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Table of Contents
Index to Financial Statements
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_______________________________________________
FORM 10-K
________________________________________________

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

For the Fiscal Year Ended December 31, 2025
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: 001-35653
_______________________________________________
SUNOCO LP
(Exact name of registrant as specified in its charter)
_______________________________________________

Delaware |  | 30-0740483
(State or other jurisdiction of incorporation or organization) |  | (I.R.S. Employer Identification Number)

8111 Westchester Drive, Suite 400, Dallas, Texas 75225
(Address of principal executive offices, including zip code)
Registrant’s telephone number, including area code: (214) 981-0700
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 Representing Limited Partner Interests | SUN | New York Stock Exchange

Securities registered pursuant to Section 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 ý No ☐
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 ☐ No ý
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 ý No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Registration 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 ý No ☐
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 | ý |  | 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. ☐
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. ☐
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). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ý
As of June 30, 2025, the aggregate market value of common units representing limited partner interests held by non-affiliates of the registrant was approximately $5.8 billion based upon the closing price of its common units on the New York Stock Exchange.
The registrant had 136,894,754 common units, 16,410,780 Class C Units and 51,517,198 Class D Units, each representing limited partner interests outstanding as of February 13, 2026.
Documents Incorporated by Reference: None

Table of Contents
Index to Financial Statements
SUNOCO LP
ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS

PART I
Item 1. Business | 5
Item 1A. Risk Factors | 21
Item 1B. Unresolved Staff Comments | 51
Item 1C. Cybersecurity | 51
Item 2. Properties | 53
Item 3. Legal Proceedings | 53
Item 4. Mine Safety Disclosures | 53
PART II
Item 5. Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities | 54
Item 6. [Reserved] | 55
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations | 55
Item 7A. Quantitative and Qualitative Disclosures About Market Risk | 69
Item 8. Financial Statements and Supplementary Data | 70
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure | 70
Item 9A. Controls and Procedures | 70
Item 9B. Other Information | 73
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections | 73
PART III
Item 10. Directors, Executive Officers and Corporate Governance | 73
Item 11. Executive Compensation | 78
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters | 91
Item 13. Certain Relationships and Related Transactions, and Director Independence | 94
Item 14. Principal Accountant Fees and Services | 96
PART IV
Item 15. Exhibits and Financial Statement Schedules | 97
Item 16. Form 10-K Summary | 97
SIGNATURES | 104

2

Table of Contents
Index to Financial Statements
Definitions
References to the “Partnership,” “Sunoco,” “we,” “us” and “our” refer to Sunoco LP and its consolidated subsidiaries. In addition, the following is a list of certain acronyms and terms used throughout this document:

AOCI |  | accumulated other comprehensive income (loss)
Burnaby Refinery |  | refinery located in Burnaby, British Columbia owned and operated by the Partnership, which was acquired in the Parkland Acquisition
Credit Facility |  | Sunoco LP's $2.50 billion revolving credit facility, which matures in June 2030
Energy Transfer |  | Energy Transfer LP (NYSE: ET)
EPA |  | United States Environmental Protection Agency
ET-S Permian |  | ET-S Permian Holdings Company LP, a joint venture between Sunoco LP and Energy Transfer, which owns crude oil and water gathering pipelines and storage assets in the Permian Basin
Exchange Act |  | Securities Exchange Act of 1934, as amended
FASB |  | Financial Accounting Standards Board
FERC |  | United States Federal Energy Regulatory Commission
FIFO |  | first-in, first-out
GAAP |  | accounting principles generally accepted in the United States of America
General Partner |  | Sunoco GP LLC, the general partner of Sunoco LP
IDRs |  | incentive distribution rights
IRS |  | United States Internal Revenue Service
Isla |  | Isla Dominicana de Petroleo Corporation
J.C. Nolan |  | collectively, J.C. Nolan Terminal Co., LLC and J.C. Nolan Pipeline Co., LLC, both of which are joint ventures between Sunoco LP and Energy Transfer, which own a diesel fuel storage terminal in Midland, Texas and a 500-mile diesel fuel pipeline
LIFO |  | last-in, first-out
NuStar |  | NuStar Energy L.P.
NuStar Acquisition |  | acquisition of NuStar completed on May 3, 2024
NuStar Logistics |  | NuStar Logistics L.P., a wholly owned subsidiary acquired in the NuStar Acquisition
NYSE |  | New York Stock Exchange
Parkland |  | Parkland Corporation
Parkland Acquisition |  | acquisition of Parkland completed on October 31, 2025
Partnership Agreement |  | Sunoco’s Third Amended and Restated Agreement of Limited Partnership, as amended to date
SARA |  | Societe Anonyme de la Raffinerie des Antilles refinery
SEC |  | United States Securities and Exchange Commission
Series A Preferred Units |  | 7.875% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
Sunoco Retail |  | Sunoco Retail LLC, a wholly owned corporate subsidiary of Sunoco LP
SunocoCorp |  | SunocoCorp LLC, a Delaware limited liability company (NYSE: SUNC), an affiliate which owns all of the Partnership's outstanding Class D Units
TanQuid |  | TanQuid GmbH & Co. KG, a subsidiary of the Partnership acquired on January 16, 2026
West Texas Sale |  | sale of 204 convenience stores in West Texas, New Mexico and Oklahoma completed on April 16, 2024

3

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Index to Financial Statements
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
Some of the information in this Annual Report on Form 10-K may contain forward-looking statements within the meaning of Section 21E of the Exchange Act. All statements, other than statements of historical fact included in this Annual Report on Form 10-K, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. Statements using words such as “believe,” “plan,” “could,” “expect,” “anticipate,” “intend,” “forecast,” “assume,” “estimate,” “continue,” “position,” “predict,” “project,” “goal,” “strategy,” “budget,” “potential,” “will” and other similar words or phrases are used to help identify forward-looking statements, although not all forward-looking statements contain such identifying words. Descriptions of our objectives, goals, targets, plans, strategies, costs, anticipated capital expenditures, expected cost savings and benefits are also forward-looking statements. These forward-looking statements are based on our current plans and expectations and involve a number of risks and uncertainties that could cause actual results and events to vary materially from the results and events anticipated or implied by such forward-looking statements, including:
•our ability to integrate acquisitions from affiliates or third parties, including the ability to successfully integrate Parkland's business;
•business strategy and operations of Energy Transfer and its conflicts of interest with us;
•changes in the price of and demand for the motor fuel that we distribute and our ability to appropriately hedge any motor fuel we hold in inventory;
•our dependence on limited principal suppliers;
•competition in the wholesale motor fuel distribution and retail store industry;
•changing customer preferences for alternate fuel sources or improvement in fuel efficiency;
•volatility of fuel prices or a prolonged period of low fuel prices and the effects of actions by, or disputes among or between, oil producing countries with respect to matters related to the price or production of oil;
•any acceleration of the domestic and/or international transition to a low carbon economy as a result of policy changes or otherwise;
•the possibility of cyber and malware attacks;
•changes in our credit rating, as assigned by rating agencies;
•a deterioration in the credit and/or capital markets, including as a result of recent increases in cost of capital resulting from Federal Reserve policies and changes in financial institutions’ policies or practices concerning businesses linked to fossil fuels;
•general economic conditions, including sustained periods of inflation, supply chain disruptions, new, increased and reciprocal tariffs and associated central bank monetary policies;
•environmental, tax and other federal, state and local laws and regulations;
•the macroeconomic, regulatory or other potential effects of a prolonged government shutdown;
•changes to, and the application of, regulation of tariff rates and operational requirements related to our joint ventures’ and subsidiaries’ interstate and intrastate pipelines, including the impact on the raw materials;
•political and economic conditions and events in the U.S. and in foreign oil, natural gas and NGL producing countries, including embargoes, political and regulatory changes implemented by the Trump Administration and foreign investments, continued hostilities in the Middle East, including the Israel-Hamas conflict, conflict with Iran and other sustained military campaigns, the armed conflict in Ukraine and associated economic sanctions on Russia, conditions in South America, including most recently in Venezuela, Central America and China and acts of terrorism or sabotage;
•the fact that we are not fully insured against all risks incident to our business;
•dangers inherent in the storage and transportation of motor fuel;
•our ability to manage growth and/or control costs;
•our ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results;
•our reliance on senior management, supplier trade credit and information technology; and
•our partnership structure, which may create conflicts of interest between us and our General Partner and its affiliates, and limits the fiduciary duties of our General Partner and its affiliates.
4

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Index to Financial Statements
All forward-looking statements, expressed or implied, are expressly qualified in their entirety by the foregoing cautionary statements.
New factors that could impact forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors. Should one or more of the risks or uncertainties described or referenced in this Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, actual results and plans could differ materially from those expressed in any forward-looking statements.
For a discussion of these and other risks and uncertainties, please refer to “Item 1A. Risk Factors” included herein. The list of factors that could affect future performance and the accuracy of forward-looking statements is illustrative but by no means exhaustive. Accordingly, all forward-looking statements should be evaluated with the understanding of their inherent uncertainty. The forward‑looking statements included in this report are based on, and include, our estimates as of the filing of this report. We anticipate that subsequent events and market developments will cause our estimates to change. However, while we may elect to update these forward-looking statements at some point in the future, we specifically disclaim any obligation to do so except as required by law, even if new information becomes available in the future.
In addition to risks and uncertainties in the ordinary course of business that are common to all businesses, important factors that are specific to our structure as a limited partnership, our industry and our company could materially impact our future performance and results of operations.
PART I
Item 1. Business
General
As used in this report, the terms “Partnership,” “Sunoco,” “we,” “us” or “our” should be understood to refer to Sunoco LP and our consolidated subsidiaries as applicable and appropriate.
Overview
We are a Delaware master limited partnership. We are managed by our General Partner, which is owned by Energy Transfer. As of February 13, 2026, Energy Transfer owned 100% of the membership interest in our General Partner, 28,463,967 of our common units and all of our IDRs. In addition, Energy Tra nsfer controls SunocoCorp, which owns all of the outstanding Class D Units representing limited partner interests in the Partnership (“Class D Units”) and pursuant to the Delegation Agreement (as defined below) has been delegated Energy Transfer’s power and authority to appoint the board of directors of our General Partner.
We are primarily engaged in energy infrastructure and distribution of motor fuels across 32 countries and territories in North America, the Greater Caribbean and Europe. Our midstream operations include an extensive network of over 14,000 miles of pipeline and over 160 terminals. Our fuel distribution operations distribute over 15 billion gallons annually to approximately 11,000 Sunoco and partner branded locations, as well as independent dealers and commercial customers.
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The following simplified diagram depicts our organizational structure as of February 13, 2026.
Significant Achievements in 2025
Parkland Acquisition
On October 31, 2025, we completed the previously announced acquisition of Parkland, whereby Sunoco Retail LLC (“Sunoco Retail”), a wholly owned corporate subsidiary of the Partnership, indirectly acquired all the outstanding shares of Parkland, in exchange for cash and SunocoCorp units that were contributed by SunocoCorp to the Partnership at the close of the Parkland Acquisition. Under the terms of the agreement, Parkland shareholders received 0.295 SunocoCorp units and C$19.80 for each Parkland share. Parkland shareholders could elect, in the alternative, to receive C$44.00 per Parkland share in cash or 0.536 SunocoCorp units for each Parkland share, subject to proration to ensure that the aggregate consideration payable in connection with the transaction would not exceed C$19.80 in cash per Parkland share outstanding as of immediately before close and 0.295 SunocoCorp units per Parkland share outstanding as of immediately before close. In connection with the closing of the Parkland Acquisition, we paid approximately $2.60 billion to Parkland’s shareholders and transferred 51,517,198 SunocoCorp common units, which we had received from SunocoCorp in exchange for our issuance of 51,517,198 Sunoco Class D Units to SunocoCorp.
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Parkland is a leading international fuel distributor, marketer and convenience retailer with operations in 26 countries across the Americas. Parkland’s functional currency is the Canadian dollar, and its consolidated structure includes subsidiaries with multiple other functional currencies.
As part of the transaction, the Partnership repurposed and renamed an existing subsidiary as SunocoCorp. Prior to the Parkland Acquisition, SunocoCorp did not have any significant assets, liabilities or operations; in connection with the Parkland Acquisition, the Partnership deconsolidated SunocoCorp and SunocoCorp became a publicly traded entity classified as a corporation for U.S. federal income tax purposes. SunocoCorp units began trading on the NYSE effective November 6, 2025. Subsequent to the Parkland Acquisition, SunocoCorp holds Sunoco Class D Units, representing limited partnership interests in Sunoco that are generally economically equivalent to Sunoco’s publicly traded common units on the basis of one Sunoco Common Unit for each outstanding SunocoCorp unit. For a period of two years following closing of the transaction, Sunoco will ensure that SunocoCorp unitholders receive distributions on a per unit basis that are equivalent to the per unit distributions to Sunoco unithold ers.
TanQuid Acquisition
On January 16, 2026, the Partnership completed the previously announced acquisition of TanQuid for approximately €465 million (approximately $540 million as of January 16, 2026), includ ing approximately €300 million of assumed debt, less approximately €39 million of cash acquired. TanQuid owns and operates 15 fuel terminals in Germany and one fuel terminal in Poland. The transaction was funded using cash on hand and amounts available under the Partnership's Credit Facility.
Other Acquisitions
In the first quarter of 2025, Sunoco acquired fuel equipment, motor fuel inventory and supply agreements in two separate transactions for total consideration of approximately $17 million. Aggregate consideration included $12 million in cash and 91,776 newly issued Sunoco Common Units, which had an aggregate acquisition-date fair value of approximately $5 million.
In the second quarter of 2025, Sunoco acquired a total of 151 fuel distribution consignment sites in three separate transactions for total consideration of approximately $105 million, plus working capital. Aggregate consideration included $92 million in cash and 251,646 newly issued Sunoco Common Units which had an aggregate acquisition-date fair value of approximately $13 million.
In the third quarter of 2025, Sunoco acquired approximately 70 fuel distribution consignment sites and 100 supply agreements in five separate transactions for total cash consideration of approximately $85 million, plus working capital.
In the fourth quarter of 2025, Sunoco acquired a total of 27 fuel distribution consignment sites and 36 dealer sites, as well as commercial customers, in four separate transactions for total cash consideration of approximately $64 million, plus working capital.
These transactions were accounted for as asset acquisitions, and the purchase price was primarily allocated to inventories, property, plant and equipment and other non-current assets.
Available Information
Our principal executive offices are located at 8111 Westchester Drive, Suite 400, Dallas, Texas 75225. Our telephone number is (214) 981-0700. Our Internet address is www.sunocolp.com. We make available through our website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as soon as reasonably practicable after we electronically file such material with, or furnish such material to, the SEC. Information contained on our website is not part of this report. The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC.
Our Relationship with Energy Transfer
One of our principal strengths is our relationship with Energy Transfer. As of February 13, 2026, Energy Transfer owned 100% of the membership interest in our General Partner, all of our IDRs and 28,463,967 of our common units and pursuant to the Delegation Agreement delegated its power and authority to appoint the board of directors of our General Partner to SunocoCorp, which is also controlled by Energy Transfer. Given the significant ownership, we believe Energy Transfer will be motivated to promote and support the successf ul execution of our business strategies. In particular, we believe it will be in the best interest of Energy Transfer to facilitate organic growth opportunities and accretive acquisitions of third parties, although Energy Transfer is not under any obligation to do so.
Energy Transfer is one of the largest and most diversified midstream energy companies in North America. Energy Transfer, through its wholly owned operating subsidiaries, is primarily engaged in:
•natural gas midstream, intrastate and interstate transportation and storage operations; and
•crude oil, natural gas liquids (“NGL”) and refined products transportation, terminalling services, and acquisition and marketing activities as well as NGL storage and fractionation services and liquefied natural gas (“LNG”) regasification.
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Our Business and Operations
Our business is comprised of four reportable segments: Fuel Distribution, Pipeline Systems, Terminals and Refinery.
The following map depicts the major assets of our business and excludes corporate and field offices and certain assets that are less significant to Sunoco. This map includes the assets of TanQuid, which the Partnership acquired on January 16, 2026; however, the descriptions of our business and operations by segment below exclude TanQuid, given the timing of the transaction subsequent to December 31, 2025.
Fuel Distribution Segment
We are a distributor of motor fuels and other petroleum products that we supply to customers that include third-party dealers and distributors, commission agent operators, and commercial businesses, in addition to our directly operated convenience retail facilities. We are the largest independent fuel distributor in the Americas and are the exclusive wholesale distributor of Sunoco, Aloha, Sol, Pioneer, Fas Gas, Ultramar and EcoMaxx-branded motor fuels, supplying an extensive distribution network of customer and company operated locations. We also are one of the largest distributors of Chevron, Texaco, ExxonMobil and Valero branded motor fuel in the Americas. The other petroleum products that we distribute include marine fuel, aviation fuel, propane and lubricating oil.
The fuel distribution channel also provides for revenue associated with credit card services, franchise royalty offerings, and rental income from controlled properties leased to independent operators.
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We purchase motor fuel primarily from independent refiners and major oil companies and distribute it across the United States, Canada and the Greater Caribbean to:
•approximately 9,200 retail facilities operated by independent customer operators, which we refer to as “dealers” or “distributors,” pursuant to long-term distribution agreements;
•approximately 1,300 independently operated commission agent locations where we sell motor fuel to customers under commission agent arrangements, which we refer to as “commission agents”;
•approximately 330 company operated convenience retail facilities; and
•over 13,000 other commercial businesses, including retail stores, other fuel distributors, municipalities and industrial customers.
Dealer and Distributor Business
In 2025, we distributed fuel under long-term contracts to our approximately 9,200 dealer and distributor customers. These customers buy fuel directly from us and sell the fuel to consumers at the pump. Sunoco-branded supply contracts generally have both time and volume commitments that establish contract duration. The supply contracts require, among other things, that the customers maintain the operating standards established by the applicable brand.
Commission Agent Business
During 2025, our Fuel Distribution business distributed fuel to approximately 1,300 commission agent locations. Under these arrangements, we control motor fuel inventory and price at the site. Similarly to our dealer and distributor business channels, the customers are responsible for operating standards established by the applicable brand.
The dealer, distributor and commission agent business channels continue to grow and remain an attractive part of our company performance. We continually seek to expand through the addition of new branded dealers, distributors and commission agent locations, new commercial customers and through acquisitions of contracts for existing independently operated sites from other distributors. We evaluate potential new customers based on the quality of their facilities and operations, including the facility’s size and location, projected monthly volumes of motor fuel, and operating experience. We may extend credit to certain customers based on our credit evaluation process.
Company Operated Retail Business
Sunoco owns and operates convenience retail facilities in desirable markets including Hawaii, certain markets of the US mainland and on the New Jersey Turnpike, which is one of the most heavily traveled highways in the nation. These directly operated facilities further provide for complementary revenue to our fuel distribution given their expanded service offerings including merchandise sales.
Unbranded Customers Business
We distribute unbranded fuel to numerous other customers, including retail facilities and commercial businesses, municipalities and a multitude of commercial company customers, which also remains an attractive and growing part of our fuel distribution business segment. These customers are primarily commercial, governmental and other parties who buy motor fuel by the load or in bulk and who do not always enter into exclusive contractual relationships with us. We also sell propane, lubricating oil and other petroleum products, such as heating fuels, to our customers on both a spot and contracted basis. With the addition of Parkland, Sunoco’s lubricant business now spans large portions of Canada, western U.S. and throughout the Caribbean. In addition, we receive income from the manufacture and distribution sale of race fuels at our Marcus Hook, Pennsylvania manufacturing facility.
Fuel Supplier Arrangements
We distribute branded motor fuel under the Aloha, Chevron, Citgo, Conoco, EcoMaxx, Exxon, Mahalo, Mobil, Phillips 66, Shamrock, Shell, Sunoco, Texaco and Valero brands. We purchase branded motor fuel from major oil companies and refiners under supply agreements. Our largest branded fuel suppliers in terms of volume are Chevron, Exxon, Phillips 66 and Valero. The branded fuel supply agreements generally have an initial term of three to five years.
We also distribute motor fuel, which we purchase in bulk, on a rack basis based upon prices posted by the refiner at a fuel supply terminal or on a contract basis with the price tied to one or more market indices.
Bulk Fuel Purchases
We purchase motor fuel in bulk and hold it in inventory or transport it via pipeline, barge, vessel, truck or rail. To mitigate inventory risk, we use commodity futures contracts or other derivative instruments, which are matched in quantity and timing to the anticipated usage of the inventory. We also blend in various additives, including ethanol and biomass-based diesel. We purchase fuel globally from Asia, Europe, Africa, South America and North America. Our scale of operation allows us to provide a lower cost of supply. This operation not only supplies our network but mitigates exposure to volatility, supply disruptions, and geopolitical risks.
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Transportation Logistics
We provide transportation logistics for most of our motor fuel deliveries through our own fleet of fuel transportation vehicles as well as third-party and affiliated transportation providers. In Canada, we predominately distribute through third-party carriers and independent brokers. We arrange for motor fuel to be delivered from the storage terminals to the appropriate sites in our distribution network at prices consistent with those historically charged to third parties for the delivery of fuel. We also deliver motor fuel, propane and lubricating oils to commercial customers involved in petroleum exploration and production.
We operate a waterborne logistics network, including the use of both Jones Act and foreign flag vessels, which is a critical component of our supply chain. The fleet supports sourcing crude and refined product barrels from diverse supply origins, including Asia, South America, U.S. Gulf Coast, Canada, and Europe, and facilitates delivery to downstream customers and storage locations. By maintaining a globally distributed sourcing footprint, we reduce reliance on any single region and capture arbitrage opportunities. The integration of our marine operations allows us to optimize inventory, manage transit times, and reduce overall logistics costs. Sunoco also operates blending operations across the U.S. East Coast, Gulf Coast and the Caribbean markets, creating additional supply advantages while meeting regulated specifications.
Technology
Technology is an important part of our Fuel Distribution segment. While our technology solutions can vary by country and acquisitions must be integrated, we utilize a proprietary web-based system that allows our wholesale customers to access their accounts at any time. We use Internet-based systems to assist with fuel inventory management and procurement and an integrated distribution fuel system for financial accounting, procurement, billing and inventory management.
Sale of Regulated Products
In certain areas where our convenience stores are located, state or local laws limit the hours of operation for the sale of alcoholic beverages and restrict the sale of alcoholic beverages and tobacco products to persons younger than a certain age. State and local regulatory agencies have the authority to approve, revoke, suspend or deny applications for and renewals of permits and licenses relating to the sale of alcoholic beverages, as well as to issue fines to convenience stores for the improper sale of alcoholic beverages and tobacco products. Failure to comply with these laws may result in the loss of necessary licenses and the imposition of fines and penalties on us.
Pipeline Systems Segment
Our Pipeline Systems segment includes an integrated pipeline and terminal network comprised of approximately 6,000 miles of refined product pipeline (including the pipeline of J.C. Nolan), approximately 6,000 miles of crude oil pipeline (including the pipelines of ET-S Permian), approximately 2,000 miles of ammonia pipeline and 69 terminals.
The following details our pipelines and storage facilities, excluding our investments in J.C. Nolan and ET-S Permian, in the Pipeline Systems segment:

Description of Assets |  |  |  | Miles of Pipeline |  | Storage Capacity (Barrels) |
Southwest Crude and Refined Products System |  |  |  |  |  |  |
Panhandle Refined Product System |  |  |  | 1,991 |  |  | 1,740,000 |  |
Panhandle Crude System |  |  |  | 547 |  |  | 1,795,000 |  |
Valley Refined Products System |  |  |  | 1,005 |  |  | 2,486,000 |  |
Valley Crude System |  |  |  | 474 |  |  | 6,117,000 |  |
Total Southwest Crude and Refined Products System |  |  |  | 4,017 |  |  | 12,138,000 |  |
Mid-Continent Refined Product System |  |  |  |  |  |  |
East Pipeline |  |  |  | 2,147 |  |  | 5,906,000 |  |
North Pipeline |  |  |  | 446 |  |  | 1,771,000 |  |
Total Mid-Continent Refined Product System |  |  |  | 2,593 |  |  | 7,677,000 |  |
Mid-Continent Ammonia System |  |  |  |  |  |  |
Ammonia Pipeline |  |  |  | 2,021 |  |  | 19,000 |  |
Total Ammonia System |  |  |  | 2,021 |  |  | 19,000 |  |
Total |  |  |  | 8,631 |  |  | 19,834,000 |  |

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J.C. Nolan
Through our investment in J.C. Nolan, we provide diesel fuel storage in Midland, Texas with storage capacity of 130,000 barrels, and transport diesel fuel from a tank farm in Hebert, Texas to Midland, Texas on a 500 mile pipeline with a throughput capacity of approximately 36 thousand barrels per day.
ET-S Permian
Through our investment in ET-S Permian, we operate more than 5,000 miles of crude oil and water gathering pipelines and provide crude oil storage capacity in excess of 11 million barrels.
Terminals Segment
Through our Terminals segment, we operate four transmix processing facilities and 83 terminals (two in Europe, six in Hawaii, nine in Canada, 13 in the Greater Caribbean and 53 in the continental United States). Transmix is the mixture of various off-specification refined products created in the supply chain (primarily in pipelines and terminals) when various products interface with each other. Transmix processing plants separate this mixture and return it to merchantable products of gasoline and distillates. Our terminals provide storage and distribution services to support our fuel distribution business and other third-party customers.
Refinery Segment
Our Refinery segment is composed of the Burnaby Refinery, which was acquired in the Parkland Acquisition, with an operational capacity of approximately 55,000 barrels per day. The refinery consumes primarily sweet conventional crude oil and sweet synthetic crude oil to produce gasoline, diesel and jet fuel among other products. The refinery meets federal and provincial regulations for lower carbon intensity transportation fuels through a combination of co-processing of bio feedstocks (i.e. canola oil, tallow, tall oil and others) and blending of low-carbon intensity fuels such as bio-diesel, renewable diesel, ethanol and others. Fuel from the refinery is sold primarily through Sunoco-owned retail network in British Columbia (“BC”), directly to Vancouver International Airport, and to commercial and cardlock customers.
SARA
Sunoco owns a 29% interest in SARA, which is a refinery based in Martinique with operations to sell refined crude oil in Guadeloupe, French Guiana and Martinique.
Real Estate and Lease Arrangements
As of December 31, 2025, our real estate and lease arrangements were as follows:

| Owned |  | Leased
Dealer and commission agent sites | 822 |  | 1,877
Company-operated retail stores | 732 |  | 605
Warehouses, offices and other | 307 |  | 210
Total | 1,861 |  |  | 2,692 |

