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, 2023
OR
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number 1-16417
NuStar Energy L.P.
(Exact name of registrant as specified in its charter)
| Delaware | 74-2956831 | |||||||
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |||||||
19003 IH-10 West
San Antonio, Texas 78257
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code (210) 918-2000
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||||||||||||
| Common units | NS | New York Stock Exchange | ||||||||||||
| 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 | þ | Accelerated filer | ☐ | |||||||||||||||||
| Non-accelerated filer | ☐ | Smaller reporting company | ☐ | |||||||||||||||||
| Emerging growth company | ☐ | |||||||||||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑
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 $1.7 billion based on the last sales price quoted as of June 30, 2023, the last business day of the registrant’s most recently completed second quarter.
The number of common units outstanding as of January 31, 2024 was 126,532,875.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Proxy Statement for the registrant’s 2024 annual meeting of unitholders, expected to be filed within 120 days after the end of the fiscal year covered by this Form 10-K, are incorporated by reference into Part III to the extent described therein.
NUSTAR ENERGY L.P.
FORM 10-K
TABLE OF CONTENTS
| PART I | ||||||||
| Items 1., 2. & 7 | ||||||||
| Item 1A. | ||||||||
| Item 1B. | ||||||||
| Item 1C. | ||||||||
| Item 3. | ||||||||
| Item 4. | ||||||||
| PART II | ||||||||
| Item 5. | ||||||||
| Item 6. | ||||||||
| Item 7A. | ||||||||
| Item 8. | ||||||||
| Item 9. | ||||||||
| Item 9A. | ||||||||
| Item 9B. | ||||||||
| Item 9C. | ||||||||
| PART III | ||||||||
| Item 10. | ||||||||
| Item 11. | ||||||||
| Item 12. | ||||||||
| Item 13. | ||||||||
| Item 14. | ||||||||
| PART IV | ||||||||
| Item 15. | ||||||||
| Item 16. | ||||||||
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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 demand for or supply of crude oil, refined products, renewable fuel and anhydrous ammonia. While these forward-looking statements, and any assumptions upon which they are based, are made in good faith and reflect our current judgment regarding the direction of our business, actual results will almost always vary, sometimes materially, from any estimates, predictions, projections, assumptions or other future performance suggested in this report. These forward-looking statements can generally be identified by the words “anticipates,” “believes,” “expects,” “plans,” “intends,” “estimates,” “forecasts,” “budgets,” “projects,” “will,” “could,” “should,” “may” and similar expressions. These statements reflect our current views with regard to future events and are subject to various risks, uncertainties and assumptions, which may cause actual results to differ materially. See Item 1A. “Risk Factors” for a discussion of certain of those risks, uncertainties and assumptions.
If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those described in any forward-looking statement. Other unknown or unpredictable factors could also have material adverse effects on our future results. Readers are cautioned not to place undue reliance on this forward-looking information, which is as of the date of this Form 10-K. We do not intend to update these statements unless we are required by the securities laws to do so, and we undertake no obligation to publicly release the result of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.
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. As of December 31, 2023, our limited partner interests consisted of the following:
•common units (NYSE: NS); and
•8.50% Series A (NYSE: NSprA), 7.625% Series B (NYSE: NSprB) and 9.00% Series C (NYSE: NSprC) Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (collectively, the Series A, B and C Preferred Units).
We are primarily engaged in the transportation, terminalling and storage of petroleum products and renewable fuels and the transportation of anhydrous ammonia. We also market petroleum products. The term “throughput” as used in this document generally refers to barrels of crude oil, refined product or renewable fuels, or tons of ammonia, as applicable, that pass through our pipelines, terminals or storage tanks.
We divide our operations into the following three reportable business segments: pipeline, storage and fuels marketing. As of December 31, 2023, our assets included 9,490 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.
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The following factors affect our results of operations:
•economic factors and price volatility;
•industry factors, such as changes in the prices of petroleum products that affect demand or production, or regulatory changes that could increase 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 we transport and/or store in our assets and the demand for products we sell.
See Item 1A. “Risk Factors” for additional discussion on how these factors could affect our operations.
The following map depicts our assets as of December 31, 2023:
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Merger Agreement
On January 22, 2024, NuStar Energy entered into an Agreement and Plan of Merger (the Merger Agreement) with Sunoco LP, a Delaware limited partnership (Sunoco), Saturn Merger Sub, LLC, a Delaware limited liability company and a direct wholly owned subsidiary of Sunoco (Merger Sub), Riverwalk Logistics, L.P., NuStar GP, LLC, and Sunoco GP LLC, a Delaware limited liability company and sole general partner of Sunoco (the Sunoco GP). The Merger Agreement provides that, among other things and on the terms and subject to the conditions set forth therein, Sunoco will acquire NuStar Energy in an all-equity transaction by means of a merger of Merger Sub with and into NuStar Energy (the Merger) with NuStar Energy surviving the Merger as a subsidiary of Sunoco.
On the terms and subject to the conditions set forth in the Merger Agreement, at the effective time of the Merger (the Effective Time), each NuStar Energy common unit issued and outstanding immediately prior to the Effective Time will be converted into and shall thereafter represent the right to receive 0.400 of a common unit of Sunoco and, if applicable, cash in lieu of fractional units. In addition, prior to the Effective Time, we will declare and pay a special cash distribution to our common unitholders in the amount of $0.212 per common unit (the Special Distribution) (in addition to continuing to pay our quarterly distributions in the ordinary course, subject to certain conditions, until the Effective Time).
Each Series A, B and C Preferred Unit issued and outstanding immediately prior to the Effective Time will remain issued and outstanding from and after the Effective Time as limited partnership interests of the surviving entity having the same terms as are applicable to the applicable series of NuStar Energy preferred unit immediately prior to the Effective Time.
The completion of the Merger is subject to the fulfillment or waiver of certain conditions, including, among others: approval and adoption by NuStar Energy’s common unitholders of the Merger Agreement and the transactions contemplated thereby, including the Merger; expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; and the effectiveness of the registration statement on Form S-4 to be filed by Sunoco pursuant to which Sunoco common units to be issued in connection with the Merger are registered with the U.S. Securities and Exchange Commission (the SEC).
The Merger Agreement contains termination rights for each of NuStar Energy and Sunoco. Upon termination of the Merger Agreement under specified circumstances, including the termination by Sunoco in the event of an adverse recommendation change by our Board of Directors or by NuStar Energy to accept a Superior Proposal (as defined in the Merger Agreement), NuStar Energy would be required to pay Sunoco a termination fee of approximately $90.3 million.
Concurrently with the entry into the Merger Agreement, NuStar Energy and Sunoco entered into an agreement (the Support Agreement) with Energy Transfer LP (Energy Transfer), a Delaware limited partnership and the sole member of the Sunoco GP. The Support Agreement provides, among other things, that Energy Transfer will not transfer its ownership interest in the Sunoco GP, any of the Sunoco incentive distribution rights owned by it or any material portion of the Sunoco common units owned by it prior to the Effective Time. Energy Transfer has also agreed to be bound by the terms of the non-solicitation provisions in the Merger Agreement with respect to competing proposals for Sunoco and the Sunoco GP and to abide by certain covenants with respect to regulatory approvals, SEC filings, confidentiality and litigation, among other things.
The foregoing descriptions of the Merger Agreement and the Support Agreement and the transactions contemplated thereby, including the Merger, are summaries, do not purport to be complete and are qualified in their entirety by reference to the full text of the Merger Agreement and the Support Agreement, which are included in Item 15. “Exhibits and Financial Statement Schedules” as Exhibit 2.01 and Exhibit 10.54, respectively, and incorporated by reference herein.
Other Recent Developments
Redemptions of Series D Preferred Units. In the second and third quarters of 2023, we redeemed all of our outstanding Series D Cumulative Convertible Preferred Units (the Series D Preferred Units) for an aggregate net redemption price of $518.7 million. These redemptions were primarily funded with borrowings under our Revolving Credit Agreement, as defined below. Pursuant to our partnership agreement, the Series D Preferred Units were cancelled; therefore, the Series D Preferred Units no longer represent a limited partnership interest. For the year ended December 31, 2023, we recorded a loss of $0.55 per common unit attributable to the redemptions. See Note 17 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for 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 2022 to 2021 results of operations can be found in Items 1., 2., and 7. “Business, Properties and Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2022 filed with the SEC on February 23, 2023.
The following table presents our consolidated financial results for the year ended December 31, 2023, compared to the year ended December 31, 2022:
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | Change | |||||||||||||||
| (Thousands of Dollars, Except Per Unit Data) | |||||||||||||||||
| Statement of Income Data: | |||||||||||||||||
| Revenues: | |||||||||||||||||
| Service revenues | $ | 1,155,567 | $ | 1,120,249 | $ | 35,318 | |||||||||||
| Product sales | 478,620 | 562,974 | (84,354) | ||||||||||||||
| Total revenues | 1,634,187 | 1,683,223 | (49,036) | ||||||||||||||
| Costs and expenses: | |||||||||||||||||
| Costs associated with service revenues | 622,671 | 616,867 | 5,804 | ||||||||||||||
| Costs associated with product sales | 407,793 | 486,947 | (79,154) | ||||||||||||||
| Other impairment loss | — | 46,122 | (46,122) | ||||||||||||||
| General and administrative expenses | 129,846 | 117,116 | 12,730 | ||||||||||||||
| Other depreciation and amortization expense | 4,728 | 7,358 | (2,630) | ||||||||||||||
| Total costs and expenses | 1,165,038 | 1,274,410 | (109,372) | ||||||||||||||
| Gain on sale of assets | 41,075 | — | 41,075 | ||||||||||||||
| Operating income | 510,224 | 408,813 | 101,411 | ||||||||||||||
| Interest expense, net | (241,364) | (209,009) | (32,355) | ||||||||||||||
| Other income, net | 10,215 | 26,182 | (15,967) | ||||||||||||||
| Income before income tax expense | 279,075 | 225,986 | 53,089 | ||||||||||||||
| Income tax expense | 5,412 | 3,239 | 2,173 | ||||||||||||||
| Net income | $ | 273,663 | $ | 222,747 | $ | 50,916 | |||||||||||
| Basic and diluted net income per common unit | $ | 0.72 | $ | 0.36 | $ | 0.36 | |||||||||||
Consolidated Overview
Net income increased $50.9 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to higher operating income of $101.4 million, partially offset by an increase in interest expense, net of $32.4 million and a decrease in other income, net of $16.0 million. Operating income increased primarily due to a gain of $41.1 million related to the Sale-Leaseback Transaction in the first quarter of 2023, a non-cash pre-tax impairment loss of $46.1 million in the first quarter of 2022 and higher operating income from our pipeline segment in 2023. These increases were partially offset by lower operating income from our storage segment, excluding the 2022 impairment loss, and higher general and administrative expenses in 2023.
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Total revenues decreased $49.0 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to lower product sales in our fuels marketing segment resulting from lower fuel prices. Service revenues increased in 2023 due to higher revenues from our pipeline segment, primarily due to higher average tariff rates, partially offset by lower revenues from our storage segment, resulting from current unfavorable market conditions affecting certain of our terminals.
Total costs and expenses decreased $109.4 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to lower fuel costs associated with product sales in our fuels marketing segment and a non-cash, pre-tax impairment loss of $46.1 million in the first quarter of 2022, partially offset by an increase in general and administrative expenses.
General and administrative expenses increased $12.7 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to an increase in rent expense of $6.5 million, mainly related to the Sale-Leaseback Transaction of our Corporate Headquarters in the first quarter of 2023 and higher compensation expenses in 2023.
Interest expense, net increased $32.4 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to higher interest rates on our variable rate debt and higher balances on our Revolving Credit Agreement, which was used to fund a portion of the 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, 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 2,915 miles and crude oil pipelines with an aggregate length of 2,070 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
•an 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 | |||||||||||||||||||||||||||
Description of Pipelines
Central West System. The Central West System covers a total of 4,985 miles, including refined product and crude oil pipelines. The refined product pipelines have an aggregate length of 2,915 miles (Central West Refined Products Pipelines) and transport gasoline, distillates (including diesel and jet fuel), renewable fuels, natural gas liquids and other products produced at the refineries to which they are connected, including Valero Energy Corporation’s (Valero Energy) McKee, Corpus Christi and Three Rivers refineries.
The crude oil pipelines have an aggregate length of 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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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. As of December 31, 2023, the system consists of 1,025 miles of pipelines and covers approximately 500,000 dedicated acres controlled by producers, with 369 receipt points. The Permian Crude System also includes three terminals in Texas, at Big Spring, Stanton and Colorado City, as well as several truck stations and other operational storage facilities, with aggregate storage capacity of 1.6 million barrels.
Central East System. The Central East System covers a total of 4,505 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 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 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. 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, 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 a feedstock 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 steady and somewhat insulated from volume fluctuations due to continued strong agricultural demand in the Midwest. However, global conflicts, such as the Russia-Ukraine conflict, can increase export demand, which could reduce the supply of anhydrous ammonia transported on our Ammonia Pipeline.
Customers
As discussed above, our customers include integrated oil companies, refining companies and others. The largest customer of our pipeline segment accounted for approximately 27% of the total segment revenues for the year ended December 31, 2023. No other single customer accounted for 10% or 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-haul destinations; however, trucking costs render that mode of transportation uncompetitive with pipeline options for long-haul destinations or for larger volumes.
Most of our refined product pipelines and certain of our crude oil pipelines within the Central West System are physically integrated with, and principally serve, refineries owned by Valero Energy. As a result, we do not believe that we will face significant competition for transportation services provided to the Valero Energy refineries we serve.
Certain of our crude oil pipelines serve areas and/or refineries 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.
Our East Pipeline and North Pipeline compete with an independent common carrier pipeline system owned by ONEOK, Inc. (ONEOK) that operates approximately 100 miles east of, and parallel to, the East Pipeline and in close proximity to the North Pipeline. Certain of the East Pipeline’s and the North Pipeline’s delivery terminals are in direct competition with ONEOK’s terminals. Competition with ONEOK is based primarily on transportation charges, quality of customer service and proximity to end users.
Competitors of 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 energy to power fuel-cell vehicles. While future uses for lower emission-producing “blue” and “green” ammonia are still developing, we are partnering with existing and potential customers to develop these projects, which could increase demand for and utilization of our Ammonia Pipeline.
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Results of Operations
The following table presents operating highlights for the pipeline segment:
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | Change | |||||||||||||||
| (Thousands of Dollars, Except Barrel Data) | |||||||||||||||||
| Pipeline Segment: | |||||||||||||||||
| Crude oil pipelines throughput (barrels/day) | 1,234,051 | 1,319,360 | (85,309) | ||||||||||||||
| Refined products and ammonia pipelines throughput (barrels/day) | 602,913 | 579,240 | 23,673 | ||||||||||||||
| Total throughput (barrels/day) | 1,836,964 | 1,898,600 | (61,636) | ||||||||||||||
| Throughput and other revenues | $ | 873,869 | $ | 828,191 | $ | 45,678 | |||||||||||
| Operating expenses | 214,751 | 210,719 | 4,032 | ||||||||||||||
| Depreciation and amortization expense | 175,930 | 178,802 | (2,872) | ||||||||||||||
| Segment operating income | $ | 483,188 | $ | 438,670 | $ | 44,518 | |||||||||||
Tariff indexations effective July 2022 and July 2023 increased the average tariff rates on most of our pipeline systems and resulted in higher revenues for the year ended December 31, 2023, compared to the year ended December 31, 2022.
Pipeline segment revenues increased $45.7 million, and throughputs decreased 61,636 barrels per day for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to:
•an increase in revenues of $31.1 million and an increase in throughputs of 43,563 barrels per day on our McKee System pipelines, primarily due to operational issues and a planned turnaround at a customer’s refinery in 2022, as well as higher demand on our pipeline serving the Denver, Colorado market in 2023; additionally, higher average tariff rates contributed to $9.7 million of the overall increase;
•an increase in revenues of $12.1 million, despite a decrease in throughputs of 3,601 barrels per day on our East and North pipelines combined; revenues increased primarily due to higher average tariff rates, while throughputs decreased primarily due to unfavorable market conditions and planned turnarounds at customers’ refineries in 2023;
•an increase in revenues of $7.2 million and an increase in throughputs of 1,550 barrels per day on our Valley Pipeline, primarily due to higher average tariff rates;
•an increase in revenues of $5.9 million and an increase in throughputs of 5,159 barrels per day on our Three Rivers System, partially due to higher demand on certain of our pipelines within this system and pipeline expansions that were placed in service in July 2022. Also, higher average tariff rates contributed to $4.0 million of the overall increase;
•an increase in revenues of $3.4 million, despite slightly lower throughputs of 1,028 barrels per day on our Ammonia Pipeline; revenues increased primarily due to higher average tariff rates;
•a decrease in revenues of $2.2 million and a decrease in throughputs of 27,367 barrels per day on our Permian Crude System, primarily due to decreased customer production supplying this system. Revenues also decreased $7.9 million due to lower commodity prices on PLA volumes and other products sold; these decreases were partially offset by higher average tariff rates in 2023;
•a decrease in revenues of $2.4 million and a decrease in throughputs of 10,781 barrels per day on our Ardmore System due to a turnaround at a customer’s refinery in the second quarter of 2023 and lower demand in 2023; and
•a decrease in revenues of $10.9 million and a decrease in throughputs of 68,374 barrels per day on our Corpus Christi Crude Pipeline System, primarily due to unfavorable market conditions and changes to a customer contract.
Operating expenses increased $4.0 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to an increase of $2.8 million in maintenance and regulatory expenses across various pipelines.
Depreciation and amortization expense decreased $2.9 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to fully amortized definite-lived intangible assets.
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STORAGE SEGMENT
Our storage segment is composed of our facilities that provide storage, handling and other services on a fee basis for refined products, crude oil, specialty chemicals, renewable fuels and other liquids. As of December 31, 2023, we owned and operated 29 terminal and storage facilities in the United States and one terminal in Nuevo Laredo, Mexico, with an aggregate storage capacity of 36.4 million barrels. The following table sets forth information about our terminal and storage facilities as of December 31, 2023:
| Facility | Tank Capacity | |||||||
| (Barrels) | ||||||||
| Colorado Springs, CO | 327,000 | |||||||
| Denver, CO | 110,000 | |||||||
| Albuquerque, NM | 250,000 | |||||||
| Rosario, NM | 167,000 | |||||||
| Catoosa, OK | 359,000 | |||||||
| Abernathy, TX | 161,000 | |||||||
| Amarillo, TX | 269,000 | |||||||
| Corpus Christi, TX | 410,000 | |||||||
| Corpus Christi, TX (North Beach) | 3,962,000 | |||||||
| Edinburg, TX | 345,000 | |||||||
El Paso, TX(a) | 415,000 | |||||||
| Harlingen, TX | 286,000 | |||||||
| Laredo, TX | 218,000 | |||||||
San Antonio, TX(b) | 379,000 | |||||||
| Southlake, TX | 569,000 | |||||||
| Nuevo Laredo, Mexico | 268,000 | |||||||
| Central West Terminals | 8,495,000 | |||||||
| St. James, LA | 9,906,000 | |||||||
| Houston, TX | 87,000 | |||||||
| Gulf Coast Terminals | 9,993,000 | |||||||
| Los Angeles, CA | 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 | |||||||
| West Coast Terminals | 7,017,000 | |||||||
| Benicia, CA | 3,698,000 | |||||||
| Corpus Christi, TX | 4,030,000 | |||||||
| Texas City, TX | 3,141,000 | |||||||
| Refinery Storage Tanks | 10,869,000 | |||||||
| Total | 36,374,000 | |||||||
(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. Although the Permian and Eagle Ford shale plays are partially insulated from negative economic conditions due to the low break-even point, our Corpus Christi exports have not returned to pre-pandemic levels due to lower global demand for refined products and crude oil and increased competition in crude oil export markets out of the U.S. Overall, refinery production rates,
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drilling activity and overall consumer demand in the U.S. rebounded in 2021, bringing demand for most of our terminal and storage facilities back to pre-pandemic levels. However, the detrimental impact of the pandemic, amplified by the Russia-Ukraine conflict, has continued to affect current global demand, resulting in a decline in crude oil exports from our Corpus Christi North Beach facility, and the current volatile and backwardated market has led to customers not renewing expiring contracts, primarily at our St. James terminal.
Demand for renewable diesel, renewable jet fuel, ethanol and other renewable fuels continues to grow in markets served by our West Coast terminals due to new regulations with aggressive carbon emissions reduction goals. As this demand growth is expected to continue, we have completed, and continue to develop, renewable fuel storage projects at our West Coast terminals to meet this demand.
Customers
We provide storage and terminalling services for crude oil, refined products and other products to many of the world’s largest producers of crude oil, integrated oil companies, chemical companies, oil traders and refiners. In addition, our blending capabilities in our storage assets have attracted customers who have leased capacity primarily for blending purposes. The largest customer of our storage segment accounted for approximately 39% of the total revenues of the segment for the year ended December 31, 2023. No other customer accounted for 10% or more of the total revenues of the storage segment.
Competition and Other Business Considerations
Many major energy and chemical companies own extensive terminal storage facilities. Although such terminals often have the same capabilities as terminals owned by independent operators, they generally do not provide terminalling services to third parties. In many instances, even major energy and chemical companies that have storage and terminalling facilities are also significant customers of independent terminal operators, especially terminals located in cost-effective locations near key transportation links, such as deep-water ports. Major energy and chemical companies also need independent terminal storage when their proprietary storage facilities are inadequate, due to size constraints, the nature of the stored material or specialized handling requirements.
Independent terminal owners generally compete on the basis of the location and versatility of terminals, service and price. A favorably located terminal will have access to various cost-effective transportation modes both to and from the terminal. Transportation modes typically include waterways, railroads, roadways and pipelines.
Terminal versatility is a function of the operator’s ability to offer complex handling requirements for diverse products. The services typically provided by the terminal include, among other things, the safe storage of the product at specified temperature, moisture and other conditions, as well as receipt at and delivery from the terminal, all of 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 Operations
Point Tupper Terminal Disposition. In the first quarter of 2022, we recognized a non-cash pre-tax impairment loss of $46.1 million related to our Point Tupper terminal facility, which was sold on April 29, 2022 (the Point Tupper Terminal Disposition). See Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of this disposition.
Point Tupper Terminal Disposition. In the first quarter of 2022, we recognized a non-cash pre-tax impairment loss of $46.1 million related to our Point Tupper terminal facility, which was sold on April 29, 2022 (the Point Tupper Terminal Disposition). See Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of this disposition.
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The following table presents operating highlights for the storage segment:
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | Change | |||||||||||||||
| (Thousands of Dollars, Except Barrel Data) | |||||||||||||||||
| Storage Segment: | |||||||||||||||||
| Throughput (barrels/day) | 448,331 | 480,129 | (31,798) | ||||||||||||||
| Throughput terminal revenues | $ | 104,495 | $ | 110,591 | $ | (6,096) | |||||||||||
| Storage terminal revenues | 215,104 | 223,958 | (8,854) | ||||||||||||||
| Total revenues | 319,599 | 334,549 | (14,950) | ||||||||||||||
| Operating expenses | 156,938 | 154,270 | 2,668 | ||||||||||||||
| Depreciation and amortization expense | 75,052 | 73,076 | 1,976 | ||||||||||||||
| Impairment loss | — | 46,122 | (46,122) | ||||||||||||||
| Segment operating income | $ | 87,609 | $ | 61,081 | $ | 26,528 | |||||||||||
Throughput terminal revenues decreased $6.1 million, and throughputs decreased 31,798 barrels per day for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to a decrease in revenues of $13.2 million and a decrease in throughputs of 51,361 barrels per day at our Corpus Christi North Beach terminal, due to unfavorable market conditions and changes to a customer contract. These decreases were partially offset by an increase in revenues of $7.1 million and an increase in throughputs of 19,563 barrels per day at our Central West Terminals, primarily due to higher demand.
Storage terminal revenues decreased $8.9 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to:
•a decrease in revenues of $29.7 million at our St. James terminal due to customers not renewing expiring contracts in the current backwardated market; and
•a decrease in revenues of $9.6 million due to the Point Tupper Terminal Disposition in April 2022.
These decreases were partially offset by the following:
•an increase in revenues of $26.4 million at our West Coast Terminals, primarily due to new contracts and rate escalations across various terminals, combined with higher throughput and handling fees, mainly at our Stockton terminal; and
•an increase in revenues of $4.3 million, primarily due to rate escalations at our Central West Terminals and at our refinery storage tanks.
Operating expenses increased $2.7 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to the following:
•an increase in maintenance and regulatory expenses of $3.1 million, across various terminals;
•an increase of $2.8 million in ad valorem taxes due to higher property valuations;
•increases in reimbursable and other expenses of $2.5 million that have corresponding increases in revenue, primarily at our West Coast Terminals, partially offset by lower reimbursable expenses at our St. James terminal; and
•an increase of $1.8 million at our Corpus Christi North Beach terminal due to changes in a customer contract.
These increases were partially offset by a decrease in operating expenses of $7.9 million due to the sale of our Point Tupper Terminal Operations during the second quarter of 2022.
Depreciation and amortization expense increased $2.0 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to expansion projects at our West Coast Terminals.
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FUELS MARKETING SEGMENT
Our fuels marketing segment sells petroleum products primarily through our bunkering operations in the Gulf Coast and certain of our blending operations associated with our Central East System. The results of operations for the fuels marketing segment depend largely on the margin between our costs and the sales prices of the products we market. Therefore, the results of operations for this segment are more sensitive to changes in commodity prices compared to the operations of the pipeline and storage segments. We enter into derivative contracts to attempt to mitigate the effects of commodity price fluctuations. The financial impacts of the derivative financial instruments associated with commodity price risk were not material for any periods presented. Fluctuations in global demand for crude oil, which was caused by many economic factors outside of our control, has caused volatility in commodity prices and volumes for our blending operations and bunker fuel sales in 2022 and 2023.
Competition and Customers
In the sale of bunker fuel, we compete with ports offering bunker fuels that are along the route of travel of the vessel. Customers for bunker fuel sales are primarily ship owners, marketers and traders. One of our customers, a marketer of petroleum products, was the largest customer of our fuels marketing segment and accounted for approximately 11% of the total segment revenues for the year ended December 31, 2023. No other customer accounted for a significant portion of the total revenues of the fuels marketing segment for the year ended December 31, 2023.
Results of Operations
The following table presents operating highlights for the fuels marketing segment:
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | Change | |||||||||||||||
| (Thousands of Dollars) | |||||||||||||||||
| Fuels Marketing Segment: | |||||||||||||||||
| Product sales | $ | 440,725 | $ | 520,486 | $ | (79,761) | |||||||||||
| Cost of goods | 405,992 | 484,477 | (78,485) | ||||||||||||||
| Gross margin | 34,733 | 36,009 | (1,276) | ||||||||||||||
| Operating expenses | 1,807 | 2,473 | (666) | ||||||||||||||
| Segment operating income | $ | 32,926 | $ | 33,536 | $ | (610) | |||||||||||
Product sales decreased $79.8 million, and cost of goods decreased $78.5 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to lower fuel prices for our bunkering operations. Gross margin decreased $1.3 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, as a decrease of $2.8 million in gross margin from our bunkering operations and a decrease of $2.8 million in gross margin from other product sales more than offset higher blending gross margins of $4.3 million, all primarily due to lower fuel prices.
Segment operating income decreased $0.6 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, due to the changes in gross margins described above, partially offset by a decrease in operating expenses of $0.7 million, primarily related to our bunkering operations.
LIQUIDITY AND CAPITAL RESOURCES
The following sections are included in Liquidity and Capital Resources:
•Overview
•Cash Flows
•Sources of Liquidity
•Material Cash Requirements
OVERVIEW
Our primary cash requirements include distributions to our limited partners, debt service, capital expenditures and operating expenses. Our partnership agreement requires that we distribute all Available Cash (as defined in our partnership agreement) to our common limited partners each quarter. Available Cash is generally defined as all cash receipts less cash disbursements, including distributions to our preferred unit holders, and cash reserves established by our general partner, in its sole discretion. We may maintain our distribution level with other sources of Available Cash, as provided in our partnership agreement, including borrowings under our Revolving Credit Agreement and proceeds from the sale of assets.
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In the first quarter of 2023, we completed the Sale-Leaseback Transaction for $103.0 million, and in the third quarter of 2023, we issued 14,950,000 common units for net proceeds of approximately $222.0 million. We used the proceeds from these transactions to repay outstanding borrowings under our Revolving Credit Agreement, which facilitated the redemption of 16,346,650 of the Series D Preferred Units, representing all outstanding Series D Preferred Units. Additionally, in the second quarter of 2023, we extended the maturity date on our Revolving Credit Agreement to January 27, 2027, and extended the scheduled termination date on our Receivables Financing Agreement to July 1, 2026. Similarly, in 2022, we had reduced our leverage to position ourselves to repurchase 6,900,000 of the Series D Preferred Units in November 2022, representing approximately one-third of the outstanding units at that time, using borrowings under our Revolving Credit Agreement.
As illustrated in the chart below, in 2023 and 2022, we funded all our expenses, distribution requirements and capital expenditures using cash from operating activities.
For the full-year 2024, we expect to fund all our expenses, distribution requirements and capital expenditures using internally generated cash flows. We have no long-term debt maturities until 2025.
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CASH FLOWS
A discussion of our cash flows and other changes in financial position for 2021 can be found in Items 1., 2. and 7. “Business, Properties and Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2022 filed with the SEC on February 23, 2023.
The following table summarizes our cash flows from operating, investing and financing activities (see also our Consolidated Statements of Cash Flows in Item 8. “Financial Statements and Supplementary Data”).
| Year Ended December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| (Thousands of Dollars) | |||||||||||
| Net cash provided by (used in): | |||||||||||
| Operating activities | $ | 514,269 | $ | 527,549 | |||||||
| Investing activities | (23,240) | (84,365) | |||||||||
| Financing activities | (502,430) | (434,953) | |||||||||
| Effect of foreign exchange rate changes on cash | 40 | 707 | |||||||||
| Net (decrease) increase in cash, cash equivalents and restricted cash | $ | (11,361) | $ | 8,938 | |||||||
Net cash provided by operating activities decreased $13.3 million for the year ended December 31, 2023, compared to the year ended December 31, 2022. The increase in net income of $50.9 million was more than offset by noncash adjustments to reconcile to net cash provided by operating activities. In addition, our working capital decreased by $10.6 million for the year ended December 31, 2023 and $0.7 million for the year ended December 31, 2022. Generally, working capital requirements are affected by our accounts receivable, accounts payable and accrued liability balances, which vary depending on the timing of payments.
Net cash used in investing activities decreased $61.1 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to proceeds of approximately $103.0 million from the Sale-Leaseback Transaction in the first quarter of 2023, compared to proceeds from asset sales of $59.3 million in 2022. Additionally, for the year ended December 31, 2023 compared to the year ended December 31, 2022, cash outflows related to capital expenditures decreased an aggregate $14.9 million. Investing activities also include insurance proceeds of $12.4 million for the year December 31, 2023, compared to insurance proceeds of $9.8 million for the December 31, 2022, both related to the 2019 Selby terminal fire.
Net cash used in financing activities increased $67.5 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily due to the redemption of the outstanding Series D Preferred Units for $518.7 million in 2023, compared to the repurchase of outstanding Series D Preferred Units for $222.4 million in 2022, partially offset by the issuance of common units in the third quarter of 2023 for approximately $222.0 million.
SOURCES OF LIQUIDITY
Revolving Credit Agreement
As of December 31, 2023, our Revolving Credit Agreement had $652.4 million available for borrowing and $343.0 million of borrowings outstanding. Letters of credit issued under our Revolving Credit Agreement totaled $4.6 million as of December 31, 2023 and limit the amount we can borrow under our Revolving Credit Agreement. Obligations under our Revolving Credit Agreement are guaranteed by NuStar Energy and NuPOP.
Our Revolving Credit Agreement is subject to maximum consolidated debt coverage ratio and minimum consolidated interest coverage ratio requirements, which may limit the amount we can borrow to an amount less than the total amount available for borrowing. For the rolling period of four quarters ending December 31, 2023, the Consolidated Debt Coverage Ratio (as defined in the Revolving Credit Agreement) may not exceed 5.00-to-1.00 and the Consolidated Interest Coverage Ratio (as defined in the Revolving Credit Agreement) must not be less than 1.75-to-1.00. Our Revolving Credit Agreement also contains customary restrictive covenants, such as limitations on indebtedness, liens, mergers, asset transfers and certain investing activities. As of December 31, 2023, our Consolidated Debt Coverage Ratio was 3.85x and our Consolidated Interest Coverage Ratio was 2.18x.
On June 30, 2023, we amended our Revolving Credit Agreement, primarily to extend the maturity date from April 27, 2025 to January 27, 2027. The amendment also includes a requirement that we must demonstrate and certify, prior to using any borrowings under our Revolving Credit Agreement to redeem certain unsecured indebtedness or prior to their redemption/repurchase, the Series D Preferred Units, that the sum of our Revolving Credit Agreement availability and unrestricted cash
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balance is no less than $150.0 million on a pro forma basis both before and immediately after giving effect to the borrowing and the redemption. On January 28, 2022, we amended and restated our Revolving Credit Agreement to, among other items:
(i) increase the maximum amount of letters of credit capable of being issued from $400.0 million to $500.0 million; (ii) replace London Interbank Offering Rate, or LIBOR, benchmark provisions with customary secured overnight financing rate, or SOFR, benchmark provisions; (iii) remove the 0.50x increase permitted in our Consolidated Debt Coverage Ratio for certain rolling periods in which an acquisition for aggregate net consideration of at least $50.0 million occurs; and (iv) add baskets and exceptions to certain negative covenants.
