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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, ~~2022~~ 2023

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

For the transition period from to

Commission File Number 1-16417

NuStar Energy L.P.

(Exact name of registrant as specified in its charter)


Delaware						74-2956831
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)

19003 IH-10 West

San Antonio, Texas 78257

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code (210) 918-2000

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Units

New York Stock Exchange

Common units

New York Stock Exchange

8.50% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

NSprA

New York Stock Exchange

7.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

NSprB

New York Stock Exchange

9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

NSprC

New York Stock Exchange

Securities registered pursuant to 12(g) of the Act: None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:

Large accelerated filer

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑

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 þ

The aggregate market value of the common units held by non-affiliates was approximately $1.47 billion based on the last sales price quoted as of June 30, ~~2022~~2023, the last business day of the registrant’s most recently completed second quarter.

The number of common units outstanding as of January 31, ~~2023~~2024 was ~~110~~126,~~903~~532,~~823~~875.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the Proxy Statement for the registrant’s ~~2023~~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.

Tabl e of Contents

NUSTAR ENERGY L.P.

FORM 10-K

TABLE OF CONTENTS

PART I
Items 1., 2. & 7	Business, Properties and Management's Discussion and Analysis of Financial Condition and Results of Operations	3
	Overview	3
	Consolidated Results of Operations	67
	Segments and Results of Operations	79
	Liquidity and Capital Resources	1618
	Human Capital	2527
	Properties	2628
	Rate Regulation	2628
	Environmental, Health, Safety and Security Regulation	2729
	Critical Accounting Policies	29
	Critical Accounting Estimates	31
	New Accounting Pronouncements	3032
	Available Information	3032
Item 1A.	Risk Factors	3033
Item 1B.	Unresolved Staff Comments	4548
Item 3.	Legal Proceedings	45
Item 1C.	Cybersecurity	48
Item 4.	Mine Safety Disclosures	45
Item 3.	Legal Proceedings	49
Item 4.	Mine Safety Disclosures	49
PART II
Item 5.	Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities	4650
Item 6.	Reserved	4751
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	4852
Item 8.	Financial Statements and Supplementary Data	4953
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	97102
Item 9A.	Controls and Procedures	97102
Item 9B.	Other Information	97102
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	97102
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	98103
Item 11.	Executive Compensation	98103
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	98103
Item 13.	Certain Relationships and Related Transactions and Director Independence	98103
Item 14.	Principal Accountant Fees and Services	98103
PART IV
Item 15.	Exhibits and Financial Statement Schedules	99104
Item 16.	Form 10-K Summary	~~105~~111
Signatures		106
SIGNATURES		112

Tabl e of Contents

PART I

Unless otherwise indicated, the terms “NuStar,” “NuStar Energy,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to NuStar Energy L.P., to one or more of our consolidated subsidiaries or to all of them taken as a whole.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION AND OTHER DISCLAIMERS

In this Form 10-K, we make certain forward-looking statements, such as statements regarding our plans, strategies, objectives, expectations, estimates, predictions, projections, assumptions, intentions, resources and the future impact of economic activity and the ~~actions~~demand byfor or supply of crude oil~~-producing~~, ~~nations~~refined onproducts, ~~our~~renewable ~~business~~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, which may cause actual results to differ materially. ~~Please~~See ~~read~~ Item 1A. “Risk Factors” for a discussion of certain of those risks, uncertainties and assumptions.

If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those described in any forward-looking statement. Other unknown or unpredictable factors could also have material adverse effects on our future results. Readers are cautioned not to place undue reliance on this forward-looking information, which is as of the date of this Form 10-K. We do not intend to update these statements unless we are required by the securities laws to do so, and we undertake no obligation to publicly release the result of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.

This Form 10-K contains trade names, trademarks and service marks of others, which are the property of their respective owners. Solely for convenience, trademarks and trade names referred to in this Form 10-K appear without the ® or ™ symbols.

ITEMS 1., 2. and 7. BUSINESS, PROPERTIES AND MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

NuStar Energy L.P. (NuStar Energy) is a publicly traded Delaware limited partnership. Our principal executive offices are located at 19003 IH-10 West, San Antonio, Texas 78257, and our telephone number is (210) 918-2000. Our business is managed under the direction of the board of directors of NuStar GP, LLC (the 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. ~~Our~~As of December 31, 2023, our limited partner interests ~~consist~~consisted of the following:

•~~Common~~common ~~Units~~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)~~; and~~.

~~•Series~~We Dare ~~Cumulative~~primarily ~~Convertible~~engaged ~~Preferred~~in ~~Units~~the ~~(Series~~transportation, Dterminalling ~~Preferred~~and ~~Units)~~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 ~~are~~divide ~~primarily~~our ~~engaged~~operations ininto the ~~transportation,~~following ~~terminalling~~three ~~and~~reportable ~~storage~~business ofsegments: ~~petroleum~~pipeline, ~~products~~storage and ~~renewable~~ fuels ~~and~~marketing. ~~the~~As ~~transportation~~ of ~~anhydrous~~December 31, ~~ammonia.~~2023, Weour ~~also~~assets ~~market~~included ~~petroleum~~9,490 ~~products.~~miles ~~The~~of ~~term~~pipeline ~~“throughput”~~and as63 ~~used~~terminal inand ~~this~~storage ~~document~~facilities, ~~generally~~which ~~refers~~provide toapproximately 49 million barrels of ~~crude~~storage ~~oil,~~capacity. ~~refined~~We ~~product~~conduct orour ~~renewable~~operations ~~fuels~~through orour ~~tons~~wholly ofowned ~~ammonia~~subsidiaries, asprimarily ~~applicable~~NuStar Logistics, ~~that~~L.P. ~~pass~~(NuStar ~~through~~Logistics) ~~our~~and ~~pipelines,~~NuStar ~~terminals~~Pipeline orOperating ~~storage~~Partnership ~~tanks~~L.P. (NuPOP). We generate revenue primarily from:

We divide our operations into the following three reportable business segments: pipeline, storage and fuels marketing. As of December 31, 2022, our assets included 9,465 miles of pipeline and 63 terminal and storage facilities, which provide approximately 49 million barrels of storage capacity. We conduct our operations through our wholly owned subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics) and NuStar Pipeline Operating Partnership L.P. (NuPOP). We generate revenue primarily from:

•tariffs for transportation through our pipelines;

•fees for the use of our terminal and storage facilities and related ancillary services; and

•sales of petroleum products.

Tabl e of Contents

We are focused on:

•maintaining safe, reliable operations, continuing our strong safety and environmental stewardship, and controlling costs;

•improving our existing assets through strategic internal growth projects, including renewable fuel enhancements;

•continuing to self-fund our spending with internally generated cash flows; and

•improving our leverage metrics and redeeming our Series D Preferred Units to further strengthen our balance sheet.

The following factors affect our results of operations:

•economic factors and price volatility;

•industry factors, such as changes in the prices of petroleum products that affect demand or production, or regulatory changes that could increase costs or impose restrictions on operations;

•factors that affect our customers and the markets they serve, such as utilization rates and maintenance turnaround schedules of our refining company customers and drilling activity by our crude oil production customers;

•company-specific factors, such as facility integrity issues, maintenance requirements and outages that impact the throughput rates of our assets; and

•seasonal factors that affect the demand for products ~~transported~~we bytransport and/or ~~stored~~store in our assets and the demand for products we sell.

~~Please~~See ~~read~~ Item 1A. “Risk Factors” for additional discussion on how these factors could affect our operations.

The following map depicts our assets atas of December 31, ~~2022~~2023:

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~~Recent~~Merger ~~Developments~~Agreement

InOn ~~2022~~January 22, we2024, ~~continued~~NuStar toEnergy ~~prioritize~~entered ~~protecting~~into ~~our~~an ~~employees,~~Agreement ~~maintaining~~and ~~safe,~~Plan ~~reliable~~of ~~operations,~~Merger ~~executing~~(the ~~our~~Merger ~~capital~~Agreement) ~~projects~~with ~~and~~Sunoco ~~exercising fiscal discipline~~LP, ~~while~~a ~~also~~Delaware ~~working~~limited topartnership ~~improve~~(Sunoco), ~~our~~Saturn ~~leverage~~Merger ~~metrics~~Sub, ~~and~~LLC, ~~further~~a ~~strengthen~~Delaware ~~our~~limited ~~balance~~liability ~~sheet.~~company ~~Last~~and ~~year,~~a wedirect ~~successfully~~wholly ~~repurchased~~owned ~~6,900,000~~subsidiary of ~~our~~Sunoco ~~Series~~(Merger DSub), ~~Preferred~~Riverwalk ~~Units~~Logistics, ~~sold~~L.P., ~~our~~NuStar ~~Point~~GP, ~~Tupper~~LLC, ~~terminal~~and ~~facility~~Sunoco GP LLC, asa ~~described~~Delaware ~~below,~~limited liability company and ~~extended~~sole ~~the~~general ~~maturity~~partner of ~~our~~Sunoco ~~$1.0~~(the ~~billion~~Sunoco ~~unsecured~~GP). ~~revolving~~The ~~credit~~Merger ~~agreement~~Agreement toprovides ~~April 27~~that, ~~2025.~~among ~~After~~other ~~extending~~things ~~our~~and ~~credit~~on ~~agreement,~~the weterms ~~have~~and nosubject ~~debt~~to ~~maturing~~the ~~until~~conditions ~~2025.~~set Inforth ~~2022~~therein, weSunoco ~~were~~will ~~also~~acquire ~~able~~NuStar toEnergy ~~fund~~in an all-equity transaction by means of ~~our~~a ~~expenses,~~merger ~~distribution~~of ~~requirements~~Merger Sub with and ~~capital~~into ~~expenditures~~NuStar ~~using~~Energy ~~our~~(the ~~internally~~Merger) ~~generated~~with ~~cash~~NuStar ~~flows~~Energy surviving the Merger as a subsidiary of Sunoco.

~~Repurchase~~On ofthe ~~Series~~terms Dand ~~Preferred~~subject ~~Units.~~to Onthe ~~November 16~~conditions set forth in the Merger Agreement, ~~2022~~at the effective time of the Merger (the Effective Time), each NuStar Energy ~~L.P.~~common ~~entered~~unit ~~into~~issued ~~agreements~~and ~~with~~outstanding ~~EIG~~immediately ~~Nova~~prior ~~Equity~~to ~~Aggregator,~~the ~~L.P~~Effective ~~and~~Time FSwill ~~Energy~~be converted into and ~~Power~~shall ~~Fund~~thereafter torepresent ~~repurchase~~the anright ~~aggregate~~to ~~6,900,000~~receive 0.400 of ~~our~~a ~~Series~~common Dunit ~~Preferred~~of ~~Units~~Sunoco and, ~~representing~~if ~~approximately~~applicable, ~~one-third~~cash in lieu of fractional units. In addition, prior to the ~~outstanding~~Effective ~~units~~Time, atwe will declare and pay a ~~price~~special ~~per~~cash ~~unit~~distribution ofto ~~$32.73~~our ~~for~~common anunitholders ~~aggregate~~in ~~purchase~~the ~~price~~amount of $~~225~~0.~~8 million,~~212 ~~including~~per ~~approximately~~common ~~$3.4 million~~unit ~~related~~(the toSpecial ~~accrued~~Distribution) ~~distributions.~~(in ~~These~~addition ~~transactions~~to ~~closed~~continuing onto ~~November 22,~~pay ~~2022~~our ~~and~~quarterly ~~were~~distributions ~~funded~~in ~~with~~the ~~borrowings~~ordinary ~~under~~course, ~~our~~subject ~~$1.0~~to ~~billion~~certain ~~unsecured~~conditions, ~~revolving~~until ~~credit~~the ~~agreement~~Effective Time).

~~Point~~Each ~~Tupper~~Series ~~Terminal Disposition. On April 29~~A, ~~2022,~~B weand ~~sold~~C ~~the~~Preferred ~~equity~~Unit ~~interests~~issued inand ~~our~~outstanding ~~wholly~~immediately ~~owned~~prior ~~subsidiaries~~to ~~that owned our Point Tupper terminal facility in Nova Scotia, Canada (~~the ~~Point~~Effective ~~Tupper~~Time ~~Terminal~~will ~~Operations)~~remain toissued ~~EverWind~~and ~~Fuels~~outstanding ~~for~~from ~~$60.0~~and ~~million~~after (the ~~Point~~Effective ~~Tupper~~Time ~~Terminal~~as ~~Disposition).~~limited ~~The~~partnership ~~terminal~~interests ~~facility had a storage capacity~~ of ~~7.8~~the ~~million~~surviving ~~barrels~~entity ~~and~~having ~~was included in~~ the ~~storage~~same ~~segment.~~terms Weas ~~recognized~~are aapplicable ~~non-cash~~to ~~pre-tax impairment loss of $46.1 million in~~ the ~~first~~applicable ~~quarter~~series of ~~2022.~~NuStar ~~Please~~Energy ~~see~~preferred ~~Note~~unit 4immediately ofprior ~~the Notes~~ to ~~Consolidated~~the ~~Financial~~Effective ~~Statements in Item 8~~Time. ~~“Financial Statements and Supplementary Data” for additional information.~~

~~Trends~~The completion of the Merger is subject to the fulfillment or waiver of certain conditions, including, among others: approval and ~~Outlook~~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).

InThe ~~2023,~~Merger weAgreement ~~are~~contains ~~planning~~termination torights ~~continue~~for toeach ~~execute~~of ~~our~~NuStar ~~plan~~Energy toand ~~strengthen~~Sunoco. ~~our~~Upon ~~balance~~termination ~~sheet.~~of ~~For~~ the ~~full-year~~Merger ~~2023,~~Agreement weunder ~~expect~~specified ~~to fund all of our expenses~~circumstances, ~~distribution~~including ~~requirements~~the ~~and~~termination ~~capital~~by ~~expenditures~~Sunoco ~~using~~in ~~internally~~the ~~generated~~event ~~cash~~of ~~flows,~~an asadverse werecommendation ~~did~~change inby ~~2022~~our ~~and~~Board ~~2021.~~of WeDirectors ~~will~~or ~~continue~~by toNuStar ~~evaluate~~Energy ~~sources of liquidity~~ to ~~facilitate~~accept ~~the~~a ~~planned~~Superior ~~redemption~~Proposal of(as ~~the~~defined ~~remaining Series D Preferred Units~~ in ~~2023~~the ~~and~~Merger ~~2024~~Agreement), ~~which~~NuStar isEnergy ~~several~~would ~~years~~be ~~ahead~~required ~~of the holders’ redemption option in 2028. We plan~~ to ~~continue~~pay toSunoco ~~manage~~a ~~our~~termination ~~operations~~fee ~~with~~of ~~fiscal~~approximately ~~discipline~~$90.3 ~~and to evaluate our capital expenditures~~million.

InConcurrently ~~our~~with ~~pipeline~~the ~~segment~~entry into the Merger Agreement, weNuStar ~~expect~~Energy ~~2023~~and ~~volumes~~Sunoco onentered ~~our~~into ~~Permian~~an ~~Crude~~agreement ~~System~~(the toSupport ~~continue~~Agreement) towith ~~benefit~~Energy ~~from~~Transfer ~~strong~~LP ~~producer~~(Energy ~~volume~~Transfer), ~~growth~~a Delaware limited partnership and the ~~pipeline~~sole ~~capital~~member ~~projects~~of wethe ~~completed~~Sunoco ~~in 2022~~GP. InThe ~~addition~~Support Agreement provides, weamong ~~expect~~other ~~most~~things, ofthat ~~our~~Energy ~~pipeline~~Transfer ~~systems~~will tonot ~~benefit~~transfer ~~from~~its ownership interest in the ~~positive~~Sunoco ~~revenue~~GP, ~~impact~~any of ~~our~~the ~~tariff~~Sunoco ~~indexation~~incentive ~~increases~~distribution ~~effective~~rights inowned ~~July~~by ~~2022,~~it asor ~~well~~any asmaterial portion of the ~~increases~~Sunoco wecommon ~~expect~~units inowned ~~July~~by ~~2023,~~it ~~which~~prior ~~will~~to ~~help~~the usEffective Time. Energy Transfer has also agreed to ~~counterbalance~~be bound by the ~~impact~~terms of ~~inflation~~the onnon-solicitation ~~our~~provisions ~~business~~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.

~~While~~The ~~many~~foregoing ~~terminals~~descriptions inof ~~our~~the ~~storage~~Merger ~~segment~~Agreement ~~are~~and ~~somewhat~~the ~~insulated~~Support ~~from~~Agreement ~~demand~~and ~~volatility~~the ~~due~~transactions tocontemplated ~~contracted~~thereby, ~~rates~~including ~~for~~the ~~storage~~Merger, ~~and~~are ~~minimum volume commitments~~summaries, ~~revenues~~do atnot ~~our~~purport ~~St. James and Corpus Christi North Beach facilities continue~~ to be ~~negatively~~complete ~~impacted by ongoing global economic uncertainty~~ and ~~continued~~are ~~crude~~qualified ~~oil~~in ~~price~~their ~~backwardation.~~entirety ~~Conversely,~~by wereference ~~expect our West Coast region~~ to ~~continue~~the tofull ~~benefit~~text inof ~~2023 from~~ the ~~completion~~Merger ofAgreement ~~renewable~~and ~~fuel~~the ~~projects~~Support Agreement, which ~~continue~~are toincluded ~~expand~~in ~~the~~Item ~~capacity~~15. of“Exhibits ~~our renewable fuels distribution system~~ and ~~further~~Financial ~~solidify~~Statement ~~the~~Schedules” ~~significant~~as ~~role~~Exhibit ~~NuStar~~2.01 ~~plays~~and inExhibit ~~facilitating~~10.54, ~~California’s~~respectively, ~~transition~~and toincorporated ~~low-carbon~~by ~~renewable~~reference ~~fuels~~herein.

IfOther weRecent see a continuation or acceleration of 2022’s inflationary conditions, rising interest rates, supply chain disruptions and tight labor markets, then we may also see higher costs of operating our assets and executing on our capital projects in 2023. Last year, the Russia-Ukraine conflict may have amplified inflation and supply chain constraints that were already constraining and complicating the rebound of the global economy in 2022. In an effort to curb inflation, the U.S. Federal Reserve (the Fed) raised interest rates several times in 2022 and again in early 2023. The Fed is expected to implement additional increases in 2023, which will increase the cost of our variable-rate debt, as well as the cost of our Series A, B and C Preferred Units, which have distribution rates that increase or decrease along with current 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 our tariffs and contracts, should help to counterbalance the impact of inflation on our costs.Developments

~~Our~~Redemptions ~~outlook~~of ~~for~~Series ~~the~~D ~~partnership,~~Preferred ~~both~~Units. ~~overall~~In the second and ~~for~~third ~~any~~quarters of ~~our segments~~2023, ~~may change, as~~ we ~~base~~redeemed ~~our~~all ~~expectations on our continuing evaluation~~ of ~~several factors, many of which are outside~~ our ~~control.~~outstanding ~~These~~Series ~~factors~~D ~~include,~~Cumulative ~~but~~Convertible ~~are~~Preferred ~~not~~Units ~~limited to,~~ (the ~~lingering~~Series ~~impact~~D ofPreferred ~~the~~Units) ~~COVID-19~~for ~~pandemic~~an oraggregate ~~other~~net ~~health~~redemption ~~crises;~~price ~~war~~of ~~and~~$518.7 ~~other~~million. ~~armed~~These ~~conflicts;~~redemptions ~~actions~~were ofprimarily ~~oil-producing~~funded ~~nations;~~with ~~the~~borrowings ~~state~~under ofour ~~the~~Revolving ~~economy~~Credit ~~and~~Agreement, ~~the~~as ~~capital~~defined ~~markets;~~below. ~~changes~~Pursuant to our ~~customers’~~partnership ~~refinery~~agreement, ~~maintenance~~the ~~schedules~~Series ~~and~~D ~~unplanned~~Preferred ~~refinery~~Units ~~downtime;~~were ~~crude oil prices~~cancelled; therefore, the ~~supply~~Series ofD ~~and~~Preferred ~~demand~~Units ~~for~~no ~~petroleum~~longer ~~products,~~represent ~~renewable~~a ~~fuels~~limited ~~and~~partnership ~~anhydrous~~interest. ~~ammonia;~~For ~~demand~~the ~~for~~year ~~our~~ended ~~transportation~~December 31, ~~and~~2023, ~~storage~~we ~~services;~~recorded ~~the~~a ~~availability~~loss ~~and~~of ~~costs~~$0.55 ofper ~~personnel,~~common ~~equipment,~~unit ~~supplies~~attributable ~~and~~to ~~services~~the ~~essential~~redemptions. toSee ~~our~~Note ~~operations;~~17 of the ~~ability~~Notes to ~~obtain~~Consolidated ~~timely~~Financial ~~permitting~~Statements ~~approvals;~~in ~~and~~Item 8. ~~changes~~“Financial inStatements ~~laws~~ and ~~regulations~~Supplementary ~~affecting~~Data” ~~our~~for ~~operations~~more information.

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. We used these proceeds to repay outstanding borrowings under our Revolving Credit Agreement.

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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 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 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for more information.

Sale-Leaseback Transaction. On March 21, 2023, we consummated a sale-leaseback (the Sale-Leaseback Transaction) of our corporate headquarters facility and approximately 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 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 expect to fund all of our 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 ~~2021~~2022 to ~~2020~~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, ~~2021~~2022 filed with the ~~Securities and Exchange Commission (~~SEC) on February 2423, ~~2022~~2023.

The following table presents our consolidated financial results for the year ended December 31, ~~2022~~2023, compared to the year ended December 31, ~~2021~~2022:

	Year Ended December 31,
	2022		2021		Change
	2023		2022		Change
	(Thousands of Dollars, Except Per Unit Data)
Statement of Income Data:
Revenues:
Service revenues	$	1,~~120~~155,~~249~~567	$	1,~~157~~120,~~410~~249	$	~~(37~~35,~~161)~~318
Product sales	~~562~~478,~~974~~620		~~461~~562,~~090~~974		~~101~~(84,~~884~~354)
Total revenues	1,~~683~~634,~~223~~187		1,~~618~~683,~~500~~223		64(49,~~723~~036)
Costs and expenses:
Costs associated with service revenues	~~616~~622,~~867~~671		~~654~~616,~~666~~867		~~(37~~5,~~799)~~804
Costs associated with product sales	~~486~~407,~~947~~793		~~417~~486,~~413~~947		69(79,~~534~~154)
Goodwill impairment loss	—		34,060		(34,060)
Other impairment loss	—		46,122		(46,122)
Other impairment losses	46,122		154,908		(108,786)
General and administrative expenses	129,846		117,116		12,730
General and administrative expenses	117,116		113,207		3,909
Other depreciation and amortization expense	4,728		7,358		(2,630)
Other depreciation and amortization expense	7,358		7,792		(434)
Total costs and expenses	1,165,038		1,274,410		(109,372)
Total costs and expenses	1,274,410		1,382,046		(107,636)
Gain on sale of assets	41,075		—		41,075
Operating income	~~408~~510,~~813~~224		~~236~~408,~~454~~813		~~172~~101,~~359~~411
Interest expense, net	(~~209~~241,~~009~~364)		(~~213~~209,~~985~~009)		4(32,~~976~~355)
Other income, net	2610,~~182~~215		1926,~~644~~182		6(15,~~538~~967)
Income before income tax expense	~~225~~279,~~986~~075		42225,~~113~~986		~~183~~53,~~873~~089
Income tax expense	35,~~239~~412		3,~~888~~239		~~(649)~~2,173
Net income	$	~~222~~273,~~747~~663	$	38222,~~225~~747	$	~~184~~50,~~522~~916
Basic and diluted net income (loss) per common unit	$	0.36	$	(0.99)	$	1.35
Basic and diluted net income per common unit	$	0.72	$	0.36	$	0.36

Consolidated Overview

Net income increased $~~184~~50.59 million for the year ended December 31, ~~2022~~2023, compared to the year ended December 31, ~~2021~~2022, primarily due to higher operating income ~~from~~of ~~our~~$101.4 ~~pipeline~~million, ~~and~~partially ~~fuels~~offset ~~marketing~~by ~~segments,~~an asincrease ~~further~~in ~~discussed~~interest inexpense, ~~the~~net ~~“Segments~~of $32.4 million and ~~Results~~a ofdecrease ~~Operations”~~in ~~section~~other ~~that~~income, ~~follows~~net of $16.0 ~~Net~~million. Operating income ~~also~~ 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 ~~losses~~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, ~~compared~~excluding tothe ~~non-cash~~2022 impairment ~~losses~~loss, ofand ~~$189.0~~higher ~~million~~general and administrative expenses in ~~2021~~2023.

General and administrative expenses increased $3.9 million for the year ended December 31, 2022, compared to the year ended December 31, 2021, mainly due to an increase in compensation costs of $2.8 million and an increase in business travel and employee-related expenses of $1.6 million following post-COVID-19 return to work.7

Interest expense, net decreased $5.0 million for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily due to lower overall debt balances for most of 2022, prior to the repurchase of 6,900,000 of our Series D Cumulative Convertible Preferred Units in November 2022, partially offset by higher interest expense on our variable-rate debt due to higher interest rates in 2022.