Competition
In the Fuel Distribution segment, we compete primarily with other independent motor fuel distributors. The markets for distribution of motor fuel and the retail store industry are highly competitive and fragmented, which result in narrow margins. We have numerous competitors, some of which may have significantly greater resources and name recognition than we do. Significant competitive factors include the availability of major brands, customer service, price, range of services offered and quality of service, among others. We rely on our ability to provide value-added, reliable service and control our operating costs in order to maintain our margins and competitive position. Additionally, we face strong competition in the market for the sale of retail gasoline and merchandise. Our competitors include service stations of large integrated oil companies, independent gasoline service stations, convenience stores, fast food stores, supermarkets, drugstores, dollar stores, club stores and other similar retail outlets, some of which are well-recognized national or regional retail systems. The number of competitors varies depending on the geographical area. Competition also varies with gasoline and convenience store offerings. The principal competitive factors affecting our retail marketing operations include gasoline and diesel acquisition costs, site location, product price, selection and quality, site appearance and cleanliness, hours of operation, store safety, customer loyalty and brand recognition. We compete by pricing gasoline competitively, combining our retail gasoline business with convenience stores that provide a wide variety of products, and using advertising and promotional campaigns.
In the Pipeline Systems segment, we compete primarily with 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 noncompetitive with pipeline options for long-haul destinations or for larger volumes.
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In the Terminals segment, we compete primarily with both major energy and chemical companies as well as independent terminal owners. Although major energy and chemical company 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.
In the Refinery segment, our Burnaby Refinery competes with other refineries owned by major energy companies. The majority of the Burnaby Refinery’s production remains in British Columbia, Canada but faces competition with Alberta, Canada-based refineries which consume crude from Alberta, Canada and sell to the British Columbia market with transportation through the Trans Mountain Pipeline (“TMPL”) and other means. Competition is based primarily on transportation charges, reliability of supply and proximity to end users.
Seasonality
Our business exhibits some seasonality due to our customers’ increased demand for motor fuel during the late spring and summer months, as compared to the fall and winter months. Travel, recreation and construction activities typically increase in these months in the geographic areas in which we operate, increasing the demand for motor fuel. Therefore, the volume of motor fuel that we distribute is typically somewhat higher in the second and third quarters of our fiscal year. As a result, our results from operations may vary from period to period. Our commercial operations experience higher volumes in the winter months as a result of higher demand for diesel and heating oil in the winter.
Working Capital Requirements
Related to our retail store operations, we maintain customary levels of fuel and merchandise inventories and carry corresponding payable balances to suppliers of those inventories. In addition, Sunoco, LLC purchases and stores a significant amount of unbranded fuel in bulk. We also have rental obligations related to leased locations. Our working capital needs will typically fluctuate over the medium to long term with the price of crude oil, and over the short term due to the timing of motor fuel tax, sales tax, interest and rent payments.
Environmental Matters
Environmental Laws and Regulations
Sunoco is subject to various federal, state, p rovincial and local environmental laws and regulations, including those relating to underground storage tanks; the release or discharge of hazardous materials into the air, water and soil; the generation, storage, handling, use, transportation and disposal of regulated materials and wastes; the exposure of persons to regulated materials; and the remediation of contaminated soil, groundwater or other environmental media. For more information, see “Sunoco’s operations are subject to federal, state, provincial and local laws and regulations pertaining to environmental protection and operational safety that may require significant expenditures or result in liabilities that could have a material adverse effect on Sunoco’s business” in “Item 1A. Risk Factors” in this Annual Report on Form 10-K.
Environmental laws and regulations can restrict or impact Sunoco’s business activities in many ways, such as:
•requiring remedial action to mitigate releases of hydrocarbons, hazardous substances or wastes caused by its operations or attributable to former operators;
•requiring capital expenditures to comply with environmental control requirements; and
•enjoining the operations of facilities deemed to be in noncompliance with environmental laws and regulations.
Failure to comply with environmental laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining, imposing restrictions on or otherwise curtailing future operations. Certain environmental statutes impose strict, joint and
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several liability for costs required to clean up and restore sites where hydrocarbons, hazardous substances or wastes have been released or disposed of. Moreover, neighboring landowners and other third parties may file claims for personal injury and property damage allegedly caused by the release of hydrocarbons, hazardous substances or other wastes into the environment.
Sunoco does not believe that compliance with federal, state, provincial or local environmental laws and regulations will have a material adverse effect on its financial position, results of operations or cash available for distribution to its unitholders, including SunocoCorp. Any future change in regulatory requirements could cause it to incur significant costs. We incorporate by reference into this section the disclosures included in Note 15 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
Hazardous Substances and Releases
Certain environmental laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), impose strict, and under certain circumstances, joint and several, liability on the owner and operator as well as former owners and operators of properties for the costs of investigation, removal or remediation of contamination and also impose liability for any related damages to natural resources without regard to fault. In addition, under CERCLA and similar state laws, as persons who arrange for the transportation, treatment or disposal of hazardous substances, Sunoco also may be subject to similar liability at sites where such hazardous substances are released. Sunoco may also be subject to third-party claims alleging property damage and/or personal injury in connection with releases of or exposure to hazardous substances at, from or in the vicinity of, our current properties or off-site waste disposal sites.
Sunoco is required to comply with federal and state financial responsibility requirements to demonstrate that it has the ability to pay for remediation or to compensate third parties for damages incurred as a result of a release of regulated materials from its underground storage tank systems. It meets these requirements primarily by maintaining insurance, which it purchases from private insurers.
The Burnaby Refinery is subject to several federal, BC provincial and municipal laws, regulations and bylaws that apply to the assessment, management and disposal of pollution, toxic substances and hazardous wastes. For example, the BC Environmental Management Act (“BCEMA”) imposes absolute, retroactive, joint and several liability on several classes of responsible parties, including current or previous owners or operators of contaminated sites, and persons that generated or arranged for the transport of the contaminating substance that agreed to handle the substance in a manner that caused a site to become contaminated. In addition, the BCEMA requires Sunoco to develop and implement a spill contingency plan for the transport of certain hazardous substances, including aviation fuel, crude oil, gasoline and kerosene, by pipeline or highway.
At the federal level, the Canadian Environmental Protection Act (“CEPA”) imposes requirements for managing toxic substances and other pollution, including those related to petroleum storage tanks. Sunoco, along with certain corporate officers, may be subject to administrative fines, penalties and compliance orders for any failure to comply with these regulations. Sunoco is also subject to the federal Dangerous Goods Transportation Act and similar provincial laws and regulations when transporting or handling hazardous materials over road or water.
Environmental Reserves
Sunoco is currently involved in the investigation and remediation of contamination at motor fuel storage and gasoline store sites where releases of regulated substances have been detected. It accrues for anticipated future costs and the related probable state reimbursement amounts for remediation activities. Accordingly, it has recorded estimated undiscounted liabilities for these sites totaling $168 million as of December 31, 2025. As of December 31, 2025, Sunoco has additional reserves of $254 million that re present its estimate for future asset retirement obligations for underground storage tanks.
Underground Storage Tanks
Sunoco is required to make financial expenditures to comply with regulations governing underground storage tanks (“USTs”) adopted by federal, state and local regulatory agencies. Pursuant to the Resource Conservation and Recovery Act of 1976 (“RCRA”), as amended, the EPA has established a comprehensive regulatory program for the detection, prevention, investigation and cleanup of leaking underground storage tanks. State or local agencies are often delegated the responsibility for implementing the federal program or developing and implementing equivalent state or local regulations. Additionally, with respect to the Burnaby Refinery, the federal Storage Tank Systems for Petroleum Products and Allied Petroleum Products Regulations impose technical standards for design, installation, operation and removal of federally regulated tanks. Sunoco may be required in the future to remove USTs, aboveground storage tanks and in-ground lifts containing petroleum-based products and hazardous substances should they represent a risk of release or threatened release into the environment. Sunoco has a comprehensive program in place for performing routine tank testing and other compliance activities, which are intended to promptly detect and investigate any potential releases. To date, compliance with applicable underground or other petroleum storage tank requirements have not had a material adverse impact on Sunoco’s business, though we cannot guarantee this will always be the case.
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Air Emissions and Climate Change
The Clean Air Act and similar state laws impose requirements on emissions to the air from motor fueling, storage and transportation activities in certain areas of the country, including those that do not meet state or national ambient air quality standards. These laws and implementing regulations may require the installation of vapor recovery systems to control emissions of volatile organic compounds to the air during the motor fueling process or otherwise in the course of our operations. For example, in October 2024, the EPA finalized changes to its new source performance standards (“NSPS”) for new, modified and reconstructed storage vessels containing volatile organic liquids, a term which includes certain of our products. The EPA’s final rule created new NSPS subpart Kc, which broadened the definition of modification for storage tanks (which would result in significantly broader application of this rule to existing tanks), introduced more stringent emission control requirements for certain tanks, imposed additional annual monitoring requirements for certain tanks, and require control of degassing events, amongst other matters. Costs to comply with new rules under the Clean Air Act can be substantial. In addition, under the Clean Air Act and comparable state and local laws, permits are typically required to emit regulated air pollutants into the atmosphere. Although we can give no assurances, we are aware of no changes to air quality regulations that will have a material adverse effect on our financial condition, results of operations or cash available for distribution to our unitholders.
Various federal, state, provincial and local agencies have the authority to prescribe product quality and volatility specifications for the motor fuels that Sunoco sells, including with respect to products produced at the Burnaby Refinery, largely in an effort to reduce air pollution. Failure to comply with these regulations can result in substantial penalties. To date, compliance with applicable product quality and volatility specifications for motor fuels has not had a material adverse impact on Sunoco’s business, though we cannot guarantee this will always be the case.
In Canada, CEPA and similar provincial and local laws and regulations impose restrictions, permitting obligations and other requirements with respect to emissions of pollutants from industrial facilities, including the Burnaby Refinery. These laws and regulations require Sunoco to meet specified air contaminant emissions limits, undertake air quality monitoring activities, implement odor management activities and meet reporting obligations, among other requirements. Governmental authorities may also impose fees on emissions. If Sunoco fails to comply with applicable laws or permit obligations, it may be subject to significant fines and penalties.
In recent years, there have been a number of efforts at the federal, state and provincial levels focused on reducing greenhouse gas (“GHG”) emissions from various sources in the United States and in Canada. With respect to the United States, at both the state and the federal level, legislators have from time to time considered legislation to reduce GHG emissions in the United States such as a carbon emissions tax or a cap-and-trade program or direct emission regulation by the EPA. For example, in 2022 President Biden signed the Inflation Reduction Act of 2022 (“IRA 2022”) into law, which created significant incentives for renewable energy initiatives and imposed a fee on excess methane emissions from certain oil and gas facilities. The EPA issued a final rule implementing the fee in November 2024. However, in February 2025, Congress repealed the rule using the Congressional Review Act, and the One Big Beautiful Bill Act (“OBBBA”), enacted in July 2025, delayed implementation of the fee until 2034. We cannot predict with any certainty whether, how, or the timing for when the Trump Administration or Congress may take further action to repeal or revise this requirement in the IRA 2022. Notwithstanding the EPA’s recent final rule repealing the “Endangerment Finding” that underlies the majority of its GHG-related regulations, GHG emissions have been regulated by the EPA under previous administrations pursuant to the Clean Air Act as well as by state environmental authorities. For example, the EPA previously finalized new criteria pollutant and GHG emissions standards for light and medium-duty vehicles, including passenger cars, vans, pickups, sedans and sport utility vehicles for model years 2027 through 2032 and beyond. However, in February 2026, the EPA issued final rules rescinding the “Endangerment Finding” underpinning the majority of EPA’s GHG regulations and GHG emission standards for new motor vehicles and engines. Litigation challenging these rules is expected. As a result, there is significant uncertainty with respect to regulation of GHG emissions. Additionally, OBBBA eliminates electric vehicle credits previously available for new and used electric vehicles and commercial fleets. However, we cannot predict whether or not these regulatory repeals will ultimately be successful or if future administrations may seek to restore incentives and further promote or mandate the adoption of electric vehicles.
New federal or state restrictions on emissions of GHGs that may be imposed in areas of the United States in which Sunoco conducts business and that apply to its operations could adversely affect the demand for its products. However, on his first day in office, President Trump issued several Executive Orders rescinding many of the previous administration’s climate-related initiatives, including directing agencies to immediately pause the disbursement of certain funds, including funding for GHG mitigation projects. Even absent any significant GHG-related rulemakings in the near-term at the federal level, several states in which Sunoco operates, such as California, Colorado and Pennsylvania, may continue to aggressively pursue the regulation of GHG emissions.
With respect to Canada, legislators at the federal and provincial levels have implemented or proposed to implement a number of regulations pertaining to GHG emissions. For example, Sunoco is required to submit annual GHG emissions reports with respect to the Burnaby Refinery pursuant to the CEPA. Further, in 2018, Canada enacted the Greenhouse Gas Pollution Pricing Act, which set federal standards for carbon pricing and allowed federal and provincial governments to impose a “tax” on carbon emissions. However, in March 2025, Prime Minister Mark Carney removed the federal consumer carbon tax, and in April 2025, BC repealed the provincial
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consumer carbon tax. Future efforts to reinstate these taxes or otherwise impose fees on GHG emissions could have a material adverse impact on our business. At the provincial level, the BC Greenhouse Gas Industrial Reporting and Control Act (“GGIRCA”) imposes emissions performance standards and ongoing emissions reporting and reduction requirements for certain industrial facilities, with payment obligations to the provincial government for emissions in excess of statutory limits. The GGIRCA further establishes a compliance mechanism that includes creation, trading and usage of compliance credits, which are generated by facilities that emit GHGs below their specified limit or from specified offset project proponents.
The profitability of the Burnaby Refinery and its business are dependent upon opportunities and obligations to create, sell, purchase and retire compliance credits, legislated carbon-intensity standard considerations and legislated and market pricing stringency considerations in which such compliance credits are made to be tradeable. Changes impacting these credits, including changing market conditions may negatively impact Sunoco’s profitability or otherwise increase compliance costs, which may in turn adversely affect our Refinery Segment business and results of operations.
At the international level, the United States, Canada and 194 other countries previously reached an agreement during the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change (the “Paris Agreement”), a long-term, international framework convention designed to address climate change over the next several decades. However, in January 2025, President Trump issued an executive order withdrawing the United States from the Paris Agreement. In January 2026, President Trump announced the United States’ withdrawal from the United Nations Framework Convention on Climate Change. State or local governments may, however, elect to continue to participate in international climate change initiatives and pursue state- or regional-level climate change-related regulations. Any efforts to control and/or reduce GHG emissions by the United States or other countries, or concerted conservation efforts that result in reduced consumption, could adversely impact demand for Sunoco’s products and, in turn, our financial position and results of operations.
Climate change may also result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns that could adversely impact Sunoco’s operations or those of its supply chains. Such physical risks may result in damage to Sunoco’s facilities or its customers’ facilities or otherwise adversely impact its operations, such as to the extent changing weather and temperature trends reduce the demand for our products or frequency with which consumers may visit its locations or impact the cost or availability of insurance. Moreover, certain parties, including local and state governments, have from time to time filed lawsuits against various fossil fuel energy companies seeking damages for alleged physical impacts resulting from climate change or relating to false or misleading statements related to fossil fuel’s contribution to climate change. In addition, several states, including New York and Vermont, have passed climate change-related “Superfund” laws that seek to impose liability for alleged damages from climate change on certain types of entities. Other states are also considering the adoption of such laws. Further, there are increasing financial risks to companies in the fossil fuel sector as members of the general financial and investment communities increase sustainability considerations in their practices. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector, although this trend has waned in recent years. To the extent implemented or pursued, these efforts may adversely affect the market for our securities and our ability to access capital and financial markets in the future.
Separately, in March of 2024, the SEC has published a rule establishing a framework for reporting of climate risks, targets and metrics. However, the rule is currently paused pending litigation, with such litigation held in abeyance until the SEC reconsiders, repeals or otherwise modifies the rule. In March 2025, the SEC voted to end its defense of the rule, though further action has not been taken at this time to repeal the rule. Similarly, in October 2023 the Governor of California signed the Climate Corporate Data Accountability Act (“CCDAA”) and Climate-Related Financial Risk Act (“CRFRA”) into law. The CCDAA requires both public and private U.S. companies that are “doing business in California” and that have a total annual revenue of $1 billion to publicly disclose and verify, on an annual basis, Scope 1, 2, and 3 GHG emissions. Both laws are vague and potentially overbroad with respect to their applicability, appearing to require only minimal contacts with California. The CRFRA requires the disclosure of a climate-related financial risk report in line with certain stakeholder frameworks every other year for public and private companies that are “doing business in California” and have total annual revenue of $500 million. Reporting under both laws would begin in 2026; however, both the CCDAA and CRFRA are currently subject to litigation, and in November 2025, the U.S. Court of Appeals for the Ninth Circuit stayed enforcement of the CRFRA pending the outcome of litigation, and we cannot predict the final outcome. Currently, the ultimate impact of these laws on Sunoco’s business is uncertain, but to the extent implemented, Sunoco may face additional costs to comply with these disclosure requirements as well as increased costs of and restrictions on access to capital. Separately, enhanced climate related disclosure requirements could lead to reputational or other harm with customers, regulators, investors or other stakeholders and could also increase Sunoco’s litigation risks relating to alleged climate-related damages resulting from its operations, statements alleged to have been made by us or others in our industry regarding climate change risks, or in connection with any future disclosures Sunoco may make regarding reported emissions, particularly given the inherent uncertainties and estimations with respect to calculating and reporting GHG emissions. These various political, regulatory, financial, physical and litigation risks related to climate change have the potential to adversely impact Sunoco’s operations and financial performance.
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Water
The U.S. Federal Water Pollution Control Act, as amended, (the “Clean Water Act”), and analogous state laws, impose restrictions and strict controls regarding the discharge of pollutants into navigable waters of the United States (“WOTUS”). The definition of WOTUS has been subject to repeated change in recent years. Most recently, the EPA issued a final WOTUS rule in September 2023 that is currently only implemented in 24 states due to ongoing litigation. In November 2025, the EPA issued a proposed rule to further update and narrow the definition of WOTUS. To the extent any action further expands the scope of the Clean Water Act’s jurisdiction, it could cause increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Federal and state regulatory agencies can impose administrative, civil and/or criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act, and can also pursue injunctive relief to enforce compliance with the Clean Water Act and analogous laws. Spill prevention control and countermeasure requirements of federal and state laws require containment and equipment to monitor, mitigate or prevent contamination of waters in the event of a refined product overflow, rupture, or leak from above-ground pipelines and storage tanks. The Clean Water Act also requires Sunoco to maintain spill prevention control and countermeasure plans at its terminal facilities with above-ground storage tanks and pipelines.
The U.S. Oil Pollution Act of 1990 (“OPA 90”) amended certain provisions of the Clean Water Act as they relate to the release of petroleum products into navigable waters. OPA 90 subjects owners of facilities to strict, joint and potentially unlimited liability for containment and removal costs, natural resource damages and certain other consequences of an oil spill. State laws also impose requirements relating to the prevention of oil releases and the remediation of areas. In addition, the OPA 90 requires that most fuel transport and storage companies maintain and update various oil spill prevention and oil spill contingency plans. Facilities that are adjacent to water require the engagement of Federally Certified Oil Spill Response Organizations to be available to respond to a spill on water from above ground storage tanks or pipelines.
Transportation and storage of refined products over and adjacent to water involves risk and potentially subjects Sunoco to strict, joint, and potentially unlimited liability for removal costs and other consequences of an oil spill where the spill is into navigable waters, along shorelines or in the exclusive economic zone of the United States. In the event of an oil spill into navigable waters, substantial liabilities could be imposed upon us. The Clean Water Act imposes restrictions and strict controls regarding the discharge of pollutants into navigable waters, with the potential of substantial liability for the violation of permits or permitting requirements.
In Canada, the BCEMA and other federal, provincial and local laws, such as the Petroleum Refinery Liquid Effluent Regulations issued under the federal Fisheries Act, impose permitting obligations and restrictions on the direct and indirect discharge of wastes and deleterious materials into land and water. Governmental authorities can impose administrative penalties or other regulatory consequences for failure to comply with these laws or permits issued thereunder or for harm to sensitive marine populations or their habitat, which penalties can be significant.
Environmental Reviews
If permits or other authorizations from the federal government are required, Sunoco’s future operations may be subject to broad environmental review under the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies to evaluate the environmental impacts of all “major federal actions” significantly affecting the quality of the human environment, which may include the granting of a federal permit for a major development project, such as a pipeline. Procedures for implementing NEPA vary at the agency level, and in their evaluations, agencies may consider impacts of the proposed action on air and water quality, wildlife, cultural resources, geology, socioeconomics and aesthetics. As a result of NEPA reviews, agencies may decide to deny permits or other authorizations for a project or to condition such authorizations on modifications or mitigation measures. Further, authorizations and reviews under NEPA are often subject to appeal or litigation, which may lead to further delays.
Endangered Species
The Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats. While some of Sunoco’s operations may be located in areas that are designated as habitats for such species, Sunoco believes that it is in substantial compliance with the ESA. However, the designation of previously unlisted or threatened species could cause Sunoco to incur additional costs or become subject to operating restrictions in the affected areas.
Pipeline Safety Regulation
Some of Sunoco’s pipelines are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), pursuant to the Hazardous Liquids Pipeline Safety Act of 1979 (“HLPSA”). The HLPSA was amended by the Pipeline Safety Act of 1992, the Accountable Pipeline Safety and Partnership Act of 1996, the Pipeline Safety Improvement Act of 2002 (“PSIA”), as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (“2011 Pipeline Safety Act”) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020. The HLPSA regulates safety requirements in the design, construction, operation and maintenance of crude oil and NGL pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. crude oil, NGLs and hazardous liquid transmission pipelines in certain high risk areas, such as high-consequence areas (“HCAs”) or moderate consequence areas (“MCAs”).
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In October 2025, members of Congress introduced the Pipeline Safety Act of 2025, which would reauthorize appropriation for PHMSA and modernize pipeline safety regulations.
PHMSA has developed regulations that require pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in HCAs and MCAs. The regulations require operators, including us, to:
•perform ongoing assessments of pipeline integrity;
•identify and characterize applicable threats to pipeline segments that could impact certain high risk areas;
•improve data collection, integration and analysis;
•repair and remediate pipelines as necessary; and
•implement preventive and mitigating actions.
The 2011 Pipeline Safety Act, among other things, increased the maximum civil penalty for pipeline safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in HCAs. Consistent with the 2011 Pipeline Safety Act, PHMSA finalized rules that increased the maximum administrative civil penalties for violation of the pipeline safety laws and regulations to $200,000 per violation per day, with a maximum of $2,000,000 for a related series of violations. In December 2024, those maximum civil penalties were increased to $272,926 and $2,729,245, respectively, to account for inflation. The PHMSA has also issued a final rule applying safety regulations to certain rural low-stress hazardous liquid pipelines that were not covered previously by some of its safety regulations.
Following legislation enacted by Congress, PHMSA has issued or proposed regulations that either seek to impose new obligations on pipeline operations or expand existing pipeline safety requirements. In the Fiscal Year 2021 Omnibus Appropriations Bill, Congress authorized PHMSA’s spending through fiscal year 2023 and directed the Agency to move forward with several regulatory actions: the promulgation of rules related to changes in class location of existing pipelines, pipeline integrity and maintenance, and the management of idled pipelines, amongst other matters. An example of PHMSA’s rulemaking under this directive was a 2022 rule, expanding regulations for the installation of rupture mitigation valves and establishing of a minimum rupture detection standard. PHMSA also released final regulations in January 2025 related to the management of methane emissions from pipelines, but the Trump Administration subsequently withdrew these regulations before formal publication in the Federal Register, and PHMSA has not announced any intention to re-propose these or any similar rules. Separately, on July 1, 2025 and August 21, 2025, PHMSA issued final rules amending its pipeline safety regulations to incorporate updated industry standards. However, in September 2025, industry groups requested a stay of enforcement of the July 2025 final rule, and PHMSA stated it would use its enforcement discretion to allow regulated entities to operate under the outdated industry standards through January 1, 2027. We cannot predict the capital and operating expenditures related to Sunoco’s compliance with future PHMSA rulemakings, and such rulemakings may require it to incur significant costs to maintain compliance.
States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. States may adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines; however, states vary considerably in their authority and capacity to address pipeline safety. State standards may include requirements for facility design and management in addition to requirements for pipelines. We do not anticipate any significant difficulty in complying with applicable state laws and regulations; however, we cannot guarantee that this will or will always be the case.
Sunoco regularly reviews all existing and proposed pipeline safety requirements and work to incorporate the new requirements into procedures and budgets. Sunoco expects to incur increasing regulatory compliance costs, based on the intensification of the regulatory environment and upcoming changes to regulations as outlined above, consistent with other similarly situated midstream companies. In addition to regulatory changes, costs may be incurred if there is an accidental release of a commodity transported by Sunoco’s system, or a regulatory inspection identifies a deficiency in its required programs and corrective action is required.
Regulation of Interstate Crude Oil and Products Pipelines
Interstate common carrier pipeline operations are subject to rate regulation by the FERC under the Interstate Commerce Act (“ICA”), the Energy Policy Act of 1992 (“EPAct of 1992”), and related rules and orders. The ICA requires that tariff rates for petroleum pipelines be “just and reasonable” and not unduly discriminatory and that such rates and terms and conditions of service be filed with the FERC. This statute also permits interested persons to challenge proposed new or changed rates. The FERC is authorized to suspend the effectiveness of such rates for up to seven months, though rates are typically not suspended for the maximum allowable period. If the FERC finds that the new or changed rate is unlawful, it may require the carrier to pay refunds for the period that the rate was in effect. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a
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carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.
The FERC generally has not investigated interstate rates on its own initiative when those rates, like those Sunoco charges, have not been the subject of a protest or a complaint by a shipper. However, the FERC could investigate Sunoco’s rates at the urging of a third party if the third party is either a current shipper or has a substantial economic interest in the tariff rate level. Although no assurance can be given that the tariff rates charged by Sunoco ultimately will be upheld if challenged, management believes that the tariff rates now in effect for Sunoco’s pipelines are within the maximum rates allowed under current FERC policies and precedents.
Sunoco is able to use various FERC-authorized rate change methodologies for its interstate pipelines, including indexed rates, cost-of-service rates, market-based rates and negotiated rates. Typically, it adjusts its 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 a 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.
To the extent Sunoco relies on cost-of-service ratemaking to establish or support its rates, the issue of the proper allowance for federal and state income taxes could arise. In July 2016, the United States Court of Appeals for the District of Columbia Circuit issued an opinion in United Airlines, Inc., et al. v. FERC, finding that the FERC had failed to demonstrate that permitting an interstate petroleum products pipeline organized as a master limited partnership, or MLP, to include an income tax allowance in the cost of service underlying its rates, in addition to the discounted cash flow return on equity, would not result in the pipeline partnership owners double recovering their income taxes. The court vacated the FERC’s order and remanded to the FERC to consider mechanisms for demonstrating that there is no double recovery as a result of the income tax allowance.
In March 2018, the FERC issued a Revised Policy Statement on Treatment of Income Taxes in which the FERC found that an impermissible double recovery results from granting an MLP pipeline both an income tax allowance and a return on equity pursuant to the FERC’s discounted cash flow methodology. The FERC revised its previous policy, stating that it would no longer permit an MLP pipeline to recover an income tax allowance in its cost of service. The FERC stated it will address the application of the United Airlines decision to non-MLP partnership forms as those issues arise in subsequent proceedings. In July 2018, the FERC dismissed requests for rehearing and clarification of the March 2018 Revised Policy Statement, but provided further guidance, clarifying that a pass-through entity will not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double recovery of investors’ income tax costs. On July 31, 2020, the United States Court of Appeals for the District of Columbia Circuit issued an opinion upholding FERC’s March 2018 Revised Policy Statement, as clarified and revised on rehearing. In light of the rehearing order’s clarification regarding individual entities’ ability to argue in support of recovery of an income tax allowance and the court’s subsequent opinion upholding denial of an income tax allowance to a master limited partnership, the impacts the FERC’s policy on the treatment of income taxes may have on the rates an interstate pipeline held in a tax-pass-through entity can charge for the FERC regulated transportation services are unknown at this time.
Effective January 2018, the 2017 Tax Cuts and Jobs Act changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. With the lower tax rate, and as discussed immediately above, the tariff rates allowed by the FERC under its rate base methodology may be impacted by a lower income tax allowance component. The timing and impact to Sunoco’s pipelines of any tax-related policy change is unknown at this time and varies based on the circumstances of each pipeline.
The EPAct of 1992 required the FERC to establish a simplified and generally applicable methodology to adjust tariff rates for inflation for interstate petroleum pipelines. As a result, the FERC adopted an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPI-FG. The FERC’s indexing methodology is subject to review every five years.
The indexing methodology is applicable to existing rates, including grandfathered rates, with the exclusion of market-based rates. A pipeline is not required to raise its rates up to the index ceiling, but it is permitted to do so and rate increases made under the index are presumed to be just and reasonable unless a protesting party can demonstrate that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. Under the indexing rate methodology, in any year in which the index is negative, pipelines must file to lower their rates if those rates would otherwise be above the rate ceiling.
In December 2020, FERC issued an order setting the indexed rate at PPI-FG plus 0.78% during the five-year period commencing July 1, 2021 and ending June 30, 2026. The FERC received requests for rehearing of its December 17, 2020 order and on January 20, 2022, granted rehearing and modified the oil index. Specifically, for the five-year period commencing July 1, 2021 and ending June 30, 2026, FERC-regulated liquids pipelines charging indexed rates were permitted to adjust their indexed ceilings annually by PPI-FG minus 0.21%. FERC directed liquids pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022, as well as the ceiling levels for the period July 1, 2022 through June 30, 2023, based on the new index level. Where an oil pipeline’s filed rates exceeded its ceiling levels, FERC ordered such oil pipelines to reduce the rate to bring it into compliance with the recomputed ceiling level to be effective March 1, 2022. Some parties sought rehearing of the January 20 order with FERC, which was denied by FERC on
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May 6, 2022. Certain parties have appealed the January 20 and May 6 orders. On July 26, 2024, the D.C. Circuit ruled in LEPA v. FERC that FERC violated the Administrative Procedure Act because the January 20 order modified the index without following notice and comment. As a result, the D.C. Circuit vacated the January 20 order and on September 17, 2024, the Commission reinstated the index level established by its original December 17 order, directed pipelines to file an informational filing to show their recomputed ceiling levels reflecting the reinstated index level and stated that pipelines could file to prospectively increase their indexed rates to their recomputed levels. On October 17, 2024, FERC issued a Supplemental Notice of Proposed Rulemaking (“Supplemental NOPR”) that proposed a reduction to the then-currently effective index by one p ercent. On November 20, 2025, FERC withdrew the Supplemental NOPR and confirmed that the PPI-FG-0.78% index established in December 2020 will remain in place through June 30, 2026. On the same day, FERC approved limited relief for pipelines. Oil pipelines with index-based rates may recover applicable rate differences from March 1, 2022 to September 17, 2024, but only if such pipelines charged the maximum rate allowed under the applicable index ceiling during the relevant time period. Parties have since filed requests for clarification or rehearing, as well as court appeals, to determine whether pipelines may recover rate differences in other scenarios.
In addition to terminating the Supplemental NOPR proceeding, on November 20, 2025, FERC issued an Order Denying Rehearing of the Reinstatement Order and Granting Remedial Relief (“Remedial Relief Order”), which granted remedial relief to liquids pipelines for the locked-in period of March 1, 2022 to September 17, 2024, when the lower index was effective under the order vacated by the D.C. Circuit in LEPA v. FERC.
Also on November 20, 2025, the FERC issued a Notice of Proposed Rulemaking on the 2026 Five-Year Oil Pipeline Index (“2026 Index NOPR”), proposing to use the Producer Price Index for Finished Goods (PPI-FG) minus 1.42% as the index level beginning July 1, 2026 to June 30, 2031. The 2026 Index NOPR is currently in the midst of the standard notice and comment period.
On December 18, 2025, the Commission issued an Order Denying Petition for Emergency Relief (“Emergency Relief Order Denial”), which denied a petition requesting emergency relief from invoices issued by a liquid pipeline company to recover amounts of indexed rates for the period from March 1, 2022, to September 17, 2024 (Locked-In Period) and explained that, consistent with the Remedial Relief Order, pipelines that charged the maximum rates permitted under the Commission’s now-vacated January 2022 rehearing order during the Locked-In Period may invoice shippers to recover the amounts that would have been chargeable under the December 2020 order.
In January 2026, multiple shippers have filed petitions for review at the D.C. Circuit of the (i) Remedial Relief Order, (ii) Order Terminating Supplemental NOPR, and (iii) Emergency Relief Order Denial. These appeals are pending.
On December 15, 2022, the FERC issued a Proposed Policy Statement on Oil Pipeline Affiliate Committed Service, which addresses whether a contract for committed transportation service complies with the ICA where the only shipper to obtain the committed service is an affiliate of the regulated entity. If adopted, the proposed policy statement would create a rebuttable presumption that affiliate contracts are unduly discriminatory and not just and reasonable in certain circumstances and require a pipeline to produce additional evidentiary support for affiliate contracts rates and terms. This follows a trend of increased scrutiny by FERC on affiliated contracts across all industries regulated by the FERC. The FERC has taken no further action on the proposed policy statement.
Regulation of Intrastate Crude Oil and Products Pipelines
In addition to federally regulated 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.
In addition, as noted above, the rates, terms and conditions for shipments of crude oil or petroleum products on Sunoco’s pipelines could be subject to regulation by the FERC under the ICA and the EPAct of 1992 if the crude oil or petroleum products are transported in interstate or foreign commerce whether by its pipelines or other means of transportation. Since Sunoco does not control the entire transportation path of all crude oil or petroleum products shipped on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.
Regulation of Interstate Ammonia Pipelines
Our ammonia pipeline is subject to regulation by the Surface Transportation Board (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
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tariff which is posted publicly on Sunoco’s 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.
Other Government Regulation
The Petroleum Marketing Practices Act (the “PMPA”) is a federal law that governs the relationship between a refiner and a distributor, as well as between a distribut or and branded dealer, pursuant to which the refiner or distributor permits a distributor or dealer to use a trademark in connection with the sale or distribution of motor fuel. Under the PMPA, Sunoco may not terminate or fail to renew a branded distributor contract, unless certain enumerated preconditions or grounds for termination or non-renewal are met and it also complies with the prescribed notice requirements. Additionally, Sunoco is subject to state petroleum franchise laws as well as laws specific to gasoline retailers and dealers, including state laws that regulate its relationships with third parties to whom it leases sites and supplies motor fuels. Sunoco’s operations at the Burnaby Refinery are also subject to reporting obligations under the Fuel Price Transparency Act. Finally, Sunoco is subject to laws regarding fuel standards. For more information, see “Sunoco is subject to federal laws related to the RFS” and “Sunoco is subject to federal, state and local laws and regulations that govern the product quality specifications of refined petroleum products it purchases, stores, transports, and sells to its distribution customers” in “Item 1A. Risk Factors” in this Annual Report on Form 10-K.
Employee Safety
Sunoco is subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes that regulate the protection of the health and safety of workers. In addition, OSHA’s hazard communication standards require that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that Sunoco is in substantive compliance with the applicable OSHA requirements.
Sunoco is also subject to the BC Worker’s Compensation Act and Occupational Health and Safety Regulation with respect to the Burnaby Refinery. We believe Sunoco is in substantial compliance with these requirements.
Store Operations
Sunoco’s remaining retail locations are subject to regulation by federal agencies and to licensing and regulations by state and local health, sanitation, safety, fire and other departments relating to the development and operation of convenience stores, including regulations related to zoning and building requirements and the preparation and sale of food.
Sunoco’s operations are also subject to federal and state laws governing such matters as wage rates, overtime, working conditions and citizenship requirements. At the federal level, there are proposals under consideration from time to time to increase minimum wage rates.
Human Capital Management
As of December 31, 2025, Sunoco employed an aggregate of 8,910 employees, 628 of which are represented by labor unions. We and our subsidiaries believe that our relations with our employees are good.
In order to accomplish our objectives, Sunoco must continue to attract and retain top talent. It seeks to accomplish this by fostering a culture that is guided by its ethics and principles, that respects all people and cultures, and that focuses on health and safety.
Ethics and Principles. We are committed to operating our business in a manner that honors and respects all people and the communities in which we do business. We recognize that people are our most valued resource, and we are committed to hiring and investing in employees who strive for excellence and live by our core values: working safely, corporate stewardship, ethics and integrity, entrepreneurial mindset, supporting our people, excellence and results, and social responsibility. We value our employees for what they bring to our organization by embracing those from all backgrounds, cultures, and experiences. We also believe that the keys to our success have been the cultivation of an atmosphere of belonging and respect within our family of partnerships and sustaining organizations that promote and support all of the communities in which we do business. These are the principles upon which we build and strengthen relationships among our people, our stakeholders, and those within the communities we support.
Respecting All People and All Cultures. We believe strict adherence to our Code of Business Conduct and Ethics is not only right, but is in the best interest of the Partnership, its unitholders, its customers, and the industry in general. The Partnership's policies require that business be conducted in a lawful and ethical manner at all times. Every employee acting on behalf of the Partnership must adhere to these policies. Please refer to “Item 10. Directors, Executive Officers and Corporate Governance” for additional information on our Code of Business Conduct and Ethics.
Commitment to Health and Safety. Sunoco’s goal is operational excellence, which means an injury and incident-free workplace. To achieve this, we strive to hire and maintain a qualified and dedicated workforce and encourage safety and safety accountability throughout our daily operations.
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Sunoco’s environmental, health and safety professionals provide environmental and safety training to our field representatives. This group also assists others throughout the organization in identifying continuous training for personnel, including the training that is required by applicable laws, regulations, standards, and permit conditions. Sunoco’s safety standards and expectations are clearly communicated to all employees and contractors with the expectation that each individual has the obligation to make safety the highest priority. Its safety culture promotes an open environment for discovering, resolving, and sharing safety challenges. Sunoco strives to eliminate unwanted safety events through a comprehensive process that promotes leadership, employee involvement, communication, and personal responsibility to comply with standard operating procedures and regulatory requirements, effective risk reduction processes, maintaining clean facilities, contractor safety, and personal wellness.
Item 1A. Risk Factors
Below we have provided a summary of our key risk factors, followed by detail of these and other risks that should be reviewed when considering an investment in our securities. The risk factors set forth below are not all the risks we face and other factors that we face in the ordinary course of our business, that are currently considered immaterial or that are currently unknown to us may impact our future operations.
Risk Factor Summary
Risks Related to Our Business
Results of Operations and Financial Condition. Our results of operations and financial condition could be impacted by many risks that are beyond our control, including the following:
•cash distributions are not guaranteed and may fluctuate with our performance and other external factors;
•general economic, financial, and political conditions, including the impact of tariffs;
•the imposition or increase of tariffs on steel or other raw materials, or changes in trade agreements or trade relations;
•changes in the prices of motor fuel;
•demand for motor fuel, including consumer preference for alternative motor fuels or improvements in fuel efficiency;
•demand for and supply of crude oil, refined products, renewable fuels, and anhydrous ammonia;
•seasonal trends;
•dangers inherent in the storage and transportation of motor fuel, crude oil, renewable fuels and anhydrous ammonia;
•operational and business risks associated with our refinery, pipelines and fuel storage terminals;
•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;
•events or developments associated with our branded suppliers;
•extreme weather events that may be more severe or frequent than historically experienced and that may be attributable to changes in climate due to adverse effects of an industrialized economy;
•competition and fragmentation within the wholesale motor fuel distribution industry;
•competition within the convenience store industry, including the impact of new entrants;
•possible increased costs related to land use and facilities and equipment leases;
•possible future litigation;
•potential loss of key members of our senior management team;
•failure to attract and retain qualified employees;
•failure to insure against risks incident to our business;
•terrorist attacks and threatened or actual war;
•cybersecurity attacks, data breaches and other disruptions affecting us, or our service providers;
•disruption of our information systems;
•failure to protect sensitive customer, employee or vendor data, or to comply with applicable regulations relating to data security and privacy;
•failure to obtain trade credit terms to adequately fund our ongoing operations;
•our dependence on cash flow generated by our subsidiaries; and
•potential impairment of goodwill and intangible assets.
Acquisitions and Future Growth. Our business, results of operations, cash flows, financial condition and future growth could be impacted by the following:
•failure to make acquisitions on economically acceptable terms, including as a result of recent increases in cost of capital resulting from Federal Reserve policies and changes in financial institutions’ policies or practices concerning businesses linked to fossil fuels, or to successfully integrate acquired assets;
•any acceleration of the domestic and/or international transition to a low carbon economy as a result policy changes or otherwise; and
•failure to manage risks associated with acquisitions.
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Regulatory Matters. Our business, results of operations, cash flows, financial condition and future growth could be impacted by the following:
•significant expenditures or liabilities resulting from federal, state, provincial and local laws, regulations and bylaws pertaining to environmental protection, operational safety, pipeline safety or the Renewable Fuel Standard (“RFS”) or Canada’s federal and provincial renewable fuel blending and fuel emissions-intensity legislation, including the Clean Fuel Regulations and Low Carbon Fuels Act;
•changes in demand for motor fuel, crude oil, renewable fuels or other petroleum products resulting from federal, state and/or provincial regulations that may discourage the use or storage of petroleum products;
•significant expenditures or penalties associated with federal, state and local laws and regulations that govern the product quality specifications of refined petroleum products we purchase and sell;
•changes in federal, state or local laws and regulations pertaining to the facilities and operations of third parties that supply fuel to or transport for our storage terminals;
•laws, regulations and policies governing the rates, terms and conditions of our services;
•failure to recover the full amount of increases in the costs of our pipeline or refinery operations;
•costs and liabilities resulting from performance of pipeline integrity programs and related repairs;
•new or more stringent pipeline safety controls or enforcement of legal requirements;
•impacts to our business as a result of the energy transition and legislative, regulatory and financial risks relating to climate change; and
•regulatory provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) and the rules adopted thereunder.
Indebtedness. Our business, results of operations, cash flows and financial condition, as well as our ability to make distributions and the market value of our common units, could be impacted by the following:
•our debt levels;
•increases in interest rates, including the impact to the relative value of our distributions to yield-oriented investors; and
•restrictions and financial covenants associated with our debt agreements.
Risks Related to Our Structure
Our General Partner. Our stakeholders could be impacted by risks related to our General Partner, including:
•our General Partner’s and its affiliates’ conflicts of interest with us and contractually-limited duties;
•our General Partner’s limited liability regarding our obligations;
•our General Partner’s ability to approve the issuance of partnership securities and specify the terms of such securities; and
•cost reimbursements due to our General Partner and its affiliates for services provided to us or on our behalf.
Our Partnership Agreement. Our stakeholders could be impacted by risks related to our Partnership Agreement, including:
•the requirement that we distribute all of our available cash;
•the limited liability and duties of our General Partner and restrictions on the remedies available for actions taken;
•the potential need to issue common units in connection with a resetting of the target distribution levels related to our IDRs;
•our common unitholders’ limited voting rights and lack of rights to elect our General Partner or its directors;
•limitations on our common unitholders’ ability to remove our General Partner without its and SunocoCorp’s consent;
•potential transfer of the General Partner interest or the control of our General Partner to a third party;
•the potential requirement for unitholders to sell their common units at an undesirable time or price;
•our ability to issue additional units without unitholder approval;
•potential sales of substantial amounts of our common units in the public or private markets;
•restrictions on the voting rights of unitholders owning 20% or more of our outstanding common units;
•the dependence of our distributions primarily on our cash flow and not solely on profitability;
•our unitholders’ potential liability to repay distributions; and
•the lack of certain corporate governance requirements by the NYSE for a publicly traded partnership like us.
Tax Risks to Unitholders
Our unitholders could be impacted by tax risks, including:
•our potential to be taxed as a corporation or otherwise become subject to a material amount of entity-level taxation;
•the potential for our unitholders to be required to pay taxes on their share of our income even if they do not receive any cash distributions from us; and
•unique tax issues faced by tax-exempt entities from owning common units.
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Detail of Risk Factors Related to Our Business
Results of Operations and Financial Condition
Cash distributions are not guaranteed and may fluctuate with our performance and other external factors.
Cash distributions to unitholders is principally dependent upon cash generated from operations. The amount of cash generated from operations will fluctuate from quarter to quarter based on a number of factors, some of which are beyond our control, which include, among others:
•demand for motor fuel in the markets we serve, including the result of secular trends towards increased usage of electric vehicles and/or seasonal fluctuations in demand for motor fuel;
•competition from other companies that sell motor fuel products or have convenience stores in the market areas in which we or our commission agents or dealers operate;
•the amount of crude oil and refined petroleum products transported through our subsidiaries’ pipelines;
•the level of competition from other midstream, transportation and storage and retail marketing companies, refinery operators and other energy providers;
•regulatory action affecting the supply of or demand for motor fuel, crude oil, refined petroleum products, our operations, our existing contracts or our operating costs;
•prevailing economic conditions;
•the price of crude oil, feedstock at our refining operations and refined petroleum products;
•rising interest rates and slowing economic growth;
•the accelerated transition to a low carbon economy;
•geopolitical events such as the conflicts in Ukraine and Venezuela and political instability in the Middle East;
•supply, extreme weather and logistics disruptions; and
•volatility of margins for motor fuel.
In addition, the actual amount of cash we will have available for distribution will depend on other factors such as:
•the level and timing of capital expenditures we make;
•the cost of acquisitions, if any;
•our debt service requirements, distributions on our Series A Preferred Units and other liabilities;
•fluctuations in our general working capital needs;
•reimbursements made to our General Partner and its affiliates for all direct and indirect expenses they incur on our behalf pursuant to the Partnership Agreement;
•our ability to borrow funds at favorable interest rates and access capital markets;
•restrictions contained in debt agreements to which we are a party;
•the level of costs related to litigation and regulatory compliance matters; and
•the amount of cash reserves established by our General Partner in its discretion for the proper conduct of our business.
If our cash flow from operations is insufficient to satisfy our needs, we cannot be certain that we will be able to obtain bank financing or access the capital markets. Further, incurring additional debt may significantly increase our interest expense and financial leverage and issuing additional limited partner interests may result in significant unitholder dilution and would increase the aggregate amount of cash required to maintain the cash distribution rate which could materially decrease our ability to pay distributions. If additional capital resources are unavailable to us, our business, financial condition, results of operations and ability to make distributions could be materially adversely affected.
Changes in U.S. administrative policy, including the imposition of or increases in tariffs on steel and/or other raw materials, changes to existing trade agreements and any resulting changes in international trade relations, may have an adverse effect on us.
We own and operate pipelines and terminals and, like others in our industry, we use significant amounts of steel in our projects and rely on our ability to obtain that steel in an affordable way to maintain our operating margins. Any imposition of or increase in tariffs
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on steel and/or other raw materials could increase our growth project costs, which may impact the profitability of new projects and our maintenance capital expenditures, potentially in excess of budgeted amounts.
On March 12, 2025 the U.S. government imposed a 25% tariff on steel imports, which was increased to 50% on June 4, 2025, and on April 2, 2025, the U.S government announced a 10% tariff on product imports from almost all countries and individualized higher tariffs on certain other countries. Several tariff announcements have been followed by announcements of limited exemptions and temporary pauses. These actions have caused uncertainty and volatility in financial markets and may result in retaliatory measures on U.S. goods. The ultimate impact of these tariffs is unknown at this time. Additionally, ongoing changes in U.S. and foreign government trade policies, including potential modifications to existing trade agreements and further restrictions on free trade, could introduce additional uncertainty. Any escalation of trade tensions, additional tariffs, retaliatory measures by foreign governments or shifts in U.S. or international trade policies could adversely impact our supply chain and increase costs, particularly on our expansion projects. A trade war or other significant changes in trade regulations could have an adverse effect on our business and results of operations.
Our business could be negatively impacted by the inflationary pressures which may decrease our operating margins and increase working capital investments required to operate our business.
The U.S. inflation rate remained relatively stable through 2024 and 2025, after an extended period of rising rates, which began in 2022. A sustained increase in inflation may continue to increase our costs for labor, services and materials, which, in turn, could cause our operating costs and capital expenditures to increase. Further, our customers face inflationary pressures and resulting impacts, such as the tight labor market and supply chain disruptions. The rate and scope of these various inflationary factors may increase our operating costs and capital expenditures materially, which may not be readily recoverable in the prices of our services and may have an adverse effect on our costs, operating margins, results of operations and financial condition. Additionally, the Federal Reserve and other central banks have implemented policies in an effort to curb inflationary pressure on the costs of goods and services across the U.S., including the significant increases in prevailing interest rates that occurred during 2022 and 2023 as a result of the 525 aggregate basis point increase in the federal funds rate, and the associated macroeconomic impact on slowdown in economic growth could negatively impact our business. While the Federal Reserve reduced benchmark interest rates by 100 basis points in late 2024, and 75 basis points in late 2025, the prospect of additional interest rate cuts remains uncertain and the continuation of rates at the current level could have the effects of raising the cost of capital and depressing economic growth, either of which—or the combination thereof—could hurt the financial and operating results of our business.
General economic, financial, and political conditions, including the impact of tariffs, may materially adversely affect our results of operations and financial condition.
General economic, financial, and political conditions may have a material adverse effect on our results of operations and financial condition. For example, on March 12, 2025, the U.S. government imposed a 25% tariff on steel imports, which was increased to 50% on June 4, 2025, and on April 2, 2025, the U.S. government announced a 10% tariff on product imports from almost all foreign countries and individualized higher tariffs on certain other countries. Several tariff announcements have been followed by announcements of limited exemptions and temporary pauses. These actions have caused uncertainty and volatility in financial markets and may result in retaliatory measures on U.S. goods. It is possible that our operations may be affected by the resulting volatility in pricing and demand. Similarly, declines in consumer confidence and/or consumer spending, changes in unemployment, significant inflationary or deflationary changes or disruptive regulatory or geopolitical events could contribute to increased volatility and diminished expectations for the economy and our markets, including the market for our goods and services, and lead to demand or cost pressures that could negatively and adversely impact our business. These conditions could affect each of our business segments.
Examples of such conditions could include:
•a general or prolonged decline in, or shocks to, regional or broader macro-economies;
•regulatory changes that could impact the markets in which we operate, such as immigration, tariffs or trade reform laws or regulations prohibiting or limiting hydraulic fracturing, which could reduce demand for or supply of our goods and services or lead to pricing, currency, or other pressures; and
•deflationary economic pressures, which could hinder our ability to operate profitably in view of the challenges inherent in making corresponding deflationary adjustments to our cost structure.
In addition, volatility in the capital markets resulting from tariff announcements could also limit our ability to access capital on favorable terms, which could have an adverse impact on our ability to finance new projects and/or acquisitions.
The nature of these types of risks, which are often unpredictable, makes them difficult to plan for, or otherwise mitigate, and they are generally uninsurable—which compounds their potential impact on our business.
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Our financial condition and results of operations are influenced by changes in the prices of motor fuel, crude oil, refinery feedstock or refined petroleum products, which may adversely impact our margins, our customers’ financial condition and the availability of trade credit.
Our operating results are influenced by prices for motor fuel, crude oil, refinery feedstock and refined petroleum products. General economic and political conditions, acts of war or terrorism and instability in oil producing regions, particularly in the Middle East, South America, Russia and Africa could significantly impact crude oil supplies, refinery feedstock and refined product petroleum costs. Significant increases or high volatility in petroleum costs could impact consumer demand for motor fuel and convenience merchandise. Such volatility makes it difficult to predict the impact that future petroleum costs fluctuations may have on our operating results and financial condition. We are subject to dealer tank wagon pricing structures at certain locations further contributing to margin volatility. A significant change in any of these factors could materially impact both wholesale and retail fuel margins, the volume of motor fuel we distribute or sell, and overall customer traffic, each of which in turn could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution to our unitholders.
Significant increases in wholesale motor fuel prices could impact us as some of our customers may have insufficient credit to purchase motor fuel from us at their historical volumes. Higher prices for motor fuel may also reduce our access to trade credit support or cause it to become more expensive.
A significant decrease in demand for motor fuel, crude oil, refinery feedstock or refined petroleum products, including increased consumer preference for alternative motor fuels or improvements in fuel efficiency or a material shift toward electric or other alternative-power vehicles, in the areas we serve would reduce our ability to make distributions to our unitholders.
Sales of refined motor fuels accounted for approximately 92% of Sunoco’s total revenues and 42% of Sunoco’s profit for the year ended December 31, 2025. A significant decrease in demand for motor fuel in the areas we serve could significantly reduce our revenues and our ability to make distributions to our unitholders. Our revenues are dependent on various trends, such as trends in commercial truck traffic, travel and tourism in our areas of operation, and these trends can change. Regulatory action, including government imposed fuel efficiency standards, may also affect demand for motor fuel. Because certain of our operating costs and expenses are fixed and do not vary with the volumes of motor fuel we distribute, our costs and expenses might not decrease ratably or at all should we experience such a reduction. As a result, we may experience declines in our profit margin if our fuel distribution volumes decrease.
Any technological advancements, regulatory changes or changes in consumer preferences causing a significant shift toward alternative motor fuels could reduce demand for the conventional petroleum based motor fuels we currently sell. Additionally, a shift toward electric, hydrogen, natural gas or other alternative-power vehicles could fundamentally change our customers’ shopping habits or lead to new forms of fueling destinations or new competitive pressures.
New technologies have been developed and from time to time governmental mandates have been implemented to improve fuel efficiency, which may ultimately result in decreased demand for petroleum-based fuel. For example, the EPA previously finalized new criteria pollutant and GHG emissions standards for light and medium-duty vehicles, including passenger cars, vans, pickups, sedans and sport utility vehicles for model years 2027 through 2032 and beyond. However, following the change in U.S. presidential administrations, the EPA in February 2026 finalized rules rescinding these standards and the GHG “Endangerment Finding,” which underpins the majority of EPA’s GHG regulations and GHG emissions standards for new motor vehicles and engines. Additionally, the Trump Administration has taken steps to reduce or eliminate incentives for zero-emission vehicles, and OBBBA, passed by Congress in July 2025, eliminates electric vehicle credits previously available for new and used electric vehicles and commercial fleets. However, we cannot predict whether or not these regulatory repeals will ultimately be successful or if future administrations may seek to restore incentives and further promote or mandate the adoption of electric vehicles. Any of these or similar actions could result in fewer visits to our convenience stores or independently operated commission agents and dealer locations, a reduction in demand from our wholesale customers, decreases in both fuel and merchandise sales revenue, or reduced profit margins, any of which could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution to our unitholders.
Similarly, any sustained decrease in demand for crude oil, refined products, refinery feedstock, 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;
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•new government and regulatory actions or court decisions requiring the phase out or reduced use of gasoline-fueled vehicles;
•the increased use of and public demand for use of alternative fuel sources or electric vehicles;
•an increase in the market price of crude oil that increases refined product prices, which may reduce demand for refined products and increase demand for alternative products; and
•adverse weather events resulting in decreased corn acres planted, which may reduce demand for anhydrous ammonia.
The industries in which we operate are subject to seasonal trends, which may cause our operating costs to fluctuate, affecting our cash flow.
We rely in part on consumer travel and spending patterns, and may experience more demand for gasoline in the late spring and summer months than during the fall and winter. Travel, recreation and construction are typically higher in these months in the geographic areas in which we or our commission agents and dealers operate, increasing the demand for motor fuel that we sell and distribute. Therefore, our revenues and cash flows are typically higher in the second and third quarters of our fiscal year. As a result, our results from operations may vary widely from period to period, affecting our cash flow.
The dangers inherent in the storage and transportation of motor fuel, crude oil, refinery feedstock, refined petroleum products and anhydrous ammonia could cause disruptions in our operations and could expose us to potentially significant losses, costs or liabilities.
Our operations are subject to significant hazards and risks inherent in transporting and storing motor fuel crude oil, refinery feedstock, refined petroleum products, and anhydrous ammonia. These hazards and risks include, but are not limited to, traffic accidents, fires, explosions, spills, discharges, and other releases, any of which could result in distribution difficulties and disruptions, environmental pollution, governmentally-imposed fines or clean-up obligations, personal injury or wrongful death claims, and other damage to our properties and the properties of others. Any such event not covered by our insurance could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution to our unitholders. Additionally, our pipelines, terminals, storage assets and refinery operations 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.
Our pipelines, fuel storage terminals and refinery are subject to operational and business risks which may adversely affect our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.
Our pipelines, fuel storage terminals and refinery are subject to operational and business risks, the most significant of which include the following:
•our inability to renew a ground lease for certain of our pipelines or fuel storage terminals or at the Burnaby Refinery on similar terms or at all;
•our dependence on third parties to supply our fuel storage terminals and refinery feedstock;
•outages on our pipelines or at our fuel storage terminals or the Burnaby Refinery or interrupted operations due to weather-related or other natural causes;
•the threat that the nation’s terminal infrastructure and the Burnaby Refinery may be a future target of terrorist organizations;
•the volatility in the prices of the products transported on our pipelines or stored at our fuel storage terminals or our refinery feedstock and the resulting fluctuations in demand for our storage services;
•the effects of a sustained recession or other adverse economic conditions;
•the possibility of federal and/or state regulations that may discourage our customers from transporting or storing gasoline, diesel fuel, ethanol and jet fuel at our fuel storage terminals or reduce the demand by consumers for petroleum products, and possibility of federal, state or provincial regulation in Canada, particularly with respect to the Burnaby Refinery;
•competition from other pipelines and fuel storage terminals that are able to provide our customers with comparable transportation service or storage capacity at lower prices or from other refineries servicing the Lower Mainland in Canada; and
•climate change legislation or regulations that restrict emissions of GHGs could result in increased operating and capital costs and reduced demand for our transportation and storage services.
The occurrence of any of the above situations, among others, may affect operations at our fuel storage terminals or the Burnaby Refinery and may adversely affect our business, financial condition, results of operations, cash flows and ability to make distributions to our unitholders.
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Negative events or developments associated with our branded suppliers could have an adverse impact on our revenues.
We believe that the success of our operations is dependent, in part, on the continuing favorable reputation, market value, and name recognition associated with the motor fuel brands sold at our convenience stores and at stores operated by our independent, branded dealers and commission agents. Erosion of the value of those brands could have an adverse impact on the volumes of motor fuel we distribute, which in turn could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our unitholders.
Severe weather, which may increase in frequency and intensity due to climate change, could adversely affect our business by damaging our suppliers’ or our customers’ facilities or communications networks.
A substantial portion of our wholesale distribution, refinery operations and retail networks are located in regions susceptible to severe storms, including hurricanes. A severe storm could damage our facilities or communications networks, or those of our suppliers or our customers, as well as interfere with our ability to distribute motor fuel to our customers or our customers’ ability to operate their locations. If warmer temperatures, or other climate changes, lead to changes in extreme weather events, including increased frequency, duration or severity, these weather-related risks could become more pronounced. Any weather-related catastrophe or disruption could have a material adverse effect on our business, financial condition and results of operations, potentially causing losses beyond the limits of the insurance we currently carry.
The wholesale motor fuel distribution industry is characterized by intense competition and fragmentation. Failure to effectively compete could result in lower margins.
The market for distribution of wholesale motor fuel is highly competitive and fragmented, which results in narrow margins. We have numerous competitors, some of which may have significantly greater resources and name recognition than us. We rely on our ability to provide value-added, reliable services and to control our operating costs in order to maintain our margins and competitive position. If we fail to maintain the quality of our services, certain of our customers could choose alternative distribution sources and our margins could decrease. While major integrated oil companies have generally continued a strategy of limited direct retail operation and the corresponding wholesale distribution to such sites, such major oil companies could shift from this strategy and decide to distribute their own products in direct competition with us, or large customers could attempt to buy directly from the major oil companies. The occurrence of any of these events could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution to our unitholders.
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.
The convenience store industry is highly competitive and impacted by new entrants. Failure to effectively compete could result in lower sales and lower margins.
The geographic areas in which we operate and supply independently operated commission agent and dealer locations are highly competitive and marked by ease of entry and constant change in the number and type of retailers offering products and services of the type we and our independently operated commission agents and dealers sell in our stores. Our convenience stores and the commission agents and dealer locations we supply compete with other convenience store chains, independently owned convenience stores, motor fuel stations, supermarkets, drugstores, discount stores, dollar stores, club stores, mass merchants and local restaurants. Over the past two decades, several non-traditional retailers, such as supermarkets, hypermarkets, club stores and mass merchants, have impacted the convenience store industry, particularly in the geographic areas in which we operate and supply, by entering the motor fuel retail business. These non-traditional motor fuel retailers have captured a significant share of the motor fuels market, and we expect their market share will continue to grow.
In some of our markets, our competitors have been in existence longer and have greater financial, marketing, and other resources than we or our independently operated commission agents and dealers do. As a result, our competitors may be able to respond better to changes in the economy and new opportunities within the industry. To remain competitive, we must constantly analyze consumer
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preferences and competitors’ offerings and prices to ensure that we offer a selection of convenience products and services at competitive prices to meet consumer demand. We must also maintain and upgrade our customer service levels, facilities and locations to remain competitive and attract customer traffic to our stores. We may not be able to compete successfully against current and future competitors, and competitive pressures faced by us could have a material adverse effect on our business, results of operations and cash available for distribution to our unitholders.
We do not own all of the land on which our retail service stations are located, and we lease certain facilities and equipment, and we are subject to the possibility of increased costs to retain necessary land use which could disrupt our operations.
We do not own all of the land on which our retail service stations are located. We have rental agreements for approxim ately 61% of the Partnership, commission agent or dealer operated retail service stations where we currently control the real estate. We also have rental agreements for certain logistics facilities. As such, we are subject to the possibility of increased costs under rental agreements with landowners, primarily through rental increases and renewals of expired agreements. We are also subject to the risk that such agreements may not be renewed. Additionally, certain facilities and equipment (or parts thereof) used by us are leased from third parties for specific periods. Our inability to renew leases or otherwise maintain the right to utilize such facilities and equipment on acceptable terms, or the increased costs to maintain such rights, could have a material adverse effect on our financial condition, results of operations and cash flows.
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.
Our investment in the Burnaby Refinery is subject to operational risks, including commodity price and pricing pressure and environment, health and safety hazards. If any of the operational risks materialize our financial condition or results of operations could be materially and adversely affected.
Following the Parkland Acquisition, we own and operate the Burnaby Refinery, which produces and supplies fuel within the Lower Mainland in BC. The Burnaby Refinery has two crude units, including a 25,000 barrel per day crude unit and a 30,000 barrel per day splitter, that are designed to process Canadian light and medium sweet crudes.
Key operational risks at the Burnaby Refinery include: supply disruptions of crude oil and bio-feedstocks, product offtake contract issues or interruptions, operational availability, labor and material shortages, compliance with regulatory requirements, including GHG emission and low-carbon fuel intensity production requirements, and local community opposition. Major accidents could cause significant damage and may result in operational interruptions, loss of licenses, fines, reputational damage, injuries or fatalities. Large amounts of power, heat by way of natural gas and large volumes of water are used to refine crude oil, the supply of which is not in our control, and even a temporary interruption of power, natural gas or water could adversely affect continuous operations. Unanticipated costs and delays during maintenance may negatively impact our operational results. Scheduled and unscheduled maintenance and repairs at the Burnaby Refinery may reduce revenue and increase our operating costs, impacting our financial and operational results.
Additionally, we contract with third parties for the supply of crude oil and other feedstock to the Burnaby Refinery. Crude oil sourced by the Burnaby Refinery is delivered from Alberta by the TMPL. Interruptions or apportionment on the TMPL’s pipeline system can result in us temporarily ceasing or decreasing processing operations at the Burnaby Refinery and may materially affect our business, financial condition and results of operations. The Burnaby Refinery could see variability in its crude deliveries as the capacity on the pipeline fluctuates from time to time, which can impact committed as well as uncommitted linespace, based on operating conditions and planned and/or unplanned maintenance. In addition to the TMPL line capacity, extreme or unexpected weather events may affect the operation of the TMPL. Significant operational delays, changes in tariffs and unanticipated costs could adversely impact the refinery.
Refining gross margins are primarily driven by commodity prices and are a function of the difference between the costs of feedstock (primarily crude oil) and the market prices for the marketing of finished products (such as gasoline, diesel, jet fuel, lubricants, fuel oil and fuel and lubricant additives). Prices for commodities are determined by global and regional marketplaces and are influenced by many factors, including supply and demand balances, inventory levels, industry refinery operations, import and export balances, currency fluctuations, seasonal demand, political climate, disruptions at the refinery resulting from unplanned outages due to severe weather, fires or other operational events and plant capacity utilization. Sustained low refining margins may have an adverse effect on our revenue, profitability and ability to service debt and pay distributions.
The Burnaby Refinery faces hazards related to hydrocarbon supply and processing, including, but not limited to, fires, explosions, railcar or marine vessel incidents, oil spills, migration of harmful substances, corrosion, vandalism, terrorism and other accidents that may occur at or during transport to or from sites. The consequences of an accidental spill or release at or near any marine terminal
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used in connection with our operations could be significant, given the complexities of addressing releases occurring in marine environments or along populated coastlines. Such incidents could result in significant disruptions to offshore shipping activities and impede our ability to operate in any affected areas.
These hazards may interrupt operations, cause injuries or fatalities, cause loss of or damage to equipment, property, information technology or control systems and data, or result in environmental damage that may include pollution of water, land or air. The consequences could expose us to business interruptions, potential liabilities, modifications to or revocation of existing regulatory approvals, administrative, civil and criminal fines and other environmental damages, or reputational impacts.
We face a variety of risks related to our entry into the refinery business following the completion of the Parkland Acquisition.
Entry into a new line of business in a new jurisdiction may also subject us to new laws and regulations with which we are not familiar and may lead to increased litigation and regulatory risk. In addition, there is some risk as it relates to indigenous groups asserting aboriginal or treaty rights in various regions of western Canada, particularly in BC. Such claims may affect many businesses operating in western Canada as the claims are litigated or settled with the federal and provincial governments. The federal and provincial governments have a duty to consult with indigenous people on actions and decisions that may affect their aboriginal or treaty rights and, in certain cases, accommodate their concerns. The government’s duty to consult may be triggered if we apply to obtain or renew significant permits, leases, licenses or other approvals for our operations in the traditional territories of indigenous groups. Our management team has not engaged in the refinery operations business in recent years and continues to familiarize itself with the Canadian regulatory landscape, which imposes more stringent requirements than those in the other jurisdictions in which we operate. If we are unable to successfully implement the acquired business of Parkland, in particular, the Burnaby Refinery, our revenue and profitability may not grow as we expect, our competitiveness may be materially and adversely affected and our reputation and business may be harmed.
Future litigation could adversely affect our financial condition and results of operations.
We are exposed to various litigation claims in the ordinary course of our wholesale business operations, including, but not limited to, dealer litigation and industry-wide or class-action claims arising from the products we carry, the equipment or processes we use or employ or industry-specific business practices. If we were to become subject to an y such claims, our defense costs and any resulting awards or settlement amounts may not be fully covered by our insurance policies. Additionally, our retail operations are characterized by a high volume of customer traffic and by transactions involving a wide array of product selections. These operations carry a higher exposure to consumer litigation risk when compared to the operations of companies operating in many other industries. Consequently, we are frequently party to individual personal injury, bad fuel, products liability and other legal actions in the ordinary course of our business. While we believe these actions are generally routine in nature, incidental to the operation of our business and immaterial in scope, if our assessment of any action or actions should prove inaccurate our financial condition and results of operations could be adversely affected. Additionally, several fossil fuel companies have been the targets of litigation alleging, among other things, that such companies created public nuisances by producing and marketing fuels that contributed to climate change or that the companies have been aware of the adverse effects of climate change but failed to adequately disclose those impacts. While we cannot predict the likelihood of success of such suits, to the extent the plaintiffs prevail, we could face significant costs or decreased demand for our services, which could adversely affect our financial condition and results of operations.
Because we depend on our senior management’s experience and knowledge of our industry, we could be adversely affected were we to lose key members of our senior management team.
We are dependent on the expertise and continued efforts of our General Partner’s senior management team. If, for any reason, our senior executives do not continue to be active, our business, financial condition, or results of operations could be adversely affected. We do not maintain key man life insurance for our senior executives or other key employees.
We compete with other businesses in our market with respect to attracting and retaining qualified employees.
Our continued success depends on our ability to attract and retain qualified personnel in all areas of our business. We compete with other businesses in our market with respect to attracting and retaining qualified employees. A tight labor market, increased overtime and a higher full-time employee ratio may cause labor costs to increase. A shortage of qualified employees may require us to enhance wage and benefits packages in order to compete effectively in the hiring and retention of such employees or to hire more expensive temporary employees. No assurance can be given that our labor costs will not increase, or that such increases can be recovered through increased prices charged to customers. We are especially vulnerable to labor shortages in oil and gas drilling areas when energy prices drive higher exploration and production activity.
We are not fully insured against all risks incident to our business.
We are not fully insured against all risks incident to our business. We may be unable to obtain or maintain insurance with the coverage that we desire at reasonable rates. As a result of market conditions, the premiums and deductibles for certain of our insurance policies have increased and could continue to do so. Certain insurance coverage could become unavailable or available only for reduced
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amounts of coverage. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our unitholders.
Terrorist attacks and threatened or actual war may adversely affect our business.
Our business is affected by general economic conditions and fluctuations in consumer confidence and spending, which can decline as a result of numerous factors outside of our control. Terrorist attacks or threats, whether within the United States or abroad, rumors or threats of war, actual conflicts involving the United States, its allies or other countries or regions where we operate, or military or trade disruptions impacting our suppliers or our customers may adversely impact our operations by increasing our operating costs, reducing customer demand, disrupting supply chains, or limiting our ability to operate certain locations or serve certain markets. Specifically, strategic targets such as energy related assets (which could include refineries that produce the motor fuel we purchase, ports in which crude oil is delivered or attacks to the electrical grid) may be at greater risk of future terrorist attacks than other targets in North America, the Greater Caribbean and Europe. These occurrences could have an adverse impact on energy prices, including prices for motor fuels, and an adverse impact on our operations. Any or a combination of these occurrences could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution to our unitholders and could increase volatility in our financial performance and results from period to period.
Cybersecurity attacks, data breaches and other disruptions affecting us, or our service providers, could materially and adversely affect our business, operations, reputation, and financial results.
The security and integrity of our information technology (“IT”) infrastructure and physical assets is critical to our business and our ability to perform day-to-day operations and deliver services. In addition, in the ordinary course of our business, we collect, process, transmit and store sensitive data, including intellectual property, our proprietary business information and that of our customers, suppliers and business partners, as well as personally identifiable information, in our data centers and on our networks. We also engage third parties, such as service providers and vendors, who provide a broad array of software, technologies, tools, and other products, services and functions (e.g., human resources, finance, data transmission, communications, risk, compliance, among others) that enable us to conduct, monitor and/or protect our business, operations, systems and data assets.
Our IT and IT infrastructure, physical assets and data, may be vulnerable to unauthorized access, computer viruses, malicious attacks and other events (e.g., distributed denial of service attacks or ransomware attacks) that are beyond our control. These events can result from malfeasance by external parties, such as hackers, or due to human error by our or our service providers’ employees and contractors (e.g., due to social engineering or phishing attacks). In addition, our providers’ work-from-home arrangements may present additional operational and cybersecurity risks to our IT infrastructure and physical assets.
We and certain of our service providers have, from time to time, been subject to cybersecurity attacks and other security incidents. The frequency and magnitude of cybersecurity attacks is expected to increase and attackers are becoming more sophisticated. We may be unable to anticipate, detect or prevent future attacks, particularly as the methodologies used by attackers change frequently or are not recognized until launched, and we may be unable to investigate or remediate incidents because attackers are increasingly using techniques and tools designed to circumvent controls, to avoid detection, and to remove or obfuscate forensic evidence.
Moreover, our increasingly broad global operating footprint may increase our exposure to cybersecurity risks, as a larger and more geographically dispersed workforce requires broader access to our information systems and intranet, which may increase the likelihood of unauthorized access, data breaches or other cyber incidents. Breaches of our IT infrastructure or physical assets, or other disruptions, could result in damage to our assets, safety incidents, damage to the environment, potential liability or the loss of contracts, and have a material adverse effect on our operations, financial position and results of operations. A successful cybersecurity attack or other security incident could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or loss could result in legal claims or proceedings, regulatory investigations and enforcement, penalties and fines, increased costs for system remediation and compliance requirements, disruption of our operations, damage to our reputation, loss of confidence in our products and services, any or all of which could have a material adverse effect on our business and results. We may be required to invest significant additional resources to comply with evolving cybersecurity regulations and to modify and enhance our information security and controls, and to investigate and remediate any security vulnerabilities. Any losses, costs or liabilities may not be covered by, or may exceed the coverage limits of, any or all of our applicable insurance policies. See “Item 1C. Cybersecurity” for additional information on our cybersecurity risk management, strategy and governance.
We rely on our information systems to manage numerous aspects of our business, and a disruption of these systems could adversely affect our business.
We depend on our information systems to manage numerous aspects of our business transactions and provide analytical information to management. Our information systems are an essential component of our business and growth strategies, and a serious disruption to our information systems could significantly limit our ability to manage and operate our business efficiently. These systems are vulnerable to, among other things, damage and interruption from power loss or natural disasters, computer system and network failures, loss of telecommunications services, physical and electronic loss of data, security breaches and computer viruses, which