Receivables Financing Agreement
NuStar Energy and NuStar Finance LLC (NuStar Finance), a special purpose entity and wholly owned subsidiary of NuStar Energy, are parties to the Receivables Financing Agreement with a third-party lender and agreements with certain of NuStar Energy’s wholly owned subsidiaries (together with the Receivables Financing Agreement, the Securitization Program). The amount available for borrowing under the Receivables Financing Agreement is based on the availability of eligible receivables and other customary factors and conditions. The Securitization Program contains various customary affirmative and negative covenants and default, indemnification and termination provisions, and the Receivables Financing Agreement provides for acceleration of amounts owed upon the occurrence of certain specified events. On June 29, 2023, we amended the Receivables Financing Agreement to extend the scheduled termination date from January 31, 2025 to July 1, 2026. On January 28, 2022, the Receivables Financing Agreement was amended to, among other items: (i) reduce the floor rate in the calculation of our borrowing rates; and (ii) replace provisions related to the LIBOR rate of interest with references to SOFR rates of interest.
See Note 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of our debt agreements.
Issuance of Common Units
We used the net proceeds of approximately $222.0 million from the issuance of common units on August 11, 2023 to repay outstanding borrowings under our Revolving Credit Agreement. See Note 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.
Asset Sales
We used the proceeds of approximately $103.0 million from the sale of our Corporate Headquarters on March 21, 2023 and approximately $60.0 million from the Point Tupper Terminal Disposition on April 29, 2022 to repay outstanding borrowings under our Revolving Credit Agreement. See Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of these asset sales.
MATERIAL CASH REQUIREMENTS
Capital Expenditures
Our operations require significant investments to maintain, upgrade or enhance the operating capacity of our existing assets. Our capital expenditures consist of:
•strategic capital expenditures, such as those to expand or upgrade the operating capacity, increase efficiency or increase the earnings potential of existing assets, whether through construction or acquisition, as well as certain capital expenditures related to support functions; and
•reliability capital expenditures, such as those required to maintain the current operating capacity of existing assets or extend their useful lives, as well as those required to maintain equipment reliability and safety.
The following table summarizes our capital expenditures:
| Strategic Capital 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 | |||||||||||
Strategic capital expenditures for the years ended December 31, 2023 and December 31, 2022 primarily consisted of expansion projects on our Permian Crude System and Central West Refined Products Pipelines, and biofuel and other projects at our West Coast Terminals, as well as connection projects on our Ammonia Pipeline in 2023. Reliability capital expenditures primarily related to maintenance upgrade projects at our terminals and on our Ammonia Pipeline.
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We expect our strategic capital expenditures for the year ended December 31, 2024 to be concentrated on expansion projects to accommodate production growth in the Permian Basin and projects to expand our renewable fuels network on the West Coast. We continue to evaluate our capital budget and internal growth projects can be accelerated or scaled back depending on market conditions or customer demand.
Series D Preferred Units Redemption and Repurchase
We redeemed or repurchased all the Series D Preferred Units, as shown below:
| 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 | ||||||||||||||||||||
See Note 17 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.
Distributions
Preferred Units. Distributions on our outstanding preferred units are payable out of any legally available funds, accrue and are cumulative from the original issuance dates, and are payable on the 15th day (or next business day) of each of March, June, September and December of each year to holders of record on the first business day of each payment month. See Notes 17 and 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.
Series D Preferred Units. Prior to their redemption and/or repurchase, the distribution rates on the outstanding Series D Preferred Units were as follows: (i) 9.75% per annum ($0.619 per unit per distribution period) for the first two years (beginning with the September 17, 2018 distribution); (ii) 10.75% per annum ($0.682 per unit per distribution period) for years three through five; and (iii) the greater of 13.75% per annum ($0.872 per unit per distribution period) or the distribution per common unit thereafter. The number of Series D Preferred Units outstanding as of December 31, 2022 was 16,346,650, and due to the redemptions and repurchase discussed above, the Series D Preferred Units were cancelled and no longer represent a limited partner interest.
The distribution rate on the Series D Preferred Units increased on June 15, 2023, to the greater of 13.75% per annum ($0.872 per unit per distribution period) or the distribution per common unit. Distributions accrued for redeemed Series D Preferred Units from the notification dates to the redemption dates are reported in “Interest expense, net” on the consolidated statements of income and are excluded from total distributions below for the applicable periods. Distribution information on the Series D Preferred Units was as follows:
| Distribution 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 | ||||||||||
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Series A, B and C Preferred Units. Information on our Series A, B and C Preferred Units is shown below:
| 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% | |||||||||||||||||
(a)Beginning with the distribution period starting on September 15, 2023, LIBOR was replaced with the corresponding CME Term SOFR plus the applicable tenor spread adjustment of 0.26161%.
Distribution information on our Series A, B and C Preferred Units is as follows (thousands of dollars, except per unit data):
| Series A Preferred 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 | ||||||||||||||||||||||||||
On January 25, 2024, our Board of Directors declared quarterly distributions with respect to the Series A, B and C Preferred Units to be paid on March 15, 2024 to holders of record as of March 1, 2024.
Common Units. Under our partnership agreement, distribution payments are required to be made to our common limited partners within 45 days after the end of each quarter as of a record date that is set after the end of each quarter. On January 25, 2024, our Board of Directors declared distributions with respect to our common units for the quarter ended December 31, 2023. The following table summarizes information about cash distributions to our common limited partners applicable to the period in which the distributions were earned:
| Quarter 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 | ||||||||||||||||||||||
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Debt Obligations
The following table summarizes our debt obligations:
| 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 | ||||||||||||||
We believe that, as of December 31, 2023, we are in compliance with the financial covenants applicable to our debt obligations. A default under certain of our debt agreements would be considered an event of default under other of our debt obligations.
Receivables Financing Agreement and Revolving Credit Agreement. Borrowings under the Receivables Financing Agreement bear interest, at NuStar Finance’s option, at a base rate or a SOFR rate, each as defined in the Receivables Financing Agreement. Borrowings under our Revolving Credit Agreement bear interest, at our option, at an alternate base rate or a SOFR rate, each as defined in the Revolving Credit Agreement. The interest rate on our Revolving Credit Agreement and certain fees under the Receivables Financing Agreement, are the only debt arrangements that are subject to adjustment if our debt rating is downgraded or upgraded by certain credit rating agencies. The following table reflects the current ratings and outlook that have been assigned to our debt:
| Fitch Ratings | Moody’s Investor Service Inc. | S&P Global Ratings | |||||||||||||||
| Ratings | BB | Ba3 | BB- | ||||||||||||||
| Outlook | Stable | Stable | Positive | ||||||||||||||
Gulf Opportunity Zone Revenue Bonds. As reflected in the table below, the holders of the Series 2008, Series 2010B and Series 2011 GoZone Bonds are required to tender their bonds at the applicable mandatory purchase date in exchange for 100% of the principal plus accrued and unpaid interest, after which these bonds are expected to be remarketed with a new interest rate established. Each of the Series 2010 and Series 2010A GoZone Bonds is subject to redemption on or after June 1, 2030 by the Parish of St. James, at our option, in whole or in part, at a redemption price of 100% of the principal amount to be redeemed plus accrued interest. The following table summarizes the GoZone Bonds outstanding as of December 31, 2023:
| Series | Date Issued | Amount Outstanding | Interest Rate | Mandatory Purchase Date | Optional Redemption Date | Maturity Date | ||||||||||||||||||||||||||||||||
| (Thousands of Dollars) | ||||||||||||||||||||||||||||||||||||||
| Series 2008 | June 26, 2008 | $ | 55,440 | 6.10 | % | June 1, 2030 | n/a | June 1, 2038 | ||||||||||||||||||||||||||||||
| Series 2010 | July 15, 2010 | 100,000 | 6.35 | % | n/a | June 1, 2030 | July 1, 2040 | |||||||||||||||||||||||||||||||
| Series 2010A | October 7, 2010 | 43,300 | 6.35 | % | n/a | June 1, 2030 | October 1, 2040 | |||||||||||||||||||||||||||||||
| Series 2010B | December 29, 2010 | 48,400 | 6.10 | % | June 1, 2030 | n/a | December 1, 2040 | |||||||||||||||||||||||||||||||
| Series 2011 | August 9, 2011 | 75,000 | 5.85 | % | June 1, 2025 | n/a | August 1, 2041 | |||||||||||||||||||||||||||||||
| Total | $ | 322,140 | ||||||||||||||||||||||||||||||||||||
NuStar Logistics Subordinated Notes. NuStar Logistics’ $402.5 million of fixed-to-floating rate subordinated notes (the Subordinated Notes). Effective with the quarterly interest periods starting after June 30, 2023, the interest rate on the Subordinated Notes is equal to the sum of the three-month CME term SOFR plus the applicable tenor spread adjustment of 0.26161% for the related quarterly interest period plus 6.734%, payable quarterly, unless payment is deferred in accordance with the terms of the notes. NuStar Logistics may elect to defer interest payments on the Subordinated Notes on one or more occasions for up to five consecutive years. Deferred interest will accumulate additional interest at a rate equal to the interest rate then applicable to the Subordinated Notes until paid. If NuStar Logistics elects to defer interest payments, NuStar Energy
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cannot declare or make cash distributions with respect to, or redeem, purchase or make a liquidation payment with respect to, its equity securities during the period that interest payments are deferred.
Guarantor Summarized Financial Information. NuStar Energy has no operations, and its assets consist primarily of its 100% ownership interest in its indirectly owned subsidiaries, NuStar Logistics and NuPOP. The senior and subordinated notes issued by NuStar Logistics are fully and unconditionally guaranteed by NuStar Energy and NuPOP. Each guarantee of the senior notes by NuStar Energy and NuPOP (i) ranks equally in right of payment with all other existing and future unsecured senior indebtedness of that guarantor, (ii) is structurally subordinated to all existing and any future indebtedness and obligations of any subsidiaries of that guarantor that do not guarantee the notes and (iii) ranks senior to its guarantee of our subordinated indebtedness. Each guarantee of the subordinated notes by NuStar Energy and NuPOP ranks equal in right of payment with all other existing and future subordinated indebtedness of that guarantor and is subordinated in right of payment and upon liquidation to the prior payment in full of all other existing and future senior indebtedness of that guarantor. NuPOP will be released from its guarantee when it no longer guarantees any obligations of NuStar Energy or any of its subsidiaries, including NuStar Logistics, under any bank credit facility or public debt instrument. The rights of holders of our senior and subordinated notes may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. See Note 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of our debt agreements.
The following tables present summarized combined balance sheet and income statement information for NuStar Energy, NuStar Logistics and NuPOP (collectively, the Guarantor Issuer Group). Intercompany items among the Guarantor Issuer Group have been eliminated in the summarized combined financial information below, as well as intercompany balances and activity for the Guarantor Issuer Group with non-guarantor subsidiaries, including the Guarantor Issuer Group’s investment balances in non-guarantor subsidiaries.
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
As described below under “Environmental, Health, Safety and Security Regulation,” our operations in the U.S. and Mexico are subject to extensive international, federal, state and local environmental laws and regulations, including those relating to the discharge of materials into the environment, waste management, remediation, the characteristics and composition of fuels, climate change and greenhouse gases. Our operations are also subject to extensive health, safety and security laws and regulations, including those relating to worker and pipeline safety, pipeline and storage tank integrity and operations security. Because more stringent environmental and safety laws and regulations are continuously being enacted or proposed, the level of expenditures required for environmental, health and safety matters is expected to increase in the future.
The balance of and changes in our accruals for environmental matters as of and for the years ended December 31, 2023 and 2022 are included in Note 13 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.” We believe that we have adequately accrued for our environmental exposures.
HUMAN CAPITAL
We strive to make NuStar a safe, positive, inclusive and rewarding workplace, with competitive compensation, benefits and health and wellness programs and opportunities for our employees to grow and develop in their careers.
Our Employees
As of December 31, 2023, we had 1,184 employees, of which 1,173 are based in the United States and 11 are based in Mexico. Only 1.1 percent of our employees are represented under collective bargaining agreements. In the United States, 487 of our employees work at our headquarters in San Antonio, Texas, with the remaining 686 employees working at other locations.
We believe that having a workforce composed of diverse employees with wide-ranging backgrounds, experiences and ideas makes our company stronger. As of December 31, 2023:
•19.1% of all of our employees and 29.0% of our employees at senior manager level and above are female; and
•34.8% of our U.S. employees and 24.5% of our U.S. employees at senior manager level and above are minorities (as defined by the U.S. Equal Opportunity Employment Commission).
Employee Benefits and NuStar’s Culture
We provide opportunities for our employees to develop and enhance their skills through defined career paths, professional training, educational reimbursement and leadership and development programs, as well as regular training regarding safety, operations, ethics (including our Code of Business Conduct and Ethics), human resources topics and cybersecurity. In addition, we support our employees by providing competitive compensation and benefits.
We benchmark our compensation programs through market surveys to help offer competitive packages to attract and retain high-performing employees. Our compensation department also evaluates company-wide racial and gender equity by job-profile each time an employee is hired or recommended for a promotion. This helps to ensure that compensation levels are equitable for all employees regardless of race or gender.
Our benefits and health and wellness programs include life and health insurance (medical, dental and vision), prescription drug benefits, flexible spending accounts, paid sick leave, vacation, short- and long-term disability, mental and behavioral health resources, retirement benefits (including 401(k) and pension), educational reimbursement, a disaster relief fund that provides cash grants (that do not have to be repaid) to employees undergoing difficult circumstances, an employee assistance program and employee recognition programs. We also are committed to supporting the communities in which we operate, and we organize opportunities for our employees to participate in and enrich our communities through a variety of initiatives, such as fundraising activities, community clean-up projects and educational programs.
Our culture is driven by our nine guiding principles: safety; integrity; commitment; make a difference; teamwork; respect; communication; excellence; and pride. We believe that these principles are the building blocks for our success and have helped us to recruit and retain our employees and make NuStar a great place to work. We have been recognized on FORTUNE’S “100 Best Companies to Work For” list 13 times, FORTUNE’S “Best Workplaces for Millennials” list five times, the “Best Places For Working Parents” list three times, and Latino Leader Magazine’s “Best Companies for Latinos to Work” list three times. We also were recognized as a top employer by regional and local publications, including being recognized as a top employer in Texas by FORTUNE. In addition, we were recently recognized on Newsweek’s “America’s Most Trustworthy Companies” and “World’s Most Trustworthy Companies” lists. Many of these awards are based on confidential surveys of our employees. In addition, we monitor our ability to retain our employees through our voluntary turnover rate (the percentage of our total employees who voluntarily leave our company, other than through retirement). As of December 31, 2023, our voluntary
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turnover rate over the last five years has averaged 3.8%, and 231 of our employees have been employed by NuStar or predecessor entities for at least 20 years.
Safety
Safety is our first priority. In managing our business, we focus on the safety of our employees and contractors, as well as the communities in which we operate. We have implemented safety programs and management practices to promote a culture of safety, including required training for field and office employees and contractors, as well as specific qualifications and certifications for field employees and contractors. To further emphasize the importance of safety at NuStar, our Board of Directors receives a comprehensive annual report and monthly updates regarding our health, safety and environmental performance. The Compensation Committee of our Board of Directors also evaluates our overall environmental, social and governance (ESG) performance and our health, safety and environmental performance together annually as one of the metrics used to determine the annual incentive bonus for all of our employees, including our executive officers, which we believe reinforces the importance of maintaining safe, responsible operations and focusing on ESG excellence.
We are proud of NuStar’s safety performance. Our 2023 total recordable incident rate (TRIR) of 0.55 was better than the 3.60 average most recently reported by the U.S. Bureau of Labor Statistics (BLS) for the bulk terminals industry and in line with the 0.50 average most recently reported by BLS for the pipeline transportation industry. Our 2023 days away, restricted or transferred rate (DART) of 0.39 was better than the 2.80 average most recently reported by BLS for the bulk terminals industry and in line with the 0.30 average most recently reported by BLS for the pipeline transportation industry. NuStar also participates in the Occupational Safety and Health Administration’s (OSHA) Voluntary Protection Program (VPP), which promotes effective worksite health and safety. Achieving VPP Star status requires rigorous OSHA review and audit, and requires recertification every three to five years. As of December 31, 2023, approximately 92% of our eligible U.S. terminals have attained VPP Star status. NuStar also has received the International Liquids Terminals Association’s Safety Excellence Award 13 times.
Sustainability Report
We publish a Sustainability Report, which covers topics similar to those described above, including our guiding principles; operations and economic impact; environmental and safety programs; sustainability; renewable fuels-related services; policies and statistics (including greenhouse gas emissions disclosures); employee development and training; diversity and inclusion; community involvement and development; recent awards; risk management; cybersecurity; and governance. Our Sustainability Report can be viewed at https://sustainability.nustarenergy.com. Our Sustainability Report and the information contained on our website are not part of this Annual Report on Form 10-K, are not “soliciting materials,” are not deemed filed with the SEC and are not to be incorporated by reference into any of NuStar Energy’s filings under the Securities Act of 1933 or the Securities Act of 1934, as amended, respectively.
PROPERTIES
Our principal properties are described above under the caption “Segments and Results of Operations” above, and that information is incorporated herein by reference. We believe that we have satisfactory title to all of our properties. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, liens for current taxes and other burdens and easements, and restrictions or other encumbrances, including those related to environmental liabilities associated with historical operations, to which the underlying properties were subject at the time of acquisition by us or our predecessors, we believe that none of these burdens will materially detract from the value of these properties or from our interest in these properties or will materially interfere with their use in the operation of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this report. We perform scheduled maintenance on all of our pipelines, terminals, crude oil tanks and related equipment and make repairs and replacements when necessary or appropriate. We believe that our pipelines, terminals, crude oil tanks and related equipment have been constructed and are maintained in all material respects in accordance with applicable federal, state and local laws and the regulations and standards prescribed by the American Petroleum Institute, the DOT and accepted industry practice.
RATE REGULATION
Several of our crude oil and refined products pipelines are interstate common carrier pipelines, which are subject to regulation by the FERC under the Interstate Commerce Act (ICA) and the Energy Policy Act of 1992 (the EP Act). The ICA and its implementing regulations give the FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate liquids pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates a common carrier pipeline charges for providing transportation services on its interstate common carrier liquids pipelines, as well as the rules and
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regulations governing these services, to be maintained on file with the FERC and posted publicly. The EP Act deemed certain rates in effect prior to its passage to be just and reasonable and limited the circumstances under which a complaint can be made against such “grandfathered” rates. The EP Act and its implementing regulations also allow interstate common carrier liquids pipelines to annually index their rates up to a prescribed ceiling level and generally require that such pipelines index their rates down to the prescribed ceiling level if the index is negative. In addition, the FERC retains cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach.
Our ammonia pipeline is subject to regulation by the STB pursuant to the ICA applicable to such pipelines (which differs from the ICA applicable to interstate liquids pipelines). Under that regulation, the ammonia pipeline’s rates, classifications, rules and practices related to the interstate transportation of anhydrous ammonia must be reasonable and, in providing interstate transportation, the ammonia pipeline may not subject a person, place, port or type of traffic to unreasonable discrimination. Similar to the crude and refined products pipelines, the rates for transportation services on the ammonia pipeline are required to be in a tariff which is posted publicly on our website, however, that tariff is not required to be on file with the STB. The STB does not prescribe an indexing approach similar to the EP Act but rates under the STB must be reasonable and the pipeline may not subject a person, place, port or type of traffic to unreasonable discrimination.
In addition to federal regulatory body oversight, various states, including Colorado, Kansas, Louisiana, North Dakota and Texas, maintain commissions focused on the rates and practices of common carrier pipelines offering services within their borders. Although the applicable state statutes and regulations vary, they generally require that intrastate pipelines publish tariffs setting forth all rates, rules and regulations applying to intrastate service, and generally require that pipeline rates and practices be just, reasonable and nondiscriminatory.
Shippers may challenge tariff rates, rules and regulations on our pipelines. In most instances, state commissions have not initiated investigations of the rates or practices of pipelines in the absence of shipper complaints. There are no pending challenges or complaints regarding our tariffs or tariff rates.
ENVIRONMENTAL, HEALTH, SAFETY AND SECURITY REGULATION
Our operations are subject to extensive international, federal, state and local environmental laws and regulations, in the U.S. and in Mexico, including those relating to the discharge of materials into the environment, waste management, remediation, the characteristics and composition of fuels, climate change and greenhouse gases. In 2023, our capital expenditures attributable to compliance with environmental regulations were $5.5 million, and we currently project environmental regulatory compliance spending of approximately $12.5 million in 2024.
Our operations are also subject to extensive health, safety and security laws and regulations, including those relating to worker and pipeline safety, pipeline and storage tank integrity and operations security. The principal environmental, health, safety and security risks associated with our operations relate to unauthorized emissions into the air, releases into soil, surface water or groundwater, personal injury and property damage. We have adopted policies, practices, systems and procedures designed to comply with the laws and regulations, and to help minimize and mitigate these risks, limit the liability that could result from such events, prevent material environmental or other damage, ensure the safety of our employees and the public and secure our pipelines, terminals and operations. Compliance with environmental, health, safety and security laws, regulations and related permits increases our capital expenditures and operating expenses, and violation of these laws, regulations or permits could result in significant civil and criminal liabilities, injunctions or other penalties. Future governmental actions could result in more restrictive laws and regulations, which could increase required capital expenditures and operating expenses. At this time, we are unable to estimate either the impact, if any, of potential future regulation and/or legislation on our financial condition or results of operations, or the amount and timing of such possible future expenditures or expenses. The risk of additional compliance expenditures, expenses and liabilities are inherent to government-regulated industries, including midstream energy. As a result, there can be no assurances that significant expenditures, expenses and liabilities will not be incurred in the future. However, while compliance may affect our capital expenditures and operating expenses, we believe that the cost of such compliance will not have a material impact on our competitive position, financial condition or results of operations. Further, we do not believe that our cost of compliance is proportionately greater than the cost to other companies operating in our industry.
Discussed below are the primary U.S. environmental, health, safety and security laws applicable to our operations. Compliance with or violations of any of these laws and related regulations could result in significant expenditures, expenses and liabilities.
Occupational, Safety and Health
We are subject to the Occupational Safety and Health Act, as amended, and analogous or more stringent international, state and local laws and regulations for the protection of worker safety and health. In addition, we have operations subject to the
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Occupational Safety and Health Administration’s Process Safety Management regulations. These regulations apply to processes that involve certain chemicals at or above specified thresholds.
Fuel Standards and Renewable Energy
International, federal, state and local laws and regulations regulate the fuels we transport and store for our customers. Changes in these laws or regulations could affect our earnings, including by reducing our throughput volumes, or require capital expenditures and expenses to segregate and separately store fuels. In addition, several federal and state programs require, subsidize or encourage the purchase and use of competing fuels or energy, renewable energy, electric battery-powered motor vehicle engines and renewable fuels and blending additives, like ethanol, biodiesel and renewable diesel. These programs may over time offset projected increases or reduce the demand for refined products, particularly gasoline, in certain markets. However, the increased production and use of renewable fuels may also create opportunities for pipeline transportation and fuel blending. Other legislative changes in the future may similarly alter the expected demand and supply projections for refined products in ways that cannot be predicted.
Hazardous Substances and Hazardous Waste
The Federal Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA or “Superfund,” and analogous or more stringent international, state and local laws and regulations, impose restrictions and liability related to the release, threatened release, disposal and remediation of hazardous substances. This liability can be joint and several strict liability, without regard to fault or the legality of the original release or disposal. Current operators of a facility, past owners or operators of a facility and parties who arranged for the disposal of a hazardous substance can be held liable under these laws and regulations.
We currently own, lease, and operate on, and have in the past owned, leased and operated on, properties and at facilities that handled, transported and stored hazardous substances. Despite our compliance with applicable requirements and industry standards, hazardous substances may have been released on or under our facilities and properties, or on or under locations where these substances were taken for disposal. We are currently remediating subsurface contamination at several facilities, and, based on currently available information, we believe the costs related to these remedial activities should not materially affect our financial condition or results of operations. However, the aggregate total cost of remediation projects can be difficult to estimate, and there are no assurances that the cost of future remedial activities will not become material. Further, applicable laws or regulation, including those dictating the degree of remediation required, may be revised to be more restrictive in the future. As a result, we are unable to estimate the effect of future regulation on our financial condition or results of operations or the amount and timing of future expenditures required to comply with such possible regulatory changes.
The Federal Resource Conservation and Recovery Act, as amended, and analogous or more stringent international, state and local laws and regulations impose restrictions and strict controls regarding the handling and disposal of wastes, including hazardous wastes. We generate hazardous wastes and it is possible that additional wastes, which could include wastes currently generated during operations, will be designated as hazardous wastes in the future. Hazardous wastes are subject to more rigorous requirements than are non-hazardous wastes.
Air
The Federal Clean Air Act, as amended, and various applicable international, state and local laws and regulations impose restrictions and strict controls regarding emission into the air, including greenhouse gas emissions. These laws and regulations generally require permits issued by applicable federal, state or local authorities for emissions, and impose monitoring and reporting requirements. Such laws and regulations can also require pre-approval for the construction or modification of certain operations or facilities expected to produce or increase air emissions.
Water
The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, the federal Spill Prevention, Control, and Countermeasure and Facility Response Plan Rules and analogous or more stringent international, state and local laws and regulations impose restrictions and strict controls regarding the discharge of pollutants into state waters or waters of the United States. The discharge of pollutants into waters is generally prohibited, except in accordance with a permit issued by applicable federal or state authorities. The Oil Pollution Act further regulates the discharge of oil, and the response to and liability for oil spills, and the Rivers and Harbors Act regulates pipelines crossing navigable waters.
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Pipeline and Other Asset Integrity, Safety and Security
Our pipeline, storage tank and other operations are subject to extensive international, federal, state and local laws and regulations governing integrity, safety and security, including those in Title 49 of the U.S. Code and its implementing regulations. These laws and regulations include the Pipeline and Hazardous Materials Safety Administration’s requirements for safe pipeline design, construction, operation, maintenance, inspection, testing and corrosion control, control rooms and qualification programs for operating personnel. In addition, we have marine terminal operations subject to Coast Guard safety, integrity and security regulations and standards. We also have operations subject to the Department of Homeland Security Chemical Facility Anti-Terrorism Standards and security guidelines and directives issued by the Transportation Security Administration.
We take proactive steps to protect our company, systems and data from cyberattacks. See Item 1C. “Cybersecurity” for our cybersecurity considerations.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in accordance with U.S. generally accepted accounting principles (GAAP) requires management to select accounting policies and to make estimates and assumptions related thereto that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The following summary provides further information on our accounting policies that involve critical accounting estimates due to judgments made by management and the sensitivity of these estimates to deviations of actual results from management’s assumptions. The critical accounting estimates should be read in conjunction with Note 2 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data,” which summarizes our significant accounting policies.
Impairment of Long-Lived Assets
We test long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. We evaluate recoverability using undiscounted estimated net cash flows generated by the related asset or asset group. If the results of that evaluation indicate that the undiscounted cash flows are less than the carrying amount of the asset (i.e., the asset is not recoverable), we perform an impairment analysis. If our intent is to hold the asset for continued use, we determine the amount of impairment as the amount by which the net carrying value exceeds its fair value. If our intent is to sell the asset, and the criteria required to classify an asset as held for sale are met, we determine the amount of impairment as the amount by which the net carrying amount exceeds its fair value less costs to sell.
In determining the existence of an impairment of the carrying value of an asset, we make a number of subjective assumptions as to:
•whether there is an event or circumstance that may indicate that the carrying amount of an asset may not be recoverable;
•the grouping of assets;
•the intention of holding, abandoning or selling an asset;
•the forecast of undiscounted expected future cash flows with respect to an asset or asset group; and
•if an impairment exists, the fair value of the asset or asset group.
Our estimates of undiscounted future cash flows include: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) estimates of useful lives of the assets. The identification of impairment indicators and the estimates of future undiscounted cash flows are highly subjective and are based on numerous assumptions about future operations and market conditions, which we believe to be reasonable but are inherently uncertain. The uncertainties underlying our assumptions and estimates could differ significantly from actual results and could cause a different conclusion about the recoverability of our assets. If we determined one or more assets was impaired, the amount of impairment could be material to our results of operations.
Impairment of Goodwill
We perform an assessment of goodwill annually or more frequently if events or changes in circumstances warrant. We have the option to first perform a qualitative annual assessment to determine whether it is necessary to perform a quantitative goodwill impairment test. A qualitative assessment includes, among other things, industry and market considerations, overall financial performance, other entity-specific events and events affecting individual reporting units. If, after assessing the totality of events or circumstances for each reporting unit, we determine that it is more likely than not that the carrying value exceeds its fair value, then we would perform a quantitative impairment test for that reporting unit.
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We recognize an impairment of goodwill if the carrying value of a reporting unit that contains goodwill exceeds its estimated fair value. In order to estimate the fair value of the reporting unit, including goodwill, management must make certain estimates and assumptions that affect the total fair value of the reporting unit including, among other things, an assessment of market conditions, projected cash flows, discount rates and growth rates. Management’s estimates of projected cash flows related to the reporting unit include, but are not limited to, future earnings of the reporting unit, assumptions about the use or disposition of assets included in the reporting unit, estimated remaining lives of those assets, and future expenditures necessary to maintain the assets’ existing service potential.
We calculate the estimated fair value of each of our reporting units using a weighted average of values calculated using an income approach and a market approach. The income approach involves estimating the fair value of each reporting unit by discounting its estimated future cash flows using a discount rate, consistent with a market participant’s assumption. The market approach bases the fair value measurement on information obtained from observed stock prices of public companies and recent merger and acquisition transaction data for comparable entities. Our fair value estimates are sensitive to typical valuation assumptions, particularly our estimates for the weighted-average cost of capital used for the income approach and the guideline public company and guideline transaction multiples used for the market approach.
NEW ACCOUNTING PRONOUNCEMENTS
See Note 3 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of new accounting pronouncements.
AVAILABLE INFORMATION
Our internet website address is www.nustarenergy.com. Information contained on our website is not part of this report. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and any amendments thereto, filed with (or furnished to) the SEC are available on our website, free of charge, as soon as reasonably practicable after we file or furnish such material (select the “Investors” link, then the “SEC Filings” link). We also post our corporate governance guidelines, code of business conduct and ethics, code of ethics for senior financial officers and the charters of our board’s committees on our website free of charge (select the “Investors” link, then the “Corporate Governance” link).
Our governance documents are available in print to any unitholder that makes a written request to Corporate Secretary, NuStar Energy L.P., 19003 IH-10 West, San Antonio, Texas 78257 or corporatesecretary@nustarenergy.com.
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ITEM 1A. RISK FACTORS
RISKS RELATED TO SUNOCO’S PROPOSED ACQUISITION OF NUSTAR
The Merger is subject to a number of conditions to the obligations of both NuStar and Sunoco to complete the Merger, including approval by NuStar’s common unitholders and regulatory clearance, which may impose unacceptable conditions or could delay completion of the Merger or result in termination of the Merger Agreement.
On January 22, 2024, NuStar entered into a definitive agreement (the Merger Agreement), whereby Sunoco will acquire NuStar in an all-equity transaction (the Merger). The respective obligations of each of NuStar and Sunoco to consummate the Merger are subject to the satisfaction at or prior to the closing of numerous conditions, including, among other things, approval by NuStar’s common unitholders, the absence of any law or order prohibiting the consummation of the Merger, and the expiration or termination of the waiting period (and any extension of such period) under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. Many of the conditions to the completion of the Merger are not within either NuStar’s or Sunoco’s control, and NuStar cannot predict when, or if, these conditions will be satisfied. Furthermore, the requirement for obtaining the required regulatory clearances could delay the completion of the Merger for a significant period of time or prevent it from occurring. Regulators may seek to enjoin the completion of the Merger, seek divestiture of substantial assets of the parties, or require the parties to license, or hold separate, assets or terminate existing relationships and contractual rights.
Failure to complete the Merger could negatively impact the price of our units and have a material adverse effect on our results of operations, cash flows and financial position.
If the Merger is not completed for any reason, including as a result of failure to obtain all requisite regulatory and unitholder approvals, our ongoing business may be materially and adversely affected and, without realizing any of the benefits of having completed the Merger, we would be subject to a number of risks, including the following:
•we may experience negative reactions from the financial markets, including negative unit price impacts;
•we may experience negative reactions from commercial and business partners; and
•we will still be required to pay certain significant costs relating to the Merger, such as legal, accounting, financial advisor, and printing fees.
In addition, if the Merger Agreement is terminated under certain circumstances specified therein, we may be required to pay Sunoco a termination fee of approximately $90.3 million.
If the Merger is not completed, the risks described above may materialize and they may have a material adverse effect on our results of operations, cash flows, financial position, and the price of our publicly-traded units.
The announcement and pendency of the Merger may adversely affect our business, financial results and operations.
Whether or not the Merger is completed, its announcement and pendency could cause disruptions to our business, including:
•uncertainties associated with the Merger may cause us to lose management personnel and other key employees, which could adversely affect our future business and operations following the Merger;
•our business relationships may be subject to disruption due to uncertainty associated with the Merger, which could have a material adverse effect on our results of operations, cash flows, and financial position;
•matters relating to the Merger (including integration planning) require substantial commitments of time and resources by our management, which may result in the distraction of our management from ongoing business operations and pursuing other opportunities that could be beneficial to us; and
•the Merger Agreement places certain restrictions on how we conduct our operations, which may delay or prevent us from undertaking business opportunities that, absent the Merger Agreement, we may have pursued.
Sunoco may fail to realize the anticipated benefits of the Merger and fail to successfully integrate the businesses and operations of the parties in the expected time frame.