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~~Other~~Total ~~income,~~revenues ~~net~~decreased ~~increased~~ $649.50 million for the year ended December 31, ~~2022~~2023, compared to the year ended December 31, ~~2021~~2022, ~~mainly~~primarily due to ~~foreign~~lower ~~exchange~~product ~~rate~~sales ~~fluctuations~~in ofour ~~$3.7~~fuels ~~million~~marketing ~~and~~segment anresulting ~~increase~~from oflower $2fuel prices.1 ~~million~~Service ~~for~~revenues ~~gains~~increased onin ~~insurance~~2023 ~~recoveries~~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 Series D Preferred Unit redemptions. In addition, $4.8 million of Series 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 income 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 $0.55 per common unit related to the Series D Preferred Unit redemptions in 2023, compared to a loss of $0.31 per common unit related to the Series D Preferred Unit repurchase in 2022. See Notes 17 and 19 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for more information.

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SEGMENTS AND RESULTS OF OPERATIONS

PIPELINE SEGMENT

As of December 31, ~~2022~~2023, our pipeline operations consist of the transportation of refined products, crude oil and anhydrous ammonia, including:

•refined product pipelines with an aggregate length of 2,~~920~~915 miles and crude oil pipelines with an aggregate length of 2,~~050~~070 miles in Texas, Oklahoma, Colorado and New Mexico (collectively, the Central West System);

•a 2,045-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 Marathon Petroleum Corporation’s (Marathon) Mandan, North Dakota refinery and terminating in Minneapolis, Minnesota (the North Pipeline); and

•aan approximately 2,000-mile anhydrous ammonia pipeline originating in the Louisiana delta area and then running north through the Midwestern United States to Missouri before forking east and west to terminate in Indiana and Nebraska (the Ammonia Pipeline).

The following table lists information about our pipeline assets:


	As of December 31, 2023			Throughput For the Year Ended December 31,
Region / Pipeline System	Length	Terminals	Tank Capacity	2023	2022
	(Miles)		(Barrels)	(Barrels/Day)
Central West System:
McKee Refined Product System	1,981	—	—	182,840	160,490
Three Rivers System	378	—	—	119,453	114,294
Valley Pipeline System	271	—		59,885	58,335
Other	285	—	—	18,892	19,649
Central West Refined Products Pipelines	2,915	—	—	381,070	352,768
Corpus Christi Crude Pipeline System	538	8	2,157,000	317,346	385,720
McKee Crude System	388	—	1,039,000	153,410	132,197
Ardmore System	119	—	824,000	77,883	88,664
Permian Crude System	1,025	3	1,583,000	685,412	712,779
Central West Crude Oil Pipelines	2,070	11	5,603,000	1,234,051	1,319,360
Total Central West System	4,985	11	5,603,000	1,615,121	1,672,128

Central East System:
East Pipeline	2,045	18	5,906,000	149,947	151,139
North Pipeline	450	4	1,503,000	45,739	48,148
Ammonia Pipeline	2,010	—	—	26,157	27,185
Total Central East System	4,505	22	7,409,000	221,843	226,472

Total	9,490	33	13,012,000	1,836,964	1,898,600

	As of December 31, 2022			ThroughputFor the Year Ended December 31,
Region / Pipeline System	Length	Terminals	Tank Capacity	2022	2021
	(Miles)		(Barrels)	(Barrels/Day)
Central West System:
McKee Refined Product System	1,981	—	—	160,490	167,029
Three Rivers System	383	—	—	114,294	106,526
Valley Pipeline System	271	—		58,335	55,790
Other	285	—	—	19,649	18,362
Central West Refined Products Pipelines	2,920	—	—	352,768	347,707
Corpus Christi Crude Pipeline System	538	8	2,157,000	385,720	423,528
McKee Crude System	388	—	1,039,000	132,197	146,248
Ardmore System	119	—	824,000	88,664	81,609
Permian Crude System	1,005	3	1,583,000	712,779	630,183
Central West Crude Oil Pipelines	2,050	11	5,603,000	1,319,360	1,281,568
Total Central West System	4,970	11	5,603,000	1,672,128	1,629,275
Central East System:
East Pipeline	2,045	18	5,906,000	151,139	155,610
North Pipeline	450	4	1,502,000	48,148	50,365
Ammonia Pipeline	2,000	—	—	27,185	31,507
Total Central East System	4,495	22	7,408,000	226,472	237,482
Total	9,465	33	13,011,000	1,898,600	1,866,757

Description of Pipelines

Central West System. The Central West System covers a total of 4,~~970~~985 miles, including refined product and crude oil pipelines. The refined product pipelines have an aggregate length of 2,~~920~~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.

7The crude oil pipelines have an aggregate length of 2,070 miles (Central West Crude Oil Pipelines) and transport crude oil and other feedstocks to the refineries to which they are connected, including Valero Energy’s McKee, Three Rivers and Ardmore refineries, or from the Permian Basin and Eagle Ford Shale regions to our North Beach marine export terminal or to third-party refineries in Corpus Christi, Texas. Our Corpus Christi Crude Pipeline System is composed of pipelines that transport crude oil

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The crude oil pipelines have an aggregate length of 2,050 miles (Central West Crude Oil Pipelines) and transport crude oil and other feedstocks to the refineries to which they are connected, including Valero Energy’s McKee, Three Rivers and Ardmore refineries, or from the ~~Permian Basin and~~ Eagle Ford Shale regions to our North Beach marine export terminal or to third-party refineries in Corpus Christi, Texas. Our Corpus Christi Crude Pipeline System is comprised of pipelines that transport crude oil from the Eagle Ford region to Corpus Christi, Texas, including eight terminals along those pipelines, with aggregate storage capacity of 2.2 million barrels. In addition, the Corpus Christi Crude Pipeline System is connected to third-party long-haul pipelines that transport crude oil from the Permian Basin region to Corpus Christi, Texas.

Our Permian Crude System consists of crude oil transportation, pipeline connection and storage assets located in the Midland Basin of West Texas, that aggregate receipts from wellhead connection lines into intra-basin trunk lines for delivery to regional hubs and to connections with third-party mainline takeaway pipelines. ~~The~~As of December 31, 2023, the system consists of 1,~~005~~025 miles of pipelines and covers approximately 500,000 dedicated acres controlled by producers, with ~~approximately~~369 ~~345~~ receipt points. The Permian Crude System also includes three terminals in Texas, at Big Spring, Stanton and Colorado City, as well as several truck stations and other operational storage facilities, with an aggregate storage capacity of 1.6 million barrels.

Central East System. The Central East System covers a total of 4,~~495~~505 miles and consists of the East Pipeline, the North Pipeline and the Ammonia Pipeline.

The East Pipeline covers 2,045 miles and transports refined products and natural gas liquids north via pipelines to our terminals and third-party terminals along the system and to receiving pipeline connections in Kansas. Shippers on the East Pipeline ~~mainly~~primarily obtain refined products from refineries in Kansas, Oklahoma and Texas. The East Pipeline includes 18 terminals, with aggregate storage capacity of 4.5 million barrels and two tank farms with aggregate storage capacity of 1.4 million barrels at McPherson and El Dorado, Kansas.

The North Pipeline originates at Marathon’s Mandan, North Dakota refinery and runs from west-to-east for approximately 450 miles to its termination in Minneapolis, Minnesota. The North Pipeline is 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 with aggregate storage capacity of 1.5 million barrels.

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 located along the Mississippi River. The line then runs north through Louisiana and Arkansas into Missouri, where, at Hermann, Missouri, it splits into two branches, one of which goes east into Illinois and Indiana, while the other branch continues north into Iowa and then turns west into Nebraska. The Ammonia Pipeline is connected to multiple third-party-owned terminals, which include industrial facility delivery locations. Product is supplied to the pipeline from anhydrous ammonia plants in Louisiana and Arkansas, imported product delivered through ~~the~~ marine 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-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. 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 via marine vessels, pipelines or 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 regulated by one or more of the following federal governmental agencies: the Federal Energy Regulatory Commission (the FERC), the Surface Transportation Board (the STB), the Department of Transportation (the DOT), the Environmental Protection Agency (the EPA) and the Department of Homeland Security. In addition, our pipelines are subject to the respective jurisdictions of the states those lines traverse. See “Rate Regulation” and “Environmental, Health, Safety and Security Regulation” below for additional discussion.

The majority of our pipelines are deemed to be “common carrier” lines. Common carrier activities are those for which transportation is available to any shipper who requests such services and satisfies the conditions and specifications for transportation. Published tariffs for our petroleum product pipeline shipments are (i) filed with the FERC for interstate pipeline shipments and (ii) filed with the relevant state authority for intrastate pipeline shipments.

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We operate our pipelines remotely through an operational technology system called the Supervisory Control and Data Acquisition, or SCADA, system.

Demand for and Sources of Refined Products and Crude Oil

Throughput activity on our Central West Refined Product Pipelines and the East and North pipelines depends on the level of demand for refined products and other products in the markets served by those pipelines, as well as the ability and willingness of the refiners and marketers with access to the pipelines to supply that demand through our pipelines. Demand for renewable products handled by our pipeline systems, such as biodiesel and ethanol, is driven by the overall level of demand for refined products mentioned above, as well as regulatory requirements and our customers’ goals to increase their use of renewable fuels.

The majority of the refined products delivered through the Central West Refined Product Pipelines and the North Pipeline are gasoline and diesel fuel that originate at refineries connected to our pipelines. Demand for motor fuels fluctuates as prices for these products fluctuate. Prices fluctuate for a variety of reasons, including the overall balance in supply and demand, which is affected by general economic conditions, among other factors. Prices for gasoline and diesel fuel usually increase in the warm weather months when people tend to drive automobiles more often and for longer distances.

Much of the refined products and natural gas liquids delivered through the East Pipeline, and a portion of volumes on the North Pipeline, are ultimately used as fuel for railroads, ethanol denaturant or in agricultural operations, including fuel for farm equipment, irrigation systems, trucks used for transporting crops and crop-drying facilities. Demand for refined products for agricultural use, and the relative mix of products required is affected by weather conditions in the markets served by the East and North pipelines. The agricultural sector is also affected by government agricultural policies and crop commodity prices. Although periods of drought suppress agricultural demand for some refined products, particularly those used for fueling farm equipment, the demand for fuel to power irrigation systems often increases during such times. The mix of refined products delivered for agricultural use varies seasonally, with gasoline demand peaking in early summer, diesel fuel demand peaking in late summer and propane demand highest in the fall.

Our refined product pipelines are also dependent upon adequate levels of production of refined products by refineries connected to the pipelines, directly or through connecting pipelines. The refineries are, in turn, dependent upon adequate supplies of suitable grades of crude oil. Certain of our Central West Refined Products Pipelines are connected directly to Valero Energy refineries and are subject to long-term throughput agreements with Valero Energy. If operations at one of these refineries were discontinued or significantly reduced, it could have a material adverse effect on our operations, although we would endeavor to minimize the impact by seeking alternative customers for those pipelines.

The North Pipeline is heavily dependent on Marathon’s Mandan, North Dakota refinery, which primarily runs regionally-sourced crude oil (although it has the ability to process other crude oils), and an interruption in operations at the Marathon refinery could have a material adverse effect on our operations. In addition, the North Pipeline receives refined products from the Laurel, Montana refinery operated by CHS ~~Inc~~. The majority of the refined products transported through the East Pipeline are produced at three refineries located at McPherson and El Dorado, Kansas and Ponca City, Oklahoma, which are operated by CHS ~~Inc.~~, HollyFrontier Corporation and Phillips 66, respectively. The East Pipeline also has access to Gulf Coast supplies of products through third-party connecting pipelines that receive products originating from Gulf Coast refineries.

Other than the Valero Energy refineries and the Marathon refinery described above, if operations at any one refinery were discontinued, we believe (assuming stable demand for refined products in markets served by the refined product pipelines) that the effects thereof would be short-term in nature, and our business would not be materially adversely affected over the long-term because such discontinued production could be replaced by other refineries or other sources.

Our crude oil pipelines are dependent on our customers’ continued access to sufficient crude oil and sufficient demand for refined products for our customers to operate their refineries. The supply of crude oil production (domestic and foreign) could fluctuate with the price of crude oil. Changes in crude oil prices could also affect the exploration and production of shale plays, which could affect demand for crude oil pipelines serving those regions, such as our Corpus Christi Crude Pipeline System and Permian Crude System. During periods of sustained low prices, or uncertainty in regulatory changes that could increase costs or impose restrictions on operations, producers tend to reduce their capital spending and drilling activity and narrow their focus to assets in the most cost-advantaged regions.

In addition, certain of our crude oil pipelines, including the McKee System, are the primary source of crude oil for our customers’ refineries. Therefore, these “demand-pull” pipelines are less affected by changes in crude oil prices. For example, refiners can benefit from lower crude oil prices if they are able to take advantage of lower feedstock prices in areas with healthy regional demand; however, as refined product inventories increase, refiners typically reduce their production rate, which may reduce the degree to which they are able to benefit from low crude prices.

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Demand for and Sources of Anhydrous Ammonia

Our Ammonia Pipeline is currently the only major pipeline in the United States transporting anhydrous ammonia into the nation’s corn belt. The pipeline is connected to domestic production facilities and also has the capability to receive products from outside the United States directly into the system.

Throughputs on our Ammonia Pipeline depend on overall demand for nitrogen fertilizer use, the price of natural gas, which is ~~the~~a ~~primary~~feedstock ~~component~~for the production of anhydrous ammonia, and the level of demand for direct application of anhydrous ammonia as a fertilizer for crop production (Direct Application). Demand for Direct Application is dependent on the weather, as Direct Application is not effective when soil is either too wet or too dry.

Corn producers have fertilizer alternatives to anhydrous ammonia, such as liquid or dry nitrogen fertilizers. Liquid and dry nitrogen fertilizers are both less sensitive to weather conditions during application but are generally more costly than anhydrous ammonia. In addition, anhydrous ammonia has the highest nitrogen content of any nitrogen-derivative fertilizer.

Demand for anhydrous ammonia has been ~~insulated~~steady ~~from~~and ~~the~~somewhat ~~negative~~insulated ~~impacts~~ from ~~COVID-19~~volume byfluctuations due to continued strong agricultural demand ~~and lower-density population centers~~ 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 ~~two~~ largest ~~customers~~customer of our pipeline segment accounted for approximately 2427% ~~and 11%, respectively,~~ of the total segment revenues for the year ended December 31, ~~2022~~2023. No other single customer accounted for a10% ~~significant~~or ~~portion~~more of the total revenues of our pipeline segment.

Competition and Other Business Considerations

Because pipelines are generally the lowest-cost method for intermediate and long-haul movement of crude oil and refined products, our more significant competitors are common carrier and proprietary pipelines owned and operated by major integrated and large independent oil companies and other pipeline companies in our service areas. Competition between common carrier pipelines is based primarily on transportation charges, quality of customer service and proximity to end users. Trucks may deliver products competitively for short-~~hauls~~haul destinations; however, trucking costs render that mode of transportation uncompetitive with pipeline options for ~~longer~~long-haul ~~hauls~~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 that are affected by domestic shale oil production in the Eagle Ford, Permian Basin and Granite Wash regions. Our pipelines also face competition from other crude oil pipelines and truck transportation in these regions. However, some of that exposure is mitigated through our long-term contracts and minimum volume commitments with creditworthy customers.

~~The~~Our East Pipeline and North ~~Pipelines~~Pipeline compete with an independent common carrier pipeline system owned by ~~Magellan Midstream Partners~~ONEOK, LInc.P. (~~Magellan~~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~~ONEOK’s terminals. Competition with ~~Magellan~~ONEOK is based primarily on transportation charges, quality of customer service and proximity to end users.

Competitors of ~~the~~our Ammonia Pipeline include Midwest production facilities, nitrogen fertilizer substitutes and barge, truck and railroad transportation under certain market conditions.

Looking forward, we continue to see growing interest for utilization of ammonia as a source for renewable ~~electricity~~energy ~~generation~~ to power fuel-cell vehicles. While future uses for lower emission-producing “blue” and “green” ammonia are still developing, we are partnering with existing and potential customers to develop these projects, which could increase demand for and utilization of our Ammonia Pipeline.

~~Results of Operations~~12

Houston Pipeline Impairment. In the third quarter of 2021, we recorded a non-cash asset impairment charge of $59.2 million related to the southern section of our Houston refined product pipeline. Please refer to Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion.

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Results of Operations

The following table presents operating highlights for the pipeline segment:

	Year Ended December 31,
	2022		2021		Change
	2023		2022		Change
	(Thousands of Dollars, Except Barrel Data)
Pipeline Segment:
Crude oil pipelines throughput (barrels/day)	1,~~319~~234,~~360~~051		1,~~281~~319,~~568~~360		37(85,~~792~~309)
Refined products and ammonia pipelines throughput (barrels/day)	~~579~~602,~~240~~913		~~585~~579,~~189~~240		(523,~~949)~~673
Total throughput (barrels/day)	1,~~898~~836,~~600~~964		1,~~866~~898,~~757~~600		31(61,~~843~~636)
Throughput and other revenues	$	~~828~~873,~~191~~869	$	~~762~~828,~~238~~191	$	6545,~~953~~678
Operating expenses	~~210~~214,~~719~~751		~~202~~210,~~481~~719		84,~~238~~032
Depreciation and amortization expense	~~178~~175,~~802~~930		~~179~~178,~~088~~802		(~~286~~2,872)
Impairment loss	—		59,197		(59,197)
Segment operating income	$	483,188	$	438,670	$	44,518
Segment operating income	$	438,670	$	321,472	$	117,198

~~Pipeline~~Tariff ~~segment~~indexations ~~revenues~~effective ~~increased~~July ~~$66.0~~2022 ~~million~~ and ~~throughputs~~July 2023 increased ~~31,843~~the ~~barrels~~average ~~per~~tariff ~~day~~rates on most of our pipeline systems and resulted in higher revenues for the year ended December 31, ~~2022~~2023, compared to the year ended December 31, ~~2021~~2022. Results for the first quarter of 2021 were negatively affected by Winter Storm Uri, which brought snow and damaging ice and caused widespread power outages in Texas and surrounding states in February 2021, as well as the lingering effects of COVID-19 restrictions. However, by the second quarter of 2021, demand had largely recovered to pre-pandemic levels. Revenues primarily increased due to the following:

~~•an~~Pipeline ~~increase~~segment in revenues ofincreased $6145.67 million, and ~~an increase in~~ throughputs ofdecreased 8261,~~596~~636 barrels per day onfor ~~our~~the ~~Permian~~year ~~Crude~~ended ~~System~~December 31, ~~mainly~~2023, ~~due~~compared to ~~increased customer production supplying this system and~~ the ~~completion~~year ofended ~~pipeline~~December 31, ~~expansion projects~~2022, asprimarily ~~well as the negative impacts on the first quarter of 2021 described above. The increase in revenues included an increase of $14.5 million~~ due to higher commodity prices on PLA volumes sold and a $4.4 million adjustment to deferred revenue in the second quarter of 2022 resulting from higher expected tariff revenue on certain incentive pricing contracts;:

•an increase in revenues of $531.71 million and an increase in throughputs of 743,~~768~~563 barrels per day on our ~~Three~~McKee ~~Rivers~~ System pipelines, ~~mainly~~primarily due to anoperational ~~increase~~issues inand ~~demand~~a planned turnaround at a customer’s refinery in ~~the~~2022, ~~markets~~as ~~served~~well byas higher demand on our ~~Nuevo~~pipeline ~~Laredo~~serving ~~and~~the ~~San~~Denver, ~~Antonio~~Colorado ~~pipelines~~market in ~~2022~~2023; ~~and~~additionally, ~~the~~higher ~~negative~~average ~~impacts~~tariff onrates ~~the~~contributed ~~first~~to ~~quarter~~$9.7 million of ~~2021~~the ~~described~~overall ~~above~~increase;

•an increase in revenues of $312.41 million, ~~and~~despite ana ~~increase~~decrease in throughputs of 23,~~545~~601 barrels per day on our ~~Valley~~East ~~Pipeline,~~and ~~mainly~~North pipelines combined; revenues increased primarily due to higher ~~demand~~average intariff ~~the~~rates, ~~markets~~while ~~served~~throughputs bydecreased ~~this~~primarily ~~pipeline~~due to unfavorable market conditions and planned turnarounds at customers’ refineries in ~~2022~~2023;

•an increase in revenues of $37.02 million onand ~~our~~an ~~Corpus~~increase ~~Christi Crude Pipeline System, mainly due to increased volumes on certain of our pipelines~~ in ~~this system, despite lower overall~~ throughputs of 371,~~808~~550 barrels per day, ~~mainly~~on ~~due~~our toValley ~~unfavorable~~Pipeline, ~~market~~primarily ~~conditions~~due onto ~~other~~higher ~~pipelines~~average intariff ~~this system~~rates; ~~and~~

•an increase in revenues of $15.39 million and an increase in throughputs of 15,~~526~~159 barrels per day on our ~~Houston~~Three ~~Pipeline~~Rivers System, partially due to ahigher ~~new~~demand ~~contract~~on ~~with~~certain aof ~~customer~~our pipelines within this system and pipeline expansions that ~~began~~were atplaced ~~the~~in ~~end~~service ofin ~~March~~July ~~2021~~2022. Also, higher average tariff rates contributed to $4.0 million of the overall increase;

~~However~~•an increase in revenues of $3.4 million, ~~these~~despite ~~increases~~slightly ~~were~~lower ~~partially~~throughputs ~~offset~~of by1,028 ~~the~~barrels ~~following:~~per day on our Ammonia Pipeline; revenues increased primarily due to higher average tariff rates;

•a decrease in revenues of $42.12 million and a decrease in throughputs of 427,~~322~~367 barrels per day on our ~~Ammonia~~Permian ~~Pipeline~~Crude System, primarily due to ~~scheduled~~decreased ~~maintenance~~customer onproduction ~~our~~supplying ~~pipeline~~this insystem. ~~the~~Revenues ~~third~~also ~~quarter~~decreased of$7.9 ~~2022~~million due to lower commodity prices on PLA volumes and ~~unfavorable~~other ~~market~~products ~~conditions~~sold; these decreases were partially offset by higher average tariff rates in ~~2022~~2023;

•a decrease in revenues of $2.64 million onand ~~the Ardmore System, mainly due to the expiration of~~ a ~~customer~~decrease ~~contract~~in atthroughputs ~~the end~~ of ~~the first quarter of 2021; although throughputs on this system increased 7~~10,~~055~~781 barrels per day inon ~~2022~~our Ardmore System due to ~~the~~a ~~negative~~turnaround ~~impacts~~at a customer’s refinery in the ~~first~~second quarter of ~~2021~~2023 ~~described~~and ~~above, these higher throughputs did not offset the decrease in revenues as more barrels were moved at~~ lower ~~average~~demand ~~tariffs~~ in ~~2022~~2023; and

•a decrease in revenues of $110.39 million and a decrease in throughputs of 468,~~471~~374 barrels per day on our ~~East~~Corpus Christi Crude Pipeline System, ~~mainly~~primarily due to ~~the~~unfavorable ~~current backwardated~~ market, ~~which~~conditions ~~led~~and changes to a ~~decline in PLA volumes sold and the expiration of~~ customer ~~contracts; and~~contract.

•aOperating ~~decrease~~expenses inincreased ~~revenues of~~ $04.70 million ~~and~~for athe ~~decrease~~year inended ~~throughputs of 20~~December 31,~~590~~ ~~barrels per day on our McKee System pipelines~~2023, ~~mainly~~compared ~~due~~ to ~~operational~~the ~~issues~~year atended aDecember 31, ~~customer’s refinery in~~ 2022, ~~including~~primarily adue ~~planned~~to ~~turnaround~~an inincrease ~~the third quarter~~ of ~~2022,~~$2.8 ~~which~~million ~~had~~in anmaintenance ~~even~~and ~~greater~~regulatory ~~negative~~expenses ~~impact~~across ~~than~~various ~~the first quarter of 2021 impacts described above~~pipelines.

~~Operating~~Depreciation ~~expenses~~and ~~increased~~amortization expense decreased $8.2.9 million for the year ended December 31, ~~2022~~2023, compared to the year ended December 31, ~~2021~~2022, ~~mainly~~primarily due to anfully ~~increase~~amortized indefinite-lived ~~power~~intangible ~~costs of $5~~assets.~~7 million, primarily on our Permian Crude System and various refined product pipelines, and an increase in maintenance and regulatory expenses of $1.6 million across various pipelines.~~

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STORAGE SEGMENT

Our storage segment is ~~comprised~~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, ~~2022~~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, ~~2022~~2023:

Facility						Tank Capacity
						(Barrels)
Colorado Springs, CO						327,000
Denver, CO						110,000
Albuquerque, NM						250,000
Rosario, NM						167,000
Catoosa, OK						359,000
Abernathy, TX						161,000
Amarillo, TX						269,000
Corpus Christi, TX						410,000
Corpus Christi, TX (North Beach)						3,962,000
Edinburg, TX						345,000
El Paso, TX (a)						415,000
El Paso, TX(a)						415,000
Harlingen, TX						286,000
Laredo, TX						218,000
San Antonio, TX (b)						379,000
San Antonio, TX(b)						379,000
Southlake, TX						569,000
Nuevo Laredo, Mexico						268,000
Central West Terminals						8,495,000
St. James, LA						9,906,000
Houston, TX						87,000
Gulf Coast Terminals						9,993,000
Los Angeles, CA						~~606~~615,000
Pittsburg, CA						398,000
Selby, CA						2,672,000
Stockton, CA						818,000
Portland, OR						1,348,000
Tacoma, WA						391,000
Vancouver, WA (b)						775,000
Vancouver, WA(b)						775,000
West Coast Terminals						7,~~008~~017,000
Benicia, CA						3,~~683~~698,000
Corpus Christi, TX						4,030,000
Texas City, TX						3,141,000
Refinery Storage Tanks						10,~~854~~869,000
Total						36,~~350~~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 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 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 level of demand for products stored in our terminals in the markets served by those assets. Demand for our terminalling services will generally increase or decrease with demand for refined products, and demand for refined products tends to increase or decrease with the relative strength of the economy. In addition, the forward pricing curve can have an impact on demand. For example, crude oil traders focus less on the current market commodity price than on whether that price is higher or lower than expected future market prices: if the future price for a product is believed to be higher than the current market price, or a “contango market,” traders are more likely to purchase and store products to sell in the future at the higher price. On the other hand, when the current price of crude oil nears or exceeds the expected future market price, or “backwardation,” traders are no longer incentivized to purchase and store product for future sale. Our storage terminal revenues are somewhat insulated from demand volatility due to contracted rates for storage and minimum volume commitments.