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could result in a loss of sensitive business information, systems interruption or the disruption of our business operations. To protect against unauthorized access or attacks, we have implemented infrastructure protection technologies and disaster recovery plans, but there can be no assurance that a technology systems breach or systems failure will not have a material adverse effect on our financial condition or results of operations. See “Item 1C. Cybersecurity” for additional information on our cybersecurity risk management, strategy and governance.
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.
A significant portion of our revenues and cash flows are generated 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 could result 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, Canada 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;
•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.
Our business and our reputation could be adversely affected by the failure to protect sensitive customer, employee or vendor data, whether as a result of cybersecurity attacks or otherwise, or to comply with applicable regulations relating to data security and privacy.
In the normal course of our business as a motor fuel, food service and merchandise retailer, we obtain large amounts of personal data, including credit and debit card information from our customers. In recent years several retailers have experienced data breaches resulting in exposure of sensitive customer data, including payment card information. While we have invested significant amounts in the protection of our information systems and maintain what we believe are adequate security controls over personally identifiable customer, employee and vendor data provided to us, a breakdown or a breach in our systems that results in the unauthorized release of personally identifiable customer or other sensitive data could nonetheless occur and have a material adverse effect on our reputation, operating results and financial condition. Such a breakdown or breach could also materially increase the costs we incur to protect against such risks. Also, a material failure on our part to comply with regulations relating to our obligation to protect such sensitive data or to the privacy rights of our customers, employees and others could subject us to fines or other regulatory sanctions and potentially to lawsuits.
Cybersecurity attacks are rapidly evolving and becoming increasingly sophisticated, and recent developments in the space of artificial intelligence increase the cybersecurity attack surface. A successful cybersecurity attack resulting in the loss of sensitive customer, employee or vendor data could adversely affect our reputation, results of operations, financial condition and liquidity, and could result in litigation against us or the imposition of penalties. Moreover, a security breach could require that we expend significant additional resources to upgrade further the security measures that we employ to guard against cybersecurity attacks. See “Item 1C. Cybersecurity” for additional information on our cybersecurity risk management, strategy and governance.
We rely on our suppliers to provide trade credit terms to adequately fund our ongoing operations.
Our business is impacted by the availability of trade credit to fund fuel purchases. An actual or perceived downgrade in our liquidity or operations (including any credit rating downgrade by a rating agency) could cause our suppliers to seek credit support in the form of additional collateral, limit the extension of trade credit, or otherwise materially modify their payment terms. Any material changes
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in our payment terms, including early payment discounts, or availability of trade credit provided by our principal suppliers could impact our liquidity, results of operations and cash 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. 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; our cash flows may be adversely affected, which could adversely affect our ability to make distributions to our unitholders.
We depend on cash flow generated by our subsidiaries.
We are a holding company with no material assets other than the equity interests in our subsidiaries. Our subsidiaries conduct all of our operations and own all of our assets. These subsidiaries are distinct legal entities and, under certain circumstances, legal and contractual restrictions may limit our ability to obtain cash from our subsidiaries and our subsidiaries may not be able to, or be permitted to, make distributions to us. In the event that we do not receive distributions from our subsidiaries, we may be unable to meet our financial obligations or make distributions to our unitholders.
An impairment of goodwill and intangible assets could reduce our earnings.
As of December 31, 2025, our consolidated balance sheet refl ected $3.03 billion of goodwill and $2.41 billion of intangibl e assets. Goodwill is recorded when the purchase price of a business exceeds the fair value of the tangible and separately measurable intangible net assets. GAAP require us to test goodwill and indefinite-lived intangible assets for impairment on an annual basis or when events or circumstances occur, indicating that goodwill or indefinite-lived intangible assets might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings. Impairment charges are allowed to be removed from our debt covenant calculations. See Note 9 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
Acquisitions and Future Growth
If we are unable to make acquisitions on economically acceptable terms from third parties, our future growth and ability to increase distributions to unitholders will be limited.
A portion of our strategy to grow our business is dependent on our ability to make acquisitions that result in an increase in cash flow. The acquisition component of our growth strategy is based, in part, on our expectation of ongoing strategic divestitures of wholesale fuel distribution assets by industry participants. If we are unable to make acquisitions from third parties for any reason, including if we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, we are unable to obtain financing for these acquisitions on economically acceptable terms, we are outbid by competitors, or we or the seller are unable to obtain all necessary consents, our future growth and ability to increase distributions to unitholders will be limited. In addition, if we consummate any future acquisitions, our capitalization and results of operations may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial, and other relevant information considered in determining the application of these funds and other resources. Finally, we may complete acquisitions which at the time of completion we believe will be accretive, but which ultimately may not be accretive. If any of these events were to occur, our future growth would be limited.
Integration of assets and businesses acquired in past acquisitions or future acquisitions with our existing business will be a complex, time-consuming and costly process, particularly given that assets acquired to date significantly increased our size and diversif ied the geographic areas in which we operate. A failure to successfully integrate the acquired assets or businesses, such as Parkland, with our existing business in a timely manner may have a material adverse effect on our business, financial condition, results of operations or cash available for distribution to our unitholders.
The difficulties of integrating past and future acquisitions with our business include, amo ng other things:
•operating a larger combined organization in new geographic areas and new lines of business;
•hiring, training or retaining qualified personnel to manage and operate our growing business and assets;
•integrating management teams and employees into existing operations and establishing effective communication and information exchange with such management teams and employees;
•diversion of management’s attention from our existing business;
•assimilation of acquired assets and operations, including additional regulatory programs, operational philosophies and complex systems;
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•loss of customers, suppliers or key employees;
•maintaining an effective system of internal controls in compliance with the Sarbanes-Oxley Act of 2002 as well as other regulatory compliance and corporate governance matters;
•integrating new technology systems for financial reporting; and
•assuming contractual obligations of acquired businesses, potential unknown liabilities and unforeseeable increased expenses as a result of such acquisitions.
If any of these risks or other unanticipated liabilities or costs were to materialize, then desired benefits from past acquisitions and future acquisitions could result in a negative impact to our future results of operations. In addition, acquired assets may perform at levels below the forecasts used to evaluate them, due to factors beyond our control. If the acquired assets perform at levels below the forecasts, then our future results of operations could be negatively impacted.
Also, our reviews of proposed business or asset acquisitions are inherently imperfect because it is generally not feasible to perform an in-depth review of each such proposal given time constraints imposed by sellers. Even if performed, a detailed review of assets and businesses may not reveal existing or potential problems, and may not provide sufficient familiarity with such business or assets to fully assess their deficiencies and potential. Inspections may not be performed on every asset, and environmental problems, such as groundwater contamination, may not be observable even when an inspection is undertaken.
We acquired Parkland, a Canadian corporation, indirectly through Sunoco Retail, a wholly owned corporate subsidiary of ours. The acquisition involved the creation of a separate public company, SunocoCorp, within our ownership structure, and resulted in our expansion into jurisdictions where we did not previously have an operating footprint, which may expose us to additional regulatory, operational and geopolitical risks. See “—Regulatory Matters—We operate assets outside of the United States, which exposes us to different legal and regulatory requirements and additional risk” for more information.
The combination of two independent businesses is complex, costly and time consuming, and we will be required to continue to devote significant management attention and resources to integrating the business practices and operations of Parkland into the Partnership to achieve, among other things, the targeted cost synergies associated with the acquisition. To the extent we are unable to successfully integrate the business and operations of Parkland into the Partnership, and to the extent we are unable to successfully manage the creation and associated expenses of SunocoCorp, our business, results of operations and our ability to achieve the anticipated benefits of the acquisition may be adversely affected.
Acquisitions are subject to substantial risks that could adversely affect our financial condition and results of operations and reduce our ability to make distributions to unitholders.
Any acquisitions involve potential risks, including, among others:
•the validity of our assumptions about revenues, capital expenditures and operating costs of the acquired business or assets, as well as assumptions about achieving synergies with our existing business;
•the validity of our assessment of environmental and other liabilities, including legacy liabilities;
•the costs associated with additional debt or equity capital, which may result in a significant increase in our interest expense and financial leverage resulting from any additional debt incurred to finance the acquisition, or the issuance of additional common units on which we will make distributions, either of which could offset the expected accretion to our unitholders from such acquisition and could be exacerbated by volatility in the equity or debt capital markets;
•a failure to realize anticipated benefits, such as increased available cash per unit, enhanced competitive position or new customer relationships;
•a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance the acquisition;
•the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges; and
•the risk that our existing financial controls, information systems, management resources and human resources will need to grow to support future growth and we may not be able to react timely.
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We could be subject to liabilities from our assets that predate our acquisition of those assets, but that are not covered by indemnification rights we have against the sellers of the assets.
We have acquired assets and businesses and we are not always indemnified by the seller for liabilities that precede our ownership. In addition, in some cases, we have indemnified the previous owners and operators of acquired assets or businesses. Some of our assets have been used for many years to refine, 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.
The Inflation Reduction Act of 2022 could accelerate the transition to a low carbon economy and could impose new costs on our operations.
In August 2022, President Biden signed the IRA 2022, which contains hundreds of billions in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, amongst other provisions. In addition, the IRA 2022 amended the Clean Air Act to impose a fee on the emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the onshore petroleum and natural gas production categories. However, the OBBBA amended the Clean Air Act to postpone the implementation of the fee until 2034. Although the OBBBA made various changes to the incentives created under the IRA 2022, including elimination of electric vehicle credits, if the incentives offered for various clean energy industries referenced above are pursued in the future, it could further accelerate the transition of the economy away from the use of fossil fuels and decrease demand for gasoline and diesel, increase our compliance and operating costs and consequently adversely affect our business.
Regulatory Matters
Our operations are subject to federal, state, provincial and local laws and regulations, in North America, the Greater Caribbean and Europe, relating to the environment, 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, including those relating to: terminals and underground storage tanks; refinery operations; the release or discharge of regulated materials into the air, water and soil; the generation, storage, handling, use, transportation and disposal of hazardous materials; the exposure of persons to regulated materials; and the health and safety of our employees. A violation of, liability under, or noncompliance with these laws and regulations, or any future environmental law or regulation, could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution to our unitholders.
In the United States, regulations under the Clean Water Act, OPA 90 and state laws impose regulatory burdens on terminal operations. Spill prevention control and countermeasure requirements of federal and state laws require containment to mitigate or prevent contamination of waters in the event of a refined product overflow, rupture or leak from above-ground pipelines and storage tanks. The Clean Water Act also requires us to maintain spill prevention control and countermeasure plans at our terminal facilities with above-ground storage tanks and pipelines. In addition, OPA 90 requires that most fuel transport and storage companies maintain and update various oil spill prevention and oil spill contingency plans. Certain oil handling facilities that are adjacent to water require the engagement of Federally Certified Oil Spill Response Organizations to be available to respond to a spill on water from above-ground storage tanks or pipelines.
Transportation and storage of refined products over and adjacent to water involves risk and potentially subjects us to strict, joint and potentially unlimited liability for removal costs and other consequences of an oil spill where the spill is into navigable waters, along shorelines or in the exclusive economic zone of the United States. In the event of an oil spill into navigable waters, substantial liabilities could be imposed upon us. The Clean Water Act imposes restrictions and strict controls regarding the discharge of pollutants into navigable waters, with the potential of substantial liability for the violation of permits or permitting requirements.
Terminal operations and associated facilities are subject to the Clean Air Act as well as comparable state and local statutes. Under these laws, permits may be required before construction can commence on a new source of potentially significant air emissions, and operating permits may be required for sources that are already constructed. If regulations become more stringent, additional emission control technologies may be required at our facilities. Any such future obligation could require us to incur significant additional capital or operating costs. Additionally, permits or licenses may be difficult to obtain and may include public comment and other public involvement periods, which could affect agency considerations or the decisions reached. For more information, see our regulatory disclosure titled “Air Emissions and Climate Change.”
Terminal operations are subject to additional programs and regulations under OSHA, such as the Process Safety Management rule. Liability under, or a violation of compliance with, these laws and regulations, or any future laws or regulations, could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution to our unitholders.
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Pipeline operations are also subject to a number of environmental and safety programs and regulations. Should our operations fail to comply with applicable Department of Transportation or comparable state regulations regarding pipeline safety, we could be subject to substantial fines and penalties. In addition, the adoption of recently proposed or new laws or regulations that apply more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased operational costs that could be significant. For more information, see our regulatory disclosure titled “Pipeline Safety Regulation.”
Certain environmental laws, including CERCLA, impose strict, and under certain circumstances, joint and several, liability on the current and former owners and operators of properties for the costs of investigation and removal or remediation of contamination and also impose liability for any related damages to natural resources without regard to fault. Under CERCLA and similar state laws, as persons who arrange for the transportation, treatment, and disposal of hazardous substances, we may also be subject to liability at sites where such hazardous substances are released. We may be subject to third-party claims alleging property damage and/or personal injury in connection with releases of or exposure to hazardous substances at, from, or in the vicinity of our current or former properties or off-site waste disposal sites. Costs associated with the investigation and remediation of contamination, as well as associated third-party claims, could be substantial, and could have a material adverse effect on our business, financial condition, results of operations and our ability to service our outstanding indebtedness. In addition, the presence of, or failure to remediate, identified or unidentified contamination at our properties could materially and adversely affect our ability to sell or rent such property or to borrow money using such property as collateral.
We are required to make financial expenditures to comply with regulations governing underground storage tanks as adopted by federal, state and local regulatory agencies. Compliance with existing and future environmental laws regulating underground storage tank systems of the kind we use may require significant capital expenditures. For example, the EPA has previously published rules that amend existing federal underground storage tank rules, requiring certain upgrades to underground storage tanks and related piping to further ensure the detection, prevention, investigation, and remediation of leaks and spills.
We are required to comply with federal and state financial responsibility requirements to demonstrate that we have the ability to pay for cleanups or to compensate third parties for damages incurred as a result of a release of regulated materials from our underground storage tank systems. We seek to comply with these requirements by maintaining insurance that we purchase from private insurers and in certain circumstances, rely on applicable state trust funds, which are funded by underground storage tank registration fees and taxes on wholesale purchases of motor fuels. Coverage afforded by each fund varies and is dependent upon the continued maintenance and solvency of each fund.
We are responsible for investigating and remediating contamination at a number of our current and former properties. We are entitled to reimbursement for certain of these costs under various third-party contractual indemnities and insurance policies, subject to eligibility requirements, deductibles, and per incident, annual and aggregate caps. To the extent third parties (including insurers) do not pay for investigation and remediation, and/or insurance is not available, we will be obligated to make these additional payments, which could have a material adverse impact on our business, liquidity, results of operations and cash available for distribution to our unitholders.
Although we believe that we have a comprehensive environmental, health, and safety program, we may not have identified all environmental liabilities at all of our current and former locations; material environmental or pipeline safety conditions not known to us may exist; existing and future laws, ordinances or regulations may impose material environmental or pipeline safety liability or compliance cos ts on us; or we may be required to make material expenditures for the remediation of contamination or pipeline integrity and safety matters.
Further, as discussed above, with the acquisition of the Burnaby Refinery located in BC, we are subject to a number of additional regulatory and environmental requirements in Canada, which may increase our costs of compliance and, in turn, have a material adverse impact on our results of operations.
The occurrence of any of the events described abov e could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution to our unitholders.
Our operations are subject to a series of risks related to climate change.
The threat of climate change continues to attract considerable attention in the United States and in foreign countries. In the United States to date, no comprehensive climate change legislation has been implemented at the federal level, although federal regulators, state and local governments, and private parties have taken (or announced that they plan to take) actions related to climate change that have or may have a significant impact on our operations. However, following the change in U.S. presidential administrations, proposals have been made to repeal or otherwise modify climate change-related requirements. For example, in February 2026, the EPA finalized a rule rescinding the GHG “Endangerment Finding,” which underpins the majority of EPA’s GHG regulations. Litigation challenging the rule is expected. As a result, there is significant uncertainty with respect to future regulation of GHG emissions. For more information, see our regulatory disclosure titled “Air Emissions and Climate Change.”
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Internationally, the United Nations-sponsored Paris Agreement requires member states to individually determine and submit non-binding emissions reduction targets every five years after 2020. While previously a party to the Paris Agreement, in January 2025, President Trump issued an executive order withdrawing of the United States from the Paris Agreement and revoking any related financial commitments thereunder. State or local governments may, however, elect to continue to participate in international climate change initiatives and pursue state- or regional-level climate change-related regulations. Any efforts to control and/or reduce GHG emissions by the United States or other countries, or concerted conservation efforts that result in reduced consumption, could adversely impact demand for our products and, in turn, our financial position and results of operations. Increasingly, fossil fuel companies are also exposed to litigation risks from climate change.
Additionally, California has recently enacted a set of laws that may require climate-related disclosures from companies “doing business in California” with certain total annual revenue thresholds, though these laws are currently subject to litigation, and we cannot predict the ultimate outcome. Moreover, some other states in which we operate, such as New York and Illinois, are considering adopting climate disclosure laws. For more information, see our regulatory disclosure titled “Air Emissions and Climate Change.” Although the final form and substance of these requirements is not yet known, these rules and laws may result in additional costs to comply with any such disclosure requirements.
Climate change may also result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns that could adversely impact our operations or those of our supply chains. Such physical risks may result in damage to our facilities or otherwise adversely impact our operations, the demand for our products, the frequency with which consumers may visit our locations or the cost or availability of insurance. Moreover, certain parties, including local and state governments, have from time to time filed lawsuits against various fossil fuel energy companies seeking damages for alleged physical impacts resulting from climate change or relating to false or misleading statements related to fossil fuel’s contribution to climate change. These various political, regulatory, financial, physical and litigation risks related to climate change have the potential to adversely impact our operations and financial performance.
A climate-related decrease in demand for crude oil could negatively affect our business.
Supply and demand for crude oil is dependent upon a variety of factors, many of which are beyond our control. These factors include, among others, the potential adoption of new government regulations, including those related to fuel conservation measures and climate change regulations, technological advances in fuel economy and energy generation devices. For example, legislative, regulatory or executive actions intended to reduce emissions of GHGs could increase the cost of consuming crude oil, thereby potentially causing a reduction in the demand for this product. A broader transition to alternative fuels or energy sources, whether resulting from potential new government regulation, carbon taxes, governmental incentives and funding such as those provided in the IRA 2022, or consumer preferences could result in decreased demand for products like crude oil. Any decrease in demand could consequently reduce demand for our services and could have a negative effect on our business.
Increased attention to environmental, social and governance (“ESG”) matters and conservation measures may adversely impact our business.
Attention from investors, customers, employees, regulatory bodies and other stakeholders to climate change, societal expectations on companies to address climate change or social and employment initiatives and other ESG matters, investor and societal expectations regarding voluntary ESG disclosures, and consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, heightened scrutiny of our statements and initiatives, and negative impacts on our common unit price and access to capital markets.
Moreover, while we may create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures may be based on expectations, assumptions and hypothetical scenarios. Such expectations, assumptions and hypothetical scenarios are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established approach to identifying, measuring and reporting on many ESG matters. Additionally, while we may announce various voluntary ESG targets, such targets are often aspirational. We may not be able to meet or progress against such targets in the manner or on such a timeline as initially contemplated, including but not limited to as a result of unforeseen costs or technical difficulties associated with achieving such results. To the extent we meet such targets, it may be achieved through various contractual arrangements, including the purchase of various credits or offsets that may be deemed to mitigate our environmental impact instead of actual changes in our business operations. Some of these arrangements may receive scrutiny from certain constituencies.
Certain regulators, such as various state agencies, as well as nongovernmental organizations and other private actors have filed lawsuits under various securities and consumer protection laws alleging that certain ESG statements, goals or standards were misleading, false or otherwise deceptive, including for alleged “greenwashing” (i.e., the process of conveying misleading information or making false claims that overstate potential ESG benefits). Certain social and inclusion initiatives are the subject of scrutiny by both those calling for the continued advancement of such policies, as well as those who believe they should be curbed, including government actors, and the complex regulatory and legal frameworks applicable to such initiatives continue to evolve. More recent
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political developments could mean that the Partnership faces increasing criticism or litigation risks from certain “anti-ESG” parties, including various governmental agencies. Such sentiment may focus on the Partnership’s environmental commitments (such as reducing GHG emissions) or its pursuit of certain employment practices or social initiatives that are alleged to be political or polarizing in nature or are alleged to violate laws based, in part, on changing priorities of, or interpretations by, federal agencies or state governments. Consideration of ESG-related factors in the Partnership’s decision-making could be subject to increasing scrutiny and objection from such anti-ESG parties. As a result, the Partnership may be subject to pressure in the media or through other means, such as governmental investigations, enforcement actions, or other proceedings, all of which could adversely affect our reputation, business, financial performance, market access and growth. Accordingly, there may be increased costs related to reviewing, implementing and managing such policies, as well as compliance and litigation risks based both on positions we do or do not take, or work we do or do not perform.
ESG activism directed at shifting funding away from companies with fossil fuel-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our common unit price and our access to and costs of capital. Also, institutional lenders may decide not to provide funding for fossil fuel companies based on climate change related concerns, which could affect our access to capital.
Sunoco is subject to federal laws related to the RFS.
New laws, new interpretations of existing laws, increased governmental enforcement of existing laws or other developments could require us to make additional capital expenditures or incur additional liabilities. For example, at times, certain independent refiners have initiated discussions with the EPA to change the way the RFS is administered in an attempt to shift the burden of compliance from refiners and importers to blenders and distributors. Under the RFS, which requires an annually increasing amount of biofuels to be blended into the fuels used by U.S. drivers, refiners/importers are obligated to obtain renewable identification numbers (“RINs”) either by blending biofuel into gasoline or through purchase in the open market. If the obligation was shifted from the importer/refiner to the blender/distributor, the Partnership would potentially have to utilize the RINs it obtains through its blending activities to satisfy a new obligation and would be unable to sell RINs to other obligated parties, which may cause an impact on the fuel margins associated with the Partnership’s sale of gasoline. Additionally, the price of RINs is not fixed and is subject to change due to various considerations, including regulatory actions. In June 2025, the EPA proposed volume requirements for 2026 and 2027 that continue to build on the increasing volume requirements established in July 2023, though the substance of any final rule is uncertain.
The occurrence of any of the events described above could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution to our unitholders.
Sunoco is subject to federal, state and local laws and regulations that govern the product quality specifications of refined petroleum products it purchases, stores, transports, and sells to its distribution customers.
Various federal, state, and local government agencies have the authority to prescribe specific product quality specifications for certain commodities, including commodities that we distribute. Changes in product quality specifications, such as reduced sulfur content in refined petroleum products, or other more stringent requirements for fuels, could reduce our ability to procure product, require us to incur additional handling costs and/or require the expenditure of capital. If we are unable to procure product or recover these costs through increased selling price, we may not be able to meet our financial obligations. Failure to comply with these regulations could result in substantial penalties.
We operate assets outside of the United States, which exposes us to different legal and regulatory requirements and additional risk.
A portion of our revenues are generated from our assets located in Canada, the Greater Caribbean northern Mexico and Europe. Our operations are subject to various risks 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 and tensions in Venezuela, 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.
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Disputes regarding a failure to maintain product quality specifications or other claims related to the operation of our assets and the services we provide to our customers 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.
The swaps regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder could have an adverse effect on our ability to use derivative instruments to mitigate the risks of changes in commodity prices and interest rates and other risks associated with our business.
Provisions of the Dodd-Frank Act and rules adopted by the Commodity Futures Trading Commission (the “CFTC”), the SEC and other prudential regulators establish federal regulation of the physical and financial derivatives, including over-the-counter derivatives market and entities, such as us, participating in that market. While most of these regulations are already in effect, the implementation process is still ongoing and the CFTC continues to review and refine its initial rulemakings through additional interpretations and supplemental rulemakings. As a result, any new regulations or modifications to existing regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability and/or liquidity of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. Any of these consequences could have a material adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.
The CFTC has re-proposed speculative position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents, although certain bona fide hedging transactions would be exempt from these position limits provided that various conditions are satisfied. The CFTC has also finalized a related aggregation rule that requires market participants to aggregate their positions with certain other persons under common ownership and control, unless an exemption applies, for purposes of determining whether the position limits have been exceeded. If adopted, the revised position limits rule and its finalized companion rule on aggregation may create additional implementation or operational exposure. In addition to the CFTC federal speculative position limit regime, designated contract markets (“DCMs”) also maintain speculative position limit and accountability regimes with respect to contracts listed on their platform as well as aggregation requirements similar to the CFTC’s final aggregation rule. Any speculative position limit regime, whether imposed at the federal-level or at the DCM-level may impose added operating costs to monitor compliance with such position limit levels, addressing accountability level concerns and maintaining appropriate exemptions, if applicable.
The Dodd-Frank Act requires that certain classes of swaps be cleared on a derivatives clearing organization and traded on a DCM or other regulated exchange, unless exempt from such clearing and trading requirements, which could result in the application of certain margin requirements imposed by derivatives clearing organizations and their members. The CFTC and prudential regulators have also adopted mandatory margin requirements for uncleared swaps entered into between swap dealers and certain other counterparties. We currently qualify for and rely upon an end-user exception from such clearing and margin requirements for the swaps we enter into to hedge our commercial risks. However, the application of the mandatory clearing and trade execution requirements and the uncleared swaps margin requirements to other market participants, such as swap dealers, may adversely affect the cost and availability of the swaps that we use for hedging.
In addition to the Dodd-Frank Act, the European Union and other foreign regulators have adopted and are implementing local reforms generally comparable with the reforms under the Dodd-Frank Act. Implementation and enforcement of these regulatory provisions may reduce our ability to hedge our market risks with non-U.S. counterparties and may make transactions involving cross-border swaps more expensive and burdensome. Additionally, the lack of regulatory equivalency across jurisdictions may increase compliance costs and make it more difficult to satisfy our regulatory obligations.
If third-party pipelines and other facilities interconnected to our fuel storage terminals and transmix processing facilities become partially or fully unavailable to transport refined products, our revenues could be adversely affected.
We depend upon third-party pipelines and other facilities that provide delivery options to and from our fuel storage terminals and transmix processing facilities. Since we do not own or operate these pipelines or other facilities, their continuing operation in their current manner is not within our control. If any of these third-party facilities become partially or fully unavailable, or if the quality specifications for their facilities change so as to restrict our ability to utilize them, our financial condition and results of operations could be adversely affected.
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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, in the U.S. and internationally, 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.
Certain of our interstate common carrier pipelines are subject to regulation by the FERC and the STB, 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 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 2025 and 2026. See our regulatory disclosure titled “Regulation of Interstate Crude Oil and Products Pipelines” for additional information on FERC’s indexing methodology.
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 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.
The third parties on whom we rely for transportation services to our fuel storage terminals and transmix processing facilities are subject to complex federal, state, and other laws that could adversely affect our financial condition and results of operations.
The operations of the third parties on whom we rely for transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for services. Similarly, a failure to comply with such laws and regulations by the third parties could have a material adverse effect on our financial condition and results of operations.
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Indebtedness
Our debt levels may impair our financial condition and our ability to make distributions on our Series A Preferred Units, common units and Class D Units.
We had $13.39 billion of debt outstanding as of December 31, 2025, which includes approximately $3.65 billion aggregate principal amount of debt we assumed and issued in connection with the Parkland Acquisition. We have the ability to incur additional debt under our Credit Facility and the indentures governing our senior notes. The level of our future indebtedness could have important consequences to us, including:
•making it more difficult for us to satisfy our obligations with respect to our senior notes and our credit agreement governing our Credit Facility;
•limiting our ability to borrow additional amounts to fund working capital, capital expenditures, acquisitions, debt service requirements, the execution of our growth strategy and other activities;
•requiring us to dedicate a substantial portion of our cash flow from operations to pay interest and principal on our debt, which would reduce our cash flow available to make distributions to our unitholders and to fund working capital, capital expenditures, acquisitions, execution of our growth strategy and other activities;
•making us more vulnerable to adverse changes in general economic conditions, our industry and government regulations and in our business by limiting our flexibility in planning for, and making it more difficult for us to react quickly to, changing conditions; and
•placing us at a competitive disadvantage compared with our competitors that have less debt.
In addition, we may not be able to generate sufficient cash flow from our operations to repay our indebtedness when it becomes due and to meet other cash needs. Our ability to service our debt depends upon, among other things, our financial and operating performance as impacted by prevailing economic conditions, and financial, business, regulatory and other factors, some of which are beyond our control. In addition, our ability to service our debt will depend on market interest rates, since the rates applicable to a portion of our borrowings fluctuate. If we are not able to pay our debts as they become due, we will be required to pursue one or more alternative strategies, such as selling assets, refinancing or restructuring our indebtedness or selling additional debt or equity securities. We may not be able to refinance our debt or sell additional debt or equity securities or our assets on favorable terms, if at all, and if we must sell our assets, it may negatively affect our ability to generate revenues.
Increases in interest rates could reduce the amount of cash we have available for distributions as well as the relative value of those distributions to yield-oriented investors, which could cause a decline in the market value of our common units.
Borrowings under our Credit Facility bear interest at variable interest rates. Should variable interest rates rise, the amount of cash we would otherwise have available for distribution would ordinarily be expected to decline, which could impact our ability to make distributions on our Series A Preferred Units or to maintain or grow our quarterly distributions. Additionally, an increase in interest rates in lower risk investment alternatives, such as United States treasury securities, could cause investors to demand a relatively higher distribution yield on our common units, which, unless we are able to raise our distribution, would imply a lower trading price for our common units. Consequently, rising interest rates could cause a significant decline in the market value of our common units.
Our existing debt agreements have substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions to our unitholders.
We are dependent upon the earnings and cash flow generated by our operations in order to meet our debt service obligations and to allow us to make cash distributions to our unitholders. The operating and financial restrictions and covenants in our credit agreement, the indentures governing our senior notes, the indentures governing NuStar’s senior notes, the agreements governing the revenue bonds issued by the Parish of St. James, Louisiana pursuant to the Gulf Opportunity Zone Act of 2005 (the “GoZone Bonds”) and any future financing agreements may restrict our ability to finance future operations or capital needs, to engage in or expand our business activities or to pay distributions to our unitholders. For example, our credit agreement, the indentures governing our senior notes, the indentures governing the NuStar senior notes and the agreements governing the GoZone Bonds restrict our ability to, among other things:
•incur certain additional indebtedness;
•incur, permit, or assume certain liens to exist on our properties or assets;
•make certain investments or enter into certain restrictive material contracts;
•make distributions;
•repurchase units; and
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•merge or dispose of all or substantially all of our assets.
In addition, our credit agreement contains covenants requiring us to maintain certain financial ratios. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources” for additional information.
Our future ability to comply with these restrictions and covenants is uncertain and will be affected by the levels of cash flow from our operations and other events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of our credit agreement, the indentures governing our senior notes, the indentures governing the NuStar senior notes, the agreements governing the GoZone Bonds or any agreements governing future indebtedness that are not cured or waived within the appropriate time period provided therein, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions to our unitholders will be inhibited and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments.
Detail of Risk Factors Related to Our Structure
Our General Partner
Energy Transfer owns and controls our General Partner, which has sole responsibility for conducting our business and managing our operations. Our General Partner and its affiliates, including Energy Transfer, have conflicts of interest with us and limited contractual duties and they may favor their own interests to the detriment of us and our unitholders.
Energy Transfer owns and controls our General Partner and, following the Parkland Acquisition, has delegated its power and authority to appoint all of the directors of our General Partner to SunocoCorp pursuant to that certain Delegation Agreement, dated October 27, 2025, by and among Energy Transfer, the General Partner and SunocoCorp (the “Delegation Agreement”). Energy Transfer, as sole member of the managing member of SunocoCorp, controls the appointment of the directors by SunocoCorp under the Delegation Agreement. Although our General Partner has a contractual obligation to manage us in a manner it believes is not adverse to us, the executive officers and directors of our General Partner also have a contractual duty to manage our General Partner in a manner beneficial to Energy Transfer. Therefore, conflicts of interest may arise between Energy Transfer and its affiliates, including our General Partner and SunocoCorp, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our General Partner may favor its own interests and the interests of its affiliates over the interests of our common unitholders. These conflicts include the following situations, among others:
•Our General Partner’s affiliates, including Energy Transfer, SunocoCorp and their respective affiliates, are not prohibited from engaging in other business or activities, including those in direct competition with us.
•In addition, neither our Partnership Agreement nor any other agreement requires Energy Transfer to pursue a business strategy that favors us. The affiliates of our General Partner have contractual duties to make decisions in their own best interests and in the best interest of their owners, which may be contrary to our interests. In addition, our General Partner is allowed to take into account the interests of parties other than us or our unitholders, such as Energy Transfer, in resolving conflicts of interest.
•Certain officers and directors of our General Partner are officers or directors of affiliates of our General Partner, including SunocoCorp, and also devote significant time to the business of these entities and are compensated accordingly.
•Affiliates of our General Partner, including Energy Transfer and SunocoCorp, are not limited in their ability to compete with us and may offer business opportunities or sell assets to parties other than us.
•Our Partnership Agreement provides that our General Partner may, but is not required to, in connection with its resolution of a conflict of interest, seek “special approval” of such resolution by appointing a conflicts committee of the General Partner’s board of directors composed of one or more independent directors to consider such conflicts of interest and to either, itself, take action or recommend action to the board of directors, and any resolution of the conflict of interest by the conflicts committee shall be conclusively deemed to be approved by our unitholders.
•Except in limited circumstances, our General Partner has the power and authority to conduct our business without unitholder approval.
•Our General Partner determines the amount and timing of asset purchases and sales, borrowings, repayment of indebtedness and issuances of additional partnership securities and the level of reserves, each of which can affect the amount of cash that is distributed to our unitholders.
•Our General Partner determines the amount and timing of any capital expenditure and whether a capital expenditure is classified as a maintenance capital expenditure or an expansion capital expenditure. These determinations can affect the amount of cash that is distributed to our unitholders.
•Our General Partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions on the IDRs.
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•Our Partnership Agreement permits us to distribute up to $25 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on the IDRs.
•Our General Partner determines which costs incurred by it and its affiliates are reimbursable by us.
•Our Partnership Agreement does not restrict our General Partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with its affiliates on our behalf. There is no limitation on the amounts our General Partner can cause us to pay it or its affiliates.
•Our General Partner has limited its liability regarding our contractual and other obligations.
•Our General Partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units.
•Our General Partner controls the enforcement of obligations owed to us by it and its affiliates. In addition, our General Partner will decide whether to retain separate counsel or others to perform services for us.
•Energy Transfer may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to Energy Transfer’s IDRs without the approval of the conflicts committee of the board of directors of our General Partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
Our General Partner has limited its liability regarding our obligations.
Our General Partner has limited its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our General Partner or its assets. Our General Partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our General Partner. Our Partnership Agreement provides that any action taken by our General Partner to limit its liability is not a breach of our General Partner’s contractual duties to us, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our General Partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
Our General Partner may approve the issuance of partnership securities and specify the terms of such partnership securities.
Pursuant to our Partnership Agreement, our General Partner has the ability to approve the issuance of securities by the Partnership at any time and to specify the terms and conditions of such securities without the approval of our unitholders. The securities authorized to be issued may be issued in one or more classes or series, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of partnership securities), as shall be determined by our General Partner, including:
•the right to share in the Partnership’s profits and losses;
•the right to share in the Partnership’s distributions;
•the rights upon dissolution and liquidation of the Partnership;
•whether, and the terms upon which, the Partnership may redeem the securities;
•whether the securities will be issued, evidenced by certificates and assigned or transferred; and
•the right, if any, of the security to vote on matters relating to the Partnership, including matters relating to the relative rights, preferences and privileges of such security.
Cost reimbursements due to our General Partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our unitholders. The amount and timing of such reimbursements will be determined by our General Partner.
Prior to making any distribution on the common units, we will reimburse our General Partner and its affiliates for all expenses they incur and payments they make on our behalf pursuant to our Partnership Agreement. Our Partnership Agreement does not limit the amount of expenses for which our General Partner and its affiliates may be reimbursed. Our Partnership Agreement provides that our General Partner will determine in good faith the expenses that are allocable to us. Reimbursement of expenses and payment of fees to our General Partner and its affiliates will reduce the amount of cash available to pay distributions to our unitholders.
Our Partnership Agreement
Our Partnership Agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
Our Partnership Agreement requires that we distribute all of our available cash to our unitholders. Our General Partner will determine the amount and timing of such distributions and has broad discretion to establish and make additions to our reserves in amounts it determines in its reasonable discretion to be necessary or appropriate. As such, we rely primarily upon external financing sources,
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including borrowings under our Credit Facility and the issuance of debt and equity securities, to fund our acquisitions and expansion capital requirements. To the extent we are unable to finance growth externally, our cash distribution policy may significantly impair our ability to grow.
In addition, because we distribute all of our available cash, our growth rate may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our Partnership Agreement on our ability to issue additional units, including units ranking senior to existing common units. The incurrence of bank borrowings or other debt to finance our growth strategy may result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.
Our Partnership Agreement limits the liability and duties of our General Partner and restricts the remedies available to us and our common unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty if we were a Delaware corporation.
Our Partnership Agreement limits the liability and duties of our General Partner, while also restricting the remedies available to our common unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty under Delaware law. Delaware partnership law permits such contractual reductions or elimination of fiduciary duty. By purchasing common units, common unitholders consent to be bound by the Partnership Agreement, and pursuant to our Partnership Agreement, each unitholder consents to various actions and conflicts of interest contemplated in our Partnership Agreement that might otherwise constitute a breach of fiduciary or other duties under Delaware law. For example:
•Our Partnership Agreement permits our General Partner to make a number of decisions in its individual capacity, as opposed to its capacity as General Partner. This entitles our General Partner to consider only the interests and factors that it desires, with no duty or obligation to give consideration to the interests of, or factors affecting, our common unitholders. Decisions made by our General Partner in its individual capacity will be made by Energy Transfer, as the owner of our General Partner, and not by the board of directors of our General Partner. Examples of such decisions include:
◦whether to exercise limited call rights;
◦how to exercise voting rights with respect to any units it owns;
◦whether to exercise registration rights; and
◦whether to consent to any merger or consolidation, or amendment to our Partnership Agreement.
•Our Partnership Agreement provides that our General Partner will not have any liability to us or our unitholders for decisions made in its capacity as General Partner so long as it acted in good faith as defined in the Partnership Agreement, meaning it believed that the decisions were not adverse to the interests of our partnership.
•Our Partnership Agreement provides that our General Partner and the officers and directors of our General Partner will not be liable for monetary damages to us for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our General Partner or those persons acted in bad faith or, in the case of a criminal matter, acted with knowledge that such person’s conduct was criminal.
•Our Partnership Agreement provides that our General Partner will not be in breach of its obligations under the Partnership Agreement or its duties to us or our limited partners with respect to any transaction involving an affiliate if:
◦the transaction with an affiliate or the resolution of a conflict of interest is:
•approved by the conflicts committee of the board of directors of our General Partner, although our General Partner is not obligated to seek such approval;
•approved by the vote of a majority of the outstanding common units, excluding any common units owned by our General Partner and its affiliates; or
•the board of directors of our General Partner acted in good faith in taking any action or failing to act.
If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors acted in good
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faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Energy Transfer may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its IDRs, without the approval of the conflicts committee of our General Partner’s board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.
Energy Transfer has the right, at any time it has received incentive distributions at the highest level to which it is entitled (50%) for each of the prior four consecutive whole fiscal quarters (and the amount of each such did not exceed adjusted operating surplus for each such quarter), to reset the initial target distribution levels at higher levels based on our cash distributions at the time of the exercise of the reset election. Following a reset election by Energy Transfer, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on the same percentage increases above the reset minimum quarterly distribution reflected by the current target distribution levels.
If Energy Transfer elects to reset the target distribution levels, it will be entitled to receive a number of common units equal the number of common units which would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to Energy Transfer on the IDRs in the prior two quarters. We anticipate that Energy Transfer would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that Energy Transfer could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its IDRs and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that they would have otherwise received had we not issued new common units to Energy Transfer in connection with resetting the target distribution levels.
Holders of our common units have limited voting rights and are not entitled to elect our General Partner or its directors.
Unlike the holders of common stock in a corporation, our common unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our common unitholders have no right on an annual or ongoing basis to elect our General Partner or its board of directors. The board of directors of our General Partner, including the independent directors, are chosen entirely by Energy Transfer due to its ownership of our General Partner, and not by our common unitholders. Unlike a publicly traded corporation, we do not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. Our Partnership Agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders’ ability to influence the manner or direction of management.
Even if holders of our common units are dissatisfied, they cannot easily remove our General Partner without its and SunocoCorp’s consent.
If our unitholders are dissatisfied with the performance of our General Partner, they have limited ability to remove our General Partner. Our General Partner generally may not be removed except upon the vote of the holders of 66⅔% of our outstanding common units, including units owned by our General Partner and its affiliates, and the holders of 66⅔% of our outstanding Class D Units, including units owned by SunocoCorp and its affiliates. Further, the right of the holders of our outstanding common units and Class D Units to remove our General Partner shall not exist or be exercised unless we have received an opinion of counsel confirming that the removal of the General Partner will not result in SunocoCorp being required to be registered under the Investment Company Act of 1940, as amended. As of December 31, 2025, Energy Transfer and its affiliates held approximately 20.8% of our outstanding common units, and SunocoCorp holds 100% of our outstanding Class D Units.
Our General Partner interest or the control of our General Partner may be transferred to a third party without unitholder consent.
Our General Partner may transfer its General Partner interest to a third party without the consent of our unitholders in a merger, in a sale of all or substantially all of its assets or in other transactions so long as certain conditions are satisfied. Furthermore, our Partnership Agreement does not restrict the ability of Energy Transfer to transfer all or a portion of its interest in our General Partner to a third party. Pursuant to the Delegation Agreement, Energy Transfer delegated its power and authority to elect, appoint and remove the directors and officers of our General Partner to SunocoCorp, which Energy Transfer may terminate under certain circumstances. Any new owner of SunocoCorp or our General Partner interest would then be in a position to replace the board of directors and executive officers of our General Partner with its own designees without the consent of unitholders and thereby exert significant control over us, and may change our business strategy.
Our General Partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.
If at any time our General Partner and its affiliates own more than 80% of the common units, our General Partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held
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by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our General Partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our General Partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our Partnership Agreement that prevents our General Partner from issuing additional common units and exercising its call right.
We may issue additional units without unitholder approval, which would dilute existing unitholder ownership interests.
Our Partnership Agreement does not limit the number of additional limited partner interests we may issue at any time without the approval of our unitholders. The issuance of additional common units or other equity interests of equal or senior rank will have the following effects:
•our existing unitholders’ proportionate ownership interest in us will decrease;
•the amount of cash available for distribution on each 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 the common units may decline.
The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets, including sales by Energy Transfer.
As of December 31, 2025, Energy Transfer owned 28,463,967 of our co mmon units. The sale or disposition of a substantial portion of these units in the public or private markets could reduce the market price of our outstanding common units.
Our Partnership Agreement restricts the voting rights of unitholders owning 20% or more of our outstanding common units.
Our Partnership Agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our General Partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our General Partner, cannot vote on any matter.
The amount of cash we have available for distribution to holders of our units depends primarily on our cash flow and not solely on profitability, which may prevent us from making cash distributions during periods when we record net income.
The amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may pay cash distributions during periods when we record net losses for financial accounting purposes and may not pay cash distributions during periods when we record net income.
Unitholders may have liability to repay distributions.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to such purchaser at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the Partnership Agreement. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Our Partnership Agreement limits the forum, venue and jurisdiction of claims, suits, actions or proceedings.
Our Partnership Agreement is governed by Delaware law. Our Partnership Agreement requires that any claims, suits, actions or proceedings:
•arising out of or relating in any way to our Partnership Agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our Partnership Agreement or the duties, obligations or liabilities among our limited partners or of our limited partners to us, or the rights or powers of, or restrictions on, our limited partners or us);
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•brought in a derivative manner on our behalf;
•asserting a claim of breach of a fiduciary duty owed by any director, officer or other employee of us or our General Partner, or owed by our General Partner, to us or the limited partners;
•asserting a claim arising pursuant to any provision of the Delaware Act; or
•asserting a claim governed by the internal affairs doctrine,
will be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction). By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware in connection with any such claims, suits, actions or proceedings.
The provisions may have the effect of discouraging lawsuits against our directors, officers, employees and agents. The enforceability of similar forum selection provisions in other companies’ certificates of incorporation or similar governing documents have been challenged in legal proceedings, and it is possible that, in connection with one or more actions or proceedings described above, a court could find that the forum selection provision contained in our Partnership Agreement is inapplicable or unenforceable in such action or actions, including with respect to claims arising under the federal securities laws. Limited partners will not be deemed, by operation of the forum selection provision alone, to have waived claims arising under the federal securities laws and the rules and regulations thereunder.
The forum selection provision is intended to apply “to the fullest extent permitted by applicable law” to the above-specified types of actions and proceedings, including, to the extent permitted by the federal securities laws, to lawsuits asserting both the above-specified claims and federal securities claims. However, application of the forum selection provision may in some instances be limited by applicable law. Section 27 of the Exchange Act provides: “The district courts of the United States ... shall have exclusive jurisdiction of violations of the Exchange Act or the rules and regulations thereunder, and of all suits in equity and actions at law brought to enforce any liability or duty created by the Exchange Act or the rules and regulations thereunder.” As a result, the forum selection provision will not apply to actions arising under the Exchange Act or the rules and regulations thereunder. However, Section 22 of the Securities Act of 1933, as amended (the "Securities Act") provides for concurrent federal and state court jurisdiction over actions under the Securities Act and the rules and regulations thereunder, subject to a limited exception for certain “covered class actions” as defined in Section 16 of the Securities Act and interpreted by the courts. Accordingly, we believe that the forum selection provision would apply to actions arising under the Securities Act or the rules and regulations thereunder, except to the extent a particular action fell within the exception for covered class actions.
The NYSE does not require a publicly traded partnership like us to comply with certain corporate governance requirements.
Because we are a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our General Partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to stockholders of corporations that are subject to all of the corporate governance requirements of the applicable stock exchange.
Detail of Tax Risks to Unitholders
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for U.S. federal income tax purposes or we were otherwise subject to a material amount of entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our units depends largely on our being treated as a partnership for U.S. federal income tax purposes.
Despite the fact that we are organized as a limited partnership under Delaware law, we will be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, no ruling has been or will be requested regarding our treatment as a partnership for U.S. federal income tax purposes. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 21%, and would likely pay state income tax at varying rates. Distributions to our unitholders who are treated as holders of corporate stock would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced.
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Our Partnership Agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for U.S. federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are currently subject to the entity-level Texas franchise tax. Imposition of any such additional taxes on us or an increase in the existing tax rates would reduce the cash available for distribution to our unitholders. Therefore, if we were treated as a corporation for U.S. federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. Members of Congress have frequently proposed and considered substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including proposals that would eliminate our ability to qualify for partnership tax treatment. Recent proposals have provided for the expansion of the qualifying income exception for publicly traded partnerships in certain circumstances and other proposals have provided for the total elimination of the qualifying income exception upon which we rely for our partnership tax treatment.
In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. There can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership in the future.
Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any changes or other proposals will ultimately be enacted. Any future legislative changes could negatively impact the value of an investment in our units.
If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect directly from us taxes (including any applicable penalties and interest) resulting from such audit adjustments, in which case our cash available for distribution to our unitholders might be substantially reduced.
If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. To the extent possible, our General Partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue an information statement to our current and former unitholders with respect to an audited and adjusted return. Although our General Partner may elect to have our current and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance 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 units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced.
We have subsidiaries that are treated as corporations for U.S. federal income tax purposes and are subject to corporate-level income taxes.
Even though we (as a partnership for U.S. federal income tax purposes) are not subject to U.S. federal income tax, some of our operations are currently conducted through subsidiaries that are organized as corporations for U.S. federal income tax purposes. The taxable income, if any, of these subsidiaries is subject to corporate-level U.S. federal income taxes, which may reduce the cash available for distribution to us and, in turn, to our unitholders. If the IRS or other state or local jurisdictions were to successfully assert that these corporations have more tax liability than we anticipate or legislation is enacted that increases the corporate tax rate, then cash available for distribution could be further reduced. The income tax return filing positions taken by these corporate subsidiaries requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is also required in assessing the amounts of deductible and taxable items. Despite our belief that the income tax return positions taken by these subsidiaries are fully supportable, certain positions may be successfully challenged by the IRS, state or local jurisdictions.
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Our unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
Because our unitholders will be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, our unitholders will be required to pay U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income whether or not they receive cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If a unitholder sells its common units, it will recognize a gain or loss equal to the difference between the amount realized and its tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income result in a decrease in its tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the common units it sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price the unitholder receives is less than its original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells its common units, such unitholder may incur a tax liability in excess of the amount of cash received from the sale.
Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture of depreciation deductions and certain other items. Thus, a unitholder may recognize both ordinary income and capital loss from the sale of units if the amount realized on a sale of such units is less than such unitholder’s adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a unitholders sells their units, such unitholder may recognize ordinary income from our allocations of income and gain to such unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.
Tax-exempt entities face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investments in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (“IRAs”) raise 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. Additionally, all or part of any gain recognized by such tax-exempt organization upon a sale or other disposition of our units may be unrelated business taxable income. Tax-exempt entities should consult a tax advisor before investing in our common units.
If the IRS contests the U.S. federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.
The IRS may adopt positions that differ from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest by the IRS may materially and adversely impact the market for our common units and the price at which they trade. The costs of any contest by the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution.
We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could result in a unitholder owing more tax and may adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units, we have adopted certain methods for allocating depreciation and amortization deductions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a unitholder. 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 a unitholder’s tax returns.
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We generally 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 unitholders.
We generally 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 (the “Allocation Date”), instead of on the basis of the date a particular common unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the General Partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of the proration method we have currently adopted. If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for U.S. federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the U.S. federal income tax consequences of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered as having disposed of the loaned common units. In that case, he may no longer be treated for U.S. federal income tax purposes as a partner with respect to those common 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 common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common 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 securities loan 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 common units.
We have adopted certain valuation methodologies in determining a 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 unitholders, we must routinely determine the fair market value of our respective assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many 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. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of our units may have a greater portion of their Internal Revenue Code Section 743(b) (“Section 743(b)”) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our general partner and certain of our unitholders.
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 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 unitholders’ tax returns without the benefit of additional deductions.
Unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units.
In addition to U.S. federal income taxes, unitholders may be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangibles taxes that may be imposed by the various jurisdictions in which we conduct business or own property now or in the future or in which the unitholder is a resident. We currently own property or do business in a substantial number of states, most of which impose a personal income tax and many of which impose an income tax on corporations and other entities. We may also own property or do business in other states in the future. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on its investment in us.
Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of the jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a
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unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return.
It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of its investment in us. We strongly recommend that each prospective unitholder consult, and depend on, its own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local, and non-U.S., as well as U.S. federal tax returns that may be required of it.
Unitholders may be subject to limitations on their ability to deduct interest expense we incur.
In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income.
If our “business interest” is subject to limitation under these rules, our unitholders will be limited in their ability to deduct their share of any interest expense that has been allocated to them. As a result, unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
Non-U.S. unitholders will be subject to U.S. federal income taxes and withholding with respect to their income and gain from owning our common units.
Non-U.S. unitholders are generally taxed and subject to U.S. federal income tax filing requirements on income effectively connected with a U.S. trade or business. Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a common unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit. In addition to the withholding tax imposed on distributions of effectively connected income, distributions to a non-U.S. unitholder will also be subject to a 10% withholding tax on the amount of any distribution in excess of our cumulative net income. As we do not compute our cumulative net income for such purposes due to the complexity of the calculation and lack of clarity in how it would apply to us, we intend to treat all of our distributions as being in excess of our cumulative net income for such purposes and subject to such 10% withholding tax. Accordingly, distributions to a non-U.S. unitholder will be subject to a combined withholding tax rate equal to the sum of the highest applicable effective tax rate and 10%.
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. While the determination of a partner’s “amount realized” generally includes any decrease of a partner’s share of the partnership’s liabilities, the Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership, such as our common units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and thus will be determined without regard to any decrease in that partner’s share of a publicly traded partnership’s liabilities. For a transfer of interests in a publicly traded partnership that is 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 units.
Certain U.S. federal income tax consequences of the ownership of our Series A Preferred Units, including treatment of distributions as guaranteed payments for the use of capital, are uncertain.
The U.S. federal income tax treatment of distributions on our Series A Preferred Units is uncertain. We will treat the holders of the Series A Preferred Units as partners for U.S. federal income tax purposes and will treat distributions on the Series A Preferred Units as guaranteed payments for the use of capital that will generally be taxable to the holders of the Series A Preferred Units as ordinary income. Although a holder of Series A Preferred Units will recognize taxable income from the accrual of such a guaranteed payment (even in the absence of a contemporaneous cash distribution), we anticipate accruing and making the guaranteed payment distributions semi-annually. Otherwise, except in the case of our liquidation, the holders of Series A 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 Series A Preferred Units. If the Series A Preferred Units were treated for U.S. federal income tax purposes as indebtedness, 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 Series A Preferred Units.
A holder of Series A Preferred Units will be required to recognize a gain or loss on a sale or other taxable disposition of Series A Preferred Units equal to the difference between the amount realized by such holder and such holder’s tax basis in the Series A 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 Series A Preferred Units. Subject to general rules requiring a blended basis among multiple
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partnership interests, the tax basis of a Series A Preferred Unit will generally be equal to the sum of the cash and the fair market value of other property paid by the holder of such Series A Preferred Units to acquire such Series A Preferred Units. Gain or loss recognized by a holder of Series A Preferred Units on the sale or exchange of a Series A Preferred Unit held for more than one year generally will be taxable as long-term capital gain or loss. Because holders of Series A Preferred Units will generally not be allocated a share of our items of depreciation, depletion or amortization, it is not anticipated that such holders would be required to recharacterize any portion of their gain as ordinary income as a result of the recapture rules.
Investment in the Series A Preferred Units by tax-exempt investors, such as employee benefit plans and individual retirement accounts (“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 such payments may be treated as unrelated business taxable income for U.S. federal income tax purposes.
Distributions to non-U.S. holders of Series A Preferred Units will be subject to U.S. federal income, withholding and, in the case of non-U.S. holders that are corporations, branch profits taxes, and non-U.S. holders will be required to file U.S. federal income tax returns to report their income and gain in respect of our Series A Preferred Units and pay U.S. federal income tax on such income in a manner similar to a taxable U.S. holder. If the amount of withholding exceeds the amount of U.S. federal income tax actually due, non-U.S. holders of Series A Preferred Units may be required to file U.S. federal income tax returns in order to seek a refund of such excess. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor with respect to the consequences of owning our Series A Preferred Units.
Our treatment of distributions on our Series A Preferred Units as guaranteed payments for the use of capital means that such distributions will not be eligible for the 20% deduction for qualified business income.
A non-corporate unitholder may be entitled to a deduction equal to 20% of its “qualified business income” attributable to its interest in a partnership, subject to certain limitations. As described above, we will treat distributions on the Series A Preferred Units as guaranteed payments for the use of capital, and under the applicable Treasury Regulations, a guaranteed payment for the use of capital will not be taken into account for purposes of computing qualified business income. As a result, distributions received by the holders of our Series A Preferred Units will not be eligible for the 20% deduction for qualified business income. Prospective holders of Series A Preferred Units should consult their tax advisors regarding the availability of the deduction for qualified business income.
Item 1B. Unresolved Staff Comments
None.
Item 1C. Cybersecurity
Description of Processes for Assessing, Identifying, and Managing Cybersecurity Risks
The information and operational technology infrastructure we use is important to the operation of our business and to our ability to perform day-to-day operations. In the normal course of business, we may collect and store certain sensitive information of the Partnership, including proprietary and confidential business information, trade secrets, intellectual property, sensitive third-party and employee information, and certain personally identifiable information.
We are part of Energy Transfer’s shared services cybersecurity program (the “Cybersecurity Program”) for assessing, identifying, and managing material risks from cybersecurity threats. This program includes processes that are modeled after the National Institute of Standards and Technology’s Cybersecurity Framework and focuses on using business drivers to guide cybersecurity activities. This program is managed by Energy Transfer’s Chief Information Officer, who is supported by a team of full-time employees tasked with conducting our day-to-day IT operations (collectively, the “IT team”). Furthermore, the Partnership considers cybersecurity risks as part of, and has incorporated its cybersecurity program into, the Partnership’s overall risk management processes. Through engagement with the guidance of the Federal Bureau of Investigation (FBI), Cybersecurity and Infrastructure Security Agency (CISA), Transportation Security Administration (TSA) and the U.S. Coast Guard (USCG), we and the IT Team seek to follow industry cybersecurity standards and protect our infrastructure against cyberattacks from domestic and international threats.
The Cybersecurity Program seeks to use a defense-in-depth approach for cybersecurity management, layers of technology, policies, and training at all levels of the enterprise designed to keep the Partnership’s assets secure and operational. It uses various processes to maintain the confidentiality, integrity, and availability of our systems, including security threat intelligence, incident response, identity and access management, supply-chain security assessments, endpoint extended detection and response protection, network segmentation, data encryption, event monitoring, and a Security Operations Center (SOC). In an effort to validate the effectiveness of our cybersecurity program and assess such program’s compliance with legal and regulatory requirements, we and the IT team engage third-party service providers to perform audits, assessments, and penetration tests.
Cybersecurity awareness among our employees is promoted with regular training and awareness programs. All employees who have access to our systems are required to undergo annual cybersecurity training and, each year, our employees must review and acknowledge our cybersecurity policies. Further, the IT team is trained to understand how to manage, use and protect personally
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identifiable information. User access controls have been implemented to limit unauthorized access to sensitive information and critical systems. Employees are required to use multifactor authentication and keep their passwords confidential, among other measures.
We recognize that third-party service providers may introduce cybersecurity risks. In an effort to mitigate these risks, before contracting with certain technology services providers, when possible, we conduct due diligence to evaluate their cybersecurity capabilities. Additionally, the IT team endeavors to include cybersecurity requirements in contracts with these providers and endeavor to require them to adhere to security standards and protocols. Further, the IT team also endeavors to engage with any third-party service providers with access to personally identifiable employee information to evaluate their security controls.
Finally, Energy Transfer maintains cybersecurity insurance coverage which coverage extends to the Partnership.
Impact of Risks from Cybersecurity Threats
The energy industry’s increasing dependence on IT and operational technology to support critical functions, such as energy distribution and management activities, has heightened its vulnerability to cybersecurity incidents. Consequently, the global surge in cybersecurity incidents, whether caused by intentional attacks or accidental events, presents a significant challenge to our sector. As cybersecurity threats grow in complexity and scale, preventing, detecting, mitigating and remediating these incidents remains a continuous and increasingly demanding task for the industry. Compliance with evolving cybersecurity reporting requirements, such as those mandated by FERC, presents significant challenges. These regulations necessitate timely and detailed reporting of cyber incidents, demanding substantial resources and robust internal processes to ensure adherence. Failure to comply could result in legal penalties, increased regulatory scrutiny and reputational damage. Moreover, the dynamic nature of these requirements may lead to overlapping or inconsistent obligations, further complicating compliance efforts. Monitoring these developments and integrating them into our cybersecurity and compliance frameworks is essential to mitigate potential risks.
As of the date of this Annual Report on Form 10-K, though the Partnership and our service providers have experienced certain cybersecurity incidents, we are not aware of any cybersecurity threats that have materially affected, or are reasonably likely to materially affect, the Partnership, either financially or operationally. Cybersecurity incident response is a component of both the Partnership’s Cybersecurity Program and the Partnership’s business continuity plans, which are designed to limit service interruptions and provide for continued business operation in the event of disaster, whether physical, environmental or cyber in nature. However, we recognize that cybersecurity threats are continually evolving, and there remains a risk that a cybersecurity incident could potentially negatively impact the Partnership. Despite the implementation of our cybersecurity processes, we cannot guarantee that a significant cybersecurity attack will not occur. A successful attack on our information system or operational technology system could have significant consequences to the business, including the interruption of key services that our customers depend on. While we devote resources to our security measures to protect our systems and information, these measures cannot provide absolute security. Due to the number of acquisitions made by the Partnership over the past few years and the time it takes to implement technology standards across the enterprise, certain assets may be in different stages of integration and may have incomplete cybersecurity controls applied. For additional information on cybersecurity risks, see “Item 1A. Risk Factors - Cybersecurity attacks, data breaches and other disruptions affecting us, or our service providers, could materially and adversely affect our business, operations, reputation, and financial results; and - We rely on our information systems to manage numerous aspects of our business, and a disruption of these systems could adversely affect our business.”
Board of Directors’ Oversight and Management’s Role
Under the Cybersecurity Program, Energy Transfer’s Chief Information Officer oversees the Partnership’s functions of IT, cybersecurity, infrastructure and IT governance (including the Partnership’s IT team) and has more than 35 years of experience leading business technology functions. The IT team is responsible for the Partnership’s efforts to comply with applicable cybersecurity standards, establish effective cybersecurity protocols and protect the integrity, confidentiality and availability of our IT infrastructure. The members of the IT team have over 50 years of combined experience in the field of IT, including 20 years dedicated to cybersecurity, and hold various certifications, including Global Industrial Cyber Security Professional (GICSP), Certified Information Systems Security Professional (CISSP) and Certified Ethical Hacker (CEH) certifications. This team is responsible for cybersecurity threat prevention, detection, mitigation, and remediation for the combined organization. Our cyber incident response plan requires IT team members who detect suspicious activity in our IT environment to escalate that activity to a supervisor who then evaluates the threat. If necessary, the suspicious activity is reported to Energy Transfer’s Chief Information Officer. Management (including representatives from the legal, human resources, IT and corporate security departments) is notified by the IT team whenever a discovered cybersecurity incident may potentially have a significant impact on our business operations.
The Partnership’s Board of Directors has delegated the responsibility for the oversight of cybersecurity risks to the Audit Committee. The IT team provides periodic cybersecurity program updates to senior management and to the Audit Committee. Management also updates the Audit Committee as new risks are identified and regarding the steps taken to mitigate such risks. The Audit Committee reviews periodic reporting and updates regarding our cybersecurity risk management.
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Item 2. Properties
A description of our properties is included in “Item 1. Business.” In addition, we own and lease warehouses and offices in the continental United States, Canada, Europe, Hawaii and the Greater Caribbean. While we may require additional warehouse and office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future, and that additional facilities will be available on commercially reasonable terms as needed.
We believe that we have satisfactory title to or valid rights to use all of our material properties. Although some of our properties are subject to liabilities and leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-competition agreements and immaterial encumbrances, easements and restrictions, we do not believe that any such burdens will materially interfere with our continued use of such properties in our business, taken as a whole. In addition, we believe that we have, or are in the process of obtaining, all required material approvals, authorizations, orders, licenses, permits, franchises and consents of, and have obtained or made all required material registrations, qualifications and filings with, the various state and local government and regulatory authorities which relate to ownership of our properties or the operations of our business.
Item 3. Legal Proceedings
For information regarding legal proceedings, see Note 15 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this Annual Report on Form 10-K for the year ended December 31, 2025.
Sunoco LP, Aloha Petroleum and other Energy Transfer affiliates are defendants in lawsuits alleging liability for climate change impacts from greenhouse gas emissions in Hawaii, Maine and Vermont. Plaintiffs in these cases allege deceptive marketing and concealment of information about these effects, violations of state consumer protection and unfair trade practices laws, and seek certain equitable relief, statutory and civil penalties, punitive damages, disgorgement of profits and attorney’s fees. We are unable to estimate the possible loss or range of loss in excess of amounts accrued. Sunoco intends to vigorously defend the subject claims.
Item 4. Mine Safety Disclosures
Not applicable.
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Part II
Item 5. Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
Our Partnership Interest
As of February 13, 2026, we had outstanding 136,894,754 common units, 16,410,780 Class C units representing limited partner interests in the Partnership (“Class C Units”), 51,517,198 Class D Units, a non-economic general partner interest, and IDRs. As of February 13, 2026, Energy Transfer directly owned approximately 20.8% of our outstanding common units. Our General Partner is 100% owned by Energy Transfer and owns a non-economic general partner interest in us. Energy Transfer also owns all of our IDRs. As discussed below, the IDRs represent the right to receive increasing percentages, up to a maximum of 50%, of the cash we distribute from operating surplus (as defined below) in excess of $0.503125 per unit per quarter. Our common units, which represent limited partner interests in us, are listed on the NYSE under the symbol “SUN.” Our common units have been traded on the NYSE since September 20, 2012.
Holders
At the close of business on February 13, 2026, we had 206 holders of record of our common units, two holders of record of our Class C Units and one holder of record of our Class D Units. The number of record holders does not include holders of units in “street names” or persons, partnerships, associations, corporations or other entities identified in security position listings maintained by depositories.
Distributions of Available Cash
Our Partnership Agreement requires that within 60 days after the end of each quarter, we distribute our available cash to unitholders of record on the applicable record date.
Definition of Available Cash
Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of the quarter; less, the amount of cash reserves established by our General Partner at the date of determination of available cash for the quarter to:
•provide for the proper conduct of our business;
•comply with applicable law, any of our debt instruments or other agreements or any other obligation; or
•provide funds for distributions to our unitholders for any one or more of the next four quarters;
plus, if our General Partner so determines on the date of determination, all or any portion of the cash on hand immediately prior to the date of determination of available cash for the quarter, including cash on hand resulting from working capital borrowings made after the end of the quarter.
Minimum Quarterly Distributions
We intend to make a cash distribution to the holders of our common units, Class C Units and Class D Units on a quarterly basis to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including payments to our General Partner and its affiliates. However, there is no guarantee that we will pay the minimum quarterly distribution, as described below, on our common units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our General Partner, taking into consideration the terms of our Partnership Agreement.
Incentive Distribution Rights
The following table illustrates the percentage allocations of available cash from operating surplus, after the payment of distributions to the Class C unitholders, between our common unitholders and the holder of our IDRs based on the specified target distribution levels. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of the holder of our IDRs and the common unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “total quarterly distribution per common unit target amount.” The percentage interests shown for our common unitholders and the holder of our IDRs for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. Energy Transfer currently owns all of our IDRs.
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|  |  | Marginal percentage interest in distributions
| Total quarterly distribution per common unit target amount |  | Common Unitholders |  | IDR Holder
Minimum Quarterly Distribution | $0.4375 |  | 100 | % |  | — |
First Target Distribution | Above $0.4375 up to $0.503125 |  | 100 | % |  | — |
Second Target Distribution | Above $0.503125 up to $0.546875 |  | 85 | % |  | 15 | %
Third Target Distribution | Above $0.546875 up to $0.656250 |  | 75 | % |  | 25 | %
Thereafter | Above $0.656250 |  | 50 | % |  | 50 | %