The success of the Merger, and the value that our common unitholders who receive Sunoco common units following the Merger will realize, depends on, among other things, the successful combination of NuStar’s and Sunoco’s businesses in a manner that realizes anticipated synergies and benefits and meets or exceeds the forecasted stand-alone cost savings anticipated by the combined business. If the combined business is not able to successfully achieve these synergies, or the cost to achieve these synergies is greater than expected, then the anticipated benefits of the Merger may not be realized fully or at all or may take longer to realize than expected. If the transaction closes, it is possible that the integration process could result in the loss of key NuStar employees or key Sunoco employees, the loss of customers, providers, vendors, or business partners, the disruption of either or both parties’ ongoing businesses, inconsistencies in standards, controls, procedures, and policies, potential unknown liabilities and unforeseen expenses, delays, or regulatory conditions associated with and following completion of the Merger, or higher than expected integration costs and an overall post-completion integration process that takes longer than originally anticipated.
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In addition, at times the attention of certain members of our management team and resources may be focused on the completion of the Merger and planning the anticipated integration, and diverted from day-to-day business operations or other opportunities that may have been beneficial to NuStar, which may disrupt our ongoing business and the operations of the combined business.
We may be subject to litigation challenging the Merger, and an unfavorable judgment or ruling in any such lawsuits could prevent or delay the consummation of the Merger and/or result in substantial costs.
Lawsuits related to the Merger may be filed against us, Sunoco, and our respective affiliates, directors and officers. If dismissals are not obtained or a settlement is not reached, these lawsuits could prevent or delay completion of the Merger and/or result in substantial costs to us.
RISKS RELATED TO OUR BUSINESS
Changes in price levels could negatively impact our revenue, our expenses, or both, which could adversely affect our financial position, results of operations and cash flows.
The operation of our assets and the execution of capital projects require significant expenditures for labor, materials, property, equipment and services. As a result, such costs may increase during periods of high inflation, including as a result of rising commodity prices, supply chain disruptions and tight labor markets. Recent inflationary pressures affecting the general economy and the energy industry have increased our expenses and capital costs, and those costs may continue to increase. While we expect our pipeline systems to benefit from the positive revenue impact of our tariff indexation increases, we may not be able to pass all of these increased costs to our customers in the form of higher fees for our services, and, if so, our revenues and operating margins would be negatively impacted. Prior to adjustments to applicable rates, material cost increases may affect our operating margins, even if margins in subsequent periods may be normalized following applicable rate adjustments. Accordingly, increased costs during periods of high inflation that are not passed through to customers or offset by other factors may have a material adverse effect on our financial position, results of operations and cash flows.
We may not be able to generate sufficient cash from operations to enable us to pay quarterly distributions to our unitholders.
The amount of cash that we can distribute to our unitholders each quarter principally depends upon the amount of cash we generate from our operations, based on, among other things:
•prevailing macroeconomic conditions as well as economic conditions in and specific to our primary markets;
•demand for and supply of crude oil, refined products, renewable fuels and anhydrous ammonia;
•volumes transported in our pipelines and stored in our terminals and storage facilities;
•the financial stability and strength of our customers;
•tariff and/or contractually determined rates and fees we charge and the revenue we realize for our services;
•domestic and foreign governmental laws, regulations, sanctions, embargoes and taxes;
•the effect of energy conservation, efficiency and other evolving priorities;
•the effect of weather events on our operations and demand for our services; and
•the results of our marketing, trading and hedging activities, which fluctuate depending upon the relationship between refined product prices and prices of crude oil and other feedstocks.
Furthermore, the amount of cash that we will have available for distribution depends on a number of other factors, including:
•our debt service requirements and restrictions on distributions contained in our current or future financing agreements;
•our capital expenditures;
•our operating costs;
•the costs to comply with environmental, health, safety and security laws and regulations;
•fluctuations in our working capital needs;
•fluctuations in interest rates on our variable rate debt instruments and preferred units;
•adjustments in cash reserves made by our board of directors, in its discretion;
•availability of and access to equity capital and debt markets; and
•the sources of cash used to fund our acquisitions, if any.
Moreover, the total amount of cash that we have available for distribution to common unitholders is further reduced by the required distributions with respect to our preferred units. The factors listed above, which may be further impacted by public health crises, international conflicts, actions of oil-producing nations and other factors beyond our control, may reduce our available cash to such an extent that we are unable to pay distributions at the current level or at all in a given quarter. Cash distributions to our unitholders depend primarily upon our cash flows, including cash flows from reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. In other words, we may be able to make cash distributions during periods in which we record net losses and may not be able to make cash distributions during periods in which we record net income.
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Extended periods of reduced demand for or supply of crude oil, refined products, renewable fuels and anhydrous ammonia could have an adverse impact on our results of operations, cash flows and ability to make distributions to our unitholders.
Our business is ultimately dependent upon the demand for and supply of the crude oil, refined products, renewable fuels and anhydrous ammonia we transport in our pipelines and store in our terminals. Market prices for these products are subject to wide fluctuation in response to changes in global and regional supply and demand that are beyond our control. Increases in the price of crude oil may result in a lower demand for refined products that we transport, store and market, including fuel oil, while sustained low prices may lead to reduced production in the markets served by our pipelines and storage terminals.
Any sustained decrease in demand for crude oil, refined products, renewable fuels or anhydrous ammonia in the markets our pipelines and terminals serve that extends beyond the expiration of our existing throughput and deficiency agreements could result in a significant reduction in throughputs in our pipelines and storage in our terminals, which would reduce our cash flows and impair our ability to make distributions to our unitholders. Factors that tend to decrease market demand include:
•a recession, high interest rates, inflation or other adverse economic conditions that result in lower spending by consumers on gasoline, diesel and travel;
•events that negatively impact global economic activity, travel and demand generally;
•higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline;
•an increase in aggregate automotive engine fuel economy;
•new government and regulatory actions or court decisions requiring the phase out or reduced use of gasoline-fueled vehicles;
•the increased use of and public demand for use of alternative fuel sources or electric vehicles;
•an increase in the market price of crude oil that increases refined product prices, which may reduce demand for refined products and increase demand for alternative products; and
•adverse weather events resulting in decreased corn acres planted, which may reduce demand for anhydrous ammonia.
Similarly, any sustained decrease in the supply of crude oil, refined products, renewable fuels or anhydrous ammonia in markets we serve could result in a significant reduction in throughputs in our pipelines and storage in our terminals, which would reduce our cash flows and undermine our ability to make distributions to our unitholders. Factors that tend to decrease supply and, by extension, utilization of our pipelines and terminals include:
•prolonged periods of low prices for crude oil and refined products that result in decreased exploration and development activity and reduced production in markets served by our pipelines and storage terminals;
•macroeconomic forces affecting, or actions taken by, oil and gas producing nations that impact the supply of and prices for crude oil and refined products;
•a lack of drilling services, equipment or skilled personnel available to producers to accommodate production needs;
•changes in laws, regulations, sanctions or taxation that directly or indirectly delay supply or production or increase the cost of production of refined products; and
•political unrest or hostilities, activist interference and the resulting governmental response thereto.
Failure to retain or replace current customers and renew existing contracts on comparable terms to maintain utilization of our pipeline and storage assets at current or more favorable rates could reduce our revenue and cash flows to levels that could adversely affect our ability to make quarterly distributions to our unitholders.
Our revenue and cash flows are generated primarily from our customers’ payments of fees under throughput contracts and storage agreements. Failure to renew existing contracts or enter into new contracts on acceptable terms or a material reduction in utilization under existing contracts results from many factors, including:
•sustained low crude oil prices;
•a material decrease in the supply or price of crude oil;
•a material decrease in demand for refined products, renewable fuels or anhydrous ammonia in the markets served by our pipelines and terminals;
•political, social or economic instability in the United States or another country that has a detrimental impact on our customers and our ability to conduct our operations;
•competition for customers from companies with comparable assets and capabilities;
•scheduled turnarounds or unscheduled maintenance at refineries or production facilities of customers we serve;
•operational problems or catastrophic events affecting our assets or the customers we serve;
•environmental or regulatory proceedings or other litigation that compel the cessation of all or a portion of the operations of our assets or those of the customers we serve;
•increasingly stringent environmental, health, safety and security regulations;
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•a decision by our current customers to redirect products transported in our pipelines or stored in our terminals to markets not served by our pipelines or terminals, or to transport or store crude oil, refined products or anhydrous ammonia by means other than our pipelines or storage terminals; and
•a decision by our current customers to shut down, limit operations of or sell one or more of the refineries/production facilities we serve to a purchaser that elects not to use our pipelines or terminals.
Depending on conditions in the credit and capital markets at a given time, we may not be able to obtain funding on acceptable terms or at all, which may hinder or prevent us from meeting our future capital needs, satisfying our debt obligations, or making quarterly distributions to our unitholders.
From time to time, the domestic and global financial markets and economic conditions are volatile and disrupted by a variety of factors, including low consumer confidence, high unemployment, geoeconomic and geopolitical issues, weak economic conditions, uncertainty in the market and negative sentiment toward fossil fuel energy-related companies generally, or master limited partnerships specifically. In addition, there are fewer investors and lenders for master limited partnership debt and equity capital market issuances than there are for corporate issuances, and negative public sentiment toward the fossil fuel energy industry has led some investors and lenders to reduce or cease investing in and lending to fossil fuel energy companies. As a result, the cost of raising capital has increased, the availability of funds has diminished and certain lenders have, and others may, refuse to refinance existing debt on similar terms or at all and reduce, or in some cases cease to provide, funding to borrowers such as us.
In general, if we do not generate sufficient cash from operations to finance our expenditures and funding from external sources is not available when needed, or is available only on unfavorable terms, we may be unable to execute our growth strategy, complete future acquisitions or construction projects or take advantage of other business opportunities and may be required to reduce investments or capital expenditures or sell assets, which could have a material adverse effect on our revenues and results of operations, and we may not be able to satisfy our debt obligations or pay distributions to our unitholders.
Our future financial and operating flexibility may be adversely affected by our significant leverage, any future downgrades of our credit ratings, restrictions in our debt agreements and conditions in the financial markets beyond our control.
As of December 31, 2023, our consolidated debt was $3.4 billion, and we have the ability to incur more debt. In addition to any potential direct financial impact of our debt, a material increase to our debt or other adverse financial factors would likely be viewed negatively by credit rating agencies, which could result in ratings downgrades, increased costs or inability for us to access the capital markets, an increase in interest rates on amounts borrowed under our Revolving Credit Agreement and an increase in certain fees under our Receivables Financing Agreement.
Certain affirmative and restrictive covenants in our debt agreements and other debt service obligations may adversely affect our future financial and operating flexibility. Our Revolving Credit Agreement contains customary restrictive covenants, such as limitations on indebtedness, liens, mergers, asset transfers and certain investing activities. For example, we must maintain a Consolidated Debt Coverage Ratio (as defined in the Revolving Credit Agreement) that does not exceed 5.00-to-1.00 and a minimum Consolidated Interest Coverage Ratio (as defined in the Revolving Credit Agreement) of at least 1.75-to-1.00. Failure to comply with any of the restrictive covenants or the maximum consolidated debt coverage ratio or minimum consolidated interest coverage ratio requirements would constitute an Event of Default (as defined in our Revolving Credit Agreement) and could result in acceleration of our obligations under our Revolving Credit Agreement and potentially other agreements. Our Receivables Financing Agreement, senior notes and other debt obligations also contain various customary affirmative and negative covenants, default, indemnification and termination provisions, which provide for acceleration of amounts owed upon the occurrence of certain specified events. Future financing agreements we may enter into may contain similar or more restrictive covenants and ratio requirements than those we have negotiated for our current debt agreements.
Our debt service obligations, restrictive covenants, ratio requirements and maturities may adversely affect our ability to finance future operations, pursue acquisitions, fund our capital needs and pay cash distributions to our unitholders. For example, upon the occurrence of specified events under certain of our debt agreements, we would be prohibited from making cash distributions to our unitholders. In addition, this leverage may make our results of operations more susceptible to adverse economic or operating conditions, limit our flexibility in planning for, or reacting to, changes in our business and industry and place us at a competitive disadvantage compared to competitors with proportionately less indebtedness.
Our ability to service our debt will depend on, among other things, our future financial and operating performance and our ability to access the capital markets, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our indebtedness and we are unable to access the capital markets or otherwise refinance our indebtedness, we may be required to reduce our distributions, reduce or delay our business activities, investments or capital expenditures, sell assets or issue additional equity, which could materially and adversely affect the trading price of our units, as well as, our financial condition, results of operations, cash flows and ability to make distributions to unitholders.
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Changes in interest rates could adversely affect our business, access to credit and capital markets, and the trading price of our units.
We have significant exposure to increases in interest rates through variable rate provisions in certain of our debt instruments and our Series A, Series B and Series C Preferred Units. At December 31, 2023, we had approximately $3.4 billion of consolidated debt, of which $2.6 billion was at fixed interest rates and $0.8 billion was at variable interest rates. The distribution rates on our Series A, Series B and Series C Preferred Units have converted from fixed to floating rates. Our results of operations, cash flows and financial position could be materially adversely affected by significant changes in interest rates and uncertainty regarding the floating rates referenced in our variable rate debt instruments and preferred units could adversely affect the value of those financing arrangements. Please see “Quantitative and Qualitative Disclosures about Market Risk” for discussion of our market risk related to interest rates.
We plan to self-fund all of our expenses, distribution requirements and capital expenditures for 2024 using internally generated cash flows as we did for the full-years 2023, 2022 and 2021. An increase in interest rates may have a negative impact on our ability to access the capital markets, refinance existing debt or incur new debt at economically attractive rates, which could adversely affect our future growth by limiting our operational and financial flexibility.
Moreover, the market price of master limited partnership units, like other yield-oriented securities, may be affected by, among other factors, implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, increases or decreases in interest rates may affect whether or not certain investors decide to invest in master limited partnership units, including ours. A rising interest rate environment could have an adverse impact on our unit price and impair our ability to issue additional equity, incur new debt to fund growth, satisfy our existing debt obligations or pay distributions to our unitholders.
Our inability to develop, fund and execute growth projects and acquire new assets could limit our ability to maintain and grow quarterly distributions to our unitholders.
Our ability to maintain and grow our distributions to unitholders depends on the growth of our existing businesses and strategic acquisitions. Decisions regarding new growth projects rely on numerous estimates, including, among other factors, the ability to secure a commitment from a customer that sufficiently exceeds our cost of capital to justify the project cost, predictions of future demand for our services, future supply shifts, crude oil or anhydrous ammonia production estimates, commodity price environments, economic conditions, both domestic and foreign, and potential changes in the financial condition of our customers. Our predictions of such factors could cause us to forego certain investments and to lose opportunities to competitors who make investments based on different predictions or have greater access to financial resources. In addition, volatile market conditions have caused us to reevaluate the estimates underlying certain planned projects and delay the timing of certain projects until conditions improve. If we are unable to develop and execute expansion projects, implement business development opportunities, acquire new assets and finance such activities on economically acceptable terms, our future growth will be limited, which could have a significant adverse impact on our results of operations and cash flows and, accordingly, result in reduced distributions over time.
Failure to complete capital projects as planned may adversely affect our financial condition, results of operations and cash flows.
While we incur financing costs during the planning and construction phases of our projects, a project does not generate expected operating cash flows until it is at least substantially completed, if at all. Additionally, our forecasted operating results from capital spending projects are based on future market fundamentals that are not within our control, including changes in general economic conditions, the supply and demand of crude oil, refined products, renewable fuels and anhydrous ammonia, availability to our customers of attractively priced alternative solutions for storage, transportation or supplies of crude oil, refined products, renewable fuels and anhydrous ammonia and overall customer demand. As a result of these uncertainties, the anticipated benefits associated with our capital projects may not be achieved or could be delayed. In turn, this could have a negative impact on our results of operations and cash flow and our ability to make cash distributions to our unitholders.
Although we evaluate and monitor each capital spending project and try to anticipate difficulties that may arise, unforeseen circumstances may adversely affect our ability to complete such projects as planned, if at all. Delays or cost increases arise as a result of many factors that are beyond our control, including:
•adverse economic conditions;
•market-related increases in a project’s debt or equity financing costs;
•severe adverse weather conditions, natural disasters (such as extreme temperatures, hurricanes, tornadoes, storms, floods and earthquakes) or other events (such as equipment malfunctions, explosions, fires, spills or public health events) affecting our facilities or employees;
•denial or delay in issuing requisite regulatory approvals and/or permits;
•delay or increased costs to obtain right-of-way or other property rights;
•protests and other activist interference with planned or in-process projects;
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•unplanned increases in the cost of construction materials or labor;
•shortages or disruptions in transportation of modular components and/or construction materials; or
•shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages.
Any of the above factors may also adversely affect the facilities, operations or employees of counterparties, vendors, suppliers, contractors, sub-contractors or other third parties involved with our projects, which could result in non-performance or delay by, or disputes with, such parties.
We compete with other midstream service providers, including certain major energy and chemical companies, that possess, or have greater financial resources to acquire, assets better suited to meet customer demand, which could undermine our ability to obtain and retain customers or reduce utilization of our assets, which could adversely affect our revenues and cash flows, thereby reducing our ability to make our quarterly distributions to unitholders.
We face competition in all aspects of our business and can give no assurances that we will be able to compete effectively against our competitors. Our competitors include major energy and chemical companies, some of which have greater financial resources, more pipelines or storage terminals, greater capacity pipelines or storage terminals and greater access to supply than we do. Certain of our competitors also have advantages in competing for acquisitions or other new business opportunities because of their financial resources and synergies in operations. As a consequence of increased competition in the industry or market conditions, some customers are and others may be in the future reluctant to renew or enter into long-term contracts or contracts that provide for minimum throughput amounts. Our inability to renew or replace a significant portion of our current contracts as they expire, to enter into contracts for newly acquired, constructed or expanded assets and to respond appropriately to changing market conditions would have a negative effect on our revenue, cash flows and ability to make quarterly distributions to our unitholders.
Our operations are subject to operational hazards and interruptions, and we cannot insure against or predict all potential losses and liabilities that might result therefrom.
Our operations and those of our customers and suppliers are subject to operational hazards and unforeseen interruptions due to adverse weather conditions, natural disasters (such as heat waves, freezing temperatures, hurricanes, tornadoes, storms, floods and earthquakes), accidents, fires, explosions, hazardous materials releases, mechanical failures, cyberattacks, acts of terrorism and other events beyond our control. These events have, and may in the future, result in a loss of life or equipment, injury or extensive property or environmental damage, as well as an interruption in our operations or those of our customers or suppliers. Additionally, our pipelines, terminals and storage assets are generally long-lived assets, and some have been in service for many years. The age and condition of our assets could result in increased maintenance or repair expenditures in the future. If any of our facilities, or those of our customers or suppliers, suffer significant damage or are forced to shut down for a significant period of time, it may have a material adverse effect on our results of operations and our financial condition as a whole.
As a result of market conditions and losses experienced by us and other companies, the premiums and deductibles for our insurance policies have increased and could continue to increase substantially; therefore, it has become increasingly difficult to, and we may not be able to, maintain or obtain insurance of the type and amount we desire at reasonable rates. In addition, certain insurance coverage is subject to broad exclusions, and may become subject to further exclusions, become unavailable altogether or become available only for reduced amounts of coverage and at higher rates. We are not fully insured against all hazards and risks to our business, and the insurance we carry requires us to meet deductibles before we collect for losses we sustain. If we incur a significant liability for which we are uninsured or not fully insured, or if there is a significant delay in payment of a major insurance claim, such a liability could have a material adverse effect on our financial position.
We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, vendors or other counterparties reduces our revenues and increases our expenses, and any significant level of nonpayment or nonperformance could have a negative impact on our ability to conduct our business, operating results, cash flows and our ability to service our debt obligations and make distributions to our unitholders.
Weak and volatile economic conditions and widespread financial stress may reduce the liquidity of our customers, vendors or other counterparties, making it more difficult for them to meet their obligations to us. We are therefore subject to risks of loss resulting from nonpayment or nonperformance by our customers to whom we extend credit. Financial problems encountered by our customers limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements. In addition, nonperformance by vendors or their subcontractors, who have committed to provide us with critical products or services, increases our costs and could result in significant disruptions or interfere with our ability to successfully conduct our business. Although we attempt to mitigate our risk through warehouseman’s liens and other security protections, we cannot fully eliminate counterparty credit risks. Any substantial increase in the nonpayment or nonperformance by our customers, vendors or other counterparties, or our inability to enforce our liens and other security protections, could have a material adverse effect on our results of operations, cash flows and ability to make distributions to our unitholders.
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We rely on our information technology and operational technology systems to conduct our business. Any significant cybersecurity breach or other significant disruption to those systems would cause our business, financial results and reputation to suffer, increase our costs and expose us to liability, and could adversely affect our ability to make distributions to our unitholders.
We rely on our information technology systems and our operational technology systems to process, transmit and store information, such as employee, customer and vendor data, and to conduct almost all aspects of our business, including safely operating our pipelines and storage facilities, recording and reporting commercial and financial transactions and receiving and making payments. We also rely on systems hosted by third parties, with respect to which we have limited visibility and control, and that have access to or store certain of our employee, customer and vendor data. The security of these networks and systems is critical to our operations and business strategy.
Although we take proactive steps to protect us, our systems and our data from cyberattacks, such as implementing multiple layers of security, segregated systems and user access, antivirus tools, vulnerability scanning, monitoring and patch management, regular employee training, phishing tests, penetration tests, internal risk assessments, independent third-party assessments, tabletop exercises to test our incident response plan, enhanced cyber diligence of vendors and physical security measures, all companies are at risk of a cyberattack. The number and sophistication of reported cyberattacks by both state-sponsored and criminal organizations continue to increase, across industries and around the world, including attacks on operators of critical infrastructure assets, such as pipelines, as well as the third parties that provide technology services for critical infrastructure, in some cases with considerable negative impact on targeted companies’ ability to conduct business.
Like other companies, we recognize that, despite our security measures, we remain subject to cybersecurity incidents due to attacks from a variety of external threat actors, internal employee error or malfeasance and cybersecurity incidents suffered by our service providers, vendors or customers. In addition, some of our employees and those of our service providers, vendors and customers may travel or work from home or other remote-work locations, where cybersecurity protections may be less robust and cybersecurity procedures and safeguards may be less effective. Moreover, certain attacker techniques and goals, such as surveillance, intelligence gathering or extended reconnaissance, may remain undetected for an extended period of time, which can increase the breadth and negative impact of an incident. A significant failure, compromise, breach or interruption in our systems or those of third parties critical to our operations could result in a disruption of our operations; physical damage to our assets or the environment; physical, financial, or other harm to employees or others; safety incidents; damage to our reputation; loss of customers or revenues; increased costs for remedial actions; and potential litigation or regulatory fines. Failures, interruptions and similar events that result in the loss or improper disclosure of information maintained in our systems and networks or those of our vendors, including personnel, customer and vendor information, have in the past and may in the future require reporting under relevant contractual obligations and laws and regulations protecting personal data and privacy and could also subject us to litigation or other liability under relevant contractual obligations, laws and regulations. Our financial results could also be adversely affected if our systems are breached or an employee, vendor or customer causes our systems to fail, either as a result of inadvertent error or deliberate tampering with or manipulation of our systems.
Due to the continued acceleration of cyberattacks, generally and against our industry, regulatory actions by federal, state and local governmental agencies in the United States and in Mexico have increased. Evolving laws and regulations governing cybersecurity and data privacy and protection pose increasingly complex compliance challenges. Although we believe that we have robust cybersecurity procedures and other safeguards in place, we cannot guarantee their effectiveness, and a significant failure, compromise, breach or interruption in our systems or those of our customers or vendors could have a material effect on our operations and the operations of our customers and vendors. As threats continue to evolve and cybersecurity and data privacy and protection laws and regulations continue to develop, we have spent and expect to continue spending additional resources to continue to enhance our cybersecurity, data protection, business continuity and incident response measures, to investigate and remediate any vulnerabilities to, or consequences of, cyber incidents, as well as on regulatory compliance.
Disputes regarding a failure to maintain product quality specifications or other claims related to the operation of our assets and the services we provide to our customers may result in unforeseen expenses and could result in the loss of customers.
Certain of the products we store and transport are produced to precise customer specifications. If the quality and purity of the products we receive are not maintained or a product fails to perform in a manner consistent with the quality specifications required by our customers, customers have sought, and could in the future seek, replacement of the product or damages for costs incurred as a result of the product failing to perform as guaranteed. We also have faced, and could in the future face, other claims by our customers if our assets do not operate as expected by our customers or our services otherwise do not meet our customers’ expectations. Successful claims or a series of claims against us result in unforeseen expenditures and could result in the loss of one or more customers.
Climate change, fuels legislation and other regulatory initiatives restricting emissions of “greenhouse gases” may decrease demand for some of the products we store, transport and sell, increase our operating costs or reduce our ability to expand our facilities.
Climate change laws or regulations enacted by the United States and other political bodies that increase costs, reduce demand or otherwise impede our operations, could, directly or indirectly, have an adverse effect on our business. Legislative and
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regulatory initiatives in the United States, as well as international efforts, have attempted to and will continue to address climate change and control or limit emissions of greenhouse gases. For example, the United States is now a party to the Paris Agreement and has established an economy-wide target of reducing its net greenhouse gas emissions by 50-52 percent below 2005 levels in 2030 and achieving net zero greenhouse gas emissions economy-wide by no later than 2050. The United States has also established a goal to reach 100 percent carbon emissions-free electricity by 2035. Furthermore, many state and local leaders have stated their intent to increase efforts to control or limit emissions of greenhouse gases. Specifically, certain regulatory changes have restricted, and future changes could restrict, our ability to expand our operations and have increased, and in the future could increase, our costs to operate and maintain our existing facilities by requiring that we measure and report our emissions, install new emission controls on our facilities, acquire allowances to authorize our emissions, pay taxes or fees related to our emissions or administer and manage an emissions program, among other things. The passage of climate change legislation and interpretation and action of federal and state regulatory bodies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to greenhouse gases, or restrictions on their use, may reduce volumes available to us for transportation and storage. These developments could have adverse effects on our business, financial position, results of operations and prospects.
In addition, certain of our blending operations subject us to potential requirements to purchase renewable fuels credits. Even though we attempt to mitigate such lost revenues or increased costs through the contracts we sign with our customers, we sometimes are not able to recover those revenues or mitigate the increased costs, and any such recovery depends on events beyond our control, including the outcome of future rate proceedings before the Federal Energy Regulatory Commission (FERC) or other regulators and the provisions of any final legislation or regulations. Reductions in our revenues or increases in our expenses as a result of climate change legislation or other regulatory initiatives could have adverse effects on our business, financial position, results of operations and prospects.
Finally, increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. Such events have had and may in the future have an adverse effect on our assets and operations, especially those located in coastal regions.
Public sentiment towards climate change, fossil fuels and sustainability could adversely affect our business, operations and ability to attract capital.
Our business plans are based upon the assumption that public sentiment and the regulatory environment will continue to enable the future development, transportation and use of carbon-based fuels. Negative public perception of the industry in which we operate and the influence of environmental activists and initiatives aimed at limiting climate change could interfere with our business activities, operations and access to capital. Activists concerned about the potential effects of climate change have directed their attention towards sources of funding for fossil fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital reducing or ceasing lending to or investing in companies in the fossil fuel energy industry, such as us. Having a more limited pool of lenders and investors has resulted in an increase in costs to raise capital, a decrease in the availability of new funding and a diminished ability to refinance existing debt at favorable rates for businesses such as ours, which could have a material adverse effect on our ability to meet our future capital needs, satisfy our debt obligations or pay distributions to our unitholders.
Members of the lending and investment communities are also increasing their focus on sustainability practices, including practices related to greenhouse gas emissions and climate change, in the energy industry. Additionally, some members of the lending and investment communities screen companies such as ours for sustainability performance before lending to us or investing in our units. In response to the increasing pressure regarding sustainability disclosures and practices, we and other companies in our industry publish sustainability reports that are made available to lenders and investors. Such reports are used by some lenders and investors to inform their lending, investment and voting decisions, and we may continue to face increasing pressure regarding sustainability practices and disclosures. Unfavorable sustainability ratings by organizations that provide such information to investors may lead to increased negative lender and investor sentiment toward us or our customers and to the diversion of capital to other industries, which would have a negative impact on our unit price and/or our access to and costs of capital. Such negative sentiment regarding our industry could influence consumer preference and decrease demand for the products we transport and store and may result in increased regulatory scrutiny, which could then result in additional laws, regulations, guidelines and enforcement interpretations, at the federal, state or local level. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation.
Our operations are subject to federal, state and local laws and regulations, in the U.S. and in Mexico, relating to environmental, health, safety and security that require us to make substantial expenditures.
Our operations are subject to increasingly stringent international, federal, state and local environmental, health, safety and security laws and regulations. Transporting, storing and distributing hazardous materials, including petroleum products, entails the risk of releasing these products into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies including for damages to natural resources, personal injury or property damages to private parties and significant business interruption. Further, our pipeline facilities are subject to the
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pipeline integrity and safety regulations of various federal and state regulatory agencies, as well as cybersecurity directives. In recent years, increased regulatory focus on pipeline integrity, safety and security has resulted in various proposed or adopted regulations. The implementation of these regulations has required, and the adoption of future regulations could require, us to make additional capital or other expenditures, including to install new or modified safety or security measures, or to conduct new or more extensive inspection and maintenance programs.
Legislative action and regulatory initiatives have resulted in, and could in the future result in, changes to operating permits, imposition of carbon taxes or methane fees, material changes in operations, increased capital expenditures and operating costs, increased costs of the goods we transport and/or decreased demand for products we handle. Future impacts cannot be assessed with certainty at this time. Required expenditures to modify operations or install pollution control equipment or release prevention and containment systems or other environmental, health, safety or security measures could materially and adversely affect our business, financial condition, results of operations and liquidity if these expenditures, as with all costs, are not ultimately reflected in the tariffs and other fees we receive for our services.
We own or lease a number of properties that were used to transport, store or distribute products for many years before we acquired them; therefore, such properties were operated by third parties whose handling, disposal or release of products and wastes was not under our control. Environmental laws and regulations could impose obligations to conduct assessment or remediation efforts at our facilities, third-party sites where we take wastes for disposal, or where wastes have migrated. Environmental laws and regulations also may impose joint and several liability on us for the conduct of third parties or for actions that complied with applicable requirements when taken, regardless of negligence or fault. If we were to incur a significant liability pursuant to environmental, health, safety or security laws or regulations, such a liability could have a material adverse effect on our financial position.
We operate assets outside of the United States, which exposes us to different legal and regulatory requirements and additional risk.
A portion of our revenues are generated from our assets located in northern Mexico. Our operations are subject to various risks unique to Mexico that could have a material adverse effect on our business, results of operations and financial condition, including political and economic instability from civil unrest; labor strikes; war and other armed conflict; inflation; currency fluctuations, devaluation and conversion restrictions or other factors. Any deterioration of social, political, labor or economic conditions, including the increasing threat of terrorist organizations and drug cartels in Mexico, or affecting a customer with whom we do business, as well as difficulties in staffing, obtaining necessary equipment and supplies and managing foreign operations, may adversely affect our operations or financial results. We are also exposed to the risk of foreign and domestic governmental actions that may: impose additional costs on us; delay permits or otherwise impede our operations; limit or disrupt markets for our operations, restrict payments or limit the movement of funds; impose sanctions on or otherwise restrict our ability to conduct business with certain customers or persons or in certain countries; or result in the deprivation of contract rights. Our operations outside the United States may also be affected by changes in trade protection laws, policies and measures, and other regulatory requirements affecting trade and investment, including the Foreign Corrupt Practices Act and foreign laws prohibiting corrupt payments, as well as travel restrictions and import and export regulations.
We may be unable to obtain or renew permits necessary for our current or proposed operations, which could inhibit our ability to conduct or expand our business.
Our facilities operate under a number of federal, state and local permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. These limits and standards require a significant amount of monitoring, recordkeeping and reporting in order to demonstrate compliance with the underlying permit, license or approval. Noncompliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. In addition, public protest, political activism and responsive government intervention have made it more difficult for energy companies to acquire the permits required to complete planned infrastructure projects. A decision by a government agency to deny or delay issuing a new or renewed permit, license or approval, or to revoke or substantially modify an existing permit, license or approval, or to impose additional requirements on the renewal could have a material adverse effect on our ability to continue or expand our operations and on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.
We could be subject to liabilities from our assets that predate our acquisition of those assets, but that are not covered by indemnification rights we have against the sellers of the assets.
We have acquired assets and businesses and we are not always indemnified by the seller for liabilities that precede our ownership. In addition, in some cases, we have indemnified the previous owners and operators of acquired assets or businesses. Some of our assets have been used for many years to transport and store crude oil and refined products, and past releases could require costly future remediation. If a significant release or event occurred in the past, the liability for which was not retained by the seller, or for which indemnification by the seller is not available, it could adversely affect our financial position and results of operations. Conversely, if liabilities arise from assets we have sold, we could incur costs related to those liabilities if the buyer possesses valid indemnification rights against us with respect to those assets.
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Certain of our interstate common carrier pipelines are subject to regulation by the FERC and the Surface Transportation Board, which could have an adverse impact on our ability to recover the full cost of operating our pipelines and the revenue we are able to receive from those operations.
Pursuant to the Interstate Commerce Act (ICA) and various other laws, the FERC regulates tariff rates and terms and conditions of service for interstate crude oil and refined products movements on common carrier pipelines. The FERC requires that these rates be just and reasonable and not unduly discriminatory with respect to any shipper. The FERC or shippers may challenge required pipeline tariff filings, including rates and terms and conditions of service. Further, other than for rates set under market-based rate authority, if a new rate is challenged by protest and investigated by the FERC, the FERC may require amounts refunded where such amounts were collected in excess of the deemed just and reasonable rate. In addition, shippers may challenge by complaint tariff rates and terms and conditions of service even after they take effect, and the FERC may order a carrier to change its rates prospectively to a just and reasonable level. A complaining shipper also may obtain reparations for damages sustained during the two years prior to the date of the complaint.