Crude oil delivered to our St. James and Corpus Christi North Beach terminals will generally increase or decrease with crude oil production rates in western Canada and the Bakken, Permian and Eagle Ford shale plays. In addition, the market price relationship between various grades of crude oil impacts the demand for our unit train facilities at our St. James terminal. ~~Prior~~Although to the ~~COVID-19~~Permian ~~pandemic,~~and ~~North~~Eagle ~~American~~Ford shale ~~play~~plays ~~production~~are ~~had~~partially ~~increased~~insulated ~~exports~~from ofnegative ~~crude~~economic ~~oil~~conditions ~~from~~due ~~Texas~~to ~~Gulf~~the ~~Coast~~low ~~ports~~break-even point, ~~including~~ our Corpus Christi ~~North~~exports ~~Beach~~have ~~facility,~~not returned to ~~destinations~~pre-pandemic aslevels ~~close~~due asto ~~the~~lower ~~U.S.~~global ~~East~~demand ~~Coast~~for ~~and~~refined asproducts ~~far~~and ~~away~~crude asoil ~~Europe~~ and ~~Asia.~~increased ~~Although~~competition ~~the~~in ~~negative~~crude ~~impact~~oil ofexport ~~COVID-19~~markets ~~has~~out ~~been~~of ~~partially mitigated by~~ the ~~low~~U.S. ~~break-even~~Overall, ~~point~~refinery inproduction ~~the~~rates,

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Permian and Eagle Ford shale plays, our Corpus Christi exports have not returned to pre-pandemic levels due to lower global demand for refined products and crude oil and increased competition in crude oil export markets out of the U.S. Overall, refinery production rates, drilling activity and overall consumer demand in the U.S. rebounded in 2021, bringing demand for most of our terminal and storage facilities back to pre-pandemic levels. However, the detrimental impact of the pandemic, amplified by the Russia-Ukraine conflict, has continued to affect current global demand, resulting in a decline in crude oil exports from our Corpus Christi North Beach facility, and the current volatile and backwardated market has led to customers not renewing expiring contracts, ~~mainly~~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 other products to many of the world’s largest producers of crude oil, integrated oil companies, chemical companies, oil traders and refiners. In addition, our blending capabilities in our storage assets have attracted customers who have leased capacity primarily for blending purposes. The ~~two~~ largest ~~customers~~customer of our storage segment accounted for approximately 3339% ~~and 14%, respectively,~~ of the total revenues of the segment for the year ended December 31, ~~2022~~2023. No other customer accounted for a10% ~~significant~~or ~~portion~~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 which must comply with applicable environmental regulations. A terminal operator’s ability to obtain attractive pricing is often dependent on the quality, versatility and reputation of the facilities owned by the operator. Operators with versatile storage capabilities typically require less modification prior to usage, ultimately making the storage cost to the customer more attractive. On the West Coast, regulatory priorities continue to increase demand for renewable fuels in the region, while at the same time, obtaining permits for 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 Valero Energy, and we have entered into various agreements with Valero Energy governing the use of these tanks. As a result, we believe that we will not face significant competition for our services provided to those refineries.

Results of ~~OperationsDispositions~~OperationsPoint 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). InSee the third quarter of 2021, we recorded non-cash asset and goodwill impairment losses of $95.7 million and $34.1 million, respectively, related to our Eastern U.S. Terminal Operations, which were sold on October 8, 2021 (the Eastern U.S. Terminals Disposition). Please refer to Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of ~~these~~this ~~dispositions~~disposition.

Selby Terminal Fire. We recognized 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 consolidated statements of income (loss) and relates to a fire in October 2019 at our terminal facility in Selby, California.16

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The following table presents operating highlights for the storage segment:

	Year Ended December 31,
	2022		2021		Change
	2023		2022		Change
	(Thousands of Dollars, Except Barrel Data)
Storage Segment:
Throughput (barrels/day) (a)	480,129		516,094		(35,965)
Throughput (barrels/day)	448,331		480,129		(31,798)
Throughput terminal revenues	$	~~110~~104,~~591~~495	$	~~122~~110,~~331~~591	$	(116,~~740~~096)
Storage terminal revenues	~~223~~215,~~958~~104		~~305~~223,~~337~~958		(818,~~379~~854)
Total revenues	~~334~~319,~~549~~599		~~427~~334,~~668~~549		(9314,~~119~~950)
Operating expenses	~~154~~156,~~270~~938		~~185~~154,~~597~~270		~~(31~~2,~~327)~~668
Depreciation and amortization expense	7375,~~076~~052		8773,~~500~~076		~~(14~~1,~~424)~~976
Goodwill impairment loss	—		34,060		(34,060)
Impairment loss	—		46,122		(46,122)
Other impairment losses	46,122		95,711		(49,589)
Segment operating income	$	87,609	$	61,081	$	26,528
Segment operating income	$	61,081	$	24,800	$	36,281

~~(a)Prior~~Throughput ~~period~~terminal revenues decreased $6.1 million, and throughputs 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 ~~restated~~partially ~~consistent~~offset ~~with~~by ~~current~~an ~~period~~increase ~~presentation~~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.

~~Throughput~~Storage terminal revenues decreased $118.79 million ~~and throughputs decreased 35,965 barrels per day~~ for the year ended December 31, ~~2022~~2023, compared to the year ended December 31, ~~2021~~2022, ~~mainly~~primarily ~~at our Corpus Christi North Beach terminal~~ due to ~~a decline in export demand and changes to a customer contract.~~:

~~Storage~~•a ~~terminal~~decrease in revenues ~~decreased~~of $8129.47 million ~~for~~at ~~the~~our ~~year~~St. ~~ended~~James ~~December 31,~~terminal ~~2022,~~due ~~compared~~ to ~~the~~customers ~~year~~not ~~ended~~renewing ~~December 31,~~expiring ~~2021,~~contracts ~~primarily~~in ~~due~~the ~~to:~~current backwardated market; and

•ana ~~aggregate~~ decrease in revenues of $739.6 million due to the ~~Eastern U.S. Terminals Disposition in October 2021 and the~~ Point Tupper Terminal Disposition in April 2022~~; and~~.

•a decrease in revenues of $21.1 million at our St. James terminal due to customers not renewing expiring contracts in the current backwardated market.

These decreases were partially offset by the following:

•an increase in revenues of $1026.14 million at our West Coast Terminals, ~~mainly~~primarily atdue ~~our~~to ~~Portland~~new contracts and ~~Stockton~~rate ~~terminals,~~escalations ~~primarily~~across ~~due~~various toterminals, ~~new~~combined ~~contracts~~with ~~and~~ higher throughput and handling fees, mainly at our Stockton terminal; and

•an increase in revenues of $14.63 million, primarily due to rate escalations onat our Central West Terminals and at our refinery storage tanks~~; and~~.

~~•an~~Operating ~~increase~~expenses inincreased ~~revenues of~~ $12.47 million atfor ~~our~~the ~~Central~~year ~~West~~ended ~~Terminals~~December 31, ~~mainly~~2023, ~~due~~compared to ~~rate~~the ~~escalations~~year ~~and~~ended ~~higher~~December 31, ~~throughput~~2022, ~~and~~primarily ~~handling~~due ~~fees.~~to the following:

~~Operating expenses decreased $31.3 million for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily due to~~ •an ~~aggregate~~increase ~~decrease~~ in ~~operating~~maintenance and regulatory expenses of $463.61 million, ~~due~~across tovarious ~~the Eastern U.S. Terminals Disposition in October 2021 and the Point Tupper Terminal Disposition in April 2022. This decrease was partially offset by the following:~~terminals;

•~~increases~~an inincrease ~~reimbursable expenses~~ of $42.18 million, ~~mainly~~in atad ~~our~~valorem ~~St.~~taxes ~~James~~due ~~terminal~~to higher property valuations;

•aincreases in reimbursable and other expenses of $42.05 million ~~recovery~~that have corresponding increases in ~~the~~revenue, ~~first~~primarily ~~quarter~~at ofour ~~2021~~West ~~for~~Coast ~~business~~Terminals, ~~interruption~~partially ~~insurance~~offset ~~related~~by tolower ~~the~~reimbursable ~~2019~~expenses ~~Selby~~at ~~terminal~~our ~~fire~~St. James terminal; and

•~~increases~~an inincrease ~~compensation expense~~ of $1.78 million, adat ~~valorem~~our ~~taxes~~Corpus ofChristi ~~$1.2~~North ~~million,~~Beach ~~additive~~terminal ~~and~~due ~~chemical~~to ~~expenses~~changes ofin ~~$1.1~~a ~~million~~customer ~~and maintenance and regulatory expenses of $1~~contract.~~0 million, across various terminals.~~

~~Depreciation~~These ~~and~~increases ~~amortization~~were ~~expense~~partially ~~decreased~~offset ~~$14.4~~by ~~million~~a ~~for~~decrease ~~the~~in ~~year~~operating ~~ended~~expenses ~~December 31,~~of ~~2022,~~$7.9 ~~compared~~million ~~to the year ended December 31, 2021, mainly~~ due to the ~~Eastern~~sale ~~U.S.~~of ~~Terminals~~our ~~Disposition~~Point inTupper ~~October~~Terminal ~~2021~~Operations ~~and~~during the ~~Point~~second ~~Tupper~~quarter ~~Terminal~~of ~~Disposition in April~~ 2022.

15Depreciation 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

~~The~~Our fuels marketing segment ~~mainly~~sells ~~includes~~petroleum products primarily through our bunkering operations in the Gulf Coast, asand ~~well as~~ certain of our blending operations associated with our Central East System. The results of operations for the fuels marketing segment depend largely on the margin between our costs and the sales prices of the products we market. Therefore, the results of operations for this segment are more sensitive to changes in commodity prices compared to the operations of the pipeline and storage segments. We enter into derivative contracts to attempt to mitigate the effects of commodity price fluctuations. The financial impacts of the derivative financial instruments associated with commodity price risk were not material for any periods presented. Fluctuations in global demand for crude oil, which was caused by many economic factors outside of our control, has caused volatility in commodity prices and volumes ~~in 2022 and 2021,~~ for our blending operations and bunker fuel sales. in 2022 and 2023.

~~Customers~~Competition ~~for bunker fuel sales are mainly ship owners, including cruise line companies, marketers~~ and traders. In the sale of bunker fuel, we compete with ports offering bunker fuels that are along the route of travel of the vessel. One of our customers, a marketer of petroleum products, was the largest customer of our fuels marketing segment and accounted for approximately 16% of the total segment revenues for the year ended December 31, 2022. No other customer accounted for a significant portion of the total revenues of the fuels marketing segment for the year ended December 31, 2022.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,

2022

2021

Change

2023

2022

Change

(Thousands of Dollars)

Fuels Marketing Segment:

Product sales

~~520~~440,~~486~~725

~~428~~520,~~608~~486

91(79,~~878~~761)

Cost of goods

~~484~~405,~~477~~992

~~417~~484,~~000~~477

67(78,~~477~~485)

Gross margin

3634,~~009~~733

1136,~~608~~009

24(1,~~401~~276)

Operating expenses

21,~~473~~807

~~427~~2,473

~~2,046~~(666)

Segment operating income

3332,~~536~~926

1133,~~181~~536

~~22,355~~(610)

~~Segment~~Product ~~operating~~sales ~~income~~decreased ~~increased~~$79.8 million, and cost of goods decreased $2278.45 million for the year ended December 31, ~~2022~~2023, compared to the year ended December 31, ~~2021~~2022, ~~mainly~~primarily due to anlower ~~increase~~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 $122.48 million in gross ~~margins~~margin from our bunkering operations and ana ~~increase~~decrease of $112.48 million in gross ~~margins~~margin from ~~our blending and~~ other product sales, ~~both~~more ~~driven~~than byoffset higher ~~fuel~~blending ~~prices~~gross onmargins ~~product~~of ~~sales~~$4.3 million, all primarily due to lower fuel prices.

~~Operating~~Segment ~~expenses~~operating ~~increased~~income decreased $2.0.6 million for the year ended December 31, ~~2022~~2023, compared to the year ended December 31, ~~2021~~2022, ~~primarily~~ due to athe ~~settlement~~changes ofin ~~$1.7~~gross ~~million~~margins wedescribed ~~received~~above, inpartially ~~the~~offset ~~first~~by ~~quarter~~a ofdecrease ~~2021~~in ~~for~~operating aexpenses ~~credit~~of ~~loss~~$0.7 ~~that~~million, ~~was~~primarily ~~previously~~related ~~written~~to ~~off~~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 ~~are~~include ~~for~~ 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 inas ~~the~~all ~~partnership~~cash ~~agreement~~receipts ~~generally~~less as cash ~~on hand at the end of the quarter~~disbursements, ~~plus~~including ~~certain~~distributions ~~permitted borrowings made subsequent~~ to ~~the~~our ~~end~~preferred ofunit ~~the quarter~~holders, ~~less~~and cash reserves ~~determined~~established by our ~~board~~general ~~of directors~~partner, ~~subject~~in toits ~~requirements~~sole ~~for distributions for our preferred units~~discretion. We may maintain our distribution level with other sources of Available Cash, as provided in our partnership agreement, including borrowings under our ~~revolving~~Revolving ~~credit~~Credit ~~agreement~~Agreement and proceeds from the ~~sales~~sale of assets.

1618

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~~The~~In ~~following~~the ~~chart~~first ~~shows~~quarter ~~our~~of ~~sources~~2023, we completed the Sale-Leaseback Transaction for $103.0 million, and ~~uses~~in the third quarter of ~~cash~~2023, we issued 14,950,000 common units for ~~2022~~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 ~~2021:~~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.

InAs ~~2022~~illustrated ~~and~~in ~~2021~~the chart below, wein ~~were~~2023 ~~able~~and to2022, ~~fund~~we funded all of our expenses, distribution requirements and capital expenditures using ~~internally generated~~ cash ~~flows.~~from Weoperating reduced our leverage to position ourselves to repurchase 6,900,000 of our Series D Cumulative Convertible Preferred Units in November 2022, representing approximately one-third of the outstanding units, using borrowings under our $1activities.~~0 billion unsecured revolving credit agreement.~~

For the full-year ~~2023~~2024, we expect to fund all of our expenses, distribution requirements and capital expenditures using internally generated cash flows. We have no long-term debt maturities until 2025.

Our Series D Cumulative Convertible Preferred Units (Series D Preferred Units) become redeemable, at our option, beginning in 2023, which coincides with an increase in the distribution rate of those units. Beginning in 2028, the holders of the Series D Preferred Units have the option to require us to redeem their units, and we have taken steps to position ourselves to repurchase or redeem the Series D Preferred Units in advance of the possible mandatory redemption. We plan to redeem the remaining 16,346,650 of Series D Preferred Units outstanding in 2023 and 2024, which is several years ahead of the holders’ redemption option in 2028. We will also continue to evaluate other sources of liquidity to facilitate the planned redemption of the remaining Series D Preferred Units in 2023 and 2024. 19

We have no long-term debt maturities until 2025, and we expect to be able to access debt capital markets to refinance those maturities.

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ACASH discussion of our cash flows and other changes in financial position for 2020 can be found in Items 1., 2. and 7. “Business, Properties and Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the SEC on February 24, 2022.FLOWS

~~CASH~~A ~~FLOWS~~discussion ~~FOR~~of ~~THE~~our ~~YEARS~~cash ~~ENDED~~flows ~~DECEMBER~~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 ~~AND~~filed ~~2021~~with the SEC on February 23, 2023.

The following table summarizes our cash flows from operating, investing and financing activities (~~please~~see ~~refer~~also to our Consolidated Statements of Cash Flows in Item 8. “Financial Statements and Supplementary Data”).

	Year Ended December 31,
	2022		2021
	2023		2022
	(Thousands of Dollars)
Net cash provided by (used in):
Operating activities	$	~~527~~514,~~549~~269	$	~~501~~527,~~478~~549
Investing activities	(8423,~~365~~240)		75(84,~~978~~365)
Financing activities	(~~434~~502,~~953~~430)		(~~725~~434,~~579~~953)
Effect of foreign exchange rate changes on cash	~~707~~40		~~136~~707
Net increase (decrease) in cash, cash equivalents and restricted cash	$	8,938	$	(147,987)
Net (decrease) increase in cash, cash equivalents and restricted cash	$	(11,361)	$	8,938

~~For~~Net cash provided by operating activities decreased $13.3 million for the ~~years~~year ended December 31, ~~2022~~2023, ~~and~~compared ~~2021~~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. ~~exceeded~~In addition, our ~~distributions~~working tocapital ~~unitholders~~decreased by $10.6 million for the year ended December 31, ~~reliability~~2023 and $0.7 million for the year ended December 31, 2022. Generally, working capital ~~expenditures~~requirements are affected by our accounts receivable, accounts payable and ~~strategic~~accrued ~~capital~~liability ~~expenditures~~balances, which vary depending on the timing of payments.

Net cash ~~provided~~used byin ~~operating~~investing activities ~~increased~~decreased by $2661.1 million for the year ended December 31, ~~2022~~2023, compared to the year ended December 31, ~~2021~~2022, primarily due to ~~higher~~proceeds ~~net~~of ~~income~~approximately ~~and changes in working capital~~$103.0 ~~Generally,~~million ~~working~~from ~~capital~~the ~~requirements~~Sale-Leaseback ~~are~~Transaction ~~affected~~in bythe ~~our~~first ~~accounts~~quarter ~~receivable,~~of ~~accounts payable and accrued interest payable balances~~2023, ~~which~~compared ~~vary~~to ~~depending~~proceeds onfrom ~~the~~asset ~~timing~~sales of ~~payments~~$59.3 ~~Our~~million ~~working~~in ~~capital decreased by $0~~2022.7 ~~million~~Additionally, for the year ended December 31, ~~2022,~~2023 compared to ~~an increase of $14.1 million for~~ the year ended December 31, ~~2021~~2022, ~~mainly~~cash ~~due~~outflows ~~to changes in the timing of payments~~ related to ~~accrued~~capital ~~interest~~expenditures ~~payable~~decreased ~~due~~an toaggregate ~~the~~$14.9 ~~repayment~~million. ofInvesting ~~senior~~activities ~~notes~~also ininclude ~~February~~insurance ~~and~~proceeds ~~November~~of ~~2021~~$12.4 million ~~Cash flows from operating activities~~ for the ~~years~~year ~~ended~~ December 31, ~~2022~~2023, ~~and~~compared ~~2021~~to ~~include~~insurance proceeds of $19.38 million ~~and~~for ~~$19.1~~the December ~~million~~31, ~~respectively~~2022, ofboth ~~insurance proceeds~~ related to ~~cleanup costs and business interruption from~~ the 2019 Selby terminal fire.

~~For~~Net ~~the year ended December 31, 2022, we recorded net~~ cash used in ~~investing~~financing activities ofincreased $8467.45 million, ~~compared~~for tothe ~~net~~year ~~cash~~ended ~~provided~~December 31, by2023, ~~investing~~compared ~~activities~~to ~~of $76.0 million for~~ the year ended December 31, ~~2021~~2022, primarily due to ~~lower~~the ~~proceeds~~redemption ~~from~~of ~~asset~~the ~~sales~~outstanding ofSeries D Preferred Units for $~~187~~518.27 million in 2023, ~~partially~~compared ~~offset~~to bythe arepurchase ~~decrease~~of inoutstanding ~~capital~~Series ~~expenditures~~D ofPreferred Units for $40222.54 million. ~~Cash~~in ~~flows~~2022, ~~from~~partially ~~investing~~offset ~~activities~~by ~~also~~the ~~include~~issuance ~~insurance~~of ~~proceeds~~common ~~related~~units toin the ~~2019~~third ~~Selby~~quarter ~~terminal fire~~ of ~~$9.8 million~~2023 for ~~the~~approximately ~~year ended December 31, 2022, compared to~~ $9222.~~4 million~~0 ~~for the year ended December 31, 2021~~million.

Net cash used in financing activities decreased by $290.6 million for the year ended December 31, 2022, compared to the year ended December 31, 2021, mainly due to net debt borrowings of $106.6 million for the year ended December 31, 2022, compared to net debt repayments of $412.7 million for the year ended December 31, 2021, mainly due to the timing of asset sales as proceeds were used to repay debt borrowings, and the repurchase of 6,900,000 of our Series D Preferred Units in November 2022.

SOURCES OF LIQUIDITY

Revolving Credit Agreement

As of December 31, ~~2022~~2023, ~~NuStar~~our ~~Logistics’ $1.0 billion unsecured revolving credit agreement (the~~ Revolving Credit Agreement) had $~~775~~652.34 million available for borrowing and $~~220~~343.0 million of borrowings outstanding. Letters of credit issued under ~~the~~our Revolving Credit Agreement totaled $4.76 million as of December 31, ~~2022.~~2023 ~~Letters~~and ~~of credit~~ limit the amount we can borrow under ~~the~~our Revolving Credit Agreement. Obligations under ~~the~~our Revolving Credit Agreement are guaranteed by NuStar Energy and NuPOP.

~~The~~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, ~~2022~~2023, the ~~maximum~~Consolidated ~~allowed~~Debt ~~consolidated~~Coverage ~~debt~~Ratio ~~coverage ratio~~ (as defined in the Revolving Credit Agreement) ~~could~~may not exceed 5.00-to-1.00 and the ~~minimum~~Consolidated ~~consolidated~~Interest ~~interest~~Coverage ~~coverage~~Ratio ~~ratio~~ (as defined in the Revolving Credit Agreement) must not be less than 1.75-to-1.00. ~~The~~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.

18On 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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~~certain~~balance ~~investing~~is ~~activities~~no less than $150.0 Asmillion ofon ~~December 31,~~a ~~2022,~~pro ~~our~~forma ~~consolidated~~basis ~~debt~~both ~~coverage~~before ~~ratio~~and ~~was~~immediately 3after giving effect to the borrowing and the redemption.~~98x~~ On January 28, 2022, we amended and restated our ~~consolidated~~Revolving ~~interest~~Credit ~~coverage~~Agreement ~~ratio~~to, ~~was~~among ~~2.17x.~~other items:

~~On January 28, 2022, we amended and restated the Revolving Credit Agreement primarily to:~~ (i) ~~extend the maturity date from October 27, 2023 to April 27, 2025; (ii)~~ increase the maximum amount of letters of credit capable of being issued from $400.0 million to $500.0 million; (~~iii~~ii) replace London Interbank Offering Rate, or LIBOR, benchmark provisions with customary secured overnight financing rate, or SOFR, benchmark provisions; (iviii) remove the 0.50x increase permitted in our ~~consolidated~~Consolidated ~~debt~~Debt ~~coverage~~Coverage ~~ratio~~Ratio for certain rolling periods in which an acquisition for aggregate net consideration of at least $50.0 million occurs; and (viv) add baskets and exceptions to certain negative covenants. ~~Following the amendment, borrowings under the Revolving Credit Agreement bear interest, at our option, at an alternate base rate or a SOFR rate, each as defined in the Revolving Credit Agreement.~~

The interest rate on the Revolving Credit Agreement and certain fees under the Receivables Financing Agreement, defined below, are the only debt arrangements that are subject to adjustment if our debt rating is downgraded (or upgraded) by certain credit rating agencies. The following table reflects the current ratings and outlook that have been assigned to our debt:

Fitch Ratings

Moody’s Investor Service Inc.

S&P Global Ratings

Ratings

BB-

Ba3

BB-

Outlook

Stable

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 athe ~~$100.0~~Receivables ~~million~~Financing ~~receivables~~Agreement ~~financing agreement~~ with a third-party lender ~~(the Receivables Financing Agreement)~~ and agreements with certain of NuStar Energy’s wholly owned subsidiaries (together with the Receivables Financing Agreement, the Securitization Program). The amount available for borrowing under the Receivables Financing Agreement is based on the availability of eligible receivables and other customary factors and conditions. The Securitization Program contains various customary affirmative and negative covenants and default, indemnification and termination provisions, and the Receivables Financing Agreement provides for acceleration of amounts owed upon the occurrence of certain specified events. On 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.