Class C Units
We have outstanding an aggregat e of 16,410,780 Class C Units, all of which are held by wholly owned subsidiaries of the Partnership.
Class C Units are entitled to receive quarterly distributions at a rate of $0.8682 per Class C Unit. The distributions on the Class C Units are paid out of our available cash, except that the Class C Units do not share in distributions of available cash to the extent such cash is derived from or attributable to any distribution received by us from Sunoco Retail, our indirect wholly owned subsidiary that is subject to state and federal income tax, the proceeds of any sale of the membership interests in Sunoco Retail, or any interest or principal payments we receive with respect to indebtedness of Sunoco Retail or its subsidiaries. The Class C Units are entitled to receive distributions of available cash (other than available cash attributable to Sunoco Retail) prior to distributions of such cash being made on our common units. Any unpaid distributions on the Class C Units will accrue interest at a rate of 1.5% per annum until paid in full in cash. The Class C Units are perpetual, do not have any rights of redemption or conversion, do not have the right to vote on any matter except as otherwise required by any non-waivable provision of law, and are not traded on any public securities market.
Class D Units
The Partnership has outstanding an aggrega te of 51,517,198 Class D Units, all of which are held by SunocoCorp.
Class D Units represent limited partner interests in the Partnership and are economically equivalent to other Partnership common units. No distribution may be made in respect of the Partnership’s common units unless an equal distribution is simultaneously made on the Class D Units. For a period from October 31, 2025 to December 31, 2027 (the “Equalization Period”), Class D Units shall receive, from the Partnership, cash necessary and sufficient to pay distributions on each SunocoCorp common unit for each quarter during the Equalization Period in an amount equal to 100% of the distributions paid by the Partnership on each Sunoco common unit during such quarter.
Equity Compensation Plan
For disclosures regarding securities authorized for issuance under equity compensation plans, see “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.”
Item 6. [Reserved]
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
(Tabular dollar and unit amounts, except per unit data, are in millions)
The following discussion and analysis of our financial condition and results of operations for the years ended December 31, 2025 and 2024 should be read in conjunction with our audited consolidated financial statements and notes to audited consolidated financial statements included elsewhere in this report.
Discussion and analysis of matters pertaining to the year ended December 31, 2023 and year-to-year comparisons between the years ended December 31, 2024 and 2023 are not included in this Form 10-K, but can be found under Part II, Item 7 of our annual report on Form 10-K for the year ended December 31, 2024 that was filed with the SEC on February 14, 2025.
Adjusted EBITDA is a non-GAAP financial measure of performance that has limitations and should not be considered as a substitute for net income or cash provided by operating activities. Please see “Key Measures Used to Evaluate and Assess Our Business” below for a discussion of our use of Adjusted EBITDA in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and a reconciliation to net income for the periods presented.
Overview
As used in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, the terms “Partnership,” “Sunoco,” “we,” “us” or “our” should be understood to refer to Sunoco LP and our consolidated subsidiaries, unless the context clearly indicates otherwise.
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We are primarily engaged in energy infrastructure and distribution of motor fuels across 32 countries and territories in North America, the Greater Caribbean and Europe. Our midstream operations include an extensive network of over 14,000 miles of pipeline and over 160 terminals. Our fuel distribution operations distribute over 15 billion gallons annually to approximately 11,000 Sunoco and partner branded locations, as well as independent dealers and commercial customers.
Acquisitions
Parkland Acquisition
On October 31, 2025, we completed the previously announced acquisition of Parkland, whereby Sunoco Retail, a wholly owned corporate subsidiary of the Partnership, indirectly acquired all the outstanding shares of Parkland, in exchange for cash and SunocoCorp units that were contributed by SunocoCorp to the Partnership at the close of the Parkland Acquisition. Under the terms of the agreement, Parkland shareholders received 0.295 SunocoCorp units and C$19.80 for each Parkland share. Parkland shareholders could elect, in the alternative, to receive C$44.00 per Parkland share in cash or 0.536 SunocoCorp units for each Parkland share, subject to proration to ensure that the aggregate consideration payable in connection with the transaction would not exceed C$19.80 in cash per Parkland share outstanding as of immediately before close and 0.295 SunocoCorp units per Parkland share outstanding as of immediately before close. In connection with the closing of the Parkland Acquisition, we paid approximately $2.60 billion to Parkland’s shareholders and transferred 51,517,198 SunocoCorp common units, which we had received from SunocoCorp in exchange for our issuance of 51,517,198 Sunoco Class D Units to SunocoCorp.
Parkland is a leading international fuel distributor, marketer and convenience retailer with operations in 26 countries across the Americas. Parkland’s functional currency is the Canadian dollar, and its consolidated structure includes subsidiaries with multiple other functional currencies.
As part of the transaction, the Partnership repurposed and renamed an existing subsidiary as SunocoCorp. Prior to the Parkland Acquisition, SunocoCorp did not have any significant assets, liabilities or operations; in connection with the Parkland Acquisition, the Partnership deconsolidated SunocoCorp and SunocoCorp became a publicly traded entity classified as a corporation for U.S. federal income tax purposes. SunocoCorp units began trading on the NYSE effective November 6, 2025. Subsequent to the Parkland Acquisition, SunocoCorp holds Sunoco Class D Units, representing limited partnership interests in Sunoco that are generally economically equivalent to Sunoco’s publicly traded common units on the basis of one Sunoco Common Unit for each outstanding SunocoCorp unit. For a period of two years following closing of the transaction, Sunoco will ensure that SunocoCorp unitholders receive distributions on a per unit basis that are equivalent to the per unit distributions to Sunoco unithold ers.
TanQuid Acquisition
On January 16, 2026, the Partnership completed the previously announced acquisition of TanQuid for approximately €465 million (approximately $540 million as of January 16, 2026), includ ing approximately €300 million of assumed debt, less approximately €39 million of cash acquired. TanQuid owns and operates 15 fuel terminals in Germany and one fuel terminal in Poland. The transaction was funded using cash on hand and amounts available under the Partnership's Credit Facility.
Other Acquisitions
In the first quarter of 2025, Sunoco acquired fuel equipment, motor fuel inventory and supply agreements in two separate transactions for total consideration of approximately $17 million. Aggregate consideration included $12 million in cash and 91,776 newly issued Sunoco Common Units, which had an aggregate acquisition-date fair value of approximately $5 million.
In the second quarter of 2025, Sunoco acquired a total of 151 fuel distribution consignment sites in three separate transactions for total consideration of approximately $105 million, plus working capital. Aggregate consideration included $92 million in cash and 251,646 newly issued Sunoco Common Units which had an aggregate acquisition-date fair value of approximately $13 million.
In the third quarter of 2025, Sunoco acquired approximately 70 fuel distribution consignment sites and 100 supply agreements in five separate transactions for total cash consideration of approximately $85 million, plus working capital.
In the fourth quarter of 2025, Sunoco acquired a total of 27 fuel distribution consignment sites and 36 dealer sites, as well as commercial customers, in four separate transactions for total cash consideration of approximately $64 million, plus working capital.
Market and Industry Trends and Outlook
We expect that certain trends and economic or industry-wide factors will continue to affect our business, both in the short-term and long-term. Inflation has a minimal impact on our results of operations, because we are generally able to pass along energy cost increases in the form of increased sales prices to our customers. We have recently completed and recently announced multiple strategic transactions, which we expect will continue to diversify the Partnership’s business, add scale and expand cash for reinvestment and distribution growth. We base our expectations on information currently available to us and assumptions made by us. To the extent our underlying assumptions about or interpretation of available information prove to be incorrect, our actual results may
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vary materially from our expected results. Read “Item 1A. Risk Factors” included herein for additional information about the risks associated with purchasing our common units.
Seasonality
Our business exhibits some seasonality due to our customers’ increased demand for motor fuel during the late spring and summer months, as compared to the fall and winter months. Travel, recreation, and construction activities typically increase in these months, driving up the demand for motor fuel sales. Our gallons sold are typically somewhat higher in the second and third quarters of our fiscal years due to this seasonality. Results of operations may therefore vary from period to period.
Regulatory Update
OECD Pillar Two Global Minimum Tax
The acquisition of Parkland brought Sunoco into the scope of the Pillar Two global minimum tax regime. Several jurisdictions in which Sunoco now operates have enacted legislation implementing the Organization for Economic Co-operation and Development (“OECD”) Pillar Two global minimum tax framework. These rules generally impose a 15% minimum top-up tax on the profits of large multinational enterprises. Sunoco has accrued $1 million of current tax expense related to Pillar Two global minimum taxes subsequent to the Parkland Acquisition in 2025.
On January 5, 2026, the OECD released administrative guidance that provides safe harbors for U.S. parented multinational groups under the Pillar Two framework. Effective for fiscal years beginning on or after January 1, 2026, U.S. parented multinational groups would be exempt from the main charging under the Pillar Two framework. Management expects that, starting in 2026, Sunoco should not be subject to top‑up taxes in certain low‑tax jurisdictions to the extent legislation adopting the safe harbors in enacted in the jurisdictions in which Sunoco operates. However, the timing of legislative enactment in the various countries is uncertain and the magnitude of such impacts cannot be reasonably estimated at this time.
Key Measures Used to Evaluate and Assess Our Business
Adjusted EBITDA, as used throughout this document, is defined as earnings before net interest expense, income taxes, depreciation, amortization and accretion expense, allocated non-cash unit-based compensation expense, unrealized gains and losses on commodity derivatives, inventory adjustments and certain other operating expenses reflected in net income that we do not believe are indicative of ongoing core operations, such as gain or loss on disposal of assets and non-cash impairment charges. Inventory adjustments that are excluded from the calculation of Adjusted EBITDA represent changes in lower of cost or market reserves on the Partnership's inventory; these amounts are unrealized valuation adjustments applied to fuel volumes remaining in inventory at the end of the period. Subsequent to the Parkland Acquisition on October 31, 2025, Adjusted EBITDA also excludes gains and losses that are recorded in net income in connection with impacts of foreign currency on an intercompany loan between the Partnership and a consolidated subsidiary.
Adjusted EBITDA is a non-GAAP financial measure. For a reconciliation of Adjusted EBITDA to the most directly comparable financial measure calculated and presented in accordance with GAAP, read “Results of Operations” below.
We believe Adjusted EBITDA is useful to investors in evaluating our operating performance because:
•Adjusted EBITDA is used as a performance measure under our Credit Facility;
•securities analysts and other interested parties use Adjusted EBITDA as a measure of financial performance; and
•our management uses Adjusted EBITDA for internal planning purposes, including aspects of our consolidated operating budget and capital expenditures.
Adjusted EBITDA is not a recognized term under GAAP and does not purport to be an alternative to net income as a measure of operating performance. Adjusted EBITDA has limitations as an analytical tool, and one should not consider it in isolation or as a substitute for analysis of our results as reported under GAAP. Some of these limitations include:
•it does not reflect interest expense or the cash requirements necessary to service interest or principal payments on our Credit Facility or senior notes;
•although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and Adjusted EBITDA does not reflect cash requirements for such replacements; and
•as not all companies use identical calculations, our presentation of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.
Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliates as those excluded from the calculation of Adjusted EBITDA, such as interest, taxes,
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depreciation, amortization and accretion and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliate. Sunoco does not control its unconsolidated affiliates; therefore, Sunoco does not control the earnings or cash flows of such affiliates. The use of Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.
Results of Operations
Year Ended December 31, 2025 Compared to the Year Ended December 31, 2024
Consolidated Results of Operations

