included in NuStar Energy’s Annual Report on Form 10-K for the year ended December 31, 2017.
Members of the Audit Committee:

J. Dan Bates (Chairman)
Dan J. Hill
Robert J. Munch
W. Grady Rosier


RISK OVERSIGHT
Although it is the job of management to assess and manage our risk, the Board of Directors and its Audit Committee (each where applicable) discuss the guidelines and policies that govern the process by which risk assessment and management is undertaken and evaluate reports from various functions with the management team on risk assessment and management. The Board interfaces regularly with management and receives periodic reports that include updates on operational, financial, legal and risk management matters. The Audit Committee assists the Board in oversight of the integrity of NuStar Energy’s financial statements and NuStar Energy’s compliance with legal and regulatory requirements, including those related to the health, safety and environmental performance of our company. The Audit Committee also reviews and assesses the performance of NuStar Energy’s internal audit function and its independent auditors. The Board receives regular reports from the Audit Committee. For a description of our oversight and evaluation of compensation risk, see “Evaluation of Compensation Risk” in Item 11 below.


ITEM 11.    EXECUTIVE COMPENSATION
COMPENSATION COMMITTEE
The Compensation Committee reviews and reports to the Board on matters related to compensation strategies, policies and programs, including certain personnel policies and policy controls, management development, management succession and benefit programs. The Compensation Committee also conducts periodic reviews of director compensation and makes recommendations to the Board regarding director compensation. The Compensation Committee also approves and administers NuStar Energy’s equity compensation plans and incentive bonus plan. The Board has adopted a written charter for the Compensation Committee, a copy of which is available on NuStar Energy’s website at www.nustarenergy.com. The members of the Compensation Committee are Mr. Hill (Chairman), Mr. Bates, Mr. Munch and Mr. Rosier, none of whom is a current or former employee or officer of NuStar GP, LLC, the effectiveness of our disclosure controls and eachprocedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of whom has been determined by the Board to be “independent,”1934, as described below in Item 13. The Compensation Committee met four times during 2017.

COMPENSATION COMMITTEE REPORT
The Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis with management. Based on its review and discussion and such other matters the Compensation Committee deemed relevant and appropriate, the Compensation Committee recommended to the Board that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.
Membersamended) as of the Compensation Committee:
Dan J. Hill (Chairman)
J. Dan Bates
Robert J. Munch
W. Grady Rosier
COMPENSATION DISCUSSION AND ANALYSIS
EXECUTIVE COMPENSATION PHILOSOPHY
Our philosophy for compensatingend of the period covered by this report, and has concluded that our named executive officers (NEOs) is based on the belief that a significant portiondisclosure controls and procedures were effective as of executive compensation should be incentive-based and determined by both the performance of NuStar Energy and the executive’s individual performance objectives. Our executive compensation programs are designed to accomplish the following long-term objectives:
increase value to unitholders, while practicing good corporate governance;
support our business strategy and business plan by clearly communicating what is expected of executives with respect to goals and results;
provide the Compensation Committee with the flexibility to respond to the continually changing environment in which NuStar Energy operates;
align executive incentive compensation with NuStar Energy’s short- and long-term performance results; and
provide market-competitive compensation and benefits to enable us to recruit, retain and motivate the executive talent necessary to produce sustainable growth for our unitholders.
Compensation for our NEOs primarily consists of base salary, an annual incentive bonus and long-term, equity-based incentives, which we refer to as “Total Direct Compensation.” Our NEOs participate in the same group benefit programs available to our salaried employees in the United States, and each NEO’s incentive bonus is awarded in accordance with the same bonus plan and metric that we use for each of our other employees. In addition, as discussed under “Post-Employment Benefits” below, our NEOs may participate in certain non-qualified, retirement-related programs. Our NEOs do not have employment or severance agreements, other than the change of control severance agreements described under “Potential Payments Upon Termination or Change of Control” in this Item 11. The Compensation Committee targets base salary for our NEOs, as well as annual incentive bonus and long-term incentive opportunities (expressed, in each case, as a percentage of base salary), with reference to prevailing practices of our peer companies and information from survey sources. In determining total compensation, as well as each component thereof, we consider the unique responsibilities of each individual’s position, as well as his or her experience and performance, together with the market information.

Our NEOs for the year ended December 31, 2017 were:2023.
Bradley C. Barron, President and Chief Executive Officer (CEO);
Thomas R. Shoaf, Executive Vice President and Chief Financial Officer;
Mary Rose Brown, Executive Vice President and Chief Administrative Officer;
Daniel S. Oliver, Senior Vice President-Marketing and Business Development; and
Michael Truby, Senior Vice President-Operations.
ADMINISTRATION OF EXECUTIVE COMPENSATION PROGRAMS
Our executive compensation programs are administered by our Board’s Compensation Committee. The Compensation Committee is composed of independent directors who are not participants in our executive compensation programs. Policies adopted by the Compensation Committee are implemented by our Human Resources department.
The Compensation Committee considers market trends in compensation, including the practices of identified competitors, and the alignment of the compensation program with NuStar Energy’s strategy. Specifically, for our NEOs, the Compensation Committee:
��establishes and approves target compensation levels for each NEO;
approves company performance measures and goals;
determines the mix between cash and equity compensation, short-term and long-term incentives and benefits;
verifies the achievement of previously established performance goals; and
approves the resulting cash or equity awards to our NEOs.
In making determinations about Total Direct Compensation for our NEOs, the Compensation Committee takes into account a number of factors, including:
the competitive market for talent;
compensation paid at peer companies;
industry-wide trends;
NuStar Energy’s performance;
the particular NEO’s role, responsibilities, experience and performance; and
retention.
The Compensation Committee also considers other equitable factors such as the role, contribution and performance of an individual relative to his or her peers at the company. The Compensation Committee does not assign specific weight to these factors, but rather makes a subjective judgment taking all of these factors into account.
During 2017, the Compensation Committee retained Energy Partners Pay Advisors (EPPA) as its independent compensation consultant for expertise and guidance with respect to executive compensation matters. In its role as advisor to the Compensation Committee, EPPA was retained directly by the Compensation Committee, which has the authority to select, retain and/or terminate its relationship with a consulting firm. The Compensation Committee determined that there are no conflicts of interest between the company, the Compensation Committee and EPPA because: EPPA provides no other services to NuStar Energy; EPPA has policies in place to prevent a conflict of interest, including a policy that no employee of EPPA may own NuStar Energy units; and there is no business or personal relationship between EPPA’s consultant and any of NuStar Energy’s officers or directors.
Selection of Compensation Comparative Data
To establish compensation for each of the NEOs, the Compensation Committee consults with management and EPPA and considers compensation provided by certain peer companies when evaluating competitive levels of compensation. The competitive data regarding the peer companies is derived from their respective publicly filed annual proxy statements or Annual Reports on Form 10-K.

Following the sale of our remaining 50% interest in the asphalt business during 2014, the Compensation Committee consulted with management and the Compensation Committee’s independent compensation consultant at the time, reevaluated our peer group and removed the independent refining companies that were previously included in our peer group (the 2014 Compensation Comparative Group). Since that time, several of the companies in the peer group have merged, consolidated or otherwise no longer publicly disclose comprehensive executive compensation information. Due to the changes in the midstream and logistics industry since 2014, the Compensation Committee consulted with management and EPPA and updated our peer group again in 2017 to: (1) remove entities that have been acquired or otherwise no longer publicly disclose comprehensive executive compensation information; (2) remove sponsored master limited partnerships (MLPs) for which the executives’ primary responsibility relates to the sponsor’s operations rather than the operations of the MLP; (3) add other comparable midstream and/or logistics entities; and (4) recognize the scope of responsibility of executive teams that manage two public companies, similar to NuStar Energy and NuStar GP Holdings (the Current Compensation Comparative Group).
The tables below list: (1) the companies in the 2014 Compensation Comparative Group after giving effect to all merger or consolidation transactions that closed prior to December 31, 2017 (with the relevant transactions described in the footnote); and (2) the companies in the Current Compensation Comparative Group.
2014 Compensation Comparative Group
Company (1)
Ticker
1. Andeavor Logistics LP (previously known as Tesoro Logistics LP)ANDX
2. Arc Logistics Partners LPARCX
3. Boardwalk Pipeline Partners, LPBWP
4. Buckeye Partners, L.P.BPL
5. Enable Midstream Partners, LPENBL
6. Enbridge Energy Partners, L.P.EEP
7. Energy Transfer Partners, L.P.ETP
8. EnLink Midstream Partners, LPENLK
9. Enterprise Products Partners L.P.EPD
10. Genesis Energy, L.P.GEL
11. Holly Energy Partners, L.P.HEP
12. Magellan Midstream Partners, L.P.MMP
13. MPLX LPMPLX
14. Phillips 66 Partners LPPSXP
15. Plains All American Pipeline, L.P.PAA
16. Valero Energy Partners LPVLP
(1) The following companies have been removed from the 2014 Compensation Comparative Group originally established in July 2014 as a result of the transactions described in this footnote: Access Midstream Partners, L.P. merged with Williams Partners L.P. in February 2015; Atlas Pipeline Partners, L.P. was acquired by Targa Resources Partners LP in February 2015; Kinder Morgan Energy Partners, L.P. was acquired by Kinder Morgan, Inc. in November 2014; MarkWest Energy Partners, L.P. was acquired by MPLX LP in December 2015; Regency Energy Partners LP was acquired by Energy Transfer Partners, L.P. in April 2015; Targa Resources Partners LP was acquired by Targa Resources Corp. in February 2016; Energy Transfer Partners, L.P. merged with Sunoco Logistics Partners L.P. in April 2017; and Western Refining Logistics, LP was acquired by Andeavor Logistics LP in October 2017.

Current Compensation Comparative Group
CompanyTicker
1. Boardwalk Pipeline Partners, LPBWP
2. Buckeye Partners, L.P.BPL
3. Calumet Specialty Products Partners, L.P.CLMT
4. Enable Midstream Partners, LPENBL
5. Enbridge Energy Partners, L.P./Enbridge Energy Management, L.L.C.EEP/EEQ
6. Energy Transfer Partners, L.P. /Energy Transfer Equity, L.P. (1)
ETP/ETE
7. EnLink Midstream Partners, LP/EnLink Midstream, LLCENLK/ENLC
8. Enterprise Products Partners L.P.EPD
9. Genesis Energy, L.P.GEL
10. Holly Energy Partners, L.P.HEP
11. Magellan Midstream Partners, L.P.MMP
12. MPLX LPMPLX
13. ONEOK, Inc. (includes operations of ONEOK Partners, L.P.)OKE
14. SemGroup CorporationSEMG
15. Sunoco Logistics Partners L.P. (1)
SXL
16. Targa Resources Corp. (includes operations of Targa Resources Partners LP)TRGP
(1)Although Energy Transfer Partners, L.P. and Sunoco Logistics Partners L.P. merged in April 2017, both entities are listed as separate peer companies in the Current Compensation Comparative Group because their executive compensation for the year ended December 31, 2016 was publicly disclosed separately and considered along with the compensation of the other peer companies as part of the evaluation of our 2017 compensation.
At the Compensation Committee’s request, EPPA also reviews survey data reported on a position-by-position basis to obtain additional information regarding compensation of comparable positions. The survey data consists of general industry data for specific executive positions reported in published executive compensation surveys. We refer to the competitive survey data, together with the 2014 Compensation Comparative Group data or the Current Compensation Comparative Group data, as applicable, as the “Compensation Comparative Data.”
Process and Timing of Compensation Decisions
The Compensation Committee reviews and approves all compensation of the NEOs. The CEO develops recommendations for the compensation of the other NEOs in consultation with our Human Resources department and with EPPA. In making these recommendations, the CEO considers the Compensation Comparative Data and evaluates the individual performance of each NEO and their respective contributions to NuStar Energy. The recommendations are then reviewed by the Compensation Committee, which may accept the recommendations or may make adjustments to the recommended compensation based on the Compensation Committee’s assessment of the individual’s performance and contributions to NuStar Energy.
As required by the Compensation Committee’s charter, the CEO’s compensation is reviewed and approved by the Compensation Committee based on the Compensation Comparative Data and the Compensation Committee’s independent evaluation of the CEO’s contributions to NuStar Energy’s performance.
Each July, the Compensation Committee reviews each NEO’s Total Direct Compensation, including base salary and the target levels of annual incentive and long-term incentive compensation. The review includes a comparison with competitive market data provided by EPPA (as described above), an evaluation of the Total Direct Compensation of the NEOs from an internal equity perspective and a review of reports on the compensation history of each NEO. Based on these reviews and evaluations, the Compensation Committee establishes annual salary rates for each NEO for the upcoming 12-month period and sets target levels of annual incentive and long-term incentive compensation. Although the target levels are established in July, the long-term incentives are reviewed again at the time of grant, typically in the fourth quarter for restricted units and in the first quarter for performance units. The Compensation Committee also may review salaries or grant long-term incentive awards at other times during the year because of new appointments, promotions or other extraordinary circumstances.

The following table summarizes the typical timing of some of our significant compensation events.
EventTiming
- Establish financial performance objectives for the current year’s annual incentive bonus
- Evaluate achievement of the bonus metric for the prior year
- Review prior year financial performance for performance units
- Grant performance units for the current year
First quarter
- Review NEO base salaries and targets for annual incentive bonus and long-term incentive grants for the current yearThird quarter
- Grant restricted units to employees, including the NEOs
- Grant restricted units to non-employee directors pursuant to the director compensation program
- Set meeting dates for action by the Compensation Committee for the upcoming year
Fourth quarter
Additional information regarding the timing of the 2017 long-term incentive grants is discussed below under “Restricted Units” and “Performance Units.”
ELEMENTS OF EXECUTIVE COMPENSATION
Compensation for our NEOs primarily consists of the following elements, which we refer to as Total Direct Compensation:
ElementFormPurpose
FixedBase SalaryCash
- Foundation of the executive compensation program
- Provides a fixed level of competitive pay
- Reflects the individual’s primary duties and responsibilities
- Foundation for incentive opportunities and benefit levels
At-RiskAnnual Incentive BonusCash- Focus NEOs on improving performance
At-RiskLong-Term Equity-Based Incentives:Units- Directly tie NEO financial reward opportunities with the rewards to unitholders, as measured by long-term unit price performance and payment of distributions
- Restricted Units- Time-vesting award focused on retention and increasing ownership levels
- Performance Units- Performance-vesting award focused on attainment of objective performance measure
We also offer group medical and other insurance benefits to provide our employees (including our NEOs) affordable coverage at group rates, as well as pension benefits that reward continued service and a thrift plan that provides a tax-advantaged savings opportunity.
Relative Size of Primary Elements of Compensation
In setting compensation, the Compensation Committee considers the aggregate amount of compensation payable to each NEO and the form of the compensation. The Compensation Committee seeks to achieve the appropriate balance between salary, cash rewards earned for the achievement of company and personal objectives, and long-term incentives that align the interests of our NEOs with those of our unitholders. The size of each element is based on competitive market practices, as well as company and individual performance.
As illustrated by the chart below, the level of at-risk incentive compensation typically increases in relation to an NEO’s responsibilities, with the level of incentive compensation for more senior executive officers being a greater percentage of Total Direct Compensation than for less senior executives. The Compensation Committee believes that tying a significant portion of an NEO’s incentive compensation to NuStar Energy’s performance more closely aligns the NEO’s interests with those of our unitholders.

Because we place such a large percentage of our Total Direct Compensation at risk in the form of variable pay (i.e., annual and long-term incentives), the Compensation Committee does not adjust current compensation based upon realized gains or losses from prior incentive awards. For example, we will not reduce the size of a target long-term incentive grant in a particular year solely because NuStar Energy’s unit price performed well during the immediately preceding years. We believe that adopting a policy of making such adjustments would penalize management’s current compensation for NuStar Energy’s prior success.

Individual Performance and Personal Objectives
The Compensation Committee evaluates our NEOs’ individual performance and personal objectives with input from our CEO. Our CEO’s performance is evaluated by the Compensation Committee in consultation with other members of the Board.
Assessment of individual performance may include objective criteria, but is a largely subjective process. The criteria used to measure an individual’s performance may include use of quantitative criteria (e.g., execution of projects within budget, improving an operating unit’s profitability, or timely completion of an acquisition or divestiture), as well as more qualitative factors, such as the NEO’s ability to lead, communicate and successfully adhere to NuStar Energy’s core values (i.e., environmental and workplace safety, integrity, work commitment, effective communication and teamwork). There are no specific weights given to any of these various elements of individual performance.
The Compensation Committee uses its evaluation of individual performance to supplement the objective compensation criteria and adjust an NEO’s recommended compensation. For example, although an individual’s indicated bonus may be calculated to be $100,000 based on NuStar Energy’s performance, the individual’s performance evaluation might result in a reduction or increase in that amount.
Base Salaries
The Compensation Committee reviews the base salaries for our NEOs annually based on recommendations by our CEO, with input from EPPA and our Human Resources department. Our CEO’s base salary is reviewed and approved by the Compensation Committee based on its review of recommendations by EPPA, our Chairman and our Human Resources department.
The competitiveness of base salaries for each NEO’s position is determined by an evaluation of the Compensation Comparative Data described above. Base salaries may be adjusted to achieve what is determined to be a reasonably competitive level or to reflect promotions, the assignment of additional responsibilities, individual performance or the performance of NuStar Energy.

Following a detailed analysis performed in July 2014 by the Compensation Committee’s independent compensation consultant at the time, for 2015 and 2016 base salaries the Compensation Committee considered, among other factors, the Consumer Price Index, the average base salary increase anticipated by nationwide compensation surveys, the increases required by NuStar Energy’s union contracts and the anticipated increases by other local companies and raised the base salaries of each of the NEOs effective on each of July 1, 2015 and July 1, 2016 to remain competitive.

During July 2017, EPPA performed a comprehensive review of our NEOs’ Total Direct Compensation. After consultation with EPPA, the Chairman (in the case of the CEO’s base salary) and the CEO (in the case of the base salaries for each other NEO), the Compensation Committee raised the base salaries of each of the NEOs effective July 1, 2017 to remain competitive. The July 1, 2017 increases and the December 31, 2017 base salaries for each of the NEOs are presented in the table below.

Name
Annualized Base Salary at
December 31, 2017 ($)
July 1, 2017 Increase to Prior Annualized Salary ($)
Barron592,250
  17,250
  
Shoaf360,200
  10,500
  
Brown388,000
  11,300
  
Oliver328,000
  9,700
  
Truby305,000
  24,400
  
Annual Incentive Bonus
Our NEOs participate in the same annual incentive program in which all of our domestic employees participate. Under our annual bonus plan, participants can earn annual incentive bonuses based on the following three factors:
The individual’s position, which is used to determine a targeted percentage of annual base salary that may be awarded as incentive bonus. Generally, the target amount for the NEOs is set following the analysis of market practices in the Compensation Comparative Group with reference to the median bonus target available to comparable executives in those companies;
NuStar Energy’s attainment of specific quantitative financial goals, which are established by the Compensation Committee during the first quarter of the year; and
A discretionary evaluation by the Compensation Committee of both NuStar Energy’s performance and, in the case of the NEOs, the individual’s performance.
In July 2015, after consultation with the Compensation Committee’s independent compensation consultant at the time and the Chairman, the Compensation Committee raised the annual incentive bonus target for Mr. Barron from 90% to 100%. The Compensation Committee did not make any changes to the annual incentive bonus target for Mr. Barron during 2016 or for any of the other NEOs serving as such during 2015 or 2016. In July 2017, following EPPA’s comprehensive review of our NEOs’ Total Direct Compensation, the Compensation Committee raised the annual incentive bonus target for Mr. Truby from 50% to 55% and retained the existing annual incentive bonus targets for all other NEOs. The following table shows each NEO’s annual incentive bonus target for the fiscal year ended December 31, 2017 (expressed as a percent of base salary paid).
Name
Annual Incentive Bonus Target
(% of base salary)
Barron100
Shoaf60
Brown60
Oliver55
Truby55
Determination of Annual Incentive Target Opportunities
As illustrated in the table above, each NEO has an annual incentive opportunity generally based on a stated percentage of his or her salary paid that year. The target amount is awarded for achieving a 100% score on our stated financial goal under the annual bonus plan. For example, in a year with a 100% score, an NEO paid $200,000 with a target annual incentive opportunity equal to 60% of his base salary paid would be eligible to receive a bonus of $120,000 based on those financial goals.