OnSee ~~January 28,~~Note ~~2022,~~12 ~~the~~of ~~Receivables Financing Agreement was amended primarily to: (i) extend~~ the ~~scheduled~~Notes ~~termination date from September 20, 2023~~ to ~~January 31,~~Consolidated ~~2025;~~Financial ~~(ii)~~Statements ~~reduce the floor rate~~ in ~~the~~Item 8. ~~calculation~~“Financial ofStatements ~~our borrowing rates;~~ and ~~(iii)~~Supplementary ~~replace~~Data” ~~provisions~~for ~~related~~a todiscussion ~~the LIBOR rate~~ of ~~interest~~our ~~with~~debt ~~references to SOFR rates of interest~~agreements. Following the amendment, borrowings under the Receivables Financing Agreement bear interest, at NuStar Finance’s option, at a base rate or a SOFR rate, each as defined in the Receivables Financing Agreement.

~~Please~~Issuance ~~refer to Note 12~~ of ~~the~~Common ~~Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of our debt agreements.~~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 ~~utilized~~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 inon April 29, 2022 ~~and~~to ~~the~~repay ~~Eastern~~outstanding Uborrowings under our Revolving Credit Agreement.S. ~~Terminals~~See ~~Disposition~~Note in4 ~~2021~~of the Notes to ~~reduce~~Consolidated ~~debt~~Financial Statements in Item 8. “Financial Statements and ~~improve~~Supplementary ~~our~~Data” ~~debt~~for ~~metrics~~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.

Table of Contents

The following table summarizes our capital expenditures:

	Strategic Capital Expenditures		Reliability Capital Expenditures		Total
	(Thousands of Dollars)
For the year ended December 31:
2023	$	119,513	$	27,995	$	147,508
2022	$	107,855	$	32,775	$	140,630
2021	$	140,867	$	40,266	$	181,133
Expected for the year ended December 31, 2023	$ 130,000 - 150,000		$ 25,000 - 35,000

Strategic capital expenditures for the years ended December 31, ~~2022~~2023 and December 31, ~~2021~~2022 ~~mainly~~primarily consisted of expansion projects on our Permian Crude System and Central West Refined Products Pipelines, asand ~~well as~~ biofuel and other ~~terminal~~ 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.

We expect our strategic capital expenditures for the year ended December 31, 2023 to include spending of approximately $60.0 million on expansion projects to accommodate production growth in the Permian Basin and approximately $25.0 million on projects to expand our 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. Therefore, our actual capital expenditures for 2023 may increase or decrease from the expected amounts noted above.

Distributions

Preferred Units. Distributions on our preferred units are payable out of any legally available funds, accrue and are cumulative from the original issuance dates, and are payable on the 15th day (or next business day) of each of March, June, September and December of each year to holders of record on the first business day of each payment month. Please see Notes 17 and 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.

The distribution rates on the outstanding Series D Preferred Units are as follows: (i) 9.75% per annum ($0.619 per unit per distribution period) for the first two years (beginning with the September 17, 2018 distribution); (ii) 10.75% per annum ($0.682 per unit per distribution period) for years three through five; and (iii) the greater of 13.75% per annum ($0.872 per unit per distribution period) or the distribution per common unit thereafter. The number of Series D Preferred Units outstanding as of December 31, 2022 and 2021 totaled 16,346,650 and 23,246,650, respectively, as we repurchased an aggregate 6,900,000 of our Series D Preferred Units in November 2022. While the Series D Preferred Units are outstanding, the Partnership will be prohibited from paying distributions on any junior securities, including the common units, unless full cumulative distributions on the Series D Preferred Units (and any parity securities) have been, or contemporaneously are being, paid or set aside for payment through the most recent Series D Preferred Unit distribution payment date. Any Series D Preferred Unit distributions in excess of $0.635 may be paid, in the Partnership’s sole discretion, in additional Series D Preferred Units, with the remainder paid in cash. If we fail to pay in full any Series D Preferred Unit distribution amount, then, until we pay such distributions in full, the applicable distribution rate for those distribution periods shall be increased by $0.048 per Series D Preferred Unit. We would also be subject to other requirements.

Distribution information on our Series D Preferred Units is as follows:

Distribution Period	Distribution Rate per Unit		Total Distribution
			(Thousands of Dollars)
December 15, 2022 - March 14, 2023	$	0.682	$	11,148
September 15, 2022 - December 14, 2022	$	0.682	$	14,337
June 15, 2022 - September 14, 2022	$	0.682	$	15,854
March 15, 2022 - June 14, 2022	$	0.682	$	15,854
December 15, 2021 - March 14, 2022	$	0.682	$	15,854

Table of Contents

Information on our 8.50% Series A, 7.625% Series B and 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (collectively, the Series A, B and C Preferred Units) is shown below:

Units

Units Issued and Outstanding as of December 31, 2022

Optional Redemption Date/Date When Distribution Rate Became Floating

Floating Annual Rate (as a Percentage of the $25.00 Liquidation Preference Per Unit)

Series A Preferred Units

9,060,000

December 15, 2021

Three-month LIBOR plus 6.766%

Series B Preferred Units

15,400,000

June 15, 2022

Three-month LIBOR plus 5.643%

Series C Preferred Units

6,900,000

December 15, 2022

Three-month LIBOR plus 6.88%

Distribution information on our Series A, B and C Preferred Units is as follows:

	Series A Preferred Units				Series B Preferred Units				Series C Preferred Units
Distribution Period	Distribution Rate per Unit		Total Distribution		Distribution Rate per Unit		Total Distribution		Distribution Rate per Unit		Total Distribution
			(Thousands of Dollars)				(Thousands of Dollars)				(Thousands of Dollars)
December 15, 2022 - March 14, 2023	$	0.71889	$	6,513	$	0.64871	$	9,990	$	0.72602	$	5,010
September 15, 2022 - December 14, 2022	$	0.64059	$	5,804	$	0.57040	$	8,784	$	0.56250	$	3,881
June 15, 2022 - September 14, 2022	$	0.54808	$	4,966	$	0.47789	$	7,360	$	0.56250	$	3,881
March 15, 2022 - June 14, 2022	$	0.47817	$	4,332	$	0.47657	$	7,339	$	0.56250	$	3,881
December 15, 2021 - March 14, 2022	$	0.43606	$	3,951	$	0.47657	$	7,339	$	0.56250	$	3,881

In January 2023, our board of directors declared quarterly distributions with respect to the Series A, B and C Preferred Units and the Series D Preferred Units to be paid on March 15, 2023.

Common Units. Distribution payments are made to our common limited partners within 45 days after the end of each quarter as of a record date that is set after the end of each quarter. The following table summarizes information about cash distributions to our common limited partners applicable to the period in which the distributions were earned:

	Cash Distributions Per Unit		Total Cash Distributions		Record Date	Payment Date
			(Thousands of Dollars)
Quarter ended:
December 31, 2022	$	0.40	$	44,328	February 8, 2023	February 14, 2023
September 30, 2022	0.40		44,125		November 7, 2022	November 14, 2022
June 30, 2022	0.40		44,128		August 8, 2022	August 12, 2022
March 31, 2022	0.40		44,165		May 9, 2022	May 13, 2022
Year ended December 31, 2022	$	1.60	$	176,746
Year ended December 31, 2021	$	1.60	$	175,470

Tabl e of Contents

~~Debt~~We ~~Obligations~~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.

	Maturity			Outstanding Obligations as of December 31, 2022
				(Thousands of Dollars)
Receivables Financing Agreement, 6.0% as of December 31, 2022	January 31, 2025			$	80,900
Revolving Credit Agreement, 6.9% as of December 31, 2022	April 27, 2025			$	220,000
5.75% senior notes	October 1, 2025			$	600,000
6.00% senior notes	June 1, 2026			$	500,000
5.625% senior notes	April 28, 2027			$	550,000
6.375% senior notes	October 1, 2030			$	600,000
GoZone Bonds, 5.85% - 6.35%	2038	thru	2041	$	322,140
Subordinated notes, 10.8% as of December 31, 2022	January 15, 2043			$	402,500

Series D Preferred Units Redemption and Repurchase

We redeemed or repurchased all the Series D Preferred Units, as shown below:

As reflected in the table below, certain series of GoZone Bonds in principal amounts totaling $75.0 million and $103.8 million contain a requirement for the bondholders to tender their bonds in exchange for 100% of the principal plus accrued and unpaid interest on June 1, 2025 and on June 1, 2030, respectively, after which these bonds will potentially be remarketed with a new interest rate established. The following table summarizes the GoZone Bonds outstanding as of December 31, 2022:


Transaction	Transaction Date	Number of Units	Price per Unit, including Accrued Distributions		Total Price, including Accrued Distributions
					(Thousands of Dollars)
Redemption	September 12, 2023	8,286,650	$	32.59	$	270,062
Redemption	July 31, 2023	2,560,000	$	32.18	$	82,381
Redemption	June 30, 2023	5,500,000	$	31.88	$	175,340
Repurchase	November 22, 2022	6,900,000	$	32.73	$	225,837

Series

Date Issued

AmountOutstanding

Interest Rate

Mandatory Purchase Date

Maturity Date

(Thousands of Dollars)

Series 2008

June 26, 2008

55,440

6.10

June 1, 2030

June 1, 2038

Series 2010

July 15, 2010

100,000

6.35

n/a

July 1, 2040

Series 2010A

October 7, 2010

43,300

6.35

n/a

October 1, 2040

Series 2010B

December 29, 2010

48,400

6.10

June 1, 2030

December 1, 2040

Series 2011

August 9, 2011

75,000

5.85

June 1, 2025

August 1, 2041

Total

322,140

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

We believe that, as of December 31, 2022, we are in compliance with the ratios and covenants applicable to our debt obligations. A default under certain of our debt agreements would be considered an event of default under other of our debt obligations.Distributions

~~Guarantor~~Preferred ~~Summarized Financial Information~~Units. ~~NuStar~~Distributions ~~Energy~~on ~~has~~our nooutstanding ~~operations,~~preferred ~~and~~units ~~its~~are ~~assets~~payable ~~consist~~out ~~mainly~~ of ~~its~~any ~~100%~~legally ~~ownership~~available ~~interest in its indirectly owned subsidiaries~~funds, ~~NuStar~~accrue ~~Logistics~~ and ~~NuPOP. The senior and subordinated notes issued by NuStar Logistics~~ are ~~fully~~cumulative ~~and~~from ~~unconditionally~~the ~~guaranteed~~original byissuance ~~NuStar~~dates, ~~Energy~~ and ~~NuPOP.~~are ~~Each~~payable ~~guarantee~~on of the ~~senior~~15th ~~notes~~day by(or ~~NuStar~~next ~~Energy~~business ~~and~~day) ~~NuPOP ranks equally in right~~ of ~~payment~~each ~~with all other existing and future unsecured senior indebtedness~~ of ~~that~~March, ~~guarantor~~June, isSeptember ~~structurally subordinated to all existing~~ and ~~any~~December ~~future indebtedness and obligations~~ of ~~any~~each ~~subsidiaries~~year ~~of that guarantor that do not guarantee the notes and rank senior~~ to ~~its~~holders ~~guarantee~~ of ~~our~~record ~~subordinated~~on ~~indebtedness. Each guarantee of~~ the ~~subordinated~~first ~~notes~~business byday ~~NuStar Energy and NuPOP ranks equal in right~~ of ~~payment~~each ~~with all other existing and future subordinated indebtedness of that guarantor and subordinated in right of~~ payment ~~and upon liquidation to the prior payment in full of all other existing and future senior indebtedness of that guarantor~~month. ~~NuPOP~~See ~~will~~Notes be17 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~~18 ~~notes may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Please refer to Note 12~~ of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for aadditional ~~discussion of our debt agreements~~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 Period	Distribution Rate per Unit		Total 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

Tabl e of Contents

	December 31, 2022
	(Thousands of Dollars)
Summarized Combined Balance Sheet Information:
Current assets	$	44,328
Long-term assets	$	3,210,483
Current liabilities (a)	$	120,633
Long-term liabilities, including long-term debt	$	3,279,200
Series D preferred limited partners interests	$	446,970
(a)Excluding $1,694.4 million of net intercompany payables due to the non-guarantor subsidiaries from the Guarantor Issuer Group.

Series A, B and C Preferred Units. Information on our Series A, B and C Preferred Units is shown below:

Long-term assets for the non-guarantor subsidiaries totaled $1,559.3 million as of December 31, 2022.

Units

Units Issued and Outstanding as of December 31, 2023

Optional Redemption Date/Date When Distribution Rate Became Floating

Floating Annual Rate (as a Percentage of the $25.00 Liquidation Preference Per Unit)

Series A Preferred Units

9,060,000

December 15, 2021

Three-month LIBOR(a) plus 6.766%

Series B Preferred Units

15,400,000

June 15, 2022

Three-month LIBOR(a) plus 5.643%

Series C Preferred Units

6,900,000

December 15, 2022

Three-month LIBOR(a) plus 6.88%

	Year Ended December 31, 2022
	(Thousands of Dollars)
Summarized Combined Income Statement Information:
Revenues	$	824,398
Operating income	$	277,142
Interest expense, net	$	(208,479)
Net income	$	72,456

(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%.

~~Revenues~~Distribution ~~and~~information ~~net~~on ~~income~~our ~~for~~Series ~~the~~A, ~~non-guarantor~~B ~~subsidiaries~~and ~~totaled~~C ~~$858.8 million~~Preferred ~~and~~Units ~~$150.3 million,~~is ~~respectively,~~as ~~for~~follows ~~the~~(thousands ~~year~~of ~~ended December 31~~dollars, ~~2022.~~except per unit data):

Contractual Obligations


	Series A Preferred Units				Series B Preferred Units				Series C Preferred Units
Distribution Period	Distribution Rate per Unit		Total Distribution		Distribution Rate per Unit		Total Distribution		Distribution Rate per Unit		Total Distribution
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

~~The~~On ~~following~~January 25, ~~table~~2024, ~~presents~~ our ~~contractual~~Board ~~obligations~~of Directors declared quarterly distributions with respect to the Series A, B and ~~commitments~~C Preferred Units to be paid on March 15, 2024 to holders of record as of ~~December~~March 311, ~~2022:~~2024.

	Current		Long-Term
	(Thousands of Dollars)
Long-term debt maturities	$	—	$	3,275,540
Interest payments	224,970		1,631,462
Operating leases	7,535		79,649
Finance leases	6,366		68,380
Purchase obligations	7,643		19,762
Total	$	246,514	$	5,074,793

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:

The interest payments calculated for our variable-rate, long-term debt are based on interest rates and the outstanding borrowings as of December 31, 2022. The interest payments on our fixed-rate debt are based on the stated interest rates and the outstanding borrowings as of December 31, 2022. Please see Note 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.


Quarter Ended	Cash Distributions Per Unit		Total Cash Distributions		Record Date	Payment Date
			(Thousands of Dollars)
December 31, 2023	$	0.40	$	50,607	February 7, 2024	February 13, 2024
September 30, 2023	0.40		50,358		November 7, 2023	November 14, 2023
June 30, 2023	0.40		44,363		August 8, 2023	August 14, 2023
March 31, 2023	0.40		44,396		May 8, 2023	May 12, 2023
Year ended December 31, 2023	$	1.60	$	189,724

Year ended December 31, 2022	$	1.60	$	176,746

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

Tabl e of Contents

ADebt purchase obligation is an enforceable and legally binding agreement to purchase goods or services that specifies significant terms, including (i) fixed or minimum quantities to be purchased, (ii) fixed, minimum or variable price provisions and (iii) the approximate timing of the transaction. Please see Note 14 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on our purchase obligations.Obligations

The following table summarizes our debt obligations:

Series D Preferred Units Repurchase and Redemption Features


	Maturity			Outstanding Obligations as of December 31, 2023
				(Thousands of Dollars)
5.75% senior notes	October 1, 2025			$	600,000
6.00% senior notes	June 1, 2026			$	500,000
Receivables Financing Agreement, 7.0% as of December 31, 2023	July 1, 2026			$	69,800
Revolving Credit Agreement, 8.0% as of December 31, 2023	January 27, 2027			$	343,000
5.625% senior notes	April 28, 2027			$	550,000
6.375% senior notes	October 1, 2030			$	600,000
GoZone Bonds, 5.85% - 6.35%	2038	thru	2041	$	322,140
Subordinated notes, 12.4% as of December 31, 2023	January 15, 2043			$	402,500

In November 2022, we repurchased an aggregate 6,900,000 of our Series D Preferred Units at a price per unit of $32.73 for an aggregate purchase price of $225.8 million, including approximately $3.4 million related to accrued distributions. We ~~may~~believe ~~redeem all or any portion of the remaining 16~~that,~~346,650~~ ~~Series D Preferred Units outstanding, in an amount not less than $50.0 million for cash at a redemption price equal to,~~ as ~~applicable:~~of ~~(i) $~~December 31~~.73 per Series D Preferred Unit~~, ~~or up to $518.7 million, at any time on or after June 29,~~ 2023 ~~but prior to June 29~~, ~~2024;~~we ~~(ii)~~are $30.46 per Series D Preferred Unit, or up to $497.9 million, at any time on or after June 29, 2024 but prior to June 29, 2025; (iii) $29.19 per Series D Preferred Unit, or up to $477.2 million, at any time on or after June 29, 2025; plus, in ~~each~~compliance ~~case,~~with the ~~sum~~financial ofcovenants ~~any unpaid distributions on the~~ applicable ~~Series~~to Dour ~~Preferred~~debt ~~Unit~~obligations. ~~plus~~A ~~the~~default ~~distributions~~under ~~prorated~~certain ~~for the number~~ of ~~days~~our ~~elapsed~~debt ~~(not~~agreements towould ~~exceed~~be ~~90)~~considered inan ~~the~~event ~~period~~ of ~~redemption~~default ~~(Series~~under Dother ~~Partial Period Distributions). The holders have the option to convert the units prior to such redemption as discussed in Note 17~~ of ~~the~~our ~~Notes~~debt ~~to Consolidated Financial Statements in Item 8~~obligations. ~~“Financial Statements and Supplementary Data.”~~

~~Additionally,~~Receivables atFinancing ~~any~~Agreement ~~time~~and onRevolving orCredit ~~after~~Agreement. ~~June~~Borrowings ~~29,~~under ~~2028,~~the ~~each~~Receivables ~~holder~~Financing ofAgreement ~~Series~~bear Dinterest, ~~Preferred~~at ~~Units~~NuStar ~~will~~Finance’s ~~have~~option, ~~the~~at ~~right~~a tobase ~~require~~rate usor toa ~~redeem~~SOFR ~~all~~rate, ofeach ~~the~~as ~~Series~~defined Din ~~Preferred~~the ~~Units~~Receivables ~~held~~Financing byAgreement. ~~such~~Borrowings ~~holder~~under atour aRevolving ~~redemption~~Credit ~~price~~Agreement ~~equal~~bear tointerest, ~~$29.19~~at ~~per~~our ~~Series D Preferred Unit~~option, ~~plus~~at ~~any~~an ~~unpaid~~alternate ~~Series~~base Drate ~~distributions~~or ~~plus~~a ~~the~~SOFR ~~Series~~rate, Deach ~~Partial~~as ~~Period~~defined ~~Distributions.~~in Ifthe aRevolving ~~holder~~Credit ofAgreement. ~~Series~~The Dinterest ~~Preferred~~rate ~~Units~~on ~~exercises~~our ~~its~~Revolving ~~redemption~~Credit ~~right,~~Agreement weand ~~may~~certain ~~elect~~fees tounder ~~pay~~the upReceivables toFinancing ~~50%~~Agreement, ofare ~~such~~the ~~amount~~only indebt ~~common~~arrangements ~~units~~that ~~(which~~are ~~shall~~subject beto ~~valued~~adjustment atif ~~93%~~our ofdebt arating ~~volume-weighted~~is ~~average~~downgraded ~~trading~~or ~~price~~upgraded ofby ~~the~~certain ~~common~~credit ~~units);~~rating ~~provided,~~agencies. ~~that~~The ~~the~~following ~~common~~table ~~units~~reflects ~~to be issued do not, in~~ the ~~aggregate,~~current ~~exceed~~ratings ~~15%~~and ofoutlook ~~NuStar~~that ~~Energy’s~~have ~~common~~been ~~equity~~assigned ~~market~~to ~~capitalization~~our ~~at the time.~~debt:

Pension and Other Postretirement Benefit Plan Contributions

Fitch Ratings

Moody’s Investor Service Inc.

S&P Global Ratings

Ratings

Ba3

BB-

Outlook

Stable

Positive

~~During~~Gulf ~~2022,~~Opportunity weZone ~~contributed~~Revenue $5Bonds.0 ~~million~~As ~~and~~reflected ~~$0.5~~in ~~million~~the totable ~~our~~below, ~~pension~~the ~~and~~holders ~~postretirement~~of ~~benefit~~the ~~plans~~Series 2008, ~~respectively.~~Series In2010B ~~2023,~~and weSeries ~~expect~~2011 toGoZone ~~contribute~~Bonds ~~approximately $10.1~~are ~~million~~ required to ~~our~~tender ~~pension~~their ~~and~~bonds ~~postretirement~~at ~~benefit~~the ~~plans~~applicable ~~and~~mandatory ~~will~~purchase ~~monitor~~date ~~our~~in ~~funding~~exchange ~~status~~for to100% ~~determine~~of ifthe ~~any~~principal ~~contributions~~plus ~~are~~accrued ~~required~~and byunpaid ~~regulations~~interest, orafter ~~laws,~~which orthese ~~with~~bonds ~~respect~~are expected to ~~unfunded~~be ~~plans,~~remarketed ~~necessary~~with toa ~~fund~~new ~~current~~interest ~~benefits~~rate established. ~~Pension~~Each of the Series 2010 and ~~postretirement~~Series ~~benefit~~2010A ~~plans~~GoZone ~~funding~~Bonds ~~beyond 2023~~ is ~~uncertain~~subject asto redemption on or after June 1, 2030 by the ~~funding~~Parish ~~varies~~of ~~from~~St. ~~year~~James, toat ~~year~~our ~~based~~option, ~~upon~~in ~~changes~~whole or in ~~the~~part, ~~fair~~at ~~value~~a redemption price of 100% of the ~~plan~~principal ~~assets~~amount ~~and~~to ~~actuarial~~be ~~assumptions~~redeemed plus accrued interest. The following table summarizes the GoZone Bonds outstanding as of December 31, 2023:

	PensionBenefits			Other Postretirement Benefits
Series			Date Issued			AmountOutstanding		Interest Rate		Mandatory Purchase Date	Optional Redemption Date	Maturity Date
	~~(Thousands of Dollars)~~					(Thousands of Dollars)
Increase in benefit obligation as of December 31, 2022 resulting from:
Series 2008			June 26, 2008			$	55,440	6.10	%	June 1, 2030	n/a	June 1, 2038
Discount rate decrease	$	3,300		$	400
Series 2010			July 15, 2010			100,000		6.35	%	n/a	June 1, 2030	July 1, 2040
Compensation rate increase	$	500		n/a
Series 2010A			October 7, 2010			43,300		6.35	%	n/a	June 1, 2030	October 1, 2040
(Decrease) increase in net periodic benefit cost for the year ending December 31, 2023 resulting from:
Series 2010B			December 29, 2010			48,400		6.10	%	June 1, 2030	n/a	December 1, 2040
Discount rate decrease	$	(100)		$	—
Series 2011			August 9, 2011			75,000		5.85	%	June 1, 2025	n/a	August 1, 2041
Expected long-term rate of returns on plan assets decrease	$	400		n/a
			Total			$	322,140
Compensation rate increase	$	100		n/a

~~Please~~NuStar ~~see~~Logistics Subordinated Notes. 2NuStar ~~and~~Logistics’ 21$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 ~~Consolidated~~the ~~Financial~~sum ~~Statements~~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 ~~Item~~accordance 8with the terms of the notes. ~~“Financial~~NuStar ~~Statements~~Logistics ~~and~~may ~~Supplementary~~elect ~~Data”~~to defer interest payments on the Subordinated Notes on one or more occasions for up to five consecutive years. Deferred interest will accumulate additional ~~information~~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

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.

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~~Because~~cannot ~~more~~declare ~~stringent~~or ~~environmental~~make ~~and~~cash ~~safety~~distributions ~~laws~~with ~~and~~respect ~~regulations~~to, ~~are~~or ~~continuously~~redeem, ~~being~~purchase ~~enacted~~ or ~~proposed,~~make ~~the~~a ~~level~~liquidation ofpayment ~~expenditures~~with ~~required~~respect ~~for environmental~~to, ~~health~~its ~~and~~equity ~~safety~~securities ~~matters~~during isthe ~~expected~~period tothat ~~increase~~interest inpayments ~~the~~are ~~future~~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 ~~balance~~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 ~~changes~~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 ~~accruals~~subordinated ~~for~~indebtedness. ~~environmental~~Each ~~matters~~guarantee asof the subordinated notes by NuStar Energy and NuPOP ranks equal in right of payment with all other existing and ~~for~~future subordinated indebtedness of that guarantor and is subordinated in right of payment and upon liquidation to the ~~years~~prior ~~ended~~payment ~~December 31~~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, ~~2022~~including NuStar Logistics, under any bank credit facility or public debt instrument. The rights of holders of our senior and ~~2021~~subordinated ~~are~~notes ~~included~~may inbe limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. See Note 1312 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.” Wefor ~~believe~~a ~~that~~discussion weof ~~have adequately accrued for~~ our ~~environmental~~debt ~~exposures~~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:


	Current		Long-Term
	(Thousands of Dollars)
Long-term debt maturities	$	—	$	3,387,440
Interest payments	238,001		1,506,912
Operating leases	14,267		238,031
Finance leases	7,067		67,000
Purchase obligations	6,406		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

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, ~~2022~~2023, we had 1,~~167~~184 employees, of which 1,~~156~~173 are based in the United States and 11 are based in Mexico. Only 1.1 percent of our ~~1,167~~ employees are represented under collective bargaining agreements. In the United States, ~~477~~487 of our employees work at our headquarters in San Antonio, Texas, with the remaining ~~679~~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, ~~2022~~2023:

•19.41% of all of our employees and 29.80% of our employees at senior manager level and above are female; and

•3334.28% of our U.S. employees and 2324.85% 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 ~~this~~ helps to ensure that compensation levels are equitable for all employees regardless of race or gender.