| Year Ended December 31, |  |
| 2025 |  | 2024 |  | Change
Segment Adjusted EBITDA: |  |  |  |  |
Fuel Distribution | $ | 990 |  |  | $ | 908 |  |  | $ | 82 |
Pipeline Systems | 718 |  |  | 377 |  |  | 341 |
Terminals | 299 |  |  | 172 |  |  | 127 |
Refinery | 40 |  |  | — |  |  | 40 |
Total | $ | 2,047 |  |  | $ | 1,457 |  |  | $ | 590 |

| Year Ended December 31, |  |
| 2025 |  | 2024 |  | Change
Reconciliation of net income to Adjusted EBITDA: |  |  |  |  |
Net income | $ | 527 |  |  | $ | 874 |  |  | $ | (347) |
Depreciation, amortization and accretion | 688 |  |  | 368 |  |  | 320 |
Interest expense, net | 541 |  |  | 391 |  |  | 150 |
Non-cash unit-based compensation expense | 19 |  |  | 17 |  |  | 2 |
(Gain) loss on disposal of assets and impairment charges | (6) |  |  | 45 |  |  | (51) |
Loss on extinguishment of debt | 31 |  |  | 2 |  |  | 29 |
Unrealized (gains) losses on commodity derivatives | (11) |  |  | 12 |  |  | (23) |
Inventory valuation adjustments | 156 |  |  | 86 |  |  | 70 |
Equity in earnings of unconsolidated affiliates | (143) |  |  | (60) |  |  | (83) |
Adjusted EBITDA related to unconsolidated affiliates | 221 |  |  | 101 |  |  | 120 |
Gain on West Texas Sale | — |  |  | (586) |  |  | 586 |
Other non-cash adjustments | (38) |  |  | 32 |  |  | (70) |
Income tax expense | 62 |  |  | 175 |  |  | (113) |
Adjusted EBITDA (consolidated) | $ | 2,047 |  |  | $ | 1,457 |  |  | $ | 590 |

The following discussion of results compares the operations for the years ended December 31, 2025 and 2024.
Net Income. For the year ended December 31, 2025 compared to the prior year, net income decreased due to a $586 million gain on the West Texas Sale in April 2024, as well as a $150 million increase in interest expense and a $29 million increase in losses on extinguishments of debt. These impacts were partially offset by a $144 million increase in operating income, an $83 million increase in equity in earnings of unconsolidated affiliates, a $70 million increase from gains related to the foreign currency translation impact of an intercompany loan and a $113 million decrease in income tax expense. The increase in operating income was primarily driven by higher Adjusted EBITDA, partially offset by increases in depreciation, amortization and accretion. These increases and decreases are discussed further below.
Adjusted EBITDA. For the year ended December 31, 2025 compared to the prior year, Adjusted EBITDA increased primarily due to a $741 million increase in segment profit (excluding unrealized gains and losses on commodity derivatives and inventory valuation adjustments) primarily related to the acquisitions of Parkland, NuStar and Zenith European terminals, and a $120 million increase in Adjusted EBITDA related to unconsolidated affiliates primarily from the full-year impact of the ET-S Permian joint venture. These increases were partially offset by a $281 million increase in operating costs (including operating expenses, general and administrative expenses and lease expense) due to the full-year impact of NuStar’s operations and two months of Parkland’s operations, as well as one-time transaction related expenses associated with the Parkland Acquisition in 2025, partially offset by one-time NuStar Acquisition and Zenith European terminals transaction related expenses in 2024.
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Additional discussion on the changes impacting net income and Adjusted EBITDA for the year ended December 31, 2025 compared t o the prior year is available below and in “Segment Operating Results.”
Depreciation, Amortization and Accretion. For the year ended December 31, 2025 compared to the prior year, depreciation, amortization and accretion increased primarily due to additional depreciation and amortization from assets recently placed in service and from recent acquisitions.
Interest Expense. For the year ended December 31, 2025 compared to the prior year, interest expense increased primarily due to an increase in average total long-term debt, including debt assumed in the acquisitions of Parkland and NuStar.
(Gain) Loss on Disposal of Assets and Impairment Charges. For the year ended December 31, 2024, loss on disposal of assets and impairment charges primarily related to the termination of a lease in June 2024.
Loss on Extinguishment of Debt. For the year ended December 31, 2025, loss on extinguishment of debt was primarily due to the termination of bridge financing related to the Parkland Acquisition.
Unrealized (Gains) Losses on Commodity Derivatives. The unrealized gains and losses on Sunoco’s commodity derivatives represent the changes in fair value of its commodity derivatives. The change in unrealized gains and losses between periods was impacted by the notional amounts and commodity price changes on Sunoco’s commodity derivatives. Additional information on commodity derivatives is included in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” below.
Inventory Valuation Adjustments. Inventory valuation adjustments represent changes in lower of cost or market reserves using the LIFO method on the Partnership’s inventory. These amounts are unrealized valuation adjustments applied to fuel volumes remaining in inventory at the end of the period. For the years ended December 31, 2025 and 2024, the Partnership’s cost of sales included unfavorable inventory adjustments of $156 million and $86 million, respectively, which decreased net income for the respective periods.
Equity in Earnings of Unconsolidated Affiliates and Adjusted EBITDA Related to Unconsolidated Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” and “Segment Operating Results.”
Gain on West Texas Sale. The gain on West Texas Sale related to the gain recognized by Sunoco upon completion of the sale of convenience stores to 7-Eleven, Inc. in April 2024.
Income Tax Expense. For the year ended December 31, 2025 compared to the prior year, income tax expense decreased primarily due to the taxable gain recognized by a corporate subsidiary on the West Texas Sale in April 2024.
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Supplemental Information on Unconsolidated Affiliates
The following table presents financial information related to unconsolidated affiliates:

|  | Year Ended December 31, |  |
|  | 2025 |  | 2024 |  | Change
Equity in earnings (losses) of unconsolidated affiliates: |  |  |  |  |  |
J.C. Nolan |  | $ | 7 |  |  | $ | 7 |  |  | $ | — |
ET-S Permian |  | 134 |  |  | 53 |  |  | 81 |
SARA |  | 1 |  |  | — |  |  | 1 |
Isla |  | 2 |  |  | — |  |  | 2 |
Other |  | (1) |  |  | — |  |  | (1) |
Total equity in earnings of unconsolidated affiliates |  | $ | 143 |  |  | $ | 60 |  |  | $ | 83 |
Adjusted EBITDA related to unconsolidated affiliates (1): |  |  |  |  |  |
J.C. Nolan |  | $ | 12 |  |  | $ | 12 |  |  | $ | — |
ET-S Permian |  | 202 |  |  | 89 |  |  | 113 |
SARA |  | 7 |  |  | — |  |  | 7 |
Isla |  | — |  |  | — |  |  | — |
Other |  | — |  |  | — |  |  | — |
Total Adjusted EBITDA related to unconsolidated affiliates |  | $ | 221 |  |  | $ | 101 |  |  | $ | 120 |
Distributions received from unconsolidated affiliates: |  |  |  |  |  |
J.C. Nolan |  | $ | 9 |  |  | $ | 8 |  |  | $ | 1 |
ET-S Permian |  | 256 |  |  | — |  |  | 256 |
SARA |  | — |  |  | — |  |  | — |
Isla |  | 3 |  |  | — |  |  | 3 |
Other |  | — |  |  | — |  |  | — |
Total distributions received from unconsolidated affiliates |  | $ | 268 |  |  | $ | 8 |  |  | $ | 260 |

(1)These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, amortization, accretion, non-cash items and taxes.
Segment Operating Results
We evaluate segment performance based on Segment Adjusted EBITDA, which we believe is an important performance measure of the core profitability of our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments.
The following tables identify the components of Segment Adjusted EBITDA, which is calculated as follows:
•Segment profit, operating expenses and selling, general and administrative expenses. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment.
•Adjusted EBITDA related to unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA, such as interest, taxes, depreciation, amortization and accretion and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates.
The following analysis of segment operating results includes a measure of segment profit. Segment profit is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment profit is similar to the GAAP measure of gross profit, except that segment profit excludes charges for depreciation, amortization and
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accretion. The most directly comparable measure to segment profit is gross profit. The following table presents a reconciliation of segment profit to gross profit.

| Year Ended December 31, |  |
| 2025 |  | 2024 |  | Change
Fuel Distribution segment profit | $ | 1,514 |  |  | $ | 1,187 |  |  | $ | 327 |
Pipeline Systems segment profit | 738 |  |  | 535 |  |  | 203 |
Terminals segment profit | 500 |  |  | 376 |  |  | 124 |
Refinery segment profit | 40 |  |  | — |  |  | 40 |
Total segment profit | 2,792 |  |  | 2,098 |  |  | 694 |
Depreciation, amortization and accretion, excluding corporate and other | 686 |  |  | 364 |  |  | 322 |
Gross profit | $ | 2,106 |  |  | $ | 1,734 |  |  | $ | 372 |

In addition, the following sections include information on the components of segment profit by sales type (for the fuel distribution segment), which components are included in order to provide additional disaggregated information to facilitate the analysis of segment profit and Segment Adjusted EBITDA. These components of segment profit are calculated consistent with the calculation of segment profit; therefore, these components also exclude charges for depreciation, amortization and accretion.
Fuel Distribution

| Year Ended December 31, |  |
| 2025 |  | 2024 |  | Change
Motor fuel gallons sold (millions) | 9,884 |  |  | 8,578 |  |  | 1,306 |
Motor fuel profit cents per gallon | 13.2 | ¢ |  | 11.6 | ¢ |  | 1.6 | ¢
Fuel profit | $ | 1,161 |  |  | $ | 909 |  |  | $ | 252 |
Non-fuel profit | 223 |  |  | 153 |  |  | 70 |
Lease profit | 130 |  |  | 125 |  |  | 5 |
Fuel Distribution segment profit | $ | 1,514 |  |  | $ | 1,187 |  |  | $ | 327 |
Expenses | $ | 707 |  |  | $ | 427 |  |  | $ | 280 |
Segment Adjusted EBITDA | $ | 990 |  |  | $ | 908 |  |  | $ | 82 |

Volumes. For the year ended December 31, 2025 compared to the prior year, volumes increased primarily due to the Parkland Acquisition growth, from investments and profit optimization strategies.
Segment Adjusted EBITDA. For the year ended December 31, 2025 compared to the prior year, Segment Adjusted EBITDA related to our Fuel Distribution segment increased due to the net impact of the following:
•an increase of $361 million in segment profit (excluding unrealized gains and losses on commodity derivatives and inventory valuation adjustments) primarily related to a 15% increase in gallons sold and increase in profit per gallon sold primarily due to the Parkland Acquisition; partially offset by
•an increase of $280 million in expenses primarily due to the Parkland Acquisition partially offset by the West Texas Sale.
Pipeline Systems

| Year Ended December 31, |  |
| 2025 |  | 2024 |  | Change
Pipelines throughput (thousand barrels per day) | 1,289 |  |  | 1,000 |  |  | 289 |
Pipeline Systems segment profit | $ | 738 |  |  | $ | 535 |  |  | $ | 203 |
Expenses | $ | 243 |  |  | $ | 260 |  |  | $ | (17) |
Segment Adjusted EBITDA | $ | 718 |  |  | $ | 377 |  |  | $ | 341 |

Volumes. For the year ended December 31, 2025 compared to the prior year, volumes increased due to recently acquired assets.
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Segment Adjusted EBITDA. For the year ended December 31, 2025 compared to the prior year, Segment Adjusted EBITDA related to our Pipeline Systems segment increased due to the net impact of the following:
•a $203 million increase in segment profit driven by a $234 million increase from the timing of the NuStar Acquisition, which occurred on May 3, 2024; and therefore is only reflected for eight months in the prior period, and a $19 million increase due to market demands in the current period, partially offset by a $50 million decrease from the deconsolidation of certain NuStar assets in connection with the formation of the ET-S Permian effective July 1, 2024;
•a $113 million increase in Adjusted EBITDA related to ET-S Permian, which is reflected for a full year in 2025 and six months in 2024; and
•a $17 million decrease in operating costs primarily due to a decrease in general and administrative expenses related to one-time NuStar Acquisition expenses incurred in the prior period. This decrease was partially offset by an increase in operating expenses from the timing of the NuStar Acquisition, which occurred on May 3, 2024, and a decrease of $6 million from the deconsolidation of certain NuStar assets in connection with the formation of ET-S Permian effective July 1, 2024.
Terminals

| Year Ended December 31, |  |
| 2025 |  | 2024 |  | Change
Throughput (thousand barrels per day) | 680 |  |  | 584 |  |  | 96 |
Terminals segment profit | $ | 500 |  |  | $ | 376 |  |  | $ | 124 |
Expenses | $ | 219 |  |  | $ | 207 |  |  | $ | 12 |
Segment Adjusted EBITDA | $ | 299 |  |  | $ | 172 |  |  | $ | 127 |

Volumes. For the year ended December 31, 2025 compared to the prior year, volumes increased due to recently acquired assets.
Segment Adjusted EBITDA. For the year ended December 31, 2025 compared to the prior year, Segment Adjusted EBITDA related to our Terminals segment increased primarily due to the following:
•a $135 million increase in segment profit (excluding inventory valuation adjustments) due to the acquisitions of Parkland, NuStar, the Zenith European terminals and a terminal in Portland as well as favorable transmix business performance; partially offset by
•a $12 million increase in operating costs primarily due to an increase in operating expenses from the Parkland Acquisition and timing of the NuStar and Zenith European terminals acquisitions, partially offset by one-time NuStar Acquisition and Zenith European terminals transaction related expenses in 2024.
Refinery

| Year Ended December 31, |  |
| 2025 |  | 2024 |  | Change
Crude utilization | 90 | % |  | — |  |  | — |
Composite utilization | 91 | % |  | — |  |  | — |
Crude throughput (thousand barrels per day) | 49 |  |  | — |  |  | — |
Bio-feedstock throughput (thousand barrels per day) | 1 |  |  | — |  |  | — |
Refinery segment profit | $ | 40 |  |  | $ | — |  |  | $ | 40 |
Expenses | $ | 6 |  |  | $ | — |  |  | $ | 6 |
Segment Adjusted EBITDA | $ | 40 |  |  | $ | — |  |  | $ | 40 |

Volumes. For the year ended December 31, 2025 compared to the prior year, volumes increased due to recently acquired assets.
Segment Adjusted EBITDA. For the year ended December 31, 2025 compared to the prior year, Segment Adjusted EBITDA related to our Refinery segment increased primarily due to the acquisition of Parkland.
Expenses. For the year ended December 31, 2025, expenses excluded certain direct costs of labor, maintenance expenses, utilities, and other direct operating costs which are included in cost of sales.
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Liquidity and Capital Resources
Liquidity
Our principal liquidity requirements are to finance current operations, to fund capital expenditures, including acquisitions from time to time, to service our debt and to make distributions. We expect our ongoing sources of liquidity to include cash generated from operations, borrowings under our Credit Facility and the issuance of additional long-term debt or partnership units as appropriate given market conditions. We expect that these sources of funds will be adequate to provide for our short-term and long-term liquidity needs.
Our ability to meet our debt service obligations and other capital requirements, including capital expenditures and acquisitions, will depend on our future operating performance which, in turn, will be subject to general economic, financial, business, competitive, legislative, regulatory and other conditions, many of which are beyond our control. As a normal part of our business, depending on market conditions, we will from time to time consider opportunities to repay, redeem, repurchase or refinance our indebtedness. Changes in our operating plans, lower than anticipated sales, increased expenses, acquisitions or other events may cause us to seek additional debt or equity financing in future periods. There can be no guarantee that financing will be available on acceptable terms or at all. Debt financing, if available, could impose additional cash payment obligations and additional covenants and operating restrictions. In addition, any of the items discussed in detail under “Item 1A. Risk Factors” included in this Annual Report on Form 10-K may also significantly impact our liquidity.
The Partnership is party to a Third Amended and Restated Credit Agreement among the Partnership, as borrower, the lenders from time to time party thereto and Bank of America, N.A., as administrative agent, collateral agent, swingline lender and a letter of credit issuer providing for the Credit Facility. As of December 31, 2025, we had $891 million of cash and cash equivalents on hand and borrowing capacity of $2.47 billion under the Credit Facility. Based on our current estimates, we expect to utilize capacity under the Credit Facility, along with cash from operations, to fund our announced growth capital expenditures and working capital needs; however, we may issue debt or equity securities prior to that time as we deem prudent to provide liquidity for new capital projects or other partnership purposes.
Cash Flows
Our cash flows may change in the future due to a number of factors, some of which we cannot control. These factors include regulatory changes, the price of products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions and other factors.

| Year Ended December 31,
| 2025 |  | 2024
Net cash provided by (used in) |  |  |
Operating activities | $ | 1,192 |  |  | $ | 549 |
Investing activities | (2,807) |  |  | 477 |
Financing activities | 2,412 |  |  | (961) |
Net increase in cash and cash equivalents | $ | 797 |  |  | $ | 65 |

Operating Activities
Changes in cash flows from operating activities between periods primarily result from changes in earnings, excluding the impacts of non-cash items and changes in operating assets and liabilities (net of effects of acquisitions and divestitures). Non-cash items include recurring non-cash expenses, such as depreciation, amortization and accretion expense and non-cash unit-based compensation expense. Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring, such as impairment charges. Our daily working capital requirements fluctuate within each month, primarily in response to the timing of payments for motor fuels, motor fuels tax and rent.
Net cash provided by operations was $1.19 billion and $549 million for 2025 and 2024, respectively. The increase in cash flows provided by operations was primarily due to a $628 million net increase in net income (excluding the impacts of the gain on West Texas Sale in 2024, as well as depreciation, amortization and accretion, inventory valuation adjustments and other non-cash items) compared to the prior year; partially offset by a decrease in net cash flow from operating assets and liabilities of $181 million compared to the prior year.
Cash provided by operating activities for 2025 also includes $196 million cash distributions received from unconsolidated affiliates that are deemed to be paid from cumulative earnings.
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Investing Activities
Cash flows from investing activities primarily consist of capital expenditures, cash contributions to unconsolidated affiliates, cash amounts paid for acquisitions and cash proceeds from sale or disposal of assets. Changes in capital expenditures between periods primarily result from increases or decreases in our growth capital expenditures to fund our expansion projects.
Net cash used in investing activities was $2.81 billion in 2025 and net cash provided by investing activities was $477 million in 2024. Capital expenditures were $577 million and $344 million in 2025 and 2024, respectively. Net cash used in investing activities included $253 million and $224 million of cash paid for other acquisition in 2025 and 2024, respectively. In 2025, we paid $2.00 billion, net of cash acquired, for the Parkland Acquisition. In 2024, we received $27 million in cash from the NuStar Acquisition and we received $987 million in cash proceeds from the West Texas Sale. Proceeds from disposal of property, plant and equipment were $28 million and $23 million in 2025 and 2024, respectively.
Distributions from unconsolidated affiliates in excess of cumulative earnings were $72 million and $8 million for 2025 and 2024, respectively. In 2025, we paid $73 million in cash contributions to unconsolidated affiliates.
Financing Activities
Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, which are primarily used to fund our acquisitions and growth capital expenditures. Distributions increase between the periods based on increases in the number of common units outstanding or increases in the distribution rate.
Net cash provided by financing activities was $2.41 billion in 2025 and net cash used in financing activities was and $961 million in 2024.
During the year ended December 31, 2025, we:
•borrowed $2.90 billion and repaid $600 million in senior notes;
•repurchased and remarketed $75 million principal amount of Series 2011 GoZone Bonds;
•borrowed $2.08 billion and repaid $2.28 billion under the Credit Facility to fund daily operations;
•repaid $444 million related to Parkland’s credit facility;
•paid $57 million in loan origination costs;
•issued $1.47 billion of Series A Preferred Units; and
•paid $657 million in distributions to our unitholders, of which $262 million was paid to Energy Transfer; and
During the year ended December 31, 2024, we:
•borrowed $1.50 billion and repaid $421 million in senior notes;
•borrowed $2.79 billion and repaid $3.45 billion under the Credit Facility to fund daily operations;
•paid $19 million in loan origination costs;
•redeemed $784 million of preferred units;
•paid $566 million in distributions to our unitholders, of which $226 million was paid to Energy Transfer; and
•paid $8 million in distributions to noncontrolling interests.
We intend to pay cash distributions to the holders of our common units and Class C Units on a quarterly basis, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our General Partner and its affiliates. Class C unitholders receive distributions at a fixed rate equal to $0.8682 per quarter for each Class C Unit outstanding. There is no guarantee that we will pay a distribution on our units. On January 27, 2026, we declared a quarterly distribution of $0.9317 per common unit based on the results for the three months ended December 31, 2025, excluding distributions to Class C unitholders. The distribution will be approximately $128 million in the aggregate for common units, approximately $48 million with respect to Class D Units and approximately $60 million with respect to IDRs, and will be paid on February 19, 2026 to unitholders of record on February 6, 2026.
Capital Expenditures
For the year ended December 31, 2025, total capital expenditures on an accrual basis were $651 million, which included $440 million for growth capital and $211 million for maintenance capital. This includes the Partnership's proportionate share of capital expenditures related to its investments in unconsolidated affiliates of $63 million for growth capital and $11 million for maintenance capital.
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We currently expect to spend between $400 million and $450 million in maintenance capital expenditures and at least $600 million in growth capital expenditures for the full year 2026. These amounts include the Partnership's proportionate share for joint ventures.
Description of Indebtedness
Our outstanding consolidated indebtedness was as follows:

| December 31, 2025 |  | December 31, 2024
Credit Facility | $ | — |  |  | $ | 203 |
5.750% senior notes due 2025 | — |  |  | 600 |
6.000% senior notes due 2026 (1) | 500 |  |  | 500 |
3.875% CAD senior notes due 2026 (1)(2) | 400 |  |  | — |
Parkland 3.875% CAD senior notes due 2026 (1)(3) | 37 |  |  | — |
6.000% senior notes due 2027 | 600 |  |  | 600 |
5.625% senior notes due 2027 | 550 |  |  | 550 |
5.875% senior notes due 2027 (2) | 499 |  |  | — |
Parkland 5.875% senior notes due 2027 (3) | 1 |  |  | — |
5.875% senior notes due 2028 | 400 |  |  | 400 |
7.000% senior notes due 2028 | 500 |  |  | 500 |
6.000% CAD senior notes due 2028 (2) | 277 |  |  | — |
Parkland 6.000% CAD senior notes due 2028 (3) | 14 |  |  | — |
4.500% senior notes due 2029 | 800 |  |  | 800 |
7.000% senior notes due 2029 | 750 |  |  | 750 |
4.375% CAD senior notes due 2029 (2) | 397 |  |  | — |
Parkland 4.375% CAD senior notes due 2029 (3) | 40 |  |  | — |
4.500% senior notes due 2029 (2) | 790 |  |  | — |
Parkland 4.500% senior notes due 2029 (3) | 10 |  |  | — |
4.500% senior notes due 2030 | 800 |  |  | 800 |
6.375% senior notes due 2030 | 600 |  |  | 600 |
4.625% senior notes due 2030 (2) | 798 |  |  | — |
Parkland 4.625% senior notes due 2030 (3) | 2 |  |  | — |
5.625% senior notes due 2031 | 1,000 |  |  | — |
7.250% senior notes due 2032 | 750 |  |  | 750 |
6.625% senior notes due 2032 (2) | 493 |  |  | — |
Parkland 6.625% senior notes due 2032 (3) | 7 |  |  | — |
6.250% senior notes due 2033 | 1,000 |  |  | — |
5.875% senior notes due 2034 | 900 |  |  | — |
GoZone Bonds | 322 |  |  | 322 |
Lease-related financing obligations and other subsidiary debt | 233 |  |  | 132 |
Net unamortized premiums, discounts and fair value adjustments | 2 |  |  | 16 |
Deferred debt issuance costs | (83) |  |  | (37) |
Total debt | 13,389 |  |  | 7,486 |
Less: current maturities | 17 |  |  | 2 |
Total long-term debt, net | $ | 13,372 |  |  | $ | 7,484 |

(1)As of December 31, 2025, $937 million aggregate principal amount of senior notes due before December 31, 2026 were classified as long-term as management has the intent and ability to refinance the borrowings on a long-term basis.
(2)These senior notes, totaling $3.65 billion as of December 31, 2025, were assumed and exchanged by the Partnership in connection with the closing of the Parkland Acquisition. For additional information, see “Parkland Senior Note Exchange” below.
(3)These senior notes, totaling $111 million as of December 31, 2025, represent the aggregate principal amounts not tendered in the private exchange offers and remain outstanding obligations of Parkland. For additional information, see “Parkland Senior Note Exchange” below.
Credit Facility
As of December 31, 2025, we had no outstanding borrowings on the Credit Facility, and we had $26 million in standby letters of credit outstanding. The unused availability on the Credit Facility at December 31, 2025 was $2.47 billion. The weighted average
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interest rate on the total amount outstanding at December 31, 2025 was 6.38%. The Partn ership was in compliance with all financial covenants at December 31, 2025.
Recent Financing Transactions
March 2025 Senior Notes Offering and Redemption
In March 2025, the Partnership issued $1.00 billion aggregate principal amount of 6.250% senior notes due 2033 in a private offering. These notes will mature on July 1, 2033 and interest is payable semi-annually on January 1 and July 1 of each year. The Partnership used the net proceeds from the private offering to repay its $600 million aggregate principal amount of 5.750% senior notes due 2025 and to repay a portion of the outstanding borrowings under its Credit Facility.
September 2025 Senior Notes Offering
In September 2025, the Partnership issued $1.00 billion aggregate principal amount of 5.625% senior notes due 2031 and $900 million aggregate principal amount of 5.875% senior notes due 2034 in a private offering. These notes will mature on March 15, 2031 and March 15, 2034, respectively, and interest is payable semi-annually on March 15 and September 15 of each year, commencing on March 15, 2026. The Partnership used the net proceeds from this private offering (i) on the closing date of the Parkland Acquisition to fund a portion of the cash consideration for the Parkland Acquisition and related transaction costs, with the remaining proceeds used for general corporate purposes, and (ii) prior to the closing date of the Parkland Acquisition, to temporarily reduce the borrowings outstanding under the Partnership's Credit Facility and to pay interest and fees in connection therewith.
The 5.625% senior notes due 2031 and 5.875% senior notes due 2034 were originally subject to a special mandatory redemption requirement, which was eliminated upon closing of the Parkland Acquisition.
Parkland Senior Note Exchange
In October 2025, in connection with the Parkland Acquisition, the Partnership commenced a private offering to exchange up to C$1.60 billion Canadian dollar denominated notes issued by Parkland (collectively, the “PKI CAD Notes”) and up to $2.60 billion U.S. dollar denominated notes issued by Parkland (collectively, the “PKI USD Notes”) for new notes issued by the Partnership. The exchange offer closed on November 7, 2025 with approximately C$1.47 billion of the PKI CAD Notes and approximately $2.58 billion of the PKI USD Notes being validly tendered and not validly withdrawn.
September 2025 Series A Preferred Units Offering
In September 2025, the Partnership closed a private offering of 1.5 million of its 7.875% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units (the “Series A Preferred Units”) at an offering price of $1,000 per unit. The Partnership received net proceeds of approximately $1.47 billion from the sale of the Series A Preferred Units after deducting the initial purchasers' discount and other estimated offering expenses. The Partnership used the net proceeds from this private offering (i) on the closing date of the Parkland Acquisition to fund a portion of the cash consideration for the Parkland Acquisition, and (ii) prior to the closing date of the Parkland Acquisition, to temporarily reduce the borrowings outstanding under the Partnership's Credit Facility and to pay interest and fees in connection therewith.
Distributions on the Series A Preferred Units will be cumulative from the date of original issuance and will be payable semi-annually in arrears commencing on March 18, 2026, when, as, and if declared by Sunoco GP LLC out of legally available funds for such purpose. An initial distribution on the Series A Preferred Units will be paid on March 18, 2026 in an amount equal to approximately $39.38 per Series A Preferred Unit.
Guarantor Summarized Financial Information
The senior notes issued by NuStar Logistics are fully and unconditionally guaranteed by the Partnership, Sunoco Finance Corp. and certain of its subsidiaries; the senior notes issued by the Partnership and Sunoco Finance Corp. are fully and unconditionally guaranteed by NuStar Logistics and certain other subsidiaries. Each guarantee of the senior notes (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. See Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for a discussion of certain of our debt obligations.
The following tables present summarized combined balance sheet and income statement information for the Partnership, Sunoco Finance Corp. and NuStar Logistics, L.P. (the “Issuers”), as well as the subsidiaries that guarantee the senior notes issued by those three entities (collectively with the Issuers, 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
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Guarantor Issuer Group with non-guarantor subsidiaries, including the Guarantor Issuer Group’s investment balances in non-guarantor subsidiaries.