Once the financial goals have been reviewed and measured, the Compensation Committee has the authority to exercise its discretion in evaluating NuStar Energy’s performance. In exercising this discretionary judgment, the Compensation Committee considers such relevant performance factors as growth, attainment of strategic objectives, acquisitions and divestitures, safety and environmental compliance, as well as other considerations. This discretionary judgment may result in an increase or decrease to the aggregate earned award for all employees that is based upon the attainment of NuStar Energy’s financial goals.
The CEO develops individual incentive bonus recommendations for the other NEOs based upon the methodology described above. In addition, both the CEO and the Compensation Committee may make adjustments to the recommended incentive bonus amounts based upon an assessment of an individual’s performance and contributions to NuStar Energy. The CEO and the Compensation Committee also review and discuss each NEO’s bonus on a case-by-case basis, considering such factors as teamwork, leadership, individual accomplishments and initiative, and may adjust the bonus awarded to a specific NEO to reflect these factors.
The bonus target for the CEO is decided solely by the Compensation Committee, and the Compensation Committee may make discretionary adjustments to the calculated level of bonus for the CEO based upon its independent evaluation of the CEO’s performance and contributions.
Company Performance Objectives
As in prior years, our annual incentive bonus for 2017 was designed to focus our NEOs on improving NuStar Energy’s distributable cash flow (DCF). In the MLP investment community, DCF is widely regarded as a significant indicator of operating performance. As such, the Compensation Committee believes the measure appropriately aligns our management’s interest with our unitholders’ interest.
For 2017, the Compensation Committee determined that a bonus pool for all employees would be established based on DCF such that employees would receive a 100% bonus for 2017 if NuStar Energy achieved a target distribution coverage ratio (DCR) of 1.01 times. After achieving a 100% bonus, incremental DCF earned would be shared between the bonus pool and NuStar Energy until employees achieve a 200% bonus. If DCR for 2017 is below 1.00 times, the bonus pool would be reduced dollar-for-dollar until a 1.00 times DCR is achieved or the pool is reduced to $0. The Compensation Committee has discretion to raise or lower the incentive opportunity resulting from this calculation by 25%. In addition, the budgeted DCF may be adjusted during the year in order to account for acquisitions or other significant changes not anticipated at the time the target was determined.
DCF and DCR are non-GAAP measures of performance. We derive DCF from our financial statements by adjusting our net income for depreciation and amortization expense, unrealized gains and losses arising from certain derivative contracts and other non-cash items, including non-cash gains or losses or impairment charges. We further adjust our earnings by (1) subtracting our aggregate annual reliability capital expenditures, (2) adding non-cash unit-based compensation expenses for awards that we intend to satisfy with the issuance of units upon vesting and (3) adding or subtracting, as applicable, certain cash receipts and disbursements not included in net income. DCR is determined by dividing DCF applicable to common limited partners by the distributions applicable to common limited partners.
Determination of Awards
Our executive officers, including our NEOs, did not receive cash bonuses for 2017. For the 2017 annual incentive bonus determination, the Compensation Committee reviewed NuStar Energy’s DCF against the established target of attaining a DCR of 1.01 times and considered NuStar Energy’s overall performance and the performance of each NEO. Based solely on our 2017 DCR results, our NEOs were not eligible to receive a bonus award for 2017 under the annual incentive bonus plan. The Compensation Committee recognized NuStar Energy’s significant accomplishments during 2017, including the successful acquisition of the Permian Crude System and NuStar Energy’s achievement of its best safety record in the history of the company, with only one employee recordable injury and zero lost-time injuries. The Compensation Committee also considered the strain on the business and the MLP sector generally from continued low crude oil prices and the further negative impact on NuStar Energy of several unexpected items, such as losses at seven facilities impacted by five hurricanes, losses resulting from unplanned turnarounds and downtime at customers’ refineries, a decline in results at our St. Eustatius terminal from under-utilization by an important customer there due to deteriorating conditions in Venezuela and the expense of an unanticipated reliability project on our Ammonia Pipeline.
After considering our 2017 DCR results and these additional factors, upon the recommendation of executive management (other than with respect to the CEO) and our Chairman (with respect to the CEO), the Compensation Committee decided not to award cash bonuses under the annual incentive bonus plan for any of our executive officers, including our NEOs, for 2017.

Long-Term Incentive Awards
We provide unit-based, long-term incentive compensation for employees, including our NEOs, and for our non-employee directors through our 2000 Long-Term Incentive Plan (as amended and restated from time to time, the 2000 LTIP). The 2000 LTIP provides for unit awards and a variety of unit-based awards, including unit options, restricted units and performance units. Long-term incentive awards vest over a period determined by the Compensation Committee, with performance units vesting upon the achievement of an objective performance goal.
Under the design of our long-term incentive awards, a target long-term incentive award opportunity expressed as a percentage of base salary is established for each plan participant, including each NEO. This percentage reflects the fair value of the awards to be granted.
The Compensation Committee did not make any changes to the individual long-term incentive target percentages for our NEOs serving as such during 2015 or 2016. In July 2017, following EPPA’s comprehensive review of our NEOs’ Total Direct Compensation, the Compensation Committee raised the long-term incentive targets for Mr. Barron from 200% to 250%, for Mr. Shoaf and Ms. Brown from 150% to 180% and for Mr. Truby from 100% to 125%, and retained the existing target for Mr. Oliver. The following table shows each NEO’s long-term incentive target for 2017 (expressed as a percent of base salary).
Name
Long-Term Incentive Target
(% of base salary)
Barron250
Shoaf180
Brown180
Oliver125
Truby125
The Compensation Committee allocates a percentage of long-term incentive award value to performance-based awards and a percentage to awards that focus on retention and increasing ownership levels of executive officers (including our NEOs). Since the fourth quarter of 2011, the target levels of long-term incentive award value have been allocated in the following manner:
35% performance units; and
65% restricted units.
The Compensation Committee reviews and approves long-term incentive grants for each of the NEOs. The CEO develops individual grant recommendations for the other NEOs based upon the methodology described above, but both the CEO and the Compensation Committee may make adjustments to the recommended grants based upon an assessment of an individual’s performance and contributions to NuStar Energy. Grants to the CEO are decided solely by the Compensation Committee following the methodology described above, and the Compensation Committee may make discretionary adjustments to the calculated level of long-term incentives for the CEO based upon its independent evaluation of the CEO’s performance and contributions.
Restricted Units
Restricted units comprise approximately 65% of each NEO’s total NuStar Energy long-term incentive target. The Compensation Committee expects to grant restricted units on an annual basis. In 2017, the NEOs’ long-term incentive targets included approximately 70% NuStar Energy restricted units to be granted by the Compensation Committee under the 2000 LTIP and 30% NuStar GP Holdings phantom units (which we refer to as “restricted units” in Part III of this Annual Report on Form 10-K) to be granted by NuStar GP Holdings’ compensation committee under its long-term incentive plan. In both cases, no units are issued at the time of grant and the awards represent the right to receive common units upon vesting. The awards are calculated from an assumed unit value based on the average closing price of the common units for the first 10 business days of the month prior to the committee meeting at which the awards are to be approved. The restricted units all vest over five years in equal increments on the anniversary of the grant date, and common unit distribution equivalents are paid in cash quarterly for all unvested NuStar Energy and NuStar GP Holdings restricted units. Restricted units of NuStar GP Holdings were introduced into the compensation program in 2008 to reflect the fact that the performance of NuStar GP Holdings is directly tied to the performance of NuStar Energy since NuStar GP Holdings’ sole asset is its interest in NuStar Energy. As described under “Accounting Treatment” below, effective March 1, 2016, NuStar GP Holdings retains the expense associated with the NuStar GP Holdings restricted unit awards.

The annual grants of NuStar GP Holdings restricted units, as well as the annual grants of NuStar Energy restricted units, were approved in a joint meeting of the Compensation Committee and the compensation committee of NuStar GP Holdings’ board of directors on October 18, 2017. The committees determined that the grants would be made as soon as administratively practicable and no earlier than the third business day following our third quarter earnings release. Due to the time required to award and implement the grants, the 2017 annual grants were not effective until November 16, 2017. The following table sets forth the restricted units granted to each of our NEOs in 2017.
Name
 Restricted Units Granted in 2017
NuStar EnergyNuStar GP Holdings
Barron16,66013,315
Shoaf7,2955,830
Brown7,8606,280
Oliver4,6153,690
Truby4,2903,430
For more information regarding the 2017 restricted unit grants, see the table entitled “Grants of Plan-Based Awards During the Year Ended December 31, 2017.”
Performance Units
Performance units comprise approximately 35% of each NEO’s total NuStar Energy long-term incentive target and typically have been awarded in the first quarter of each year. The number of performance units awarded is determined by multiplying the annual base salary rate by the NEO’s long-term incentive target percentage, and then multiplying that product by 35%. That product is divided by the assumed value of an individual unit, which is the product of (x) the average common unit price for the period of December 15 through December 31 (using the daily closing prices) and (y) a factor reflecting the risk that the award might be forfeited.
Performance units are earned only upon NuStar Energy’s achievement of an objective performance measure for the performance period. The Compensation Committee believes this type of incentive award strengthens the tie between each NEO’s pay and our financial performance.
Since 2014, the target performance measure for performance unit awards has been NuStar Energy achieving a specific DCR, after taking into account the aggregate expense of the performance units. As described above, the Compensation Committee believes that distribution coverage appropriately aligns our NEOs’ interest with our unitholders’ interest.

Performance units are awarded pursuant to the 2000 LTIP, with each award subject to vesting in three annual increments (or tranches), based upon our DCR during the one-year performance periods that end on December 31 of each year following the date of grant, as illustrated in the table below.

Annual Performance Target
2015 Target=
DCR 1.01 : 1
2016 Target=
DCR 1.03 : 1
2017 Target=
DCR 1.01 : 1
2015 Award Tranche Eligible to Vest1st2nd3rd
2016 Award Tranche Eligible to VestN/A1st2nd
2017 Award Tranche Eligible to VestN/AN/A1st
Performance Achieved for One-Year Performance Period1.11 : 11.07 : 10.63 : 1
Percent of Eligible Units Vested for One-Year Performance Period200%150%0%

If the DCR falls between the benchmarks established by the Compensation Committee for the performance period, the percentage vesting with respect to performance during that period will be determined through straight-line interpolation. The Compensation Committee retains the full discretion to vest up to 200% of performance units available for vesting, regardless of the DCR that NuStar Energy attains for the applicable performance period. As illustrated in the table above, performance units did not vest with respect to 2017 performance and vested at the 150% and 200% levels with respect to 2016 and 2015 performance, respectively. Additional information is provided below regarding the performance targets established by the Compensation Committee and the performance attained by NuStar Energy for each of the 2015, 2016 and 2017 performance periods.

2015 Performance Period. The target measure established by the Compensation Committee on January 29, 2015 for performance unit vesting with respect to 2015 performance was NuStar Energy achieving a DCR of 1.01:1, with all units eligible for vesting as follows based on the DCR for 2015:
LevelDCR% Performance Units Earned
Below ThresholdBelow 1.00 : 10%
Threshold1.00 : 190%
Target1.01 : 1100%
Exceeds Target1.05 : 1150%
Maximum1.10 : 1200%

On January 28, 2016, the Compensation Committee determined that NuStar Energy achieved a DCR of 1.11:1 for 2015 and, in accordance with the award terms, the performance units available to vest under the applicable tranche for each of the 2014 awards and 2015 awards with respect to 2015 performance vested at 200%.

2016 Performance Period. The target measure established by the Compensation Committee on February 24, 2016 for performance unit vesting with respect to 2016 performance was NuStar Energy achieving a DCR of 1.03:1, with all units eligible for vesting as follows based on the DCR for 2016:
LevelDCR% Performance Units Earned
Below ThresholdBelow 1.00 : 10%
Threshold1.00 : 190%
Target1.03 : 1100%
Exceeds Target1.07 : 1150%
Maximum1.12 : 1200%
On January 26, 2017, the Compensation Committee determined that NuStar Energy achieved a DCR of 1.07:1 for 2016 and, in accordance with the award terms, the performance units available to vest under the applicable tranche for each of the 2014 awards, 2015 awards and 2016 awards with respect to 2016 performance vested at 150%.

2017 Performance Period. On February 23, 2017, the Compensation Committee awarded the target number of performance units set forth below to our NEOs:
Name
Performance Units Awarded in 2017
Barron11,000
Shoaf4,776
Brown5,145
Oliver3,624
Truby2,556

The target measure established by the Compensation Committee on February 23, 2017 for performance unit vesting with respect to 2017 performance was NuStar Energy achieving a DCR of 1.01:1, with all units eligible for vesting as follows based on the DCR for 2017:
LevelDCR% Performance Units Earned
Below ThresholdBelow 1.00 : 10%
Threshold1.00 : 190%
Target1.01 : 1100%
Exceeds Target1.05 : 1150%
Maximum1.10 : 1200%
On January 25, 2018, the Compensation Committee determined that NuStar Energy achieved a DCR of 0.63:1 for 2017 and, in accordance with the award terms, the performance units available to vest under the applicable tranche for each of the 2015 awards, 2016 awards and 2017 awards with respect to 2017 performance did not vest. See the table entitled “Grants of Plan-Based Awards During the Year Ended December 31, 2017” for the performance units that did not vest with respect to the 2017 performance period.

Perquisites and Other Benefits
Perquisites
We provide only minimal perquisites to our NEOs. Each of our NEOs received federal income tax preparation services and personal liability insurance in 2017. For more information on perquisites, see the Summary Compensation Table and its footnotes.
Other Benefits
We provide other benefits, including medical, life, dental and disability insurance in line with competitive market practices. Our NEOs are eligible for the same benefit plans provided to our other employees, including our pension plans, 401(k) thrift plan (the Thrift Plan), and insurance and supplemental plans chosen and paid for by employees who desire additional coverage. Our NEOs and other employees whose compensation exceeds certain limits are eligible to participate in non-qualified excess benefit programs whereby those individuals can choose to make larger contributions than allowed under the qualified plan rules and receive correspondingly higher benefits. These plans are described below under “Post-Employment Benefits.”
Post-Employment Benefits
Pension Plans
For a discussion of our Pension Plan, as well as the Excess Pension Plan, please see the narrative description accompanying the table entitled “Pension Benefits for the Year Ended December 31, 2017.”
Nonqualified Deferred Compensation Plan (Excess Thrift Plan)
The Excess Thrift Plan provides unfunded benefits to those employees whose annual additions under the Thrift Plan are subject to the limitations under §415 of the Internal Revenue Code of 1986, as amended (the Code), and/or who are constrained from making maximum contributions under the Thrift Plan by §401(a)(17) of the Code, which limits the amount of an employee’s annual compensation that may be taken into account under that plan. The Excess Thrift Plan is comprised of two separate components, consisting of (1) an “excess benefit plan” as defined under §3(36) of The Employee Retirement Income Security Act of 1974, as amended (ERISA), and (2) a plan that is maintained primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees. Each component of the Excess Thrift Plan consists of a separate plan for purposes of Title I of ERISA. To the extent a participant’s annual total compensation exceeds the compensation limits for the calendar year under §401(a)(17) of the Code ($270,000 for 2017) or a participant’s annual additions under the Thrift Plan are limited by the maximum annual additions permitted under §415 of the Code ($54,000 for 2017), the participant’s Excess Thrift Plan account is credited with that number of hypothetical NuStar Energy units that could have been purchased with the difference between:
The total company matching contributions that would have been credited to the participant’s account under the Thrift Plan had the participant’s contributions not been limited pursuant to §401(a)(17) and/or §415; and
The actual company matching contributions credited to such participant’s account.
Each of our NEOs participated in the Excess Thrift Plan in 2017.
Change of Control Severance Arrangements
We initially entered into change of control severance agreements with each of our NEOs in, or prior to, 2007. The change of control severance agreements are intended to ensure the continued availability of these executives in the event of certain transactions culminating in a “change of control” as defined in the agreements. The change of control severance agreements have three-year terms and are automatically extended for one year upon each anniversary unless we give notice not to extend. If a “change of control” (as defined in the agreements) occurs during the term of an agreement, then the agreement becomes operative for a fixed three-year period. The agreements provide generally that the NEO’s terms and conditions of employment (including position, location, compensation and benefits) will not be adversely changed during the three-year period after a change of control.
The agreements contain tiers of compensation and benefits based on each NEO’s position. Each tier corresponds to a certain “severance multiple” used to calculate cash severance and other benefits to be provided under the agreements. Compensation and benefits under the agreements are triggered upon the occurrence of any of the following in connection with a change of control:

termination of employment by the employer other than for “cause” (as defined in the agreements), death or disability;
termination by the NEO for “good reason” (as defined in the agreements);
termination by the NEO other than for “good reason;” and
termination of employment because of death or disability.
These triggers were designed to ensure the continued availability of these executives following a change of control, and to compensate them at appropriate levels if their employment is unfairly or prematurely terminated during the applicable term following a change of control.
The following table sets forth the severance multiple applicable to each NEO, based on his or her current officer position.
NameApplicable Officer PositionSeverance Multiple
BarronChief Executive Officer3
ShoafExecutive Vice President2.5
BrownExecutive Vice President2.5
OliverSenior Vice President2
TrubySenior Vice President2
When determining the amounts and benefits payable under the agreements, the Compensation Committee sought to secure compensation that is competitive in our market in order to recruit and retain executive officer talent. Consideration was given to the principal economic terms found in written employment and change of control agreements of other publicly traded companies. For more information regarding payments and benefits that may be provided under our change of control severance arrangements, see our disclosures below under the caption “Potential Payments upon Termination or Change of Control.”
Each of our NEOs has agreed and acknowledged that the Merger will not be deemed to trigger a “change of control” as defined under any NuStar Energy or NuStar GP Holdings plan or award, and has waived any rights to vesting, payment or other benefit thereunder that would arise upon a “change of control,” to which he or she might otherwise have been entitled.
Employment Agreements
None of the NEOs have employment agreements, other than the change of control severance agreements described above. As a result, in the event of a termination, retirement, death or disability that is not related to a change of control, an NEO will only receive the compensation or benefits to which he or she would be entitled under the terms of the defined contribution, defined benefit, medical or long-term incentive plans, as applicable.
IMPACT OF ACCOUNTING AND TAX TREATMENTS
Accounting Treatment
Services Agreement
As described in Item 13 below, on March 1, 2016, NuStar GP, LLC transferred and assigned to NuStar Services Co, a wholly owned subsidiary of ours, employment of all of NuStar GP, LLC’s employees. Our executive officers continue to serve as officers of NuStar GP Holdings and NuStar GP, LLC, and also serve as officers of NuStar Services Co and other NuStar Energy subsidiaries. Our NEOs serve as employees of both NuStar GP, LLC and NuStar Services Co. In connection with the transfer and assignment, we amended and restated the Services Agreement such that, beginning March 1, 2016, NuStar GP Holdings and NuStar Energy receive all management and administrative services from NuStar Services Co. NuStar Energy reimburses NuStar Services Co for all services provided to NuStar Energy, including payroll and benefit costs, as well as NuStar Energy unit-based compensation costs. NuStar GP Holdings pays NuStar Services Co an administrative services fee, subject to certain adjustments, but no longer pays 1.0% of our domestic bonus and unit compensation expenses. Instead, NuStar GP Holdings retains the expense associated with any NuStar GP Holdings common unit awards or other compensation that it provides to its officers and directors.