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

Our culture is driven by our nine guiding principles: safety; integrity; commitment; make a difference; teamwork; respect; communication; excellence; and pride. We believe that these principles are the building blocks for our success and have helped us to recruit and retain our employees and make NuStar a great place to work. We have been recognized on FORTUNE’S “100 Best Companies to Work For” list 1213 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, ~~2022~~2023, our voluntary ~~turnover rate over the last five years has averaged 3.7%, and 224 of our employees have been employed by NuStar or predecessor entities for at least 20 years.~~

~~Safety~~27

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~~performance.~~turnover ~~The~~rate ~~Compensation~~over ~~Committee~~the oflast ~~our~~five ~~Board~~years ofhas ~~Directors~~averaged ~~also evaluates our overall environmental~~3.8%, ~~social~~ and ~~governance~~231 ~~(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~~have ~~our~~been ~~executive~~employed ~~officers,~~by ~~which~~NuStar weor ~~believe~~predecessor ~~reinforces~~entities ~~the~~for ~~importance~~at ofleast ~~maintaining~~20 ~~safe, responsible operations and focusing on ESG excellence~~years.

We are proud of NuStar’s safety performance. Our safety statistics have been substantially better than those reported by the U.S. Bureau of Labor Statistics (BLS) for our industries. Our 2022 total recordable incident rate (TRIR) of 0.23 was 17.4 times better than the 4.0 average most recently reported by BLS for the bulk terminals industry and 2.6 times better than the 0.60 average most recently reported by BLS for the pipeline transportation industry. Our 2022 days away, restricted or transferred rate (DART) of 0.23 was 13.9 times better than the 3.20 average most recently reported by BLS for the bulk terminals industry and 1.7 times better than the 0.4 average most recently reported by BLS for the pipeline transportation industry. NuStar also participates in the Occupational Safety and Health Administration’s (OSHA) Voluntary Protection Program (VPP), which promotes effective worksite health and safety. Achieving VPP Star status requires rigorous OSHA review and audit, and requires recertification every three to five years. As of December 31, 2022, approximately 91% of our eligible U.S. terminals have attained VPP Star status. NuStar also has received the International Liquids Terminals Association’s Safety Excellence Award 12 times. Throughout the COVID-19 pandemic, we continued to focus on safety and have taken measures to protect our employees and maintain safe, reliable operations.

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 ~~engagement,~~ development and training; diversity and inclusion; community involvement and development; recent awards; ~~human rights and landowner relations;~~ risk management; cybersecurity; and governance. Our Sustainability Report can be viewed at https://sustainability.nustarenergy.com. Our Sustainability Report and the information contained on our website are not part of this Annual Report on Form 10-K, are not “soliciting materials,” are not deemed filed with the SEC and are not to be incorporated by reference into any of NuStar Energy’s filings under the Securities Act of 1933 or the Securities Act of 1934, as amended, respectively.

PROPERTIES

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

RATE REGULATION

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

2628

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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 ~~2022~~2023, our capital expenditures attributable to compliance with environmental regulations were $5.9 5 million, and we currently project environmental regulatory compliance spending of approximately $612.3 5 million in ~~2023~~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 ~~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~~29

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~~subsidize~~Occupational orSafety ~~encourage the purchase~~ and ~~use~~Health ofAdministration’s ~~competing~~Process ~~fuels~~Safety orManagement ~~energy, renewable energy, electric battery-powered motor vehicle engines and renewable fuels and blending additives, like ethanol, biodiesel and renewable diesel~~regulations. These ~~programs~~regulations ~~may~~apply ~~over~~to ~~time~~processes ~~offset~~that ~~projected~~involve ~~increases or reduce the demand for refined products, particularly gasoline, in~~ certain ~~markets.~~chemicals ~~However,~~at ~~the~~or ~~increased~~above ~~production~~specified ~~and use of renewable fuels may also create opportunities for pipeline transportation and fuel blending~~thresholds. ~~Other legislative changes in the future may similarly alter the expected demand and supply projections for refined products in ways that cannot be predicted.~~

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.

~~Although~~We we take proactive steps to protect our company, systems and data from cyberattacks,. ~~such~~See asItem ~~implementing~~1C. ~~multiple~~“Cybersecurity” ~~layers~~for ofour ~~security,~~cybersecurity ~~segregated systems and user access, antivirus tools, vulnerability scanning, monitoring and patch~~ considerations.

28CRITICAL ACCOUNTING ESTIMATES

~~Table~~The preparation of ~~Contents~~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.

management, regular employee training, phishing tests, penetration tests, internal risk assessments, independent third-party assessments, tabletop exercises to test our incident response plan, enhanced cyber diligence of vendors and physical security measures, all companies are at risk of a cyberattack. Due to the continued acceleration of cyberattacks, generally and against our industry, regulatory actions by federal, state and local governmental agencies in the U.S. and in Mexico have increased. Although we believe that we have robust cybersecurity procedures and other safeguards in place, we cannot guarantee their effectiveness, and a significant failure, compromise, breach or interruption in our systems or those of our customers or vendors could have a material effect on our operations and the operations of our customers and vendors.

CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in accordance with U.S. generally accepted accounting principles requires management to select accounting policies and to make estimates and assumptions related thereto that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The accounting policies below are considered critical due to judgments made by management and the sensitivity of these estimates to deviations of actual results from management’s assumptions. The critical accounting policies should be read in conjunction with Note 2 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data,” which summarizes our significant accounting policies.

Impairment of Long-Lived Assets

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

In determining the existence of an impairment of the carrying value of an asset, we make a number of subjective assumptions as to:

•whether there is an event or circumstance that may indicate that the carrying amount of an asset may not be recoverable;

•the grouping of assets;

•the intention of holding, abandoning or selling an asset;

•the forecast of undiscounted expected future cash flows with respect to an asset or asset group; and

•if an impairment exists, the fair value of the asset or asset group.

Our estimates of undiscounted future cash flows include: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) estimates of useful lives of the assets. The identification of impairment indicators and the estimates of future undiscounted cash flows are highly subjective and are based on numerous assumptions about future operations and market conditions, which we believe to be reasonable but are inherently uncertain. The uncertainties underlying our assumptions and estimates could differ significantly from actual results and could cause a different conclusion about the recoverability of our assets. If we determined one or more assets was impaired, the amount of impairment could be material to our results of operations.

We recorded long-lived asset impairment charges of $154.9 million in 2021. Please refer to Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data,” for discussion of the impairment charges.

Impairment of Goodwill

We perform an assessment of goodwill annually or more frequently if events or changes in circumstances warrant. We have the option to first perform a qualitative annual assessment to determine whether it is necessary to perform a quantitative goodwill impairment test. A qualitative assessment includes, among other things, industry and market considerations, overall financial performance, other entity-specific events and events affecting individual reporting units. If, after assessing the totality of events or circumstances for each reporting unit, we determine that it is more likely than not that the carrying value exceeds its fair value, then we would perform a quantitative impairment test for that reporting unit.

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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 offor comparable entities. Our fair value estimates are sensitive to typical valuation assumptions, particularly our estimates for the weighted-average cost of capital used for the income approach and the guideline public company and guideline transaction multiples used for the market approach.

We recorded a goodwill impairment charge of $34.1 million for the year ended December 31, 2021. Please refer to Notes 4 and 10 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data,” for additional information.

NEW ACCOUNTING PRONOUNCEMENTS

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

AVAILABLE INFORMATION

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

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

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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 ~~business~~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 ~~reduced~~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;

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•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.

It is possible that one or more of the factors listed above, which may be further impacted by the lingering impact of the COVID-19 pandemic or other public health crises, as well as the actions of oil-producing nations, may reduce our available cash to such an extent that we are unable to pay distributions at the current level or at all in a given quarter. Cash distributions to our unitholders depend primarily upon our cash flows, including cash flows from reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items; in other words, we may be able to make cash distributions during periods in which we record net losses and may not be able to make cash distributions during periods in which we record net income.34

AnTable ~~extended period~~ of ~~reduced demand for or supply of crude oil and refined products could have an adverse impact on our results of operations, cash flows and ability to make distributions to our unitholders.~~Contents

~~Our~~Extended ~~business~~periods isof ~~ultimately~~reduced ~~dependent upon the~~ demand for ~~and~~or supply of ~~the~~ crude oil, ~~and~~ refined products, werenewable ~~transport~~fuels ~~in our pipelines~~ and ~~store~~anhydrous inammonia ~~our~~could ~~terminals.~~have ~~Market~~an ~~prices~~adverse ~~for~~impact ~~crude~~on ~~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.~~results ~~Increases in the price~~ of ~~crude oil may result in a lower demand for refined products that we transport~~operations, ~~store~~cash flows and ~~market,~~ability ~~including~~to ~~fuel~~make ~~oil,~~distributions ~~while sustained low prices may lead~~ to ~~reduced production in the markets served by~~ our ~~pipelines and storage terminals~~unitholders.

~~Any~~Our ~~sustained~~business ~~decrease~~is inultimately dependent upon the demand for and supply of the crude oil, refined products, inrenewable ~~the~~fuels ~~markets~~and anhydrous ammonia we transport in our pipelines and store in our terminals. ~~serve~~Market ~~that~~prices ~~extends~~for ~~beyond~~these ~~the~~products ~~expiration~~are ofsubject ~~our~~to ~~existing~~wide ~~throughput~~fluctuation in response to changes in global and ~~deficiency~~regional ~~agreements~~supply ~~could~~and ~~result~~demand inthat aare ~~significant~~beyond ~~reduction~~our incontrol. ~~throughputs~~Increases in ~~our~~the ~~pipelines~~price ~~and~~of ~~storage~~crude oil may result in ~~our~~a ~~terminals,~~lower ~~which~~demand ~~would~~for ~~reduce~~refined ~~our~~products ~~cash~~that ~~flows~~we transport, store and ~~impair~~market, ~~our~~including ~~ability~~fuel tooil, ~~make~~while ~~distributions~~sustained low prices may lead to ~~our~~reduced ~~unitholders.~~production ~~Factors~~in ~~that~~the ~~tend~~markets toserved ~~decrease~~by ~~market~~our ~~demand~~pipelines ~~include:~~and storage terminals.

•aAny ~~recession~~sustained decrease in demand for crude oil, ~~inflation~~refined products, renewable fuels or ~~other~~anhydrous ~~adverse~~ammonia ~~economic~~in ~~conditions~~the markets our pipelines and terminals serve that extends beyond the expiration of our existing throughput and deficiency agreements could result in ~~lower~~a ~~spending~~significant byreduction ~~consumers~~in onthroughputs ~~gasoline~~in our pipelines and storage in our terminals, ~~diesel~~which would reduce our cash flows and ~~travel;~~impair our ability to make distributions to our unitholders. Factors that tend to decrease market demand include:

•~~events~~a ~~that~~recession, ~~negatively~~high ~~impact~~interest ~~global economic activity~~rates, ~~travel~~inflation ~~and~~or ~~demand~~other ~~generally,~~adverse ~~such~~economic asconditions ~~occurred~~that result in ~~response~~lower tospending ~~the~~by ~~COVID-19~~consumers ~~pandemic~~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

•aadverse ~~decrease~~weather events resulting in decreased 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, 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;

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•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 ~~based there~~ and our ability to conduct our operations;

•competition for customers from companies with comparable assets and capabilities;

•scheduled turnarounds or unscheduled maintenance at 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;

•a decision by our current customers to redirect products transported in our pipelines to markets not served by our pipelines or to transport crude oil or refined products by means other than our pipelines; and35

•aTable ~~decision by our current customers to shut down, limit operations~~ of ~~or sell one or more of the refineries we serve to a purchaser that elects not to use our pipelines and terminals.~~Contents

•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. ~~For example, during the COVID-19 pandemic, global financial markets have experienced significant volatility, which is expected to continue during the pendency of the pandemic.~~ In addition, there are fewer investors and lenders for master limited partnership debt and equity capital market issuances than there are for corporate issuances, and negative public sentiment toward the fossil fuel energy industry has led some investors and lenders to reduce or cease investing in and lending to fossil fuel energy companies. As a result, the cost of raising capital has increased, the availability of funds has diminished and certain lenders have, and others may, refuse to refinance existing debt on similar terms or at all and reduce, or in some cases cease to provide, funding to borrowers such as us.

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

Our future financial and operating flexibility may be adversely affected by our significant leverage, any future downgrades of our credit ratings, restrictions in our debt agreements and conditions in the financial markets beyond our control.

As of December 31, ~~2022~~2023, our consolidated debt was $3.34 billion, and we have the ability to incur more debt. In addition to any potential direct financial impact of our debt, a material increase to our debt or other adverse financial factors would likely be viewed negatively by credit rating agencies, which could result in ratings downgrades, increased costs or inability for us to access the capital markets, ~~and~~ an increase in interest rates on amounts borrowed under our ~~revolving~~Revolving ~~credit~~Credit ~~agreement~~Agreement and an increase in certain fees onunder our ~~accounts~~Receivables ~~receivable~~Financing ~~securitization program~~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~~Revolving ~~credit~~Credit ~~agreement~~Agreement contains customary restrictive covenants, such as limitations on indebtedness, liens, mergers, asset transfers and certain investing activities. InFor ~~addition~~example, ~~that~~we ~~agreement~~must ~~limits~~maintain ~~us to~~ a ~~consolidated~~Consolidated ~~debt~~Debt ~~coverage~~Coverage ~~ratio~~Ratio (~~consolidated debt to consolidated EBITDA, each~~ as defined in the ~~agreement~~Revolving Credit Agreement) ~~not~~that todoes not exceed 5.00-to-1.00 and ~~requires us to maintain~~ a minimum ~~consolidated~~Consolidated ~~interest~~Interest ~~coverage~~Coverage ~~ratio~~Ratio (as defined in the ~~agreement~~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~~Event of ~~default~~Default (as defined in our Revolving Credit Agreement) and could result in acceleration of our obligations under our ~~revolving~~Revolving ~~credit~~Credit ~~agreement~~Agreement and ~~possibly~~potentially other agreements. Our ~~accounts~~Receivables ~~receivable~~Financing ~~securitization program~~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.

32Our 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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~~notes~~Changes ~~and~~in ~~other~~interest ~~debt~~rates ~~obligations~~could ~~also~~adversely ~~contain~~affect ~~various~~our ~~customary~~business, ~~affirmative~~access ~~and~~to ~~negative~~credit ~~covenants~~ and ~~default,~~capital ~~indemnification and termination provisions~~markets, and ~~provide~~the ~~for~~trading ~~acceleration~~price of amounts owed upon the occurrence of certain specified events. Future financing agreements we may enter into may contain similar or more restrictive covenants and ratio requirements than those we have negotiated for our ~~current financing agreements~~units.

~~Our~~We have significant exposure to increases in interest rates through variable rate provisions in certain of our debt ~~service~~instruments ~~obligations,~~and ~~restrictive~~our ~~covenants~~Series A, ~~ratio~~Series ~~requirements~~B and ~~maturities~~Series ~~may~~C ~~adversely~~Preferred ~~affect~~Units. ~~our~~At ~~ability~~December to31, ~~finance~~2023, ~~future~~we ~~operations,~~had ~~pursue~~approximately ~~acquisitions~~$3.4 billion of consolidated debt, ~~fund~~of ~~our~~which ~~capital~~$2.6 ~~needs~~billion was at fixed interest rates and ~~pay~~$0.8 ~~cash~~billion ~~distributions~~was toat ~~our~~variable ~~unitholders~~interest rates. InThe ~~addition~~distribution rates on our Series A, ~~this~~Series ~~leverage~~B ~~may~~and ~~make~~Series ~~our~~C ~~results~~Preferred ofUnits ~~operations~~have ~~more~~converted ~~susceptible~~from fixed to ~~adverse~~floating ~~economic~~rates. orOur ~~operating~~results ~~conditions~~of operations, ~~limit~~cash ~~our~~flows ~~flexibility~~and infinancial ~~planning~~position ~~for,~~could orbe ~~reacting~~materially ~~to,~~adversely affected by significant changes in ~~our~~interest ~~business~~rates and ~~industry~~uncertainty ~~and~~regarding ~~place~~the usfloating atrates areferenced ~~competitive~~in ~~disadvantage~~our ~~compared~~variable torate ~~competitors~~debt ~~with~~instruments ~~proportionately~~and ~~less~~preferred ~~indebtedness.~~units ~~For~~could ~~example,~~adversely ~~during~~affect anthe ~~event~~value of ~~default~~those ~~under~~financing ~~certain~~arrangements. ofPlease ~~our~~see ~~debt~~“Quantitative ~~agreements,~~and weQualitative ~~would~~Disclosures beabout ~~prohibited~~Market ~~from~~Risk” ~~making~~for ~~cash~~discussion ~~distributions~~of our market risk related to ~~our~~interest ~~unitholders~~rates.

~~Our~~We ~~ability~~plan to ~~service~~self-fund ~~our~~all ~~debt~~of ~~will~~our ~~depend on~~expenses, ~~among~~distribution ~~other~~requirements ~~things, our future financial~~ and ~~operating~~capital ~~performance~~expenditures ~~and~~for ~~our~~2024 ~~ability~~using tointernally ~~access~~generated ~~the~~cash ~~capital~~flows ~~markets,~~as ~~which~~we ~~will~~did befor ~~affected~~the byfull-years ~~prevailing economic conditions and financial~~2023, ~~business,~~2022 ~~regulatory~~ and ~~other~~2021. ~~factors,~~An ~~some~~increase ofin ~~which~~interest ~~are~~rates ~~beyond~~may ~~our~~have ~~control.~~a Ifnegative ~~our~~impact ~~operating~~on ~~results are not sufficient to service~~ our ~~indebtedness~~ability ~~and we are unable~~ to access the capital markets, ~~or otherwise~~ refinance ~~our~~existing ~~indebtedness,~~debt ~~we may be required to reduce our distributions, reduce~~ or ~~delay~~incur ~~our~~new ~~business~~debt ~~activities,~~at ~~investments~~economically orattractive ~~capital expenditures~~rates, ~~sell assets or issue additional equity,~~ which could ~~materially and~~ adversely affect our ~~financial~~future ~~condition,~~growth ~~results~~by oflimiting ~~operations,~~our ~~cash~~operational ~~flows~~ and ~~ability~~financial ~~to make distributions to unitholders, as well as the trading price of our units~~flexibility.

~~Changes~~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 ~~adversely~~have ~~affect~~an adverse impact on our ~~business~~unit price and ~~the~~impair ~~trading~~our ~~price~~ability ofto issue additional equity, incur new debt to fund growth, satisfy our ~~units~~existing debt obligations or pay distributions to our unitholders.

We have significant exposure to increases in interest rates through variable rate provisions in certain of our debt instruments and our Series A, Series B and Series C preferred units. At December 31, 2022, we had approximately $3.3 billion of consolidated debt, of which $2.6 billion was at fixed interest rates and $0.7 billion was at variable interest rates. In addition, the distribution rates on our Series A, Series B and Series C preferred units converted from a fixed rate to a floating rate in December 2021, June 2022 and December 2022, respectively. Our results of operations, cash flows and financial position could be materially adversely affected by significant changes in interest rates and uncertainty regarding the floating rates referenced in our variable rate debt instruments and preferred units could adversely affect the value of those financing arrangements. Please see “Quantitative and Qualitative Disclosures about Market Risk” for discussion of our market risk related to interest rates.

Furthermore, although we have positioned ourselves to self-fund all of our expenses, distribution requirements and capital expenditures for 2023 using internally generated cash flows as we did for the full-year 2022 and 2021, we funded our strategic capital expenditures and any acquisitions prior to 2021 primarily from borrowings under our revolving credit agreement, funds raised through debt or equity offerings and/or sales of non-strategic assets. An increase in interest rates may also have a negative impact on our ability to access the capital markets at economically attractive rates.

Moreover, the market price of master limited partnership units, like other yield-oriented securities, may be affected by, among other factors, implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, increases or decreases in interest rates may affect whether or not certain investors decide to invest in master limited partnership units, including ours, and a rising interest rate environment could have an adverse impact on our unit price and impair our ability to issue additional equity or incur debt to fund growth or for other purposes, including distributions.

Our inability to develop, fund and execute growth projects and acquire new assets could limit our ability to maintain and grow quarterly distributions to our unitholders.

Our ability to maintain and grow our distributions to unitholders depends on the growth of our existing businesses and strategic acquisitions. Decisions regarding new growth projects rely on numerous estimates, including, among other factors, the ability to secure a commitment from a customer that sufficiently exceeds our cost of capital to justify the project cost, predictions of future demand for our services, future supply shifts, crude oil 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 ~~affects~~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.

33Although 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:

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general economic conditions, the supply and demand of crude oil, refined products and renewable fuels, availability to our customers of attractively priced alternative solutions for storage, transportation or supplies of crude oil, refined products and renewable fuels and overall customer demand. As a result of these uncertainties, the anticipated benefits associated with our capital projects may not be achieved or could be delayed. In turn, this could have a negative impact on our results of operations and cash flow and our ability to make cash distributions to our unitholders.

Although we evaluate and monitor each capital spending project and try to anticipate difficulties that may arise, delays or cost increases related to capital spending programs involving construction of new facilities (or improvements and repairs to our existing facilities) adversely affect our ability to achieve forecasted operating results. Delays or cost increases arise as a result of many factors that are beyond our control, including:

•adverse economic conditions;

•market-related increases in a project’s debt or equity financing costs;

•severe adverse weather conditions, natural disasters (such as extreme temperatures, hurricanes, tornadoes, storms, floods and earthquakes) or other events (such as ~~hurricanes,~~ equipment malfunctions, explosions, fires, spills or public health events) affecting our facilities or employees~~, or those of vendors and suppliers~~;

•non-performance or delay by, or disputes with, counterparties, vendors, suppliers, contractors or sub-contractors involved with a project;

•denial or delay in issuing requisite regulatory approvals and/or permits;

•delay or increased costs to obtain right-of-way or other property rights;

•delays or failures by third parties to complete related projects;

•protests and other activist interference with planned or in-process projects;

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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.

~~Competing~~Any ~~midstream~~of ~~service~~the ~~providers,~~above ~~including~~factors ~~certain~~may ~~major~~also ~~energy~~adversely ~~and~~affect ~~chemical~~the ~~companies~~facilities, ~~possess,~~operations or ~~have~~employees ~~greater~~of ~~financial~~counterparties, ~~resources~~vendors, ~~to acquire~~suppliers, ~~assets better suited to meet customer demand~~contractors, ~~which~~sub-contractors ~~could~~or ~~undermine~~other ~~our~~third ~~ability~~parties toinvolved ~~obtain~~with ~~and retain customers or reduce utilization of~~ our ~~assets~~projects, which could ~~reduce~~result ~~our~~in ~~revenues~~non-performance ~~and~~or ~~cash~~delay ~~flows~~by, ~~thereby~~or ~~reducing~~disputes ~~our~~with, ~~ability~~such ~~to make our quarterly distributions to unitholders~~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 ~~natural disasters,~~ 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. 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 ~~event~~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. Additionally, our pipelines, terminals and storage assets are generally long-lived assets, and some have been in service for many years. The age and condition of our assets could result in increased maintenance or repair expenditures in the future.

As a result of market conditions and losses experienced by us and other companies, the premiums and deductibles for our insurance policies have increased and could continue to increase substantially; therefore, it has become increasingly difficult to, and we may not be able to, maintain or obtain insurance of the type and amount we desire at reasonable rates. In addition, certain insurance coverage is subject to broad exclusions, and may become subject to further exclusions, become unavailable altogether or become available only for reduced amounts of coverage and at higher rates. We are not fully insured against all hazards and risks to our business, and the insurance we carry requires us to meet deductibles before we collect for losses we sustain. If we incur a significant liability for which we are uninsured or not fully insured, or if there is a significant delay in payment of a major insurance claim, such a liability could have a material adverse effect on our financial position.

34We 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 are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, vendors or other counterparties reduces our revenues and increases our expenses, and any significant level of nonpayment and nonperformance could have a negative impact on our ability to conduct our business, operating results, cash flows and our ability to service our debt obligations and make distributions to our unitholders.