Summarized Combined Balance Sheet Information for the Guarantor Issuer Group: |  | December 31, 2025
Current assets |  | $ | 2,544 |
Non-current assets |  | 16,775 |
Current liabilities (a) |  | 1,816 |
Non-current liabilities, including long-term debt |  | 14,200 |

(a)Exc l udes $418 million of net intercompany payable owed to the non-guarantor subsidiaries from the Guarantor Issuer Group.
Long-term assets for the non-guarantor subsidiaries totaled $6.07 billion as of December 31, 2025.

Summarized Combined Income Statement Information for the Guarantor Issuer Group: |  | Year Ended December 31, 2025
Revenues |  | $ | 21,247 |
Operating income |  | 463 |
Net income |  | 51 |

Revenues and net income for the non-guarantor subsidiarie s totaled $3.95 billion and $476 million, respec tively, for the year ended December 31, 2025.
Contractual Obligations
We periodically enter into derivatives, such as futures and options, to manage our fuel price risk on inventory in the distribution system. Fuel hedging positions are not significant to our operations. On a consolidated basis, the Partnership had a position of 8.9 million barrels with an aggregated unrealized gain of $1.0 million at December 31, 2025.
Off-Balance Sheet Arrangements
We do not maintain any off-balance sheet arrangements for the purpose of credit enhancement, hedging transactions or other financial or investment purposes.
Cash Distributions
Sunoco Common Unit Distributions
Our Partnership Agreement sets forth the calculation used to determine the amount and priority of cash distributions that the common unitholders receive.
Cash distributions paid or to be paid with respect to Sunoco common units and Class D Units were as follows:

|  |  |  |  |  | Limited Partners |  |
Period Ended |  | Record Date |  | Payment Date |  | Per Unit Distribution |  | Distributions on Common Units |  | Distributions on Class D Units |  | Distribution to IDR Holders
December 31, 2022 |  | February 7, 2023 |  | February 21, 2023 |  | $ | 0.8255 |  |  | $ | 69 |  |  | $ | — |  |  | $ | 18 |
March 31, 2023 |  | May 8, 2023 |  | May 22, 2023 |  | 0.8420 |  |  | 71 |  |  | — |  |  | 19 |
June 30, 2023 |  | August 14, 2023 |  | August 21, 2023 |  | 0.8420 |  |  | 71 |  |  | — |  |  | 19 |
September 30, 2023 |  | October 30, 2023 |  | November 20, 2023 |  | 0.8420 |  |  | 71 |  |  | — |  |  | 19 |
December 31, 2023 |  | February 7, 2024 |  | February 20, 2024 |  | 0.8420 |  |  | 71 |  |  | — |  |  | 19 |
March 31, 2024 |  | May 13, 2024 |  | May 20, 2024 |  | 0.8756 |  |  | 119 |  |  | — |  |  | 36 |
June 30, 2024 |  | August 9, 2024 |  | August 19, 2024 |  | 0.8756 |  |  | 119 |  |  | — |  |  | 36 |
September 30, 2024 |  | November 8, 2024 |  | November 19, 2024 |  | 0.8756 |  |  | 119 |  |  | — |  |  | 36 |
December 31, 2024 |  | February 7, 2025 |  | February 19, 2025 |  | 0.8865 |  |  | 121 |  |  | — |  |  | 37 |
March 31, 2025 |  | May 9, 2025 |  | May 20, 2025 |  | 0.8976 |  |  | 122 |  |  | — |  |  | 39 |
June 30, 2025 |  | August 8, 2025 |  | August 19, 2025 |  | 0.9088 |  |  | 124 |  |  | — |  |  | 41 |
September 30, 2025 |  | October 30, 2025 |  | November 19, 2025 |  | 0.9202 |  |  | 126 |  |  | — |  |  | 42 |
December 31, 2025 |  | February 6, 2026 |  | February 19, 2026 |  | 0.9317 |  |  | 128 |  |  | 48 |  |  | 60 |

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Critical Accounting Estimates
We prepare our consolidated financial statements in conformity with GAAP. The preparation of these consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Critical accounting policies are those we believe are both most important to the portrayal of our financial condition and results of operations, and require our most difficult, subjective or complex judgments, often as a result of the need to make estimates about the effects of matters that are inherently uncertain. Judgments and uncertainties affecting the application of those policies may result in materially different amounts being reported under different conditions or using different assumptions.
We believe the following policies will be the most critical in understanding the judgments that are involved in preparation of our consolidated financial statements.
Fair Value Estimates in Business Combination Accounting and Impairment of Long-Lived Assets, Goodwill, Intangible Assets and Investments in Unconsolidated Affiliates. Business combination accounting and quantitative impairment testing are required from time to time due to the occurrence of events, changes in circumstances, or annual testing requirements. For business combinations, assets and liabilities are required to be recorded at estimated fair value in connection with the initial recognition of the transaction. For impairment testing, long-lived assets are required to be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Goodwill and intangibles with indefinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other-than-temporary. An impairment loss should be recognized only if the carrying amount of the asset/goodwill is not recoverable and exceeds its fair value. Calculating the fair value of assets or reporting units in connection with business combination accounting or impairment testing requires management to make several estimates, assumptions and judgments, and in some circumstances management may also utilize third-party specialists to assist and advise on those calculations.
In order to allocate the purchase price in a business combination or to test for recoverability when performing a quantitative impairment test, we must make estimates of projected cash flows related to the asset, which include, but are not limited to, 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. In order to determine fair value, we make certain estimates and assumptions, including, among other things, changes in general economic conditions in regions in which our markets are located, the availability and prices of commodities, our ability to negotiate favorable sales agreements, the risks that exploration and production activities will not occur or be successful, our dependence on certain significant customers and producers, and competition from other companies, including major energy producers. While we believe we have made reasonable assumptions to calculate the fair value, if future results are not consistent with our estimates, we could be exposed to future impairment losses that could be material to our results of operations.
The Partnership determines the fair value of our reporting units using the discounted cash flow method, the guideline company method, or a weighted combination of these methods. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determines fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts plus an estimate of later period cash flows, all of which are determined by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determines the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimates a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.
One key assumption in these fair value calculations is management’s estimate of future cash flows and EBITDA. In accounting for a business combination, these estimates are generally based on the forecasts that were used to analyze the deal economics. For impairment testing, these estimates are based on the annual budget for the upcoming year and forecasted amounts for multiple subsequent years. The annual budget process is typically completed near the annual goodwill impairment testing date, and management uses the most recent information for the annual impairment tests. The forecast is also subjected to a comprehensive update annually in conjunction with the annual budget process and is revised periodically to reflect new information and/or revised expectations. The estimates of future cash flows and EBITDA are subjective in nature and are subject to impacts from the business risks described in “Item 1A. Risk Factors.” Therefore, the actual results could differ significantly from the amounts used for business
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combination accounting and impairment testing, and significant changes in fair value estimates could occur in a given period. Such changes in fair value estimates could result in changes to the fair value estimates used in business combination accounting, which could significantly impact results of operations in a period subsequent to the business combination, depending on multiple factors, including the timing of such changes. In the case of impairment testing, such changes could result in additional impairments in future periods; therefore, the actual results could differ significantly from the amounts used for goodwill impairment testing, and significant changes in fair value estimates could occur in a given period, resulting in additional impairments.
In addition, we may change our method of impairment testing, including changing the weight assigned to different valuation models. Such changes could be driven by various factors, including the level of precision or availability of data for our assumptions. Any changes in the method of testing could also result in an impairment or impact the magnitude of an impairment.
Management does not believe that any of the Partnership’s goodwill balances, long-lived assets or investments in unconsolidated affiliates is currently at significant risk of a material impairment.
Income Taxes. As a limited partnership, we are generally not subject to state and federal income tax and would therefore not recognize deferred income tax liabilities and assets for the expected future income tax consequences of temporary differences between financial statement carrying amounts and the related income tax basis. We are, however, subject to a statutory requirement that our non-qualifying income cannot exceed 10% of our total gross income, determined on a calendar year basis under the applicable income tax provisions. If the amount of our non-qualifying income exceeds this statutory limit, we would be taxed as a corporation. Accordingly, certain activities that generate non-qualifying income are conducted through our wholly owned taxable corporate subsidiaries for which we have recognized deferred income tax liabilities and assets. These balances, as well as any income tax expense, are determined through management’s estimations, interpretation of tax laws of multiple jurisdictions and tax planning strategies. If our actual results differ from estimated results due to changes in tax laws, our effective tax rate and tax balances could be affected. As such, these estimates may require adjustments in the future as additional facts become known or as circumstances change.
The benefit of an uncertain tax position can only be recognized in the consolidated financial statements if management concludes that it is more likely than not that the position will be sustained with the tax authorities. For a position that is likely to be sustained, the benefit recognized in the consolidated financial statements is measured at the largest amount that is greater than 50% likely of being realized. In determining the future tax consequences of events that have been recognized in our consolidated financial statements or tax returns, judgment is required. Differences between the anticipated and actual outcomes of these future tax consequences could have a material impact on our consolidated results of operations or financial position.
Sunoco recognizes benefits in earnings and related deferred tax assets for net operating loss carryforwards (“NOLs”) and tax credit carryforwards. If necessary, a charge to earnings and a related valuation allowance are recorded to reduce deferred tax assets to an amount that is more likely than not to be realized by the Partnership in the future. Deferred income tax assets attributable to federal, state, and foreign NOLs and federal excess business interest expense carryforwards totaling $233 million have been included in Sunoco LP's consolidated balance sheet as of December 31, 2025. The state NOL carryforward benefits of $7 million ($6 million net of federal benefit) began expiring in 2025 with a substantial portion expiring between 2033 and 2039. Sunoco LP's corporate subsidiaries have federal NOLs of $287 million ($60 million in benefits) all of which were generated in 2018 or later. Of this amount, $206 million is subject to limitations under IRC §382 (ownership-change limitation) and $35 million is limited under Separate Return Limitation Year (“SRLY”) rules. Although these federal NOLs are expected to be fully utilized, the amount utilized in a particular year may be limited. Any federal NOL generated in 2018 and future years can be carried forward indefinitely. Sunoco LP's corporate subsidiaries have foreign NOLs of $93 million, of which $77 million will expire between 2026 and 2045. For the year ended December 31, 2025, the net change in the total valuation allowances was an increase of $62 million, and for the year ended December 31, 2024, there was no net change. Valuation allowances totaling $52 million and $10 million are attributable to foreign and federal NOLs, respectively. In making the assessment of the future realization of the deferred tax assets, we rely on future reversals of existing taxable temporary differences, tax planning strategies and forecasted taxable income based on historical and projected future operating results. The potential need for valuation allowances is regularly reviewed by management. If it is more likely than not that the recorded asset will not be realized, additional valuation allowances which increase income tax expense may be recognized in the period such determination is made. Likewise, if it is more likely than not that additional deferred tax assets will be realized, an adjustment to the deferred tax asset will increase income in the period such determination is made.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Interest Rate Risk
We are subject to market risk from exposure to changes in interest rates based on our financing, investing and cash management activities. We regularly borrow under our Credit Facility; however, we had no outstanding variable interest rate borrowings on the Credit Facility as of December 31, 2025. Therefore, a hypothetical change in variable rates would not have had a material impact on us at December 31, 2025. Our primary exposure relates to:
•interest rate risk on short-term borrowings; and
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•the impact of interest rate movements on our ability to obtain adequate financing to fund future acquisitions.
While we cannot predict or manage our ability to refinance existing debt or the impact interest rate movements will have on our existing debt, management evaluates our financial position on an ongoing basis. From time to time, we may enter into interest rate swaps to reduce the impact of changes in interest rates on our floating rate debt. We had no inter est rate swaps in effect during the years ended December 31, 2025 and 2024.
Commodity Price Risk
Our subsidiaries hold working inventories of refined petroleum products, renewable fuels, gasoline blendstocks and transmix in storage. As of December 31, 2025, we held approximately $1.77 billion of such inventory. While in storage, volatility in the market price of stored motor fuel could adversely impact the price at which we can later sell the motor fuel. However, we may use futures, forwards and other derivative instruments (collectively, "positions") to hedge a variety of price risks relating to deviations in that inventory from a target base operating level established by management. Derivative instruments utilized consist primarily of exchange-traded futures contracts traded on the New York Mercantile Exchange, Chicago Mercantile Exchange and Intercontinental Exchange, as well as over-the-counter transactions (including swap agreements) entered into with established financial institutions and other credit-approved energy companies. Our policy is generally to purchase only products for which there is a market and to structure sales contracts so that price fluctuations do not materially affect profit. While these derivative instruments represent economic hedges, they are not designated as hedges for accounting purposes. We may also engage in controlled trading in accordance with specific parameters set forth in a written risk management policy.
On a consolidated basis, the Partnership had a position of 8.9 million barrels with an aggregated unrealized gain of $1.0 million at December 31, 2025.
Foreign Currency Translation Risk
We generate revenues, incur expenses, and maintain investments and subsidiaries in currencies other than the U.S. dollar. As a result, our reported earnings, cash flows, and AOCI are exposed to fluctuations in foreign currency exchange rates. Changes in exchange rates can affect the U.S. dollar value of our foreign‑currency‑denominated assets and liabilities, as well as the translation of the operating results and financial position of our international subsidiaries. We may utilize derivative instruments, including foreign currency forward contracts and other hedging strategies, to mitigate the effects of foreign currency‑denominated cash flow and earnings exposures. As of December 31, 2025, the Partnership did not have any outstanding foreign currency derivatives.
Item 8. Financial Statements and Supplementary Data
See Index to Consolidated Financial Statements at Page F-1.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
We maintain disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) of the Exchange Act), that are designed to provide reasonable assurance that the information that we are required to disclose in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure. It should be noted that, because of inherent limitations, our disclosure controls and procedures, however well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the disclosure controls and procedures are met.
As required by paragraph (b) of Rule 13a-15 under the Exchange Act, our management with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-K. Based on such evaluation, our management, including our Chief Executive Officer and Chief Financial Officer, has concluded, as of December 31, 2025, that our disclosure controls and procedures were effective at the reasonable assurance level for which they were designed in that the information required to be disclosed by the Partnership in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.
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Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is a process that is designed under the supervision of our Chief Executive Officer and Chief Financial Officer and effected by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Our internal control over financial reporting includes those policies and procedures that:
•pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
•provide reasonable assurance that transactions are recorded as necessary to permit preparation of our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures recorded by us are being made only in accordance with authorizations of our management and board of directors; and
•provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our consolidated 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 and procedures may deteriorate.
On October 31, 2025, Sunoco completed its acquisition of Parkland. Management acknowledges that it is responsible for establishing and maintaining a system of internal controls over financial reporting for Parkland. We are in the process of integrating Parkland, and we therefore have excluded Parkland from our December 31, 2025 assessment of the effectiveness of internal control over financial reporting. Parkland had total asset of $13.35 billion as of December 31, 2025 and revenues of $3.17 billion from November 1, 2025 to December 31, 2025, which are included in our consolidated financial statements as of and for the year ended December 31, 2025. As a result of these integration activities, certain controls are being evaluated and may be changed. We believe, however, that we will be able to maintain sufficient controls over the substantive results of our financial reporting throughout this integration process.
Management conducted its evaluation of the effectiveness of internal control over financial reporting as of December 31, 2025, based on the framework in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessment included an evaluation of the design of its internal control over financial reporting and testing the operational effectiveness of its internal control over financial reporting. Management reviewed the results of the assessment with the audit committee of the board of directors. Based on its assessment, management determined that, as of December 31, 2025, it maintained effective internal control over financial reporting.
Grant Thornton LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Partnership included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2025. The report, which expresses an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2025, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”
Changes in Internal Control over Financial Reporting
Except for the Parkland Acquisition, there have been no changes in our internal control over financial reporting during the three months ended December 31, 2025 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
From time to time, we make changes to our internal control over financial reporting that are intended to enhance its effectiveness and which do not have a material effect on our overall internal control over financial reporting. We will continue to evaluate the effectiveness of our disclosure controls and procedures and internal control over financial reporting on an ongoing basis and will take action as appropriate.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors of Sunoco GP LLC and
Unitholders of Sunoco LP
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Sunoco LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2025, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Partnership as of and for the year ended December 31, 2025, and our report dated February 19, 2026 expressed an unqualified opinion on those 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 (“Management’s Report”). 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 included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Our audit of, and opinion on, the Partnership’s internal control over financial reporting does not include the internal control over financial reporting of Parkland Corporation, a consolidated subsidiary, whose financial statements reflect total assets and revenues constituting 47 and 13 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2025. As indicated in Management’s Report, Parkland Corporation was acquired during 2025. Management’s assertion on the effectiveness of the Partnership’s internal control over financial reporting excluded internal control over financial reporting of Parkland Corporation.
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/ GRANT THORNTON LLP
Dallas, Texas
February 19, 2026
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Item 9B. Other Information
None.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not Applicable.
Part III
Item 10. Directors, Executive Officers and Corporate Governance
Board of Directors
Our general partner, Sunoco GP LLC (our “General Partner”), manages and directs our operations and activities. The membership interest in our General Partner is solely owned by Energy Transfer LP (“Energy Transfer”). In connection with the Parkland Acquisition and related restructuring in 2025, Energy Transfer delegated the right to appoint all directors of our General Partner to SunocoCorp. As the owner of the managing member of SunocoCorp, Energy Transfer ultimately maintains the right to appoint the directors of our General Partner. Our General Partner’s limited liability company agreement provides that our General Partner’s Board of Directors (the “Board”) shall consist of between three and twelve persons, at least three of whom are required to qualify as independent directors. As of December 31, 2025, the Board consisted of seven persons, five of whom qualify as “independent” under the listing standards of the NYSE and our governance guidelines. Our Board has affirmatively determined that the directors who qualify as “independent” under the NYSE’s listing standards, SEC rules and our governance guidelines are Oscar A. Alvarez, Bradley C. Barron, David K. Skidmore, W. Brett Smith and Ray W. Washburne.
As a limited partnership, we are not required by the rules of the NYSE to seek unitholder approval for the election of any of our directors. We do not have a formal process for identifying director nominees, nor do we have a formal policy regarding consideration of diversity in identifying director nominees. We believe, however, that the individuals appointed as directors have experience, skills and qualifications relevant to our business and have a history of service in senior leadership positions with the qualities and attributes required to provide effective oversight of the Partnership.
The Board’s Role in Risk Oversight
Our Board generally administers its risk oversight function as a whole. It does so in part through discussion and review of our business, financial and corporate governance practices and procedures, with opportunity for specific inquiries of management. In addition, at each regular meeting of the Board, management provides a report of the Partnership’s operational and financial performance, which often prompts questions and feedback from the Board. The audit committee provides additional risk oversight through its quarterly meetings, where it discusses policies with respect to risk assessment and risk management, reviews contingent liabilities and risks that may be material to the Partnership and assesses major legislative and regulatory developments that could materially impact the Partnership’s contingent liabilities and risks. The audit committee is required to discuss any material violations of our policies brought to its attention on an ad hoc basis. Additionally, the compensation committee reviews our overall compensation program and its effectiveness at both linking executive pay to performance and aligning the interests of our executives and our unitholders.
Committees of the Board of Directors
The Board has established standing committees to consider designated matters. The standing committees of the Board are: the audit committee and the compensation committee. The listing standards of the NYSE do not require boards of directors of publicly traded limited partnerships to be composed of a majority of independent directors, nor are they required to have a standing nominating or compensation committee. Notwithstanding, the Board has elected to have a standing compensation committee. We do not have a nominating committee in view of the fact that SunocoCorp, which holds the board appointment rights of our General Partner, appoints the directors to our Board. The Board has adopted governance guidelines for the Board and charters for each of the audit and compensation committees.
Audit Committee
We are required to have an audit committee of at least three members, and all of its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act. The current members of the audit committee are Oscar A. Alvarez, David K. Skidmore and W. Brett Smith, each of whom are independent under the NYSE’s standards and SEC’s rules for audit committee members. In addition, the Board has determined that Mr. Skidmore, who serves as chairman of the audit committee, has “accounting or related financial management expertise” and constitutes an “audit committee financial expert,” in accordance with SEC and NYSE rules and regulations.
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The audit committee assists the Board in its oversight of the integrity of our consolidated financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee meets on a regularly-scheduled basis with our independent accountants at least four times each year and is available to meet at their request. Our independent registered public accounting firm has been given unrestricted access to the audit committee and our management, as necessary. The audit committee has the authority and responsibility to review our external financial reporting, to review our procedures for internal auditing and the adequacy of our internal accounting controls, to consider the qualifications and independence of our independent accountants, to engage and resolve disputes with our independent accountants, including the letter of engagement and statement of fees relating to the scope of the annual audit work and special audit work that may be recommended or required by the independent accountants, and to engage the services of any other advisors and accountants as the audit committee deems advisable. The committee reviews and discusses the audited consolidated financial statements with management, discusses with our independent auditors matters and makes recommendations to the Board relating to our audited consolidated financial statements. In addition, the audit committee is authorized to recommend to the Board any changes or modifications to its charter that the committee believes may be required. The charter of the audit committee is publicly available on our website at http://www.sunocolp.com/investors/corporate-governance. The audit committee held four meetings during 2025.
Compensation Committee
Although we are not required under NYSE rules to appoint a compensation committee because we are a limited partnership, the Board established a compensation committee to establish standards and make recommendations concerning the compensation of our officers and directors. The compensation committee is currently chaired by Mr. Alvarez and includes Mr. Smith. In addition, the compensation committee determines and establishes the standards for any awards to employees and officers providing services to us under the equity compensation plans adopted by our unitholders, including the performance standards or other restrictions pertaining to the vesting of any such awards. Pursuant to the charter of the compensation committee, a director serving as a member of the compensation committee may not be an officer of or employed by our General Partner, us or our subsidiaries. During 2025, neither Mr. Alvarez nor Mr. Smith was an officer or employee of affiliates of Energy Transfer, or served as an officer of any company with respect to which any of our executive officers served on such company’s board of directors. In addition, neither Mr. Alvarez nor Mr. Smith is a former employee of affiliates of Energy Transfer. The charter of the compensation committee is publicly available on our website at http://www.sunocolp.com/investors/corporate-governance. The compensation committee held four meetings during 2025.
Code of Ethics
The Board has approved a Code of Business Conduct and Ethics which is applicable to all directors, officers and employees of our General Partner and its affiliates, including the principal executive officer, the principal financial officer and the principal accounting officer. The Code of Business Conduct and Ethics is available on our website at http://www.sunocolp.com/investors/corporate-governance (under the ‘Investor Relations/Corporate Governance’ tab) and in print without charge to any unitholder who sends a written request to our secretary at our principal executive offices at 8111 Westchester Drive, Suite 400, Dallas, Texas 75225. We intend to post any amendments of this code, or waivers of its provisions applicable to directors or executive officers of our General Partner, including its principal executive officer, principal financial officer and principal accounting officer, at this location on our website.
Insider Trading Policy
The Board has adopted insider trading policies and procedures that we believe are reasonably designed to promote compliance with insider trading laws, rules, and regulations, and the listing standards of the New York Stock Exchange. Our insider trading policy is applicable to all employees, officers and directors and, among other things, (i) prohibits our employees, officers, directors and related persons and entities from trading in securities of the Partnership and its affiliated companies while in possession of material, non-public information, (ii) prohibits our employees, officers and directors from disclosing material, non-public information to persons outside of the Partners hip, other than in the course of performance of their duties, and (iii) requires that certain individuals who are designated as “Insiders” only transact in Partnership securities during an open trading window period, subject to limited exceptions. A copy of our insider trading policy is incorporated by reference into Exhibit 1 9.1 to this Annual Report on Form 10-K.
Corporate Governance Guidelines
The Board has adopted a set of Corporate Governance Guidelines to promote a common set of expectations as to how the Board and its committees should perform their functions. These principles are published on our website at http://www.sunocolp.com/investors/corporate-governance and reviewed by the Board annually or more often as the Board deems appropriate.
Meetings of Non-Management Directors and Communications with Directors
In accordance with our Corporate Governance Guidelines, the Board holds executive sessions of non-management directors not less than twice annually. These meetings are presided over, on a rotating basis, by the chairman of the audit and compensation committees of the Board. Interested parties may contact the chairman of our audit or compensation committee, or our independent or non-
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management directors individually or as a group, utilizing the contact information set forth on our website at http://www.sunocolp.com/investors/corporate-governance.
Note that the preceding Internet addresses are for information purposes only and are not intended to be hyperlinked. Accordingly, no information found or provided at those Internet addresses or at our website in general is intended or deemed to be incorporated by reference herein.
Executive Officers and Directors of our General Partner
The following table shows information about the current executive officers and directors of our General Partner as of February 19, 2026. References to “our officers,” “our directors,” or “our Board” refer to the officers, directors and Board of Directors of our General Partner. Directors are appointed to hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers serve at the discretion of the Board.

Name |  | Age |  | Position With Our General Partner
Joseph Kim |  | 54 |  | President & Chief Executive Officer and Director
Karl R. Fails |  | 51 |  | Executive Vice President, Chief Operating Officer
Brian A. Hand |  | 58 |  | Executive Vice President, Chief Sales Officer
Dylan A. Bramhall |  | 49 |  | Chief Financial Officer
Austin B. Harkness |  | 46 |  | Executive Vice President, Chief Commercial Officer
Ray W. Washburne |  | 65 |  | Chairman of the Board
Oscar A. Alvarez |  | 70 |  | Director
Bradley C. Barron |  | 60 |  | Director
David K. Skidmore |  | 70 |  | Director
W. Brett Smith |  | 66 |  | Director

Joseph Kim - President and Chief Executive Officer and Director. Mr. Kim was appointed to the Board in January 2018 and has served as President and Chief Executive Officer of our General Partner since January 2018. From June 2017 through December 2017, he served as President and Chief Operating Officer and prior to that served as Executive Vice President and Chief Development Officer since October 2015. Prior to joining the Partnership in October 2015, Mr. Kim held various executive positions, including Chief Operating Officer for Pizza Hut and Senior Vice President - Retail Strategy and Growth for Valero Energy. Prior to his 18 years with Pizza Hut and Valero, Mr. Kim worked for Arthur Andersen within both the Audit and Consulting business units. He is a graduate of Trinity University with a bachelor’s degree in Business Administration.
Karl R. Fails - Executive Vice President, Chief Operating Officer. Mr. Fails has served as Executive Vice President, Chief Operating Officer of our General Partner since September 2021. He is responsible for overall performance of the business across all segments, both financial and operational, and has direct control of midstream, refining and trucking operations. Mr. Fails previously held the positions of Senior Vice President, Chief Operations Officer from January 2019 to September 2021, Senior Vice President, Chief Commercial Officer from February 2018 to January 2019, and Executive Vice President - Supply & Trading from January 2017 to January 2018 and held various other leadership positions during his tenure at the Partnership and Sunoco, Inc. (now known as ETC Sunoco Holdings LLC). Prior to joining Sunoco, Inc. in 2010, Mr. Fails served in various operations and engineering roles in the refining business for both Valero Energy and Exxon. He holds Bachelor’s degrees in Chemical Engineering and Math from Brigham Young University and a Master of Business Administration degree from the University of California, Berkeley.
Brian A. Hand - Executive Vice President, Chief Sales Officer. Mr. Hand has served as Executive Vice President, Chief Sales Officer since March 2024. He is responsible for all aspects of the fuel distribution business, including strategic acquisition and divestment, branded wholesale, direct dealers, performance products, and sales. He is also responsible for all marketing functions, engineering, construction and strategic partnerships. Mr. Hand previously held the positions of Senior Vice President, Chief Sales Officer, Chief Development and Marketing Officer, Chief Procurement Officer and various other leadership positions during his tenure with the Partnership and Sunoco, Inc. (now known as ETC Sunoco Holdings LLC). Prior to joining Sunoco, Inc. in 2010, Mr. Hand served in various leadership positions at Hewlett Packard, Blockbuster, Inc. and Cingular Wireless (now AT&T Mobility). He holds a Bachelor’s degree in Accounting and Business Management from Lebanon Valley College and a Master of Business Administration degree from Widener University.
Dylan A. Bramhall - Chief Financial Officer. Mr. Bramhall has served as Chief Financial Officer of our General Partner since October 2020 and currently is also Group Chief Financial Officer of Energy Transfer's General Partner since November 2022. Mr. Bramhall joined Energy Transfer in 2015 as a result of its merger with Regency Energy Partners and is responsible for oversight of the Partnership’s Financial Planning and Analysis, Credit and Commodity Risk Management, Insurance, Cash Management, Capital Markets, Accounting, Financial Reporting and Investor Relations groups. He also serves as a member of Energy Transfer’s Risk
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Oversight Committee. While at Regency, Mr. Bramhall held management positions in the finance, risk, commercial and operations groups. Mr. Bramhall holds a Bachelor of Business Administration in finance and Master of Business Administration in finance and operations management, both from the University of Iowa.
Austin B. Harkness - Executive Vice President, Chief Commercial Officer. Mr. Harkness has served as Executive Vice President, Chief Commercial Officer, since March 2024 He is responsible for all aspects of the Partnership’s supply, trading, pricing, real estate and unbranded sales activity. Mr. Harkness previously held the positions of Senior Vice President, Commercial from June 2021 to March 2024 and Vice President, Pricing & Real Estate beginning in March 2020 when he joined the Partnership. Prior to joining the Partnership, Mr. Harkness held various executive positions, including Chief Operating Officer for Honor and Vice President, Operations at YUM! Brands. Prior to that, Mr. Harkness worked at McKinsey where he served clients on a variety of strategic and commercial topics spanning multiple industries. He holds a Bachelor’s degree in Business Administration from the Business Honors Program and a Master of Business Administration degree from the McCombs School of Business, both at the University of Texas at Austin.
Ray W. Washburne - Chairman of the Board. Mr. Washburne was appointed to the Board and elected as the Chairman of the Board in April 2022. He is currently President and Chief Executive Officer of Charter Holdings, Inc., a Dallas-based investment company involved in real estate, restaurants and diversified financial investments. He is also the Vice Chairman of the Gillon Property Group (GPG) governing board. GPG is a privately held, vertically integrated real estate investment, development, and operations firm based in Dallas, Texas. From August 2017 to February 2019, Mr. Washburne served as the President and Chief Executive Officer of the Overseas Private Investment Corporation (OPIC), the United States government’s development finance institution. From 2000 to 2017, Mr. Washburne served on the board of directors of Veritex Holdings, Inc. (Nasdaq: VBTX), a Texas -based bank holding company that conducts banking activities through its subsidiary, Veritex Community Bank. He has also served as an adjunct professor at the Cox School of Business at Southern Methodist University. Mr. Washburne is also a member of the Republican Governors Association Executive Roundtable, the American Enterprise Institute, the Council on Foreign Relations, and is on the Advisory Board of the United States Southern Command. Mr. Washburne was selected to serve on the Board of Directors because of his expertise in international finance, his relationships in government, and his experience on the board of a publicly traded company.
Oscar A. Alvarez - Director. Mr. Alvarez was appointed to the Board in March 2018. Mr. Alvarez chairs our compensation committee and serves on our audit committee. Mr. Alvarez served the Republic of Honduras for over 30 years, and was elected as a Representative in the National Congress of Honduras multiple times before retiring from politics in 2018. Over the course of his political career he was appointed to the cabinet position of Secretary of Security in both 2002 and 2010. Prior to this, he assisted with the diplomatic mission of the Honduran Embassy in Washington D.C. as Assistant Defense Attaché. In 1994, Mr. Alvarez entered the private sector and founded Atessa Seguridad S.A., providing turnkey security services for many major banks in the country of Honduras. A veteran of the Honduran Armed Forces, he is a graduate of United States Army Ranger School in Fort Benning, GA and the Special Forces Qualification Course at Fort Bragg, NC. Mr. Alvarez has a bachelor's degree from Texas A&M University, where he was the first cadet to be commissioned into a foreign army. He has also taken graduate courses in International Relations at Johns Hopkins University. Mr. Alvarez was selected to serve on our Board due to his extensive international experience.
Bradley C. Barron - Director. Mr. Barron was appointed to the Board in connection with our acquisition of Nu Star in 2024. Mr. Barron previously served as the chairman of the board, President and Chief Executive Officer of NuStar Energy, LP. From 2003 until his 2013 promotion to Chief Executive Officer, Mr. Barron served in executive positions at NuStar ranging from Vice President, Executive Vice President, and General Counsel and Secretary. Prior to Mr. Barron’s service with NuStar, he was with Valero Energy Corporation from 2001 to 2003. He holds a Bachelor’s degree in Business Administration at Texas Tech University and a Juris Doctorate degree from The University of Texas School of Law, where he was Order of the Coif. Mr. Barron also serves on the board of directors of the San Antonio branch of the Federal Reserve Bank of Dallas. Mr. Barron was selected to serve on the Board because of his experience, qualifications and skills in the logistics and refining industries and the extensive knowledge and experience he attained as an executive officer and director of public companies.
David K. Skidmore - Director. Mr. Skidmore was appointed to the Board in May 2021. Mr. Skidmore was elected as the Chair of our audit committee in January 2023. Mr. Skidmore previously served as a director of Energy Transfer Operating, L.P. from March 2013 to May 2021. He was also a member of the audit committee of Energy Transfer Operating, L.P. He has been Vice President of Ventex Oil & Gas, Inc. since 1995 and has been actively involved in exploration and production throughout the Gulf Coast and mid-Continent regions for over 35 years. He founded Skidmore Exploration, Inc. in 1981 and has been an independent oil and gas producer since that time. From 1977 to 1981, he worked for Paraffine Oil Corporation and Texas Oil & Gas in Houston. He holds BS degrees in both Geology and Petroleum Engineering, is a Certified Petroleum Geologist and Registered Professional Engineer (inactive), and active member of the AAPG, and SPE. Mr. Skidmore was selected to serve as a director because of his continual involvement in geological, geophysical, legal, engineering and accounting aspects of an active oil and gas exploration company. As an energy professional, active oil and gas producer and successful business owner, Mr. Skidmore possesses valuable first-hand knowledge of the energy transportation business and market conditions affecting its economics.
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W. Brett Smith - Director. Mr. Smith was appointed to the Board and to serve as a member of the audit committee of the Board in March 2024. He has served as President and Managing Partner of Rubicon Oil & Gas, LLC since October 2000. He has also served as President of Rubicon Oil & Gas II, LP since May 2005, President of Quientesa Royalty LP since February 2005 and President of Action Energy LP since October 2008. Mr. Smith was President of Rubicon Oil & Gas, LP from October 2000 to May 2005. For more than 30 years, Mr. Smith has been active in assembling exploration prospects in the Permian Basin, Oklahoma, New Mexico and the Rocky Mountain areas. Mr. Smith previously served on the board of directors of LE GP, LLC, the general partner of Energy Transfer, and on the audit committee, and on the board of directors of USA Compression GP, LLC, the general partner of USA Compression Partners, LP. Mr. Smith was selected to serve as a director based on his experience as an executive and as a director in the oil and gas industry, particularly for other limited partnerships.
Section 16(a) Beneficial Ownership Reporting Compliance
Each director and executiv e officer (and, for a specified period, certain former directors and executive officers) of our General Partner and each holder of more than 10% of a class of our equity securities is required to report to the SEC his or her pertinent position or relationship, as well as transactions in those securities, by specified dates.
Delinquent Section 16(a) Report s
Section 16(a) of the Exchange Act requires the directors and executive officers of our general partner, as well as persons who own more than ten percent of the common units representing limited partner interests in us, to file reports of ownership and changes of ownership on Forms 3, 4 and 5 with the SEC. The SEC regulations also require that copies of these Section 16(a) reports be furnished to us by such reporting persons. Based upon a review of copies of these reports, we believe all applicable Section 16(a) reports were timely filed in 2025.
Reimbursement of Expenses of our General Partner
Under our Partnership Agreement, our General Partner does not receive a management fee or other compensation for its role as our general partner. However, our General Partner is reimbursed for all expenses incurred on our behalf. These expenses include shared service fees, as well as all other expenses necessary or appropriate to the conduct of our business that are allocable to us, as provided for in our Partnership Agreement. There is no cap on the amount that may be paid or reimbursed to our General Partner.
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Item 11. Executive Compensation
As is commonly the case for many publicly traded limited partnerships, we do not have officers or directors. Instead, we are managed by the board of directors of our General Partner, and the executive officers of our General Partner perform all of our management functions. As a result, the executive officers of our General Partner are essentially our executive officers. Because Energy Transfer controls our General Partner and owns a significant limited partner interest in us, Energy Transfer will be referenced throughout this Item 11. References to “our officers” and “our directors” refer to the officers and directors of our General Partner.
Compensation Discussion and Analysis
Named Executive Officers
This Compensation Discussion and Analysis is focused on the total compensation of the executive officers of our General Partner as set forth below. The executive officers we refer to in this discussion as our “named executive officers,” or “NEOs,” for the 2025 fiscal year are the following officers of our General Partner:

Name | Principal Position
Joseph Kim | President and Chief Executive Officer
Dylan A. Bramhall | Chief Financial Officer
Karl R. Fails | Executive Vice President, Chief Operating Officer
Brian A. Hand | Executive Vice President, Chief Sales Officer
Austin B. Harkness | Executive Vice President, Chief Commercial Officer