Unit-Based Compensation
In connection with the employee transfer on March 1, 2016, we assumed all outstanding awards under the 2000 LTIP. Our financial statements include the expense for awards of NuStar Energy restricted units and performance units. The transfer of the outstanding awards qualified as a plan modification. Therefore, we measured the fair value of then-outstanding awards to domestic employees (including our NEOs) based on the common unit price on the transfer date. Restricted units awarded to international employees are liability-classified awards that are cash-settled and measured at fair value based on the common unit price at each reporting period.
NuStar Energy Restricted Units. Our restricted unit awards are considered “phantom” units, as they represent the right to receive our common units upon vesting. We account for restricted units expected to result in the issuance of our common units upon vesting as equity-classified awards. The restricted units granted to our domestic employees (including our NEOs) generally vest over five years and the restricted units granted to non-employee directors generally vest over three years. We record compensation expense ratably over the vesting period based on the fair value of the units at the grant date (for domestic employees, including our NEOs) or the fair value of the units measured at each reporting period (for non-employee directors) using the market price of our common units on the applicable date. Common unit distribution equivalents paid with respect to outstanding, unvested equity-classified restricted units reduce equity, similar to cash distributions to unitholders.
NuStar Energy Performance Units. Performance units are equity-classified awards that vest in three increments (tranches) and represent the right to receive our common units, based upon our achievement of the performance measure set by the Compensation Committee during the one-year performance periods that end on December 31 of each year following the grant date. Under applicable accounting standards, a tranche of performance units is not considered “granted” until the Compensation Committee has set the performance measure for that specific tranche of the award. Therefore, performance units are measured at the grant date fair value once the performance measure is established for a specific tranche. In addition, since the performance units granted do not receive common unit distribution equivalents, the estimated fair value of these awards does not include the per unit distributions expected to be paid to unitholders during the vesting period. We record compensation expense ratably for each vesting tranche over its one-year service period if it is probable that the specified performance measure will be achieved. Additionally, changes in the actual or estimated outcomes that affect the quantity of performance units expected to be converted are recognized as a cumulative adjustment.
NuStar GP Holdings, LLC Restricted Units. NuStar GP Holdings’ restricted units are “phantom” units, as they represent the right to receive NuStar GP Holdings’ common units upon vesting. As described above, pursuant to the amended and restated services agreement, NuStar GP Holdings retains the expense associated with NuStar GP Holdings restricted unit awards. NuStar GP Holdings accounts for restricted units that it awards under its long-term incentive plan to its directors and employees (including our NEOs) at fair value. NuStar GP Holdings uses the market price at the grant date as the fair value of its restricted units. Awards of NuStar GP Holdings’ restricted units to its employees vest over five years, and NuStar GP Holdings recognizes the resulting compensation expense ratably over the vesting period.
Tax Treatment
We are a limited partnership and not a corporation for U.S. federal income tax purposes. Therefore, we are not subject to the executive compensation deduction limitations under Section 162(m) of the Code.
COMPENSATION-RELATED POLICIES
Unit Ownership Guidelines
We believe that ownership of NuStar Energy units aligns the interests of our directors and executives with those of NuStar Energy’s unitholders. We have long emphasized and reinforced the importance of unit ownership among our executives and directors.
During 2006, the Compensation Committee worked with its independent compensation consultant to formalize unit ownership and retention guidelines for our directors and officers to ensure continuation of our successful track record in aligning the interests of our directors and officers with those of our unitholders through unit ownership. During 2015, at the request of the Board and its committees, management undertook a review of the unit ownership and retention guidelines. Management discussed the results of its review with the Compensation Committee’s independent compensation consultant at the time, which agreed with management’s conclusions. The Compensation Committee and the Nominating/Governance and Conflicts Committee of NuStar GP, LLC’s Board, as well as the board of directors of NuStar GP Holdings, have approved the updated unit ownership and retention guidelines described below.

Non-Employee Director Unit Ownership Guidelines
Non-employee directors are expected to acquire and hold during their service as a Board member NuStar Energy units and/or NuStar GP Holdings units with an aggregate value of at least two times their annual cash retainer. Directors have five years from their initial election to the Board to meet the target unit ownership guidelines, and they are expected to continuously own sufficient units to meet the guidelines, once attained. As of December 31, 2017, each of our directors exceeded the ownership levels set forth in the unit ownership guidelines.
Officer Unit Ownership Guidelines
Unit ownership guidelines for the officers set forth below are as follows:
Officer
Value of NuStar Energy Units and/or
NuStar GP Holdings Units Owned
CEO/President4.0x base salary
EVP serving on CEO’s officer committee3.0x base salary
SVP serving on CEO’s officer committee2.0x base salary
VP serving on CEO’s officer committee1.0x base salary

The officers subject to the unit ownership and retention guidelines, including each of our NEOs, are expected to meet the applicable guidelines within five years of becoming subject to the guidelines and continuously own sufficient units to meet the guidelines, once attained. As of December 31, 2017, each of our NEOs exceeded the ownership levels set forth in the unit ownership guidelines.
Unit Ownership
For purposes of satisfying the unit ownership guidelines, the following units are considered owned:
units owned directly;
units owned indirectly through possession of the right to sell, transfer and/or vote such units; and
unvested restricted or phantom units granted under our long-term incentive plan or NuStar GP Holdings’ long-term incentive plan.
Unexercised unit options and unvested performance units are not considered owned for purposes of satisfying the unit ownership guidelines.
Prohibition on Insider Trading and Speculation in NuStar Energy or NuStar GP Holdings Units

We have established policies prohibiting our officers, directors and employees from purchasing or selling either NuStar Energy or NuStar GP Holdings securities while in possession of material, nonpublic information or otherwise using such information for their personal benefit or in any manner that would violate applicable laws and regulations. Our directors, officers and certain other employees are prohibited from trading in either NuStar Energy or NuStar GP Holdings securities for the period beginning on the last business day of each calendar quarter through the first business day following our disclosure of our quarterly or annual financial results. In addition, our policies prohibit our officers, directors and employees from speculating in either NuStar Energy or NuStar GP Holdings units, such as by short selling (profiting if the market price of our units decreases), buying or selling publicly traded options (including writing covered calls), hedging or any other type of derivative arrangement that has a similar economic effect. Our directors, officers and certain other employees also are required to obtain consent from the CEO (or, in the case of the CEO, from the Chair of the applicable company’s Audit Committee) before they enter into margin loans or other financing arrangements that may lead to the ownership or other rights to their NuStar Energy or NuStar GP Holdings securities being transferred to a third party.


EVALUATION OF COMPENSATION RISK
The Compensation Committee has focused on aligning our compensation policies with the long-term interests of NuStar Energy and avoiding short-term rewards for management decisions that could pose long-term risks to NuStar Energy. As described above in “Compensation Discussion and Analysis,” the primary elements of our compensation program are base salary, annual incentive bonus and long-term incentives. We believe that our compensation program appropriately balances cash with equity-based compensation and fixed compensation with short- and long-term incentives such that no single pay element would motivate unnecessary risk taking.
NuStar Energy’s compensation program is structured so that base salaries provide a fixed level of competitive pay that reflects the individual’s primary duties and responsibilities, and a considerable amount of our management’s compensation is tied to NuStar Energy’s long-term fiscal health. Bonuses, including executive bonuses, are determined with reference to a well-defined performance measure selected by the Compensation Committee and applicable to all employees, as well as the Compensation Committee’s review of each individual executive’s performance. Historically, our long-term incentives have taken the form of performance units and restricted units that typically vest over three- and five-year periods, respectively, which we believe serves to align our employees’ interests with the long-term goals of NuStar Energy. No business group or unit is compensated differently than any other, regardless of profitability. There also is a maximum number of performance units that may be earned, based on the performance of NuStar Energy relative to a performance measure selected by the Compensation Committee. As such, we believe that our compensation policies encourage employees to operate our business in a fundamentally sound manner, align our executives’ interests with those of our unitholders and do not create incentives to take risks that are reasonably likely to have a material adverse effect on NuStar Energy.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
There are no compensation committee interlocks. The members of our Compensation Committee are Mr. Hill (Chairman), Mr. Bates, Mr. Munch and Mr. Rosier. None of the members of our Compensation Committee have served as an officer or employee of ours. Furthermore, except for compensation arrangements disclosed in this Annual Report on Form 10-K, NuStar Energy has not participated in any contracts, loans, fees or awards, nor does it have financial interests, direct or indirect, with any Compensation Committee member. In addition, none of NuStar Energy’s management or Board members are aware of any means, directly or indirectly, by which a Compensation Committee member could receive a material benefit from NuStar Energy.


COMPENSATION OF EXECUTIVE OFFICERS AND DIRECTORS
The following pages of this Item 11 provide information required by the SEC regarding compensation paid to or earned by our NEOs and the members of our Board for the periods indicated. We have used captions and headings in the tables provided below in accordance with the SEC regulations requiring these disclosures. The footnotes to these tables provide important information to explain the values presented in the tables, and are an important part of our disclosures.
SUMMARY COMPENSATION TABLE
The following table provides a summary of compensation paid for the years ended December 31, 2017, December 31, 2016 and December 31, 2015 to our Chief Executive Officer, Chief Financial Officer and our three other most highly compensated executive officers serving during 2017. For each NEO, the table shows amounts earned for services rendered to us in all capacities in which the NEO served during the periods presented for that NEO. Mr. Oliver and Mr. Truby were not considered “executive officers” for SEC reporting purposes prior to 2017 and, accordingly, their compensation is reported only with respect to 2017.

Name and Principal
Position
Year
Salary 
($)
Unit
Awards
($)(1)
Non-Equity
Incentive
Plan
Compensation
($)(2)
Change in Pension Value
and Nonqualified
Deferred Compensation
Earnings
($)(3)
All Other
Compensation
($)(4)
Total 
($)
Bradley C. Barron President and Chief Executive Officer

2017583,625
 1,233,907
 
—


 218,342
 54,897
 2,090,771
 
2016557,500
 1,039,456
 700,000
 184,931
 35,698
 2,517,585
 
2015515,000
 1,077,860
 800,000
 47,061
 35,677
 2,475,598
 
Thomas R. Shoaf Executive Vice President and Chief Financial Officer2017354,950
 554,372
 
—


 171,513
 28,387
 1,109,222
 
2016344,600
 479,970
 260,000
 124,479
 22,924
 1,231,973
 
2015334,550
 515,023
 311,000
 47,692
 21,729
 1,229,994
 
Mary Rose Brown
Executive Vice President and Chief Administrative Officer
2017382,350
 597,187
 
—


 188,315
 60,689
 1,228,541
 
2016371,200
 516,952
 280,000
 142,437
 24,520
 1,335,109
 
2015360,350
 554,552
 335,000
 173,968
 23,836
 1,447,706
 
Daniel S. Oliver
Senior Vice President-Marketing and Business Development

2017323,150
 382,223
 
—


 142,129
 29,973
 877,475
 
Michael Truby
Senior Vice President-Operations
2017293,800
 310,868
 —
 112,573
 23,259
 740,500
 

(1)The amounts reported represent the aggregate grant date fair value of grants of NuStar Energy restricted units, NuStar Energy performance units and NuStar GP Holdings restricted units. Under a services agreement in effect prior to March 1, 2016, we reimbursed NuStar GP, LLC for 99% of the compensation expense associated with NuStar Energy awards. On March 1, 2016, NuStar GP, LLC transferred and assigned to NuStar Services Co, a wholly owned subsidiary of ours, employment of all of NuStar GP, LLC’s employees and we assumed all outstanding NuStar Energy awards. Our NEOs are employees of both NuStar Services Co and NuStar GP, LLC. NuStar GP Holdings retains the expense associated with the NuStar GP Holdings restricted unit awards.
Restricted Units
The grant date fair valueOur restricted unit awards are considered phantom units, as they represent the right to receive our common units upon vesting. We account for restricted units presented inas either equity-classified awards or liability-classified awards, depending on expected method of settlement. Awards we settle with the table above was determined by multiplying the numberissuance of NuStar Energy restricted units or NuStar GP Holdings restricted units that were granted by the NYSE closing unit price of NuStar Energy common units or NuStar GP Holdings common units, as applicable,upon vesting are equity-classified. Awards we settle in cash upon vesting are liability-classified. We record compensation expense ratably over the vesting period based on the date of grant.
Performance Units
For the 2015 row in the Summary Compensation Table, the grant date fair value of the NuStar Energy performance units was determined by multiplying the target number of performance units that were granted by the NYSE closing unit price of NuStar Energy common units at the grant date (for domestic employees and NEDs), or, prior to the sale of our Point Tupper Terminal Operations on the date of grant.

On March 1, 2016, in connection with the employee transfer, we assumed all outstanding NuStar Energy awards, and performance unit awards are now equity-classified awards. The transfer qualified as a plan modification, and we measuredApril 29, 2022, the fair value of then-outstandingthe common units measured at each reporting period (for international employees). DERs paid with respect to outstanding equity-classified unvested restricted units reduce equity, similar to cash distributions to unitholders, whereas DERs paid with respect to outstanding liability-classified unvested restricted units were expensed prior to the sale of our Point Tupper Terminal Operations on April 29, 2022. In connection with the DERs for equity awards, based on our common unit price onwe paid $2.7 million, $2.5 million and $2.4 million respectively, in cash, for the transferyears ended December 31, 2023, 2022 and 2021.

Domestic Employees. The outstanding restricted units granted to domestic employees are equity-classified awards and generally vest over five years, beginning one year after the grant date. Under applicable accounting standards, a trancheThe fair value of performance unitsthese awards is not considered “granted” until the Compensation Committee has set the performance measure for that specific tranche of the award. Therefore, performance units are measured at the grant datedate.

Non-Employee Directors. The outstanding restricted units granted to NEDs are equity-classified awards that vest over three years. The fair value once the performance measureof these awards is established for a specific tranche (or, for 2016, the transfer date).
Beginning with the 2016 period,measured at the grant date fair value presented indate.

International Employees. Prior to the Summary Compensation Table includessale of our Point Tupper Terminal Operations on April 29, 2022, the outstanding restricted units granted to international employees were cash-settled and accounted for as liability-classified awards. These awards vested over three years and the fair value was equal to the market price of our common units at each tranchereporting period. For the year ended December 31, 2022, 11,364 restricted units vested, and 10,396 restricted units were forfeited related to our international employees.

A summary of performance units for which the Compensation Committee established a performance measure during that year. Accordingly, as illustrated in the table below:
the amount reported for 2016 includes the one tranche of each of the 2014, 2015 and 2016 performanceour equity-classified restricted unit awards subjectis as follows:
Measured at Grant Date Fair Value
Number of UnitsWeighted-Average Fair Value Per Unit
Nonvested units as of January 1, 20212,333,894 $17.70 
Granted1,049,081 16.28 
Vested(630,888)20.07 
Forfeited(102,339)14.28 
Nonvested units as of December 31, 20212,649,748 16.57 
Granted1,206,824 16.09 
Vested(738,701)17.79 
Forfeited(125,078)16.23 
Nonvested units as of December 31, 20222,992,793 16.08 
Granted1,112,965 17.49 
Vested(921,890)16.81 
Forfeited(23,434)15.93 
Nonvested units as of December 31, 20233,160,434 16.39 

The total fair value of our equity-classified restricted unit awards vested for the years ended December 31, 2023, 2022 and 2021 was $16.1 million, $11.9 million and $10.3 million, respectively. We issued 661,050, 531,637 and 460,076 common units in
95
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
connection with these award vestings, net of employee tax withholding requirements, for the years ended December 31, 2023, 2022 and 2021, respectively. Unrecognized compensation cost related to vesting based onour equity-classified employee awards totaled $49.2 million as of December 31, 2023, which we expect to recognize over a weighted-average period of 3.6 years.

Performance Awards
Performance awards are issued to certain of our key employees and represent either rights to receive our common units or cash upon achieving performance measures for the performance criteriaperiod established by the NuStar GP, LLC Compensation Committee on February 24, 2016 with respect to 2016 performance; and
the amount reported for 2017 includes the one tranche of each(the Compensation Committee). Achievement of the 2015, 2016 and 2017 performance unit awards subject to vesting based onmeasures determines the rate at which the performance criteria established by the Compensation Committee on February 23, 2017 with respectawards convert into our common units or cash, which ranges from zero to 2017 performance.200% for certain awards.


AwardTranche Considered “Granted”
In 2017 with respect to 2017 Performance MeasureIn 2016 with respect to 2016 Performance Measure
2014 Performance Unit AwardN/A3rd
2015 Performance Unit Award3rd2nd
2016 Performance Unit Award2nd1st
2017 Performance Unit Award1stN/A

For 2017 and 2016, the grant date fair valuePerformance awards vest in three annual increments (tranches), based upon our achievement of the NuStar Energy performance units was determined by multiplying the probable number of performance units for all tranches eligible to vest with respect to 2017 and 2016 performance (as illustrated in the table above), respectively, by the NYSE closing unit price of NuStar Energy common units on the grant date (or, for 2016, the transfer date as described above), reduced by the per unit value of distributions not paid on performance units prior to vesting.
If the maximum number of NuStar Energy performance units had been used to determine the grant date fair value of performance units for the 2017 and 2016 periods presented, the grant date fair value for performance units for the 2017 and 2016 periods presented in the Summary Compensation Table for each of our NEOs would have been as set forth in the table below:
NameGrant Date Fair Value Based on Maximum Number of Performance Units
2017 ($)2016 ($)
Barron1,077,444
618,393
Shoaf499,944
305,958
Brown538,471
329,513
Oliver379,247
N/A
Truby263,667
N/A
Please see the “Long-Term Incentive Awards” section and the “Accounting Treatment” section of “Compensation Discussion and Analysis” above in this Item 11 and Note 23 of the Notes to Consolidated Financial Statements in Item 8 for additional information regarding the vesting schedules and the assumptions made in the valuation.


(2)Our NEOs did not receive cash annual incentive bonus amounts for 2017. The amounts reported as “non-equity incentive plan compensation” for 2016 and 2015 reflect the cash annual incentive bonus amounts paid to our NEOs pursuant to the annual bonus plan with respect to performance for those years. Any bonus amounts are paid in February of each year with respect to performance during the immediately preceding year. Bonuses are determined taking into consideration NuStar Energy’s performance in the applicable year, each individual NEO’s target and each NEO’s performance, as described above under “Compensation Discussion and Analysis-Elements of Executive Compensation-Annual Incentive Bonus.” For an explanation of the amount of salary and bonus in proportion to total compensation, see “Compensation Discussion and Analysis-Elements of Executive Compensation-Relative Size of Primary Elements of Compensation.”
(3)The amounts reported reflect the amounts attributable to the aggregate change in the actuarial present value of each NEO’s accumulated benefit under our defined benefit and actuarial pension plans, including supplemental plans (but excluding tax-qualified defined contribution plans and nonqualified defined contribution plans). None of the NEOs received any above-market or preferential earnings on compensation that is deferred on a basis that is not tax-qualified during the periods presented.
(4)The amounts reported in this column for 2017 consist of the following for each NEO:

Name
Company
Contribution
to Thrift
Plan ($)
Company
Contribution
to Excess
Thrift Plan ($)
Tax
Preparation ($)
Personal Liability Insurance ($)
Executive Health Exams ($)(a)
TOTAL ($)
Barron16,200
 36,316
 850
 1,531
—54,897
Shoaf16,200
 7,226
 850
 1,531
2,58028,387
Brown13,185
 42,543
 850
 1,531
2,58060,689
Oliver16,200
 11,392
 850
 1,531
—29,973
Truby16,200
 4,678
 850
 1,531
—23,259
(a)The amount reported is the difference between the value of the respective NEO’s health exams and the value of NuStar Energy’s all-employee wellness assessments.


PAY RATIO

As required by SEC regulations, we are providing the following information regarding the ratio of the annual total compensation of our President and Chief Executive Officer, Mr. Barron, to the median of the annual total compensation of our employees for our last completed fiscal year.

For 2017:

the median of the annual total compensation of all of our employees (other than our President and Chief Executive Officer) was $88,610; and
the annual total compensation of our President and Chief Executive Officer, as reported in the Summary Compensation Table above, was $2,090,771.

Accordingly, for 2017, the ratio of the annual total compensation of our President and Chief Executive Officer to the annual total compensation of our median employee was 24 to 1.

To determine our median employee, we identified each individual employed by us on October 1, 2017 (our Determination Date), and, for each individual employed by us on the Determination Date, we examined each of the following elements of compensation (which we refer to as the Total Comparable Compensation) that we paid those employees during the period from October 1, 2016 through September 30, 2017 (the Compensation Review Period):

salary, wages and any overtime paid during the Compensation Review Period;
any bonus awards paid during the Compensation Review Period; and
the grant date fair value of any restricted units awarded during the Compensation Review Period.

As of our Determination Date, we had approximately 1,690 employees located in five countries. We selected our Determination Date and our Compensation Review Period to provide sufficient time for us to gather the necessary information from multiple countries and to enable us to make the identification of the median employee in a reasonably efficient and economical manner. After identifying the median employee based on Total Comparable Compensation, we calculated the annual total compensation for the median employee for 2017 using the same methodology we use to calculate the annual total compensation for our NEOs for 2017, as set forth in the Summary Compensation Table above. We did not make any assumptions, adjustments or estimates to identify the median employee, to determine the Total Comparable Compensation for each employee or to determine the annual total compensation for the median employee.


GRANTS OF PLAN-BASED AWARDS
DURING THE YEAR ENDED DECEMBER 31, 2017
The following table provides information regarding grants of plan-based awards to the NEOs during 2017.