Weak and volatile economic conditions and widespread financial stress reduce the liquidity of our customers, vendors or other counterparties, making it more difficult for them to meet their obligations to us. We are therefore subject to risks of loss resulting from nonpayment or nonperformance by our customers to whom we extend credit. Financial problems encountered by our customers limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements. In addition, nonperformance by vendors or their subcontractors, who have committed to provide us with critical products or services, increases our costs and could result in significant disruptions or interfere with our ability to successfully conduct our business. Although we attempt to mitigate our risk through warehouseman’s liens and other security protections, we are not always able to enforce such liens and protections due to competing claims from other parties. Any substantial increase in the nonpayment and nonperformance by our customers, vendors or other counterparties or our inability to enforce our warehouseman’s liens and other security protections could have a material adverse effect on our results of operations, cash flows and ability to make distributions to our unitholders.

We rely on our information technology and operational technology systems to conduct our business. Any significant cybersecurity breach or other significant disruption to those systems would cause our business, financial results and reputation to suffer, increase our costs and expose us to liability, and could adversely affect our ability to make distributions to our unitholders.

We rely on our information technology systems and our operational technology systems to process, transmit and store information, such as employee, customer and vendor data, and to conduct almost all aspects of our business, including safely operating our pipelines and storage facilities, recording and reporting commercial and financial transactions and receiving and making payments. We also rely on systems hosted by third parties, with respect to which we have limited visibility and control, and that have access to or store certain of our employee, customer and vendor data. The security of these networks and systems is critical to our operations and business strategy.

Although we take proactive steps to protect us, our systems and our data from cyberattacks, such as implementing multiple layers of security, segregated systems and user access, antivirus tools, vulnerability scanning, monitoring and patch management, regular employee training, phishing tests, penetration tests, internal risk assessments, independent third-party assessments, tabletop exercises to test our incident response plan, enhanced cyber diligence of vendors and physical security measures, all companies are at risk of a cyberattack. The number and sophistication of reported cyberattacks by both state-sponsored and criminal organizations continue to increase, across industries and around the world, including attacks on operators of critical infrastructure assets, such as pipelines, as well as the third parties that provide technology services for critical infrastructure, in some cases with considerable negative impact on targeted companies’ ability to conduct business.

Like other companies, we recognize that, despite our security measures, we remain subject to cybersecurity incidents due to attacks from a variety of external threat actors, internal employee error or malfeasance and cybersecurity incidents suffered by our service providers, vendors or customers. In addition, insome ~~connection with precautions during the COVID-19 pandemic, many~~ of our employees and those of our service providers, vendors and customers ~~began~~may ~~working,~~travel ~~and~~or ~~some have continued to~~ work, from home or other remote-work locations, where cybersecurity protections may be less robust and cybersecurity procedures and safeguards may be less effective. Moreover, certain attacker techniques and goals, such as surveillance, intelligence gathering or extended reconnaissance, may remain undetected for an extended period of time, which can increase the breadth and negative impact of an incident. A significant failure, compromise, breach or interruption in our systems or those of third parties critical to our operations could result in a disruption of our operations; physical damage to our assets or the environment; physical, financial, or other harm to employees or others; safety incidents; damage to our reputation; loss of customers or revenues; increased costs for remedial actions; and potential litigation or regulatory fines. Failures, interruptions and similar events that result in the loss or improper disclosure of information maintained in our systems and networks or those of our vendors, including personnel, customer and vendor information, have in the past and may in the future require reporting under relevant contractual obligations and laws and regulations protecting personal data and privacy and could also subject us to litigation or other liability under relevant contractual obligations, laws and regulations. Our financial results could also be adversely affected if our systems are breached or an employee, vendor or customer causes our systems to fail, either as a result of inadvertent error or deliberate tampering with or manipulation of our systems.

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

35Disputes 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.

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Disputes regarding a failure to maintain product quality specifications or other claims related to the operation of our assets and the services we provide to our customers result in unforeseen expenses and could result in the loss of customers.

Certain of the products we store and transport are produced to precise customer specifications. If the quality and purity of the products we receive are not maintained or a product fails to perform in a manner consistent with the quality specifications required by our customers, customers have sought, and could in the future seek, replacement of the product or damages for costs incurred as a result of the product failing to perform as guaranteed. We also have faced, and could in the future face, other claims by our customers if our assets do not operate as expected by our customers or our services otherwise do not meet our customers’ expectations. Successful claims or a series of claims against us result in unforeseen expenditures and could result in the loss of one or more customers.

Climate change, ~~and~~ fuels legislation and other regulatory initiatives restricting emissions of “greenhouse gases” may decrease demand for some of the products we store, transport and sell, increase our operating costs or reduce our ability to expand our facilities.

~~Federal~~Climate ~~and state legislative and regulatory initiatives in the United States, as well as international efforts, have attempted to and will continue to address climate~~ change and control or limit emissions of greenhouse gases. For example, the United States is now a party to the Paris Agreement and has established an economy-wide target of reducing its net greenhouse gas emissions by 50-52 percent below 2005 levels in 2030 and achieving net zero greenhouse gas emissions economy-wide by no later than 2050. The United States has also established a goal to reach 100 percent carbon emissions-free electricity by 2035. Furthermore, many state and local leaders have stated their intent to increase efforts to control or limit emissions of greenhouse gases. To this end, climate change laws or regulations enacted by the United States and other political bodies that increase costs, reduce demand or otherwise impede our operations, could, directly or indirectly, have an adverse effect on our business. ~~Specifically,~~Legislative ~~certain regulatory changes have restricted,~~ and future changes could restrict, our ability to expand our operations and have increased, and in the future could increase, our costs to operate and maintain our existing facilities by requiring that we measure and report our emissions, install new emission controls on our facilities, acquire allowances to authorize our emissions, pay taxes related to our emissions or administer and manage an emissions program, among other things. The passage of climate change legislation and interpretation and action of federal and state regulatory bodies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to greenhouse gases, or restrictions on their use, may reduce volumes available to us for transportation and storage. These developments could have adverse effects on our business, financial position, results of operations and prospects.

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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. ~~Such~~Having ~~negative~~a ~~sentiment~~more ~~regarding~~limited ~~our~~pool ~~industry~~of ~~could~~lenders ~~influence~~and ~~consumer~~investors ~~preference~~has ~~and~~resulted ~~decrease~~in ~~demand~~an ~~for~~increase ~~the~~in ~~products~~costs weto ~~transport~~raise ~~and~~capital, ~~store~~a ~~and~~decrease ~~result~~ in ~~increased~~the ~~regulatory~~availability ~~scrutiny,~~of ~~which~~new ~~could~~funding ~~then~~and ~~result~~a indiminished ~~additional~~ability ~~laws,~~to ~~regulations,~~refinance ~~guidelines~~existing ~~and~~debt ~~enforcement~~at ~~interpretations,~~favorable atrates ~~the~~for ~~federal~~businesses such as ours, ~~state~~which orcould ~~local~~have ~~level.~~a ~~These~~material ~~actions~~adverse ~~may~~effect ~~cause~~on ~~operational~~our ~~delays~~ability orto ~~restrictions,~~meet ~~increased~~our ~~operating~~future ~~costs~~capital needs, ~~additional~~satisfy ~~regulatory~~our ~~burdens~~debt ~~and~~obligations ~~increased~~or ~~risk~~pay ofdistributions ~~litigation~~to our unitholders.

Members of the lending and investment ~~community~~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 ~~community~~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 ~~industries~~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.

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investor sentiment toward us or our customers and to the diversion of investment to other industries, which would have a negative impact on our unit price and/or our access to and costs of capital.

Our operations are subject to federal, state and local laws and regulations, in the U.S. and in Mexico, relating to environmental, health, safety and security that require us to make substantial expenditures.

Our operations are subject to increasingly stringent international, federal, state and local environmental, health, safety and security laws and regulations. Transporting, storing and distributing hazardous materials, including petroleum products, entails the risk of releasing these products into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies including for damages to natural resources, personal injury or property damages to private parties and significant business interruption. Further, our pipeline facilities are subject to the pipeline integrity and safety regulations of various federal and state regulatory agencies, as well as cybersecurity directives. In recent years, increased regulatory focus on pipeline integrity, safety and security has resulted in various proposed or adopted regulations. The implementation of these regulations has required, and the adoption of future regulations could require, us to make additional capital or other expenditures, including to install new or modified safety or security measures, or to conduct new or more extensive inspection and maintenance programs.

Legislative action and regulatory initiatives have resulted in, and could in the future result in, changes to operating permits, material changes in operations, increased capital expenditures and operating costs, increased costs of the goods we transport and/or decreased demand for products we handle. Future impacts cannot be assessed with certainty at this time. Required expenditures to modify operations or install pollution control equipment or release prevention and containment systems or other environmental, health, safety or security measures could materially and adversely affect our business, financial condition, results of operations and liquidity if these expenditures, as with all costs, are not ultimately reflected in the tariffs and other fees we receive for our services.40

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

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.

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We could be subject to liabilities from our assets that predate our acquisition of those assets, but that are not covered by indemnification rights we have against the sellers of the assets.

We have acquired assets and businesses and we are not always indemnified by the seller for liabilities that precede our ownership. In addition, in some cases, we have indemnified the previous owners and operators of acquired assets or businesses. Some of our assets have been used for many years to transport and store crude oil and refined products, and past releases could require costly future remediation. If a significant release or event occurred in the past, the liability for which was not retained by the seller, or for which indemnification by the seller is not available, it could adversely affect our financial position and results of operations. Conversely, if liabilities arise from assets we have sold, we could incur costs related to those liabilities if the buyer possesses valid indemnification rights against us with respect to those assets.

Our interstate common carrier pipelines are subject to regulation by the FERC, which could have an adverse impact on our ability to recover the full cost of operating our pipelines and the revenue we are able to receive from those operations.41

~~The~~Table ~~FERC regulates the tariff rates and terms and conditions~~ of service for interstate oil movements on common carrier pipelines. FERC requires that these rates be just and reasonable and that the pipeline not engage in undue discrimination with respect to any shipper. The FERC or shippers may challenge required pipeline tariff filings, including rates and terms and conditions of service. Further, other than for rates set under market-based rate authority, if a new rate is challenged by protest and investigated by the FERC, the FERC may require the pipeline owner to refund amounts collected in excess of the deemed just and reasonable rate. In addition, shippers may challenge by complaint tariff rates and terms and conditions of service even after they take effect, and the FERC may order a carrier to change its rates prospectively to a just and reasonable level. A complaining shipper also may obtain reparations for damages sustained during the two years prior to the date of the complaint.Contents

WeCertain ~~are~~of ~~able to use various FERC-authorized rate change methodologies for~~ our interstate ~~pipelines,~~common ~~including~~carrier ~~indexed~~pipelines 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~~subject to anregulation ~~inflation~~by ~~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~~Surface ~~recent~~Transportation ~~five-year review occurring in 2020. On December 17~~Board, ~~2020,~~which ~~the~~could ~~FERC~~have ~~established~~an ~~the~~adverse ~~index~~impact ~~level for the five-year period commencing July 1, 2021, which will end~~ on ~~June~~our ~~30,~~ability ~~2026,~~to atrecover the ~~Bureau~~full ofcost ~~Labor’s producer price index for finished goods (PPI-FG) plus 0.78%. On January 20, 2022, the FERC granted rehearing~~ of ~~certain~~operating ~~aspects~~our ofpipelines ~~the final rule~~ and ~~revised~~ the ~~index~~revenue ~~level~~we toare ~~PPI-FG~~able ~~minus 0.21%, effective March 1, 2022 through June 30, 2026. FERC ordered pipelines with filed rates that exceed their index ceiling levels based on PPI-FG minus 0.21%~~ to ~~file~~receive ~~rate~~from ~~reductions~~those ~~effective March 1, 2022~~operations. ~~Pending appellate review could result in a further change to the index.~~

~~FERC~~Pursuant ~~has~~to ~~granted~~the usInterstate ~~authority~~Commerce toAct ~~charge~~(ICA) ~~market-based~~and various other laws, the FERC regulates tariff rates onand ~~some~~terms and conditions of ~~our~~service for interstate crude oil and refined products movements on common carrier pipelines,. ~~which~~The ~~are~~FERC requires that these rates be just and reasonable and not ~~subject~~unduly discriminatory with respect to ~~cost-of-service~~any shipper. The FERC or ~~indexing~~shippers ~~constraints~~may challenge required pipeline tariff filings, including rates and terms and conditions of service. IfFurther, weother ~~were~~than tofor ~~lose~~rates set under market-based rate authority, ~~however,~~if wea ~~could~~new berate ~~required~~is tochallenged ~~establish~~by ~~rates~~protest onand ~~some~~investigated ~~other~~by ~~basis~~the FERC, the FERC may require amounts refunded where such asamounts ~~cost-of-service,~~were ~~which~~collected ~~could~~in ~~reduce~~excess ~~our~~of ~~revenues~~the deemed just and ~~cash~~reasonable ~~flows~~rate. ~~Additionally~~In addition, ~~because~~shippers ~~competition~~may ~~constrains~~challenge ~~our~~by complaint tariff rates inand ~~various~~terms ~~markets~~and conditions of service even after they take effect, weand the FERC may ~~from~~order ~~time~~a carrier to ~~time~~change beits ~~forced~~rates prospectively to ~~reduce~~a ~~some~~just ofand ~~our~~reasonable ~~rates~~level. A complaining shipper also may obtain reparations for damages sustained during the two years prior to ~~remain~~the ~~competitive~~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 ~~our~~ operating expenses and our ability to make distributions to our unitholders.

Power costs constitute a significant portion of our operating expenses. For the year ended December 31, ~~2022~~2023, our power costs equaled approximately $5148.62 million, or 1413% of our operating expenses for the year. We use mainly electric power at our pipeline pump stations and terminals, and such electric power is furnished by various utility companies. Requirements for utilities to use less carbon intensive power or to add pollution control devices also could cause our power costs to increase and our cash flows may be adversely affected, which could adversely affect our ability to make distributions to our unitholders.

We may be adversely affected by changes in the method of determining the London Interbank Offering Rate (LIBOR) or the replacement of LIBOR with an alternative reference rate, such as the Secured Overnight Financing Rate (SOFR).

The publication of non-U.S. dollar LIBOR rates ceased after publication on December 31, 2021 and the publication of U.S. dollar LIBOR rates for the most common tenors (overnight and one, three, six and twelve months) is ~~expected~~ceased ~~to cease~~ after publication on June 30, 2023. ~~Regulators~~In ~~have~~addition, ~~emphasized~~in ~~that~~March 2022, ~~despite~~the ~~any~~Adjustable ~~continued~~Interest ~~publication~~Rate of(LIBOR) UAct (the “LIBOR Act”) was signed into law.S. ~~dollar~~This law provides a statutory fallback mechanism to replace LIBOR ~~rates~~with ~~through~~a ~~June~~benchmark ~~30,~~rate ~~2023,~~that nois ~~new~~selected ~~contracts~~by ~~using~~the ~~U.S.~~Federal ~~dollar~~Reserve Board and based on SOFR for certain contracts that reference LIBOR ~~rates~~without ~~should~~adequate befallback ~~entered~~provisions ~~into~~providing ~~after~~for a clearly defined replacement benchmark. On December 3116, ~~2021.~~2022, the Federal Reserve Board adopted a final rule to

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~~Further,~~implement ~~there~~the isLIBOR noAct ~~assurance~~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 ~~any~~terminated ~~particular~~following ~~currency~~the replacement of LIBOR. On June 30, 2023, the publication of U.S. dollar LIBOR rates ceased and, ~~tenor~~beginning with the distribution period starting on September 15, ~~will~~2023, ~~continue~~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 bethree-month ~~published~~CME ~~until~~Term ~~any~~SOFR ~~particular~~plus ~~date~~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.

In addition, in March 2022, the Adjustable Interest Rate (LIBOR) Act (the “LIBOR Act”) was signed into law. This law provides a statutory fallback mechanism to replace LIBOR with a benchmark rate that is selected by the Federal Reserve Board and based on SOFR for certain contracts that reference LIBOR without adequate fallback provisions providing for a clearly defined replacement benchmark. On December 16, 2022, the Federal Reserve Board adopted a final rule to implement the LIBOR Act and established benchmark rates based on SOFR to replace LIBOR contracts governed by U.S. law that reference certain tenors of U.S. dollar LIBOR after June 30, 2023. The regulations include provisions that (i) provide a mechanism for the automatic replacement of LIBOR with the benchmark rate selected by the Federal Reserve Board; (ii) clarify who may contractually select a benchmark replacement for LIBOR; and (iii) ensure that contracts transitioning to the replacement benchmark rate selected by the Federal Reserve Board will not be interrupted or terminated following the replacement of LIBOR.

Following the amendment and restatement of our revolving credit agreement and the amendment of our accounts receivable securitization program on January 28, 2022, to replace LIBOR with SOFR as the benchmark rate, we had approximately $0.4 billion of variable-rate indebtedness using LIBOR as a benchmark for establishing the interest rate. In addition, the distribution rates on our Series A, Series B and Series C preferred units converted from a fixed rate to a floating rate based on LIBOR in December 2021, June 2022 and December 2022, respectively. Although our variable rate indebtedness and Series A, Series B and Series C preferred units contain certain alternative calculation measures if LIBOR is no longer published, we are unable to unilaterally change the LIBOR-based rates on our variable rate indebtedness and Series A and Series B preferred units to a replacement benchmark rate without the consent of the holders of the variable rate indebtedness, the holders of 66-2/3% of each of the Series A and Series B preferred units, and we may not be able to do so on terms favorable to us. We do not anticipate seeking or obtaining consent of holders of the Series A and Series B preferred units. In accordance with the LIBOR Act, we expect that the floating rate based on LIBOR with respect to the Series A and Series B preferred units will be replaced with the 3-month SOFR plus a credit spread adjustment. The calculation agent for the Series C preferred units is able to select a replacement benchmark for LIBOR, however, such election may not be made in a manner favorable to us. Furthermore, given SOFR’s limited history and potential volatility as compared to other benchmark or market rates, the future performance of SOFR cannot be predicted based on historical performance. The consequences of the transition away from LIBOR and the use of SOFR cannot be entirely predicted but could include an increase in the cost of our variable-rate indebtedness, our Series A, Series B and Series C preferred units and other commercial arrangements tied to LIBOR.

An impairment of goodwill or long-lived assets could reduce our earnings.

As of December 31, ~~2022~~2023, we had $0.7 billion of goodwill and $3.98 billion of long-lived assets, including property, plant and equipment, net and intangible assets, net. ~~U.S.~~GAAP ~~generally accepted accounting principles~~ requires us to test both goodwill and long-lived assets for impairment when events or circumstances occur indicating that either goodwill or long-lived assets might be impaired and, in the case of goodwill, at least annually. ~~Charges to impair our goodwill or our long-lived assets reduce earnings and partners’ capital.~~ Any event that causes a reduction in demand for our services could result in a reduction of our estimates of future cash flows and growth rates in our business, which could cause us to record an impairment charge to reduce the value of goodwill. Similarly, any event or change in circumstances that causes the carrying value of our long-lived assets to no longer be recoverable may require us to record an impairment charge to reduce the value of our long-lived assets. If we determine that either our goodwill or our long-lived assets are impaired, the resulting charge will reduce earnings and partners’ capital.

If we determine that either our goodwill or our long-lived assets are impaired, the resulting charge will reduce earnings and partners’ capital.

RISKS INHERENT IN AN INVESTMENT IN US

As a master limited partnership, we do not have the same flexibility that corporations and other ~~types~~business of organizations may have to accumulate cash and prevent illiquidity in the future, which may ~~also~~ limit our growth.

Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our common unitholders of all available cash, after taking into account reserves for commitments and contingencies, including growth and other capital expenditures and operating costs, debt service requirements and payments with respect to our preferred units. We are therefore more likely than those organizations to require issuances of additional debt and equity securities to finance our growth plans, meet unforeseen cash requirements and service our debt and other obligations. 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.

In addition, to the extent we issue additional units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain our current per unit distribution level and the value of our common units and other limited partner interests may decrease in correlation with any reduction in our cash distributions per unit. Accordingly, if we experience a liquidity shortage in the future, we may not be able to issue more equity to recapitalize.

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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. ~~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 cannot vote on any matter without the prior approval of our general partner.

We may issue additional equity securities, including equity securities that are senior to our common units, which would dilute our unitholders’ existing ownership interests.

Our partnership agreement allows us to issue an unlimited number of additional equity securities without the approval of other unitholders as long as the newly issued equity securities are not senior to, or equally ranked with, our preferred units. ~~With~~We ~~the consent of the holders of a majority of the Series D preferred units, we~~ may issue an unlimited number of units that are senior to our common units and equally ranked with our preferred units. However, in certain circumstances, we may be required to obtain the approval of the holders of a majority of each class of our preferred units before we could issue equity securities that are equally ranked with our preferred units.

Our issuance of additional units or other equity interests of equal or senior rank will have the following effects:

•our unitholders’ proportionate ownership interest in us will decrease;

•the amount of cash available for distribution on each unit may decrease;

•the amount of cash available for redemption of, or payment of the liquidation preference on, each preferred unit may decrease;

•the ratio of taxable income to distributions may increase;

•the relative voting strength of each previously outstanding unit may be diminished; and

•the market price of our common units and preferred units may decline.

Holders of our Series D preferred units generally have the same voting rights as holders of our common units and generally vote on an as-converted basis with the holders of our common units as a single class. Although holders of our other preferred units also have voting rights, such rights are limited to certain matters and require that such holders vote as a separate class with all other series of our equally ranked securities that may be issued and possess similar voting rights. As a result, the voting rights of holders of our preferred units may be significantly diluted, and the holders of such future securities of equal rank may be able to control or significantly influence the outcome of any vote with respect to which the holders of our preferred units are entitled to vote. Our partnership agreement contains limited protections for the holders of our preferred units (other than Series D preferred units) in the event of a transaction, including a merger, sale, lease or conveyance of all or substantially all of our assets or business, which might adversely affect the holders of our preferred units.43

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

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

If we do not pay distributions on our preferred units in any distribution period, we would be unable to declare or pay distributions on our common units until all unpaid preferred unit distribution obligations have been paid, and our common unitholders are not entitled to receive distributions for such prior period.

Our preferred units rank senior to our common units with respect to distribution rights and rights upon liquidation. If we do not pay the required distributions on our preferred units, we will be unable to declare or pay distributions on our common units. ~~Additionally,~~Distributions ~~because distributions~~ to our preferred unitholders are cumulative, so we ~~will~~must ~~have to~~ pay all unpaid accumulated preferred distributions before we can declare or pay any distributions to our common unitholders. ~~Also,~~Distributions ~~because 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 ~~covering~~that ~~any~~would ~~prior periods. In addition, if we do not pay the required distributions on our Series D preferred units for three consecutive distribution periods, the holders of our Series D preferred units~~ have ~~certain~~accumulated ~~additional~~in ~~rights~~that until such distributions are paid, including the right to convert the Series D preferred units into common units, the right to appoint one director to our board of directors and the right to approve certain subsequent indebtedness, acquisitions or asset salesquarter. The preferences and privileges granted to holders of our 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.

If a court were to determine that a unitholder action constituted control of our business, the unitholders may lose their legal protection from liability and be required to repay distributions wrongfully distributed to them.

~~Under~~Our ~~Delaware~~partnership ~~law,~~agreement ifis 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, ~~unitholders~~that unitholder would be held liable for our obligations to the same extent as a general partner. InUnder ~~addition~~Delaware law, ~~under~~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.

40Furthermore, 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.

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

Furthermore, under Delaware law, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are nonrecourse to the partnership are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that, for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to us for the repayment of the distribution amount. Likewise, upon the winding up of our partnership, in the event that (a) we do not distribute assets in the following order: (1) to creditors in satisfaction of our debts; (2) to partners and former partners in satisfaction of liabilities for distributions owed under our partnership agreement; (3) to partners for the return of their contributions; and finally (4) to the partners in the proportions in which the partners share in distributions and (b) a limited partner knows at the time that the distribution violated Delaware law, then such limited partner will be liable to repay the distribution for a period of three years from the impermissible distribution under applicable Delaware law.

A purchaser of our common or preferred units becomes a limited partner and is liable for the obligations of the transferring limited partner to make contributions to us that are known to such purchaser of common or preferred units at the time it became a limited partner and, for unknown obligations, if the liabilities could be determined from our partnership agreement.

The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.

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

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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 ~~or otherwise adversely affect our business, financial condition or results of operations~~. We are unable to predict whether any additional changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our units or otherwise adversely affect our business, financial condition or results of operations.

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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 ~~with~~on ~~respect to~~ their income and gain from owning our units.

Non-U.S. unitholders are subject to U.S. federal income tax on income effectively connected with a U.S. trade or business (effectively connected income). A unitholder’s share of our income, gain, loss and deduction, and any gain from the sale or disposition of our units will generally be considered ~~to be~~ effectively connected income and subject to U.S. federal income tax. Additionally, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate.

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

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We will treat each purchaser of our common units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of our common units, we have adopted depreciation and amortization positions that may not conform with all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the unitholder’s tax returns.

Unitholders will likely be subject to state and local taxes and return filing requirements as a result of investing in our units.

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

We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our common unitholders.

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

We have adopted certain valuation methodologies in determining a common unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methods or the resulting allocations and such a challenge could adversely affect the value of our common units.