We are able to use various FERC-authorized rate change methodologies for our interstate pipelines, including indexed rates, cost-of-service rates, market-based rates and negotiated rates. Typically, we adjust our rates annually in accordance with the FERC indexing methodology, which currently allows a pipeline to change its rates within prescribed ceiling levels that are tied to an inflation index. It is possible that the index may result in negative rate adjustments in some years, or that changes in the index might not be large enough to fully reflect actual increases in our costs. The FERC’s indexing methodology is subject to review and revision every five years, with the most recent five-year review occurring in 2020. On December 17, 2020, the FERC established the index level for the five-year period commencing July 1, 2021, which will end on June 30, 2026, at the Bureau of Labor’s producer price index for finished goods (PPI-FG) plus 0.78%. On January 20, 2022, the FERC granted rehearing of certain aspects of the final rule and revised the index level to PPI-FG minus 0.21%, effective March 1, 2022 through June 30, 2026. The FERC ordered pipelines with filed rates that exceed their index ceiling levels based on PPI-FG minus 0.21% to file rate reductions effective March 1, 2022, which could result in a further change to the index. The FERC has granted us authority to charge market-based rates on some of our pipelines, which are not subject to cost-of-service or indexing constraints. If we were to lose market-based rate authority, however, we could be required to establish rates on some other basis, such as cost-of-service, which could reduce our revenues and cash flows. Additionally, competition constrains our rates in various markets, which may force us to reduce certain rates to remain competitive.
Pursuant to the ICC Termination Act of 1995 (ITA), the Surface Transportation Board (STB) regulates interstate pipelines carrying products other than gas, oil or water, including the anhydrous ammonia we transport. Unlike the ICA, which allows the FERC to investigate a carrier’s rates on its own initiative, ITA prescribes the STB may only investigate issues in response to complaints by shippers and other interested parties. Further, carriers are not required by the ITA or the STB to report rates charged to transport anhydrous ammonia or other commodities, and the STB does not routinely collect such information. Adverse changes in the FERC’s or STB’s rate change methodologies or challenges to our rates that result in significant damages could negatively affect our cash flows, results of operations and our ability to make distributions to our unitholders.
We do not own all of the land on which our pipelines and facilities are located, and we are therefore subject to the possibility of increased costs or the inability to retain necessary land use.
Like other pipeline and storage logistics services providers, certain of our pipelines, storage terminals and other facilities are located on land owned by third parties and governmental agencies that we have obtained the right to utilize for these purposes through contract (rather than through outright purchase). Many of our rights-of-way or other property rights are perpetual in duration, but others are for a specific period of time. In addition, some of our facilities are located on leased premises. A potential loss of property rights through our inability to renew right-of-way contracts or leases or otherwise retain property rights on acceptable terms or the increased costs to renew such rights could adversely affect our financial condition, results of operations and cash flows available for distribution to our unitholders.
Increases in power prices could adversely affect operating expenses and our ability to make distributions to our unitholders.
Power costs constitute a significant portion of our operating expenses. For the year ended December 31, 2023, our power costs equaled approximately $48.2 million, or 13% of our operating expenses for the year. We use mainly electric power at our pipeline pump stations and terminals, and such electric power is furnished by various utility companies. Requirements for utilities to use less carbon intensive power or to add pollution control devices also could cause our power costs to increase and our cash flows may be adversely affected, which could adversely affect our ability to make distributions to our unitholders.
We may be adversely affected by changes in the method of determining the London Interbank Offering Rate (LIBOR) or the replacement of LIBOR with an alternative reference rate, such as the Secured Overnight Financing Rate (SOFR).
The publication of non-U.S. dollar LIBOR rates ceased after publication on December 31, 2021 and the publication of U.S. dollar LIBOR rates for the most common tenors (overnight and one, three, six and twelve months) is ceased after publication on June 30, 2023. In addition, in March 2022, the Adjustable Interest Rate (LIBOR) Act (the “LIBOR Act”) was signed into law. This law provides a statutory fallback mechanism to replace LIBOR with a benchmark rate that is selected by the Federal Reserve Board and based on SOFR for certain contracts that reference LIBOR without adequate fallback provisions providing for a clearly defined replacement benchmark. On December 16, 2022, the Federal Reserve Board adopted a final rule to
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implement the LIBOR Act and established benchmark rates based on SOFR to replace LIBOR contracts governed by U.S. law that reference certain tenors of U.S. dollar LIBOR after June 30, 2023. The regulations include provisions that (i) provide a mechanism for the automatic replacement of LIBOR with the benchmark rate selected by the Federal Reserve Board; (ii) clarify who may contractually select a benchmark replacement for LIBOR; and (iii) ensure that contracts transitioning to the replacement benchmark rate selected by the Federal Reserve Board will not be interrupted or terminated following the replacement of LIBOR. On June 30, 2023, the publication of U.S. dollar LIBOR rates ceased and, beginning with the distribution period starting on September 15, 2023, the distribution rates on our Series A, Series B and Series C preferred units converted from a floating rate based on three-month LIBOR to three-month CME Term SOFR plus the applicable tenor spread adjustment of 0.26161%, in accordance with the guidance and the applicable rules and regulations governing such transition. The consequences of the transition away from LIBOR and the use of SOFR cannot be entirely predicted but could include an increase in the cost of our variable-rate indebtedness, our Series A, Series B and Series C preferred units and other commercial arrangements tied to LIBOR.
An impairment of goodwill or long-lived assets could reduce our earnings.
As of December 31, 2023, we had $0.7 billion of goodwill and $3.8 billion of long-lived assets, including property, plant and equipment, net and intangible assets, net. GAAP requires us to test both goodwill and long-lived assets for impairment when events or circumstances occur indicating that either goodwill or long-lived assets might be impaired and, in the case of goodwill, at least annually. Any event that causes a reduction in demand for our services could result in a reduction of our estimates of future cash flows and growth rates in our business, which could cause us to record an impairment charge to reduce the value of goodwill. Similarly, any event or change in circumstances that causes the carrying value of our long-lived assets to no longer be recoverable may require us to record an impairment charge to reduce the value of our long-lived assets. If we determine that either our goodwill or our long-lived assets are impaired, the resulting charge will reduce earnings and partners’ capital.
RISKS INHERENT IN AN INVESTMENT IN US
As a master limited partnership, we do not have the same flexibility that corporations and other business organizations may have to accumulate cash and prevent illiquidity in the future, which may limit our growth.
Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our common unitholders of all available cash, after taking into account reserves for commitments and contingencies, including growth and other capital expenditures and operating costs, debt service requirements and payments with respect to our preferred units. We are therefore more likely than those organizations to require issuances of additional debt and equity securities to finance our growth plans, meet unforeseen cash requirements and service our debt and other obligations. To the extent we issue additional units, the payment of distributions on those additional units may increase the risk that we will be unable to maintain our current per unit distribution level and the value of our common units and other limited partner interests may decrease in correlation with any reduction in our cash distributions per unit. Accordingly, if we experience a liquidity shortage in the future, we may not be able to issue additional equity to recapitalize.
Unitholders have limited voting rights, and our partnership agreement restricts the voting rights of certain unitholders owning 20% or more of any class of our units.
Unlike holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders’ voting rights are further restricted by a provision in our partnership agreement providing that units held by certain persons that own 20% or more of any class of units then outstanding cannot vote on any matter without the prior approval of our general partner.
We may issue additional equity securities, including equity securities that are senior to our common units, which would dilute our unitholders’ existing ownership interests.
Our partnership agreement allows us to issue an unlimited number of additional equity securities without the approval of other unitholders as long as the newly issued equity securities are not senior to, or equally ranked with, our preferred units. We may issue an unlimited number of units that are senior to our common units and equally ranked with our preferred units. However, in certain circumstances, we may be required to obtain the approval of the holders of a majority of each class of our preferred units before we could issue equity securities that are equally ranked with our preferred units.
Our issuance of additional units or other equity interests of equal or senior rank will have the following effects:
•our unitholders’ proportionate ownership interest in us will decrease;
•the amount of cash available for distribution on each unit may decrease;
•the amount of cash available for redemption of, or payment of the liquidation preference on, each preferred unit may decrease;
•the ratio of taxable income to distributions may increase;
•the relative voting strength of each previously outstanding unit may be diminished; and
•the market price of our common units and preferred units may decline.
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In addition, our partnership agreement requires that unitholders vote as a separate class with all other series of our equally ranked securities that may be issued and possess similar voting rights. As a result, the voting rights of holders of our preferred units may be significantly diluted, and the holders of such future securities of equal rank may be able to control or significantly influence the outcome of any vote with respect to which the holders of our preferred units are entitled to vote. Our partnership agreement contains limited protections for the holders of our preferred 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. Distributions to our preferred unitholders are cumulative, so we must pay all unpaid accumulated preferred distributions before we can declare or pay any distributions to our common unitholders. Distributions to our common unitholders are not cumulative, therefore, if we do not pay distributions on our common units with respect to any quarter, our common unitholders will not be entitled to receive distributions that would have accumulated in that quarter. The preferences and privileges granted to holders of our preferred units could adversely affect the market price for our common units and could make it more difficult for us to sell our common units in the future.
If a court were to determine that a unitholder action constituted control of our business, the unitholders may lose their legal protection from liability and be required to repay distributions wrongfully distributed to them.
Our partnership agreement is governed by the laws of the State of Delaware. If a Delaware court were to determine that actions of a unitholder constituted participation in the “control” of our business, that unitholder would be held liable for our obligations to the same extent as a general partner. Under Delaware law, a general partner generally has unlimited liability for the obligations of the partnership, such as its debts and environmental liabilities, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner.
Furthermore, under Delaware law, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are nonrecourse to the partnership are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that, for a period of three years from the date of an impermissible distribution, limited partners, including a unitholder, who received such impermissible distribution and who knew at the time of the distribution that it violated Delaware law will be liable to us for the repayment of the distribution amount. Likewise, our unitholders may be required to repay impermissible distributions upon the winding up of our partnership in the event that our assets are not distributed in accordance with Delaware law and a limited partner knows at the time that the distribution violated Delaware law. If a limited partner knowingly received an impermissible distribution, then such limited partner could be liable to repay the distribution for a period of three years from the impermissible distribution under applicable Delaware law.
The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.
We currently list our common units on the NYSE under the symbol “NS” and our preferred units on the NYSE under the symbols “NSprA,” “NSprB” and “NSprC,” respectively. Although our general partner has maintained a majority of independent directors on its board and all members of its board’s audit committee, compensation committee and nominating/governance & conflicts committee are independent directors, because we are a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to have a compensation committee or a nominating committee consisting of independent directors. Additionally, any future issuance of additional common or preferred units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules that apply to a corporation. Accordingly, the NYSE does not mandate the same protections for our unitholders as are required for certain corporations that are subject to all of the NYSE corporate governance requirements.
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TAX RISKS TO OUR UNITHOLDERS
If we were treated as a corporation for federal or state income tax purposes or we were otherwise subject to a material amount of entity-level taxation, then our cash available for distribution to unitholders would be substantially reduced.
The anticipated after-tax benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes. Despite the fact that we are a limited partnership under Delaware law, we will be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement.
If we were treated as a corporation, we would pay federal income tax at the corporate tax rate and would likely pay state and local income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our distributable cash flow would be substantially reduced. Additionally, at the state level, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. If we were treated as a corporation for federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, then our cash available for distribution to unitholders would be substantially reduced and there would be a material reduction in the after-tax return to our unitholders, likely causing a substantial reduction in the value of our units.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, and possibly applied on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws, which may be further interpreted by federal courts, that affect publicly traded partnerships, including elimination of partnership tax treatment for certain publicly traded partnerships.
Any changes to the federal income tax laws and interpretations thereof may be applied retroactively and any such changes that are adverse to our interests could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for federal income tax purposes. We are unable to predict whether any additional changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our units or otherwise adversely affect our business, financial condition or results of operations.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes, penalties and interest directly from us. If we bear such payment, our cash available for distribution to our unitholders might be substantially reduced.
For tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes, penalties and interest resulting from such audit adjustment directly from us. To the extent possible under applicable rules, our general partner may pay such amounts directly to the IRS or, if we are eligible, elect to issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. No assurances can be made that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own common units in us during the tax year under audit. If, as a result of any such audit adjustment, we make payments of taxes, penalties and interest, our cash available for distribution to our unitholders could be substantially reduced.
Unitholders will be required to pay taxes on their share of our taxable income even if they do not receive cash distributions from us.
Unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their respective share of our taxable income, whether or not the unitholders receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their respective share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.
Tax gain or loss on the disposition of our common units could be different than expected.
A unitholder who sells units will recognize a gain or loss equal to the difference between the amount realized and the unitholder’s tax basis in those units. Prior distributions to the unitholder in excess of the total net taxable income with respect to a common unit will reduce the unitholder’s tax basis in that unit. As a result, the selling unitholder can recognize a gain if such unit is sold at a price greater than the unitholder’s tax basis in that unit, even if the price the unitholder receives is less than the unit’s original cost. A substantial portion of the amount realized, even if there is a net taxable loss realized on the sale, may be ordinary income to the selling unitholder. In addition, because the amount realized will include a unitholder’s share of our nonrecourse liabilities, a unitholder may incur a tax liability upon a sale of common units in excess of the amount of cash it receives from the sale.
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Unitholders may be subject to limitations on their ability to deduct interest expense incurred by us.
Our ability to deduct interest paid or accrued on indebtedness properly allocable to a trade or business (business interest), may be limited in certain circumstances. Should our ability to deduct business interest be limited, the amount of taxable income allocated to our unitholders in the taxable year in which the limitation is in effect may increase. However, in certain circumstances, a unitholder may be able to utilize a portion of a business interest deduction subject to this limitation in future taxable years. Prospective unitholders should consult their tax advisors regarding the impact of this business interest deduction limitation on an investment in our units.
Tax-exempt entities face unique tax issues from owning our units that may result in adverse tax consequences to them.
Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (IRAs) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Tax-exempt entities should consult a tax advisor before investing in our units.
Non-U.S. unitholders will be subject to U.S. taxes and withholding on their income and gain from owning our units.
Non-U.S. unitholders are subject to U.S. federal income tax on income effectively connected with a U.S. trade or business (effectively connected income). A unitholder’s share of our income, gain, loss and deduction, and any gain from the sale or disposition of our units will generally be considered effectively connected income and subject to U.S. federal income tax. Additionally, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate.
Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person. Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor. Quarterly distributions made to our non-U.S. unitholders will also be subject to withholding under these rules to the extent a portion of a distribution is attributable to an amount in excess of our cumulative net income that has not previously been distributed. We intend to treat all of our distributions as being in excess of our cumulative net income for such purposes and subject to the additional 10% withholding tax. The Treasury regulations further provide that these rules will generally not apply to transfers of, or distributions on, interests in a publicly traded partnership occurring before January 1, 2023, and after that date, if effected through a broker, the obligation to withhold is imposed on the transferor’s broker. Current and prospective non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common and preferred units.
We will treat each purchaser of our common units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
Because we cannot match transferors and transferees of our common units, we have adopted depreciation and amortization positions that may not conform with all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the unitholder’s tax returns.
Unitholders will likely be subject to state and local taxes and return filing requirements as a result of investing in our units.
In addition to federal income taxes, unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. Unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We may own property or conduct business in other states or foreign countries in the future. It is each unitholder’s responsibility to file all federal, state and local tax returns.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our common unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. Treasury regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our common unitholders.
We have adopted certain valuation methodologies in determining a common unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methods or the resulting allocations and such a challenge could adversely affect the value of our common units.
In determining the items of income, gain, loss and deduction allocable to our common unitholders, we must routinely determine
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the fair market value of our respective assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our respective assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.
A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of taxable income or loss being allocated to our common unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our common unitholders’ tax returns without the benefit of additional deductions.
A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller”) may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
Treatment of distributions on our preferred units as guaranteed payments for the use of capital is uncertain and such distributions are not eligible for the 20% deduction for qualified publicly traded partnership income.
The tax treatment of distributions on our preferred units is uncertain. We will treat the holders of preferred units as partners for tax purposes and will treat distributions on the preferred units as guaranteed payments for the use of capital that will generally be taxable to the holders of preferred units as ordinary income. Holders of preferred units will recognize taxable income from the accrual of such a guaranteed payment even in the absence of a contemporaneous distribution. Otherwise, the holders of preferred units are generally not anticipated to share in our items of income, gain, loss or deduction, nor will we allocate any share of our nonrecourse liabilities to the holders of preferred units. If the preferred units were treated as indebtedness for tax purposes, rather than as guaranteed payments for the use of capital, distributions likely would be treated as payments of interest by us to the holders of preferred units.
Although we expect that much of our income will be eligible for the 20% deduction for qualified publicly traded partnership income (currently available for taxable years beginning after December 31, 2017, and ending on or before December 31, 2025), Treasury regulations provide that income attributable to a guaranteed payment for the use of capital is not eligible for the 20% deduction for qualified business income. As a result, income attributable to a guaranteed payment for use of capital recognized by holders of our preferred units is not eligible for the 20% deduction for qualified business income.
A holder of preferred units will be required to recognize gain or loss on a sale of preferred units equal to the difference between the amount realized by such holder and such holder’s tax basis in the preferred units sold. The amount realized generally will equal the sum of the cash and the fair market value of other property such holder receives in exchange for such preferred units. Subject to general rules requiring a blended basis among multiple partnership interests, the tax basis of a preferred unit will generally be equal to the sum of the cash and the fair market value of other property paid to acquire such preferred unit. Gain or loss recognized on the sale or exchange of a preferred unit held for more than one year generally will be taxable as long-term capital gain or loss. Because holders of preferred units will generally not be allocated a share of our items of depreciation or amortization, it is not anticipated that such holders would be required to re-characterize any portion of their gain as ordinary income as a result of the recapture rules.
Investment in the preferred units by tax-exempt investors, such as employee benefit plans and IRAs, and non-U.S. persons raises issues unique to them. The treatment of guaranteed payments for the use of capital to tax-exempt investors is not certain and the income resulting from such payments may be treated as unrelated business taxable income for U.S. federal income tax purposes. A non-U.S. holder’s income from guaranteed payments and any gain from the sale or disposition of our units may be considered to be effectively connected income and subject to U.S. federal income tax. Distributions and any gain from the sale or disposition of our preferred units to non-U.S. holders of preferred units may be subject to withholding taxes. If the amount of withholding exceeds the amount of U.S. federal income tax actually due, non-U.S. holders of preferred units may be required to file U.S. federal income tax returns in order to seek a refund of such excess.
All holders of our preferred units are urged to consult a tax advisor with respect to the consequences of owning and selling our preferred units.
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ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 1C. CYBERSECURITY
Risk Management and Strategy
We have developed an information security program to assess, identify and manage material risks from cybersecurity threats. Our program includes policies and procedures that identify how security measures and controls are developed, implemented and maintained. We have aligned our cybersecurity program to the NIST Cybersecurity Framework and we assess our program against this standard annually. We are regulated by the Transportation Security Administration (TSA) as a pipeline infrastructure company and are required to comply with all TSA cybersecurity regulations. We use industry standard metrics to assess the criticality of software, data assets and operational technology.
We conduct periodic cyber risk assessments and assessments of our operational-technology network. We use these risk assessments together with risk-based analysis and judgment to determine which security controls to use to address identified risks. We also complete internal and external testing of software, hardware, defensive capabilities and other information security systems as advised by industry standards, and we use the test results to address identified vulnerabilities. We regularly conduct cyber threat exercises, which help us identify and address any gaps in our incident response plan. These exercises also help us practice sound decision-making skills to enhance our ability to react effectively during a material cyber event.
We rely on third-party software, third-party service providers and third-party applications to run certain aspects of our business and to aid in the development, implementation and maintenance of our security measures and controls. We regularly conduct third-party security audits and use vendor management programs to ensure that third-party software, service providers and applications comply with our vendor management program.
We consider the following factors, among others, to identify and manage material risks: (i) the likelihood of a risk occurring; (ii) the impact of a risk on us and others, including the likelihood of enforcement actions alleging potential regulatory violations, sanctions, litigation and other legal risks; and (iii) the controls we have applied to mitigate a risk’s likelihood and impact. When selecting controls, we consider the likelihood and impact of identified risks, regulatory and other legal requirements, the feasibility of implementing a control and the potential impact of a control on our operations.
We use the following controls, among others, to mitigate the material cyber risks that we face: endpoint threat detection and response (EDR), identity and access management (IAM), logging and monitoring involving the use of security information and event management (SIEM), multi-factor authentication (MFA), firewalls and intrusion detection and prevention, a vendor management program (VMP) and vulnerability and patch management.
We use third-party security firms to provide or operate certain controls and technology systems. We use third parties to conduct assessments, such as monitoring vulnerability scans and penetration testing. We address cybersecurity threats related to our third-party technology and services through several processes, including pre-acquisition due diligence, contractual obligations and performance monitoring.
We have a written incident response plan and we conduct tabletop exercises to enhance incident response preparedness. We use business continuity and disaster recovery plans to prepare for a potential disruption in the technology we rely on. We train our employees on cybersecurity awareness when they are hired and conduct additional training annually thereafter.
Our executive management team has the day-to-day responsibility of assessing and managing our overall risk exposure, and our Board of Directors oversees those efforts. We have integrated cybersecurity risk into our overall risk management systems and processes. Our full Board has direct oversight over our cybersecurity risk management. The Board interfaces regularly with management and receives periodic reports on our areas of risk, including cybersecurity. Management interacts regularly with our Cyber Risk Governance Committee (CRGC), which meets regularly and oversees the effectiveness of our cybersecurity program. We make additional disclosures regarding our assessment, identification and management of cybersecurity risks below under the caption “Governance,” and we hereby incorporate by reference those disclosures into this discussion of “Risk Management and Strategy.”
We (or third parties we rely on) may not be able to fully, continuously and effectively implement security controls as designed or intended. We use a risk-based approach and the judgment of our CRGC, management and third parties with extensive expertise in cyber risk management to determine which security controls we implement. It is possible we may not implement appropriate controls if we do not properly identify or inadvertently underestimate a particular risk. In addition, security controls, no matter how well designed or implemented, may only mitigate but not fully eliminate risks. Further, when security tools or third parties detect events, it may take us and our third parties time to analyze and understand the risks — and to determine the proper procedural steps to mitigate the effects of such risks — before we can effectively act upon the events.
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Impacts of Material Risk.
Pipeline operators have faced and continue to face risks from threat actors that focus their attacks on critical infrastructure assets and disruption to operations. We also face risks from ransomware groups that steal data, encrypt systems and demand a payment. We have cybersecurity protocols and procedures in place—and we rely on third-party software, hardware and vendors—to manage critical aspects of our operations. While we have controls in place to address these risks, if these risks occur, the impact could be material, such as in the event of a cybersecurity incident causing the loss of operational control, disruption of our operations, a demand for ransomware payment or physical damage to our assets or the environment.
Additionally, in Item 1A. “Risk Factors” under the caption “Risks Related to our Business,” we discuss forward-looking cybersecurity risks that could have a material impact on us. Our disclosures in Item 1A. “Risk Factors” should be read in conjunction with this Item 1C.
Governance
Our Board of Directors has direct oversight over key risks that are broadly applicable across NuStar’s businesses, including cybersecurity risk management. At each regularly scheduled meeting of the Board, the Board receives reports from our President and Chief Executive Officer (CEO) and Senior Vice President–Chief Information Officer and Controller (CIO) regarding our cybersecurity program. These reports include (i) regulatory updates, which include information on regulatory initiatives promulgated by governmental agencies and our compliance with such initiatives, and (ii) quarterly metrics and data, which include information on employee training, threats, incidents, preventive practices (e.g., patch installation), tabletop exercises, cybersecurity policies and cybersecurity program resources, risks and controls.
Our CIO is the management position with primary responsibility for the development, operation and maintenance of our information security program. He reports directly to our CEO. Certain of the CIO’s direct reports have extensive expertise in the area of cyber risk management.
Our CRGC is composed of management representatives from key functions across our company. Our CIO serves as the Chair of the CRGC. The CRGC meets regularly and oversees the effectiveness of our cybersecurity program. The CRGC operates to deliver management-level oversight of cybersecurity matters. The CRGC reports regularly to our executive management team. The Chair of our CRGC reports regularly to our Board of Directors.
We use governance, risk and compliance tools to assess, identify and manage cybersecurity risks. To address potential cybersecurity events, we have developed an incident response plan that defines protocols and processes for effectively managing our response to an event, including protocols for the escalation of critical information to management, key company personnel and the Board.
ITEM 3. LEGAL PROCEEDINGS
We incorporate by reference into this Item 3. our disclosures in Note 14 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” under the caption, “Contingencies.”
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Series A, B and C Preferred Units
Information on our 8.50% Series A, 7.625% Series B and 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (collectively the Series A, B and C Preferred Units) is shown below:
| 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% | |||||||||||||||||
(a)Beginning with the distribution period from September 15, 2023 to December 14, 2023, LIBOR was replaced with the corresponding CME Term SOFR plus the applicable tenor spread adjustment of 0.26161%.
Common Units
Our common units are listed and traded on the New York Stock Exchange under the symbol “NS.” At the close of business on February 7, 2024, we had 344 holders of record of our common units.
Our partnership agreement requires that we distribute all Available Cash to our common limited partners each quarter. Available Cash is generally defined in the partnership agreement as all cash receipts less cash disbursements, including distributions to our preferred unit holders, and cash reserves established by our general partner, in its sole discretion.
See Note 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on our Series A, B and C Preferred Units and common units.
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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, 2018, and its relative performance is tracked through December 31, 2023.
| As of December 31, | |||||||||||||||||||||||||||||||||||
| 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | ||||||||||||||||||||||||||||||
| NuStar Energy L.P. | $ | 100.00 | $ | 135.03 | $ | 84.77 | $ | 103.03 | $ | 114.84 | $ | 147.51 | |||||||||||||||||||||||
| S&P 500 Index | 100.00 | 131.49 | 155.68 | 200.37 | 164.08 | 207.21 | |||||||||||||||||||||||||||||
| Alerian MLP Index | 100.00 | 106.56 | 75.99 | 106.51 | 139.44 | 176.47 | |||||||||||||||||||||||||||||
Sales of Unregistered Securities
During the fourth quarters of 2022 and 2021, NuStar Energy issued an aggregate of 3,120 common units and 5,509 common units, respectively, in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof, upon the vesting of outstanding awards under a long-term incentive plan.
ITEM 6. RESERVED
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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 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.
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 | Fair Value | ||||||||||||||||||||||||||||||||||||||||
| (Thousands of Dollars, Except Interest Rates) | |||||||||||||||||||||||||||||||||||||||||||||||
| Fixed-rate debt | $ | — | $ | — | $ | 600,000 | $ | 500,000 | $ | 550,000 | $ | 922,140 | $ | 2,572,140 | $ | 2,478,720 | |||||||||||||||||||||||||||||||
| Weighted-average rate | — | — | 5.8 | % | 6.0 | % | 5.6 | % | 6.3 | % | 6.0 | % | — | ||||||||||||||||||||||||||||||||||
| Variable-rate debt | $ | — | $ | — | $ | 300,900 | $ | — | $ | — | $ | 402,500 | $ | 703,400 | $ | 690,944 | |||||||||||||||||||||||||||||||
| Weighted-average rate | — | — | 6.7 | % | — | — | 10.8 | % | 9.0 | % | — | ||||||||||||||||||||||||||||||||||||
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 on December 15, 2021, June 15, 2022 and December 15, 2022, respectively. Based upon the 9,060,000 Series A Preferred Units, 15,400,000 Series B Preferred Units and 6,900,000 Series C Preferred Units outstanding as of December 31, 2023 and the $25.00 liquidation preference per unit, a change of 1.0% in interest rates would increase or decrease the annual distributions on our Series A, B and C Preferred Units by an aggregate amount of $7.8 million. See Note 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information 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
53
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining effective internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934. Our management assessed the effectiveness of NuStar Energy L.P.’s internal control over financial reporting as of December 31, 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, 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, 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 57.
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Report of Independent Registered Public Accounting Firm
To the Board of Directors of NuStar GP, LLC and Unitholders of
NuStar Energy L.P.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of NuStar Energy L.P. and subsidiaries (the Partnership) as of December 31, 2023 and 2022, the related consolidated statements of income, comprehensive income, cash flows, and partners’ equity and mezzanine equity for each of the years in the three-year period ended December 31, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 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, 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 22, 2024 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Identification of triggering events related to the recoverability of certain long-lived assets or asset groups
As discussed in Note 2, the Partnership tests long-lived assets, including property, plant, and equipment, for impairment whenever events or changes in circumstances (triggering events) indicate that the carrying amount may not be recoverable. The Partnership evaluates recoverability using undiscounted estimated net cash flows generated by the related asset or asset group considering the intended use of the asset. The balance of property, plant, and equipment, net as of December 31, 2023 was $3,283 million, or 67% of total assets, of which certain assets or asset groups were not supported by existing revenue generating contacts or have not historically had consistent revenue generating activities.
We identified the assessment of the identification of triggering events related to the recoverability of certain long-lived assets or asset groups as a critical audit matter. Challenging auditor judgment was required to assess the identification of triggering events for certain long-lived assets or asset groups that were not supported by existing revenue generating contracts or have not historically had consistent revenue generating activities. Specifically, this assessment included
55
the evaluation of subjective qualitative considerations, such as alternative customers and alternative uses for the asset or asset group, and the Partnership's intent for the asset or asset group.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Partnership's triggering event assessment. This included controls over the identification of long-lived asset groups that would be at greater risk for a triggering event and evaluation of the qualitative considerations in assessing the identification of a triggering event. We examined the Partnership's analysis of the long-lived assets and asset groups identified to be evaluated for a potential triggering event and assessed the factors considered in determining the identification of a triggering event. Specifically, we evaluated the Partnership's assessment of the factors considered, including alternative customers, alternative uses for the assets or asset group, and the Partnership's intent for the assets or asset group by evaluating internal and external documentation. Documentation evaluated included internal presentations, draft customer contracts, publicly available market data, and communications between the Partnership and potential customers.
We have served as the Partnership’s auditor since 2004.