NameGrant Date
Date of
Approval by Compensation Committee of Equity-Based Awards
Estimated Future Payouts Under Non-Equity
Incentive Plan Awards
Estimated Future Payouts Under Equity
Incentive Plan Awards
All Other
Unit
Awards:
Number of
Units (#)
Grant Date
Fair Value of
Unit
Awards ($)
Threshold  ($)Target ($)Maximum ($)Threshold  (#)
Target
(#)
Maximum (#)
BarronN/A
(1) 
N/AN/A583,625
1,167,250
—
—
—
—
 — 
2/23/2017
(2) 
2/23/2017——
—
9,665
10,739
21,478
—
 538,722 
11/16/2017
(3) 
10/18/2017——
—
—
—
—
16,660
16,660
486,805 
11/16/2017
(4) 
10/18/2017——
—
—
—
—
13,315
 208,380 
ShoafN/A
(1) 
N/AN/A212,970
425,940
—
—
—
—
 — 
2/23/2017
(2) 
2/23/2017——
—
4,485
4,983
9,966
—
249,972 
11/16/2017
(3) 
10/18/2017——
—
—
—
—
7,295
213,160 
11/16/2017
(4) 
10/18/2017——
—
—
—
—
5,830
91,240 
BrownN/A
(1) 
N/AN/A229,410
458,820
—
—
—
—
 — 
2/23/2017
(2) 
2/23/2017——
—
4,830
5,367
10,734
—
269,236 
11/16/2017
(3) 
10/18/2017——
—
—
—
—
7,860
229,669 
11/16/2017
(4) 
10/18/2017——
—
—
—
—
6,280
98,282 
OliverN/A
(1) 
N/AN/A177,733
355,465
—
—
—
—
 — 
2/23/2017
(2) 
2/23/2017——
—
3,402
3,780
7,560
—
 189,624 
11/16/2017
(3) 
10/18/2017——
—
—
—
—
4,615
 134,850 
11/16/2017
(4) 
10/18/2017——
—
—
—
—
3,690
 57,749 
TrubyN/A
(1) 
N/AN/A161,590
323,180
—
—
—
—
 — 
2/23/2017
(2) 
2/23/2017——
—
2,365
2,628
5,256
—
 131,834 
11/16/2017
(3) 
10/18/2017——
—
—
—
—
4,290
 125,354 
11/16/2017
(4) 
10/18/2017——
—
—
—
—
3,430
 53,680 

(1)The amounts reported represent the target and maximum amounts that would potentially have been payable in cash to the NEOs as annual incentive bonus awards under the annual bonus plan with respect to 2017 performance. The annual incentive bonus awards with respect to 2017 performance did not include a threshold amount that would potentially be payable to the NEOs. As reflected in the “Non-Equity Incentive Plan Compensation” column of the Summary Compensation Table and as described above under “Compensation Discussion and Analysis-Elements of Executive Compensation-Annual Incentive Bonus,” the target level of performance with respect to 2017 was not met, and, upon the recommendation of executive management, the Compensation Committee did not award our executives, including our NEOs, annual incentive bonus award payments with respect to 2017 performance.

(2)Performance units were awarded by the Compensation Committee on February 23, 2017 pursuant to the 2000 LTIP. Performance units vest in three annual increments (tranches), based upon our achievement of the performance measuremeasures set by the Compensation Committee during the one-year performance periods that end on December 31 of each year following the date of grant. Under applicable accounting standards, a tranche of performance units is not considered “granted” until the Compensation Committee has set the performance measure for that specific tranche of the award. Therefore, performance units are measured at the grant date fair value once the performance measure is established for a specific tranche. In addition, since the performance units granted do not receive common unit distribution equivalents, the estimated fair value of these awards does not include the per unit distributions expected to be paid to unitholders during the vesting period.

The estimated future payouts and the grant date fair value presented in the table above with respect to performance units includes each tranche of performance units for which the Compensation Committee established a performance measure during 2017. For 2017, the amounts presented include the one tranche of each of the 2015, 2016 and 2017 performance unit awards that was subject to vesting based on the performance criteria established by the Compensation Committee on February 23, 2017 with respect to 2017 performance, as illustrated in the table below:
AwardTranche Considered “Granted” in 2017 With Respect to 2017 Performance Measure
2015 Performance Unit Award3rd
2016 Performance Unit Award2nd
2017 Performance Unit Award1st

On January 25, 2018, the Compensation Committee determined that, based on the performance level attained for the performance period ended December 31, 2017, the performance units reported in the table above did not vest. See “Compensation Discussion and Analysis-Elements of Executive Compensation-Long Term Incentive Awards-Performance Units” for a description of the performance measure and the performance level attained with respect to the 2017 performance period. See “Compensation Discussion and Analysis-Impact of Accounting and Tax Treatments-Accounting Treatment” and footnote (1) to the Summary Compensation Table above in this Item 11 for information regarding the assumptions made in valuation.
(3)Restricted units of NuStar Energy were approved by the Compensation Committee on October 18, 2017, and the grant date for these NuStar Energy restricted units was set at that time for the date that was as soon as administratively practicable after the meeting and no earlier than the third business day following our third quarter earnings release. The NuStar Energy restricted units were awarded pursuant to the 2000 LTIP and vest 1/5 annually over five years beginning on the first anniversary of the grant date. All grantees receiving NuStar Energy restricted units are entitled to receive an amount in cash equal to the product of (a) the number of restricted units granted to the grantee that remain outstanding and unvested as of the record date for such quarter and (b) the quarterly distribution declared by the Board for such quarter with respect to NuStar Energy’s common units. See “Compensation Discussion and Analysis-Impact of Accounting and Tax Treatments-Accounting Treatment” and footnote (1) to the Summary Compensation Table above in this Item 11 for information regarding the assumptions made in valuation.
(4)Restricted units of NuStar GP Holdings were approved by the compensation committee of NuStar GP Holdings on October 18, 2017, and the grant date for these NuStar GP Holdings restricted units was set at that time for the date that was as soon as administratively practicable after the meeting and no earlier than the third business day following NuStar GP Holdings’ third quarter earnings release. The NuStar GP Holdings restricted units were awarded pursuant to the NuStar GP Holdings Long-Term Incentive Plan, as amended and restated as of April 1, 2007, and vest 1/5 annually over five years beginning on the first anniversary of the grant date. All grantees receiving NuStar GP Holdings restricted units are entitled to receive an amount in cash equal to the product of (a) the number of restricted units granted to the grantee that remain outstanding and unvested as of the record date for such quarter and (b) the quarterly distribution declared by the NuStar GP Holdings Board for such quarter with respect to NuStar GP Holdings’ common units. See “Compensation Discussion and Analysis-Impact of Accounting and Tax Treatments-Accounting Treatment” and footnote (1) to the Summary Compensation Table above in this Item 11 for information regarding the assumptions made in valuation.
At the effective time of the Merger, each outstanding award of NuStar GP Holdings restricted units will be converted, on the same terms and conditions as were applicable to the awards immediately prior to the Merger, into an award of NuStar Energy restricted units. The number of NuStar Energy restricted units subject to the converted awards will be determined as provided in the Merger Agreement.


OUTSTANDING EQUITY AWARDS
AT DECEMBER 31, 2017
The following table provides information regarding our NEOs’ unvested restricted units and the target amount of our NEOs’ unvested performance units as of December 31, 2017. The value of NuStar Energy restricted units, NuStar Energy performance units and NuStar GP Holdings restricted units reported below was determined by multiplying (1) the number of units reflected in the table by (2) $29.95 (the closing price of NuStar Energy common units on December 29, 2017, the last trading day of the year) or $15.70 (the closing price of NuStar GP Holdings common units on December 29, 2017, the last trading day of the year), as applicable.
At the effective time of the Merger, each outstanding award of NuStar GP Holdings restricted units will be converted, on the same terms and conditions as were applicable to the awards immediately prior to the Merger, into an award of NuStar Energy restricted units. The number of NuStar Energy restricted units subject to the converted awards will be determined as provided in the Merger Agreement. Each of our NEOs has agreed and acknowledged that the Merger will not be deemed to trigger a “change of control” as defined under any NuStar Energy or NuStar GP Holdings plan or award, and has waived any rights to vesting, payment or other benefit thereunder that would arise upon a “change of control,” to which he or she might otherwise have been entitled.
 NameUnit Awards
Type of Award
Number of Units
That Have Not
Vested (#)
Market
Value of
Units That
Have Not
Vested ($)
Equity
Incentive
Plan Awards:
Number of
Unearned Units
or Other Rights
That Have Not
Vested (#)
Equity
Incentive
Plan Awards: Market or Payout Value of Unearned Units or Other Rights That Have Not Vested ($)
Barron
NuStar Energy Performance Unit (1)
——
22,480673,276
NuStar Energy
Restricted Unit (2)
35,2721,056,396
——
NuStar GP Holdings Restricted Unit (3)
27,505431,829
——
Shoaf
NuStar Energy Performance Unit (4)
——
10,245306,838
NuStar Energy
Restricted Unit (5)
16,102482,255
——
NuStar GP Holdings Restricted Unit (6)
12,551197,051
——
Brown
NuStar Energy Performance Unit (7)
——
11,035330,498
NuStar Energy
Restricted Unit (8)
17,607527,330
——
NuStar GP Holdings Restricted Unit (9)
13,709215,231
——
Oliver
NuStar Energy Performance Unit (10)
——
7,772232,771
NuStar Energy
Restricted Unit (11)
11,479343,796
——
NuStar GP Holdings Restricted Unit (12)
8,924140,107
——
Truby
NuStar Energy Performance Unit (13)
——
5,444163,048
NuStar Energy
Restricted Unit (14)
9,650289,018
——
NuStar GP Holdings Restricted Unit (15)
6,25998,266
——

(1)Mr. Barron’s target number of NuStar Energy performance units consist of: 2,666 units awarded January 29, 2015; 8,814 units awarded February 24, 2016; and 11,000 units awarded February 23, 2017.
The performance units awarded in 2015, 2016 and 2017 are eligible to vest in three annual increments and are payable in NuStar Energy’s common units. Upon vesting, the performance units are converted into a number of NuStar Energy common units based upon NuStar Energy’s performance during the one-year performance periods that end on December 31 of each year followingapplicable year. Therefore, the date of grant against an objective performance measure established by the Compensation Committee.
On January 25, 2018,awards are not considered granted for accounting purposes until the Compensation Committee determined that, based onhas set the performance level attainedmeasures for each tranche of awards. Performance unit awards are equity-classified awards measured at the grant date fair value. In addition, since the performance unit awards granted do not receive DERs, the grant date fair value of these awards is reduced by the per unit distributions expected to be paid to common unitholders during the vesting period. Performance cash awards are accounted for as a liability but may be settled in common units. We record compensation expense ratably for each vesting tranche over its requisite service period (one year) if it is probable that the specified performance measures will be achieved. Additionally, changes in the actual or estimated outcomes that affect the quantity of performance awards expected to be converted into common units or paid in cash, are recognized as a cumulative adjustment. Performance units vested relate to the performance for the performance period ended December 31 2017,of the previous year.

A summary of our performance awards is shown below:
Performance Unit Awards
Granted for Accounting Purposes
Performance Cash AwardsTotal Performance
Unit Awards Granted		Performance Unit AwardsWeighted-Average Grant Date Fair Value per Unit
(Thousands of Dollars)
Outstanding as of January 1, 2021$2,167 87,122 57,448 $13.21 
Granted2,254 4,021 33,695 15.79 
Vested (a)(672)(53,427)(53,427)13.21 
Forfeited(51)(4,021)(4,021)13.21 
Outstanding as of December 31, 20213,698 33,695 33,695 15.79 
Granted2,954 — — — 
Performance adjustment (b)— 14,839 14,839 15.79 
Vested (a)(1,507)(48,534)(48,534)15.79 
Outstanding as of December 31, 20225,145 — — — 
Granted3,287 — — — 
Vested (a)(2,575)— — — 
Forfeited(141)— — — 
Outstanding as of December 31, 2023$5,716 — — — 
(a)For the years ended December 31, 2023, 2022 and 2021, we settled performance cash awards with 149,608, 137,931 and 43,733 common units, respectively, and issued 86,945, 84,778 and 26,704 common units, net of employee tax withholding requirements, respectively.
(b)For the year ended December 31, 2022, common units granted and issued upon vesting resulted from performance units earned at 150% of the 2021 target.

The total fair value of our performance unit awards vested for the years ended December 31, 2022 and 2021 was $0.8 million and $0.8 million, respectively. For the years ended December 31, 2022 and 2021 we issued 29,840 and 31,366 common units in connection with the performance unit award vestings, net of employee tax withholding requirements, respectively. In January 2024, we settled performance cash awards, net of employee tax withholding requirements, in cash for $1.6 million.
96
NUSTAR ENERGY L.P. AND SUBSIDIARIES
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 that was paid in unit awards in the first quarter of 2022. We base the number of unit awards granted on the fair value of the common units availableat the grant date. A summary of our unit awards is shown below:
Date of GrantGrant Date Fair ValueUnit Awards GrantedCommon Units Issued, Net of Employee Withholding Tax
(Thousands of Dollars)
February 2022$4,645 280,685 186,190 

23. INCOME TAXES
Components of income tax expense related to vestcertain of our operations conducted through separate taxable wholly owned corporate subsidiaries were as follows:
 Year Ended December 31,
 202320222021
 (Thousands of Dollars)
Current:
U.S.$4,292 $3,558 $3,755 
Foreign— 272 221 
Foreign withholding tax519 355 1,281 
Total current4,811 4,185 5,257 
Deferred:
U.S.601 341 (93)
Foreign— (1,287)(531)
Foreign withholding tax— — (745)
Total deferred601 (946)(1,369)
Income tax expense$5,412 $3,239 $3,888 

The difference between income tax expense recorded in our consolidated statements of income 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.

97
NUSTAR ENERGY L.P. AND SUBSIDIARIES
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,
 20232022
 (Thousands of Dollars)
Deferred income tax assets:
Net operating losses$19,340 $17,710 
Capital loss3,714 3,714 
Other701 793 
Total deferred income tax assets23,755 22,217 
Less: Valuation allowance(22,866)(21,573)
Net deferred income tax assets889 644 
Deferred income tax liabilities:
Property, plant and equipment(4,420)(3,534)
Foreign withholding tax(330)(286)
Other(72)(43)
Total deferred income tax liabilities(4,822)(3,863)
Net deferred income tax liability$(3,933)$(3,219)

As of December 31, 2023, our U.S. and foreign corporate operations have net operating loss carryforwards for tax purposes totaling $49.2 million and $30.1 million, respectively, which are subject to various limitations on use and expire in years 2032 through 2034 for U.S. losses and in years 2024 through 2034 for foreign losses. However, U.S. losses generated after
December 31, 2017, totaling $5.1 million, can be carried forward indefinitely. As of December 31, 2023, 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.

As of December 31, 2023 and 2022, we have a valuation allowance of $22.9 million and $21.6 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 2023, there was a $0.4 million decrease in the valuation allowance for the U.S. net operating loss and a $1.7 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, 2023 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, 2023 will be realized, based on expected future taxable income.

98
NUSTAR ENERGY L.P. AND SUBSIDIARIES
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,
 202320222021
 (Thousands of Dollars)
Revenues:
Pipeline$873,869 $828,191 $762,238 
Storage319,599 334,549 427,668 
Fuels marketing440,725 520,486 428,608 
Consolidation and intersegment eliminations(6)(3)(14)
Total revenues$1,634,187 $1,683,223 $1,618,500 
Depreciation and amortization expense:
Pipeline$175,930 $178,802 $179,088 
Storage75,052 73,076 87,500 
Segment depreciation and amortization expense250,982 251,878 266,588 
Other depreciation and amortization expense4,728 7,358 7,792 
Total depreciation and amortization expense$255,710 $259,236 $274,380 
Reconciliation of segment operating income to income before income tax expense:
Pipeline$483,188 $438,670 $321,472 
Storage87,609 61,081 24,800 
Fuels marketing32,926 33,536 11,181 
Segment operating income603,723 533,287 357,453 
Gain on sale of assets41,075 — — 
General and administrative expenses129,846 117,116 113,207 
Other depreciation and amortization expense4,728 7,358 7,792 
Operating income510,224 408,813 236,454 
Interest expense, net(241,364)(209,009)(213,985)
Other income, net10,215 26,182 19,644 
Income before income tax expense$279,075 $225,986 $42,113 

Revenues by geographic area are shown in the table below:
 Year Ended December 31,
 202320222021
 (Thousands of Dollars)
United States$1,628,215 $1,667,672 $1,582,672 
Foreign5,972 15,551 35,828 
Total revenues$1,634,187 $1,683,223 $1,618,500 

99
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
For the years ended December 31, 2023, 2022 and 2021, Valero Energy Corporation accounted for approximately 22%, or $360.4 million, 18%, or $307.3 million, and 19%, or $308.5 million, of our revenues, respectively. These revenues were included in our pipeline and storage segments for the year ended December 31, 2023, and in all of our reportable business segments for the years ended December 31, 2022 and 2021. No other single customer accounted for 10% or more of our consolidated revenues.

Total amounts of property, plant and equipment, net by geographic area were as follows:
 December 31,
 20232022
 (Thousands of Dollars)
United States$3,234,544 $3,359,427 
Foreign47,993 43,656 
Property, plant and equipment, net$3,282,537 $3,403,083 

Total assets by reportable segment were as follows:
 December 31,
 20232022
 (Thousands of Dollars)
Pipeline$3,292,546 $3,360,685 
Storage1,398,929 1,438,609 
Fuels marketing46,151 37,763 
Total segment assets4,737,626 4,837,057 
Other partnership assets158,766 136,629 
Total assets$4,896,392 $4,973,686 

Capital expenditures by reportable segment were as follows:
 Year Ended December 31,
 202320222021
 (Thousands of Dollars)
Pipeline$100,759 $90,430 $67,340 
Storage43,584 47,222 112,043 
Other partnership assets3,165 2,978 1,750 
Capital expenditures$147,508 $140,630 $181,133 

25. SUBSEQUENT EVENT

On January 22, 2024, NuStar Energy entered into an Agreement and Plan of Merger (the Merger Agreement) with Sunoco LP, a Delaware limited partnership (Sunoco), Saturn Merger Sub, LLC, a Delaware limited liability company and a direct wholly owned subsidiary of Sunoco (Merger Sub), Riverwalk Logistics, L.P., NuStar GP, LLC, and Sunoco GP LLC, a Delaware limited liability company and sole general partner of Sunoco (the Sunoco GP). The Merger Agreement provides that, among other things and on the terms and subject to the conditions set forth therein, Sunoco will acquire NuStar Energy in an all-equity transaction by means of a merger of Merger Sub with and into NuStar Energy (the Merger) with NuStar Energy surviving the Merger as a subsidiary of Sunoco.

On the terms and subject to the conditions set forth in the Merger Agreement, at the effective time of the Merger (the Effective Time), each NuStar Energy common unit issued and outstanding immediately prior to the Effective Time will be converted into and shall thereafter represent the right to receive 0.400 of a common unit of Sunoco and, if applicable, cash in lieu of fractional units. In addition, prior to the Effective Time, we will declare and pay a special cash distribution to our common unitholders in the amount of $0.212 per common unit (the Special Distribution) (in addition to continuing to pay our quarterly distributions in the ordinary course, subject to certain conditions, until the Effective Time).

100
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Each Series A, B and C Preferred Unit issued and outstanding immediately prior to the Effective Time will remain issued and outstanding from and after the Effective Time as limited partnership interests of the surviving entity having the same terms as are applicable to the applicable series of NuStar Energy preferred unit immediately prior to the Effective Time.

The completion of the Merger is subject to the fulfillment or waiver of certain conditions, including, among others: approval and adoption by NuStar Energy’s common unitholders of the Merger Agreement and the transactions contemplated thereby, including the Merger; expiration or termination of the applicable waiting period under the 2015 awards, 2016 awardsHart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; and 2017 awardsthe effectiveness of the registration statement on Form S-4 to be filed by Sunoco pursuant to which Sunoco common units to be issued in connection with the Merger are registered with the U.S. Securities and Exchange Commission (the SEC).

The Merger Agreement contains termination rights for each of NuStar Energy and Sunoco. Upon termination of the Merger Agreement under specified circumstances, including the termination by Sunoco in the event of an adverse recommendation change by our Board of Directors or by NuStar Energy to accept a Superior Proposal (as defined in the Merger Agreement), NuStar Energy would be required to pay Sunoco a termination fee of approximately $90.3 million.

Concurrently with the entry into the Merger Agreement, NuStar Energy and Sunoco entered into an agreement (the Support Agreement) with Energy Transfer LP (Energy Transfer), a Delaware limited partnership and the sole member of the Sunoco GP. The Support Agreement provides, among other things, that Energy Transfer will not transfer its ownership interest in the Sunoco GP, any of the Sunoco incentive distribution rights owned by it or any material portion of the Sunoco common units owned by it prior to the Effective Time. Energy Transfer has also agreed to be bound by the terms of the non-solicitation provisions in the Merger Agreement with respect to 2017 performancecompeting proposals for Sunoco and the Sunoco GP and to abide by certain covenants with respect to regulatory approvals, SEC filings, confidentiality and litigation, among other things.

The foregoing descriptions of the Merger Agreement and the Support Agreement and the transactions contemplated thereby, including the Merger, are summaries, do not purport to be complete and are qualified in their entirety by reference to the full text of the Merger Agreement and the Support Agreement.
101
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 amended) 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, 2023.
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. “Financial Statements and Supplementary Data” 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. “Financial Statements and Supplementary Data” 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
(a) None.
(b) Rule 10b5-1 under the Securities Exchange Act of 1934, as amended, provides an affirmative defense that enables prearranged transactions in securities in a manner that avoids concerns about initiating transactions at a future date while possibly in possession of material nonpublic information. Our Insider Trading Policy permits our directors and executive officers to enter into trading plans designed to comply with Rule 10b5-1. During the three-month period ending December 31, 2023, we did not vest. Seeadopt or terminate and none of our executive officers or directors adopted or terminated a Rule 10b5-1 trading plan or a non-Rule 10b5-1 trading arrangement (as defined in Item 408(c) of Regulation S-K).