In determining the items of income, gain, loss and deduction allocable to our common unitholders, we must routinely determine the fair market value of our respective assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our respective assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

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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 ~~creates~~is auncertain ~~different tax treatment for the holders of preferred units than the holders of our common units~~ and such distributions are not eligible for the 20% deduction for qualified publicly traded partnership income.

The tax treatment of distributions on our preferred units is uncertain. We will treat the holders of preferred units as partners for tax purposes and will treat distributions on the preferred units as guaranteed payments for the use of capital that will generally be taxable to the holders of preferred units as ordinary income. Holders of preferred units will recognize taxable income from the accrual of such a guaranteed payment even in the absence of a contemporaneous distribution. Otherwise, the holders of preferred units are generally not anticipated to share in our items of income, gain, loss or deduction, nor will we allocate any share of our nonrecourse liabilities to the holders of preferred units. If the preferred units were treated as indebtedness for tax purposes, rather than as guaranteed payments for the use of capital, distributions likely would be treated as payments of interest by us to the holders of preferred units.

43Although 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.

~~Table~~A holder of ~~Contents~~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.

purposes, rather than as guaranteed payments for the use of capital, distributions likely would be treated as payments of interest by us to the holders of preferred units.

Although we expect that much of our income will be eligible for the 20% deduction for qualified publicly traded partnership income, Treasury regulations provide that income attributable to a guaranteed payment for the use of capital is not eligible for the 20% deduction for qualified business income. As a result, income attributable to a guaranteed payment for use of capital recognized by holders of our preferred units is not eligible for the 20% deduction for qualified business income.

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

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

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

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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 D Preferred Units

On November 16, 2022, NuStar Energy L.P. entered into agreements with EIG Nova Equity Aggregator, L.P and FS Energy and Power Fund to repurchase an aggregate 6,900,000 of our Series D Cumulative Convertible Preferred Units (Series D Preferred Units) at a price per unit of $32.73 for an aggregate purchase price of $225.8 million, including approximately $3.4 million related to accrued distributions. These transactions closed on November 22, 2022. The number of Series D Preferred Units outstanding as of December 31, 2022 and 2021, totaled 16,346,650 and 23,246,650, respectively.

Series A, B and C Preferred Units

Units

Units Issued and Outstanding as of December 31, ~~2022~~2023

Optional Redemption Date/Date When Distribution Rate Became Floating

Floating Annual Rate (as a Percentage of the $25.00 Liquidation Preference Per Unit)

Series A Preferred Units

9,060,000

December 15, 2021

Three-month LIBOR(a) plus 6.766%

Series B Preferred Units

15,400,000

June 15, 2022

Three-month LIBOR(a) plus 5.643%

Series C Preferred Units

6,900,000

December 15, 2022

Three-month LIBOR(a) plus 6.88%

(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 97, ~~2023~~2024, we had ~~360~~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. ~~This~~Available ~~term~~Cash is generally defined in the partnership agreement ~~generally~~ as all cash receipts less cash disbursements, including distributions to our preferred ~~units~~unit holders, and cash reserves established by ~~the~~our general partner, in its sole discretion.

~~Please~~See ~~see~~Note ~~Notes 17 and~~ 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on our Series ~~D Preferred Units, Series~~ A, B and C Preferred Units and common units.

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Performance Graph

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

The following graph compares the cumulative five-year total return provided to holders of NuStar Energy’s common units relative to the cumulative total returns of the S&P 500 index and the Alerian MLP index. An investment of $100 (with reinvestment of all dividends) is assumed to have been made in our common units and in each of the indexes on December 31, 2017, and its relative performance is tracked through December 31, 2022.

*An investment of $100 ~~invested~~(with reinvestment of all dividends) is assumed to have been made in our common units and in each of the indexes on December 31, ~~2017~~2018, inand ~~stock~~its orrelative ~~index,~~performance ~~including~~is ~~reinvestment~~tracked ofthrough ~~dividends~~December 31, 2023.

	As of December 31,
	2017		2018		2019		2020		2021		2022
	2018		2019		2020		2021		2022		2023
NuStar Energy L.P.	~~100.00~~$	100.00	~~77.87~~$	135.03	~~105.15~~$	84.77	~~66.01~~$	103.03	~~80.23~~$	114.84	~~89.42~~$	147.51
S&P 500 Index	100.00		95131.6249		~~125~~155.7268		~~148~~200.8537		~~191~~164.5808		~~156~~207.8921
Alerian MLP Index	100.00		87106.5856		9375.3299		66106.5551		93139.2844		~~122~~176.1247

Sales of Unregistered Securities

During the fourth quarters of 2022, ~~2021~~ and ~~2020 and the first quarter of 2020~~2021, NuStar Energy issued an aggregate of 3,120 common units, and 5,509 common units, ~~11,384 common units and nine common units,~~ respectively, in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof, upon the vesting of outstanding awards under a long-term incentive plan.

ITEM 6. RESERVED

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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. Borrowings under our variable-rate debt expose us to increases in interest rates.

On ~~January~~June 2830, ~~2022~~2023, we amended ~~and restated~~ our $1.0 billion unsecured revolving credit agreement to(as ~~extend~~amended, the ~~maturity~~Revolving toCredit ~~April 27~~Agreement), ~~2025,~~primarily ~~replace~~to extend the ~~LIBOR-based~~maturity ~~interest~~date ~~rate~~from ~~and~~April 27, ~~modify~~2025 ~~other~~to ~~terms~~January 27, 2027. ~~Also~~On ~~on January~~June 2829, ~~2022~~2023, we amended our $100.0 million receivables financing agreement (as amended, the Receivables Financing Agreement) to extend the scheduled termination date tofrom January 31, 2025, ~~replace~~to ~~the~~July 1, ~~LIBOR-based interest rate and modify other terms~~2026. ~~Please~~See ~~refer to~~ Note 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for more information.

The following tables present principal cash flows and related weighted-average interest rates by expected maturity dates for our long-term debt, excluding finance leases:


	December 31, 2023
	Expected Maturity Dates
	2024		2025			2026			2027			2028		There- after			Total			Fair Value
	(Thousands of Dollars, Except Interest Rates)
Fixed-rate debt	$	—	$	600,000		$	500,000		$	550,000		$	—	$	922,140		$	2,572,140		$	2,595,857
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, 2022
	Expected Maturity Dates
	2023		2024		2025			2026			2027			There-after			Total			FairValue
	(Thousands of Dollars, Except Interest Rates)
Fixed-rate debt	$	—	$	—	$	600,000		$	500,000		$	550,000		$	922,140		$	2,572,140		$	2,478,720
Weighted-average rate	—		—		5.8		%	6.0		%	5.6		%	6.3		%	6.0		%	—
Variable-rate debt	$	—	$	—	$	300,900		$	—		$	—		$	402,500		$	703,400		$	690,944
Weighted-average rate	—		—		6.7		%	—			—			10.8		%	9.0		%	—

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

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 Series A, B and C Preferred Units expose us to changes in interest rates as the distribution rates on these units converted to a floating rate ~~of the applicable LIBOR plus a spread~~ on December 15, 2021, June 15, 2022 and December 15, 2022, respectively. Based upon the 9,060,000 Series A Preferred Units, 15,400,000 Series B Preferred Units and 6,900,000 Series C Preferred Units outstanding atas ~~December~~of December 31, ~~2022~~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. ~~Please~~See ~~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.

COMMODITY 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. Derivative financial instruments associated with commodity price risk were not material for any periods presented.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX

Management's Report on Internal Control over Financial Reporting			5054
Reports of Independent Registered Public Accounting Firm			5155
Consolidated Balance Sheets			5458
Consolidated Statements of Income (Loss)			55
Consolidated Statements of Income			59
Consolidated Statements of Comprehensive Income (Loss)			56
Consolidated Statements of Comprehensive Income			60
Consolidated Statements of Cash Flows			5761
Consolidated Statements of Partners' Equity and Mezzanine Equity			5862
Notes to Consolidated Financial Statements			5963
1. Organization and Operations			5963
2. Summary of Significant Accounting Policies			6064
3. New Accounting Pronouncement			65
3. New Accounting Pronouncements			70
4. Dispositions and Impairments			6570
5. Revenue from Contracts with Customers			6772
6. Allowance for Credit Losses			6873
7. Inventories			6873
8. Property, Plant and Equipment			6974
9. Intangible Assets			6974
10. Goodwill			7074
11. Accrued Liabilities			7075
12. Debt			7175
13. Health, Safety and Environmental Matters			7478
14. Commitments and Contingencies			7579
15. Lease Assets and Liabilities			7679
16. Derivatives and Fair Value Measurements			7881
17. Series D Cumulative Convertible Preferred Units			7982
18. Partners’ Equity			8185
19. Net Income (Loss) per Common Unit			8387
20. Supplemental Cash Flow Information			8488
21. Employee Benefit Plans			8589
22. Unit-based Compensation			9094
23. Income Taxes			9497
24. Segment Information			9599
25. Subsequent Event			100

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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, ~~2022~~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, ~~2022~~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.

The effectiveness of internal control over financial reporting as of December 31, ~~2022~~2023 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 5357.

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Report of Independent Registered Public Accounting Firm

To the Board of Directors of NuStar GP, LLC and Unitholders of

~~and Unitholders of~~ NuStar Energy L.P.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of NuStar Energy L.P. and subsidiaries (the Partnership) as of December 31, ~~2022~~2023 and ~~2021~~2022, the related consolidated statements of income ~~(loss)~~, comprehensive income ~~(loss)~~, cash flows, and partners’ equity and mezzanine equity for each of the years in the three-year period ended December 31, ~~2022~~2023, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, ~~2022~~2023 and ~~2021~~2022, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, ~~2022~~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), the Partnership’s internal control over financial reporting as of December 31, ~~2022~~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 2322, ~~2023~~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, ~~2022~~2023 was $3,~~403~~283 million, or 6867% of total assets, of which certain assets or asset groups were not supported by existing revenue generating contacts or have not historically had consistent revenue generating activities.

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

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the 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 2322, ~~2023~~2024

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Report of Independent Registered Public Accounting Firm

~~The~~To the Board of Directors of NuStar GP, LLC and Unitholders of

~~and Unitholders of~~ NuStar Energy L.P.:

Opinion on Internal Control Over Financial Reporting

We have audited NuStar Energy L.P. and subsidiaries' (the Partnership) internal control over financial reporting as of December 31, ~~2022~~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, ~~2022~~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), the consolidated balance sheets of the Partnership as of December 31, ~~2022~~2023 and ~~2021~~2022, the related consolidated statements of income ~~(loss)~~, comprehensive income ~~(loss)~~, cash flows, and partners’ equity and mezzanine equity for each of the years in the three-year period ended December 31, ~~2022~~2023, and the related notes (collectively, the consolidated financial statements), and our report dated February 2322, ~~2023~~2024 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

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

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

Definition and Limitations of Internal Control Over Financial Reporting

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

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

/s/ KPMG LLP

San Antonio, Texas

February 2322, ~~2023~~2024

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of Dollars, Except Unit Data)

	December 31,
	2022		2021
	2023		2022
Assets
Current assets:
Cash and cash equivalents	$	142,~~489~~765	$	514,~~637~~489
Accounts receivable, net	~~149~~135,~~971~~787		~~135~~149,~~126~~971
Inventories	1518,~~397~~623		1615,~~644~~397
Prepaid and other current assets	2429,~~067~~927		2724,~~135~~067
Total current assets	~~203~~187,~~924~~102		~~184~~203,~~542~~924
Property, plant and equipment, at cost	5,~~733~~789,~~685~~927		5,~~728~~733,~~848~~685
Accumulated depreciation and amortization	(2,~~330~~507,~~602~~390)		(2,~~187~~330,~~206~~602)
Property, plant and equipment, net	3,~~403~~282,~~083~~537		3,~~541~~403,~~642~~083
Intangible assets, net	~~513~~476,~~696~~063		~~557~~513,~~785~~696
Goodwill	732,356		732,356
Other long-term assets, net	~~120~~218,~~627~~334		~~140~~120,~~007~~627
Total assets	$	4,~~973~~896,~~686~~392	$	54,~~156~~973,~~332~~686
Liabilities, Mezzanine Equity and Partners’ Equity
Current liabilities:
Accounts payable	$	6777,~~765~~050	$	8267,~~446~~765
Current portion of finance leases	4,~~416~~951		34,~~848~~416
Accrued interest payable	3739,~~607~~975		3437,~~139~~607
Accrued liabilities	7688,~~072~~062		7976,~~818~~072
Taxes other than income tax	10,~~607~~948		1410,~~475~~607
Total current liabilities	~~196~~220,~~467~~986		~~214~~196,~~726~~467
Long-term debt, less current portion of finance leases	3,~~293~~410,~~415~~338		3,~~183~~293,~~555~~415
Deferred income tax liability	3,~~219~~933		113,~~831~~219
Other long-term liabilities	~~131~~214,~~299~~854		~~147~~131,~~956~~299
Total liabilities	3,~~624~~850,~~400~~111		3,~~558~~624,~~068~~400
Commitments and contingencies (Note 14)
Series D preferred limited partners (16,346,650 and 23,246,650 units outstanding as ofDecember 31, 2022 and 2021, respectively) (Note 17)	446,970		616,439
Series D preferred limited partners (0 and 16,346,650 units outstanding as ofDecember 31, 2023 and 2022, respectively) (Note 17)	—		446,970
Partners’ equity (Note 18):
Preferred limited partners:
Series A (9,060,000 units outstanding as of December 31, 2022 and 2021)	218,307		218,307
Series A (9,060,000 units outstanding as of December 31, 2023 and 2022)	218,307		218,307
Series B (15,400,000 units outstanding as of December 31, 2022 and 2021)	371,476		371,476
Series B (15,400,000 units outstanding as of December 31, 2023 and 2022)	371,476		371,476
Series C (6,900,000 units outstanding as of December 31, 2022 and 2021)	166,518		166,518
Series C (6,900,000 units outstanding as of December 31, 2023 and 2022)	166,518		166,518
Common limited partners (110,818,718 and 109,986,273 common units outstandingas of December 31, 2022 and 2021, respectively)	177,620		299,502
Common limited partners (126,516,713 and 110,818,718 units outstandingas of December 31, 2023 and 2022, respectively)	312,905		177,620
Accumulated other comprehensive loss	(3122,~~605~~925)		(7331,~~978~~605)
Total partners’ equity	~~902~~1,~~316~~046,281		~~981~~902,~~825~~316
Total liabilities, mezzanine equity and partners’ equity	$	4,~~973~~896,~~686~~392	$	54,~~156~~973,~~332~~686

See Notes to Consolidated Financial Statements.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME ~~(LOSS)~~

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

	Year Ended December 31,
	2022		2021		2020
	2023		2022		2021
Revenues:
Service revenues	$	1,~~120~~155,~~249~~567	$	1,~~157~~120,~~410~~249	$	1,~~205~~157,~~494~~410
Product sales	~~562~~478,~~974~~620		~~461~~562,~~090~~974		~~276~~461,~~070~~090
Total revenues	1,~~683~~634,~~223~~187		1,~~618~~683,~~500~~223		1,~~481~~618,~~564~~500
Costs and expenses:
Costs associated with service revenues:
Operating expenses (excluding depreciation and amortization expense)	~~364~~371,~~989~~689		~~388~~364,~~078~~989		~~403~~388,~~579~~078
Depreciation and amortization expense	~~251~~250,~~878~~982		~~266~~251,~~588~~878		~~276~~266,~~476~~588
Total costs associated with service revenues	~~616~~622,~~867~~671		~~654~~616,~~666~~867		~~680~~654,~~055~~666
Costs associated with product sales	~~486~~407,~~947~~793		~~417~~486,~~413~~947		~~256~~417,~~066~~413
Goodwill impairment losses	—		34,060		225,000
Goodwill impairment loss	—		—		34,060
Other impairment losses	~~46,122~~—		~~154~~46,~~908~~122		—154,908
General and administrative expenses (excluding depreciation and amortization expense)	~~117~~129,~~116~~846		~~113~~117,~~207~~116		~~102~~113,~~716~~207
Other depreciation and amortization expense	74,~~358~~728		7,~~792~~358		87,~~625~~792
Total costs and expenses	1,~~274~~165,~~410~~038		1,~~382~~274,~~046~~410		1,~~272~~382,~~462~~046
Operating income	408,813		236,454		209,102
Gain on sale of assets	41,075		—		—
Interest expense, net	(209,009)		(213,985)		(229,054)
Operating income	510,224		408,813		236,454
Loss on extinguishment of debt	—		—		(141,746)
Interest expense, net	(241,364)		(209,009)		(213,985)
Other income (expense), net	26,182		19,644		(34,622)
Other income, net	10,215		26,182		19,644
Income (loss) before income tax expense	225,986		42,113		(196,320)
Income before income tax expense	279,075		225,986		42,113
Income tax expense	35,~~239~~412		3,~~888~~239		23,~~663~~888
Net income (loss)	$	222,747	$	38,225	$	(198,983)
Net income	$	273,663	$	222,747	$	38,225
Basic and diluted net income (loss) per common unit (Note 19)	$	0.3672	$	(0.~~99)~~36	$	(30.1599)
Basic and diluted weighted-average common units outstanding	~~110~~116,~~341~~851,~~206~~373		~~109~~110,~~585~~341,~~635~~206		109,~~155~~585,~~117~~635

See Notes to Consolidated Financial Statements.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME ~~(LOSS)~~

(Thousands of Dollars)

	Year Ended December 31,
	2022		2021		2020
	2023		2022		2021
Net income (loss)	$	222,747	$	38,225	$	(198,983)
Net income	$	273,663	$	222,747	$	38,225
Other comprehensive income (loss):
Other comprehensive income (loss) (Note 18):
Foreign currency translation adjustment (Note 18)	41,823		601		1,410
Foreign currency translation adjustment	728		41,823		601
Net (loss) gain on pension and other postretirement benefit adjustments, net of income tax (expense) benefit of ($24), ($61) and $28	(1,556)		16,413		(4,144)
Net gain (loss) on pension and other postretirement benefit adjustments, net of income tax expense of $69, $24 and $61	5,371		(1,556)		16,413
Change in unrealized loss on cash flow hedges	—		—		(30,291)
Reclassification of loss on cash flow hedges	2,581		2,106		5,664
Reclassification of loss on cash flow hedges to interest expense, net	2,106		5,664		4,265
Total other comprehensive income	8,680		42,373		22,678
Total other comprehensive income (loss)	42,373		22,678		(28,760)
Comprehensive income	$	282,343	$	265,120	$	60,903
Comprehensive income (loss)	$	265,120	$	60,903	$	(227,743)

See Notes to Consolidated Financial Statements.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of Dollars)

	Year Ended December 31,
	2022		2021		2020
	2023		2022		2021
Cash flows from operating activities:
Net income (loss)	$	222,747	$	38,225	$	(198,983)
Net income	$	273,663	$	222,747	$	38,225
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	~~259~~255,~~236~~710		~~274~~259,~~380~~236		~~285~~274,~~101~~380
Amortization of unit-based compensation	1315,~~781~~547		1413,~~209~~781		1114,~~477~~209
Amortization of debt related items	1011,~~267~~026		1210,~~490~~267		1112,~~463~~490
(Gain) loss from sale or disposition of assets	(2,785)		(61)		38,084
Gain from sale or disposition of assets	(40,946)		(2,785)		(61)
Gain from insurance recoveries	~~(16,366)~~—		(1416,~~860~~366)		—(14,860)
Goodwill impairment losses	—		34,060		225,000
Goodwill impairment loss	—		—		34,060
Other impairment losses	~~46,122~~—		~~154~~46,~~908~~122		—154,908
Loss on extinguishment of debt	—		—		141,746
Changes in current assets and current liabilities (Note 20)	10,618		737		(14,147)
Deferred income tax (benefit) expense	(946)		(1,369)		212
Decrease in other long-term assets, net	1,199		1,091		9,867
Changes in current assets and current liabilities (Note 20)	737		(14,147)		11,928
Decrease in other long-term liabilities	(4,226)		(1,579)		(6,636)
Decrease (increase) in other long-term assets	1,091		9,867		(8,101)
Other, net	(8,322)		(5,702)		(957)
(Decrease) increase in other long-term liabilities	(1,579)		(6,636)		7,920
Net cash provided by operating activities	514,269		527,549		501,478
Other, net	(4,756)		412		151
Net cash provided by operating activities	527,549		501,478		525,998
Cash flows from investing activities:
Capital expenditures	(~~140~~147,~~630~~508)		(~~181~~140,~~133~~630)		(~~198~~181,~~079~~133)
Change in accounts payable related to capital expenditures	~~(12~~8,~~786)~~969		1(12,~~264~~786)		~~(10~~1,~~645)~~264
Proceeds from insurance recoveries	912,~~777~~395		9,~~372~~777		—9,372
Proceeds from sale or disposition of assets	59102,~~274~~904		~~246~~59,~~475~~274		~~110~~246,~~640~~475
Net cash (used in) provided by investing activities	(8423,~~365~~240)		75(84,~~978~~365)		~~(98~~75,~~084)~~978
Cash flows from financing activities:
Proceeds from Term Loan, net of discount and issuance costs	—		—		463,045
Proceeds from long-term debt borrowings	1,006,900		989,900		977,000
Proceeds from note offerings, net of issuance costs	—		—		1,182,035
Long-term debt repayments	(895,000)		(883,300)		(1,389,700)
Proceeds from other long-term debt borrowings	989,900		977,000		883,748
Redemption/repurchase of Series D preferred units	(518,680)		(222,387)		—
Proceeds from short-term debt borrowings	—		—		52,000
Proceeds from issuance of common units, net of issuance costs	221,843		—		—
Term Loan repayment, including debt extinguishment costs	—		—		(601,316)
Distributions to preferred unitholders	(116,396)		(127,299)		(127,551)
Other long-term debt repayments	(883,300)		(1,389,700)		(1,813,963)
Distributions to common unitholders	(183,444)		(176,413)		(175,263)
Repurchase of Series D preferred limited partner units	(222,387)		—		—
Payment of tax withholding for unit-based compensation	(5,694)		(6,012)		(3,384)
Short-term debt repayments	—		—		(57,500)
Other, net	(11,959)		(9,442)		(6,681)
Distributions to preferred unitholders	(127,299)		(127,551)		(124,622)
Net cash used in financing activities	(502,430)		(434,953)		(725,579)
Distributions to common unitholders	(176,413)		(175,263)		(196,203)
Effect of foreign exchange rate changes on cash	40		707		136
Payments for termination of interest rate swaps	—		—		(49,225)
Net (decrease) increase in cash, cash equivalents and restricted cash	(11,361)		8,938		(147,987)
Payment of tax withholding for unit-based compensation	(6,012)		(3,384)		(10,028)
Cash, cash equivalents and restricted cash as of the beginning of the period	23,377		14,439		162,426
Increase (decrease) in cash book overdrafts	2,331		(142)		(2,288)
Cash, cash equivalents and restricted cash as of the end of the period	$	12,016	$	23,377	$	14,439
Other, net	(11,773)		(6,539)		(17,067)
Net cash used in financing activities	(434,953)		(725,579)		(291,384)
Effect of foreign exchange rate changes on cash	707		136		916
Net increase (decrease) in cash, cash equivalents and restricted cash	8,938		(147,987)		137,446
Cash, cash equivalents and restricted cash as of the beginning of the period	14,439		162,426		24,980
Cash, cash equivalents and restricted cash as of the end of the period	$	23,377	$	14,439	$	162,426

See Notes to Consolidated Financial Statements.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY AND MEZZANINE EQUITY

(Thousands of Dollars, Except Per Unit Data)

	Limited Partners						Mezzanine Equity
	Preferred		Common		Accumulated OtherComprehensive Loss		Total Partners’ Equity (Note 18)		Series D Preferred Limited Partners (Note 17)		Total
Balance as of January 1, 2020	$	756,301	$	1,087,805	$	(67,896)	$	1,776,210	$	581,935	$	2,358,145
Balance as of January 1, 2021	$	756,301	$	572,314	$	(96,656)	$	1,231,959	$	599,542	$	1,831,501
Net income (loss)	64,134		(323,865)		—		(259,731)		60,748		(198,983)
Other comprehensive loss	—		—		(28,760)		(28,760)		—		(28,760)
Distributions to partners:
Series A, B and C preferred	(64,134)		—		—		(64,134)		—		(64,134)
Common ($1.80 per unit)	—		(196,203)		—		(196,203)		—		(196,203)
Series D preferred	—		—		—		—		(60,748)		(60,748)
Unit-based compensation	—		22,219		—		22,219		—		22,219
Series D Preferred Unit accretion	—		(17,626)		—		(17,626)		17,626		—
Other	—		(16)		—		(16)		(19)		(35)
Balance as of December 31, 2020	756,301		572,314		(96,656)		1,231,959		599,542		1,831,501
Net income (loss)	63,982		(89,174)		—		(25,192)		63,417		38,225
Other comprehensive income	—		—		22,678		22,678		—		22,678
Distributions to partners:
Series A, B and C preferred	(63,982)		—		—		(63,982)		—		(63,982)
Common ($1.60 per unit)	—		(175,263)		—		(175,263)		—		(175,263)
Series D preferred	—		—		—		—		(63,417)		(63,417)
Unit-based compensation	—		8,528		—		8,528		—		8,528
Series D Preferred Unit accretion	—		(16,903)		—		(16,903)		16,903		—
Other	—		—		—		—		(6)		(6)
Balance as of December 31, 2021	756,301		299,502		(73,978)		981,825		616,439		1,598,264
Net income	66,526		95,158		—		161,684		61,063		222,747
Other comprehensive income	—		—		42,373		42,373		—		42,373
Distributions to partners:
Series A, B and C preferred	(66,526)		—		—		(66,526)		—		(66,526)
Common ($1.60 per unit)	—		(176,413)		—		(176,413)		—		(176,413)
Series D preferred	—		—		—		—		(61,063)		(61,063)
Unit-based compensation	—		12,302		—		12,302		—		12,302
Series D Preferred Unit accretion	—		(18,538)		—		(18,538)		18,538		—
Series D Preferred Unit repurchase	—		(34,382)		—		(34,382)		(188,005)		(222,387)
Other	—		(9)		—		(9)		(2)		(11)
Balance as of December 31, 2022	$756,301	~~756,301~~	$177,620	~~177,620~~	$(31,605)	~~(31,605)~~	$902,316	~~902,316~~	$446,970	~~446,970~~	$1,349,286	~~1,349,286~~
Net income	90,114		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.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, ~~2022~~2023, ~~2021~~2022 and ~~2020~~2021

1. ORGANIZATION AND OPERATIONS

Organization

NuStar Energy L.P. (~~NYSE:~~NuStar NSEnergy) is a publicly traded Delaware limited partnership ~~primarily engaged in the transportation, terminalling and storage of petroleum products and renewable fuels and the transportation of anhydrous ammonia~~. Unless otherwise indicated, the terms “NuStar Energy,” “NS,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to NuStar Energy L.P., to one or more of our consolidated subsidiaries or to all of them taken as a whole. Our business is managed under the direction of the board of directors of NuStar GP, LLC (the Board of Directors), the general partner of our general partner, Riverwalk Logistics, L.P., both of which are indirectly 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.