/s/ KPMG LLP
San Antonio, Texas
February 22, 2024
56
Report of Independent Registered Public Accounting Firm
To the Board of Directors of NuStar GP, LLC and Unitholders of
NuStar Energy L.P.:
Opinion on 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, 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, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
December 31, 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, 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, 2023 and 2022, the related consolidated statements of income, comprehensive income, cash flows, and partners’ equity and mezzanine equity for each of the years in the three-year period ended December 31, 2023, and the related notes (collectively, the consolidated financial statements), and our report dated February 22, 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 22, 2024
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars, Except Unit Data)
| December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| Assets | |||||||||||
| Current assets: | |||||||||||
| Cash and cash equivalents | $ | 2,765 | $ | 14,489 | |||||||
| Accounts receivable, net | 135,787 | 149,971 | |||||||||
| Inventories | 18,623 | 15,397 | |||||||||
| Prepaid and other current assets | 29,927 | 24,067 | |||||||||
| Total current assets | 187,102 | 203,924 | |||||||||
| Property, plant and equipment, at cost | 5,789,927 | 5,733,685 | |||||||||
| Accumulated depreciation and amortization | (2,507,390) | (2,330,602) | |||||||||
| Property, plant and equipment, net | 3,282,537 | 3,403,083 | |||||||||
| Intangible assets, net | 476,063 | 513,696 | |||||||||
| Goodwill | 732,356 | 732,356 | |||||||||
| Other long-term assets, net | 218,334 | 120,627 | |||||||||
| Total assets | $ | 4,896,392 | $ | 4,973,686 | |||||||
| Liabilities, Mezzanine Equity and Partners’ Equity | |||||||||||
| Current liabilities: | |||||||||||
| Accounts payable | $ | 77,050 | $ | 67,765 | |||||||
| Current portion of finance leases | 4,951 | 4,416 | |||||||||
| Accrued interest payable | 39,975 | 37,607 | |||||||||
| Accrued liabilities | 88,062 | 76,072 | |||||||||
| Taxes other than income tax | 10,948 | 10,607 | |||||||||
| Total current liabilities | 220,986 | 196,467 | |||||||||
| Long-term debt, less current portion of finance leases | 3,410,338 | 3,293,415 | |||||||||
| Deferred income tax liability | 3,933 | 3,219 | |||||||||
| Other long-term liabilities | 214,854 | 131,299 | |||||||||
| Total liabilities | 3,850,111 | 3,624,400 | |||||||||
Commitments and contingencies (Note 14) | |||||||||||
Series D preferred limited partners (0 and 16,346,650 units outstanding as of December 31, 2023 and 2022, respectively) (Note 17) | — | 446,970 | |||||||||
Partners’ equity (Note 18): | |||||||||||
| Preferred limited partners: | |||||||||||
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, 2023 and 2022) | 371,476 | 371,476 | |||||||||
Series C (6,900,000 units outstanding as of December 31, 2023 and 2022) | 166,518 | 166,518 | |||||||||
Common limited partners (126,516,713 and 110,818,718 units outstanding as of December 31, 2023 and 2022, respectively) | 312,905 | 177,620 | |||||||||
| Accumulated other comprehensive loss | (22,925) | (31,605) | |||||||||
| Total partners’ equity | 1,046,281 | 902,316 | |||||||||
| Total liabilities, mezzanine equity and partners’ equity | $ | 4,896,392 | $ | 4,973,686 | |||||||
See Notes to Consolidated Financial Statements.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of Dollars, Except Unit and Per Unit Data)
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Revenues: | |||||||||||||||||
| Service revenues | $ | 1,155,567 | $ | 1,120,249 | $ | 1,157,410 | |||||||||||
| Product sales | 478,620 | 562,974 | 461,090 | ||||||||||||||
| Total revenues | 1,634,187 | 1,683,223 | 1,618,500 | ||||||||||||||
| Costs and expenses: | |||||||||||||||||
| Costs associated with service revenues: | |||||||||||||||||
| Operating expenses (excluding depreciation and amortization expense) | 371,689 | 364,989 | 388,078 | ||||||||||||||
| Depreciation and amortization expense | 250,982 | 251,878 | 266,588 | ||||||||||||||
| Total costs associated with service revenues | 622,671 | 616,867 | 654,666 | ||||||||||||||
| Costs associated with product sales | 407,793 | 486,947 | 417,413 | ||||||||||||||
| Goodwill impairment loss | — | — | 34,060 | ||||||||||||||
| Other impairment losses | — | 46,122 | 154,908 | ||||||||||||||
| General and administrative expenses (excluding depreciation and amortization expense) | 129,846 | 117,116 | 113,207 | ||||||||||||||
| Other depreciation and amortization expense | 4,728 | 7,358 | 7,792 | ||||||||||||||
| Total costs and expenses | 1,165,038 | 1,274,410 | 1,382,046 | ||||||||||||||
| Gain on sale of assets | 41,075 | — | — | ||||||||||||||
| Operating income | 510,224 | 408,813 | 236,454 | ||||||||||||||
| Interest expense, net | (241,364) | (209,009) | (213,985) | ||||||||||||||
| Other income, net | 10,215 | 26,182 | 19,644 | ||||||||||||||
| Income before income tax expense | 279,075 | 225,986 | 42,113 | ||||||||||||||
| Income tax expense | 5,412 | 3,239 | 3,888 | ||||||||||||||
| Net income | $ | 273,663 | $ | 222,747 | $ | 38,225 | |||||||||||
Basic and diluted net income (loss) per common unit (Note 19) | $ | 0.72 | $ | 0.36 | $ | (0.99) | |||||||||||
| Basic and diluted weighted-average common units outstanding | 116,851,373 | 110,341,206 | 109,585,635 | ||||||||||||||
See Notes to Consolidated Financial Statements.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Thousands of Dollars)
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Net income | $ | 273,663 | $ | 222,747 | $ | 38,225 | |||||||||||
Other comprehensive income (loss) (Note 18): | |||||||||||||||||
| Foreign currency translation adjustment | 728 | 41,823 | 601 | ||||||||||||||
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 | ||||||||||||||
| Reclassification of loss on cash flow hedges | 2,581 | 2,106 | 5,664 | ||||||||||||||
| Total other comprehensive income | 8,680 | 42,373 | 22,678 | ||||||||||||||
| Comprehensive income | $ | 282,343 | $ | 265,120 | $ | 60,903 | |||||||||||
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, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Cash flows from operating activities: | |||||||||||||||||
| Net income | $ | 273,663 | $ | 222,747 | $ | 38,225 | |||||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||||
| Depreciation and amortization expense | 255,710 | 259,236 | 274,380 | ||||||||||||||
| Amortization of unit-based compensation | 15,547 | 13,781 | 14,209 | ||||||||||||||
| Amortization of debt related items | 11,026 | 10,267 | 12,490 | ||||||||||||||
| Gain from sale or disposition of assets | (40,946) | (2,785) | (61) | ||||||||||||||
| Gain from insurance recoveries | — | (16,366) | (14,860) | ||||||||||||||
| Goodwill impairment loss | — | — | 34,060 | ||||||||||||||
| Other impairment losses | — | 46,122 | 154,908 | ||||||||||||||
Changes in current assets and current liabilities (Note 20) | 10,618 | 737 | (14,147) | ||||||||||||||
| Decrease in other long-term assets, net | 1,199 | 1,091 | 9,867 | ||||||||||||||
| Decrease in other long-term liabilities | (4,226) | (1,579) | (6,636) | ||||||||||||||
| Other, net | (8,322) | (5,702) | (957) | ||||||||||||||
| Net cash provided by operating activities | 514,269 | 527,549 | 501,478 | ||||||||||||||
| Cash flows from investing activities: | |||||||||||||||||
| Capital expenditures | (147,508) | (140,630) | (181,133) | ||||||||||||||
| Change in accounts payable related to capital expenditures | 8,969 | (12,786) | 1,264 | ||||||||||||||
| Proceeds from insurance recoveries | 12,395 | 9,777 | 9,372 | ||||||||||||||
| Proceeds from sale or disposition of assets | 102,904 | 59,274 | 246,475 | ||||||||||||||
| Net cash (used in) provided by investing activities | (23,240) | (84,365) | 75,978 | ||||||||||||||
| Cash flows from financing activities: | |||||||||||||||||
| Proceeds from long-term debt borrowings | 1,006,900 | 989,900 | 977,000 | ||||||||||||||
| Long-term debt repayments | (895,000) | (883,300) | (1,389,700) | ||||||||||||||
| Redemption/repurchase of Series D preferred units | (518,680) | (222,387) | — | ||||||||||||||
| Proceeds from issuance of common units, net of issuance costs | 221,843 | — | — | ||||||||||||||
| Distributions to preferred unitholders | (116,396) | (127,299) | (127,551) | ||||||||||||||
| Distributions to common unitholders | (183,444) | (176,413) | (175,263) | ||||||||||||||
| Payment of tax withholding for unit-based compensation | (5,694) | (6,012) | (3,384) | ||||||||||||||
| Other, net | (11,959) | (9,442) | (6,681) | ||||||||||||||
| Net cash used in financing activities | (502,430) | (434,953) | (725,579) | ||||||||||||||
| Effect of foreign exchange rate changes on cash | 40 | 707 | 136 | ||||||||||||||
| Net (decrease) increase in cash, cash equivalents and restricted cash | (11,361) | 8,938 | (147,987) | ||||||||||||||
| Cash, cash equivalents and restricted cash as of the beginning of the period | 23,377 | 14,439 | 162,426 | ||||||||||||||
| Cash, cash equivalents and restricted cash as of the end of the period | $ | 12,016 | $ | 23,377 | $ | 14,439 | |||||||||||
See Notes to Consolidated Financial Statements.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY AND MEZZANINE EQUITY
(Thousands of Dollars, Except Per Unit Data)
| Limited Partners | Mezzanine Equity | ||||||||||||||||||||||||||||||||||
| Preferred | Common | Accumulated Other Comprehensive Loss | Total Partners’ Equity (Note 18) | Series D Preferred Limited Partners (Note 17) | Total | ||||||||||||||||||||||||||||||
| Balance as of January 1, 2021 | $ | 756,301 | $ | 572,314 | $ | (96,656) | $ | 1,231,959 | $ | 599,542 | $ | 1,831,501 | |||||||||||||||||||||||
| Net income (loss) | 63,982 | (89,174) | — | (25,192) | 63,417 | 38,225 | |||||||||||||||||||||||||||||
| Other comprehensive income | — | — | 22,678 | 22,678 | — | 22,678 | |||||||||||||||||||||||||||||
| Distributions to partners: | |||||||||||||||||||||||||||||||||||
| Series A, B and C preferred | (63,982) | — | — | (63,982) | — | (63,982) | |||||||||||||||||||||||||||||
Common ($1.60 per unit) | — | (175,263) | — | (175,263) | — | (175,263) | |||||||||||||||||||||||||||||
| Series D preferred | — | — | — | — | (63,417) | (63,417) | |||||||||||||||||||||||||||||
| Unit-based compensation | — | 8,528 | — | 8,528 | — | 8,528 | |||||||||||||||||||||||||||||
| Series D Preferred Unit accretion | — | (16,903) | — | (16,903) | 16,903 | — | |||||||||||||||||||||||||||||
| Other | — | — | — | — | (6) | (6) | |||||||||||||||||||||||||||||
| Balance as of December 31, 2021 | 756,301 | 299,502 | (73,978) | 981,825 | 616,439 | 1,598,264 | |||||||||||||||||||||||||||||
| Net income | 66,526 | 95,158 | — | 161,684 | 61,063 | 222,747 | |||||||||||||||||||||||||||||
| Other comprehensive income | — | — | 42,373 | 42,373 | — | 42,373 | |||||||||||||||||||||||||||||
| Distributions to partners: | |||||||||||||||||||||||||||||||||||
| Series A, B and C preferred | (66,526) | — | — | (66,526) | — | (66,526) | |||||||||||||||||||||||||||||
Common ($1.60 per unit) | — | (176,413) | — | (176,413) | — | (176,413) | |||||||||||||||||||||||||||||
| Series D preferred | — | — | — | — | (61,063) | (61,063) | |||||||||||||||||||||||||||||
| Unit-based compensation | — | 12,302 | — | 12,302 | — | 12,302 | |||||||||||||||||||||||||||||
| Series D Preferred Unit accretion | — | (18,538) | — | (18,538) | 18,538 | — | |||||||||||||||||||||||||||||
| Series D Preferred Unit repurchase | — | (34,382) | — | (34,382) | (188,005) | (222,387) | |||||||||||||||||||||||||||||
| Other | — | (9) | — | (9) | (2) | (11) | |||||||||||||||||||||||||||||
| Balance as of December 31, 2022 | 756,301 | 177,620 | (31,605) | 902,316 | 446,970 | 1,349,286 | |||||||||||||||||||||||||||||
| 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, 2023, 2022 and 2021
1. ORGANIZATION AND OPERATIONS
Organization
NuStar Energy L.P. (NuStar Energy) is a publicly traded Delaware limited partnership. Unless otherwise indicated, the terms “NuStar Energy,” “NS,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to NuStar Energy L.P., to one or more of our consolidated subsidiaries or to all of them taken as a whole. Our business is managed under the direction of the board of directors of NuStar GP, 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. Our assets included 9,490 miles of pipeline with aggregate storage capacity of 13.0 million barrels. Our Central West System includes 2,915 miles of refined product pipelines and 2,070 miles of crude oil pipelines, as well as 5.6 million barrels of crude oil storage capacity, while our Central East System includes 2,495 miles of refined product pipelines, consisting of the East and North pipelines, and an approximately 2,000-mile ammonia pipeline (the Ammonia Pipeline). The East and North pipelines have aggregate storage capacity of 7.4 million barrels. We charge tariffs on a per barrel basis for transporting refined products, crude oil and other feedstocks in our refined product and crude oil pipelines and on a per ton basis for transporting anhydrous ammonia in the Ammonia Pipeline.
Storage. We own terminal and storage facilities in the United States and Mexico, with aggregate storage capacity of 36.4 million barrels. Our terminal and storage facilities provide storage, handling and other services on a fee basis for refined products, crude oil, specialty chemicals, renewable fuels and other liquids.
Fuels Marketing. The fuels marketing segment primarily includes our bunkering operations in the Gulf Coast, as well as certain of our blending operations associated with our Central East System.
Recent Developments
Merger Agreement. On January 22, 2024, we entered into a merger agreement with Sunoco LP and its affiliates, in an all-equity transaction, which will result in NuStar Energy surviving the merger as a subsidiary of Sunoco LP. At closing of the merger, each NuStar Energy common unit issued and outstanding immediately prior to closing will be converted into the right to receive 0.400 of a common unit of Sunoco and, if applicable, cash in lieu of fractional units. See Note 25 for further information on the merger.
Redemptions of Series D Preferred Units. In the second and third quarters of 2023, we redeemed all of our outstanding Series D Preferred Units, as defined in Note 17, for an aggregate net redemption price of $518.7 million. See Note 17 for additional information on these redemptions.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Issuance of Common Units. On August 11, 2023, we issued 14,950,000 common units representing limited partner interests at a price of $15.35 per unit for net proceeds of approximately $222.0 million. See Note 18 for more information.
Debt Amendments. On June 30, 2023, we amended our Revolving Credit Agreement, as defined in Note 12, primarily to extend the maturity date from April 27, 2025 to January 27, 2027. On June 29, 2023, we amended our Receivables Financing Agreement, as defined in Note 12, to extend the scheduled termination date from January 31, 2025 to July 1, 2026. See Note 12 for more information.
Sale-Leaseback Transaction. On March 21, 2023, we consummated the Sale-Leaseback Transaction, as defined in Note 4, of our Corporate Headquarters, also as defined in Note 4, for approximately $103.0 million and recognized a gain of $41.1 million. See Note 4 for more information.
Other Event
Selby Terminal Fire. On October 15, 2019, a fire at our terminal facility in Selby, California destroyed two storage tanks and temporarily shut down the terminal. We received insurance proceeds of $12.4 million, $11.1 million and $28.5 million for the years ended December 31, 2023, 2022 and 2021, respectively. The amount received in 2023 represented the remaining proceeds from the settlement of the 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, 2023 and 2022, we have restricted cash representing legally restricted funds that are unavailable for general use totaling $9.3 million and $8.9 million, respectively, which is included in “” on the consolidated balance sheets.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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, 2023 and 2022, our reporting units to which goodwill has been allocated consisted of the following:
•crude oil pipelines;
•refined product pipelines; and
•terminals, excluding our refinery crude storage tanks.
See Notes 4 and 10 for a discussion of the balances of and changes in the carrying amount of goodwill.
We assess goodwill for impairment annually on October 1, or more frequently if events or changes in circumstances indicate it might be impaired. We have the option to first assess qualitative factors to determine whether it is necessary to perform a quantitative goodwill impairment test. We elected to bypass the qualitative assessment for all reporting units as of October 1, 2023 and October 1, 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
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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.
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, 2023 are recoverable.
Income Taxes
We are a limited partnership and generally are not subject to federal or state income taxes. Accordingly, our taxable income or loss, which may vary substantially from income or loss reported for financial reporting purposes, is generally included in the federal and state income tax returns of our partners. For transfers of publicly held common units subsequent to our initial public offering, we have made an election permitted by Section 754 of the Internal Revenue Code (the Code) to adjust the common unit purchaser’s tax basis in our underlying assets to reflect the purchase price of the units. This results in an allocation of taxable income and expenses to the purchaser of the common units, including depreciation deductions and gains and losses on sales of assets, based upon the new unitholder’s purchase price for the common units.
We conduct certain of our operations through taxable wholly owned corporate subsidiaries. We account for income taxes related to our taxable subsidiaries using the asset and liability method. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. We measure deferred taxes using enacted tax rates expected to apply to taxable income in the year those temporary differences are expected to be recovered or settled.
We recognize a tax position if it is more likely than not that the tax position will be sustained, based on the technical merits of the position, upon examination. We record uncertain tax positions in the financial statements at the largest amount of benefit that is more likely than not to be realized. We had no unrecognized tax benefits as of December 31, 2023 and 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 2018 through 2022, according to standard statute of limitations.
Asset Retirement Obligations
We record a liability for asset retirement obligations at the fair value of the estimated costs to retire a tangible long-lived asset at the time we incur that liability, which is generally when the asset is purchased, constructed or leased, when we have a legal obligation to incur costs to retire the asset and when a reasonable estimate of the fair value of the obligation can be made. If a reasonable estimate cannot be made at the time the liability is incurred, we record the liability when sufficient information is available to estimate the fair value.
We have asset retirement obligations with respect to certain of our assets due to various legal obligations to clean and/or dispose of those assets at the time they are retired. However, these assets can be used for an extended and indeterminate period of time as long as they are properly maintained and/or upgraded. It is our practice and current intent to maintain our assets and continue making improvements to those assets based on technological advances. As a result, we believe that our assets have indeterminate lives for purposes of estimating asset retirement obligations because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of any asset, we estimate the costs of performing the retirement activities and record a liability for the fair value of these costs.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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, 2023 and 2022.
Environmental Remediation Costs
Environmental remediation costs are expensed, and an associated accrual established when site restoration and environmental remediation and cleanup obligations are either known or considered probable and can be reasonably estimated. These environmental obligations are based on estimates of probable undiscounted future costs using currently available technology and applying current regulations, as well as our own internal environmental policies. The environmental liabilities have not been reduced by possible recoveries from third parties. Environmental costs include initial site surveys, costs for remediation and restoration and ongoing monitoring costs, as well as fines, damages and other costs, when applicable and estimable. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. 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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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The performance obligation for our storage segment consists of multiple activities necessary to receive, store and deliver our customers’ products. We typically satisfy this performance obligation over time as the product volume is delivered in or out of the tanks (for throughput terminal revenues) or with the passage of time (for storage terminal revenues).
Product sales contracts generally include a single performance obligation to deliver specified volumes of a commodity, which we satisfy at a point in time, when the product is delivered and the customer obtains control of the commodity.
Optional services described in our contracts do not provide a material right to the customer, and are not considered a separate performance obligation in the contract. If and when a customer elects an optional service, and the terms of the contract are otherwise met, those services become part of the existing performance obligation.
Transaction Price. For uninterruptible services, we determine the transaction price at contract inception based on the guaranteed minimum amount of revenue over the term of the contract. For interruptible services and optional services, we determine the transaction price based on our right to invoice the customer for the value of services provided to the customer for the applicable period.
In certain instances, our customers reimburse us for capital projects, in arrangements referred to as contributions in aid of construction, or CIAC. Typically, in these instances, we receive upfront payments for future services, which are included in the transaction price of the underlying service contract.
We collect taxes on certain revenue transactions to be remitted to governmental authorities, which may include sales, use, value-added and some excise taxes. These taxes are not included in the transaction price and are, therefore, excluded from revenues.
Allocation of Transaction Price. We allocate the transaction price to the single performance obligation that exists in the vast majority of our contracts with customers. For the few contracts that have a second performance obligation, such as those that include an incentive pricing structure, we calculate an average rate based on the estimated total volumes to be delivered over the term of the contract and the resulting estimated total revenue to be billed using the applicable rates in the contract. We allocate the transaction price to the two performance obligations by applying the average rate to product volumes as they are delivered to the customer over the term of the contract. Determining the timing and amount of volumes subject to these incentive pricing contracts requires judgment that can impact the amount of revenue allocated to the two separate performance obligations. We base our estimates on our analysis of expected future production information available from our customers or other sources, which we update at least quarterly.
Some of our MVC contracts include provisions that allow the customer to apply deficiency payments to future service periods (the carryforward period). In those instances, we have not satisfied our performance obligation as we still have the obligation to perform those services, subject to contractual and/or capacity constraints, at the customer’s request. At least quarterly, we assess the customer’s ability to utilize any deficiency payments during the carryforward period. If we receive a deficiency payment from a customer that we expect the 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.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Basic and Diluted Net Income (Loss) Per Common Unit
Basic and diluted net income (loss) per common unit is determined pursuant to the two-class method. Under this method, all earnings are allocated to our limited partners and participating securities based on their respective rights to receive distributions earned during the period. Participating securities include restricted units awarded under our long-term incentive plans and, from June 15, 2023 to their redemption on September 12, 2023, the Series D Preferred Units. We compute basic net income (loss) per common unit by dividing net income (loss) attributable to our common limited partners by the weighted-average number of common units outstanding during the period. We compute diluted net income (loss) per common unit by dividing net income (loss) attributable to our common limited partners by the sum of (i) the weighted-average number of common units outstanding during the period and (ii) the effect of dilutive potential common units outstanding during the period. Dilutive potential common units include contingently issuable performance units awarded and the Series D Preferred Units, prior to their redemption and/or repurchase. See Note 22 for additional information on our performance units, Note 17 for additional information on the Series D Preferred Units and Note 19 for the calculation of basic and diluted net income (loss) per common unit.
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 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. See Note 21 for further discussion of our pension and other postretirement benefit obligations.
Unit-based Compensation
Unit-based compensation for our long-term incentive plans is recorded in 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. 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
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
of the gain or loss on sale. Gains and losses on foreign currency transactions are included in “Other income, net” in the consolidated statements of income.
Reclassifications
We have reclassified certain previously reported amounts in the consolidated financial statements and notes to conform to current-period presentation.
3. NEW ACCOUNTING PRONOUNCEMENTS
Improvements to Income Tax Disclosures
In December 2023, the Financial Accounting Standards Board (FASB) issued guidance intended to enhance the transparency and decision usefulness of income tax disclosures, primarily through changes to the rate reconciliation and income taxes paid information. The amendments are effective for annual periods beginning after December 15, 2024, and early adoption is permitted. The amendments should be applied prospectively; however, retrospective application is permitted. We plan to adopt the amended guidance on January 1, 2025, and are currently evaluating our method of adoption and the impact of this amended guidance on our disclosures.
Improvements to Reportable Segment Disclosures
In November 2023, the FASB issued guidance intended to improve reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. Among other changes, the amendments will require disclosure of significant segment expenses that are regularly provided to the chief operating decision maker and included within each reported measure of segment profit or loss. The amendments are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, and should be applied on a retrospective basis. Early adoption is permitted. We plan to adopt the annual and interim disclosure requirements on January 1, 2024 and January 1, 2025, respectively, and are currently evaluating the impact of this amended guidance on our disclosures.
4. DISPOSITIONS AND IMPAIRMENTS
Sale-Leaseback Transaction
On March 21, 2023, we sold our corporate headquarters facility and approximately 24 acres of underlying land located in San Antonio, Texas (the Corporate Headquarters) for an aggregate cash sales price of $103.0 million and immediately entered into an operating lease agreement (the HQ Lease Agreement) to lease back the Corporate Headquarters for an initial term of 20 years, with two renewal options of ten years each (the Sale-Leaseback Transaction). Upon closing of the sale in the first quarter of 2023, the Sale-Leaseback Transaction qualified as a completed sale, and we recognized a gain of $41.1 million, which is presented in “Gain on sale of assets” on the consolidated statements of income. We entered into the Sale-Leaseback Transaction in order to monetize the Corporate Headquarters, and used the proceeds to repay outstanding borrowings under our Revolving Credit Agreement in order to position ourselves to redeem the Series D Preferred Units.
Point Tupper Terminal Disposition
On April 29, 2022, we sold the equity interests in our wholly owned subsidiaries that owned our Point Tupper terminal facility in Nova Scotia, Canada (the Point Tupper Terminal Operations) to EverWind Fuels for $60.0 million (the Point Tupper Terminal Disposition). The terminal facility had a storage capacity of 7.8 million barrels and was included in the storage segment. We utilized the sales proceeds to repay outstanding borrowings under our Revolving Credit Agreement and improve our debt metrics.
During the first quarter of 2022, we determined that the Point Tupper Terminal Operations met the criteria to be classified as held for sale. We compared the carrying value of the Point Tupper Terminal Operations, which included $42.2 million in cumulative foreign currency translation losses accumulated since our acquisition of the Point Tupper terminal facility in 2005, to its fair value less costs to sell, and we recognized a pre-tax impairment loss of $46.1 million in the first quarter of 2022, which is presented in “Other impairment losses” on the consolidated statements of income. We believe that the sales price of $60.0 million provided a reasonable indication of the fair value of the Point Tupper Terminal Operations as it represented an exit price in an orderly transaction between market participants. The sales price was a quoted price for identical assets and liabilities in a market that was not active and, thus, our fair value estimate fell within Level 2 of the fair value hierarchy. Upon closing in the second quarter of 2022, we released $39.6 million of foreign currency translation losses from AOCI and finalized our sales price, resulting in a gain of $1.6 million, which is presented in “” on the consolidated statements of income.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Eastern U.S. Terminals Disposition
On August 1, 2021, we entered into an agreement (the Purchase Agreement) to sell nine U.S. terminal and storage facilities, including all our North East Terminals and one terminal in Florida (the Eastern U.S. Terminal Operations) to Sunoco LP for $250.0 million (the Eastern U.S. Terminals Disposition). The Eastern U.S. Terminal Operations included terminals in the following locations; Jacksonville, Florida; Andrews Air Force Base, Maryland; Baltimore, Maryland; Piney Point, Maryland; Virginia Beach, Virginia; Paulsboro, New Jersey; and Blue Island, Illinois, as well as both Linden, New Jersey terminals. The Eastern U.S. Terminal Operations had an aggregate storage capacity of 14.8 million barrels and were included in the storage segment. We closed the sale on October 8, 2021 and used the proceeds from the sale to reduce debt and improve our debt metrics.
The Eastern U.S. Terminal Operations met the criteria to be classified as held for sale upon our entrance into the Purchase Agreement during the third quarter of 2021. At that time, we allocated goodwill of $34.1 million to the Eastern U.S. Terminal Operations based on its fair value relative to the terminals reporting unit, with which it had been fully integrated. We tested the allocated goodwill for impairment by comparing the fair value of the Eastern U.S. Terminal Operations to its carrying value. The results of our goodwill impairment test indicated that the carrying value of the Eastern U.S. Terminal Operations exceeded its fair value, and we recognized a related goodwill impairment charge of $34.1 million in the third quarter of 2021 to reduce the allocated goodwill to $0. The goodwill impairment loss is reported in “Goodwill impairment loss” on the consolidated statements of income. We believe that the sales price of $250.0 million provided a reasonable indication of the fair value of the Eastern U.S. Terminal Operations as it represented an exit price in an orderly transaction between market participants. The sales price was a quoted price for identical assets and liabilities in a market that was not active and, thus, our fair value estimate fell within Level 2 of the fair value hierarchy.
We compared the remaining carrying value of the Eastern U.S. Terminal Operations, after its goodwill impairment, to its fair value less costs to sell. We recognized an asset impairment loss of $95.7 million in the third quarter of 2021, which is reported in “Other impairment losses” on the consolidated statements of income. The asset impairment loss included $23.9 million related to intangible assets representing customer contracts and relationships.
We determined the assets included in the Point Tupper Terminal Disposition and the Eastern U.S. Terminals Disposition were no longer synergistic with our core assets, and these dispositions did not qualify, either individually or in the aggregate, for reporting as discontinued operations, as the sales did not represent strategic shifts that would have a major effect on our operations or financial results.
Houston Pipeline Impairment
In the third quarter of 2021, we recorded a long-lived asset impairment charge of $59.2 million within our pipeline segment related to our refined product pipeline extending from Mt. Belvieu, Texas to Corpus Christi, Texas (the Houston Pipeline). During the third quarter of 2021, we identified an indication of impairment related to the southern section of the Houston Pipeline, specifically that its physical condition would require significant investment in order to pursue commercial opportunities. Consequently, we separated the pipeline into two distinct assets: the northern and southern sections. Our estimate of the undiscounted cash flows associated with the southern section indicated it was not recoverable. Due to the factors described above, we determined the carrying value of the southern section exceeded its fair value, and reduced its carrying value to $0. We recorded the asset impairment charge in “” on the consolidated statements of income. We determined that the northern portion of the pipeline was not impaired.
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5. REVENUE FROM CONTRACTS WITH CUSTOMERS
Contract Assets and Contract Liabilities
The following table provides information about contract assets and contract liabilities from contracts with customers:
| 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) | |||||||||||||||||||||||
Contract assets relate to performance obligations satisfied in advance of scheduled billings. Current contract assets are included in “Prepaid and other current assets” and noncurrent contract assets are included in “Other long-term assets, net” on the consolidated balance sheets. Contract liabilities relate to payments received in advance of satisfying performance obligations under a contract, which primarily result from contracts with an incentive pricing structure, CIAC payments and contracts with MVCs. The current portion of contract liabilities is included in “Accrued liabilities” and the noncurrent portion of contract liabilities is included in “Other long-term liabilities” on the consolidated balance sheets.
Remaining Performance Obligations
The following table presents our estimated revenue from contracts with customers for remaining performance obligations that has not yet been recognized, representing our contractually committed revenue as of December 31, 2023:
| Remaining Performance Obligations | |||||
| (Thousands of Dollars) | |||||
| 2024 | $ | 373,630 | |||
| 2025 | 242,776 | ||||
| 2026 | 173,095 | ||||
| 2027 | 82,500 | ||||
| 2028 | 45,412 | ||||
| Thereafter | 82,143 | ||||
| Total | $ | 999,556 | |||
Our contractually committed revenue, for purposes of the tabular presentation above, is generally limited to customer contracts that have fixed pricing and fixed volume terms and conditions, including contracts with MVC payment obligations.
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Disaggregation of Revenues
The following table disaggregates our revenues:
| Year Ended December 31, | |||||||||||||||||
| 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 | |||||||||||
6. ALLOWANCE FOR CREDIT LOSSES
As of and for the years ended December 31, 2023, 2022 and 2021, balances and activity related to our allowance for credit losses were immaterial.
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 | |||||||
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.
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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 | |||||||||||||||||||
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.
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 | $ | (282,563) | |||||||||||||||||||||
Intangible assets are recorded at fair value as of the date acquired. All our intangible assets are amortized on a straight-line basis. Amortization expense for intangible assets was $37.6 million, $44.1 million and $48.5 million for the years ended December 31, 2023, 2022 and 2021, respectively. The estimated aggregate amortization expense is $38.0 million for each of the years 2024 through 2026 and $35.0 million for 2027 and 2028.
10. GOODWILL
As of December 31, 2023, December 31, 2022 and January 1, 2022, carrying amounts of goodwill by segment were as follows:
| Pipeline | Storage | Total | |||||||||||||||
| (Thousands of Dollars) | |||||||||||||||||
| Goodwill | $ | 704,231 | $ | 253,125 | $ | 957,356 | |||||||||||
| Accumulated impairment loss | (225,000) | — | (225,000) | ||||||||||||||
| Net goodwill | $ | 479,231 | $ | 253,125 | $ | 732,356 | |||||||||||
We had no activity for the years ended December 31, 2023 or 2022.
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11. ACCRUED LIABILITIES
Accrued liabilities consisted of the following:
| December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| (Thousands of Dollars) | |||||||||||
| Employee wages and benefit costs | $ | 41,290 | $ | 40,249 | |||||||
| Revenue contract liabilities | 27,131 | 17,647 | |||||||||
| Operating lease liabilities | 6,188 | 5,541 | |||||||||
| Environmental costs | 4,059 | 3,122 | |||||||||
| Other | 9,394 | 9,513 | |||||||||
| Accrued liabilities | $ | 88,062 | $ | 76,072 | |||||||
12. DEBT
Our debt consisted of the following:
| December 31, | |||||||||||||||||||||||
| Maturity | 2023 | 2022 | |||||||||||||||||||||
| (Thousands of Dollars) | |||||||||||||||||||||||
| Current portion of finance leases | n/a | $ | 4,951 | $ | 4,416 | ||||||||||||||||||
5.75% senior notes | October 1, 2025 | 600,000 | 600,000 | ||||||||||||||||||||
6.00% senior notes | June 1, 2026 | 500,000 | 500,000 | ||||||||||||||||||||
| Receivables Financing Agreement | July 1, 2026 | 69,800 | 80,900 | ||||||||||||||||||||
| Revolving Credit Agreement | January 27, 2027 | 343,000 | 220,000 | ||||||||||||||||||||
5.625% senior notes | April 28, 2027 | 550,000 | 550,000 | ||||||||||||||||||||
6.375% senior notes | October 1, 2030 | 600,000 | 600,000 | ||||||||||||||||||||
| GoZone Bonds | 2038 | thru | 2041 | 322,140 | 322,140 | ||||||||||||||||||
| Subordinated Notes | January 15, 2043 | 402,500 | 402,500 | ||||||||||||||||||||
| Unamortized debt issuance costs | n/a | (27,809) | (33,251) | ||||||||||||||||||||
| Long-term debt, excluding finance leases | 3,359,631 | 3,242,289 | |||||||||||||||||||||
Long-term portion of finance leases (Note 15) | 50,707 | 51,126 | |||||||||||||||||||||
| Long-term debt, less current portion of finance leases | $ | 3,410,338 | $ | 3,293,415 | |||||||||||||||||||
The long-term debt repayments (excluding finance leases) as of December 31, 2023 are due as follows:
| Long-Term Debt Repayments | |||||
| (Thousands of Dollars) | |||||
| 2024 | $ | — | |||
| 2025 | 600,000 | ||||
| 2026 | 569,800 | ||||
| 2027 | 893,000 | ||||
| 2028 | — | ||||
| Thereafter | 1,324,640 | ||||
| Total repayments | 3,387,440 | ||||
| Unamortized debt issuance costs | (27,809) | ||||
| Long-term debt, excluding finance leases | $ | 3,359,631 | |||
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Interest payments related to debt obligations (excluding finance leases) totaled $226.9 million, $197.3 million and $220.0 million for the years ended December 31, 2023, 2022 and 2021, respectively. We amortized $8.4 million, $8.2 million and $7.9 million of debt issuance costs for the years ended December 31, 2023, 2022 and 2021, respectively.
Revolving Credit Agreement
As of December 31, 2023, NuStar Logistics’ $1.0 billion unsecured revolving credit agreement (as amended, the Revolving Credit Agreement) had $652.4 million available for borrowing and $343.0 million borrowings outstanding. Letters of credit issued under our Revolving Credit Agreement totaled $4.6 million as of December 31, 2023. Letters of credit limit the amount we can borrow under our Revolving Credit Agreement. Obligations under our Revolving Credit Agreement are guaranteed by NuStar Energy and NuPOP.
Our Revolving Credit Agreement is subject to maximum consolidated debt coverage ratio and minimum consolidated interest coverage ratio requirements, which may limit the amount we can borrow to an amount less than the total amount available for borrowing. For the rolling period ending December 31, 2023, the Consolidated Debt Coverage Ratio (as defined in the Revolving Credit Agreement) may not exceed 5.00-to-1.00 and the Consolidated Interest Coverage Ratio (as defined in the Revolving Credit Agreement), must not be less than 1.75-to-1.00. As of December 31, 2023, we believe that we are in compliance with these financial covenants. Our Revolving Credit Agreement also contains customary restrictive covenants, such as limitations on indebtedness, liens, mergers, asset transfers and certain investing activities.
Our Revolving Credit Agreement bears interest, at our option, based on an alternative base rate or a secured overnight financing rate (SOFR) based rate. The interest rate on our Revolving Credit Agreement is subject to adjustment if our debt rating is downgraded or upgraded by certain credit rating agencies. The interest rate on our Revolving Credit Agreement and certain fees under the Receivables Financing Agreement are the only debt arrangements that are subject to adjustment if our debt rating is downgraded or upgraded by certain credit rating agencies. As of December 31, 2023, our weighted-average interest rate under our Revolving Credit Agreement was 8.0%. During the year ended December 31, 2023, the weighted-average interest rate related to borrowings under our Revolving Credit Agreement was 7.8%.