ITEM 9C.DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.


102
PART III

ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information required to be disclosed under this Item 10. is incorporated by reference to the table entitledfollowing sections of our Proxy Statement for the 2024 annual meeting of unitholders (Proxy Statement), which is expected to be filed within 120 days after the end of the fiscal year covered by this Form 10-K: “Corporate Governance;” “Proposal No. 1 Election of Directors;” “Information About Our Executive Officers,” and “Compensation Discussion and Analysis–Compensation Related Policies.”

ITEM 11.    EXECUTIVE COMPENSATION
Information required to be disclosed under this Item 11. is incorporated by reference to the following sections of our Proxy Statement: “Compensation Discussion and Analysis;” “Evaluation of Compensation Risk;” “Summary Compensation Table;” “Pay Ratio;” “Grants of Plan-Based Awards During the Year Ended December 31, 2017” for the performance units that did not vest with respect to the 2017 performance period. See “Compensation Discussion and Analysis-Elements of Executive Compensation-Long Term Incentive Awards-Performance Units” for a description of the performance measure and the performance level attained with respect to the 2017 performance period.
If the maximum level of performance (200%) had been assumed for all of the target unvested performance units reported in the table, the number of performance units outstanding and the market value thereof as of December 31, 2017 would have been twice the amounts reflected in the table.
(2)Mr. Barron’s restricted NuStar Energy units consist of: 950 restricted units granted December 16, 2013; 2,862 restricted units granted December 19, 2014; 6,000 restricted units granted November 16, 2015; 8,800 restricted units granted November 16, 2016; and 16,660 restricted units granted November 16, 2017. All of Mr. Barron’s NuStar Energy restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.
(3)Mr. Barron’s restricted NuStar GP Holdings units consist of: 688 restricted units granted December 16, 2013; 1,922 restricted units granted December 19, 2014; 4,380 restricted units granted November 16, 2015; 7,200 restricted units granted November 16, 2016; and 13,315 restricted units granted November 16, 2017. All of Mr. Barron’s NuStar GP Holdings restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.
(4)Mr. Shoaf’s target number of NuStar Energy performance units consist of: 1,313 units awarded January 29, 2015; 4,156 units awarded February 24, 2016; and 4,776 units awarded February 23, 2017. The performance units vest in accordance with the description in footnote (1) above.
(5)Mr. Shoaf’s restricted NuStar Energy units consist of: 637 restricted units granted December 16, 2013; 1,444 restricted units granted December 19, 2014; 2,790 restricted units granted November 16, 2015; 3,936 restricted units granted November 16, 2016; and 7,295 restricted units granted November 16, 2017. All of Mr. Shoaf’s NuStar Energy restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.
(6)Mr. Shoaf’s restricted NuStar GP Holdings units consist of: 461 restricted units granted December 16, 2013; 970 restricted units granted December 19, 2014; 2,058 restricted units granted November 16, 2015; 3,232 restricted units granted November 16, 2016; and 5,830 restricted units granted November 16, 2017. All of Mr. Shoaf’s NuStar GP Holdings restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.
(7)Ms. Brown’s target number of NuStar Energy performance units consist of: 1,414 units awarded January 29, 2015; 4,476 units awarded February 24, 2016; and 5,145 units awarded February 23, 2017. The performance units vest in accordance with the description in footnote (1) above.
(8)Ms. Brown’s restricted NuStar Energy units consist of: 950 restricted units granted December 16, 2013; 1,554 restricted units granted December 19, 2014; 3,003 restricted units granted November 16, 2015; 4,240 restricted units granted November 16, 2016; and 7,860 restricted units granted November 16, 2017. All of Ms. Brown’s NuStar Energy restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.
(9)Ms. Brown’s restricted NuStar GP Holdings units consist of: 688 restricted units granted December 16, 2013; 1,044 restricted units granted December 19, 2014; 2,217 restricted units granted November 16, 2015; 3,480 restricted units granted November 16, 2016; and 6,280 restricted units granted November 16, 2017. All of Ms. Brown’s NuStar GP Holdings restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

(10)Mr. Oliver’s target number of NuStar Energy performance units consist of: 996 units awarded January 29, 2015; 3,152 units awarded February 24, 2016; and 3,624 units awarded February 23, 2017. The performance units vest in accordance with the description in footnote (1) above.
(11)Mr. Oliver’s restricted NuStar Energy units consist of: 671 restricted units granted December 16, 2013; 1,094 restricted units granted December 19, 2014; 2,115 restricted units granted November 16, 2015; 2,984 restricted units granted November 16, 2016; and 4,615 restricted units granted November 16, 2017. All of Mr. Oliver’s NuStar Energy restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.
(12)Mr. Oliver’s restricted NuStar GP Holdings units consist of: 486 restricted units granted December 16, 2013; 736 restricted units granted December 19, 2014; 1,560 restricted units granted November 16, 2015; 2,452 restricted units granted November 16, 2016; and 3,690 restricted units granted November 16, 2017. All of Mr. Oliver’s NuStar GP Holdings restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.
(13)Mr. Truby’s target number of NuStar Energy performance units consist of: 664 units awarded July 23, 2015; 2,224 units awarded February 24, 2016; and 2,556 units awarded February 23, 2017. The performance units vest in accordance with the description in footnote (1) above.
(14)Mr. Truby’s restricted NuStar Energy units consist of: 747 restricted units granted December 16, 2013; 1,018 restricted units granted December 19, 2014; 1,491 restricted units granted November 16, 2015; 2,104 restricted units granted November 16, 2016; and 4,290 restricted units granted November 16, 2017. All of Mr. Truby’s NuStar Energy restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.
(15)Mr. Truby’s restricted NuStar GP Holdings units consist of: 1,101 restricted units granted November 16, 2015; 1,728 restricted units granted November 16, 2016; and 3,430 restricted units granted November 16, 2017. All of Mr. Truby’s NuStar GP Holdings restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.


OPTION EXERCISES AND UNITS VESTED
DURING THE YEAR ENDED DECEMBER 31, 2017
The following table provides information regarding the vesting of restricted units and performance units held by our NEOs during 2017. None of our NEOs had outstanding unit option awards during 2017.
Unit2023;” “Outstanding Equity Awards
Name
Number of Units
Acquired on Vesting (#)
Value Realized
on Vesting ($)(1)
Barron
27,269(2)
1,106,122
Shoaf
13,734(3)
553,181
Brown
15,654(4)
616,374
Oliver
10,988(5)
430,859
Truby
6,074(6)
237,937

(1)The value realized on vesting of NuStar Energy restricted units and performance units was calculated by multiplying the closing price of NuStar Energy common units on the NYSE on the date of vesting by the number of NuStar Energy units vested. The value realized on vesting of NuStar GP Holdings restricted units was calculated by multiplying the closing price of NuStar GP Holdings common units on the NYSE on the date of vesting by the number of NuStar GP Holdings units vested. In the case of the December 16, 2017 vesting date, which was not a trading day, the value realized was calculated using the NuStar Energy or NuStar GP Holdings closing price, as applicable, on the preceding trading day. The closing prices on the applicable dates are as follows:

Closing Prices for 2017 Vestings
DateNuStar Energy Closing Price ($)
January 26, 201755.31
November 16, 201729.22
December 15, 201730.54
December 19, 201730.18
DateNuStar GP Holdings Closing Price ($)
November 16, 201715.65
December 15, 201715.05
December 19, 201714.50

(2)Mr. Barron's restricted NuStar Energy units vested in 2017 as follows: 4,200 units on November 16, 2017; 950 units on December 16, 2017; and 2,121 units on December 19, 2017. Mr. Barron's restricted NuStar GP Holdings units vested in 2017 as follows: 3,260 units on November 16, 2017; 688 units on December 16, 2017; and 1,439 units on December 19, 2017. On January 26, 2017, 14,611 of Mr. Barron’s NuStar Energy performance units vested.
(3)Mr. Shoaf’s restricted NuStar Energy units vested in 2017 as follows: 1,914 units on November 16, 2017; 637 units on December 16, 2017; and 1,190 units on December 19, 2017. Mr. Shoaf’s restricted NuStar GP Holdings units vested in 2017 as follows: 1,494 units on November 16, 2017; 461 units on December 16, 2017; and 809 units on December 19, 2017. On January 26, 2017, 7,229 of Mr. Shoaf’s NuStar Energy performance units vested.
(4)Ms. Brown’s restricted NuStar Energy units vested in 2017 as follows: 2,061 units on November 16, 2017; 950 units on December 16, 2017; and 1,523 units on December 19, 2017. Ms. Brown’s restricted NuStar GP Holdings units vested in 2017 as follows: 1,609 units on November 16, 2017; 688 units on December 16, 2017; and 1,038 units on December 19, 2017. On January 26, 2017, 7,785 of Ms. Brown’s NuStar Energy performance units vested.
(5)Mr. Oliver’s restricted NuStar Energy units vested in 2017 as follows: 1,451 units on November 16, 2017; 671 units on December 16, 2017; and 1,114 units on December 19, 2017. Mr. Oliver’s restricted NuStar GP Holdings units vested in 2017 as follows: 1,133 units on November 16, 2017; 486 units on December 16, 2017; and 733 units on December 19, 2017. On January 26, 2017, 5,400 of Mr. Oliver’s NuStar Energy performance units vested.
(6)Mr. Truby’s restricted NuStar Energy units vested in 2017 as follows: 1,023 units on November 16, 2017; 747 units on December 16, 2017; and 841 units on December 19, 2017. On November 16, 2017, 799 of Mr. Truby’s restricted NuStar GP Holdings units vested. On January 26, 2017, 2,664 of Mr. Truby’s NuStar Energy performance units vested.



POST-EMPLOYMENT COMPENSATION

PENSION BENEFITS
FOR THE YEAR ENDED DECEMBER 31, 2017
We maintain a noncontributory defined benefit pension plan (the Pension Plan) in which most of our employees are eligible to participate and under which contributions by individual participants are neither required nor permitted. We also maintain a noncontributory, non-qualified excess pension plan (the Excess Pension Plan), which provides supplemental pension benefits to certain highly compensated employees. The Excess Pension Plan provides eligible employees with additional retirement savings opportunities that cannot be achieved with tax-qualified plans due to the Code’s limits on (1) annual compensation that can be taken into account under qualified plans or (2) annual benefits that can be provided under qualified plans.
The following table provides information regarding the accumulated benefits of our NEOs under our pension plans during the year ended December 31, 2017.
NamePlan Name
Number of Years
Credited Service
Present Value of
Accumulated
Benefit ($)(1)
Payments During Last
Fiscal Year ($)
BarronPension Plan
(2)
366,056
—
Excess Pension Plan
(2)
610,215
—
ShoafPension Plan
(2)
483,611
—
Excess Pension Plan
(2)
482,321
—
BrownPension Plan
(2)
484,661
—
Excess Pension Plan
(2)
611,118
—
OliverPension Plan
(2)
336,416
—
Excess Pension Plan
(2)
376,814
—
TrubyPension Plan
(2)
465,657
—
Excess Pension Plan
(2)
132,458
—
(1)The present values stated in the table above were calculated using the same interest rates and mortality tables we use for our financial reporting. The present values as of December 31, 2017 were determined using plan-specific discount rates (3.73% for the Pension Plan and 3.42% for the Excess Pension Plan) and the plans’ earliest unreduced retirement age (age 62). The present values reflect post-retirement mortality rates based on the RP2006 generational mortality table projected using scale MP2016. No decrements were included for pre-retirement termination, mortality or disability. Where applicable, lump sums were determined based on a 3.23% interest rate and the mortality table prescribed by the IRS in Rev. Ruling 2007-67 and updated by IRS Notices 2008-85 and 2013-49 for distributions in the years 2009-2017.
(2)As of December 31, 2013, the final average pay formula used in the Pension Plan and the Excess Pension Plan, which was based on years of service and compensation during service, was frozen. Benefits for service after December 31, 2013 accrue under a cash balance formula described below. The number of years of credited service under the final average pay formula and the cash balance formula for each of our NEOs under the Pension Plan and the Excess Pension Plan are set forth below.

NamePlan Name
Number of Years
Credited Service - Final Average Pay Formula (Frozen as of
December 31, 2013)
Number of Years
Credited Service - Cash Balance Formula
BarronPension Plan7.5
 17.0
Excess Pension Plan13.0
 17.0
ShoafPension Plan7.5
 32.5
Excess Pension Plan28.5
 32.5
BrownPension Plan6.7
 20.3
Excess Pension Plan6.7
 20.3
OliverPension Plan6.8
 20.7
Excess Pension Plan6.8
 20.7
TrubyPension Plan7.5
 25.0
Excess Pension Plan7.5
 25.0
Pension Plan
The Pension Plan is a qualified, non-contributory defined benefit pension plan that became effective as of July 1, 2006. The Pension Plan covers substantially all of our employees and generally provides retirement income calculated under a cash balance formula (CBF), which is comprised of contribution credits based on age and years of vesting service and interest credits. Employees become fully vested in their CBF benefits upon attaining three years of vesting service. Prior to January 1, 2014, eligible employees were covered under either the CBF or a defined benefit final average pay formula (FAP) based on years of service and compensation during their period of service, and employees became fully vested in their benefits upon attaining five years of service under the FAP and upon attaining three years of service under the CBF. The Pension Plan was amended to freeze the FAP benefit at December 31, 20132023;” “Option Exercises and on or after January 1, 2014, all employees are covered underUnits Vested During the CBF.
An eligible employee’s benefits under the Pension Plan will be equal to:
1.6% of the employee’s average monthly compensation multiplied by the employee’s years of credited service for service through December 31, 2013 for the FAP benefit plus
the employee’s CBF account balance.
An employee may start receiving his or her benefits under the Pension Plan at any time following his or her separation of service, but must begin receiving benefits by April 1 of the year after the employee attains age 70½. Mr. Shoaf, Ms. Brown and Mr. Truby have attained the Early Retirement Age, which is defined in the Pension Plan as age 55. If an employee with a FAP benefit begins receiving benefits after the Early Retirement Age and before age 62, the FAP benefit amount will be reduced by 4% for each full year between the benefit start date and age 62. If an employee with a FAP benefit begins receiving benefits before the Early Retirement Age, the amount of the FAP benefit will be the actuarial equivalent of the lump sum that otherwise would have been payable on the date the employee starts benefits. The CBF benefit amount under the Pension Plan is based on the CBF account balance and, therefore, is not reduced based on the age at which the employee begins receiving benefits.
Excess Pension Plan
The Excess Pension Plan, which became effective July 1, 2006, provides benefits to our eligible employees whose pension benefits under the Pension Plan and the Valero Energy Pension Plan, where applicable, are subject to limitations under the Code. The Excess Pension Plan is an excess benefit plan as contemplated under ERISA for those benefits provided in excess of the maximum amount allowable under Section 415 of the Code. Benefits provided as a result of other statutory limitations are limited to a select group of management or highly compensated employees. The Excess Pension Plan is not intended to constitute either a qualified plan under the Code or a funded plan subject to ERISA. For our employees who were eligible to receive a benefit under the Valero Energy Excess Pension Plan (the Predecessor Excess Pension Plan) as of July 1, 2006, the Excess Pension Plan assumed the liabilities of the Predecessor Excess Pension Plan and will provide a single, nonqualified defined benefit to eligible employees for their pre-July 1, 2006 benefit accruals under the Predecessor Excess Pension Plan and their post-July 1, 2006 benefit accruals under the Excess Pension Plan.

An eligible employee’s monthly pension under the Excess Pension Plan will be equal to:
1.6% of the employee’s average monthly compensation multiplied by the employee’s years of credited service for service through December 31, 2013, plus
the employee’s CBF benefits, in each case without regard to the limitations imposed by the Code, less
the employee’s Pension Plan benefit.
All of our NEOs participated in the Excess Pension Plan during 2017.

NONQUALIFIED DEFERRED COMPENSATION
FOR THE YEAR ENDED DECEMBER 31, 2017
The following table provides information regarding our contributions and the contributions by each of our NEOs under our non-qualified defined contribution plan, the Excess Thrift Plan, during the year ended December 31, 2017. The table also presents each NEO’s withdrawals, earnings and year-end balances in such plan. Please see the description of our Excess Thrift Plan above in “Compensation Discussion and Analysis-Elements of Executive Compensation-Post-Employment Benefits.”
Name
Executive
Contributions
in 2017 ($)(1)
Registrant
Contributions in
2017 ($)(2)
Aggregate
Earnings/(Losses) in 
2017 ($)(3)
Aggregate
Withdrawals/
Distributions ($)
Aggregate
Balance at
December 31,
2017 ($)(4)
Barron—
 36,316
 (37,400) —
 83,402
 
Shoaf—
 7,226
 (5,798) —
 15,482
 
Brown—
 42,543
 (36,590) —
 75,737
 
Oliver—
 11,392
 (6,711) —
 15,728
 
Truby—
 4,678
 (1,349) —
 3,637
 

(1)The NEOs made no contributions during 2017.
(2)Amounts reported represent our contributions to our Excess Thrift Plan. All of the amounts included in this column are included within the amounts reported as “All Other Compensation” for 2017 in the Summary Compensation Table.
(3)Amounts reported reflect the losses for each NEO’s respective account in our Excess Thrift Plan.
(4)Amounts include the aggregate balance at year end, if any, of each NEO’s respective account in our Excess Thrift Plan and include registrant contributions that were previously reported as compensation to each of the NEOs in the “All Other Compensation” column in the Summary Compensation Table for 2017 and previous years, as applicable.




POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE OF CONTROL
SEC regulations require us to disclose potential payments to an NEO in connection with his or her termination or a change of control of NuStar Energy, other than those amounts disclosed under the headings “Pension Benefits For The Year Ended December 31, 2017” and “Nonqualified Deferred Compensation For The2023;” “Pension Benefits for the Year Ended December 31, 2017” above in this Item 112023;” “Nonqualified Deferred Compensation for the Year Ended December 31, 2023;” “Potential Payments Upon Termination or amounts pursuant to arrangements that do not discriminate in favorChange of executive officersControl;” “Pay Versus Performance;” “Director Compensation;” “Corporate Governance-Compensation Committee Interlocks and are generally available to salaried employees. The following narrativeInsider Participation;” “Compensation Committee Report;” “Corporate Governance-Board Structure and table provide the required disclosures.
None of our NEOs have employment agreements, other than the change of control severance agreements described below. As a result, in the event of a termination, retirement, death or disability that does not occur in connection with a change of control, an NEO will only receive the compensation or benefits to which he or she would already be entitled under the terms of, as applicable, the defined contribution, defined benefit, medical or long-term incentive plans. Therefore, these scenarios are not presented in the table below.
Each of our NEOs has entered into a change of control severance agreement with NuStar EnergyGovernance;” and our wholly owned subsidiary, NuStar Services Co. These agreements seek to ensure the continued availability of these executives in the event of a “change of control” (described below). The agreements contain tiers of compensation and benefits based on each NEO’s position. Each tier corresponds to a certain “severance multiple” used to calculate cash severance and other benefits to be provided under the agreements. The following table sets forth the severance multiple applicable to each NEO, based on his or her current officer position.
NameApplicable Officer PositionSeverance Multiple
BarronChief Executive Officer3
ShoafExecutive Vice President2.5
BrownExecutive Vice President2.5
OliverSenior Vice President2
TrubySenior Vice President2
If a change of control occurs, the agreements become operative for a fixed three-year period. The agreements provide generally that the NEO’s terms of employment will not be adversely changed during the three-year period after a change of control. In addition, any outstanding unit options held by the NEO will automatically vest, restrictions applicable to any outstanding restricted units held by the NEO will lapse and any unvested performance units held by the NEO will fully vest and become payable at 200% of target. The NEOs also are entitled to receive a payment in an amount sufficient to make the NEO whole for any excise tax on excess parachute payments imposed under Section 4999“Corporate Governance–Committees of the Code, as set forth in the table below. Each agreement subjects the NEO to obligations of confidentiality, both during the term and after termination, for secret and confidential information that the NEO acquired during his or her employment relating to NuStar Energy, NuStar Services Co and affiliated companies.Board.”
For purposes of these agreements, a “change of control” means any of the following (subject to additional particulars as stated in the agreements):
the acquisition by an individual, entity or group of beneficial ownership of 40% of NuStar GP Holdings’ voting interests;
the failure of NuStar GP Holdings to control NuStar GP, LLC, NuStar Energy’s general partner, Riverwalk Logistics, L.P., or all of the general partner interests of NuStar Energy;
Riverwalk Logistics, L.P. ceases to be NuStar Energy’s general partner or Riverwalk Logistics, L.P. is no longer controlled by either NuStar GP, LLC or one of its affiliated companies;
the acquisition of more than 50% of all voting interests of NuStar Energy then outstanding;
certain consolidations or mergers of NuStar GP Holdings;
certain consolidations or mergers of NuStar Energy;
the sale of all or substantially all of the assets of NuStar GP Holdings to anyone other than its affiliated companies;
the sale of all or substantially all of the assets of NuStar Energy to anyone other than its affiliated companies; or
a change in the composition of the NuStar GP Holdings board of directors so that fewer than a majority of those directors are “incumbent directors” as defined in the agreements.