Our board of directors has established a compensation committee to review and make decisions with respect to the compensation determinations of our officers and directors. In this discussion, we refer to our compensation committee as the “Compensation Committee.” However, our Compensation Committee consults with and receives guidance and input, as appropriate, from Energy Transfer’s Compensation Committee, Energy Transfer’s Executive Chairman of the board of directors, and Energy Transfer’s most senior Human Resources executive to ensure compensation decisions are undertaken consistent with the compensation philosophy and objectives set by Energy Transfer.
In addition to his role as the Chief Financial Officer of our General Partner, Mr. Bramhall also serves as Executive Vice President and Group Chief Financial Officer of Energy Transfer’s general partner. For the periods presented herein, 100% of Mr. Bramhall’s compensation was attributed to Energy Transfer.
Compensation Philosophy and Objectives
Generally, our compensation philosophy and objectives are substantially the same as those set by Energy Transfer and are based on the premise that a significant portion of each executive's total compensation should be incentive-based or “at-risk” compensation. We also share Energy Transfer’s philosophy that executives’ total compensation levels should be competitive in the marketplace for executive talent and abilities. Our General Partner seeks a total compensation program for our NEOs that provides for an annual base compensation rate slightly below the median market (i.e., approximately the 30 th to 40 th percentile of market) but incentive-based compensation composed of a combination of compensation vehicles designed to reward both short- and long-term performance that are both targeted to pay out at approximately the top-quartile of market for similarly situated businesses. Our General Partner believes the incentive-based balance is achieved by (i) the payment of annual discretionary cash bonuses that consider the achievement of the financial performance objectives for a fiscal year set at the beginning of such fiscal year and the individual contributions of our NEOs to the success of the achievement of the annual financial performance objectives, and (ii) the annual grant of time-based restricted, restricted phantom unit awards and/or cash restricted awards under the long-term incentive plan, which awards are intended to provide a long-term incentive and retentive value to our key employees to focus their efforts on increasing the market price of our publicly traded units and to increase the cash distribution we pay to our unitholders.
The Partnership historically granted restricted unit and/or phantom unit awards (“RSUs”). Beginning in 2024, the Partnership began granting cash restricted units (“CRSUs”) that vest, based generally upon continued employment, at a rate of 1/3 annually over a three-year period. Upon the introduction of the award in CRSUs in 2024 and continuing for 2025, the total annual awards to executives, including the NEOs, were split 75% in the form of RSUs and 25% in the form of CRSUs. The RSUs vest, based generally upon continued employment, at a rate of 60% after the third year of service and the remaining 40% after the fifth year of service and the CRSUs vest, based generally upon continued employment, at a rate of 1/3 annually over a three-year period. The Partnership believes that these equity-based incentive arrangements are important in attracting and retaining executive officers and key employees as well as motivating these individuals to achieve stated business objectives. The equity-based compensation reflects the importance our General Partner places on aligning the interests of its named executive officers with those of Unitholders.
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While the Partnership utilizes time-based forms of equity awards, the grant date valuation utilizes a modified total unitholder return (“TUR”) performance as measured against the average return of Alerian MLP index (AMZ) over defined periods of time. The modified TUR is designed to create a recognition of a performance adjustment to the equity awards based on the prior periods measured to add an element of performance impact in setting grant date value even though the RSUs themselves are a time-vested vehicle. As discussed below, our Compensation Committee, in consultation with our General Partner, and, as applicable Energy Transfer or the Energy Transfer Compensation Committee, are responsible for the compensation policies and compensation level of the named executive officers of our General Partner.
Our compensation program is structured to achieve the following:
•reward executives with an industry-competitive total compensation package of competitive base salaries and significant incentive opportunities yielding a total compensation package approaching the top-quartile of the market;
•attract, retain and reward talented executive officers and key management employees by providing total compensation competitive with that of other executive officers and key management employees employed by publicly traded limited partnerships or other peer companies of similar size and in similar lines of business;
•motivate executive officers and key employees to achieve strong financial and operational performance;
•emphasize performance-based or “at-risk” compensation; and
•reward individual performance.
Components of Executive Compensation
For the year ended December 31, 2025, the compensation paid to our NEOs consisted of the following components:
•annual base salary;
•non-equity incentive plan compensation consisting solely of discretionary cash bonuses based on stated performance objectives;
•time-vested RSUs and CRSUs under the equity incentive plan;
•payment of distribution equivalent rights (“DERs”) on unvested RSUs under our equity incentive plan;
•vesting of previously issued time-based RSUs issued pursuant to equity incentive plans of affiliates; and
•401(k) plan employer matching contributions.
Methodology
The Compensation Committee considers relevant data available to it to assess our competitive position with respect to base salary, annual short-term incentives and long-term incentive compensation for our executives, including our NEOs. The Compensation Committee also considers individual performance, levels of responsibility, skills and experience.
Periodically, we engage a third-party consultant to provide the Compensation Committee of our General Partner with market information for compensation levels at peer companies in order to assist in the determination of compensation levels for executives, including the named executive officers. In 2025, Meridian Compensation Partners (“Meridian”), the independent compensation advisor to Energy Transfer completed an evaluation of the market competitiveness of total compensation levels of the senior leadership team, including the named executive officers. The Meridian review provided market information with respect to compensation of Partnership executives, including the named executive officers during the year ended December 31, 2025, which replaced and updated data from the previous review conducted in 2023.
In particular, the review by Meridian was designed to (i) evaluate the market competitiveness of total compensation levels for certain members of senior management, including our named executive officers; (ii) assist in the determination of appropriate compensation levels for our senior management, including the named executive officers; and (iii) confirm that our compensation programs were yielding compensation packages consistent with our overall compensation philosophy. The Partnership was reviewed by Meridian through various metrics in order to recognize the Partnership’s unique structure, including (i) the recent transformative transactional activity over the most recent two-years, including the international aspects thereof and (ii) that the Partnership receives certain shared-service support from Energy Transfer. As such, Meridian reviewed certain of our executives, including the named executive officers, in their specific functions to determine the appropriate benchmarking technique. In all circumstances, Meridian considered our annual revenues and market capitalization levels in its benchmarking. In conducting its review, Meridian assisted in continuing the development of the “peer group” of companies in the energy industry that most closely reflect the profile of the Partnership. In addition to the companies reviewed as part of Meridian’s review for benchmarking, Sunoco will continue to work to refine a “core peer” group that is more identifiable in similar business lines and types as Sunoco, especially in light of the Partnership’s recent growth and on-going transition to a more traditional midstream company.
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The compensation analysis provided by Meridian covered all major components of total compensation, including annual base salary, annual short-term cash bonus and long-term incentive awards for our named executive officers as compared to officers of companies similarly situated in terms of structure, annual revenues, assets and market capitalization and made determinations with respect to such officers’ level (i.e. as a corporate officer, subsidiary officer or shared service function) given the unique characteristics of our structure. In preparing the review materials, Meridian utilized generally accepted compensation principles and gathered data from public disclosures, including Form 10-K and proxy data and published survey data from multiple sources that are relevant to Sunoco’s, industry, financial size and operational breadth. The Meridian review process also included significant engagement with management to fully understand job scope, responsibilities and roles of each of the executive officers, which discussions allow Meridian the ability to completely evaluate specific aspects of an executive officer’s position to allow for more accurate comparisons.
After completion of the 2025 review, the Compensation Committee undertook a detailed review of the information provided, including Meridian’s specific summary observations and recommended considerations for all compensation going forward. The observations addressed overall competitive benchmarking, peer company approaches to compensation and short and long-term incentive plan design, the Compensation Committee considered and reviewed the results of the study performed by Meridian to determine if the results indicated that the compensation programs were yielding a competitive total compensation model prioritizing incentive-based compensation and rewarding achievement of short and long-term performance objectives and considered Meridian’s conclusions and recommendations. While Meridian found that Sunoco is continuing to achieve its stated objectives with respect to the “at-risk” approach, Meridian also recommended certain adjustments for consideration, which considerations were designed to allow Sunoco to continue to achieve its targeted percentiles on base compensation and incentive compensation (short and long-term). In respect of the 2025 Meridian review, the Compensation Committee, in consultation with Meridian and executive management, made certain changes to base compensation of the executives, including the NEOs and certain adjustments to the variable compensation targets for the annual bonus plan and the equity plan.
In addition to the information received as part of Meridian’s review, the Compensation Committee also has access to information obtained from other sources in its determination of compensation levels for our named executive officers, such as annual third party surveys, although third-party survey data is not used by the Compensation Committee to benchmark the amount of total compensation or any specific element of compensation for the named executive officers.
Base salary. Base salary is designed to provide for a competitive fixed level of pay that attracts and retains executive officers and compensates them for their level of responsibility and sustained individual performance (including experience, scope of responsibility and results achieved). The salaries of our named executive officers are targeted at an annual base salary slightly below median level of market and are determined by the Compensation Committee. Base salaries also are influenced by internal pay equity (fair and consistent application of compensation practices). At the NEO level, the balance of compensation is weighted toward pay-at-risk compensation (annual bonuses and long-term incentives).
In August, in response to the 2025 Meridian review, the Compensation Committee approved base salary increase to each of the named executive officers. Mr. Kim’s salary increased to $950,000 from his previous level of $881,875, Mr. Fails’ salary increased to $600,000 from his previous level of $539,500, Mr. Hand’s salary increased to $450,000 from his previous level of $420,810 and Mr. Harkness’ salary increased to $450,000 from his previous level of $420,810. Prior to the August adjustments, in June during the annual merit process, Mr. Kim’s salary increased to $881,875 from his previous level of $850,000, Mr. Fails’ salary increased to $539,500 from his previous level of $520,000, Mr. Hand’s salary increased to $420,810 from his previous level of $405,600 and Mr. Harkness’ salary increased to $420,810 from his previous level of $405,600. In general, Sunoco approved a merit pool increase of 3.75% for all of its employees and all of the named executive officers’ adjustments were in line with the pool for all employees. As noted above, Mr. Bramhall no longer receives a salary allocation from Sunoco effective November 11, 2022.
Annual Bonus. In addition to base salary, the Compensation Committee makes a determination whether to award discretionary annual cash bonuses to employees, including our named executive officers, following the end of the year. These discretionary bonuses, if awarded, are intended to reward our named executive officers for the achievement of financial performance objectives during the year for which the bonuses are awarded in light of the contribution of each individual to our profitability and success during such year.
The Amended Bonus Plan is a discretionary annual cash bonus plan available to all employees, including the named executive officers. The purpose of the Amended Bonus Plan is to reward employees for contributions towards the Partnership’s business goals and to aid in motivating employees. The Amended Bonus Plan is administered by the Compensation Committee and the Compensation Committee has the authority to establish and interpret the rules and regulations relating to the Amended Bonus Plan, to select participants, to determine and approve the size of any actual award amount, to make all determinations, including factual determinations, under the Amended Bonus Plan, and to take all other actions necessary or appropriate for the proper administration of the Bonus Plan.
Under the Amended Bonus Plan, the Compensation Committee evaluates and determines an overall funded cash bonus pool based on achievement of (i) an internal Adjusted EBITDA Target, (ii) an internal distributable cash flow target (“DCF Target”) and (iii) performance of each department compared to the applicable department budget (“Departmental Budget Target”). Under the Amended Bonus Plan, the Budget Targets were weighted 60% on the achievement of the Adjusted EBITDA Target, 25% on the achievement of
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the DCF Target and 15% on the achievement of the Departmental Budget Target. The total amount of cash to be allocated to the funded bonus pool will range from 0% to 135% for each of the budgeted DCF Target and Adjusted EBITDA Target and will range from 0% to 100% of the Departmental Budget Target. Under the Amended Bonus Plan, the maximum bonus pool funding is 130% of the bonus pool target.
While the funded bonus pool will reflect an aggregation of performance under each target, in the event performance under the Adjusted EBITDA Target is below 80% of its target, no bonus pool will be funded. If the bonus pool is funded, a participant may earn a cash award for the Performance Period based upon the level of attainment of the Budget Targets and his or her individual performance. Awards under both the Bonus Plan and the Amended Bonus Plan are paid in cash as soon as practicable after the end of the Performance Period but in no event later than two and one-half months after the end of the Performance Period.
For 2025, the short-term annual cash bonus pool targets for Messrs. Kim, Fails, Hand and Harkness were as follows: 150% for Mr. Kim, 125% for Mr. Fails, and 110% for Messrs. Hand and Harkness. The increase in targets for Mr. Kim from 130%; Mr. Fails 110% and Messrs. Hand and Harkness from 105% also reflected the consideration of the 2025 Meridian review. As noted above, Mr. Bramhall no longer receives a bonus allocation from Sunoco.
While the achi evement of the various budget targets sets a bonus pool under the Bonus Plan and the Amended Bonus Plan, actual bo nus awards are discretionary. These discretionary bonuses, if awarded, are intended to reward our named executive officers for the achievement of the budget targets during the performance period in light of the contribution of each individual to our profitability and success during such year. The Compensation Committee does not establish its own financial performance objectives in advance for purposes of determining whether to approve any annual bonuses, and it does not utilize any formulaic approach to determine annual bonuses.
In February 2026, the Compensation Committee certified Partnership results to achieve a bonus payout of the bonus pool. The actual results reflected the achievement of approximately 99.5% of the Adjusted EBITDA Target, 100.9% of the DCF Target and 91.6% of the Departmental Budget Target. The Compensation Committee based on achieved results approved a 100% of the achieved pool target. The cash bonuses approved for Messrs. Kim, Fails, Hand and Harkness were $1,400,000, $750,000, $515,000 and $515,000, respectively.
In approving the 2025 bonuses of the named executive officers, the Compensation Committee took into account the achievement by the Partnership of all of the targeted performance objectives for 2025 and the individual performances of each of the named executive officers. The cash bonuses awarded to each of the named executive officers for 2025 performance represented an increase over their applicable bonus pool targets in consideration of the significant work each provided in support of Sunoco’s transformative transactional activity in 2025.
Equity Awards. Each of the Sunoco LP 2012 Long-Term Incentive Plan (the “2012 LTIP”) and the Sunoco LP 2018 Long-Term Incentive Plan (the “2018 LTIP,” and together with the 2012 LTIP, the “LTIPs”) is designed to provide long-term incentive awards in order to promote achievement of our long-term strategic business objectives. The LTIPs are designed to align the economic interests of the named executive officers, key employees and directors with those of our unitholders and to provide an incentive to management for continuous employment with the General Partner and its affiliates. Each of our named executive officers is eligible to participate in the LTIPs. These awards are intended to align the interests of plan participants (including our NEOs) with those of our unitholders and to give plan participants the opportunity to share in our long-term performance.
In addition, in 2024, we adopted the Sunoco LP Long-Term Cash Restricted Unit Plan (the “CRU Plan”). The CRU Plan authorizes the Compensation Committee, in its discretion, to grant awards, as applicable, of CRSUs, upon such terms and conditions as it may determine appropriate and in accordance with general guidelines as defined by the CRU Plan. Like awards from the LTIP, awards from the CRU Plan will be used to incentivize and reward eligible employees over a long-term basis.
From time to time, the Compensation Committee may make grants under the plan to employees and/or directors containing such terms as the Compensation Committee shall determine under the LTIPs or the CRU Plan. The Compensation Committee determines the conditions upon which the restricted units granted may become vested or forfeited, and whether or not any such restricted units will have DERs entitling the grantee to receive an amount in cash equal to cash distributions made by us with respect to a like number of our common units during the restricted period.
For 2025, the annual long-term incentive targets set by the Compensation Committee for the named executive officers were 700% of annual base salary for Mr. Kim, 400% for Mr. Fails, and 300% for Messrs. Hand and Harkness. Mr. Bramhall’s 2025 Energy Transfer equity award was at a target of 600%. The increases of Mr. Kim from 500%; Mr. Fails from 350% and Messrs. Hand and Harkness from 250% also reflected the consideration of the 2025 Meridian review.
The annual long-term incentive targets are used as the basis to determine the target number of units to be awarded to the eligible participant, including the named executive officers. A multiple of base salary is used to set the pool target, that number is then divided by a weighted average price determined by considering Sunoco’s modified TUR performance as measured against the average return of Alerian MLP index (AMZ) over defined time periods. In previous years, the comparison was conducted against an independently
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identified peer group. The change to using the AMZ for the TUR analysis beginning for 2022 awards was a recognition of the challenge of matching Sunoco’s business with an adequate set of peer companies for performance evaluation. It was determined that the AMZ would provide the most adequate basis for analysis. Sunoco will continue to evaluate the best and most adequate tool to appropriately measure an appropriate modified TUR analysis and will make changes as appropriate in future years. The modified TUR is designed to create a recognition of performance adjustment based on the prior periods measured to an element of performance impact in setting grant date value even though the RSUs themselves are a time-vested vehicle. For purposes of establishing an initial price, we utilize a 60 trading-day trailing weighted average price of Sunoco common units prior t o November 1 of the respective year. This average trading price is then subject to adjustment when our TUR is more than 10% greater or less than that of companies within the AMZ. If the TUR analysis yields a result that is within 10% of the AMZ, the Compensation Committee will simply use the 60 trading day trailing weighted average price divided by the applicable salary multiple to establish a target pool for each eligible participant, including the named executive officers. If our TUR is outside of the 10% deviation, the 60 trading day trailing weighted average will be adjusted. For purposes of the adjustment to the trailing average, we will consider deviations from 10% to 30% up or down, which number will then be divided by two to establish a maximum of 15% either way from the trailing weighted average price based on Sunoco’s performance as compared to the AMZ.
For 2025, our TUR performed within 10% of the AMZ for the applicable measurement period. As such, the 60 day trailing weighted average price was used to establish the total available pool without adjustment.
In December 2025, the Compensation Committee granted RSU awards to Messrs. Kim, Fails, Hand, and Harkness 97,200 units, 35,000 units, 19,875 units and 19,875 units, respectively, under the LTIP. The Compensation Committee also approved grants of CRSUs to Messrs. Kim, Fails, Hand, and Harkness of 32,400 units, 11,700 units, 6,625 units and 6,625 units, respectively. In approving the grant of such RSUs, the Compensation Committee considered several factors, including the long-term objective of retaining such individuals as key drivers of the Partnership’s future success, the existing level of equity ownership of such individuals and the previous awards to such individuals of equity awards subject to vesting.
In December 2025, Mr. Bramhall received a grant of equity awards by the Energy Transfer Compensation Committee in connection with his service to Energy Transfer’s general partner, with such awards including 200,438 Energy Transfer restricted units and 66,812 Energy Transfer cash restricted units.
Vesting of the 2025 awards would accelerate in the event of the death or disability of the named executive officer or in the event of a change in control of the partnership as that term is defined under the LTIPs and the CRU Plan.
All of the RSUs granted, including to the named executive officers, provided for the vesting of 60% of the units at the end of the third year from the date of the grant and the vesting of the remaining 40% of the units at the end of the fifth year, subject to continued employment of the named executive officers through each specified vesting date. These RSUs entitle the grantee of the unit awards to receive, with respect to each Partnership common unit subject to such RSU that has not either vested or been forfeited, a DER cash payment promptly following each such distribution by us to our unitholders. In approving the grant of such unit awards, the Compensation Committee took into account a number of performance factors as well as the long-term objective of retaining such individuals as key drivers of the Partnership’s future success, the existing level of equity ownership of such individuals and the previous awards to such individuals of equity awards subject to vesting.
The CRSUs granted in 2025 provide for incremental vesting over a three-year period, with 1/3 vesting at the end of each year. Each CRSU entitles the award recipient to receive cash equal to the market value of one Sunoco LP common unit upon vesting. The CRSUs do not include rights to DER cash payments.
As discussed below under “Potential Payments Upon a Termination or Change of Control,” all outstanding equity awards would automatically accelerate upon a change in control event, which means vesting automatically accelerates upon a change of control irrespective of whether the officer is terminated. In addition, the award agreements also include certain acceleration provisions upon retirement with the ability to accelerate 40% of outstanding unvested awards at age 65 and 50% at age 68. These acceleration provisions require that the participant have not less than five (5) years of employment service to the Partnership or an affiliate and are subject to the applicable provisions of IRC Section 409(A), which may include a six (6) month delay in the vesting after retirement. The retirement provision also requires that the award be held for at least one year after the grant date in order to be eligible for acceleration.
The issuance of common units pursuant to our equity incentive plans is intended to serve as a means of incentive compensation; therefore, no consideration will be payable by the plan participants upon vesting and issuance of the common units.
We believe that permitting the accelerated vesting of equity awards upon a change in control creates an important retention tool for us by enabling employees to realize value from these awards in the event that we undergo a change in control transaction. The actual value to be realized upon any acceleration is discussed below under “Potential Payments Upon a Termination or Change of Control.”
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Executive Compensation Clawback Policy. In November 2023, the Compensation Committee adopted the Sunoco LP Executive Officer Incentive Compensation Clawback Policy (the “Clawback Policy”), which requires the Partnership to recover erroneously awarded incentive-based compensation from executive officers in the event the Partnership is required to prepare an accounting restatement. The Clawback Policy applies to any individual who is currently or was previously designated as an “officer” of the Partnership as defined in Rule 16a-1(f) under the Securities Exchange Act of 1934, including all of our current NEOs. The Clawback Policy is designed to comply with the requirements of the SEC and the NYSE Listed Company Manual, including (i) the definition of an accounting restatement, (ii) the applicable types of incentive-based compensation, (iii) the relevant recovery period, and (iv) the approach for calculating the recovery amount.
Benefit Plans. Our NEOs are provided compensation in the form of other benefits, including medical, life, dental, and disability insurance in line with competitive market conditions in retail non-store plans sponsored by Sunoco GP LLC. Our NEOs receive the same benefits and are responsible to pay the same premiums, deductibles and out of pocket maximums as other employees participating in these plans.
Sunoco GP LLC 401(k) Plan. Effective December 31, 2018, our previous 401(k) benefit plan, the Sunoco GP LLC 401(k), was merged into the Energy Transfer LP 401(k) Plan (the “ET 401(k) Plan”). The ET 401(k) Plan is a defined contribution 401(k) plan, which covers substantially all of our employees, including the named executive officers. Employees may elect to defer up to 100% of their eligible compensation after applicable taxes, as limited under the Internal Revenue Code. We make a matching contribution that is not less than the aggregate amount of matching contributions that would be credited to a participant’s account based on a rate of match equal to 100% of each participant’s elective deferrals up to 5% of covered compensation. The amounts deferred by the participant are fully vested at all times, and the amounts contributed by the Partnership become vested based on years of service. We provide this benefit as a means to incentivize employees and provide them with an opportunity to save for their retirement.
The Partnership provides a 3% profit sharing contribution to employee 401(k) accounts for all employees with a base compensation below a specified threshold. The contribution is in addition to the 401(k) matching contribution and employees become vested based on years of service.
Sunoco GP LLC Severance Plan. In addition, Sunoco GP LLC has also adopted the Sunoco Severance Plan, which provides for payment of certain severance benefits in the event of Qualifying Termination (as that term is defined in the Sunoco Severance Plan). In general, the Severance Plan provides payment of one (1) week of annual base salary for each year or partial year of employment service, up to a maximum of fifty-two weeks or one year of annual base salary (with a minimum of eight weeks of annual base salary) and up to three months of continued group health insurance coverage. The Sunoco Severance Plan also provides that additional benefits in addition to those provided under the Severance Plan may be paid based on special circumstances, which additional benefits shall be unique and non-precedent setting. The Severance Plan is available to all salaried employees on a nondiscriminatory basis; therefore, amounts that would be payable to the named executive officers upon a Qualified Termination have been excluded from “Compensation Tables - Potential Payments Upon a Termination or Change of Control” below.
The benefit levels are summarized below:

Employee Level |  | Minimum Severance Pay |  | Maximum Severance Pay
Senior Manager or below |  | 8 weeks of Base Pay |  | 26 weeks of Base Pay
Director or Senior Director |  | 16 weeks of Base Pay |  | 39 weeks of Base Pay
Vice President and above |  | 26 weeks of Base Pay |  | 52 weeks of Base Pay

Other Energy Transfer Sponsored Benefit Plans. Our NEOs participate in certain retirement and deferred compensation plans sponsored by Energy Transfer or its affiliates as described below. The Partnership is not allocated any compensation expense nor does it make any contributions to the plans sponsored by Energy Transfer or its affiliates.
Energy Transfer Non-Qualified Deferred Compensation Plan (the “ET NQDC Plan”) is a deferred compensation plan, which permits eligible highly compensated employees to defer a portion of their salary, bonus and/or quarterly non-vested restricted unit and/or restricted phantom unit distribution equivalent income until retirement, termination of employment or other designated distribution event. Energy Transfer may make annual discretionary matching contributions to participants’ accounts; however, Energy Transfer has not made any discretionary contributions to participants’ accounts and currently has no plans to make any discretionary contributions to participants’ accounts.
Risk Assessment Related to Our Compensation Structure
We believe our compensation plans and programs for our named executive officers, as well as the other employees who provide services to us, are appropriately structured and are not reasonably likely to result in material risk to us. We believe our compensation plans and programs are structured in a manner that does not promote excessive risk-taking that could harm our value or reward poor judgment. We also believe we have allocated our compensation among base salary and short and long-term compensation in such a
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way as to not encourage excessive risk-taking. We use restricted units and/or restricted phantom units rather than unit options for equity awards because restricted units and/or restricted phantom units retain value even in a depressed market so that employees are less likely to take unreasonable risks to get, or keep, options “in-the-money.” Finally, the time-based vesting over five years for our long-term incentive awards ensures that our employees’ interests align with those of our unitholders for our long-term performance.
Accounting and Tax Considerations
We account for the equity compensation expense for equity awards granted under our LTIP in accordance with U.S. generally accepted accounting principles (“GAAP”), which requires us to estimate and record an expense for each equity award over the vesting period of the award. For restricted units and/or restricted phantom units that are paid out in the form of common units, the value of our common units on the date of grant is used for determining the expense. The expense for restricted units and/or restricted phantom units settled in common units is recognized ratably over the vesting period. For cash compensation, the accounting rules require us to record it as an expense at the time the obligation is accrued. Because we are a partnership, and our General Partner is a limited liability company, Internal Revenue Code (“Code”) Section 162(m) does not apply to the compensation paid to our NEOs and, accordingly, our Compensation Committee did not consider its impact in making the compensation recommendations discussed above.
Compensation Committee Interlocks and Insider Participation
Messrs. Alvarez and Smith were the only members of the Compensation Committee during 2025. During 2025, neither of Messrs. Alvarez nor Mr. Smith was an officer or employee of affiliates of Energy Transfer or served as an officer of any company with respect to which any of our executive officers served on such company’s board of directors. In addition, neither of the current Compensation Committee members is a former employee of affiliates of Energy Transfer.
Compensation Committee Report
The Compensation Committee of the board of directors of our General Partner has reviewed and discussed the section of this report entitled “Compensation Discussion and Analysis” with the management of the Partnership and approved its inclusion on this annual report on Form 10-K.
Compensation Committee
Oscar A. Alvarez (Chairman)
W. Brett Smith
The foregoing report shall not be deemed to be incorporated by reference by any general statement or reference to this Annual Report on Form 10-K into any filing under the Securities Act, as amended, or the Exchange Act, as amended, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under those Acts.
Summary Compensation Table

Name and Principal Position | Year |  | Salary ($) (1) |  |  |  | Unit Awards ($) (2) |  | Non-Equity Incentive Plan Compensation ($) (3) |  | Change in Nonqualified Deferred Compensation Earnings ($) |  | All Other Compensation ($) (4) |  | Total ($)
Joseph Kim | 2025 |  | $ | 892,139 |  |  |  |  | $ | 9,953,128 |  |  | $ | 1,400,000 |  |  | $ | 55,633 |  |  | $ | 17,009 |  |  | $ | 12,317,909 |
President and Chief Executive Officer | 2024 |  | 800,962 |  |  |  |  | 4,145,250 |  |  | 1,291,150 |  |  | 44,221 |  |  | 16,817 |  |  | 6,298,400 |
2023 |  | 649,500 |  |  |  |  | 3,759,700 |  |  | 1,015,000 |  |  | 44,275 |  |  | 16,832 |  |  | 5,485,307 |
Dylan A. Bramhall (5) | 2025 |  | — |  |  |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Chief Financial Officer | 2024 |  | — |  |  |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
2023 |  | — |  |  |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Karl R. Fails | 2025 |  | 553,019 |  |  |  |  | 3,996,824 |  |  | 750,000 |  |  | 239,234 |  |  | 21,432 |  |  | 5,560,509 |
Executive Vice President, Chief Operating Officer | 2024 |  | 492,787 |  |  |  |  | 1,823,910 |  |  | 675,000 |  |  | 245,334 |  |  | 21,111 |  |  | 3,258,142 |
2023 |  | 401,187 |  |  |  |  | 1,611,300 |  |  | 530,000 |  |  | 240,541 |  |  | 19,494 |  |  | 2,802,522 |
Brian A. Hand | 2025 |  | 424,432 |  |  |  |  | 1,442,395 |  |  | 515,000 |  |  | 31,935 |  |  | 19,950 |  |  | 2,433,712 |
Executive Vice President, Chief Sales Officer | 2024 |  | 394,915 |  |  |  |  | 1,105,400 |  |  | 515,000 |  |  | 152,697 |  |  | 19,224 |  |  | 2,187,236 |
2023 |  | 359,629 |  |  |  |  | 1,101,055 |  |  | 454,000 |  |  | 136,917 |  |  | 18,836 |  |  | 2,070,437 |
Austin B. Harkness | 2025 |  | 419,232 |  |  |  |  | 1,442,395 |  |  | 515,000 |  |  | — |  |  | 18,542 |  |  | 2,395,169 |
Executive Vice President, Chief Commercial Officer | 2024 |  | 381,831 |  |  |  |  | 1,105,400 |  |  | 515,000 |  |  | — |  |  | 18,189 |  |  | 2,020,420 |
2023 |  | 327,500 |  |  |  |  | 1,101,055 |  |  | 413,000 |  |  | — |  |  | 16,905 |  |  | 1,858,460 |

____________________________________________
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(1)In accordance with the terms of our Partnership Agreement, we reimburse our General Partner and its affiliates for compensation related expenses attributable to the portion of the named executive officer’s time dedicated to providing services to us. For the periods presented, amounts reported herein reflect 100% of the base salary associated with the NEO’s services, except for Mr. Bramhall’s base salary which is allocated at 100% to Energy Transfer, as discussed above. Cash compensation expenses for each NEO were allocated on the basis of total cash compensation earned by the NEO during the period.
(2)The amounts reported for unit awards represent the full grant date fair value of RSUs and CRSUs granted to each of our NEOs, computed in accordance with FASB ASC Topic 718, disregarding any estimates for forfeitures. For Mr. Bramhall, the amounts reported above exclude grants of Energy Transfer plan-based awards.
(3)Sunoco LP maintains the Amended Bonus Plan which provides for discretionary bonuses. Awards of discretionary bonuses are tied to achievement of targeted performance objectives and described in the Compensation Discussion and Analysis. In respect of Mr. Bramhall, 100% of his bonuses for the periods presented were awarded under the Energy Transfer bonus plan and are 100% attributable to Energy Transfer.
(4)The amounts reflected for 2025 in this column include (i) 401(k) Plan matching contributions made on behalf of the named executive officers of $13,077 for Mr. Kim, $17,500 for Mr. Fails, $14,921 for Mr. Hand, and $17,500 for Mr. Harkness, (ii) health savings account contributions made on behalf of the named executive officers of $2,000 each for Messrs. Kim, Fails and Hand, and (iii) the dollar value of life insurance premiums paid for the benefit of the named executive officers of $1,932 for Mr. Kim, $1,932 for Mr. Fails, $3,029 for Mr. Hand and $1,042 for Mr. Harkness.
(5)Mr. Bramhall’s compensation is reported in detail in Item 11 of the Energy Transfer LP Annual Report on Form 10-K. All compensation decisions impacting Mr. Bramhall are made by the Compensation Committee of LE GP LLC, the general partner of Energy Transfer LP. As noted in the compensation discussion and analysis above, other than the $122,123 in DERs paid on his unvested Sunoco LP restricted units the remainder of his 2025 compensation was fully attributable to Energy Transfer LP.
The amounts reflected for all periods exclude distribution payments in connection with DERs on unvested unit awards, because the dollar value of such distributions are factored into the grant date fair value reported in the “Unit Awards” column of the Summary Compensation Table at the time that the unit awards and DERs were originally granted. For 2025, distribution payments in connection with DERs totaled $1,098,462 for Mr. Kim, $122,123 for Mr. Bramhall (excluding distributions related to Energy Transfer unit awards), $475,181 for Mr. Fails, $266,105 for Mr. Hand, and $273,873 for Mr. Harkness.
Grants of Plan-Based Awards in 2025
The following table reflects awards granted to our NEOs under the LTIP during 2025.

Name |  | Grant Date |  | Type of Award (1) |  | All Other Unit Awards: Number of Units (#) (1) |  | Grant Date Fair Value of Unit Awards ($) (1)
Sunoco LP Unit Awards: |  |  |  |  |  |  |  |
Joseph Kim |  | 12/5/2025 |  | Restricted units |  | 97,200 |  |  | $ | 5,290,596 |
|  | 2/18/2025 |  | Restricted units |  | 50,000 |  |  | 2,899,000 |
Karl R. Fails |  | 12/5/2025 |  | Restricted units |  | 35,100 |  |  | 1,910,493 |
|  | 2/18/2025 |  | Restricted units |  | 25,000 |  |  | 1,449,500 |
Brian A. Hand |  | 12/5/2025 |  | Restricted units |  | 19,875 |  |  | 1,081,796 |
Austin B. Harkness |  | 12/5/2025 |  | Restricted units |  | 19,875 |  |  | 1,081,796 |
Sunoco LP Cash Restricted Unit Awards: |  |  |  |  |  |  |  |
Joseph Kim |  | 12/5/2025 |  | Cash restricted units |  | 32,400 |  |  | $ | 1,763,532 |
Karl R. Fails |  | 12/5/2025 |  | Cash restricted units |  | 11,700 |  |  | 636,831 |
Brian A. Hand |  | 12/5/2025 |  | Cash restricted units |  | 6,625 |  |  | 360,599 |
Austin B. Harkness |  | 12/5/2025 |  | Cash restricted units |  | 6,625 |  |  | 360,599 |

____________________________________________
(1)The reported grant date fair value of unit awards was determined in compliance with FASB ASC Topic 718 and are more fully described in Note 19 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.” For Mr. Bramhall, the amounts reported above include only his grants of Sunoco LP restricted units and exclude grants of Energy Transfer plan-based awards.
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Outstanding Equity Awards at December 31, 2025
The following table reflects NEO equity awards granted under the LTIP Plan that were outstanding at December 31, 2025.

|  |  |  | Unit Awards (1)
Name |  | Grant Date (1) |  | Number of Units That Have Not Vested (#) |  | Market Value of Units That Have Not Vested ($) (2) |  |  |  |
Sunoco LP Unit Awards: |  |  |  |  |  |  |  |  |  |
Joseph Kim |  | 12/5/2025 |  | 97,200 |  |  | $ | 5,094,252 |  |  |  |  |
|  | 2/18/2025 |  | 50,000 |  |  | 2,620,500 |  |  |  |  |
|  | 12/5/2024 |  | 56,250 |  |  | 2,948,063 |  |  |  |  |
|  | 12/8/2023 |  | 70,000 |  |  | 3,668,700 |  |  |  |  |
|  | 12/12/2022 |  | 30,920 |  |  | 1,620,517 |  |  |  |  |
|  | 12/16/2021 |  | 23,200 |  |  | 1,215,912 |  |  |  |  |
Dylan A. Bramhall (3) |  | 12/12/2022 |  | 5,680 |  |  | 297,689 |  |  |  |  |
|  | 12/16/2021 |  | 5,200 |  |  | 272,532 |  |  |  |  |
Karl R. Fails |  | 12/5/2025 |  | 35,100 |  |  | 1,839,591 |  |  |  |  |
|  | 2/18/2025 |  | 25,000 |  |  | 1,310,250 |  |  |  |  |
|  | 12/5/2024 |  | 24,750 |  |  | 1,297,148 |  |  |  |  |
|  | 12/8/2023 |  | 30,000 |  |  | 1,572,300 |  |  |  |  |
|  | 12/12/2022 |  | 10,600 |  |  | 555,546 |  |  |  |  |
|  | 12/16/2021 |  | 10,200 |  |  | 534,582 |  |  |  |  |
Brian A. Hand |  | 12/5/2025 |  | 19,875 |  |  | 1,041,649 |  |  |  |  |
|  | 12/5/2024 |  | 15,000 |  |  | 786,150 |  |  |  |  |
|  | 12/8/2023 |  | 20,500 |  |  | 1,074,405 |  |  |  |  |
|  | 12/12/2022 |  | 7,500 |  |  | 393,075 |  |  |  |  |
|  | 12/16/2021 |  | 7,400 |  |  | 387,834 |  |  |  |  |
Austin B. Harkness |  | 12/5/2025 |  | 19,875 |  |  | 1,041,649 |  |  |  |  |
|  | 12/5/2024 |  | 15,000 |  |  | 786,150 |  |  |  |  |
|  | 12/8/2023 |  | 20,500 |  |  | 1,074,405 |  |  |  |  |
|  | 12/12/2022 |  | 6,600 |  |  | 345,906 |  |  |  |  |
|  | 9/24/2022 |  | 4,000 |  |  | 209,640 |  |  |  |  |
|  | 12/16/2021 |  | 5,800 |  |  | 303,978 |  |  |  |  |
Sunoco LP Cash Restricted Unit Awards: |  |  |  |  |  |  |  |  |  |
Joseph Kim |  | 12/5/2025 |  | 32,400 |  |  | $ | 1,698,084 |  |  |  |  |
|  | 12/5/2024 |  | 12,500 |  |  | 655,125 |  |  |  |  |
Karl R. Fails |  | 12/5/2025 |  | 11,700 |  |  | 613,197 |  |  |  |  |
|  | 12/5/2024 |  | 5,500 |  |  | 288,255 |  |  |  |  |
Brian A. Hand |  | 12/5/2025 |  | 6,625 |  |  | 347,216 |  |  |  |  |
|  | 12/5/2024 |  | 3,334 |  |  | 174,735 |  |  |  |  |
Austin B. Harkness |  | 12/5/2025 |  | 6,625 |  |  | 347,216 |  |  |  |  |
|  | 12/5/2024 |  | 3,334 |  |  | 174,735 |  |  |  |  |

____________________________________________
(1)RSUs outstanding vest as follows:
•at a rate of 60% in December 2028 and 40% in December 2030 for awards granted in December 2025 and February 2025;
•at a rate of 60% in December 2027 and 40% in December 2029 for awards granted in December 2024;
•at a rate of 60% in December 2026 and 40% in December 2028 for awards granted in December 2023;
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•100% in December 2027 the remaining outstanding portion of awards granted in September and December 2022; and
•100% in December 2026 the remaining outstanding portion of awards granted in December 2021.
Such awards may be settled at the election of the Compensation Committee in (i) common units of Sunoco LP; (ii) cash equal to the Fair Market Value (as such term is defined in the LTIPs) of Sunoco LP common units that would otherwise be delivered pursuant to the terms of each named executive officers grant agreement; or (iii) other securities or property in an amount equal to Fair Market Value of Sunoco LP common units that would otherwise be delivered pursuant to the terms of the grant agreement, or a combination thereof as determined by the Compensation Committee in its discretion.
•CRSU awards granted in December 2025 vest 1/3 per year in December 2026, 2027 and 2028. The remaining outstanding portion of CRSUs granted in December 2024 vest 1/2 per year in December 2026 and 2027.
(2)Based on the closing market price of our common units of $52.41 on December 31, 2025.
(3)For Mr. Bramhall, the amounts reported above include only his outstanding grants of Sunoco LP restricted units and exclude grants of Energy Transfer plan-based awards.
Units Vested in 2025
The following table provides information regarding the vesting of Sunoco restricted units held by certain of our NEOs during 2025. There are no options outstanding on our common units.

|  | Unit Awards |
Name |  | Number of Units Acquired on Vesting (#) |  | Value Realized on Vesting ($) (1) |
Sunoco LP Unit Awards: |  |  |  |  |
Joseph Kim |  | 85,920 |  |  | $ | 4,676,626 |  |
Dylan A. Bramhall |  | 22,920 |  |  | 1,247,536 |  |
Karl R. Fails |  | 37,100 |  |  | 2,019,353 |  |
Brian A. Hand |  | 23,250 |  |  | 1,265,498 |  |
Austin B. Harkness |  | 23,900 |  |  | 1,300,877 |  |
Sunoco LP Cash Restricted Unit Awards: |  |  |  |  |
Joseph Kim |  | 6,250 |  |  | 340,188 |  |
Karl R. Fails |  | 2,750 |  |  | 149,683 |  |
Brian A. Hand |  | 1,666 |  |  | 90,680 |  |
Austin B. Harkness |  | 1,666 |  |  | 90,680 |  |

____________________________________________
(1)Amounts presented represent the number of unit awards vested during 2025 and the value realized upon vesting of these awards, which is calculated as the number of units vested multiplied by the closing price of Sunoco LP’s common units upon the vesting date.
Non-Qualified Deferred Compensation
The Energy Transfer NQDC Plan is a deferred compensation plan which permits eligible highly compensated employees to defer a portion of their salary, bonus, and/or quarterly non-vested phantom unit distribution equivalent income until retirement, termination of employment or other designated distribution event. Each year under the Energy Transfer NQDC Plan, eligible employees are permitted to make an irrevocable election to defer up to 50% of their annual base salary, 50% of their quarterly non-vested phantom unit distribution income, and/or 50% of their discretionary performance bonus compensation during the following year. Pursuant to the Energy Transfer NQDC Plan, Energy Transfer may make annual discretionary matching contributions to participants’ accounts; however, Energy Transfer has not made any discretionary contributions to participants’ accounts and currently has no plans to make any discretionary contributions to participants’ accounts. All amounts credited under the Energy Transfer NQDC Plan (other than discretionary credits) are immediately 100% vested. Participant accounts are credited with deemed earnings or losses based on hypothetical investment fund choices made by the participants among available funds.
Participants may elect to have their account balances distributed in one lump sum payment or in annual installments over a period of three or five years upon retirement, and in a lump sum upon other termination events. Participants may also elect to take lump sum in-service withdrawals five years or longer in the future, and such scheduled in-service withdrawals may be further deferred prior to the
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withdrawal date. Upon a change in control (as defined in the Energy Transfer NQDC Plan) of Energy Transfer, all Energy Transfer NQDC Plan accounts are immediately vested in full. However, distributions are not accelerated and, instead, are made in accordance with the Energy Transfer NQDC Plan’s normal distribution provisions unless a participant has elected to receive a change of control distribution pursuant to his deferral agreement.
The following table provides the voluntary salary deferrals made by the named executive officers in 2025 under the Energy Transfer NQDC Plan and Sunoco Executive DC Plan.