On June 30, 2023, we amended our Revolving Credit Agreement, primarily to extend the maturity date from April 27, 2025 to January 27, 2027. The amendment also includes a requirement that we must demonstrate and certify, prior to using any borrowings under our Revolving Credit Agreement to redeem certain unsecured indebtedness or prior to their redemption/repurchase, the Series D Preferred Units, that the sum of our Revolving Credit Agreement availability and unrestricted cash balance is no less than $150.0 million on a pro forma basis both before and immediately after giving effect to the borrowing and the redemption. On January 28, 2022, we amended and restated our Revolving Credit Agreement to, among other items:
(i) increase the maximum amount of letters of credit capable of being issued from $400.0 million to $500.0 million; (ii) replace London Interbank Offering Rate (LIBOR) benchmark provisions with customary SOFR benchmark provisions; (iii) remove the 0.50x increase permitted in our Consolidated Debt Coverage Ratio for certain rolling periods in which an acquisition for aggregate net consideration of at least $50.0 million occurs; and (iv) add baskets and exceptions to certain negative covenants.
Notes
NuStar Logistics Senior Notes. On November 1, 2021, we repaid our $250.0 million of 4.75% senior notes due February 1, 2022 with proceeds from the Eastern U.S. Terminals Disposition. We repaid our $300.0 million of 6.75% senior notes due February 1, 2021 with borrowings under our Revolving Credit Agreement.
Interest is payable semi-annually in arrears for the $600.0 million of 5.75% senior notes, $500.0 million of 6.0% senior notes, $550.0 million of 5.625% senior notes and $600.0 million of 6.375% senior notes (collectively, the NuStar Logistics Senior Notes).
The NuStar Logistics Senior Notes do not have sinking fund requirements. These notes rank equally with existing senior unsecured indebtedness and senior to existing subordinated indebtedness of NuStar Logistics and contain restrictions on NuStar Logistics’ ability to incur secured indebtedness unless the same security is also provided for the benefit of holders of the NuStar Logistics Senior Notes. In addition, the NuStar Logistics Senior Notes limit the ability of NuStar Logistics and its subsidiaries to, among other things, incur indebtedness secured by certain liens, engage in certain sale-leaseback transactions and engage in certain consolidations, mergers or asset sales. At the option of NuStar Logistics, the NuStar Logistics Senior Notes may be redeemed in whole or in part at any time at a redemption price, plus accrued and unpaid interest to the redemption date. If we undergo a change of control that is followed by a ratings decline that occurs within 60 days of the change of control, each holder of the applicable senior notes may require us to repurchase all or a portion of its notes at a price equal to 101% of the principal amount of the notes repurchased, plus any accrued and unpaid interest to the date of repurchase. The NuStar Logistics Senior Notes are fully and unconditionally guaranteed by NuStar Energy and NuPOP.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
NuStar Logistics Subordinated Notes. NuStar Logistics’ $402.5 million of fixed-to-floating rate subordinated notes are due January 15, 2043 (the Subordinated Notes). The Subordinated Notes are fully and unconditionally guaranteed on an unsecured and subordinated basis by NuStar Energy and NuPOP. Effective January 15, 2018, the interest rate on the Subordinated Notes converted from a fixed rate to an annual rate equal to the sum of three-month LIBOR for the related quarterly interest period plus 6.734%, payable quarterly, unless payment is deferred in accordance with the terms of the notes. Effective with the quarterly interest periods starting after June 30, 2023, three-month LIBOR was replaced with three-month CME term SOFR plus the applicable tenor spread adjustment of 0.26161%. NuStar Logistics may elect to defer interest payments on the Subordinated Notes on one or more occasions for up to consecutive years. Deferred interest will accumulate additional interest at a rate equal to the interest rate then applicable to the Subordinated Notes until paid. If NuStar Logistics elects to defer interest payments, NuStar Energy cannot declare or make cash distributions with respect to, or redeem, purchase or make a liquidation payment with respect to, its equity securities during the period that interest payments are deferred. As of December 31, 2023, the interest rate was 12.4% on the Subordinated Notes.
The Subordinated Notes do not have sinking fund requirements and are subordinated to existing senior unsecured indebtedness of NuStar Logistics and NuPOP. The Subordinated Notes do not contain restrictions on NuStar Logistics’ ability to incur additional indebtedness, including debt that ranks senior in priority of payment to the notes. In addition, the Subordinated Notes do not limit NuStar Logistics’ ability to incur indebtedness secured by liens or to engage in certain sale-leaseback transactions. Effective January 15, 2018, we may redeem the Subordinated Notes in whole or in part at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest to the redemption date.
Gulf Opportunity Zone Revenue Bonds
In 2008, 2010 and 2011, the Parish of St. James, Louisiana issued Revenue Bonds Series 2008, Series 2010, Series 2010A, Series 2010B and Series 2011 associated with our St. James terminal expansions pursuant to the Gulf Opportunity Zone Act of 2005 for an aggregate $365.4 million (collectively, the GoZone Bonds). Following the issuances, the proceeds were deposited with a trustee and were disbursed to us upon our request for reimbursement of expenditures related to our St. James terminal. On March 4, 2020, NuStar Logistics repaid $43.3 million of GoZone Bonds with unused funds, which had been held in trust. Also in 2020, we completed the reoffering and conversion of the GoZone Bonds which, among other things, converted the interest rate from a weekly rate to a long-term rate.
As reflected in the table below, the holders of the Series 2008, Series 2010B and Series 2011 GoZone Bonds are required to tender their bonds at the applicable mandatory purchase date in exchange for 100% of the principal plus accrued and unpaid interest, after which these bonds are expected to be remarketed with a new interest rate established. Each of the Series 2010 and Series 2010A GoZone Bonds is subject to redemption on or after June 1, 2030 by the Parish of St. James, at our option, in whole or in part, at a redemption price of 100% of the principal amount to be redeemed plus accrued and unpaid interest. Interest on the GoZone Bonds is payable semi-annually on June 1 and December 1 of each year.
The following table summarizes the GoZone Bonds outstanding as of December 31, 2023:
| Series | Date Issued | Amount Outstanding | Interest Rate | Mandatory Purchase Date | Optional Redemption Date | Maturity Date | ||||||||||||||||||||||||||||||||
| (Thousands of Dollars) | ||||||||||||||||||||||||||||||||||||||
| Series 2008 | June 26, 2008 | $ | 55,440 | 6.10 | % | June 1, 2030 | n/a | June 1, 2038 | ||||||||||||||||||||||||||||||
| Series 2010 | July 15, 2010 | 100,000 | 6.35 | % | n/a | June 1, 2030 | July 1, 2040 | |||||||||||||||||||||||||||||||
| Series 2010A | October 7, 2010 | 43,300 | 6.35 | % | n/a | June 1, 2030 | October 1, 2040 | |||||||||||||||||||||||||||||||
| Series 2010B | December 29, 2010 | 48,400 | 6.10 | % | June 1, 2030 | n/a | December 1, 2040 | |||||||||||||||||||||||||||||||
| Series 2011 | August 9, 2011 | 75,000 | 5.85 | % | June 1, 2025 | n/a | August 1, 2041 | |||||||||||||||||||||||||||||||
| Total | $ | 322,140 | ||||||||||||||||||||||||||||||||||||
NuStar Logistics’ agreements with the Parish of St. James related to the GoZone Bonds contain: (i) customary restrictive covenants that limit the ability of NuStar Logistics and its subsidiaries, to, among other things, create liens, enter into certain sale-leaseback transactions, and engage in certain consolidations, mergers or asset sales; and (ii) a repurchase provision which provides that if we undergo a change of control that is followed by a ratings decline that occurs within 60 days of the change of control, then each holder may require the trustee, with funds provided by NuStar Logistics, to repurchase all or a portion of that holder’s GoZone Bonds at a price equal to 101% of the aggregate principal amount repurchased, plus any accrued and unpaid interest.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Receivables Financing Agreement
NuStar Energy and NuStar Finance LLC (NuStar Finance), a special purpose entity and wholly owned subsidiary of NuStar Energy, are parties to a $100.0 million receivables financing agreement with a third-party lender (as amended, the Receivables Financing Agreement) and agreements with certain of NuStar Energy’s wholly owned subsidiaries (together with the Receivables Financing Agreement, the Securitization Program). Under the Securitization Program, certain of NuStar Energy’s wholly owned subsidiaries (collectively, the Originators), sell their accounts receivable to NuStar Finance on an ongoing basis, and NuStar Finance provides the newly acquired accounts receivable as collateral for its revolving borrowings under the Receivables Financing Agreement. NuStar Energy provides a performance guarantee in connection with the Securitization Program. The amount available for borrowing is based on the availability of eligible receivables and other customary factors and conditions. The Securitization Program contains various customary affirmative and negative covenants and default, indemnification and termination provisions, and the Receivables Financing Agreement provides for acceleration of amounts owed upon the occurrence of certain specified events. NuStar Finance’s sole activity consists of purchasing such receivables and providing them as collateral under the Securitization Program. NuStar Finance is a separate legal entity and the assets of NuStar Finance, including these accounts receivable, are not available to satisfy the claims of creditors of NuStar Energy, the Originators or their affiliates.
On 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.
Borrowings under the Receivables Financing Agreement bear interest, at NuStar Finance’s option, at a base rate or a SOFR rate, each as defined in the Receivables Financing Agreement. As of December 31, 2023 and 2022, accounts receivable totaling $121.0 million and $121.5 million, respectively, were included in the Securitization Program. As of December 31, 2023, our interest rate under the Securitization Program was 7.0%. The weighted-average interest rate related to borrowings under the Securitization Program during the year ended December 31, 2023 was 6.7%.
13. HEALTH, SAFETY AND ENVIRONMENTAL MATTERS
Our operations are subject to extensive international, federal, state and local environmental laws and regulations, in the U.S. and in Mexico, including those relating to the discharge of materials into the environment, waste management, remediation, the characteristics and composition of fuels, climate change and greenhouse gases. Our operations are also subject to extensive health, safety and security laws and regulations, including those relating to worker and pipeline safety, pipeline and storage tank integrity and operations security. The principal environmental, health, safety and security risks associated with our operations relate to unauthorized emissions into the air, releases into soil, surface water or groundwater, personal injury and property damage. We have adopted policies, practices, systems and procedures designed to comply with the laws and regulations, and to help minimize and mitigate these risks, limit the liability that could result from such events, prevent material environmental or other damage, ensure the safety of our employees and the public and secure our pipelines, terminals and operations.
Compliance with environmental, health, safety and security laws, regulations and related permits increases our capital expenditures and operating expenses, and violation of these laws, regulations or permits could result in significant civil and criminal liabilities, injunctions or other penalties. Future governmental action and regulatory initiatives could result in more restrictive laws and regulations, which could increase required capital expenditures and operating expenses. The risk of additional compliance expenditures, expenses and liabilities are inherent to government-regulated industries, including midstream energy. As a result, there can be no assurances that significant expenditures, expenses and liabilities will not be incurred in the future.
Most of our pipelines are subject to federal regulation by one or more of the following governmental agencies: the Federal Energy Regulatory Commission (the FERC), the Surface Transportation Board (the STB), the Department of Transportation (the DOT), the Environmental Protection Agency (the EPA) and the Department of Homeland Security. Additionally, our pipelines are subject to the respective jurisdictions of the states those lines traverse.
Environmental and safety exposures and liabilities are difficult to assess and estimate due to unknown factors such as the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental and safety laws and regulations may change in the future. Although environmental and safety costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.
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The balance of and changes in the accruals for environmental matters were as follows:
| Year Ended December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| (Thousands of Dollars) | |||||||||||
| $ | 8,369 | $ | 7,748 | ||||||||
| Additions to accrual | 3,153 | 2,640 | |||||||||
| Payments | (2,049) | (2,019) | |||||||||
| $ | 9,473 | $ | 8,369 | ||||||||
Accruals for environmental matters are included in the consolidated balance sheets as follows:
| December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| (Thousands of Dollars) | |||||||||||
| $ | 4,059 | $ | 3,122 | ||||||||
| 5,414 | 5,247 | ||||||||||
| Accruals for environmental matters | $ | 9,473 | $ | 8,369 | |||||||
14. COMMITMENTS AND CONTINGENCIES
Commitments
Future minimum payments applicable to all noncancellable purchase obligations as of December 31, 2023 are as follows:
| Payments Due by Period | |||||||||||||||||||||||||||||||||||||||||
| 2024 | 2025 | 2026 | 2027 | 2028 | Thereafter | Total | |||||||||||||||||||||||||||||||||||
| (Thousands of Dollars) | |||||||||||||||||||||||||||||||||||||||||
| Purchase obligations | $ | 6,406 | $ | 5,003 | $ | 1,851 | $ | 1,134 | $ | 867 | $ | 4,038 | $ | 19,299 | |||||||||||||||||||||||||||
Our purchase obligations primarily consist of various service agreements with information technology providers, as well as right-of-way and easement agreements with government agencies and other landowners.
Contingencies
We have contingent liabilities resulting from various litigation, claims and commitments. We record accruals for loss contingencies when losses are considered probable and can be reasonably estimated. Legal fees associated with defending the Partnership in legal matters are expensed as incurred. We accrued $1.3 million and $0.3 million for contingent losses as of December 31, 2023 and 2022, respectively. The amount that will ultimately be paid related to such matters may differ from the recorded accruals, and the timing of such payments is uncertain. We evaluate each contingent loss at least quarterly, and more frequently as each matter progresses and develops over time, and we do not believe that the resolution of any particular claim or proceeding, or all matters in the aggregate, would have a material adverse effect on our results of operations, financial position or liquidity.
15. LEASE ASSETS AND LIABILITIES
Lessee Arrangements
Our operating leases consist primarily of land and dock leases at various terminal facilities and the HQ Lease Agreement. As of December 31, 2023, land and dock leases generally have remaining terms of about five years and include options to extend for to 25 years, which we are reasonably certain to exercise. Pursuant to the HQ Lease Agreement, which we entered into in the first quarter of 2023, rent for the initial term starts at $6.4 million per year, increasing annually by 2.5%. The HQ Lease Agreement has an initial term of 20 years, with two renewal options of ten years each. At inception of the HQ Lease Agreement, we assumed a reasonably certain term of 20 years and we recorded additional lease liabilities and right-of-use assets totaling $82.2 million.
The primary component of our finance lease portfolio is a dock at our Corpus Christi North Beach terminal, which includes a commitment for minimum dockage and wharfage throughput volumes. The dock lease has a remaining term of approximately two years and three additional -year renewal periods, all of which we are reasonably certain to exercise.
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Right-of-use assets and lease liabilities included in our consolidated balance sheet were as follows:
| December 31, | ||||||||||||||||||||
| Balance Sheet Location | 2023 | 2022 | ||||||||||||||||||
| (Thousands of Dollars) | ||||||||||||||||||||
| Right-of-use assets: | ||||||||||||||||||||
| Operating | $ | 143,937 | $ | 62,745 | ||||||||||||||||
| Finance | of accumulated amortization of $25,628 and $19,295 | $ | 66,840 | $ | 68,219 | |||||||||||||||
| Lease liabilities: | ||||||||||||||||||||
| Operating: | ||||||||||||||||||||
| Current | $ | 6,188 | $ | 5,541 | ||||||||||||||||
| Noncurrent | 137,945 | 56,577 | ||||||||||||||||||
| Total operating lease liabilities | $ | 144,133 | $ | 62,118 | ||||||||||||||||
| Finance: | ||||||||||||||||||||
| Current | $ | 4,951 | $ | 4,416 | ||||||||||||||||
| Noncurrent | 50,707 | 51,126 | ||||||||||||||||||
| Total finance lease liabilities | $ | 55,658 | $ | 55,542 | ||||||||||||||||
As of December 31, 2023, maturities of our operating and finance lease liabilities were as follows:
| Operating Leases | Finance Leases | |||||||||||||
| (Thousands of Dollars) | ||||||||||||||
| 2024 | $ | 14,267 | $ | 7,067 | ||||||||||
| 2025 | 14,221 | 6,250 | ||||||||||||
| 2026 | 13,810 | 5,703 | ||||||||||||
| 2027 | 13,791 | 4,934 | ||||||||||||
| 2028 | 13,554 | 4,311 | ||||||||||||
| Thereafter | 182,655 | 45,802 | ||||||||||||
| Total lease payments | $ | 252,298 | $ | 74,067 | ||||||||||
| Less: Interest | 108,165 | 18,409 | ||||||||||||
| Present value of lease liabilities | $ | 144,133 | $ | 55,658 | ||||||||||
Costs incurred for leases were as follows:
| Year Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| (Thousands of Dollars) | ||||||||||||||||||||
| Operating lease cost | $ | 15,754 | $ | 11,777 | $ | 15,323 | ||||||||||||||
| Finance lease cost: | ||||||||||||||||||||
| Amortization of right-of-use assets | 6,378 | 5,770 | 5,251 | |||||||||||||||||
| Interest expense on lease liability | 2,109 | 2,023 | 2,081 | |||||||||||||||||
| Short-term lease cost | 11,811 | 10,345 | 14,198 | |||||||||||||||||
| Variable lease cost | 4,640 | 4,830 | 4,939 | |||||||||||||||||
| Total lease cost | $ | 40,692 | $ | 34,745 | $ | 41,792 | ||||||||||||||
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The table below presents additional information regarding our leases.
| 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||||||
| Operating Leases | Finance Leases | Operating Leases | Finance Leases | Operating Leases | Finance Leases | ||||||||||||||||||||||||||||||
| (Thousands of Dollars, Except Term and Rate Data) | |||||||||||||||||||||||||||||||||||
| For the year ended December 31: | |||||||||||||||||||||||||||||||||||
| Cash outflows from operating activities | $ | 12,670 | $ | 2,095 | $ | 11,156 | $ | 2,019 | $ | 12,829 | $ | 2,090 | |||||||||||||||||||||||
| Cash outflows from financing activities | $ | — | $ | 4,882 | $ | — | $ | 4,222 | $ | — | $ | 4,244 | |||||||||||||||||||||||
| Right-of-use assets obtained in exchange for lease liabilities | $ | 88,226 | $ | 5,064 | $ | 10,060 | $ | 3,004 | $ | 3,278 | $ | 3,173 | |||||||||||||||||||||||
| As of December 31: | |||||||||||||||||||||||||||||||||||
| Weighted-average remaining lease term (in years) | 18 | 15 | 16 | 16 | 13 | 18 | |||||||||||||||||||||||||||||
| Weighted-average discount rate | 6.2 | % | 3.9 | % | 3.8 | % | 3.6 | % | 3.2 | % | 3.6 | % | |||||||||||||||||||||||
Lessor Arrangements
We have entered into certain revenue arrangements where we are considered to be the lessor. Under the largest of these arrangements, we lease certain of our storage tanks in exchange for a fixed fee, subject to an annual CPI adjustment. The operating leases commenced on January 1, 2017, and have initial terms of ten years with successive automatic renewal terms. We recognized lease revenues from these leases of $45.3 million, $43.1 million, and $41.5 million for the years ended December 31, 2023, 2022 and 2021, respectively, which are included in “” in the consolidated statements of income. As of December 31, 2023, we expect to receive minimum lease payments totaling $117.4 million, based upon the CPI as of the adoption date. We will recognize these payments ratably over the remaining initial lease term.
The table below presents cost, accumulated depreciation and useful life information related to our storage lease assets, which are included in our “Pipeline, storage and terminals” asset class within property, plant and equipment:
| Estimated Useful Life | December 31, | ||||||||||||||||
| 2023 | 2022 | ||||||||||||||||
| (Years) | (Thousands of Dollars) | ||||||||||||||||
| Lease storage assets, at cost | 30 | $ | 257,666 | $ | 251,801 | ||||||||||||
| Less accumulated depreciation | (157,836) | (148,899) | |||||||||||||||
| Lease storage assets, net | $ | 99,830 | $ | 102,902 | |||||||||||||
16. DERIVATIVES AND FAIR VALUE MEASUREMENTS
Derivative Instruments
We utilize various derivative instruments to manage our exposure to interest rate risk and commodity price risk. Our risk management policies and procedures are designed to monitor interest rates, futures and swap positions and over-the-counter positions, as well as physical commodity volumes, grades, locations and delivery schedules, to help ensure that our hedging activities address our market risks.
Commodity Price Risk. The results of operations for the fuels marketing segment depend largely on the margin between our cost and the sales prices of the products we market. Therefore, the results of operations for this segment are more sensitive to changes in commodity prices compared to the operations of the pipeline and storage segments. Since our fuels marketing operations expose us to commodity price risk, we enter into derivative instruments to mitigate the effect of commodity price fluctuations on our operations. Derivative financial instruments associated with commodity price risk with respect to our petroleum product inventories and related firm commitments to purchase and/or sell such inventories were not material for any period presented.
Interest Rate Risk.
The remaining fair value amounts associated with unwound forward-starting interest rate swap agreements and included in “Accumulated other comprehensive loss” on the consolidated balance sheets are $31.8 million and $34.4 million as of December 31, 2023 and 2022, respectively. These amounts are amortized ratably over the remaining life of the related debt
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instrument into “Interest expense, net” on the consolidated statements of income. In conjunction with the early repayment of our $250.0 million 4.75% senior notes due February 1, 2022 in the fourth quarter of 2021, we reclassified a loss of $0.8 million from AOCI to “Interest expense, net” on the consolidated statements of income.
Our forward-starting interest rate swaps had the following impact on earnings:
| Year Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| (Thousands of Dollars) | ||||||||||||||||||||
| Reclassification of loss on cash flow hedges to interest expense, net | $ | 2,581 | $ | 2,106 | $ | 5,664 | ||||||||||||||
As of December 31, 2023, we expect to reclassify a loss of $3.6 million to “Interest expense, net” within the next twelve months associated with unwound forward-starting interest rate swap agreements.
Fair Value Measurements
We segregate the inputs used in measuring fair value into three levels: Level 1, defined as observable inputs such as quoted prices for identical assets or liabilities in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable, such as quoted prices for similar assets or liabilities in active markets or quoted prices for identical assets or liabilities in markets that are not active; and Level 3, defined as unobservable inputs for which little or no market data exists. We consider counterparty credit risk and our own credit risk in the determination of all estimated fair values.
We recognize cash equivalents, receivables, payables and debt in our consolidated balance sheets at their carrying amounts. The fair values of these financial instruments, except for long-term debt other than finance leases, approximate their carrying amounts. The estimated fair values and carrying amounts of the long-term debt, excluding finance leases, were as follows:
| December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| (Thousands of Dollars) | |||||||||||
| Fair value | $ | 3,426,307 | $ | 3,169,664 | |||||||
| Carrying amount | $ | 3,359,631 | $ | 3,242,289 | |||||||
We have estimated the fair value of our publicly traded notes based upon quoted prices in active markets; therefore, we determined that the fair value of our publicly traded notes falls in Level 1 of the fair value hierarchy. With regard to our other debt, for which a quoted market price is not available, we have estimated the fair value using a discounted cash flow analysis using current incremental borrowing rates for similar types of borrowing arrangements and determined that the fair value falls in Level 2 of the fair value hierarchy. The carrying value includes unamortized debt issuance costs.
17. SERIES D CUMULATIVE CONVERTIBLE PREFERRED UNITS
Units Issued and Outstanding
In 2018, we entered into an agreement with investment funds, accounts and entities managed by EIG Management Company, LLC and FS/EIG Advisors, LLC to issue and sell Series D Cumulative Convertible Preferred Units (the Series D Preferred Units) in a private placement. The Partnership issued a total of 23,246,650 Series D Preferred Units.
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The following is a summary of the Series D Preferred Units issued and outstanding:
| Transaction Date | Price per Unit | Number of Units | |||||||||||||||
| Issuance | June 29, 2018 | $25.38 | 15,760,441 | ||||||||||||||
| Issuance | July 13, 2018 | $25.38 | 7,486,209 | ||||||||||||||
| Total units issued | 23,246,650 | ||||||||||||||||
| Units outstanding as of January 1, 2022 | 23,246,650 | ||||||||||||||||
| Repurchase | November 22, 2022 | $32.73 | (6,900,000) | ||||||||||||||
| Units outstanding as of December 31, 2022 | 16,346,650 | ||||||||||||||||
| Redemption | June 30, 2023 | $31.88 | (5,500,000) | ||||||||||||||
| Redemption | July 31, 2023 | $32.18 | (2,560,000) | ||||||||||||||
| Redemption | September 12, 2023 | $32.59 | (8,286,650) | ||||||||||||||
| Units outstanding as of December 31, 2023 | — | ||||||||||||||||
Redemptions and Repurchase
In the fourth quarter of 2022, we repurchased 6,900,000 Series D Preferred Units with borrowings under our Revolving Credit Agreement. In the second and third quarters of 2023, we redeemed all the remaining outstanding Series D Preferred Units at the then applicable redemption price of $31.73 per Series D Preferred Unit plus accrued and unpaid distributions. We funded the redemptions primarily with borrowings under our Revolving Credit Agreement, which had been partially paid down with proceeds from the Sale-Leaseback Transaction in the first quarter of 2023 and with proceeds from the issuance of common units in the third quarter of 2023.
On the notification dates for each redemption or repurchase, those Series D Preferred Units became mandatorily redeemable; therefore, we reclassified those Series D Preferred Units from mezzanine equity to liability-classified mandatorily redeemable Series D Preferred Units valued at the redemption or repurchase price, excluding accrued distributions (Net Redemption/Repurchase Price). We recorded the difference between the carrying value at each notification date and the Net Redemption/Repurchase Price as a deemed distribution, which reduced our common equity and was subtracted from net income to arrive at net income attributable to common units in the calculation of basic and diluted net income per common unit. At each closing, we accounted for the redemptions and repurchase as extinguishments of debt. Pursuant to our partnership agreement, the Series D Preferred Units were cancelled; therefore, the Series D Preferred Units no longer represent a limited partnership interest.
Distributions accrued for redeemed Series D Preferred Units from the notification dates to the redemption dates for the year ended December 31, 2023 totaled $4.8 million, and are reported in “Interest expense, net” on the consolidated statements of income.
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Information related to the Series D Preferred Unit redemptions and repurchase is shown below (thousands of dollars, except unit and per unit data):
| September 12, 2023 Redemption | July 31, 2023 Redemption | June 30, 2023 Redemption | November 22, 2022 Repurchase | ||||||||||||||||||||
| Notification date | August 14, 2023 | June 29, 2023 | May 25, 2023 | November 16, 2022 | |||||||||||||||||||
| Units redeemed/repurchased | 8,286,650 | 2,560,000 | 5,500,000 | 6,900,000 | |||||||||||||||||||
| Redemption/repurchase price per unit, including accrued distributions | $ | 32.59 | $ | 32.18 | $ | 31.88 | $ | 32.73 | |||||||||||||||
| Redemption/repurchase price, including accrued distributions | $ | 270,062 | $ | 82,381 | $ | 175,340 | $ | 225,837 | |||||||||||||||
| Accrued distributions | 7,126 | 1,152 | 825 | 3,450 | |||||||||||||||||||
| Net Redemption/Repurchase Price | $ | 262,936 | $ | 81,229 | $ | 174,515 | $ | 222,387 | |||||||||||||||
| Carrying value at notification date | $ | 230,461 | $ | 71,210 | $ | 152,467 | $ | 188,005 | |||||||||||||||
| Net Redemption/Repurchase Price | 262,936 | 81,229 | 174,515 | 222,387 | |||||||||||||||||||
| Loss to common limited partners attributable to redemption/repurchase | $ | (32,475) | $ | (10,019) | $ | (22,048) | $ | (34,382) | |||||||||||||||
For the years ended December 31, 2023 and 2022, we recorded losses of $0.55 and $0.31 per common unit, respectively, attributable to the Series D Preferred Unit redemptions and repurchase.
Distributions
Distributions on the Series D Preferred Units were payable out of any legally available funds, accrued and were cumulative from the issuance dates and were payable on the 15th day (or next business day) of each of March, June, September and December, beginning September 17, 2018, to holders of record on the first business day of each payment month. The distribution rates on the Series D Preferred Units were as follows: (i) 9.75% per annum ($0.619 per unit per distribution period) for the first two years; (ii) 10.75% per annum ($0.682 per unit per distribution period) for years three through five; and (iii) the greater of 13.75% per annum ($0.872 per unit per distribution period) or the distribution per common unit thereafter. While the Series D Preferred Units were outstanding, we were prohibited from paying distributions on any junior securities, including the common units, unless full cumulative distributions on the Series D Preferred Units (and any parity securities) had been, or contemporaneously were being, paid or set aside for payment through the most recent Series D Preferred Unit distribution payment date.
The distribution rate on the Series D Preferred Units increased on June 15, 2023, to the greater of 13.75% per annum ($0.872 per unit per distribution period) or the distribution per common unit. The total distribution for the applicable periods in the table below excludes amounts reported in “Interest expense, net” as described above under “Redemptions and Repurchase.”
Distribution information on the Series D Preferred Units was as follows:
| Distribution 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 | ||||||||||
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Accounting Treatment
The Series D Preferred Units included redemption provisions at the option of the holders of the Series D Preferred Units and upon a Series D Change of Control (as defined in the partnership agreement), which were outside the Partnership’s control. Therefore, the Series D Preferred Units were presented in the mezzanine section of the consolidated balance sheets. The Series D Preferred Units were recorded at their issuance date fair value, net of issuance costs.
The Series D Preferred Units were subject to accretion from their carrying value at the issuance date to the redemption value of $29.19 per Series D Preferred Unit, which was based on the redemption right of the Series D Preferred Unit holders that may have been exercised at any time on or after June 29, 2028, using the effective interest method over a period of ten years. In the calculation of net income per unit, the accretion was treated in the same manner as a distribution and deducted from net income to arrive at net income attributable to common units.
18. PARTNERS’ EQUITY
Series A, B and C Preferred Units
Information on our 8.50% Series A, 7.625% Series B and 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (collectively the Series A, B and C Preferred Units) issued and outstanding as of December 31, 2023 is shown below:
| Units | Original Issuance Date | Units Issued and Outstanding | Price per Unit | Fixed Distribution Rate per Unit per Annum | Fixed Distribution per Annum | Optional Redemption Date/Date When Distribution Rate Became Floating | Floating Annual Rate (as a Percentage of the $25.00 Liquidation Preference per Unit) | |||||||||||||||||||||||||||||||||||||
| (Thousands of Dollars) | ||||||||||||||||||||||||||||||||||||||||||||
| Series A Preferred Units | November 25, 2016 | 9,060,000 | $ | 25.00 | $ | 2.125 | $ | 19,252 | December 15, 2021 | Three-month LIBOR(a) plus 6.766% | ||||||||||||||||||||||||||||||||||
| Series B Preferred Units | April 28, 2017 | 15,400,000 | $ | 25.00 | $ | 1.90625 | $ | 29,357 | June 15, 2022 | Three-month LIBOR(a) plus 5.643% | ||||||||||||||||||||||||||||||||||
| Series C Preferred Units | November 30, 2017 | 6,900,000 | $ | 25.00 | $ | 2.25 | $ | 15,525 | December 15, 2022 | Three-month LIBOR(a) plus 6.88% | ||||||||||||||||||||||||||||||||||
(a)Beginning with the distribution period starting on September 15, 2023, LIBOR was replaced with the corresponding CME Term SOFR plus the applicable tenor spread adjustment of 0.26161%.
Distributions on the Series A, B and C Preferred Units are payable out of any legally available funds, accrue and are cumulative from the original issuance dates, and are payable on the 15th day (or the next business day) of each of March, June, September and December of each year to holders of record on the first business day of each payment month. The Series A, B and C Preferred Units rank equal to each other (and to the Series D Preferred Units prior to their redemption/repurchase) and senior to all our other classes of equity securities with respect to distribution rights and rights upon liquidation.
On January 25, 2024, our Board of Directors declared quarterly distributions with respect to the Series A, B and C Preferred Units to be paid on March 15, 2024 to holders of record as of March 1, 2024.
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Distribution information on our Series A, B and C Preferred Units is as follows (thousands of dollars, except per unit data):
| 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 | ||||||||||||||||||||||||||
We may redeem any of our outstanding Series A, B and C Preferred Units at any time on or after the optional redemption date set forth above for each series of the Series A, B and C Preferred Units, in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions to, but not including, the date of redemption, whether or not declared. We may also redeem the Series A, B and C Preferred Units upon the occurrence of certain rating events or a change of control as defined in our partnership agreement. In the case of the latter instance, if we choose not to redeem the Series A, B and C Preferred Units, those preferred unitholders may have the ability to convert their Series A, B and C Preferred Units to common units at the then-applicable conversion rate, which are subject to caps of 1.0915, 1.04297 and 1.7928, respectively. Holders of the Series A, B and C Preferred Units have no voting rights except for certain exceptions set forth in our partnership agreement.
Common Units
The following table shows the balance of and changes in the number of our common units outstanding:
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Balance as of January 1 | 110,818,718 | 109,986,273 | 109,468,127 | ||||||||||||||
| Issuance of units | 14,950,000 | — | — | ||||||||||||||
Unit-based compensation (Note 22) | 747,995 | 832,445 | 518,146 | ||||||||||||||
| Balance as of December 31 | 126,516,713 | 110,818,718 | 109,986,273 | ||||||||||||||
Issuance of Common Units. On August 11, 2023, we issued 14,950,000 common units representing limited partner interests at a price of $15.35 per unit for proceeds of approximately $222.0 million, net of approximately $7.5 million of issuance costs. We used these proceeds to repay outstanding borrowings under our Revolving Credit Agreement.