In the agreements, “cause” is defined to mean, generally, the willful and continued failure of the NEO to perform substantially his or her duties, or the willful engaging by the NEO in illegal or gross misconduct that is materially and demonstrably injurious to NuStar Energy, NuStar Services Co or any affiliated company.
“Good reason” is defined to mean, generally:
a diminution in the NEO’s position, authority, duties or responsibilities;
failure of the successor of NuStar Energy or NuStar Services Co to assume and perform under the agreement; and
relocation of the NEO or increased travel requirements.
Except as otherwise noted, the values in the table below assume that a change of control occurred on December 31, 2017 and that the NEO’s employment terminated on that date.
Under the change of control severance agreements, if an NEO’s employment is terminated for “cause” following a change of control, the NEO will not receive any additional benefits or compensation as a result of the termination and will only receive accrued salary or vacation pay that remained unpaid through the date of termination and any other benefits that the NEO would already be entitled to receive, if any. Therefore, there is no presentation of termination for “cause” in the table below.
Each of our NEOs has agreed and acknowledged that the Merger will not be deemed to trigger a “change of control” as defined under any NuStar Energy or NuStar GP Holdings plan or award, and has waived any rights to vesting, payment or other benefit thereunder that would arise upon a “change of control,” to which he or she might otherwise have been entitled.


Executive Benefits and
Payments(1)
Termination of Employment by the Employer Other Than 
for “Cause,” Death or Disability, or by the Executive for 
“Good Reason” ($)(2)
Termination of Employment 
because of Death or
Disability ($)(3)
Termination by the Executive Other 
Than for “Good 
Reason” ($)(4)
Continued
Employment
Following Change 
of Control ($)(5)
Salary (1)
       
Barron 1,776,750
  —
  —
  —
 
Shoaf900,500  —  —  —  
Brown970,000  —  —  —  
Oliver656,000  —  —  —  
Truby610,000  —  —  —  
Bonus (1)
       
Barron 3,200,000
  800,000
  800,000
  800,000
 
Shoaf1,125,432  321,552  321,552  321,552  
Brown1,212,005  346,287  346,287  346,287  
Oliver784,761  261,587  261,587  261,587  
Truby630,000  210,000  210,000  210,000  
Pension and Excess Pension Benefits       
Barron 424,576
  —
  —
  —
 
Shoaf247,975  —  —  —  
Brown348,378  —  —  —  
Oliver142,462  —  —  —  
Truby137,743  —  —  —  
Contributions under Defined Contribution Plans       
Barron 157,547
  —
  —
  —
 
Shoaf58,564  —  —  —  
Brown139,321  —  —  —  
Oliver55,184  —  —  —  
Truby41,755  —  —  —  
Health and Welfare Plan Benefits (6)
      
Barron 43,932
  —
  —
  —
 
Shoaf53,709  —  —  —  
Brown28,662  —  —  —  
Oliver42,209  —  —  —  
Truby27,566  —  —  —  


Executive Benefits and
Payments(1)
Termination of Employment by the Employer Other Than 
for “Cause,” Death or Disability, or by the Executive for 
“Good Reason” ($)(2)
Termination of Employment 
because of Death or
Disability ($)(3)
Termination by the Executive Other 
Than for “Good 
Reason” ($)(4)
Continued
Employment
Following Change 
of Control ($)(5)
Accelerated Vesting of Unit Options            
Barron —
  —
  —
  —
 
Shoaf —
  —
  —
  —
 
Brown —
  —
  —
  —
 
Oliver —
  —
  —
  —
 
Truby —
  —
  —
  —
 
Accelerated Vesting of Restricted Units (7)
       
Barron 1,488,225
  1,488,225
  1,488,225
  1,488,225
 
Shoaf679,306  679,306  679,306  679,306  
Brown742,561  742,561  742,561  742,561  
Oliver483,903  483,903  483,903  483,903  
Truby387,284  387,284  387,284  387,284  
Accelerated Vesting of Performance Units (8)
       
Barron 1,346,552
  1,346,552
  1,346,552
  1,346,552
 
Shoaf613,676  613,676  613,676  613,676  
Brown660,996  660,996  660,996  660,996  
Oliver465,542  465,542  465,542  465,542  
Truby326,096  326,096  326,096  326,096  
280G Tax Gross-Up (9)
       
Barron 3,312,255
  —
  —
  —
 
Shoaf1,350,583  —  —  —  
Brown1,388,646  —  —  —  
Oliver—  —  —  —  
Truby777,507  —  —  —  
Totals      
Barron 11,749,837
  3,634,777
  3,634,777
  3,634,777
 
Shoaf5,029,745  1,614,534  1,614,534  1,614,534  
Brown5,490,569  1,749,844  1,749,844  1,749,844  
Oliver2,630,061  1,211,032  1,211,032  1,211,032  
Truby2,937,951  923,380  923,380  923,380  
(1)Per SEC regulations, for purposes of this analysis we assumed each NEO’s compensation at the time of each triggering event to be as stated below. The listed salary is the NEO’s actual annualized rate of pay as of December 31, 2017. The listed bonus amount (referred to in these footnotes as the Highest Annual Bonus) represents the highest bonus earned by the executive with respect to any of the fiscal years 2014, 2015 and 2016 (the three full fiscal years prior to the date of the assumed change of control) or the most recent fiscal year (2017):

NameAnnual Salary ($)Highest Annual Bonus ($)
Barron592,250  800,000  
Shoaf360,200  321,552  
Brown388,000  346,287  
Oliver328,000  261,587  
Truby305,000  210,000  
(2)The change of control severance agreements provide that if the employer terminates the NEO’s employment (other than for “cause,” death or “disability,” as defined in the agreements) or if the NEO terminates his or her employment for “good reason,” as defined in the agreements, the NEO is generally entitled to receive the following:

(A) a lump sum cash payment equal to the sum of:
(i)accrued and unpaid compensation through the date of termination, including a pro-rata annual bonus based on the Highest Annual Bonus;
(ii)the NEO’s severance multiple multiplied by the sum of the NEO’s annual base salary plus the NEO’s Highest Annual Bonus;
(iii)the amount of the excess of the actuarial present value of the pension benefits (qualified and nonqualified) the NEO would have received for an additional number of years of service equal to the NEO’s severance multiple over the actuarial present value of the NEO’s actual pension benefits; and
(iv)the equivalent of employer contributions under the tax-qualified and supplemental defined contribution plans for the number of years equal to the NEO’s severance multiple;
(B) continued welfare benefits for a number of years equal to the NEO’s severance multiple; and
(C) vesting of all outstanding equity incentive awards on the date of the change of control, as described above.
(3)If the NEO’s employment is terminated by reason of his or her death or disability, then his or her estate or beneficiaries will be entitled to receive a lump sum cash payment equal to any accrued and unpaid salary and vacation pay plus a bonus equal to the Highest Annual Bonus earned by the NEO (prorated to the date of termination). In addition, in the case of disability, the NEO would be entitled to any disability and related benefits at least as favorable as those provided by us under our plans and programs during the 120-days prior to the NEO’s termination of employment. In addition, all outstanding equity incentive awards will automatically vest on the date of the change of control, as described above.
(4)If the NEO voluntarily terminates his or her employment other than for “good reason,” then he or she will be entitled to a lump sum cash payment equal to any accrued and unpaid salary and vacation pay plus a bonus equal to the Highest Annual Bonus earned by the NEO (prorated to the date of termination). In addition, all outstanding equity incentive awards will automatically vest on the date of the change of control, as described above.
(5)The change of control severance agreements provide for a three-year term of employment following a change of control. The agreements generally provide that the NEO will continue to receive a salary and bonus at least as favorable as the highest salary received during the past 12 months and the highest bonus received during the past three years and will continue to receive benefits on terms at least as favorable as in effect prior to the change of control. Accordingly, no additional amounts are shown for salary, pension and excess pension benefits, contributions under defined contribution plans and health and welfare plan benefits because those amounts would remain as in effect at the time of a change of control. The amount shown as bonus reflects each NEO’s Highest Annual Bonus. In addition, all outstanding equity incentive awards will automatically vest on the date of the change of control, as described above.
(6)
The NEO is entitled to coverage under the welfare benefit plans (e.g., health, dental, etc.) for a number of years following the date of termination equal to the NEO’s severance multiple.
(7)The amounts stated in the table represent the gross value of previously unvested restricted units, derived by multiplying (x) the number of units whose restrictions lapsed because of the change of control, times (y) (as applicable) $29.95 (the closing price of NuStar Energy’s common units on the NYSE on December 29, 2017, the last trading day of 2017) or $15.70 (the closing price of NuStar GP Holdings’ common units on the NYSE on December 29, 2017, the last trading day of 2017).
(8)The amounts stated in the table represent the product of (x) the number of performance units whose vesting was accelerated because of the change of control, times (y) 200%, times (z) $29.95 (the closing price of NuStar Energy’s common units on the NYSE on December 29, 2017, the last trading day of 2017).
(9)If any payment or benefit is determined to be subject to an excise tax under Section 4999 of the Code, the impacted NEO is entitled to receive an additional payment to adjust for the incremental tax cost of the payment or benefit. However, if it is determined that the NEO is entitled to receive an additional payment to adjust for the incremental tax cost but the value of all payments to the NEO does not exceed 110% of 2.99 times the NEO’s “base amount” (as defined by Section 280G(b)(3) of the Code) (the Safe Harbor Amount), the additional payment will not be made and the amount payable to the NEO will be reduced so that the aggregate value of all payments equals the Safe Harbor Amount.


DIRECTOR COMPENSATION
FOR THE YEAR ENDED DECEMBER 31, 2017
The following table provides a summary of compensation paid for the year ended December 31, 2017 to the directors who served on the Board during 2017. The table shows amounts earned by such persons for services rendered to NuStar GP, LLC in all capacities in which they served during 2017.

Name
Fees Earned or Paid in Cash
($)(1)
Unit Awards
($)(2)
Non-Equity
Incentive Plan
Compensation 
($)(3)
Change in Pension
Value and
Nonqualified
Deferred
Compensation
Earnings 
($)(3)
All Other
Compensation 
($)
TOTAL 
($)
William E. Greehey141,167
 119,977
 N/A
N/A—
261,144
 
Bradley C. Barron
(4) 

 
(4 
) 
 
(4 
) 
(4) 
(4 
) 
(4 
) 
 
J. Dan Bates106,667
 94,994
 N/A
N/A—
201,661
 
Dan J. Hill121,667
 94,994
 N/A
N/A—
216,661
 
Robert J. Munch90,667
 94,994
 N/A
N/A—
185,661
 
W. Grady Rosier97,167
 94,994
 N/A
N/A—
192,161
 
(1)The amounts disclosed in this column exclude reimbursement for expenses for transportation to and from Board meetings and lodging while attending meetings.
(2)The amounts reported for Messrs. Greehey, Bates, Hill and Rosier represent the grant date fair value for the November 16, 2017 grant of restricted NuStar Energy units to them as non-employee directors for the fiscal year ended December 31, 2017 (4,106 restricted units for Mr. Greehey, as Chairman, and 3,251 restricted units for each of Messrs. Bates, Hill, Munch and Rosier) based on the closing price of NuStar Energy’s common units on the NYSE on November 16, 2017 ($29.22). Please see “Compensation Discussion and Analysis-Impact of Accounting and Tax Treatments-Accounting Treatment” above in this Item 11 and Note 23 of the Notes to Consolidated Financial Statements in Item 8 for information regarding the assumptions made in the valuation.
As of December 31, 2017, each director listed in the table above held the following aggregate number of NuStar Energy restricted units. None of the directors had outstanding unit options as of December 31, 2017.
NameAggregate # of Restricted Units
Greehey6,336
Barron*
Bates4,924
Hill4,924
Munch5,989
Rosier4,924
* Mr. Barron’s aggregate holdings are disclosed above in the Outstanding Equity Awards at December 31, 2017 table in this Item 11.
(3)Non-employee directors do not participate in these plans.
(4)Mr. Barron was not compensated for his service as a director of NuStar GP, LLC. His compensation for his services as President and Chief Executive Officer is included above in the Summary Compensation Table.

Directors who are our employees receive no compensation (other than reimbursement of expenses) for serving as directors. The compensation structure for our non-employee directors consists of the following components: (1) an annual cash retainer; (2) an annual restricted unit grant; (3) an additional cash payment for each meeting attended in-person and telephonically; (4) an additional annual cash retainer for each committee chair; (5) an additional annual retainer for the Chairman of the Board, which includes both cash and restricted units; and (6) an additional annual cash retainer for the lead director.
During 2017, the Compensation Committee engaged EPPA to review our non-employee directors’ compensation. Based on its review, EPPA recommended, and our Board and Compensation Committee approved effective July 27, 2017, increasing the annual cash retainer from $60,000 to $70,000 and increasing the value of the annual equity award from $75,000 to $95,000, resulting in the compensation structure for our non-employee directors set forth in the table below.
Non-Employee Director Compensation ComponentAmount
Annual Cash Retainer ($)70,000
Annual Restricted Unit Grant ($ value of restricted units)95,000
Per Meeting Fees (in-person attendance) ($)1,500
Per Meeting Fees (telephonic attendance) ($)500
Annual Audit and Compensation Committee Chair Additional Retainers ($)15,000
Annual Nominating, Governance and Conflicts Committee Chair Additional Retainer ($)10,000
Annual Chairman of the Board Retainer ($25,000 value in restricted units/$50,000 cash)75,000
Annual Lead Director Additional Retainer ($)15,000
As described above, we supplement the cash compensation paid to non-employee directors with an annual grant of restricted NuStar Energy units that vests in equal annual installments over a three-year period. We believe this annual grant of restricted units increases the non-employee directors’ identification with the interests of NuStar Energy’s unitholders through ownership of NuStar Energy common units. Upon a non-employee director’s initial election to the Board, the director will receive a grant of restricted units.
In the event of a “change of control” as defined in the 2000 LTIP, all unvested restricted units previously granted immediately become vested. The 2000 LTIP also contains anti-dilution provisions providing for an adjustment in the number of restricted units that have been granted to prevent dilution of benefits in the event there is a change in the capital structure of NuStar Energy that affects the NuStar Energy units. Each of our directors has agreed and acknowledged that the Merger will not be deemed to trigger a “change of control” as defined under any NuStar Energy or NuStar GP Holdings plan or award, and has waived any rights to vesting, payment or other benefit thereunder that would arise upon a “change of control,” to which he might otherwise have been entitled.



ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS
SECURITY OWNERSHIP OF MANAGEMENT AND DIRECTORS
The following table sets forth information as of February 20, 2018 regarding: (1) NuStar Energy common units, 8.50% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (Series A Preferred Units) and 7.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (Series B Preferred Units); and (2) NuStar GP Holdings common units, in each case beneficially owned (or deemed beneficially owned) by each director, each named executive officer and all of our directors and executive officers as a group. Unless otherwise indicated in the notes to the table, each of the named persons and members of the group has sole voting and investment power with respect to the units shown and none of the units shown are pledged as security. None of the named persons or members of the group beneficially owns (or is deemed to beneficially own) any NuStar Energy 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units.
  NuStar Energy L.P. NuStar GP Holdings, LLC
  Common Units Series A Preferred Units Series B Preferred Units Common Units
Name of
Beneficial Owner (1)
 
Number of Units Beneficially Owned (2)
 
Percentage of Units Beneficially Owned (2)
 
Number of Units Beneficially Owned (2)
 
Percentage of Units Beneficially Owned (2)
 
Number of Units Beneficially Owned (2)
 
Percentage of Units Beneficially Owned (2)
 
Number of Units Beneficially Owned (2)
 
Percentage of Units Beneficially Owned (2)
William E. Greehey (3)
 3,480,533
 3.7% —
 * —
 * 9,178,320
 21.4%
Bradley C. Barron 53,640
 *
 —
 * —
 * 31,540
 *
J. Dan Bates (4)
 33,107
 *
 —
 * —
 * —
 *
Dan J. Hill (5)
 28,149
 *
 —
 * 8,000
 * —
 *
Robert J. Munch 2,406
 *
 1,000
 * —
 * —
 *
W. Grady Rosier (6)
 35,035
 *
 —
 * 12,000
 * —
 *
Mary Rose Brown 59,125
 *
 —
 * —
 * 46,977
 *
Thomas R. Shoaf 25,137
 *
 —
 * —
 * 12,022
 *
Daniel S. Oliver 30,628
 *
 —
 * —
 * 12,920
 *
Michael Truby 16,633
 *
 —
 * —
 * 1,028
 *
                 
All directors and executive officers as a group (13 people) (7)
 3,797,807
 4.1% 1,000 * 20,000
 * 9,286,349
 21.6%
                 
* Indicates that the percentage of beneficial ownership does not exceed 1% of the class.
(1)The business address for all beneficial owners listed above is 19003 IH-10 West, San Antonio, Texas 78257.
(2)As of February 20, 2018, 93,182,030 NuStar Energy common units, 9,060,000 NuStar Energy Series A Preferred Units, 15,400,000 NuStar Energy Series B Preferred Units, 6,900,000 NuStar Energy Series C Preferred Units and 42,953,132 NuStar GP Holdings common units were outstanding. Beneficial ownership is calculated in accordance with Rule 13d-3 of the Exchange Act. Restricted units awarded under NuStar GP, LLC’s long-term incentive plan and phantom units (which we refer to as “restricted units” for purposes of Part III of this Annual Report on Form 10-K) awarded under NuStar GP Holdings’ long-term incentive plan are rights to receive NuStar Energy common units or NuStar GP Holdings common units, respectively, upon vesting and, as such, may not be disposed of or voted until vested. The restricted units do not vest within 60 days after February 20, 2018. Accordingly, the restricted units set forth in the table below are not included in the calculation of beneficial ownership pursuant to Rule 13d-3 and are not reflected in the table above. As described below in Item 13, on February 7, 2018, we, Riverwalk Logistics, L.P., NuStar GP, LLC, Merger Sub, Riverwalk Holdings, LLC and NuStar GP Holdings entered into the Merger Agreement pursuant to which Merger Sub will merge with and into NuStar GP Holdings with NuStar GP Holdings being the surviving entity, such that we will be the sole member of NuStar GP Holdings following the Merger. At the effective time of the Merger, each NuStar GP Holdings common unit outstanding will be converted into the right to receive 0.55 of a NuStar Energy common unit and each award of NuStar GP Holdings restricted units will be converted into an award of NuStar Energy restricted units, in each case as provided in the Merger Agreement.


  Restricted Units Not Reflected in Table Above
Name NuStar Energy L.P. NuStar GP Holdings, LLC
William E. Greehey 6,336
 10,558
Bradley C. Barron 35,272
 27,505
J. Dan Bates 4,924
 —
Dan J. Hill 4,924
 —
Robert J. Munch 5,166
 —
W. Grady Rosier 4,924
 —
Mary Rose Brown 17,607
 13,709
Thomas R. Shoaf 16,102
 12,551
Daniel S. Oliver 11,479
 8,924
Michael Truby 9,650
 6,259
All directors and executive officers as a group (13 people) 140,897
 97,670
(3)The number of NuStar GP Holdings common units shown as beneficially owned by Mr. Greehey includes 385,889 common units owned indirectly by Mr. Greehey through a limited liability company.
(4)The number of NuStar Energy common units shown as beneficially owned by Mr. Bates includes 28,526 common units owned indirectly by Mr. Bates through a trust.
(5)The number of NuStar Energy common units shown as beneficially owned by Mr. Hill includes 600 common units owned indirectly by Mr. Hill through his spouse.
(6)The number of NuStar Energy common units shown as beneficially owned by Mr. Rosier includes an aggregate of 29,215 common units owned indirectly by Mr. Rosier through two trusts.
(7)The number of NuStar Energy common units shown as beneficially owned by all directors and executive officers as a group includes 28,526 common units owned indirectly by Mr. Bates, 600 common units owned indirectly by Mr. Hill and 29,215 common units owned indirectly by Mr. Rosier, as described above. The number of NuStar GP Holdings common units shown as beneficially owned by all directors and executive officers as a group includes 385,889 common units owned indirectly by Mr. Greehey.

ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The following table sets forth information as of December 31, 2017 regarding each entity known to us to be the beneficial owner of more than 5% of NuStar Energy’s outstanding common units, and is based solely upon reports filed by such entities with the SEC.

Name and Address of Beneficial Owner Number of Common Units Beneficially Owned 
Percentage of Common Units Beneficially Owned(1)
NuStar GP Holdings (2)
 10,214,626
 11.0%
OppenheimerFunds, Inc. (3)
 6,732,640
 7.2%
ALPS Advisors, Inc. (4)
 6,571,734
 7.1%

(1)As of December 31, 2017, there were 93,176,683 NuStar Energy common units issued and outstanding.

(2)As of December 31, 2017, NuStar GP Holdings owns these NuStar Energy common units through its wholly owned subsidiaries, NuStar GP, LLC and Riverwalk Holdings, LLC. NuStar GP Holdings controls voting and investment power over the common units through these wholly owned subsidiaries. NuStar GP Holdings’ business address is 19003 IH-10 West, San Antonio, Texas 78257.


(3)As reported on a Schedule 13G/A filed on February 6, 2018, OppenheimerFunds, Inc. (OFI) is an investment adviser that may be deemed to beneficially own, and has shared voting and dispositive power with respect to, 6,732,640 common units. OFI’s business address is 225 Liberty Street, New York, New York 10281.
(4)As reported on a Schedule 13G/A filed on February 6, 2018, ALPS Advisors, Inc. (AAI) is an investment adviser that may be deemed to beneficially own, and has shared voting and dispositive power with respect to, 6,571,734 common units. The 6,571,734 common units that AAI may be deemed to beneficially own include 6,549,442 common units that Alerian MLP ETF (Alerian), an investment company, may be deemed to beneficially own. Alerian has shared voting and dispositive power with respect to the 6,549,442 common units. AAI disclaims beneficial ownership of the common units pursuant to Rule 13d-4 of the Securities Exchange Act of 1934. The business address of AAI and Alerian is 1290 Broadway, Suite 1100, Denver, Colorado 80203.

EQUITY COMPENSATION PLAN INFORMATION
The following table sets forth information as of December 31, 2017 about the equity compensation plan under which securities of NuStar Energy are issuable, which is described in further detail in Note 23 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”

Plan categories 
Number of securities to 
be issued upon exercise of outstanding unit options, warrants and rights (#)
 
Weighted-average
exercise price of outstanding unit options, warrants
and rights ($) (1)
 
Number of securities
remaining for
future issuance
under equity
compensation plans (#)
Equity Compensation Plans approved by security holders (2)
 902,911
 —
 679,045
Equity Compensation Plans not approved by security holders —
 —
 —

(1)No value is included in this column because there were no unit options outstanding as of December 31, 2017 and because restricted units and performance units do not have an exercise price.
(2)The information in this row relates to the 2000 LTIP. See the “Compensation Discussion and Analysis” section of Item 11 above for further details regarding the 2000 LTIP.




ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
TRANSACTIONS WITH MANAGEMENT AND OTHERSRELATED UNITHOLDER MATTERS
In January 2007, our Board adopted a written related person transaction policy that codifies our prior practice. For purposes of the policy, a related person transaction is one that is not available to all employees generally or involves $10,000 or more when aggregated with similar transactions. The policy requires that any related person transaction between NuStar Energy or NuStar GP, LLC and: (1) any vice president, Section 16 officer, director or any other person designated for these purposes as an officer by the Board; (2) any unitholder owning greater than 5% of NuStar Energy, its controlled affiliates or NuStar GP Holdings; (3) any immediate family member of any officer or director; or (4) any entity owned or controlled by any of (1), (2) or (3) (or in which any of (1), (2) or (3) owns a 5% or greater ownership interest or controls such entity) must be approved by the disinterested members of the Board. In addition, the policy requires that the officers and directors have an affirmative obligation to inform and provide updates to our Corporate Secretary regarding his or her immediate family members, as well as any entities in which he or she controls or owns 5% or more.
Please see “Potential Payments upon Termination or Change of Control” in Item 11 for a discussion of our change of control severance agreements with the NEOs.
On December 10, 2007, NuStar Logistics, L.P., our wholly owned subsidiary, entered into a non-exclusive Aircraft Time Sharing Agreement (the Time Share Agreement) with William E. Greehey, Chairman of our Board. The Time Share Agreement provides that NuStar Logistics, L.P. will sublease the aircraft to Mr. Greehey on an “as needed and as available” basis, and will provide a fully qualified flight crew for all of Mr. Greehey’s flights. Mr. Greehey will pay NuStar Logistics, L.P. an amount equal to the maximum amount of expense reimbursement permitted in accordance with Section 91.501(d) of the Aeronautics Regulations of the Federal Aviation Administration and the Department of Transportation, which expenses include and are limited to: fuel oil, lubricants and other additives; travel expenses of the crew, including food, lodging and ground transportation; hangar and tie down costs away from the aircraft’s base of operation; insurance obtained for the specific flight; landing fees, airport taxes and similar assessments; customs, foreign permit and similar fees directly related to the flight; in-flight food and beverages; passenger ground transportation; flight planning and weather contract services; and an additional charge equal to 100% of the costs of the fuel oil, lubricants and other additives. The Time Share Agreement had an initial term of two years, and automatically renews for one-year terms until terminated by either party. The Time Share Agreement was approved by the disinterested members of the Board on December 5, 2007. The Time Share Agreement was amended as of September 4, 2009 to reflect the addition of another aircraft and as of August 18, 2017 to reflect a change in the aircraft owner trustee.
On April 24, 2008, the independent directors of NuStar GP, LLC approved the adoption of a Services Agreement, effective January 1, 2008, between NuStar GP, LLC and NuStar Energy (the Services Agreement). Pursuant to the Services Agreement, NuStar GP, LLC historically furnished all services necessary for the conduct of the business of NuStar Energy, and NuStar Energy reimbursed NuStar GP, LLC for all payroll and related benefit costs, including pension and unit-based compensation costs, other than the expenses allocated to NuStar GP Holdings. The expenses allocated to NuStar GP Holdings under the Services Agreement equaled to $1.1 million (as adjusted), plus 1.0% of NuStar GP, LLC’s domestic employee bonus and unit compensation expense for the applicable fiscal year, subject to adjustment (1) by an annual amount equal to NuStar GP, LLC’s annual merit increase percentage for the most recently completed contract year and (2) for changed levels of services due to expansion of operations through, among other things, expansion of operations, acquisitions or the construction of new businesses or assets. On March 1, 2016, NuStar GP, LLC transferred and assigned to NuStar Services Co, a wholly owned subsidiary of NuStar Energy, employment of all of NuStar GP, LLC’s employees. Our executive officers continue to serve as officers of NuStar GP Holdings and NuStar GP, LLC, and also serve as officers of NuStar Services Co and other NuStar Energy subsidiaries. In connection with the transfer and assignment, we amended and restated the Services Agreement (the Amended and Restated Services Agreement) such that, beginning March 1, 2016, NuStar GP Holdings and NuStar Energy receive all management and administrative services from NuStar Services Co. NuStar Energy reimburses NuStar Services Co for all services provided to NuStar Energy, including payroll and benefit costs, as well as NuStar Energy unit-based compensation costs. NuStar GP Holdings pays NuStar Services Co an administrative services fee of $1.0 million per year, subject to adjustment (1) by an annual amount equal to NuStar Services Co’s annual merit increase percentage for the most recently completed fiscal year and (2) for changed levels of services due to expansion of operations through acquisitions, construction of new businesses or assets or otherwise. For 2017 the administrative services fee was approximately $900,000. Beginning March 1, 2016, NuStar GP Holdings no longer pays 1.0% of our domestic bonus and unit compensation expenses. Instead, NuStar GP Holdings retains the expense associated with any NuStar GP Holdings common unit awards or other compensation that it provides to its officers.

John D. Greehey, an employee, is the son of Mr. Greehey. As such, he is deemed to be a “related person” under Item 404(a) of the SEC’s Regulation S-K. Mr. J. Greehey is a Vice President of certain subsidiaries of NuStar Energy. In 2017, Mr. J. Greehey did not attend any Board or Committee meetings. The aggregate value of compensation paid to Mr. J. Greehey in 2017 was less than $500,000. There were no material differences between the compensation paid to Mr. J. Greehey and the compensation paid to any other employees who hold analogous positions.

RIGHTS OF NUSTAR GP HOLDINGS
Due to its ownership of NuStar GP, LLC and Riverwalk Holdings, LLC, as of December 31, 2017, NuStar GP Holdings indirectly owned:
the general partner interest in NuStar Energy, through its indirect 100% ownership interest in Riverwalk Logistics, L.P.;
100% of the incentive distribution rights issued by us, which entitle NuStar GP Holdings to receive increasing percentages of the cash we distribute; and
10,214,626 NuStar Energy common units.
Certain of our officers also are officers of NuStar GP Holdings. Our Chairman, Mr. Greehey, also is the Chairman of Board and, as of December 31, 2017, beneficially owned approximately 21% of the common units of NuStar GP Holdings. NuStar GP Holdings appoints NuStar GP, LLC’s directors. NuStar GP, LLC’s board is responsible for overseeing NuStar GP, LLC’s role as the owner of the general partner of NuStar Energy. NuStar GP Holdings must also approve matters that have or would reasonably be expected to have a material effect on NuStar GP Holdings’ interests as one of our major unitholders.
NuStar Energy’s partnership agreement requires that NuStar GP, LLC maintain a Conflicts Committee, composed entirely of independent directors, to review and resolve certain potential conflicts of interest between Riverwalk Logistics, L.P. and its affiliates, on the one hand, and NuStar Energy, on the other.
MERGER AGREEMENT
On February 7, 2018, NuStar Energy, Riverwalk Logistics, L.P., NuStar GP, LLC, Merger Sub, Riverwalk Holdings, LLC and NuStar GP Holdings entered into the Merger Agreement pursuant to which Merger Sub will merge with and into NuStar GP Holdings with NuStar GP Holdings being the surviving entity, such that NuStar Energy will be the sole member of NuStar GP Holdings following the Merger. Pursuant to the Merger Agreement and at the effective time of the Merger, NuStar Energy’s partnership agreement will be amended and restated to, among other things, (1) cancel the incentive distribution rights held by the general partner, (2) convert the 2% general partner interest in NuStar Energy held by the general partner into a non-economic management interest and (3) provide the holders of NuStar Energy common units with voting rights in the election of the members of the Board of NuStar GP, LLC at an annual meeting, beginning in 2019.
At the effective time of the Merger, each outstanding NuStar GP Holdings common unit, other than those held by NuStar GP Holdings or its subsidiaries, will be converted into the right to receive 0.55 of a NuStar Energy common unit. All NuStar GP Holdings common units, when converted, will cease to be outstanding and will automatically be cancelled and no longer exist. No fractional NuStar Energy common units will be issued in the Merger; instead, each holder of NuStar GP Holdings’ common units otherwise entitled to receive a fractional NuStar Energy common unit will receive cash in lieu thereof. Furthermore, the 10,214,626 NuStar Energy common units currently owned by NuStar GP Holdings will be cancelled and will cease to exist.
At the effective time of the Merger, each outstanding award of NuStar GP Holdings restricted units will be converted, on the same terms and conditions as were applicable to the awards immediately prior to the Merger, into an award of NuStar Energy restricted units. The number of NuStar Energy restricted units subject to the converted awards will be determined as provided in the Merger Agreement. Each of our executive officers and directors has agreed and acknowledged that the Merger will not be deemed to trigger a “change of control” as defined under any NuStar Energy or NuStar GP Holdings plan or award, and has waived any rights to vesting, payment or other benefit thereunder that would arise upon a “change of control,” to which he or she might otherwise have been entitled.

The Merger Agreement contains customary representations and warranties and covenants by each of the parties. Completion of the Merger is conditioned upon, among other things: (1) approval of the Merger Agreement by the affirmative vote of holders of a Unit Majority, as defined in the Second Amended and Restated Limited Liability Company Agreement of NuStar GP Holdings, as amended; (2) the effectiveness of a registration statement on Form S-4 with respect to the issuance by NuStar Energy of its common units in connection with the Merger; (3) the absence of certain legal injunctions or impediments prohibiting the transactions; (4) the receipt of certain tax opinions from a nationally recognized tax counsel; and (5) the approval for the listing on the New York Stock Exchange of NuStar Energy’s common units to be issued in the Merger.

NuStar Energy entered into a Support Agreement, dated as of February 7, 2018 (the Support Agreement), with Merger Sub, WLG Holdings, LLC, a Texas limited liability company controlled by Mr. Greehey (WLG Holdings), Mr. Greehey (together, WLG Holdings and Mr. Greehey are referred to as the Greehey Unitholders), and, for limited purposes, NuStar GP Holdings, pursuant to which the Greehey Unitholders have agreed to vote in favor of the approval and adoption of the Merger Agreement, the approval of the Merger and any other action required in furtherance thereof submitted for the vote or written consent of NuStar GP Holdings unitholders. The Support Agreement will terminate (1) at the effective time of the Merger, (2) upon the termination of the Merger Agreement as provided therein, or (3) at such time as NuStar Energy and the Greehey Unitholders agree in writing to terminate the Support Agreement.

After the Merger, the NuStar GP, LLC Board is expected to consist of nine members, initially composed of the six members of the NuStar GP, LLC Board and the three independent directors of the board of directors of NuStar GP Holdings, LLC.
DIRECTOR INDEPENDENCE
Our business is managed under the direction of the Board of NuStar GP, LLC, the general partner of Riverwalk Logistics, L.P., the general partner of NuStar Energy. The Board conducts its business through meetings of the Board and its committees. The Board has standing Audit, Compensation and Nominating/Governance & Conflicts Committees. Each committee has a written charter. During 2017, the Board held ten meetings, the Audit Committee held eight meetings, the Compensation Committee held four meetings and the Nominating/Governance & Conflicts Committee held one meeting. No member of the Board attended less than 75% of the meetings of the Board and committees during the period in which he was a member during 2017.
INDEPENDENT DIRECTORS
The Board has one member of management, Mr. Barron, President and Chief Executive Officer, and five non-management directors. As a limited partnership, NuStar Energy is not required to have a majority of independent directors. However, the Board has determined that four of five of its current non-management directors meet the independence requirements of the NYSE listing standards as set forth in the NYSE Listed Company Manual. The independent directors are: Mr. Bates, Mr. Hill, Mr. Munch and Mr. Rosier.
Mr. Greehey, Chairman of the Board, also serves as the Chairman of the NuStar GP Holdings board of directors and, as of December 31, 2017, beneficially owned approximately 21% of the common units of NuStar GP Holdings. Mr. Greehey is not an independent director under the NYSE’s listing standards.
Mr. Barron has been President and Chief Executive Officer of NuStar GP, LLC since January 2014. Mr. Barron also serves as President and Chief Executive Officer of NuStar GP Holdings. As a member of management, Mr. Barron is not an independent director under the NYSE’s listing standards.
The Audit, Compensation and Nominating/Governance & Conflicts Committees of the Board are each composed entirely of directors who meet the independence requirements of the NYSE listing standards. Each member of the Audit Committee also meets the additional independence standards for Audit Committee members set forth in the regulations of the SEC. For further information about the committees, see also Item 10 and Item 11 above.
INDEPENDENCE DETERMINATIONS
Under the NYSE’s listing standards, no director qualifies as independent unless the Board affirmatively determines that the director has no material relationship with NuStar Energy. Based upon information requested annually from and provided by each director concerning their background, employment and affiliations, including commercial, industrial, banking, consulting, legal, accounting, charitable and familial relationships, the Board has determined that, other than being a director of NuStar GP, LLC, a unitholder of NuStar Energy and/or a unitholder of NuStar GP Holdings, each of the independent directors named above has either no relationship with NuStar Energy, either directly or as a partner, equityholder or officer of an organization that has a relationship with NuStar Energy, or has only immaterial relationships with NuStar Energy, and is therefore independent under the NYSE’s listing standards.
As provided for under the NYSE listing standards, the Board has adopted categorical standards or guidelines to assist the Board in making its independence determinations with respect to each director. Under the NYSE listing standards, immaterial relationships that fall within the guidelines are notInformation required to be disclosed inunder this Annual Report on Form 10-K.Item 12. is incorporated by reference to the following sections of our Proxy Statement: “Security Ownership.”


A relationship falls within the guidelines adopted by the Board if it:
is not a relationship that would preclude a determination of independence under Section 303A.02(b) of the NYSE Listed Company Manual;ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
consists of charitable contributions by NuStar Energy to an organization where a director is an executive officer and does not exceed the greater of $1 million or 2% of the organization’s gross revenue in any of the last three years;
consists of charitable contributions by NuStar Energy to any organization with which a director, or any member of a director’s immediate family, is affiliated as an officer, director or trustee pursuant to a matching gift program of NuStar Energy and made on terms applicable to employees and directors generally, or is in amounts that do not exceed $250,000 per year; and
is notInformation required to be disclosed inunder this Annual Report on Form 10-K.Item 13. is incorporated by reference to the following sections of our Proxy Statement: “Corporate Governance-Director Independence;” “Corporate Governance–Board Structure and Governance;” and “Certain Relationships and Related Party Transactions.”
Our Corporate Governance Guidelines contain the director qualification standards, including the guidelines listed above, and are available on NuStar Energy’s website at www.nustarenergy.com (in the “Investors” section) or are available in print upon request to NuStar GP, LLC’s Corporate Secretary at the address indicated on the cover page of this Annual Report on Form 10-K or corporatesecretary@nustarenergy.com.
PRESIDING DIRECTOR/MEETINGS OF NON-MANAGEMENT DIRECTORS
The Board has designated Mr. Hill to serve as the Presiding Director for meetings of the non-management Board members outside the presence of management.
COMMUNICATIONS WITH THE BOARD, NON-MANAGEMENT DIRECTORS OR PRESIDING DIRECTOR
Unitholders and other interested parties may communicate with the Board, the non-management directors or the Presiding Director by sending a written communication in an envelope addressed to “Board of Directors,” “Non-Management Directors,” or “Presiding Director” in care of NuStar GP, LLC’s Corporate Secretary at the address indicated on the cover page of this Annual Report on Form 10-K or corporatesecretary@nustarenergy.com.
AVAILABILITY OF GOVERNANCE DOCUMENTS
NuStar Energy has posted its Corporate Governance Guidelines, Code of Business Conduct and Ethics, Code of Ethics for Senior Financial Officers and the Charters of the Audit Committee, Compensation Committee and Nominating/Governance & Conflicts Committee on NuStar Energy’s website at www.nustarenergy.com (in the “Investors” section). NuStar Energy’s governance documents are available in print to any unitholder of record who makes a written request to NuStar Energy. Requests must be directed to NuStar GP, LLC’s Corporate Secretary at the address indicated on the cover page of this Annual Report on Form 10-K or corporatesecretary@nustarenergy.com.


ITEM 14.    PRINCIPAL ACCOUNTANT FEES AND SERVICES
Our independent registered public accounting firm is KPMG FEESLLP, San Antonio, Texas, Auditor Firm ID: 185.

The aggregate fees for professional services rendered to us by KPMG for the years ended December 31, 2017 and 2016 were:
Category of Service 2017 2016
Audit fees (1)
 $3,227,500
 $2,633,321
Audit-related fees (2)
 3,000
 —
Tax fees —
 —
All other fees —
 —
Total $3,230,500
 $2,633,321

(1)
Audit fees for 2017 and 2016 were for professional services rendered by KPMG in connection with the audits of our annual financial statements for the years ended December 31, 2017 and 2016, respectively, included in our Annual Reports on Form 10-K, reviews of our interim financial statements included in our Quarterly Reports on Form 10-Q, the audit of the effectiveness of our internal control over financial reporting as of December 31, 2017 and 2016, respectively, and related services that are normally provided by the principal auditor (e.g., comfort letters and assistance with review of documents filed with the SEC).

(2)Audit-related fees for 2017 were for assurance and related services rendered by KPMG that are reasonably related to the performance of the audit or review of our financial statements and are not reported under “Audit fees.”


AUDIT COMMITTEE PRE-APPROVAL POLICY
The Audit Committee has adopted a pre-approval policy to address the pre-approval of all servicesInformation required to be rendered to usdisclosed under this Item 14. is incorporated by our independent auditor and ensure that the provision of any non-audit services does not impair the auditor’s independence. None of the services (described above) for 2017 or 2016 provided by KPMG were approved by the Audit Committee pursuantreference to the pre-approval waiver contained in paragraph (c)(7)(i)(C)following sections of Rule 2-01our Proxy Statement: “KPMG Fees;” and “Audit Committee Pre-Approval Policy.”