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 Logistics, L.P. (NuStar Logistics) and NuStar Pipeline Operating Partnership L.P. (NuPOP). We have three business segments: pipeline, storage and fuels marketing.

Pipeline. WeOur ~~own~~assets included 9,490 miles of pipeline with aggregate storage capacity of 13.0 million barrels. Our Central West System includes 2,~~920~~915 miles of refined product pipelines and 2,~~050~~070 miles of crude oil pipelines, as well as 5.6 million barrels of crude oil storage capacity, ~~which~~while ~~comprise~~ our Central ~~West~~East System. Inincludes ~~addition, we own~~ 2,495 miles of refined product pipelines, consisting of the East and North pipelines, and aan approximately 2,000-mile ammonia pipeline, ~~which~~(the ~~comprise~~Ammonia ~~our Central East System~~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 ~~of storage capacity~~. Our terminal and storage facilities provide storage, handling and other services on a fee basis for refined products, crude oil, specialty chemicals, renewable fuels and other liquids.

Fuels Marketing. The fuels marketing segment ~~mainly~~primarily includes our bunkering operations in the Gulf Coast, as well as certain of our blending operations associated with our Central East System.

Recent Developments

~~Repurchase~~Merger ~~of Series D Preferred Units~~Agreement. On ~~November 16~~January 22, ~~2022~~2024, ~~NuStar~~we ~~Energy L.P.~~ entered into ~~agreements~~a ~~with~~merger ~~EIG~~agreement ~~Nova~~with ~~Equity~~Sunoco ~~Aggregator,~~LP ~~L.P~~ and FSits ~~Energy~~affiliates, ~~and~~in ~~Power Fund to repurchase~~ an ~~aggregate~~all-equity 6transaction,~~900,000~~ ofwhich ~~our~~will ~~Series~~result Din ~~Cumulative~~NuStar ~~Convertible~~Energy ~~Preferred~~surviving ~~Units~~the ~~(Series~~merger Das ~~Preferred~~a ~~Units),~~subsidiary ~~representing~~of ~~approximately~~Sunoco ~~one-third~~LP. At closing of the ~~outstanding units~~merger, ateach aNuStar ~~price~~Energy ~~per~~common unit ofissued ~~$32.73~~and ~~for~~outstanding animmediately ~~aggregate~~prior ~~purchase~~to ~~price~~closing ofwill ~~$225.8 million,~~be ~~including~~converted ~~approximately~~into ~~$3.4 million~~the ~~related~~right to ~~accrued~~receive ~~distributions~~0.400 ~~These~~of ~~transactions~~a ~~closed~~common onunit ~~November 22,~~of ~~2022~~Sunoco and, ~~were~~if ~~funded~~applicable, ~~with~~cash ~~borrowings~~in ~~under~~lieu ~~our~~of ~~$1.0~~fractional ~~billion unsecured revolving credit agreement~~units. ~~Please~~See ~~see~~ Note 1725 for ~~additional~~further information on the merger.

~~Point~~Redemptions ~~Tupper~~of ~~Terminal~~Series ~~Disposition.~~D OnPreferred ~~April~~Units. ~~29,~~In ~~2022,~~the wesecond ~~sold~~and ~~the~~third ~~equity~~quarters ~~interests~~of in2023, ~~our~~we ~~wholly~~redeemed ~~owned~~all ~~subsidiaries~~of ~~that~~our ~~owned~~outstanding ~~our~~Series ~~Point~~D ~~Tupper~~Preferred ~~terminal~~Units, ~~facility~~as todefined ~~EverWind~~in ~~Fuels~~Note 17, for ~~$60.0~~an ~~million~~aggregate ~~(the~~net ~~Point~~redemption ~~Tupper~~price ~~Terminal~~of ~~Disposition)~~$518.7 million. ~~Please~~See ~~refer to~~ Note 417 for ~~more~~additional information on these redemptions.

~~Other Events~~63

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

Selby Terminal Fire. On October 15, 2019, our terminal facility in Selby, California experienced a fire that destroyed two storage tanks and temporarily shut down the terminal. We received insurance proceeds of $11.1 million, $28.5 million and $35.0 million, for the years ended December 31, 2022, 2021 and 2020, respectively. In addition, we received $12.4 million in January 2023, which represented the remaining proceeds from the settlement of the property loss claim. For the years ended December 31, 2022 and 2021, we recorded gains of $16.4 million and $14.9 million, respectively, for the amount by which the insurance recoveries exceeded our expenses incurred to date, which are included in “Other income (expense), net” in the consolidated statements of income (loss). We recorded gains from business interruption insurance of $4.0 million and $6.7 million for the years ended December 31, 2021 and 2020, respectively, which are included in “Operating expenses” in the consolidated statements of income (loss).

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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 property loss claim. For the years ended December 31, 2022 and 2021, we recorded gains of $16.4 million and $14.9 million, respectively, for the amount by which the insurance recoveries exceeded our expenses incurred to date, which are included in “Other income, net” in the consolidated statements of income. We recorded 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 consolidated statements of income.

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

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

Inventories

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

Restricted Cash

As of December 31, ~~2022~~2023 and ~~2021~~2022, we have restricted cash representing legally restricted funds that are unavailable for general use totaling $8.9.3 million and $8.89 million, respectively, which is included in “Other long-term assets, net” on the consolidated balance sheets.

~~Property, Plant and Equipment~~64

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

Leases

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

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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 income, net” in the consolidated statements of 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, ~~2022~~2023 and ~~2021~~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 ~~and our Point Tupper terminal facility, prior to its disposal on April 29, 2022~~.

~~Please~~See ~~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 elected to bypass the qualitative assessment for all reporting units as of October 1, ~~2022~~2023 and October 1, ~~2021~~2022 and performed quantitative assessments, resulting in the determination that goodwill was not impaired.

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

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

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 could lead to a different determination of the fair value of our assets.65

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, 2022 are recoverable.

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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.

Impairment of Long-Lived Assets

Income Taxes

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

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

We recognize a tax position if it is more likely than not that the tax position will be sustained, based on the technical merits of the position, upon examination. We record uncertain tax positions in the financial statements at the largest amount of benefit that is more likely than not to be realized. We had no unrecognized tax benefits as of December 31, ~~2022~~2023 and ~~2021~~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 ~~2017~~2018 through ~~2021~~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.

We also have legal obligations in the form of leases and right-of-way agreements, which require us to remove certain of our assets upon termination of the agreement. However, these lease or right-of-way agreements generally contain automatic renewal provisions that extend our rights indefinitely or we have other legal means available to extend our rights. Liabilities for conditional asset retirement obligations related to the retirement of terminal assets with lease and right-of-way agreements were not material as of December 31, 2022 and 2021.66

Environmental Remediation Costs

Environmental remediation costs are expensed and an associated accrual established when site restoration and environmental remediation and cleanup obligations are either known or considered probable and can be reasonably estimated. These environmental obligations are based on estimates of probable undiscounted future costs using currently available technology and applying current regulations, as well as our own internal environmental policies. The environmental liabilities have not been reduced by possible recoveries from third parties. Environmental costs include initial site surveys, costs for remediation and restoration and ongoing monitoring costs, as well as fines, damages and other costs, when applicable and estimable. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. Environmental liabilities are difficult to assess and estimate due to unknown factors, such as the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. We believe that we have adequately accrued for our environmental exposures. Please refer to Note 13 for the amount of accruals for environmental matters.

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Environmental Remediation Costs

Environmental remediation costs are expensed, and an associated accrual established when site restoration and environmental remediation and cleanup obligations are either known or considered probable and can be reasonably estimated. These environmental obligations are based on estimates of probable undiscounted future costs using currently available technology and applying current regulations, as well as our own internal environmental policies. The environmental liabilities have not been reduced by possible recoveries from third parties. Environmental costs include initial site surveys, costs for remediation and restoration and ongoing monitoring costs, as well as fines, damages and other costs, when applicable and estimable. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. Environmental liabilities are difficult to assess and estimate due to unknown factors, such as the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. We believe that we have adequately accrued for our environmental exposures. 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 and the applicable pipeline tariff on a per barrel basis for crude oil or refined products and on a per ton basis for ammonia. Revenues generated from product sales in the pipeline segment relate to surplus pipeline loss allowance volumes.

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

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

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

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

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

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

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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.

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

Income Allocation

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

~~Basic and Diluted Net Income (Loss) Per Common Unit~~68

Basic and diluted net income (loss) per common unit is determined pursuant to the two-class method. Under this method, all earnings are allocated to our limited partners and participating securities based on their respective rights to receive distributions earned during the period. Participating securities include restricted units awarded under our long-term incentive plans. We compute basic net income (loss) per common unit by dividing net income (loss) attributable to our common limited partners by the weighted-average number of common units outstanding during the period. We compute diluted net income (loss) per common unit by dividing net income (loss) attributable to our common limited partners by the sum of (i) the weighted-average number of common units outstanding during the period and (ii) the effect of dilutive potential common units outstanding during the period. Dilutive potential common units include contingently issuable performance units awarded and the Series D Preferred Units. See Note 22 for additional information on our performance units, Note 17 for additional information on our Series D Preferred Units and Note 19 for the calculation of basic and diluted net income (loss) per common unit.

Derivative Financial Instruments

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

We enter into forward-starting swaps in order to hedge the risk of changes in the interest payments attributable to changes in the benchmark interest rate during the period from the effective date of the swap to the issuance of the forecasted debt. For forward-starting interest rate swaps designated and qualifying as cash flow hedges, we recognize the fair value of each interest rate swap in the consolidated balance sheets. We record changes in the fair value of the hedge as a component of accumulated other comprehensive income (loss) (AOCI), to the extent those cash flow hedges remain highly effective. If at any point a cash flow hedge ceases to qualify for hedge accounting, changes in the fair value of the hedge are recognized in “Interest expense,

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~~net”~~Basic ~~from~~and ~~that~~Diluted ~~date~~Net ~~forward.~~Income ~~The~~(Loss) ~~amount~~Per ~~accumulated~~Common ~~in AOCI is amortized into “Interest expense, net” as the forecasted interest payments occur or if the interest payments are probable not to occur.~~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.

Derivative Financial Instruments

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 expected rates of compensation increase. Changes in these assumptions are primarily influenced by factors outside our control. ~~Please~~See ~~refer to~~ 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 our consolidated balance sheets based on the fair value of the awards granted and recognized as compensation expense primarily on a straight-line basis over the requisite service period. Forfeitures of our unit-based compensation awards are recognized as an adjustment to compensation expense when they occur. Unit-based compensation expense is included in “General and administrative expenses” on our consolidated statements of income ~~(loss)~~. 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 and expense items are translated to U.S. dollars at weighted-average exchange rates in effect during the period. These translation adjustments are included in “Accumulated other comprehensive loss” in the equity section of the consolidated balance sheets. Upon the sale or liquidation of our investment in a foreign subsidiary, translation adjustments that have historically accumulated in AOCI related to that subsidiary are released from AOCI and reported as part ~~of the gain or loss on sale. Gains and losses on foreign currency transactions are included in “Other income (expense), net” in the consolidated statements of income (loss).~~

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

3. NEW ACCOUNTING ~~PRONOUNCEMENT~~PRONOUNCEMENTS

InImprovements ~~March 2020, the Financial Accounting Standards Board (FASB) issued guidance intended~~ to ~~provide~~Income ~~relief~~Tax to companies impacted by reference rate reform, which is the transition away from the London Interbank Offering Rate (LIBOR) as its publication is expected to cease after June 30, 2023. The amended guidance provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. The guidance is effective as of March 12, 2020 through December 31, 2024. We adopted the guidance on a prospective basis on the effective date, and it did not have an impact on our financial position, results of operations or disclosures at transition. We will continue to evaluate the impact on contracts modified on or before December 31, 2024. As of December 31, 2022, we expect the interest rate on our subordinated notes and the distribution rates on our 8.50% Series A, 7.625% Series B and 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units to transition from LIBOR-based rates to rates based on the Secured Overnight Financing Rate (SOFR), or a similar rate, beginning in the third quarter of 2023, in accordance with the guidance and the applicable rules and regulations governing such transition.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 ~~reduce~~repay ~~debt~~outstanding borrowings under our Revolving Credit Agreement and improve our debt metrics.

65During 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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During the first quarter of 2022, we determined the Point Tupper Terminal Operations met the criteria to be classified as held for sale. We compared the carrying value of the Point Tupper Terminal Operations, which included $42.2 million in cumulative foreign currency translation losses accumulated since our acquisition of the Point Tupper terminal facility in 2005, to its fair value less costs to sell, and we recognized a pre-tax impairment loss of $46.1 million in the first quarter of 2022, which is presented in "Other impairment losses" on the consolidated statements of income (loss). We believe that the sales price of $60.0 million provided a reasonable indication of the fair value of the Point Tupper Terminal Operations as it represented an exit price in an orderly transaction between market participants. The sales price was a quoted price for identical assets and liabilities in a market that was not active and, thus, our fair value estimate fell within Level 2 of the fair value hierarchy. Upon closing in the second quarter of 2022, we released $39.6 million of foreign currency translation losses from AOCI and finalized our sales price, resulting in a gain of $1.6 million, which is presented in “Other income (expense), net” on the consolidated statements of income (loss).

Eastern U.S. Terminals Disposition

On August 1, 2021, we entered into an agreement (the Purchase Agreement) to sell nine U.S. terminal and storage facilities, including all our North East Terminals and one terminal in Florida (the Eastern U.S. Terminal Operations) to Sunoco LP for $250.0 million (the Eastern U.S. Terminals Disposition). The Eastern U.S. Terminal Operations included terminals in the following locations; Jacksonville, Florida; Andrews Air Force Base, Maryland; Baltimore, Maryland; Piney Point, Maryland; Virginia Beach, Virginia; Paulsboro, New Jersey; and Blue Island, Illinois, as well as both Linden, New Jersey terminals. The Eastern U.S. Terminal Operations had an aggregate storage capacity of 14.8 million barrels and were included in the storage segment. We closed the sale on October 8, 2021 and used the proceeds from the sale to reduce debt and improve our debt metrics.

The Eastern U.S. Terminal Operations met the criteria to be classified as held for sale upon our entrance into the Purchase Agreement during the third quarter of 2021. At that time, we allocated goodwill of $34.1 million to the Eastern U.S. Terminal Operations based on its fair value relative to the terminals reporting unit, with which it had been fully integrated. We tested the allocated goodwill for impairment by comparing the fair value of the Eastern U.S. Terminal Operations to its carrying value. The results of our goodwill impairment test indicated that the carrying value of the Eastern U.S. Terminal Operations exceeded its fair value, and we recognized a related goodwill impairment charge of $34.1 million in the third quarter of 2021 to reduce the allocated goodwill to $0. The goodwill impairment loss is reported in “Goodwill impairment ~~losses~~loss” on the consolidated statements of income ~~(loss)~~. We believe that the sales price of $250.0 million provided a reasonable indication of the fair value of the Eastern U.S. Terminal Operations as it represented an exit price in an orderly transaction between market participants. The sales price was a quoted price for identical assets and liabilities in a market that was not active and, thus, our fair value estimate fell within Level 2 of the fair value hierarchy.

We 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 ~~(loss)~~. The asset impairment loss included $23.9 million related to intangible assets representing customer contracts and relationships.

We determined the assets included in the ~~above~~Point ~~dispositions~~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 ~~(loss)~~. We determined that the northern portion of the pipeline was not impaired.

6671

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Sale of Texas City Terminals

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

5. REVENUE FROM CONTRACTS WITH CUSTOMERS

Contract Assets and Contract Liabilities

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


	2023				2022				2021
	Contract Assets		Contract Liabilities		Contract Assets		Contract Liabilities		Contract Assets		Contract Liabilities
	(Thousands of Dollars)
Balances as of January 1:
Current portion	$	2,612	$	(17,647)	$	2,336	$	(15,443)	$	2,694	$	(22,019)
Noncurrent portion	304		(41,405)		504		(46,027)		932		(47,537)

Total	2,916		(59,052)		2,840		(61,470)		3,626		(69,556)

Activity:
Additions	6,621		(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

Total	922		(9,357)		76		2,418		(786)		8,086

Balances as of December 31:
Current portion	3,109		(27,131)		2,612		(17,647)		2,336		(15,443)
Noncurrent portion	729		(41,278)		304		(41,405)		504		(46,027)

Total	$	3,838	$	(68,409)	$	2,916	$	(59,052)	$	2,840	$	(61,470)

	2022				2021				2020
	Contract Assets		Contract Liabilities		Contract Assets		Contract Liabilities		Contract Assets		Contract Liabilities
	(Thousands of Dollars)
Balances as of January 1:
Current portion	$	2,336	$	(15,443)	$	2,694	$	(22,019)	$	2,140	$	(21,083)
Noncurrent portion	504		(46,027)		932		(47,537)		1,003		(40,289)
Total	2,840		(61,470)		3,626		(69,556)		3,143		(61,372)
Activity:
Additions	6,137		(45,200)		3,888		(41,121)		5,686		(69,830)
Transfer to accounts receivable	(5,978)		—		(3,977)		—		(4,828)		—
Transfer to revenues	(83)		47,618		(697)		49,207		(375)		61,646
Total	76		2,418		(786)		8,086		483		(8,184)
Balances as of December 31:
Current portion	2,612		(17,647)		2,336		(15,443)		2,694		(22,019)
Noncurrent portion	304		(41,405)		504		(46,027)		932		(47,537)
Total	$	2,916	$	(59,052)	$	2,840	$	(61,470)	$	3,626	$	(69,556)

Contract assets relate to performance obligations satisfied in advance of scheduled billings. Current contract assets are included in “Prepaid and other current assets” and noncurrent contract assets are included in “Other long-term assets, net” on the consolidated balance sheets. Contract liabilities relate to payments received in advance of satisfying performance obligations under a contract, which 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.

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

Remaining Performance Obligations

The following table presents our estimated revenue from contracts with customers for remaining performance obligations that has not yet been recognized, representing our contractually committed revenue as of December 31, ~~2022~~2023:

	Remaining Performance Obligations
	(Thousands of Dollars)
2023	$	352,995
2024	$	373,630
2024	250,738
2025	242,776
2025	154,585
2026	173,095
2026	101,656
2027	82,500
2027	34,621
2028	45,412
Thereafter	6982,~~346~~143
Total	$	~~963~~999,~~941~~556

67Our 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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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.

Disaggregation of Revenues

The following table disaggregates our revenues:


	Year Ended December 31,
	2023		2022		2021
	(Thousands of Dollars)
Pipeline segment:
Crude oil pipelines	$	388,301	$	391,176	$	331,485
Refined products and ammonia pipelines	485,568		437,015		430,753
Total pipeline segment revenues from contracts with customers	873,869		828,191		762,238



Storage segment:
Throughput terminals	104,495		110,591		122,331
Storage terminals (excluding lessor revenues)	169,810		180,903		263,883
Total storage segment revenues from contracts with customers	274,305		291,494		386,214
Lessor revenues	45,294		43,055		41,454
Total storage segment revenues	319,599		334,549		427,668

Fuels marketing segment:
Revenues from contracts with customers	440,725		520,486		428,608

Consolidation and intersegment eliminations	(6)		(3)		(14)

Total revenues	$	1,634,187	$	1,683,223	$	1,618,500

	Year Ended December 31,
	2022		2021		2020
	(Thousands of Dollars)
Pipeline segment:
Crude oil pipelines	$	391,176	$	331,485	$	329,105
Refined products and ammonia pipelines (excluding lessor revenues)	437,015		430,753		387,793
Total pipeline segment revenues from contracts with customers	828,191		762,238		716,898
Lessor revenues	—		—		1,925
Total pipeline segment revenues	828,191		762,238		718,823
Storage segment:
Throughput terminals	110,591		122,331		136,632
Storage terminals (excluding lessor revenues)	180,903		263,883		316,496
Total storage segment revenues from contracts with customers	291,494		386,214		453,128
Lessor revenues	43,055		41,454		41,314
Total storage segment revenues	334,549		427,668		494,442
Fuels marketing segment:
Revenues from contracts with customers	520,486		428,608		268,345
Consolidation and intersegment eliminations	(3)		(14)		(46)
Total revenues	$	1,683,223	$	1,618,500	$	1,481,564

6. ALLOWANCE FOR CREDIT LOSSES

~~For~~As of and for the years ended December 31, 2023, 2022 and ~~2020~~2021, balances and activity related to our allowance for credit losses ~~was~~were immaterial~~, and the balances as of December 31, 2022, 2021 and 2020 totaled $0~~.~~4 million, $0 and $0, respectively. We received a settlement of $1.7 million in the first quarter of 2021 for a credit loss that was previously written off.~~

7. INVENTORIES

Inventories consisted of the following:


	December 31,
	2023		2022
	(Thousands of Dollars)
Petroleum products	$	13,533	$	11,291
Materials and supplies	5,090		4,106
Total	$	18,623	$	15,397

	December 31,
	2022		2021
	(Thousands of Dollars)
Petroleum products	$	11,291	$	12,456
Materials and supplies	4,106		4,188
Total	$	15,397	$	16,644

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

We purchase petroleum products for resale. Our petroleum products consist of gasoline, bunker fuel and other petroleum products. Materials and supplies mainly consist of blending and additive chemicals and maintenance materials used in our pipeline and storage segments.73

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8. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:


	Estimated Useful Lives			December 31,
				2023		2022
	(Years)			(Thousands of Dollars)
Land, buildings and improvements	0	-	40	$	290,103	$	362,444
Pipelines, storage and terminals	15	-	40	5,018,249		4,936,780
Rights-of-way	15	-	40	371,568		365,171
Construction in progress				110,007		69,290
Property plant and equipment, at cost				5,789,927		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,
				2022		2021
	(Years)			(Thousands of Dollars)
Land, buildings and improvements	0	-	40	$	362,444	$	366,525
Pipelines, storage and terminals	15	-	40	4,936,780		4,897,041
Rights-of-way	20	-	40	365,171		353,262
Construction in progress				69,290		112,020
Total				5,733,685		5,728,848
Less accumulated depreciation and amortization				(2,330,602)		(2,187,206)
Property, plant and equipment, net				$	3,403,083	$	3,541,642

Capitalized interest costs added to property, plant and equipment totaled $4.3 million, $3.9 million and $3.9 million for the years ended December 31, 2023, 2022 and 2021, respectively. Depreciation and amortization expense for property, plant and equipment totaled $217.9 million, $215.0 million and $225.7 million for the years ended December 31, 2023, 2022 and 2021, respectively, which includes amortization of finance leases.

Capitalized interest costs added to property, plant and equipment totaled $3.9 million, $3.9 million and $4.9 million for the years ended December 31, 2022, 2021 and 2020, respectively. Depreciation and amortization expense for property, plant and equipment totaled $215.0 million, $225.7 million and $233.5 million for the years ended December 31, 2022, 2021 and 2020, respectively, which includes amortization of finance leases.

9. INTANGIBLE ASSETS

Intangible assets consisted of the following:


	Weighted-Average Amortization Period	December 31, 2023				December 31, 2022
		Cost		Accumulated Amortization		Cost		Accumulated Amortization
	(Years)	(Thousands of Dollars)
Customer contracts and relationships	20	$	726,000	$	(251,301)	$	793,900	$	(281,618)
Other	47	2,360		(996)		2,359		(945)
Total		$	728,360	$	(252,297)	$	796,259	$

Filing Compare · NuStar Energy L.P.