Cash Distributions. We are required by our partnership agreement to make quarterly distributions to common limited partners of 100% of our Available Cash (as defined in our partnership agreement), which is generally defined as all cash receipts less cash disbursements, including distributions to our preferred unit holders, and cash reserves established by our general partner, in its sole discretion. We are required under our partnership agreement to declare and pay these quarterly distributions within
45 days subsequent to each quarter-end. The common unitholders will receive a distribution each quarter as determined by the Board of Directors, subject to limitation by distributions in arrears, if any, on our preferred units. On January 25, 2024, our Board of Directors declared distributions with respect to our common units for the quarter ended December 31, 2023.
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The following table summarizes information about cash distributions to our common limited partners applicable to the period in which the distributions were earned:
| 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 | ||||||||||||||||||||||
Year ended December 31, 2021 | $ | 1.60 | $ | 175,470 | ||||||||||||||||||||||
Accumulated Other Comprehensive Income (Loss)
The balance of and changes in the components included in AOCI were as follows:
| Foreign Currency Translation | Cash Flow Hedges | Pension and Other Postretirement Benefits | Total | ||||||||||||||||||||
| (Thousands of Dollars) | |||||||||||||||||||||||
| Balance as of January 1, 2021 | $ | (42,362) | $ | (42,150) | $ | (12,144) | $ | (96,656) | |||||||||||||||
| Other comprehensive income before reclassifications | 601 | — | 17,721 | 18,322 | |||||||||||||||||||
| Net gain reclassified into other income, net | — | — | (1,308) | (1,308) | |||||||||||||||||||
| Net loss reclassified into interest expense, net | — | 5,664 | — | 5,664 | |||||||||||||||||||
| Other comprehensive income | 601 | 5,664 | 16,413 | 22,678 | |||||||||||||||||||
| Balance as of December 31, 2021 | (41,761) | (36,486) | 4,269 | (73,978) | |||||||||||||||||||
| Other comprehensive income (loss) before reclassifications | 2,177 | — | (516) | 1,661 | |||||||||||||||||||
Sale of Point Tupper Terminal Operations reclassified into net income (Note 4) | 39,646 | — | — | 39,646 | |||||||||||||||||||
| Net gain reclassified into other income, net | — | — | (1,040) | (1,040) | |||||||||||||||||||
| Net loss reclassified into interest expense, net | — | 2,106 | — | 2,106 | |||||||||||||||||||
| Other comprehensive income (loss) | 41,823 | 2,106 | (1,556) | 42,373 | |||||||||||||||||||
| Balance as of December 31, 2022 | 62 | (34,380) | 2,713 | (31,605) | |||||||||||||||||||
| Other comprehensive income before reclassifications | 728 | — | 8,317 | 9,045 | |||||||||||||||||||
| Net gain reclassified into other income, net | — | — | (2,946) | (2,946) | |||||||||||||||||||
| Net loss reclassified into interest expense, net | — | 2,581 | — | 2,581 | |||||||||||||||||||
| Other comprehensive income | 728 | 2,581 | 5,371 | 8,680 | |||||||||||||||||||
| Balance as of December 31, 2023 | $ | 790 | $ | (31,799) | $ | 8,084 | $ | (22,925) | |||||||||||||||
19. NET INCOME (LOSS) PER COMMON UNIT
The Series D Preferred Units contained certain unitholder conversion and redemption features, and we used the if-converted method to calculate the dilutive effect of the conversion or redemption feature that would have been most advantageous to the Series D preferred unitholders. The effect of the assumed conversion or redemption of the Series D Preferred Units outstanding, prior to their redemption and/or repurchase, was antidilutive for each of the years ended December 31, 2023, 2022 and 2021; therefore, we did not include such conversion or redemption in the computation of diluted net income (loss) per common unit.
Contingently issuable performance units are included as dilutive potential common units if it is probable that the performance measures will be achieved, unless to do so would be antidilutive. For the years ended December 31, 2023 and 2022, there were no performance unit awards outstanding. For the year ended December 31, 2021, we determined that it was probable that the
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performance measures would be achieved, but the effect would be antidilutive; therefore, we did not include any contingently issuable performance units as dilutive common units in the computation below.
The following table details the calculation of basic and diluted net income (loss) per common unit:
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (Thousands of Dollars, Except Unit and Per Unit Data) | |||||||||||||||||
| Net income | $ | 273,663 | $ | 222,747 | $ | 38,225 | |||||||||||
| Distributions to preferred limited partners | (114,729) | (127,589) | (127,399) | ||||||||||||||
| Distributions to common limited partners | (189,724) | (176,746) | (175,470) | ||||||||||||||
| Distribution equivalent rights to restricted units | (2,685) | (2,534) | (2,396) | ||||||||||||||
| Distributions in excess of income | $ | (33,475) | $ | (84,122) | $ | (267,040) | |||||||||||
| Distributions to common limited partners | $ | 189,724 | $ | 176,746 | $ | 175,470 | |||||||||||
Allocation of distributions in excess of income to common limited partners | (33,475) | (84,122) | (267,040) | ||||||||||||||
| Series D Preferred Unit accretion | (7,171) | (18,538) | (16,903) | ||||||||||||||
| Series D Preferred Unit redemptions/repurchase | (64,542) | (34,382) | — | ||||||||||||||
| Net income (loss) attributable to common units | $ | 84,536 | $ | 39,704 | $ | (108,473) | |||||||||||
| Basic and diluted weighted-average common units outstanding | 116,851,373 | 110,341,206 | 109,585,635 | ||||||||||||||
| Basic and diluted net income (loss) per common unit | $ | 0.72 | $ | 0.36 | $ | (0.99) | |||||||||||
20. SUPPLEMENTAL CASH FLOW INFORMATION
Changes in current assets and current liabilities were as follows:
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (Thousands of Dollars) | |||||||||||||||||
| Decrease (increase) in current assets: | |||||||||||||||||
| Accounts receivable | $ | 1,923 | $ | (6,762) | $ | (2,105) | |||||||||||
| Inventories | (3,226) | 836 | (5,585) | ||||||||||||||
| Prepaid and other current assets | (5,833) | 768 | (1,710) | ||||||||||||||
| Increase (decrease) in current liabilities: | |||||||||||||||||
| Accounts payable | 534 | (2,960) | 10,202 | ||||||||||||||
| Accrued interest payable | 2,368 | 3,468 | (16,708) | ||||||||||||||
| Accrued liabilities | 13,642 | 9,018 | 4,448 | ||||||||||||||
| Taxes other than income tax | 1,210 | (3,631) | (2,689) | ||||||||||||||
| Changes in current assets and current liabilities | $ | 10,618 | $ | 737 | $ | (14,147) | |||||||||||
The above changes in current assets and current liabilities differ from changes between amounts reflected in the applicable consolidated balance sheets due to:
•the change in the amount accrued for capital expenditures;
•the effect of foreign currency translation;
•the effect of accrued compensation expense paid with fully vested common unit awards; and
•current assets and current liabilities disposed of during the period.
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Cash flows related to interest and income taxes were as follows:
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (Thousands of Dollars) | |||||||||||||||||
| Cash paid for interest, net of amount capitalized | $ | 229,528 | $ | 195,697 | $ | 218,181 | |||||||||||
| Cash paid for income taxes, net of tax refunds received | $ | 2,188 | $ | 4,368 | $ | 5,491 | |||||||||||
Restricted cash is included in “Other long-term assets, net” on the consolidated balance sheets. “Cash, cash equivalents and restricted cash” on the consolidated statements of cash flows was included in the consolidated balance sheets as follows:
| December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| (Thousands of Dollars) | |||||||||||
| Cash and cash equivalents | $ | 2,765 | $ | 14,489 | |||||||
| 9,251 | 8,888 | ||||||||||
| Cash, cash equivalents and restricted cash | $ | 12,016 | $ | 23,377 | |||||||
21. EMPLOYEE BENEFIT PLANS
Thrift Plans
The NuStar Thrift Plan (the Thrift Plan) is a qualified defined contribution plan that became effective June 26, 2006. Participation in the Thrift Plan is voluntary and open to substantially all our domestic employees upon their dates of hire. Thrift Plan participants can contribute from 1% up to 30% of their total annual compensation to the Thrift Plan in the form of pre-tax and/or after-tax employee contributions. We make matching contributions in an amount equal to 100% of each participant’s employee contributions up to a maximum of 6% of the participant’s total annual compensation. The matching contributions to the Thrift Plan for the years ended December 31, 2023, 2022 and 2021 totaled $7.3 million, $7.3 million and $7.6 million, respectively.
The NuStar Excess Thrift Plan (the Excess Thrift Plan) is a nonqualified deferred compensation plan that became effective July 1, 2006. The Excess Thrift Plan provides benefits to those employees whose compensation and/or annual contributions under the Thrift Plan are subject to the limitations applicable to qualified retirement plans under the Code.
Pension and Other Postretirement Benefits
The NuStar Pension Plan (the Pension Plan) is a qualified non-contributory defined benefit pension plan that provides eligible U.S. employees with retirement income as calculated under a cash balance formula. Under the cash balance formula, benefits are determined based on age, years of vesting service and interest credits, and employees become fully vested in their benefits upon attaining three years of vesting service. Prior to January 1, 2014, eligible employees were covered under either a cash balance formula or a final average pay formula (FAP). The Pension Plan was amended to freeze the FAP benefits as of December 31, 2013, and effective January 1, 2014, eligible employees are covered under the cash balance formula discussed above.
We also maintain an excess pension plan (the Excess Pension Plan), which is a nonqualified deferred compensation plan that provides benefits to a select group of management or other highly compensated employees. Neither the Excess Thrift Plan nor the Excess Pension Plan is intended to constitute either a qualified plan under the provisions of Section 401 of the Code or a funded plan subject to the Employee Retirement Income Security Act.
The Pension Plan and Excess Pension Plan are collectively referred to as the Pension Plans in the tables and discussion below. Our other postretirement benefit plans include a contributory medical benefits plan for U.S. employees who retired prior to April 1, 2014 and, for employees who retire on or after April 1, 2014, a partial reimbursement for eligible third-party health care premiums. We use December 31 as the measurement date for our pension and other postretirement plans.
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The changes in the benefit obligation, the changes in fair value of plan assets, the funded status and the amounts recognized in the consolidated balance sheets for our Pension Plans and other postretirement benefit plans as of and for the years ended December 31, 2023 and 2022 were as follows:
| Pension Plans | Other Postretirement Benefit Plans | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| (Thousands of Dollars) | |||||||||||||||||||||||
| Change in benefit obligation: | |||||||||||||||||||||||
| Benefit obligation as of January 1 | $ | 144,311 | $ | 179,907 | $ | 11,983 | $ | 16,270 | |||||||||||||||
| Service cost | 9,041 | 9,752 | 359 | 605 | |||||||||||||||||||
| Interest cost | 7,224 | 4,619 | 602 | 423 | |||||||||||||||||||
| Benefits paid (a) | (8,962) | (15,949) | (532) | (603) | |||||||||||||||||||
| Participant contributions | — | — | 71 | 66 | |||||||||||||||||||
| Actuarial loss (gain) | 6,999 | (34,221) | 404 | (4,778) | |||||||||||||||||||
| Other | — | 203 | — | — | |||||||||||||||||||
| Benefit obligation as of December 31 | $ | 158,613 | $ | 144,311 | $ | 12,887 | $ | 11,983 | |||||||||||||||
| Change in plan assets: | |||||||||||||||||||||||
| Plan assets at fair value as of January 1 | $ | 148,496 | $ | 189,838 | $ | — | $ | — | |||||||||||||||
| Actual return on plan assets | 25,448 | (30,405) | — | — | |||||||||||||||||||
| Employer contributions | 11,203 | 5,012 | 461 | 537 | |||||||||||||||||||
| Benefits paid (a) | (8,962) | (15,949) | (532) | (603) | |||||||||||||||||||
| Participant contributions | — | — | 71 | 66 | |||||||||||||||||||
| Plan assets at fair value as of December 31 | $ | 176,185 | $ | 148,496 | $ | — | $ | — | |||||||||||||||
| Reconciliation of funded status as of December 31: | |||||||||||||||||||||||
| Fair value of plan assets | $ | 176,185 | $ | 148,496 | $ | — | $ | — | |||||||||||||||
| Less: Benefit obligation | 158,613 | 144,311 | 12,887 | 11,983 | |||||||||||||||||||
| Funded status | $ | 17,572 | $ | 4,185 | $ | (12,887) | $ | (11,983) | |||||||||||||||
Amounts recognized in the consolidated balance sheets as of December 31 (b): | |||||||||||||||||||||||
| Other long-term assets, net | $ | 22,720 | $ | 9,130 | $ | — | $ | — | |||||||||||||||
| Accrued liabilities | (648) | (552) | (580) | (507) | |||||||||||||||||||
| Other long-term liabilities | (4,500) | (4,393) | (12,307) | (11,476) | |||||||||||||||||||
| Net pension asset (liability) | $ | 17,572 | $ | 4,185 | $ | (12,887) | $ | (11,983) | |||||||||||||||
| Accumulated benefit obligation | $ | 153,318 | $ | 141,517 | $ | 12,887 | $ | 11,983 | |||||||||||||||
(a)Benefit payments for the year ended December 31, 2022 include lump-sum payments of $2.9 million to participants of the Pension Plans following the Eastern U.S. Terminals Disposition, as discussed in Note 4.
(b)For the Pension Plan, since assets exceed the present value of expected benefit payments for the next 12 months, the asset is noncurrent. For the Excess Pension Plan and the other postretirement benefit plans, since there are no assets, the current liability is the present value of expected benefit payments for the next 12 months; the remainder is noncurrent.
The actuarial loss (gain) related to the benefit obligation for our pension plans was primarily attributable to a decrease in the discount rates used to determine the benefit obligation from 5.26% to 5.08% in 2023 and an increase from 3.10% to 5.26% in 2022. The fair value of our plan assets is affected by the return on plan assets resulting primarily from the performance of equity and bond markets during the period.
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The Excess Pension Plan has no plan assets and an accumulated benefit obligation of $4.8 million and $4.6 million as of December 31, 2023 and 2022, respectively. The accumulated benefit obligation is the present value of benefits earned to date, while the projected benefit obligation may include future salary increase assumptions. The projected benefit obligation for the Excess Pension Plan was $5.1 million and $4.9 million as of December 31, 2023 and 2022, respectively.
The components of net periodic benefit cost (income) related to our Pension Plans and other postretirement benefit plans were as follows:
| Pension Plans | Other Postretirement Benefit Plans | ||||||||||||||||||||||||||||||||||
| Year Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | 2023 | 2022 | 2021 | ||||||||||||||||||||||||||||||
| (Thousands of Dollars) | |||||||||||||||||||||||||||||||||||
| Service cost | $ | 9,041 | $ | 9,752 | $ | 9,978 | $ | 359 | $ | 605 | $ | 593 | |||||||||||||||||||||||
| Interest cost | 7,224 | 4,619 | 4,084 | 602 | 423 | 326 | |||||||||||||||||||||||||||||
| Expected return on plan assets | (9,660) | (9,087) | (9,233) | — | — | — | |||||||||||||||||||||||||||||
| Amortization of prior service credit | (1,876) | (1,876) | (2,057) | (1,145) | (1,145) | (1,145) | |||||||||||||||||||||||||||||
| Amortization of net actuarial loss | 75 | 1,129 | 2,279 | — | 209 | 176 | |||||||||||||||||||||||||||||
| Other | — | 846 | (561) | — | — | — | |||||||||||||||||||||||||||||
| Net periodic benefit cost (income) | $ | 4,804 | $ | 5,383 | $ | 4,490 | $ | (184) | $ | 92 | $ | (50) | |||||||||||||||||||||||
We amortize prior service costs and credits on a straight-line basis over the average remaining service period of employees expected to receive benefits under our Pension Plans and other postretirement benefit plans (“Amortization of prior service credit” in table above). We amortize the actuarial gains and losses that exceed 10% of the greater of the projected benefit obligation or market-related value of plan assets (smoothed asset value) over the average remaining service period of active employees expected to receive benefits under our Pension Plans and other postretirement benefit plans (“Amortization of net actuarial loss” in table above).
The service cost component of net periodic benefit cost (income) is reported in “General and administrative expenses” and “Operating expenses” on the consolidated statements of income, and the remaining components of net periodic benefit cost (income) are reported in “Other income, net.”
Adjustments to other comprehensive income related to our Pension Plans and other postretirement benefit plans were as follows:
| Pension Plans | Other Postretirement Benefit Plans | ||||||||||||||||||||||||||||||||||
| Year Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | 2023 | 2022 | 2021 | ||||||||||||||||||||||||||||||
| (Thousands of Dollars) | |||||||||||||||||||||||||||||||||||
| Net unrecognized gain (loss) arising during the year: | |||||||||||||||||||||||||||||||||||
| Net actuarial gain (loss) | $ | 8,790 | $ | (5,271) | $ | 18,666 | $ | (404) | $ | 4,779 | $ | (884) | |||||||||||||||||||||||
| Net (gain) loss reclassified into income: | |||||||||||||||||||||||||||||||||||
| Amortization of prior service credit | (1,876) | (1,876) | (2,057) | (1,145) | (1,145) | (1,145) | |||||||||||||||||||||||||||||
| Amortization of net actuarial loss | 75 | 1,129 | 2,279 | — | 209 | 176 | |||||||||||||||||||||||||||||
| Other | — | 643 | (561) | — | — | — | |||||||||||||||||||||||||||||
| Net gain reclassified into income | (1,801) | (104) | (339) | (1,145) | (936) | (969) | |||||||||||||||||||||||||||||
| Income tax expense | (69) | (24) | (61) | — | — | — | |||||||||||||||||||||||||||||
| Total changes to other comprehensive income | $ | 6,920 | $ | (5,399) | $ | 18,266 | $ | (1,549) | $ | 3,843 | $ | (1,853) | |||||||||||||||||||||||
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The amounts recorded as a component of “Accumulated other comprehensive loss” on the consolidated balance sheets related to our Pension Plans and other postretirement benefit plans were as follows:
| Pension Plans | Other Postretirement Benefit Plans | ||||||||||||||||||||||
| December 31, | December 31, | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| (Thousands of Dollars) | |||||||||||||||||||||||
| Unrecognized actuarial gain (loss) | $ | 1,618 | $ | (7,247) | $ | 30 | $ | 434 | |||||||||||||||
| Prior service credit | 3,878 | 5,754 | 2,594 | 3,739 | |||||||||||||||||||
| Other | (36) | 33 | — | — | |||||||||||||||||||
Accumulated other comprehensive income (loss), net of tax | $ | 5,460 | $ | (1,460) | $ | 2,624 | $ | 4,173 | |||||||||||||||
Investment Policies and Strategies
The investment policies and strategies for the assets of our qualified Pension Plan incorporate a well-diversified approach that is expected to earn long-term returns from capital appreciation and a growing stream of current income. This approach recognizes that assets are exposed to risk, and the market value of the Pension Plan’s assets may fluctuate from year to year. Risk tolerance is determined based on our financial ability to withstand risk within the investment program and the willingness to accept return volatility. In line with the investment return objective and risk parameters, the Pension Plan’s mix of assets includes a diversified portfolio of equity and fixed-income instruments. The aggregate asset allocation is reviewed on an annual basis. As of December 31, 2023, the target allocations for plan assets were approximately 65% equity securities and 35% fixed income investments, with certain fluctuations permitted.
The overall expected long-term rate of return on plan assets for the Pension Plan is estimated using various models of asset returns. Model assumptions are derived using historical data with the assumption that capital markets are informationally efficient. Three models are used to derive the long-term expected returns for each asset class. Since each method has distinct advantages and disadvantages and differing results, an equal weighted average of the methods’ results is used.
Fair Value of Plan Assets
We disclose the fair value for each major class of plan assets in the Pension Plan in three levels: Level 1, defined as observable inputs such as quoted prices for identical assets or liabilities in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable, such as quoted prices for similar assets or liabilities in active markets or quoted prices for identical assets or liabilities in markets that are not active; and Level 3, defined as unobservable inputs for which little or no market data exists.
The major classes of plan assets measured at fair value for the Pension Plan were as follows:
| December 31, 2023 | |||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
| (Thousands of Dollars) | |||||||||||||||||||||||
| Cash equivalent securities | $ | 373 | $ | — | $ | — | $ | 373 | |||||||||||||||
| Equity securities: | |||||||||||||||||||||||
| U.S. large cap equity fund (a) | — | 99,301 | — | 99,301 | |||||||||||||||||||
| International stock index fund (b) | 17,715 | — | — | 17,715 | |||||||||||||||||||
| Fixed income securities: | |||||||||||||||||||||||
| Bond market index fund (c) | 58,796 | — | — | 58,796 | |||||||||||||||||||
| Total | $ | 76,884 | $ | 99,301 | $ | — | $ | 176,185 | |||||||||||||||
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| December 31, 2022 | |||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
| (Thousands of Dollars) | |||||||||||||||||||||||
| Cash equivalent securities | $ | 789 | $ | — | $ | — | $ | 789 | |||||||||||||||
| Equity securities: | |||||||||||||||||||||||
| U.S. large cap equity fund (a) | — | 81,754 | — | 81,754 | |||||||||||||||||||
| International stock index fund (b) | 14,836 | — | — | 14,836 | |||||||||||||||||||
| Fixed income securities: | |||||||||||||||||||||||
| Bond market index fund (c) | 51,117 | — | — | 51,117 | |||||||||||||||||||
| Total | $ | 66,742 | $ | 81,754 | $ | — | $ | 148,496 | |||||||||||||||
(a)This fund is a low-cost equity index fund not actively managed that tracks the S&P 500. Fair values were estimated using pricing models, quoted prices of securities with similar characteristics or discounted cash flows.
(b)This fund tracks the performance of the Total International Composite Index.
(c)This fund tracks the performance of the Barclays Capital U.S. Aggregate Bond Index.
Contributions to the Pension Plans
For the year ended December 31, 2023, we contributed $11.2 million and $0.5 million to our Pension Plan and other postretirement benefit plans, respectively. During 2024, we expect to contribute approximately $9.6 million and $0.6 million to the Pension Plans and other postretirement benefit plans, respectively. We will monitor our funding status in 2024 to determine if any contributions are required by regulations or laws, or with respect to unfunded plans, necessary to fund current benefits.
Estimated Future Benefit Payments
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid for the years ending December 31:
| Pension Plans | Other Postretirement Benefit Plans | ||||||||||
| (Thousands of Dollars) | |||||||||||
| 2024 | $ | 10,023 | $ | 580 | |||||||
| 2025 | $ | 11,151 | $ | 621 | |||||||
| 2026 | $ | 11,286 | $ | 665 | |||||||
| 2027 | $ | 11,619 | $ | 708 | |||||||
| 2028 | $ | 12,339 | $ | 753 | |||||||
| 2029-2033 | $ | 69,178 | $ | 4,363 | |||||||
Assumptions
The discount rate is based on a hypothetical yield curve represented by a series of annualized individual discount rates. Each bond issue underlying the hypothetical yield curve required an average rating of double-A, when averaging all available ratings by Moody’s Investor Service Inc., S&P Global Ratings and Fitch Ratings. The expected long-term rate of return on plan assets is based on the weighted averages of the expected long-term rates of return for each asset class of investments held in our plans as determined using historical data and the assumption that capital markets are informationally efficient. The expected rate of compensation increase represents average long-term salary increases.
The weighted-average assumptions used to determine the benefit obligations were as follows:
| Pension Plans | Other Postretirement Benefit Plans | ||||||||||||||||||||||
| December 31, | December 31, | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| Discount rate | 5.08 | % | 5.26 | % | 5.06 | % | 5.25 | % | |||||||||||||||
| Rate of compensation increase | 3.99 | % | 3.99 | % | n/a | n/a | |||||||||||||||||
| Cash balance interest crediting rate | 3.58 | % | 3.76 | % | n/a | n/a | |||||||||||||||||
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The weighted-average assumptions used to determine the net periodic benefit cost (income) were as follows:
| Pension Plans | Other Postretirement Benefit Plans | ||||||||||||||||||||||||||||||||||
| Year Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | 2023 | 2022 | 2021 | ||||||||||||||||||||||||||||||
| Discount rate | 5.26 | % | 3.10 | % | 2.84 | % | 5.25 | % | 3.08 | % | 2.83 | % | |||||||||||||||||||||||
Expected long-term rate of return on plan assets | 6.50 | % | 6.00 | % | 6.00 | % | n/a | n/a | n/a | ||||||||||||||||||||||||||
| Rate of compensation increase | 3.99 | % | 3.99 | % | 3.51 | % | n/a | n/a | n/a | ||||||||||||||||||||||||||
| Cash balance interest crediting rate | 3.76 | % | 2.00 | % | 2.00 | % | n/a | n/a | n/a | ||||||||||||||||||||||||||
We sponsor a contributory postretirement health care plan for employees who retired prior to April 1, 2014. The plan has an annual limitation (a cap) on the increase of the employer’s share of the cost of covered benefits. The cap on the increase in employer’s cost is 2.5% per year. The assumed health care cost trend rates were as follows:
| December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| Health care cost trend rate assumed for next year | 6.88 | % | 7.00 | % | |||||||
| Rate to which the cost trend rate was assumed to decrease (the ultimate trend rate) | 5.00 | % | 5.00 | % | |||||||
| Year that the rate reaches the ultimate trend rate | 2032 | 2032 | |||||||||
22. UNIT-BASED COMPENSATION
Overview
2019 LTIP. In April 2019, our common unitholders approved the 2019 Long-Term Incentive Plan (2019 LTIP) for eligible employees, consultants and directors of NuStar Energy L.P., and of NuStar GP, LLC, and their respective affiliates who perform services for us and our subsidiaries. The 2019 LTIP allows for the awarding of (i) options; (ii) restricted units;
(iii) distribution equivalent rights (DERs); (iv) performance cash; (v) performance units; and (vi) unit awards. DERs entitle the participant to receive cash equal to cash distributions made on any award prior to its vesting. The 2019 LTIP, as amended and restated on April 27, 2023, permits the granting of awards totaling an aggregate of 7,500,000 common units, subject to adjustment as provided by the terms of the 2019 LTIP. The 2019 LTIP generally will be administered by the compensation committee of our Board of Directors. As of December 31, 2023, a total of 2,651,315 common units remained available to be awarded under the 2019 LTIP.
Other Plans. We sponsor the NuStar GP, LLC Fifth Amended and Restated 2000 Long-Term Incentive Plan, as amended (2000 LTIP), and the NuStar GP Holdings, LLC Long-Term Incentive Plan, as amended (2006 LTIP). Effective with the approval of the 2019 LTIP in April 2019, the 2000 LTIP and the 2006 LTIP terminated with respect to new grants; however, unvested restricted unit awards granted under the 2000 LTIP and the 2006 LTIP remain outstanding as of December 31, 2023.
The following table summarizes information pertaining to all our long-term incentive plans:
| Units Outstanding December 31, | Compensation Expense Year Ended December 31, | ||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | 2023 | 2022 | 2021 | ||||||||||||||||||||||||||||||
| (Thousands of Dollars) | |||||||||||||||||||||||||||||||||||
| Restricted units: | |||||||||||||||||||||||||||||||||||
| Domestic employees | 3,017,060 | 2,859,189 | 2,520,436 | $ | 14,580 | $ | 12,759 | $ | 11,892 | ||||||||||||||||||||||||||
| Non-employee directors (NEDs) | 143,374 | 133,604 | 129,312 | 967 | 1,021 | 856 | |||||||||||||||||||||||||||||
| International employees | — | — | 21,760 | — | (20) | 139 | |||||||||||||||||||||||||||||
| Performance awards | — | — | 33,695 | 2,815 | 2,442 | 3,047 | |||||||||||||||||||||||||||||
| Unit awards | — | — | — | — | — | 4,645 | |||||||||||||||||||||||||||||
| Total | 3,160,434 | 2,992,793 | 2,705,203 | $ | 18,362 | $ | 16,202 | $ | 20,579 | ||||||||||||||||||||||||||
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Common units issued under our long-term incentive plans, net of employee tax withholding requirements, were as follows:
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Restricted units | 661,050 | 531,637 | 460,076 | ||||||||||||||
| Performance awards | 86,945 | 114,618 | 58,070 | ||||||||||||||
| Unit awards | — | 186,190 | — | ||||||||||||||
| Total | 747,995 | 832,445 | 518,146 | ||||||||||||||
Restricted Units
Our restricted unit awards are considered phantom units, as they represent the right to receive our common units upon vesting. We account for restricted units as either equity-classified awards or liability-classified awards, depending on expected method of settlement. Awards we settle with the issuance of common units upon vesting are equity-classified. Awards we settle in cash upon vesting are liability-classified. We record compensation expense ratably over the vesting period based on the fair value of the common units at the grant date (for domestic employees and NEDs), or, prior to the sale of our Point Tupper Terminal Operations on April 29, 2022, the fair value of the common units measured at each reporting period (for international employees). DERs paid with respect to outstanding equity-classified unvested restricted units reduce equity, similar to cash distributions to unitholders, whereas DERs paid with respect to outstanding liability-classified unvested restricted units were expensed prior to the sale of our Point Tupper Terminal Operations on April 29, 2022. In connection with the DERs for equity awards, we paid $2.7 million, $2.5 million and $2.4 million respectively, in cash, for the years ended December 31, 2023, 2022 and 2021.
Domestic Employees. The outstanding restricted units granted to domestic employees are equity-classified awards and generally vest over five years, beginning one year after the grant date. The fair value of these awards is measured at the grant date.
Non-Employee Directors. The outstanding restricted units granted to NEDs are equity-classified awards that vest over three years. The fair value of these awards is measured at the grant date.
International Employees. Prior to the sale of our Point Tupper Terminal Operations on April 29, 2022, the outstanding restricted units granted to international employees were cash-settled and accounted for as liability-classified awards. These awards vested over three years and the fair value was equal to the market price of our common units at each reporting period. For the year ended December 31, 2022, 11,364 restricted units vested, and 10,396 restricted units were forfeited related to our international employees.
A summary of our equity-classified restricted unit awards is as follows:
| Measured at Grant Date Fair Value | |||||||||||
| Number of Units | Weighted-Average Fair Value Per Unit | ||||||||||
Nonvested units as of January 1, 2021 | 2,333,894 | $ | 17.70 | ||||||||
| Granted | 1,049,081 | 16.28 | |||||||||
| Vested | (630,888) | 20.07 | |||||||||
| Forfeited | (102,339) | 14.28 | |||||||||
Nonvested units as of December 31, 2021 | 2,649,748 | 16.57 | |||||||||
| Granted | 1,206,824 | 16.09 | |||||||||
| Vested | (738,701) | 17.79 | |||||||||
| Forfeited | (125,078) | 16.23 | |||||||||
Nonvested units as of December 31, 2022 | 2,992,793 | 16.08 | |||||||||
| Granted | 1,112,965 | 17.49 | |||||||||
| Vested | (921,890) | 16.81 | |||||||||
| Forfeited | (23,434) | 15.93 | |||||||||
Nonvested units as of December 31, 2023 | 3,160,434 | 16.39 | |||||||||
The total fair value of our equity-classified restricted unit awards vested for the years ended December 31, 2023, 2022 and 2021 was $16.1 million, $11.9 million and $10.3 million, respectively. We issued 661,050, 531,637 and 460,076 common units in
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
connection with these award vestings, net of employee tax withholding requirements, for the years ended December 31, 2023, 2022 and 2021, respectively. Unrecognized compensation cost related to our equity-classified employee awards totaled $49.2 million as of December 31, 2023, which we expect to recognize over a weighted-average period of 3.6 years.
Performance Awards
Performance awards are issued to certain of our key employees and represent either rights to receive our common units or cash upon achieving performance measures for the performance period established by the NuStar GP, LLC Compensation Committee (the Compensation Committee). Achievement of the performance measures determines the rate at which the performance awards convert into our common units or cash, which ranges from zero to 200% for certain awards.
Performance awards vest in three annual increments (tranches), based upon our achievement of the performance measures set by the Compensation Committee during the performance periods that end on December 31 of each applicable year. Therefore, the performance awards are not considered granted for accounting purposes until the Compensation Committee has set the performance measures for each tranche of awards. Performance unit awards are equity-classified awards measured at the grant date fair value. In addition, since the performance unit awards granted do not receive DERs, the grant date fair value of these awards is reduced by the per unit distributions expected to be paid to common unitholders during the vesting period. Performance cash awards are accounted for as a liability but may be settled in common units. We record compensation expense ratably for each vesting tranche over its requisite service period (one year) if it is probable that the specified performance measures will be achieved. Additionally, changes in the actual or estimated outcomes that affect the quantity of performance awards expected to be converted into common units or paid in cash, are recognized as a cumulative adjustment. Performance units vested relate to the performance for the performance period ended December 31 of the previous year.
A summary of our performance awards is shown below:
| Performance Unit Awards | |||||||||||||||||||||||
| Granted for Accounting Purposes | |||||||||||||||||||||||
| Performance Cash Awards | Total Performance Unit Awards Granted | Performance Unit Awards | Weighted-Average Grant Date Fair Value per Unit | ||||||||||||||||||||
| (Thousands of Dollars) | |||||||||||||||||||||||
Outstanding as of January 1, 2021 | $ | 2,167 | 87,122 | 57,448 | $ | 13.21 | |||||||||||||||||
| Granted | 2,254 | 4,021 | 33,695 | 15.79 | |||||||||||||||||||
| Vested (a) | (672) | (53,427) | (53,427) | 13.21 | |||||||||||||||||||
| Forfeited | (51) | (4,021) | (4,021) | 13.21 | |||||||||||||||||||
Outstanding as of December 31, 2021 | 3,698 | 33,695 | 33,695 | 15.79 | |||||||||||||||||||
| Granted | 2,954 | — | — | — | |||||||||||||||||||
| Performance adjustment (b) | — | 14,839 | 14,839 | 15.79 | |||||||||||||||||||
| Vested (a) | (1,507) | (48,534) | (48,534) | 15.79 | |||||||||||||||||||
Outstanding as of December 31, 2022 | 5,145 | — | — | — | |||||||||||||||||||
| Granted | 3,287 | — | — | — | |||||||||||||||||||
| Vested (a) | (2,575) | — | — | — | |||||||||||||||||||
| Forfeited | (141) | — | — | — | |||||||||||||||||||
Outstanding as of December 31, 2023 | $ | 5,716 | — | — | — | ||||||||||||||||||
(a)For the years ended December 31, 2023, 2022 and 2021, we settled performance cash awards with 149,608, 137,931 and 43,733 common units, respectively, and issued 86,945, 84,778 and 26,704 common units, net of employee tax withholding requirements, respectively.