103



PART IV


ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1)
(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:
Notes to Consolidated Financial Statements
(2)(2)
Financial Statement Schedules and Other Financial Information. No financial statement schedules are submitted because either they are inapplicable or because the required information is included in the consolidated financial statements or notes thereto.
(3)(3)Exhibits.
The following are filed or furnished, as applicable, as part of this Form 10-K:
 
Exhibit
Number		Description
Exhibit
Number
Description
Incorporated by Reference

to the Following Document
2.01

NuStar Energy L.P.’s Current Report on Form 8-K filed April 11, 2017January 22, 2024 (File No. 001-16417), Exhibit 2.12.01
2.023.01
NuStar Energy L.P.’s Current Report on Form 8-K filed February 8, 2018 (File No. 001-16417), Exhibit 2.1
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
NuStar Energy L.P.’s Current Report on Form 8-K filed March 27, 2007 (File No. 001-16417), Exhibit 3.01
3.03
NuStar Energy L.P.’s Current Report on Form 8-K filed November 30, 2017July 20, 2018 (File No. 001-16417), Exhibit 3.1
3.04NuStar Energy L.P.’s Current Report on Form 8-K filed January 22, 2024 (File No. 001-16417), Exhibit 2.01
3.04
3.05 
NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.8
3.053.06 
NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2007 (File No. 001-16417), Exhibit 3.03
3.063.07 
NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2014 (File No. 001-16417), Exhibit 3.09
3.073.08 
NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.9
3.083.09 
NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2001 (File No. 001-16417), Exhibit 4.1

104
Table of Contents
Exhibit
Number		Description
Exhibit
Number
Description
Incorporated by Reference

to the Following Document
3.10
3.09
NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.10
3.103.11 
NuStar Energy L.P.’s Registration Statement on Form S-1 filed August 14, 2000 (File No. 333-43668), Exhibit 3.7
3.113.12 
NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.16
3.123.13 
NuStar Energy L.P.’s Registration Statement on Form S-1 filed August 14, 2000 (File No. 333-43668), Exhibit 3.9
3.133.14 
NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.14
3.143.15 
NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2007 (File No. 001-16417), Exhibit 3.02
3.153.16 
NuStar Energy L.P.’s Amendment No. 5 to Registration Statement on Form S-1 filed March 29, 2001 (File No. 333-43668), Exhibit 3.10
3.16
First Amendment to First Amended and Restated Limited Liability Company Agreement of Shamrock Logistics GP, LLC, effective 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 3.15
3.17
Second Amendment to First Amended and Restated Limited Liability Company Agreement of Valero GP, LLC, effective as of June 1, 2006
NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2014 (File No. 001-16417), Exhibit 3.20
3.18
Third Amendment to First Amended and Restated Limited Liability Company Agreement of NuStar GP, LLC, dated as of July 29, 2016 and effective as of March 21, 200720, 2018
NuStar Energy L.P.’s QuarterlyCurrent Report on Form 10-Q for quarter ended June 30, 20168-K filed July 20, 2018 (File No. 001-16417), Exhibit 3.013.2
4.01 *
4.01
4.02 
NuStar Energy L.P.’s Current Report on Form 8-K filed July 15, 2002 (File No. 001-16417), Exhibit 4.1
4.024.03
NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.02
4.034.04 
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 

Exhibit
Number
Description
Incorporated by Reference
to the Following Document
4.04
Fourth Supplemental Indenture, dated as of April 4, 2008, to Indenture dated as of July 15, 2002, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, and Wells Fargo Bank, National Association, as Successor Trustee
NuStar Energy L.P.’s Current Report on Form 8-K filed April 4, 2008 (File No. 001-16417), Exhibit 4.2
4.05
Fifth Supplemental Indenture, dated as of August 12, 2010, to Indenture dated as of July 15, 2002, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, and Wells Fargo Bank, National Association, as Successor Trustee
NuStar Energy L.P.’s Current Report on Form 8-K filed August 16, 2010 (File No. 001-16417), Exhibit 4.3
4.06
Sixth Supplemental Indenture, dated as of February 2, 2012, to Indenture dated as of July 15, 2002, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, and Wells Fargo Bank, National Association, as Successor Trustee
NuStar Energy L.P.’s Current Report on Form 8-K filed February 7, 2012 (File No. 001-16417), Exhibit 4.3
4.07
Seventh Supplemental Indenture, dated as of August 19, 2013, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, and Wells Fargo Bank, National Association, as Successor Trustee
NuStar Energy L.P.’s Current Report on Form 8-K filed August 23, 2013 (File No. 001-16417), Exhibit 4.3
4.08
Eighth Supplemental Indenture, dated as of April 28, 2017, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, and Wells Fargo Bank, National Association, as Successor Trustee

NuStar Energy L.P.’s Current Report on Form 8-K filed April 28, 2017 (File No. 001-16417), Exhibit 4.4
4.06 NuStar Energy L.P.’s Current Report on Form 8-K filed May 22, 2019 (File No. 001-16417), Exhibit 4.3
4.09
105
Table of Contents
Exhibit
Number
DescriptionIncorporated by Reference
to the Following Document
4.07NuStar Energy L.P.’s Current Report on Form 8-K filed September 14, 2020 (File No. 001-16417), Exhibit 4.3
4.08NuStar Energy L.P.’s Current Report on Form 8-K filed January 22, 2013 (File No. 001-16417), Exhibit 4.1
4.104.09
NuStar Energy L.P.’s Current Report on Form 8-K filed January 22, 2013 (File No. 001-16417), Exhibit 4.2
4.10NuStar Energy L.P.’s Current Report on Form 8-K filed June 29, 2018 (File No. 001-16417), Exhibit 4.2
10.01
NuStar Energy L.P.’s Current Report on Form 8-K filed OctoberJanuary 31, 20142022 (File No. 001-16417), Exhibit 10.110.01
10.02 

Exhibit
Number
Description
Incorporated by Reference
to the Following Document
10.02
First Amendment to Second Amended and Restated 5-Year Revolving Credit Agreement, dated as of March 19, 2015,June 30, 2023, among NuStar Logistics, L.P., NuStar Energy L.P., JPMorgan ChaseNuStar Pipeline Operating Partnership L.P., Wells Fargo Bank, N.A., as Administrative Agent,National Association, and the Lenderslenders party thereto
NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2015 (File No. 001-16417), Exhibit 10.01

10.03
Second Amendment to Amended and Restated 5-Year Revolving Credit Agreement, dated as of August 22, 2017, among NuStar Logistics, L.P., NuStar Energy L.P., JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders party thereto

NuStar Energy L.P.’s Current Report on Form 8-K filed August 22, 2017June 30, 2023 (File No. 001-16417), Exhibit 10.01
10.0410.03 
NuStar Energy L.P.’s Current Report on Form 8-K filed November 22, 2017June 5, 2020 (File No. 001-16417), Exhibit 10.0110.1
10.04 NuStar Energy L.P.’s Current Report on Form 8-K filed June 5, 2020 (File No. 001-16417), Exhibit 10.2
10.05
NuStar Energy L.P.’s Current Report on Form 8-K filed July 21, 2010 (File No. 001-16417), Exhibit 10.01
10.06
NuStar Energy L.P.’s Current Report on Form 8-K filed June 12, 20125, 2020 (File No. 001-16417), Exhibit 10.0110.4
10.07
NuStar Energy L.P.’s Current Report on Form 8-K filed July 6, 2012June 5, 2020 (File No. 001-16417), Exhibit 10.210.5
106
Table of Contents
Exhibit
Number		DescriptionIncorporated by Reference
to the Following Document
10.08
NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2014 (File No. 001-16417), Exhibit 10.10

10.09
Third Amendment to Letter of Credit Agreement, dated as of March 8, 2013, among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and Mizuho Corporate Bank, Ltd., as Issuing Bank and Administrative Agent
NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2014 (File No. 001-16417), Exhibit 10.11

10.10
Fourth Amendment to Letter of Credit Agreement, dated as of April 19, 2013, among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and Mizuho Corporate Bank, Ltd., as Issuing Bank and Administrative Agent
NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2014 (File No. 001-16417), Exhibit 10.12

10.11
Fifth Amendment to Letter of Credit Agreement, dated as of April 23, 2014, among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and Mizuho Bank, Ltd., as Issuing Bank and Administrative Agent
NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2014 (File No. 001-16417), Exhibit 10.13

10.12
Sixth Amendment to Letter of Credit Agreement, dated as of November 3, 2014, among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and Mizuho Bank, Ltd., as Issuing Bank and Administrative Agent
NuStar Energy L.P.’s Current Report on Form 8-K filed November 6, 2014June 5, 2020 (File No. 001-16417), Exhibit 10.110.6

10.09 
Exhibit
Number
Description
Incorporated by Reference
to the Following Document
10.13
Seventh Amendment to Letter of Credit Agreement, dated as of April 30, 2015, among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and Mizuho Bank, Ltd., as Issuing Bank and Administrative Agent
NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2015 (File No. 001-16417), Exhibit 10.02

10.14
Eighth Amendment to Letter of Credit Agreement, dated as of May 6, 2016, among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and Mizuho Bank, Ltd., as Issuing Bank and Administrative Agent
NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2016 (File No. 001-16417), Exhibit 10.01

10.15
Ninth Amendment to Letter of Credit Agreement, dated as of April 17, 2017, among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and Mizuho Bank, Ltd., as Issuing Bank and Administrative Agent
NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2017 (File No. 001-16417), Exhibit 10.03

10.16
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
10.1710.10
NuStar Energy L.P.’s Current Report on Form 8-K filed September 9, 2014June 5, 2020 (File No. 001-16417), Exhibit 10.110.8
10.1810.11
NuStar Energy L.P.’s Current Report on Form 8-K filed November 6, 2014 (File No. 001-16417), Exhibit 10.3
10.19
Maturity Extension Letter (Amendment No. 2) to Letter of Credit Agreement and Subsidiary Guaranty Agreement dated as of August 19, 2015 among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Issuing Bank and Administrative Agent
NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2015 (File No. 001-16417), Exhibit 10.01

10.20
Maturity Extension Letter (Amendment No. 3) to Letter of Credit Agreement and Subsidiary Guaranty Agreement dated as of July 15, 2016 among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Issuing Bank and Administrative Agent
NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2016 (File No. 001-16417), Exhibit 10.02

10.21
Maturity Extension Letter (Amendment No. 4) to Letter of Credit Agreement and Subsidiary Guaranty Agreement dated as of July 13, 2017 among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Issuing Bank and Administrative Agent
NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2017 (File No. 001-16417), Exhibit 10.02

10.22
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
10.12

Exhibit
Number
Description
Incorporated by Reference
First Supplement and Amendment to Lease Agreement (Series 2011), dated June 1, 2020, among the Following Document
10.23
LetterParish of Credit Agreement dated asSt. James, State of June 5, 2013 amongLouisiana, NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and The Bank of Nova Scotia, as Issuing Bank and Administrative AgentNuStar Pipeline Operating Partnership L.P.
NuStar Energy L.P.’s Current Report on Form 8-K filed June 11, 20135, 2020 (File No. 001-16417), Exhibit 10.0110.10
10.2410.13 
NuStar Energy L.P.’s Current Report on Form 8-K filed November 6, 2014 (File No. 001-16417), Exhibit 10.2
10.25
Purchase and Sale Agreement, dated as of June 15, 2015, among NuStar Energy Services, Inc., NuStar Logistics, L.P., NuStar Pipeline Operating Partnership L.P. and NuStar Supply & Trading LLC, as Originators, NuStar Energy L.P., as Servicer, and NuStar Finance LLC, as Buyer
NuStar Energy L.P.'s Current Report on Form 8-K filed June 19, 2015 (File No. 001-16417), Exhibit 10.1


10.2610.14
NuStar Energy L.P.'s Current Report on Form 8-K filed June 19, 2015 (File No. 001-16417), Exhibit 10.2
10.2710.15 
NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2015 (File No. 001-16417), Exhibit 10.26
10.2810.16
NuStar Energy L.P.’s Current Report on Form 8-K filed September 20, 2017 (File No. 001-16417), Exhibit 10.01
10.2910.17
NuStar Energy L.P.’s Current Report on Form 8-K filed September 20, 2017 (File No. 001-16417), Exhibit 10.02
10.18NuStar Energy L.P.’s Current Report on Form 8-K filed March 28, 2018 (File No. 001-16417), Exhibit 10.01
+10.30
107
Table of Contents
Exhibit
Number
DescriptionIncorporated by Reference
to the Following Document
10.19NuStar Energy L.P.’s Current Report on Form 8-K filed April 29, 2019 (File No. 001-16417), Exhibit 10.1
10.20NuStar Energy L.P.’s Current Report on Form 8-K filed September 3, 2020 (File No. 001-16417), Exhibit 10.01
10.21NuStar Energy L.P.’s Current Report on Form 8-K filed January 31, 2022 (File No. 001-16417), Exhibit 10.02
10.22NuStar Energy L.P.’s Current Report on Form 8-K filed June 30, 2023 (File No. 001-16417), Exhibit 10.02
+10.23* Originally filed as Appendix A to NuStar Energy L.P.’s Proxy StatementAnnual Report on Schedule 14A filedForm 10-K for year ended December 17, 201531, 2017 (File No. 001-16417) and refiled herewith, Exhibit 10.30
+10.3110.24
*
+10.32
Form of 2012 Restricted Unit Award Agreement under the NuStar GP, LLC Third Amended and Restated 2000 Long-Term Incentive Plan
NuStar Energy L.P.’s Current Report on Form 8-K filed January 31, 2012 (File No. 001-16417), Exhibit 10.2
+10.33
Form of 2013 Restricted Unit Award Agreement under the NuStar GP, LLC Third Amended and Restated 2000 Long-Term Incentive Plan
NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 20132017 (File No. 001-16417), Exhibit 10.1510.31
+10.25

Exhibit
Number
Description
Incorporated by Reference
to the Following Document
+10.34
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
+10.26NuStar GP Holdings, LLC’s Quarterly Report on Form 10-Q for quarter ended June 30, 2007 (File No. 001-32040), Exhibit 10.04
+10.3510.27
NuStar GP Holdings, LLC’s Annual Report on Form 10-K for year ended December 31, 2017 (File No. 001-32040), Exhibit 10.46
+10.28NuStar Energy L.P.’s Current Report on Form 8-K filed July 20, 2018 (File No. 001-16417), Exhibit 10.1
+10.29NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2018 (File No. 001-16417), Exhibit 10.06
+10.30NuStar Energy L.P.’s Current Report on Form 8-K filed April 23, 2019 (File No. 001-16417), Exhibit 10.2
+10.31NuStar Energy L.P.’s Current Report on Form 8-K filed April 23, 2019 (File No. 001-16417), Exhibit 10.3
+10.32NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2020 (File No. 001-16417), Exhibit 10.11
+10.33NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2020 (File No. 001-16417), Exhibit 10.43
+10.34NuStar Energy L.P.’s Current Report on Form 8-K filed April 28, 2023 (File No. 001-16417), Exhibit 10.1
108
Table of Contents
Exhibit
Number		DescriptionIncorporated by Reference
to the Following Document
+10.35NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2021 (File No. 001-16417), Exhibit 10.02
+10.36NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2021 (File No. 001-16417), Exhibit 10.35
+10.37NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2021 (File No. 001-16417), Exhibit 10.36
+10.38NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 20172022 (File No. 001-16417), Exhibit 10.0110.03
+10.3610.39
NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 20162022 (File No. 001-16417), Exhibit 10.3110.37
+10.40NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2022 (File No. 001-16417), Exhibit 10.38
+10.3710.41
*
+10.42*
+10.43*
+10.44NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2006 (File No. 001-16417), Exhibit 10.18
+10.3810.45
NuStar Energy L.P.’s Current Report on Form 8-K filed August 4, 2016 (File No. 001-16417), Exhibit 10.1
+10.3910.46
*
+10.40
Form of Non-employee Director Change of Control Waiver Agreement dated effective as of February 7, 2018
*
+10.41
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
+10.47NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2018 (File No. 001-16417), Exhibit 10.04
+10.4210.48
NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2008 (File No. 001-16417), Exhibit 10.30
+10.4310.49
NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2017 (File No. 001-16417), Exhibit 10.02
10.44+10.50
NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 20062018 (File No. 001-16417), Exhibit 10.0310.05
10.4510.51
NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2008 (File No. 001-16417), Exhibit 10.01
10.46
Amended and Restated Services Agreementas Landlord, dated March 1, 2016 between NuStar Energy L.P., NuStar GP Holdings, LLC, NuStar GP, LLC and NuStar Services Company LLC21, 2023
NuStar Energy L.P.’s Current Report on Form 8-K filed March 1, 201621, 2023 (File No. 001-16417), Exhibit 10.210.1
109
Table of Contents
Exhibit
Number		DescriptionIncorporated by Reference
to the Following Document
10.4710.52
NuStar Energy L.P.’s Current Report on Form 8-K filed March 1, 2016 (File No. 001-16417), Exhibit 10.1
10.48
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
10.4910.53 
NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2017 (File No. 001-16417), Exhibit 10.02

10.54
Exhibit
Number
Description
Incorporated by Reference
to the Following Document
10.50
Support Agreement, dated as of February 7, 2018,January 22, 2024, by and among Sunoco LP, NuStar Energy L.P., Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, Riverwalk Holdings, LLC and NuStar GP Holdings, LLCEnergy Transfer LP.
NuStar Energy L.P.’s Current Report on Form 8-K filed February 8, 2018January 22, 2024 (File No. 001-16417), Exhibit 10.110.01
19.01*
12.01
Statement of Computation of Ratio of Earnings to Fixed Charges
*
21.01
21.01
*
22.01*
23.01
*
24.01
*
31.01
*
31.02
*
32.01
**
32.02
**
97.01*
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*



110
Table of Contents
*Filed herewith.
**Furnished herewith.
*Filed herewith.
+
**Furnished herewith.
+Identifies management contracts or compensatory plans or arrangements required to be filed as an exhibit hereto pursuant to Item 15(c)15 of Form 10-K.

An electronic copy of this Form 10-K is available on our website, free of charge, at www.nustarenergy.com
(select the “Investors” link, then the “SEC Filings” link). A paper copy of the Form 10-K also is available without charge to unitholders upon written request at the address below. Copies of exhibits filed as a part of this Form 10-K may be obtained by unitholders of record at a charge of $0.15 per page, minimum $5.00 each request. Direct inquiries to Corporate Secretary, NuStar Energy L.P., 19003 IH-10 West, San Antonio, Texas 78257.78257 or

corporatesecretary@nustarenergy.com.


ITEM 16.    FORM 10-K SUMMARY
Not applicable.

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
Chairman of the Board, President and Chief Executive Officer
February 28, 201822, 2024
By:/s/ Thomas R. Shoaf
Thomas R. Shoaf
Executive Vice President and Chief Financial Officer
February 28, 201822, 2024
By:/s/ Jorge A. del Alamo
Jorge A. del Alamo
Senior Vice President - Chief Information Officer and Controller
February 28, 201822, 2024







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.
 
SignatureTitleDate
SignatureTitleDate
/s/ William E. GreeheyChairman of the BoardFebruary 28, 2018
William E. Greehey
/s/ Bradley C. BarronChairman of the Board, President and
Chief Executive		February 28, 2018
Bradley C. Barron
Officer and Director

(Principal Executive Officer)
February 22, 2024
Bradley C. Barron
/s/ Thomas R. ShoafExecutive Vice PresidentFebruary 28, 2018
Thomas R. Shoaf

and Chief Financial Officer

(Principal Financial Officer)
February 22, 2024
Thomas R. Shoaf
/s/ Jorge A. del AlamoSenior Vice President - Chief Information Officer and Controller
(Principal Accounting Officer)		February 28, 201822, 2024
Jorge A. del Alamo(Principal Accounting Officer)
/s/ J. Dan BatesDirectorFebruary 28, 201822, 2024
J. Dan Bates
/s/ Jelynne LeBlanc BurleyDirectorFebruary 22, 2024
Jelynne LeBlanc Burley
/s/ William B. BurnettDirectorFebruary 22, 2024
William B. Burnett
/s/ Ed A. GrierDirectorFebruary 22, 2024
Ed A. Grier
/s/ Dan J. HillDirectorFebruary 28, 201822, 2024
Dan J. Hill
/s/ Robert J. MunchDirectorFebruary 28, 201822, 2024
Robert J. Munch
/s/ W. Grady RosierDirectorFebruary 28, 201822, 2024
W. Grady Rosier
/s/ Martin Salinas, Jr.DirectorFebruary 22, 2024
Martin Salinas, Jr.
/s/ Suzanne Allford WadeDirectorFebruary 22, 2024
Suzanne Allford Wade


185113