(b)For the year ended December 31, 2022, common units granted and issued upon vesting resulted from performance units earned at 150% of the 2021 target.
The total fair value of our performance unit awards vested for the years ended December 31, 2022 and 2021 was $0.8 million and $0.8 million, respectively. For the years ended December 31, 2022 and 2021 we issued 29,840 and 31,366 common units in connection with the performance unit award vestings, net of employee tax withholding requirements, respectively. In January 2024, we settled performance cash awards, net of employee tax withholding requirements, in cash for $1.6 million.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Unit Awards
Unit awards are equity-classified awards of fully vested common units. We accrued compensation expense in 2021 that was paid in unit awards in the first quarter of 2022. We base the number of unit awards granted on the fair value of the common units at the grant date. A summary of our unit awards is shown below:
| Date of Grant | Grant Date Fair Value | Unit Awards Granted | Common Units Issued, Net of Employee Withholding Tax | |||||||||||||||||
| (Thousands of Dollars) | ||||||||||||||||||||
| February 2022 | $ | 4,645 | 280,685 | 186,190 | ||||||||||||||||
23. INCOME TAXES
Components of income tax expense related to certain of our operations conducted through separate taxable wholly owned corporate subsidiaries were as follows:
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (Thousands of Dollars) | |||||||||||||||||
| Current: | |||||||||||||||||
| U.S. | $ | 4,292 | $ | 3,558 | $ | 3,755 | |||||||||||
| Foreign | — | 272 | 221 | ||||||||||||||
| Foreign withholding tax | 519 | 355 | 1,281 | ||||||||||||||
| Total current | 4,811 | 4,185 | 5,257 | ||||||||||||||
| Deferred: | |||||||||||||||||
| U.S. | 601 | 341 | (93) | ||||||||||||||
| Foreign | — | (1,287) | (531) | ||||||||||||||
| Foreign withholding tax | — | — | (745) | ||||||||||||||
| Total deferred | 601 | (946) | (1,369) | ||||||||||||||
| Income tax expense | $ | 5,412 | $ | 3,239 | $ | 3,888 | |||||||||||
The difference between income tax expense recorded in our consolidated statements of income and income taxes computed by applying the applicable statutory federal income tax rate to income before income tax expense is due to the fact that the majority of our income is not subject to federal income tax due to our status as a limited partnership. We record a tax provision related to the amount of undistributed earnings of our foreign subsidiaries expected to be repatriated.
97
The tax effects of significant temporary differences representing deferred income tax assets and liabilities were as follows:
| December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| (Thousands of Dollars) | |||||||||||
| Deferred income tax assets: | |||||||||||
| Net operating losses | $ | 19,340 | $ | 17,710 | |||||||
| Capital loss | 3,714 | 3,714 | |||||||||
| Other | 701 | 793 | |||||||||
| Total deferred income tax assets | 23,755 | 22,217 | |||||||||
| Less: Valuation allowance | (22,866) | (21,573) | |||||||||
| Net deferred income tax assets | 889 | 644 | |||||||||
| Deferred income tax liabilities: | |||||||||||
| Property, plant and equipment | (4,420) | (3,534) | |||||||||
| Foreign withholding tax | (330) | (286) | |||||||||
| Other | (72) | (43) | |||||||||
| Total deferred income tax liabilities | (4,822) | (3,863) | |||||||||
| Net deferred income tax liability | $ | (3,933) | $ | (3,219) | |||||||
As of December 31, 2023, our U.S. and foreign corporate operations have net operating loss carryforwards for tax purposes totaling $49.2 million and $30.1 million, respectively, which are subject to various limitations on use and expire in years 2032 through 2034 for U.S. losses and in years 2024 through 2034 for foreign losses. However, U.S. losses generated after
December 31, 2017, totaling $5.1 million, can be carried forward indefinitely. As of December 31, 2023, our U.S. corporate operations have a capital loss carryforward for tax purposes totaling $17.7 million, which is subject to limitations on use and expires in 2024.
December 31, 2017, totaling $5.1 million, can be carried forward indefinitely. As of December 31, 2023, our U.S. corporate operations have a capital loss carryforward for tax purposes totaling $17.7 million, which is subject to limitations on use and expires in 2024.
As of December 31, 2023 and 2022, we have a valuation allowance of $22.9 million and $21.6 million, respectively, related to our deferred tax assets on net operating losses and capital losses. We estimate the amount of valuation allowance based upon our expectations of taxable income in the various jurisdictions in which we operate and the period over which we can utilize those future deductions. The valuation allowance reflects uncertainties related to our ability to utilize certain net operating loss carryforwards before they expire. In 2023, there was a $0.4 million decrease in the valuation allowance for the U.S. net operating loss and a $1.7 million increase in the foreign net operating loss valuation allowance due to changes in our estimates of the amount of loss carryforwards that will be realized, based upon future taxable income.
The realization of net deferred income tax assets recorded as of December 31, 2023 is dependent upon our ability to generate future taxable income in the United States. We believe it is more likely than not that the net deferred income tax assets as of December 31, 2023 will be realized, based on expected future taxable income.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
24. SEGMENT INFORMATION
Our reportable business segments consist of the pipeline, storage and fuels marketing segments. Our segments represent strategic business units that offer different services and products. We evaluate the performance of each segment based on its respective operating income, before general and administrative expenses and certain non-segmental depreciation and amortization expense. General and administrative expenses are not allocated to the operating segments since those expenses relate primarily to the overall management at the entity level. We are primarily engaged in the transportation, terminalling and storage of petroleum products and renewable fuels and the transportation of anhydrous ammonia. We also market petroleum products.
Results of operations for the reportable segments were as follows:
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (Thousands of Dollars) | |||||||||||||||||
| Revenues: | |||||||||||||||||
| Pipeline | $ | 873,869 | $ | 828,191 | $ | 762,238 | |||||||||||
| Storage | 319,599 | 334,549 | 427,668 | ||||||||||||||
| Fuels marketing | 440,725 | 520,486 | 428,608 | ||||||||||||||
| Consolidation and intersegment eliminations | (6) | (3) | (14) | ||||||||||||||
| Total revenues | $ | 1,634,187 | $ | 1,683,223 | $ | 1,618,500 | |||||||||||
| Depreciation and amortization expense: | |||||||||||||||||
| Pipeline | $ | 175,930 | $ | 178,802 | $ | 179,088 | |||||||||||
| Storage | 75,052 | 73,076 | 87,500 | ||||||||||||||
| Segment depreciation and amortization expense | 250,982 | 251,878 | 266,588 | ||||||||||||||
| Other depreciation and amortization expense | 4,728 | 7,358 | 7,792 | ||||||||||||||
| Total depreciation and amortization expense | $ | 255,710 | $ | 259,236 | $ | 274,380 | |||||||||||
| Reconciliation of segment operating income to income before income tax expense: | |||||||||||||||||
| Pipeline | $ | 483,188 | $ | 438,670 | $ | 321,472 | |||||||||||
| Storage | 87,609 | 61,081 | 24,800 | ||||||||||||||
| Fuels marketing | 32,926 | 33,536 | 11,181 | ||||||||||||||
| Segment operating income | 603,723 | 533,287 | 357,453 | ||||||||||||||
| Gain on sale of assets | 41,075 | — | — | ||||||||||||||
| General and administrative expenses | 129,846 | 117,116 | 113,207 | ||||||||||||||
| Other depreciation and amortization expense | 4,728 | 7,358 | 7,792 | ||||||||||||||
| Operating income | 510,224 | 408,813 | 236,454 | ||||||||||||||
| Interest expense, net | (241,364) | (209,009) | (213,985) | ||||||||||||||
| Other income, net | 10,215 | 26,182 | 19,644 | ||||||||||||||
| Income before income tax expense | $ | 279,075 | $ | 225,986 | $ | 42,113 | |||||||||||
Revenues by geographic area are shown in the table below:
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (Thousands of Dollars) | |||||||||||||||||
| United States | $ | 1,628,215 | $ | 1,667,672 | $ | 1,582,672 | |||||||||||
| Foreign | 5,972 | 15,551 | 35,828 | ||||||||||||||
| Total revenues | $ | 1,634,187 | $ | 1,683,223 | $ | 1,618,500 | |||||||||||
99
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
For the years ended December 31, 2023, 2022 and 2021, Valero Energy Corporation accounted for approximately 22%, or $360.4 million, 18%, or $307.3 million, and 19%, or $308.5 million, of our revenues, respectively. These revenues were included in our pipeline and storage segments for the year ended December 31, 2023, and in all of our reportable business segments for the years ended December 31, 2022 and 2021. No other single customer accounted for 10% or more of our consolidated revenues.
Total amounts of property, plant and equipment, net by geographic area were as follows:
| December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| (Thousands of Dollars) | |||||||||||
| United States | $ | 3,234,544 | $ | 3,359,427 | |||||||
| Foreign | 47,993 | 43,656 | |||||||||
| Property, plant and equipment, net | $ | 3,282,537 | $ | 3,403,083 | |||||||
Total assets by reportable segment were as follows:
| December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| (Thousands of Dollars) | |||||||||||
| Pipeline | $ | 3,292,546 | $ | 3,360,685 | |||||||
| Storage | 1,398,929 | 1,438,609 | |||||||||
| Fuels marketing | 46,151 | 37,763 | |||||||||
| Total segment assets | 4,737,626 | 4,837,057 | |||||||||
| Other partnership assets | 158,766 | 136,629 | |||||||||
| Total assets | $ | 4,896,392 | $ | 4,973,686 | |||||||
Capital expenditures by reportable segment were as follows:
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (Thousands of Dollars) | |||||||||||||||||
| Pipeline | $ | 100,759 | $ | 90,430 | $ | 67,340 | |||||||||||
| Storage | 43,584 | 47,222 | 112,043 | ||||||||||||||
| Other partnership assets | 3,165 | 2,978 | 1,750 | ||||||||||||||
| Capital expenditures | $ | 147,508 | $ | 140,630 | $ | 181,133 | |||||||||||
25. SUBSEQUENT EVENT
On January 22, 2024, NuStar Energy entered into an Agreement and Plan of Merger (the Merger Agreement) with Sunoco LP, a Delaware limited partnership (Sunoco), Saturn Merger Sub, LLC, a Delaware limited liability company and a direct wholly owned subsidiary of Sunoco (Merger Sub), Riverwalk Logistics, L.P., NuStar GP, LLC, and Sunoco GP LLC, a Delaware limited liability company and sole general partner of Sunoco (the Sunoco GP). The Merger Agreement provides that, among other things and on the terms and subject to the conditions set forth therein, Sunoco will acquire NuStar Energy in an all-equity transaction by means of a merger of Merger Sub with and into NuStar Energy (the Merger) with NuStar Energy surviving the Merger as a subsidiary of Sunoco.
On the terms and subject to the conditions set forth in the Merger Agreement, at the effective time of the Merger (the Effective Time), each NuStar Energy common unit issued and outstanding immediately prior to the Effective Time will be converted into and shall thereafter represent the right to receive 0.400 of a common unit of Sunoco and, if applicable, cash in lieu of fractional units. In addition, prior to the Effective Time, we will declare and pay a special cash distribution to our common unitholders in the amount of $0.212 per common unit (the Special Distribution) (in addition to continuing to pay our quarterly distributions in the ordinary course, subject to certain conditions, until the Effective Time).
100
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Each Series A, B and C Preferred Unit issued and outstanding immediately prior to the Effective Time will remain issued and outstanding from and after the Effective Time as limited partnership interests of the surviving entity having the same terms as are applicable to the applicable series of NuStar Energy preferred unit immediately prior to the Effective Time.
The completion of the Merger is subject to the fulfillment or waiver of certain conditions, including, among others: approval and adoption by NuStar Energy’s common unitholders of the Merger Agreement and the transactions contemplated thereby, including the Merger; expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; and the effectiveness of the registration statement on Form S-4 to be filed by Sunoco pursuant to which Sunoco common units to be issued in connection with the Merger are registered with the U.S. Securities and Exchange Commission (the SEC).
The Merger Agreement contains termination rights for each of NuStar Energy and Sunoco. Upon termination of the Merger Agreement under specified circumstances, including the termination by Sunoco in the event of an adverse recommendation change by our Board of Directors or by NuStar Energy to accept a Superior Proposal (as defined in the Merger Agreement), NuStar Energy would be required to pay Sunoco a termination fee of approximately $90.3 million.
Concurrently with the entry into the Merger Agreement, NuStar Energy and Sunoco entered into an agreement (the Support Agreement) with Energy Transfer LP (Energy Transfer), a Delaware limited partnership and the sole member of the Sunoco GP. The Support Agreement provides, among other things, that Energy Transfer will not transfer its ownership interest in the Sunoco GP, any of the Sunoco incentive distribution rights owned by it or any material portion of the Sunoco common units owned by it prior to the Effective Time. Energy Transfer has also agreed to be bound by the terms of the non-solicitation provisions in the Merger Agreement with respect to competing proposals for Sunoco and the Sunoco GP and to abide by certain covenants with respect to regulatory approvals, SEC filings, confidentiality and litigation, among other things.
The foregoing descriptions of the Merger Agreement and the Support Agreement and the transactions contemplated thereby, including the Merger, are summaries, do not purport to be complete and are qualified in their entirety by reference to the full text of the Merger Agreement and the Support Agreement.
101
ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.CONTROLS AND PROCEDURES
DISCLOSURE CONTROLS AND PROCEDURES
Our management has evaluated, with the participation of the principal executive officer and principal financial officer of NuStar GP, LLC, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures were effective as of December 31, 2023.
INTERNAL CONTROL OVER FINANCIAL REPORTING
(a)Management’s Report on Internal Control over Financial Reporting.
Management’s report on NuStar Energy L.P.’s internal control over financial reporting appears in Item 8. “Financial Statements and Supplementary Data” of this Form 10-K, and is incorporated herein by reference.
(b)Attestation Report of the Registered Public Accounting Firm.
The report of KPMG LLP on NuStar Energy L.P.’s internal control over financial reporting appears in Item 8. “Financial Statements and Supplementary Data” of this Form 10-K, and is incorporated herein by reference.
(c)Changes in Internal Control over Financial Reporting.
There has been no change in our internal control over financial reporting that occurred during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.OTHER INFORMATION
(a) None.
(b) Rule 10b5-1 under the Securities Exchange Act of 1934, as amended, provides an affirmative defense that enables prearranged transactions in securities in a manner that avoids concerns about initiating transactions at a future date while possibly in possession of material nonpublic information. Our Insider Trading Policy permits our directors and executive officers to enter into trading plans designed to comply with Rule 10b5-1. During the three-month period ending December 31, 2023, we did not adopt or terminate and none of our executive officers or directors adopted or terminated a Rule 10b5-1 trading plan or a non-Rule 10b5-1 trading arrangement (as defined in Item 408(c) of Regulation S-K).
ITEM 9C.DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
102
PART III
ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information required to be disclosed under this Item 10. is incorporated by reference to the following sections of our Proxy Statement for the 2024 annual meeting of unitholders (Proxy Statement), which is expected to be filed within 120 days after the end of the fiscal year covered by this Form 10-K: “Corporate Governance;” “Proposal No. 1 Election of Directors;” “Information About Our Executive Officers,” and “Compensation Discussion and Analysis–Compensation Related Policies.”
ITEM 11. EXECUTIVE COMPENSATION
Information required to be disclosed under this Item 11. is incorporated by reference to the following sections of our Proxy Statement: “Compensation Discussion and Analysis;” “Evaluation of Compensation Risk;” “Summary Compensation Table;” “Pay Ratio;” “Grants of Plan-Based Awards During the Year Ended December 31, 2023;” “Outstanding Equity Awards at December 31, 2023;” “Option Exercises and Units Vested During the Year Ended December 31, 2023;” “Pension Benefits for the Year Ended December 31, 2023;” “Nonqualified Deferred Compensation for the Year Ended December 31, 2023;” “Potential Payments Upon Termination or Change of Control;” “Pay Versus Performance;” “Director Compensation;” “Corporate Governance-Compensation Committee Interlocks and Insider Participation;” “Compensation Committee Report;” “Corporate Governance-Board Structure and Governance;” and “Corporate Governance–Committees of the Board.”
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS
Information required to be disclosed under this Item 12. is incorporated by reference to the following sections of our Proxy Statement: “Security Ownership.”
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Information required to be disclosed under this Item 13. is incorporated by reference to the following sections of our Proxy Statement: “Corporate Governance-Director Independence;” “Corporate Governance–Board Structure and Governance;” and “Certain Relationships and Related Party Transactions.”
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Our independent registered public accounting firm is KPMG LLP, San Antonio, Texas, Auditor Firm ID: 185.
Information required to be disclosed under this Item 14. is incorporated by reference to the following sections of our Proxy Statement: “KPMG Fees;” and “Audit Committee Pre-Approval Policy.”
103
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
| (a) | (1) | Financial Statements. The following consolidated financial statements of NuStar Energy L.P. and its subsidiaries are included in Part II, Item 8 of this Form 10-K: | ||||||||||||
| (2) | Financial Statement Schedules and Other Financial Information. No financial statement schedules are submitted because either they are inapplicable or because the required information is included in the consolidated financial statements or notes thereto. | |||||||||||||
| (3) | Exhibits. | |||||||||||||
The following are filed or furnished, as applicable, as part of this Form 10-K: | ||||||||||||||
| Exhibit Number | Description | Incorporated by Reference to the Following Document | ||||||||||||
| 2.01 | NuStar Energy L.P.’s Current Report on Form 8-K filed January 22, 2024 (File No. 001-16417), Exhibit 2.01 | |||||||||||||
| 3.01 | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.3 | |||||||||||||
| 3.02 | NuStar Energy L.P.’s Current Report on Form 8-K filed March 27, 2007 (File No. 001-16417), Exhibit 3.01 | |||||||||||||
| 3.03 | NuStar Energy L.P.’s Current Report on Form 8-K filed July 20, 2018 (File No. 001-16417), Exhibit 3.1 | |||||||||||||
| 3.04 | NuStar Energy L.P.’s Current Report on Form 8-K filed January 22, 2024 (File No. 001-16417), Exhibit 2.01 | |||||||||||||
| 3.05 | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.8 | |||||||||||||
| 3.06 | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2007 (File No. 001-16417), Exhibit 3.03 | |||||||||||||
| 3.07 | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2014 (File No. 001-16417), Exhibit 3.09 | |||||||||||||
| 3.08 | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.9 | |||||||||||||
| 3.09 | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2001 (File No. 001-16417), Exhibit 4.1 | |||||||||||||
104
| Exhibit Number | Description | Incorporated by Reference to the Following Document | ||||||||||||
| 3.10 | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.10 | |||||||||||||
| 3.11 | NuStar Energy L.P.’s Registration Statement on Form S-1 filed August 14, 2000 (File No. 333-43668), Exhibit 3.7 | |||||||||||||
| 3.12 | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.16 | |||||||||||||
| 3.13 | NuStar Energy L.P.’s Registration Statement on Form S-1 filed August 14, 2000 (File No. 333-43668), Exhibit 3.9 | |||||||||||||
| 3.14 | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.14 | |||||||||||||
| 3.15 | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2007 (File No. 001-16417), Exhibit 3.02 | |||||||||||||
| 3.16 | NuStar Energy L.P.’s Current Report on Form 8-K filed July 20, 2018 (File No. 001-16417), Exhibit 3.2 | |||||||||||||
| 4.01 | * | |||||||||||||
| 4.02 | NuStar Energy L.P.’s Current Report on Form 8-K filed July 15, 2002 (File No. 001-16417), Exhibit 4.1 | |||||||||||||
| 4.03 | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.02 | |||||||||||||
| 4.04 | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2008 (File No. 001-16417), Exhibit 4.05 | |||||||||||||
| 4.05 | NuStar Energy L.P.’s Current Report on Form 8-K filed April 28, 2017 (File No. 001-16417), Exhibit 4.4 | |||||||||||||
| 4.06 | NuStar Energy L.P.’s Current Report on Form 8-K filed May 22, 2019 (File No. 001-16417), Exhibit 4.3 | |||||||||||||
105
| Exhibit Number | Description | Incorporated by Reference to the Following Document | ||||||||||||
| 4.07 | NuStar Energy L.P.’s Current Report on Form 8-K filed September 14, 2020 (File No. 001-16417), Exhibit 4.3 | |||||||||||||
| 4.08 | NuStar Energy L.P.’s Current Report on Form 8-K filed January 22, 2013 (File No. 001-16417), Exhibit 4.1 | |||||||||||||
| 4.09 | NuStar Energy L.P.’s Current Report on Form 8-K filed January 22, 2013 (File No. 001-16417), Exhibit 4.2 | |||||||||||||
| 4.10 | NuStar Energy L.P.’s Current Report on Form 8-K filed June 29, 2018 (File No. 001-16417), Exhibit 4.2 | |||||||||||||
| 10.01 | NuStar Energy L.P.’s Current Report on Form 8-K filed January 31, 2022 (File No. 001-16417), Exhibit 10.01 | |||||||||||||
| 10.02 | NuStar Energy L.P.’s Current Report on Form 8-K filed June 30, 2023 (File No. 001-16417), Exhibit 10.01 | |||||||||||||
| 10.03 | NuStar Energy L.P.’s Current Report on Form 8-K filed June 5, 2020 (File No. 001-16417), Exhibit 10.1 | |||||||||||||
| 10.04 | NuStar Energy L.P.’s Current Report on Form 8-K filed June 5, 2020 (File No. 001-16417), Exhibit 10.2 | |||||||||||||
| 10.05 | NuStar Energy L.P.’s Current Report on Form 8-K filed July 21, 2010 (File No. 001-16417), Exhibit 10.01 | |||||||||||||
| 10.06 | NuStar Energy L.P.’s Current Report on Form 8-K filed June 5, 2020 (File No. 001-16417), Exhibit 10.4 | |||||||||||||
| 10.07 | NuStar Energy L.P.’s Current Report on Form 8-K filed June 5, 2020 (File No. 001-16417), Exhibit 10.5 | |||||||||||||
106
| Exhibit Number | Description | Incorporated by Reference to the Following Document | ||||||||||||
| 10.08 | NuStar Energy L.P.’s Current Report on Form 8-K filed June 5, 2020 (File No. 001-16417), Exhibit 10.6 | |||||||||||||
| 10.09 | NuStar Energy L.P.’s Current Report on Form 8-K filed December 30, 2010 (File No. 001-16417), Exhibit 10.01 | |||||||||||||
| 10.10 | NuStar Energy L.P.’s Current Report on Form 8-K filed June 5, 2020 (File No. 001-16417), Exhibit 10.8 | |||||||||||||
| 10.11 | NuStar Energy L.P.’s Current Report on Form 8-K filed August 10, 2011 (File No. 001-16417), Exhibit 10.01 | |||||||||||||
| 10.12 | NuStar Energy L.P.’s Current Report on Form 8-K filed June 5, 2020 (File No. 001-16417), Exhibit 10.10 | |||||||||||||
| 10.13 | NuStar Energy L.P.'s Current Report on Form 8-K filed June 19, 2015 (File No. 001-16417), Exhibit 10.1 | |||||||||||||
| 10.14 | NuStar Energy L.P.'s Current Report on Form 8-K filed June 19, 2015 (File No. 001-16417), Exhibit 10.2 | |||||||||||||
| 10.15 | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2015 (File No. 001-16417), Exhibit 10.26 | |||||||||||||
| 10.16 | NuStar Energy L.P.’s Current Report on Form 8-K filed September 20, 2017 (File No. 001-16417), Exhibit 10.01 | |||||||||||||
| 10.17 | NuStar Energy L.P.’s Current Report on Form 8-K filed September 20, 2017 (File No. 001-16417), Exhibit 10.02 | |||||||||||||
| 10.18 | NuStar Energy L.P.’s Current Report on Form 8-K filed March 28, 2018 (File No. 001-16417), Exhibit 10.01 | |||||||||||||
107
| Exhibit Number | Description | Incorporated by Reference to the Following Document | ||||||||||||
| 10.19 | NuStar Energy L.P.’s Current Report on Form 8-K filed April 29, 2019 (File No. 001-16417), Exhibit 10.1 | |||||||||||||
| 10.20 | NuStar Energy L.P.’s Current Report on Form 8-K filed September 3, 2020 (File No. 001-16417), Exhibit 10.01 | |||||||||||||
| 10.21 | NuStar Energy L.P.’s Current Report on Form 8-K filed January 31, 2022 (File No. 001-16417), Exhibit 10.02 | |||||||||||||
| 10.22 | NuStar Energy L.P.’s Current Report on Form 8-K filed June 30, 2023 (File No. 001-16417), Exhibit 10.02 | |||||||||||||
| +10.23 | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2017 (File No. 001-16417), Exhibit 10.30 | |||||||||||||
| +10.24 | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2017 (File No. 001-16417), Exhibit 10.31 | |||||||||||||
| +10.25 | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2016 (File No. 001-16417), Exhibit 10.28 | |||||||||||||
| +10.26 | NuStar GP Holdings, LLC’s Quarterly Report on Form 10-Q for quarter ended June 30, 2007 (File No. 001-32040), Exhibit 10.04 | |||||||||||||
| +10.27 | NuStar GP Holdings, LLC’s Annual Report on Form 10-K for year ended December 31, 2017 (File No. 001-32040), Exhibit 10.46 | |||||||||||||
| +10.28 | NuStar Energy L.P.’s Current Report on Form 8-K filed July 20, 2018 (File No. 001-16417), Exhibit 10.1 | |||||||||||||
| +10.29 | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2018 (File No. 001-16417), Exhibit 10.06 | |||||||||||||
| +10.30 | NuStar Energy L.P.’s Current Report on Form 8-K filed April 23, 2019 (File No. 001-16417), Exhibit 10.2 | |||||||||||||
| +10.31 | NuStar Energy L.P.’s Current Report on Form 8-K filed April 23, 2019 (File No. 001-16417), Exhibit 10.3 | |||||||||||||
| +10.32 | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2020 (File No. 001-16417), Exhibit 10.11 | |||||||||||||
| +10.33 | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2020 (File No. 001-16417), Exhibit 10.43 | |||||||||||||
| +10.34 | NuStar Energy L.P.’s Current Report on Form 8-K filed April 28, 2023 (File No. 001-16417), Exhibit 10.1 | |||||||||||||
108
| Exhibit Number | Description | Incorporated by Reference to the Following Document | ||||||||||||
| +10.35 | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2021 (File No. 001-16417), Exhibit 10.02 | |||||||||||||
| +10.36 | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2021 (File No. 001-16417), Exhibit 10.35 | |||||||||||||
| +10.37 | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2021 (File No. 001-16417), Exhibit 10.36 | |||||||||||||
| +10.38 | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2022 (File No. 001-16417), Exhibit 10.03 | |||||||||||||
| +10.39 | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2022 (File No. 001-16417), Exhibit 10.37 | |||||||||||||
| +10.40 | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2022 (File No. 001-16417), Exhibit 10.38 | |||||||||||||
| +10.41 | * | |||||||||||||
| +10.42 | * | |||||||||||||
| +10.43 | * | |||||||||||||
| +10.44 | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2006 (File No. 001-16417), Exhibit 10.18 | |||||||||||||
| +10.45 | NuStar Energy L.P.’s Current Report on Form 8-K filed August 4, 2016 (File No. 001-16417), Exhibit 10.1 | |||||||||||||
| +10.46 | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2015 (File No. 001-16417), Exhibit 10.45 | |||||||||||||
| +10.47 | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2018 (File No. 001-16417), Exhibit 10.04 | |||||||||||||
| +10.48 | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2008 (File No. 001-16417), Exhibit 10.30 | |||||||||||||
| +10.49 | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2017 (File No. 001-16417), Exhibit 10.02 | |||||||||||||
| +10.50 | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2018 (File No. 001-16417), Exhibit 10.05 | |||||||||||||
| 10.51 | NuStar Energy L.P.’s Current Report on Form 8-K filed March 21, 2023 (File No. 001-16417), Exhibit 10.1 | |||||||||||||
109
| Exhibit Number | Description | Incorporated by Reference to the Following Document | ||||||||||||
| 10.52 | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2009 (File No. 001-16417), Exhibit 10.24 | |||||||||||||
| 10.53 | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2017 (File No. 001-16417), Exhibit 10.02 | |||||||||||||
| 10.54 | NuStar Energy L.P.’s Current Report on Form 8-K filed January 22, 2024 (File No. 001-16417), Exhibit 10.01 | |||||||||||||
| 19.01 | * | |||||||||||||
| 21.01 | * | |||||||||||||
| 22.01 | * | |||||||||||||
| 23.01 | * | |||||||||||||
| 24.01 | * | |||||||||||||
| 31.01 | * | |||||||||||||
| 31.02 | * | |||||||||||||
| 32.01 | ** | |||||||||||||
| 32.02 | ** | |||||||||||||
| 97.01 | * | |||||||||||||
| 101.INS | Inline XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | * | ||||||||||||
| 101.SCH | Inline XBRL Taxonomy Extension Schema Document | * | ||||||||||||
| 101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase Document | * | ||||||||||||
| 101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document | * | ||||||||||||
| 101.LAB | Inline XBRL Taxonomy Extension Label Linkbase Document | * | ||||||||||||
| 101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase Document | * | ||||||||||||
| 104 | Cover page Interactive Data File - Formatted in Inline XBRL and contained in Exhibit 101 | * | ||||||||||||
110
| * | Filed herewith. | ||||
| ** | Furnished herewith. | ||||
| + | Identifies management contracts or compensatory plans or arrangements required to be filed as an exhibit hereto pursuant to Item 15 of Form 10-K. | ||||
An electronic copy of this Form 10-K is available on our website, free of charge, at www.nustarenergy.com
(select the “Investors” link, then the “SEC Filings” link). A paper copy of the Form 10-K also is available without charge to unitholders upon written request at the address below. Copies of exhibits filed as a part of this Form 10-K may be obtained by unitholders of record at a charge of $0.15 per page, minimum $5.00 each request. Direct inquiries to Corporate Secretary, NuStar Energy L.P., 19003 IH-10 West, San Antonio, Texas 78257 or
corporatesecretary@nustarenergy.com.
ITEM 16. FORM 10-K SUMMARY
Not applicable.
111
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| NUSTAR ENERGY L.P. | |||||
| (Registrant) | |||||
| By: | Riverwalk Logistics, L.P., its general partner | ||||
| By: NuStar GP, LLC, its general partner | |||||
| By: | /s/ Bradley C. Barron | ||||
| Bradley C. Barron | |||||
| Chairman of the Board, President and Chief Executive Officer | |||||
| February 22, 2024 | |||||
| By: | /s/ Thomas R. Shoaf | ||||
| Thomas R. Shoaf | |||||
| Executive Vice President and Chief Financial Officer | |||||
| February 22, 2024 | |||||
| By: | /s/ Jorge A. del Alamo | ||||
| Jorge A. del Alamo | |||||
| Senior Vice President - Chief Information Officer and Controller | |||||
| February 22, 2024 | |||||
112
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints Bradley C. Barron, Thomas R. Shoaf and Amy L. Perry, or any of them, each with power to act without the other, his or her true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any or all subsequent amendments and supplements to this Annual Report on Form 10-K, and to file the same, or cause to be filed the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto each said attorney-in-fact and agent full power to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he or she might or could do in person, hereby qualifying and confirming all that said attorney-in-fact and agent or his or her substitute or substitutes may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| Signature | Title | Date | ||||||
| /s/ Bradley C. Barron | Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer) | February 22, 2024 | ||||||
| Bradley C. Barron | ||||||||
| /s/ Thomas R. Shoaf | Executive Vice President and Chief Financial Officer (Principal Financial Officer) | February 22, 2024 | ||||||
| Thomas R. Shoaf | ||||||||
| /s/ Jorge A. del Alamo | Senior Vice President - Chief Information Officer and Controller (Principal Accounting Officer) | February 22, 2024 | ||||||
| Jorge A. del Alamo | ||||||||
| /s/ J. Dan Bates | Director | February 22, 2024 | ||||||
| J. Dan Bates | ||||||||
| /s/ Jelynne LeBlanc Burley | Director | February 22, 2024 | ||||||
| Jelynne LeBlanc Burley | ||||||||
| /s/ William B. Burnett | Director | February 22, 2024 | ||||||
| William B. Burnett | ||||||||
| /s/ Ed A. Grier | Director | February 22, 2024 | ||||||
| Ed A. Grier | ||||||||
| /s/ Dan J. Hill | Director | February 22, 2024 | ||||||
| Dan J. Hill | ||||||||
| /s/ Robert J. Munch | Director | February 22, 2024 | ||||||
| Robert J. Munch | ||||||||
| /s/ W. Grady Rosier | Director | February 22, 2024 | ||||||
| W. Grady Rosier | ||||||||
| /s/ Martin Salinas, Jr. | Director | February 22, 2024 | ||||||
| Martin Salinas, Jr. | ||||||||
| /s/ Suzanne Allford Wade | Director | February 22, 2024 | ||||||
| Suzanne Allford Wade | ||||||||
113