Name |  | Executive Contributions in Last FY ($) |  | Registrant Contributions in Last FY ($) |  | Aggregate Earnings in Last FY ($) (1) |  | Aggregate Withdrawals/Distributions ($) |  | Aggregate Balance at Last FYE ($)
Joseph Kim |  | $ | — |  |  | $ | — |  |  | $ | 55,633 |  |  | $ | — |  |  | $ | 467,143 |
Karl R. Fails |  | — |  |  | — |  |  | 239,234 |  |  | — |  |  | 1,825,989 |
Brian A. Hand |  | 177,376 |  |  | — |  |  | 31,935 |  |  | — |  |  | 1,247,127 |

(1) Amounts included in the aggregate earnings column above have been included in the change in non-qualified deferred compensation earnings column of the summary compensation table.
Potential Payments upon Termination or Change of Control
Pursuant to the terms of the award agreements issued under the LTIPs and/or the CRU Plan, in the event of a (i) Change of Control (as defined in the LTIPs and/or the CRU Plan, summarized below) or (ii) termination of employment due to death or disability, all RSUs and CRSUs shall vest. In the event of a termination of employment for any other reason, all RSUs and CRSUs that are still unvested shall be forfeited. The RSUs and CRSUs that would vest in the event of Change of Control are those awards described for each NEO in the table entitled “Outstanding Equity Awards at December 31, 2025.”
In addition, the Compensation Committee has approved a retirement provision, which provides that employees, including the named executive officers with at least five years of service with the general partner, who leave the respective general partner voluntarily due to retirement (i) after age 65 but prior to age 68 are eligible for accelerated vesting of 40% of his or her award; or (ii) after 68 are eligible for accelerated vesting of 50% of his or her award. The acceleration of the awards is subject to the applicable provisions of IRC Section 409A. The retirement provision also requires that the award be held for at least one year after the grant date in order to be eligible for acceleration.
Under the LTIPs, a “Change of Control” means, and shall be deemed to have occurred upon one or more of the following events: (i) any “person” or “group” within the meaning of those terms as used in Sections 13(d) and 14(d)(2) of the Exchange Act, other than members of the General Partner, the Partnership, or an affiliate of either the General Partner or the Partnership, shall become the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of the voting power of the voting securities of the General Partner or the Partnership; (ii) the limited partners of the General Partner or the Partnership approve, in one transaction or a series of transactions, a plan of complete liquidation of the General Partner or the Partnership; (iii) the sale or other disposition by either the General Partner or the Partnership of all or substantially all of its assets in one or more transactions to any Person other than an affiliate; (iv) the General Partner or an affiliate of the General Partner or the Partnership ceases to be the General Partner of the Partnership; (v) any other event specified as a “Change of Control” in the equity incentive plan maintained by the Partnership at the time of such “Change of Control;” or (vi) any other event specified as a “Change of Control” in an applicable award agreement. Notwithstanding the above, with respect to a 409A award, a “Change of Control” shall not occur unless that Change of Control also constitutes a “change in the ownership of a corporation,” a “change in the effective control of a corporation,” or a “change in the ownership of a substantial portion of a corporation’s assets,” in each case, within the meaning of 1.409A-3(i)(5) of the 409A regulations, as applied to non-corporate entities.
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The following table shows the amount of incremental value that would have been received by each of the NEOs upon certain events of termination or a change of control resulting in the accelerated vesting of the restricted units and/or restricted phantom units held by our NEOs on December 31, 2025:

Name |  | Benefit |  | Termination Due to Death or Disability ($) (1) |  | Termination for any other reason ($) (2) |  | Change of Control with or without Continued Employment ($) (1) |  | Not for Cause Termination ($) (2)
Joseph Kim |  | Unit Vesting |  | $ | 19,521,153 |  |  | $ | — |  |  | $ | 19,521,153 |  |  | $ | 475,000 |
Dylan A. Bramhall (3) |  | Unit Vesting |  | 570,221 |  |  | — |  |  | 570,221 |  |  | — |
Karl R. Fails |  | Unit Vesting |  | 8,010,869 |  |  | — |  |  | 8,010,869 |  |  | 369,231 |
Brian A. Hand |  | Unit Vesting |  | 4,205,064 |  |  | — |  |  | 4,205,064 |  |  | 276,923 |
Austin B. Harkness |  | Unit Vesting |  | 4,283,679 |  |  | — |  |  | 4,283,679 |  |  | 225,000 |

____________________________________________
(1)The amounts reflected above represent the product of the number of RSUs units that were subject to vesting/restrictions on December 31, 2025 multiplied by the closing price of applicable common units on that date.
(2)These amounts represent potential severance benefits under the Sunoco Severance Plan in the event of Qualifying Termination (as that term is defined in the Sunoco Severance Plan).
(3)For Mr. Bramhall, the amounts reported above include only his outstanding grants of Sunoco LP restricted units and exclude grants of Energy Transfer plan-based awards.
CEO Pay Ratio
In accordance with Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, set forth below is information about the relationship of the annual total compensation of Mr. Kim, our President and Chief Executive Officer, and the annual total compensation of our employees.
For the 2025 calendar year:
•The annual total compensation of Mr. Kim, as reported in the Summary Compensation Tables of this Item 11 was $12,317,909; and
•The median total compensation of the employees supporting our Partnership (other than Mr. Kim) was $127,589 for 2025, which “median employee” will be used for the 2025 analysis.
Based on this information, for 2025 the ratio of the annual total compensation of Mr. Kim to the median of the annual total compensation was approximately 97 to 1.
To identify the median of the annual total compensation of the employees supporting the Partnership, the following steps were taken:
1.It was determined that, as of December 31, 2025, the applicable employee populations consisted of 3,193 with all of the identified individuals being employed in the United States. This population consisted of all of our full-time and part-time employees. We did not engage any independent contractors in 2025 that are required to be included in our employee population for the CEO pay ratio evaluation.
2.To identify the “median employee” from our employee population, we compared the total earnings of our employees as reflected in our payroll records as reported on Form W-2 for 2025.
3.We identified our median employee using W-2 reporting and applied this compensation measure consistently to all of our employees required to be included in the calculation. We did not make any cost of living adjustments in identifying the “median employee.”
4.Once we identified our median employee, we combined all elements of the employee’s compensation for 2025 resulting in an annual compensation of $127,589, with cash compensation of $104,206. The difference between such employee’s total earnings and the employee’s total compensation represents the estimated value of the employee’s health care benefits (estimated for the employee and such employee’s eligible dependents at $16,308 and the employee’s 401(k) matching contribution and profit sharing contribution, as applicable estimated at $7,075 per employee).
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5.With respect to Mr. Kim, we used the amount reported in the “Total” column of our 2025 Summary Compensation Table under this Item 11.
Compensation of Directors
Our Board periodically reviews and determines the amounts payable to the members of our Board. For 2025, the directors of the General Partner who were not employees of the General Partner or its affiliates received, as applicable: an annual cash retainer of $100,000; an annual cash retainer of $15,000 ($25,000 for the chair) for serving on our audit committee; an annual cash retainer of $7,500 ($15,000 for the chair) for serving on our Compensation Committee; and a cash fee for the engagement of the special committee of the Board (the “Special Committee”), as determined by the Board at the time of such engagement. Such directors also received an annual grant of RSUs under the LTIP equal to an aggregate of $125,000 based on the same grant date valuation as is used for annual long-term incentive awards made to Partnership officers, including the named executive officers, through the annual modified total unitholder return analysis. Directors appointed during the year, or who cease to be directors during a year, receive a pro-rated portion of any cash retainers. In addition, each non-employee director who is appointed to the Board for the first time is entitled to receive 2,500 unvested Sunoco common units. Unit awards granted to non-employee directors will vest 60% after the third year and the remaining 40% after the fifth year after the grant date.
Under the LTIP, the director will forfeit all unvested RSUs upon a termination of his duties as a director for any reason. If the director ceases providing services due to death or disability (as defined by the LTIP) prior to the date all RSUs units have vested, then all restrictions lapse and all RSUs become immediately vested. If a Change of Control (as defined under the LTIP) occurs, then all unvested RSUs become fully vested as of the date of the Change of Control. In addition, our directors will be reimbursed for out-of-pocket expenses incurred in connection with attending meetings of the Board or its committees.
The following table provides a summary of compensation paid to each of our current and former non-employee directors with respect to 2025:

Name |  | Fees Earned or Paid in Cash ($) (1) |  | Unit Awards ($) (2) |  |  |  |  |  | Total ($)
Oscar A. Alvarez |  | 130,000 |  |  | 125,000 |  |  |  |  |  |  | 255,000 |
Bradley C. Barron |  | 100,000 |  |  | 125,000 |  |  |  |  |  |  | 225,000 |
David K. Skidmore |  | 125,000 |  |  | 125,000 |  |  |  |  |  |  | 250,000 |
W. Brett Smith |  | 176,250 |  |  | 125,000 |  |  |  |  |  |  | 301,250 |
Ray W. Washburne |  | 100,000 |  |  | 125,000 |  |  |  |  |  |  | 225,000 |

(1)The amounts in this column reflect the aggregate dollar amount of fees earned or paid in cash including the annual retainer fee. The amounts reflected exclude distribution payments in connection with DERs on unvested unit awards, because the dollar value of such distributions are factored into the grant date fair value reported in the “Unit Awards” column above at the time that the unit awards and DERs were originally granted. For 2025, distribution payments in connection with DERs totaled $37,041 for Mr. Alvarez, $7,963 for Mr. Barron, $35,600 for Mr. Skidmore, $7,963 for Mr. Smith, and $33,410 for Mr. Washburne.
(2)The amounts reported for unit awards represent the full grant date fair value of the awards granted in 2025, calculated in accordance with FASB ASC Topic 718, disregarding any estimate for forfeiture. These amounts do not correspond to the actual value that may be recognized by the recipient upon any disposition of vested units and do not give effect to any decline or increase in the trading price of our common units since the date of grant. For a discussion of the assumptions and methodologies used in calculating the grant date fair value of the unit awards reported above, see Note 19 in our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
As discussed above, the number of units awarded is based on the annual award amount of $125,000 divided by the same grant-date valuation as is used for annual long-term incentive award to Partnership officers through the modified total unitholders return analysis.
Current year amounts reflect annual awards granted on January 2, 2026.
Mr. Christopher R. Curia did not receive compensation from Sunoco in 2025 and retired as an executive of Energy Transfer and member of the board in May 2025.
As of December 31, 2025, Mr. Alvarez had 10,252 outstanding RSUs, Mr. Barron had 2,204 outstanding RSUs, Mr. Skidmore had 9,853 outstanding RSUs, Mr. Smith had 2,204 outstanding RSUs and Mr. Washburne had 8,879 outstanding RSUs.
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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth the beneficial ownership of common units and Class D Units of the Partnership that are issued and outstanding as of February 13, 2026 and held by:
•each person or group of persons known by us to be beneficial owners of 5% or more of our common or Class D Units;
•each director, director nominee and named executive officer of our General Partner; and
•all of our directors and executive officers of our General Partner, as a group.

Name of Beneficial Owner (1) |  | Common Units Beneficially Owned (5) |  | Percentage of Common Units Beneficially Owned |  | Class D Units Beneficially Owned |  | Percentage of Class D Units Beneficially Owned |  | Percentage of Common and Class D Units Beneficially Owned
Energy Transfer (2) |  | 28,463,967 |  |  | 20.8% |  | — |  |  | * |  | 15.1%
SunocoCorp |  | — |  |  | * |  | 51,517,198 |  |  | 100.0% |  | 27.3%
Invesco Ltd. (3) |  | 8,846,679 |  |  | 6.5% |  | — |  |  | * |  | 4.7%
ALPS Advisors, Inc. (4) |  | 24,856,265 |  |  | 18.2% |  | — |  |  | * |  | 13.2%
Joseph Kim (6) |  | 264,318 |  |  | * |  | — |  |  | * |  | *
Karl R. Fails |  | 155,402 |  |  | * |  | — |  |  | * |  | *
Brian A. Hand |  | 100,639 |  |  | * |  | — |  |  | * |  | *
Dylan A. Bramhall |  | 31,729 |  |  | * |  | — |  |  | * |  | *
Austin B. Harkness |  | 32,776 |  |  | * |  | — |  |  | * |  | *
Ray W. Washburne |  | 3,358 |  |  | * |  | — |  |  | * |  | *
Oscar A. Alvarez |  | 16,245 |  |  | * |  | — |  |  | * |  | *
Bradley C. Barron |  | 20,000 |  |  | * |  | — |  |  | * |  | *
David K. Skidmore |  | 8,817 |  |  | * |  | — |  |  | * |  | *
W. Brett Smith |  | 1,843 |  |  | * |  | — |  |  | * |  | *
All executive officers and directors as a group (ten persons) |  | 635,127 |  |  | * |  | — |  |  | * |  | *

____________________________________________
* Represents less than 1%.
(1)As of the date set forth above, there are no arrangements for any listed beneficial owner to acquire within 60 days common units from options, warrants, rights, conversion privileges or similar obligations. Unless otherwise indicated, the address for all beneficial owners in this table is 8111 Westchester Drive, Suite 400, Dallas, Texas 75225.
(2)The address for Energy Transfer and Energy Transfer’s subsidiaries is 8111 Westchester Drive, Suite 600, Dallas, Texas 75225.
(3)The information contained in the table and this footnote with respect to Invesco Ltd. is based solely on a filing on Schedule 13G filed with the SEC on February 12, 2026. The business address of the reporting party is 1331 Spring Street NW, Suite 2500, Atlanta, Georgia 30309.
(4)The information contained in the table and this footnote with respect to ALPS Advisors, Inc. is based solely on a filing on Schedule 13G filed with the SEC on January 6, 2026. The business address of the reporting party is 1290 Broadway, Suite 1000, Denver, Colorado 80203. ALPS Advisors, Inc. and Alerian MLP ETF, a fund controlled by ALPS, have shared voting and dispositive power as to the 24,856,265 common units.
(5)Does not include unvested phantom units that may not be voted or transferred prior to vesting. As of February 13, 2026, there were 136,894,754 common units deemed to be beneficially owned for purposes of the above table.
(6)Includes 10,000 common units Mr. Kim owns indirectly by the Kim Living Trust.
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The following table sets forth, as of February 13, 2026, the number of common units of SunocoCorp owned by each of the directors and named executive officers of our General Partner and all directors and current executive officers of our General Partner as a group.

|  |  |  | SunocoCorp Common Units Beneficially Owned†
Name of Beneficial Owner (1) |  |  |  |  |  | Number of Common Units (2) |  | Percentage of Total Common Units (3)
Joseph Kim |  |  |  |  |  | 6,000 |  |  | *
Karl R. Fails |  |  |  |  |  | — |  |  | *
Brian A. Hand |  |  |  |  |  | — |  |  | *
Dylan A. Bramhall |  |  |  |  |  | — |  |  | *
Austin B. Harkness |  |  |  |  |  | — |  |  | *
Ray W. Washburne |  |  |  |  |  | — |  |  | *
Oscar A. Alvarez |  |  |  |  |  | — |  |  | *
Bradley C. Barron |  |  |  |  |  | — |  |  | *
David K. Skidmore |  |  |  |  |  | — |  |  | *
W. Brett Smith |  |  |  |  |  | — |  |  | *
All executive officers and directors as a group (ten persons) |  |  |  |  |  | 6,000 |  |  | *

* Represents less than 1%.
† Officers and directors of our General Partner may be deemed to indirectly beneficially own certain limited partnership interests in us or SunocoCorp, by virtue of owning common units in SunocoCorp, or based upon their simultaneous service as officers or directors of SunocoCorp. Any such deemed ownership is not reflected in the table.
(1)Unless otherwise indicated, the address for all beneficial owners in this table is 8111 Westchester Drive, Suite 400, Dallas, Texas 75225.
(2)Beneficial ownership for the purposes of the above table is determined in accordance with the rules and regulation of the SEC. These rules generally provide that a person is the beneficial owner of securities if they have or share the power to vote or direct the voting thereof, or to dispose or direct the disposition thereof, or have the right to acquire such powers with sixty (60) days.
(3)As of February 13, 2026, there were 51,517,198 common units of SunocoCorp deemed to be beneficially owned for purposes of the above table.
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The following table sets forth, as of February 13, 2026, the number of common units of Energy Transfer owned by each of the directors and named executive officers of our General Partner and all directors and current executive officers of our General Partner as a group.

|  |  |  | Energy Transfer Common Units Beneficially Owned†
Name of Beneficial Owner (1) |  |  |  |  |  | Number of Common Units (2) |  | Percentage of Total Common Units (3)
Joseph Kim |  |  |  |  |  | 6,000 |  |  | *
Karl R. Fails |  |  |  |  |  | 13,161 |  |  | *
Brian A. Hand |  |  |  |  |  | — |  |  | *
Dylan A. Bramhall |  |  |  |  |  | 250,415 |  |  | *
Austin B. Harkness |  |  |  |  |  | — |  |  | *
Ray W. Washburne (4) |  |  |  |  |  | 993,184 |  |  | *
Oscar A. Alvarez |  |  |  |  |  | 3,665 |  |  | *
Bradley C. Barron |  |  |  |  |  | — |  |  | *
David K. Skidmore |  |  |  |  |  | 128,313 |  |  | *
W. Brett Smith |  |  |  |  |  | 34,937 |  |  | *
All executive officers and directors as a group (ten persons) |  |  |  |  |  | 1,429,675 |  |  | *

* Represents less than 1%.
† Officers and directors of our General Partner may be deemed to indirectly beneficially own certain limited partner interests in us or Energy Transfer, by virtue of owning common units in Energy Transfer, or based upon their simultaneous service as officers or directors of Energy Transfer. Any such deemed ownership is not reflected in the table.
(1)Unless otherwise indicated, the address for all beneficial owners in this table is 8111 Westchester Drive, Suite 400, Dallas, Texas 75225.
(2)Beneficial ownership for the purposes of the above table is determined in accordance with the rules and regulation of the SEC. These rules generally provide that a person is the beneficial owner of securities if they have or share the power to vote or direct the voting thereof, or to dispose or direct the disposition thereof, or have the right to acquire such powers with sixty (60) days.
(3)As of February 13, 2026, there were 3,440,314,575 common units of Energy Transfer deemed to be beneficially owned for purposes of the above table.
(4)Includes 14,426 common units held by Mr. Washburne’s wife and 845,430 common units held in various family trusts.
Equity Compensation Plan Information
As of December 31, 2025, a total of 3,713,477 phantom units had been issued under our 2018 long-term incentive plan. Total securities remaining available for issuance under our 2018 long-term incentive plans as of December 31, 2025 were as follows:
Common Units Remaining Available for Issuance under Our Equity Compensation Plans

Plan Category |  | Number of securities to be issued upon exercise of outstanding options, warrants and rights |  | Weighted average exercise price of outstanding options, warrants and rights |  | Number of securities remaining available for future issuance under equity compensation plans
Equity compensation plans approved by security holders |  | — |  |  | $ | — |  |  | — |
Equity compensation plans not approved by security holders |  | 1,108,053 |  |  | — |  |  | 7,489,913 |
Total |  | 1,108,053 |  |  | $ | — |  |  | 7,489,913 |

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Item 13. Certain Relationships and Related Transactions, and Director Independence
Transactions between our General Partner and Energy Transfer and its Affiliates
The following table summarizes the distributions and payments made by us to Energy Transfer or its affiliates during 2025.

Transaction | Explanation | Amount/Value
2025 quarterly distributions on limited partner interests and IDRs held by affiliates. | Represents the aggregate amount of distributions made to affiliates of our General Partner in respect of common units and IDRs during 2025. | $262 million
Fuel sold to affiliates. | Total revenues we received for fuel gallons sold by us to affiliates of our General Partner for 2025. | $24 million
Bulk purchases of motor fuel from Energy Transfer and its affiliates. | Represents payments made to Energy Transfer and its affiliates for bulk motor fuel purchases. | $1.2 billion
Reimbursement to our General Partner for certain allocated overhead and other expenses. | Total payment to our General Partner for reimbursement of overhead and other expenses, including employee compensation costs relating to employees supporting our operations for 2025. | $43 million

Delegation Agreement
On October 27, 2025, our General Partner entered into the Delegation Agreement with Energy Transfer and SunocoCorp, pursuant to which, among other things, Energy Transfer delegated all of its power and authority to elect, appoint and remove the members of the Sunoco GP LLC board to SunocoCorp. The rights delegated to SunocoCorp will terminate upon the earliest to occur of, (i) the commencement of certain involuntary insolvency proceedings involving SunocoCorp, (ii) SunocoCorp or its governing body voluntarily commencing certain insolvency or liquidation proceedings, seeking consent for the appointment of a receiver, trustee or similar official, or making a general assignment for the benefit of its creditors, or (iii) upon written notice at the election of Energy Transfer, if Energy Transfer has a good faith belief that any of the foregoing events is substantially likely to occur in the near future or SunocoCorp has become unable to or generally failed to pay its debts as they become due or has become insolvent (or have admitted in writing or publicly declared our intention with respect to the foregoing).
Under the Delegation Agreement, our General Partner also agreed that, for so long as any equity securities of SunocoCorp are listed on a national securities exchange or are not wholly-owned by Energy Transfer or its subsidiaries, our General Partner will not (i) propose or make any amendments to our limited partnership agreement that would adversely affect the rights delegated to SunocoCorp under the Delegation Agreement or (ii) withdraw as our General Partner or assign or transfer its general partnership interest in us.
Other Transactions with Related Persons
Omnibus Agreement
On October 31, 2025, we entered into an Omnibus Agreement with SunocoCorp, pursuant to which, among other things, during the term of the agreement, (i) we will indemnify SunocoCorp, the SunocoCorp Management LLC, the managing member of SunocoCorp, and SunocoCorp’s officers, employees, agents and representatives from certain liabilities incurred by SunocoCorp in connection with carrying on its business as provided for in its operating agreement, including liabilities from any litigation brought against SunocoCorp by holders of SunocoCorp common units, and (ii) we agreed to provide all general and administrative services necessary or useful for the conduct of SunocoCorp’s business and pay on its behalf or otherwise reimburse SunocoCorp for any costs and expenses incurred by SunocoCorp for any such services as well as certain other costs and expenses, including the salaries and related benefits and expenses of any of its personnel and the expenses and expenditures incurred by SunocoCorp as a result of becoming and continuing as a publicly traded company. Our indemnification obligations will not apply to (a) any liabilities relating to or arising out of any business, operations or financing activities engaged in by SunocoCorp following the completion of the Arrangement that are not related to its business of owning, directly or indirectly, partnership interests in Sunoco and activities incidental thereto and financing activities engaged in under the agreement or (b) any federal, state or local income taxes payable by SunocoCorp.
The Omnibus Agreement also includes provisions relating to the intended economic alignment between the SunocoCorp common units and our publicly-traded common units. In particular, (i) from the closing date of the Arrangement until the date that is the end of the eighth full quarter following such date, we will be required to ensure that SunocoCorp has sufficient cash available for distribution for SunocoCorp to pay distributions on each of its common units in an amount equal to 100% of the distributions paid by Sunoco on each of our publicly-traded common units for each fiscal quarter and (ii) we and SunocoCorp agree that is our intention, absent certain changes in circumstances, to keep the number of our Class D Units held by SunocoCorp equal to the number of common units issued by SunocoCorp, including provisions to address potential offerings of common units or any employee equity awards issued by SunocoCorp.
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In the event of certain triggering events, including events related to the ownership of the SunocoCorp Management LLC’s managing member interest or our General Partner’s general partnership interest or SunocoCorp engaging, directly or indirectly, in any business or operations unrelated to its investment in us, we and SunocoCorp have agreed to renegotiate any needed amendments to the agreement in good faith so as to preserve, to the extent possible, their original intention to maintain economic and governance alignment between us and SunocoCorp. If we and SunocoCorp are unable to agree on the necessary amendments to the Omnibus Agreement or that no such amendments are necessary within the time period prescribed by the Omnibus Agreement, either party may terminate the Omnibus Agreement by written notice to the other parties thereto.
Related Party Agreements
During 2025, Sunoco, LLC and Sunoco Retail had administrative and support services agreements in place pursuant to which a subsidiary of Energy Transfer provided certain general and administrative services to Sunoco, LLC and Sunoco Retail during 2025. In addition, Sunoco, LLC and Sunoco Retail have treasury services agreements for certain cash management activities with Energy Transfer (R&M), LLC, an indirect wholly owned subsidiary of Energy Transfer.
We are party to fee-based commercial agreements with various subsidiaries or affiliates of Energy Transfer for pipeline, terminalling and storage services. We also have agreements with subsidiaries of Energy Transfer for the purchase and sale of fuel.
Effective July 1, 2024, Sunoco and Energy Transfer formed ET-S Permian, a joint venture combining their respective crude oil and produced water gathering assets in the Permian Basin. Sunoco contributed all of its Permian crude oil gathering assets and operations to ET-S Permian. Energy Transfer contributed its Permian crude oil and produced water gathering assets and operations to ET-S Permian. Energy Transfer’s long-haul crude pipeline network that provides transportation of crude oil out of the Permian Basin to Nederland, Houston and Cushing is excluded from ET-S Permian.
ET-S Permian operates more than 5,000 miles of crude oil and water gathering pipelines with crude oil storage capacity in excess of 11 million barrels.
Sunoco holds a 32.5% interest, with Energy Transfer holding the remaining 67.5% interest in ET-S Permian. Energy Transfer serves as the operator of ET-S Permian.
Procedures for Review, Approval and Ratification of Transactions with Related Persons
For a discussion of director independence, see “Item 10. Directors, Executive Officers and Corporate Governance.”
The Audit Committee reviews and considers related party transactions with various subsidiaries or affiliates of Energy Transfer. The Audit Committee has authorized the General Partner’s management to enter into transactions with entities affiliated to Energy Transfer on arms-length terms taking into account then-current market conditions applicable to the services to be provided, and any such transaction, within management’s delegation of authority levels shall be deemed approved by the Audit Committee, provided it is not a new related party transaction that may be material to the Partnership.
As a policy matter, our Special Committee, comprised of our independent directors, generally reviews any proposed related party transaction that may be material to the Partnership to determine whether the transaction is fair and reasonable to the Partnership. In determining materiality, our General Partner evaluates several factors including the terms of the transaction, the capital investment required, and the revenues expected from the transaction. While there are no written policies or procedures for the Board to follow in making these determinations, the Board makes those determinations in light of its contractually-limited duties to the Partnership’s unitholders. Our Partnership Agreement provides that if the Board, through the Special Committee or otherwise, approves the resolution or course of action taken with respect to a conflict of interest, then it will be presumed that, in making its decision, the Board acted in good faith, and any proceeding brought by or on behalf of any limited partner or the Partnership, the person bringing or prosecuting such proceedings will have the burden of overcoming such presumption (see “Item 1A. Risk Factors - Risks Related to Our Structure” in this annual report on Form 10-K).
Additionally, we have in place a Code of Business Conduct and Ethics that is applicable to all directors, officers and employees of the Partnership and its subsidiaries and affiliates, that requires the approval by designated executive officers prior to entering into any related party transaction that could present a potential conflict of interest.
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Item 14. Principal Accountant Fees and Services
Audit Fees
The following table presents fees for audit services rendered by Grant Thornton LLP for the audit of our annual consolidated financial statements for 2025 and 2024, and fees billed for other services rendered by Grant Thornton LLP during the corresponding periods (dollars in millions).

| Fiscal 2025 |  | Fiscal 2024
Audit Fees (1) | $ | 8.6 |  |  | $ | 5.0 |
Audit-Related Fees | — |  |  | — |
Tax Fees | — |  |  | — |
All Other Fees | — |  |  | — |
| $ | 8.6 |  |  | $ | 5.0 |

_______________________________
(1)Includes fees for audits of annual financial statements of our companies, reviews of the related quarterly financial statements and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC and services related to the audit of our internal control over financial reporting.
Policy for Approval of Audit and Non-Audit Services
Our audit committee charter requires that all services provided by our independent public accountants, both audit and non-audit, must be pre-approved by the audit committee. Pre-approval of audit and non-audit services may be given at any time up to a year before commencement of the specified service.
In determining whether to approve a particular audit or permitted non-audit service, the audit committee will consider, among other things, whether such service is consistent with maintaining the independence of the independent public accountants. The audit committee will also consider whether the independent public accountants are best positioned to provide the most effective and efficient service to us and whether the service might be expected to enhance our ability to manage or control risk or improve audit quality.
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Part IV
Item 15. Exhibit and Financial Statement Schedules
The following documents are filed as a part of this Annual Report on Form 10-K:
•Financial Statements - see Index to Consolidated Financial Statements appearing on page F-1.
•Financial Statement Schedules - pursuant to Rule 3-09 of Regulation S-X, the audited financial statements of ET-S Permian Holdings Company LP, an equity method investee of Sunoco LP, are included in this Annual Report on Form 10-K as Exhibit 99.1
•Exhibits - see Exhibit Index set forth on page 73.
Item 16. Form 10-K Summary
None.
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EXHIBIT INDEX

Exhibit No. |  | Description
2.1 |  |  | Agreement and Plan of Merger, dated as of January 22, 2024, by and among Sunoco LP, Saturn Merger Sub, LLC, NuStar Energy L.P., Riverwalk Logistics, L.P., NuStar GP, LLC and Sunoco GP, LLC (incorporated by reference to Exhibit 2.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on January 22, 2024)
2.2 |  |  | Contribution Agreement, by and among Sunoco LP, SUN Pipeline Holdings LLC, NuStar Permian Transportation and Storage LLC, NuStar Permian Crude Logistics LLC, NuStar Permian Holdings LLC, NuStar Logistics, L.P., ET-S Permian Holdings Company LP, ET-S Permian Pipeline Company LLC, ET-S Permian Marketing Company LLC, Energy Transfer LP, and Energy Transfer Crude Marketing, LLC, dated as of July 14, 2024 (incorporated by reference to Exhibit 2.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on July 18, 2024)
2.3 |  |  | Arrangement Agreement, dated as of May 4, 2025, by and among Sunoco LP, NuStar GP Holdings, LLC, 2709716 Alberta Ltd. and Parkland Corporation (incorporated by reference to Exhibit 2.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on May 6, 2025)
2.4 |  |  | First Amending Agreement to the Arrangement Agreement, dated as of May 26, 2025, by and among Sunoco LP, NuStar GP Holdings, LLC, 2709716 Alberta Ltd. and Parkland Corporation (incorporated by reference to Exhibit 2.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on May 29, 2025)
2.5 |  |  | Second Amending Agreement, dated as of October 10, 2025, by and among Sunoco LP, 2709716 Alberta ULC, SunocoCorp LLC, and Parkland Corporation (incorporated by reference to Exhibit 2.3 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 3, 2025)
3.1 |  |  | Second Amended and Restated Certificate of Limited Partnership of Sunoco LP dated as of May 8, 2018 (i ncorporated by reference to Exhibit 3.1 of the quarterly report on Form 10-Q (File Number 001-35653) filed by the registrant on May 10, 2018)
3.2 |  |  | Third Amended and Restated Agreement of Limited Partnership of Sunoco LP, dated September 18, 2025 (incorporated by reference to Exhibit 3.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on September 18, 2025)
3.3 |  |  | Amendment No. 1 to the Third Amended and Restated Agreement of Limited Partnership of Sunoco LP, dated as of October 31, 2025 (incorporated by reference to Exhibit 3.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 3, 2025)
3.4 |  |  | Certificate of Formation of Susser Petroleum Partners GP LLC (incorporated by reference to Exhibit 3.4 of the registration statement on Form S-1 (File Number 333-182276), as amended, originally filed by the registrant on June 22, 2012)
3.5 |  |  | Certificate of Amendment to the Certificate of Formation of Susser Petroleum Partners GP LLC (incorporated by reference to Exhibit 3.3 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on October 28, 2014)
3.6 |  |  | Second Amended and Restated Limited Liability Company Agreement of Sunoco GP LLC, dated as of October 28, 2025 (incorporated by reference to Exhibit 3.2 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 3, 2025)
4.1* |  | Description of the registrant’s securities registered pursuant to section 12 of the Securities Exchange Act of 1934 - Description of common units
4.2 |  |  | Indenture, dated as of March 31, 2025, by and among Sunoco LP, the Guarantors party thereto and U.S. Bank Trust Company, National Association, as Trustee (incorporated by reference to Exhibit 4.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on March 31, 2025)
4.3 |  |  | Indenture, dated as of September 18, 2025, by and among Sunoco LP, the Guarantors party thereto and U.S. Bank Trust Company, National Association, as Trustee (incorporated by reference to Exhibit 4.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on September 18, 2025)
4.4 |  |  | Trust Indenture (6.000% Senior Notes due 2028), dated as of June 23, 2020, by and among Parkland Corporation, the guarantors party thereto and Computershare Trust Company of Canada, as trustee (incorporated by reference to Exhibit 4.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 10, 2025)
4.5 |  |  | First Supplemental Indenture (6.000% Senior Notes due 2028), dated as of June 20, 2025, by and among Parkland Corporation, the guarantors party thereto and Computershare Trust Company of Canada, as trustee (incorporated by reference to Exhibit 4.2 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 10, 2025)
4.6 |  |  | Second Supplemental Indenture (6.000% Senior Notes due 2028), dated as of November 7, 2025, by and among Parkland Corporation, the guarantors party thereto and Computershare Trust Company of Canada, as trustee (incorporated by reference to Exhibit 4.3 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 10, 2025)
4.7 |  |  | Trust Indenture (4.375% Senior Notes due 2029), dated as of March 25, 2021, by and among Parkland Corporation, the guarantors party thereto and Computershare Trust Company of Canada, as trustee (incorporated by reference to Exhibit 4.4 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 10, 2025)
4.8 |  |  | First Supplemental Indenture (4.375% Senior Notes due 2029), dated as of June 20, 2025, by and among Parkland Corporation, the guarantors party thereto and Computershare Trust Company of Canada, as trustee (incorporated by reference to Exhibit 4.5 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 10, 2025)
4.9 |  |  | Second Supplemental Indenture (4.375% Senior Notes due 2029), dated as of November 7, 2025, by and among Parkland Corporation, the guarantors party thereto and Computershare Trust Company of Canada, as trustee (incorporated by reference to Exhibit 4.6 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 10, 2025)

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4.10 |  |  | Trust Indenture (3.875% Senior Notes due 2026), dated as of June 16, 2021, by and among Parkland Corporation, the guarantors party thereto and Computershare Trust Company of Canada, as trustee (incorporated by reference to Exhibit 4.7 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 10, 2025)
4.11 |  |  | First Supplemental Indenture (3.875% Senior Notes due 2026), dated as of November 7, 2025, by and among Parkland Corporation, the guarantors party thereto and Computershare Trust Company of Canada, as trustee (incorporated by reference to Exhibit 4.8 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 10, 2025)
4.12 |  |  | Indenture (5.875% Senior Notes due 2027), dated as of July 10, 2019, by and among Parkland Corporation, the guarantors party thereto, Computershare Trust Company, N.A., as U.S. trustee, and Computershare Trust Company of Canada, as Canadian trustee (incorporated by reference to Exhibit 4.9 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 10, 2025)
4.13 |  |  | First Supplemental Indenture (5.875% Senior Notes due 2027), dated as of June 20, 2025, by and among Parkland Corporation, the guarantors party thereto, Computershare Trust Company, N.A., as U.S. trustee, and Computershare Trust Company of Canada, as Canadian trustee (incorporated by reference to Exhibit 4.10 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 10, 2025)
4.14 |  |  | Second Supplemental Indenture (5.875% Senior Notes due 2027), dated as of November 7, 2025, by and among Parkland Corporation, the guarantors party thereto, Computershare Trust Company, N.A., as U.S. trustee, and Computershare Trust Company of Canada, as Canadian trustee (incorporated by reference to Exhibit 4.11 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 10, 2025)
4.15 |  |  | Indenture (4.500% Senior Notes due 2029), dated as of April 13, 2021, by and among Parkland Corporation, the guarantors party thereto, Computershare Trust Company, N.A., as U.S. trustee, and Computershare Trust Company of Canada, as Canadian trustee (incorporated by reference to Exhibit 4.12 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 10, 2025)
4.16 |  |  | First Supplemental Indenture (4.500% Senior Notes due 2029), dated as of June 20, 2025, by and among Parkland Corporation, the guarantors party thereto, Computershare Trust Company, N.A., as U.S. trustee, and Computershare Trust Company of Canada, as Canadian trustee (incorporated by reference to Exhibit 4.13 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 10, 2025)
4.17 |  |  | Second Supplemental Indenture (4.500% Senior Notes due 2029), dated as of November 7, 2025, by and among Parkland Corporation, the guarantors party thereto, Computershare Trust Company, N.A., as U.S. trustee, and Computershare Trust Company of Canada, as Canadian trustee (incorporated by reference to Exhibit 4.14 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 10, 2025)
4.18 |  |  | Indenture (4.625% Senior Notes due 2030), dated as of November 23, 2021, by and among Parkland Corporation, the guarantors party thereto, Computershare Trust Company, N.A., as U.S. trustee, and Computershare Trust Company of Canada, as Canadian trustee (incorporated by reference to Exhibit 4.15 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 10, 2025)
4.19 |  |  | First Supplemental Indenture (4.625% Senior Notes due 2030), dated as of June 20, 2025, by and among Parkland Corporation, the guarantors party thereto, Computershare Trust Company, N.A., as U.S. trustee, and Computershare Trust Company of Canada, as Canadian trustee (incorporated by reference to Exhibit 4.16 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 10, 2025)
4.20 |  |  | Second Supplemental Indenture (4.625% Senior Notes due 2030), dated as of November 7, 2025, by and among Parkland Corporation, the guarantors party thereto, Computershare Trust Company, N.A., as U.S. trustee, and Computershare Trust Company of Canada, as Canadian trustee (incorporated by reference to Exhibit 4.17 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 10, 2025)
4.21 |  |  | Indenture (6.625% Senior Notes due 2032), dated as of August 16, 2024, by and among Parkland Corporation, the guarantors party thereto, Computershare Trust Company, N.A., as U.S. trustee, and Computershare Trust Company of Canada, as Canadian trustee (incorporated by reference to Exhibit 4.18 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 10, 2025)
4.22 |  |  | First Supplemental Indenture (6.625% Senior Notes due 2032), dated as of June 20, 2025, by and among Parkland Corporation, the guarantors party thereto, Computershare Trust Company, N.A., as U.S. trustee, and Computershare Trust Company of Canada, as Canadian trustee (incorporated by reference to Exhibit 4.19 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 10, 2025)
4.23 |  |  | Second Supplemental Indenture (6.625% Senior Notes due 2032), dated as of November 7, 2025, by and among Parkland Corporation, the guarantors party thereto, Computershare Trust Company, N.A., as U.S. trustee, and Computershare Trust Company of Canada, as Canadian trustee (incorporated by reference to Exhibit 4.20 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 10, 2025)
4.24 |  |  | Indenture, dated as of November 7, 2025, by and among Sunoco LP, the Guarantors party thereto, U.S. Bank Trust Company, National Association, as U.S. trustee, and Computershare Trust Company of Canada, as Canadian trustee, relating to New CAD Notes (incorporated by reference to Exhibit 4.21 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 10, 2025)
4.25* |  | First Supplemental Indenture to Indenture, dated as of December 12, 2025, by and among Sunoco LP, the Guarantors party thereto, U.S. Bank Trust Company, National Association, as U.S. trustee, and Computershare Trust Company of Canada, as Canadian trustee, relating to New CAD Notes
4.26 |  |  | Indenture, dated as of November 7, 2025, by and among Sunoco LP, the Guarantors party thereto and U.S. Bank Trust Company, National Association, as Trustee, relating to New USD Notes (incorporated by reference to Exhibit 4.22 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 10, 2025)

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4.27 |  |  | Indenture, dated as of July 15, 2002, among Valero Logistics Operations, L.P., as Issuer, Valero L.P., as Guarantor, and The Bank of New York, as Trustee, relating to Senior Debt Securities (incorporated by reference to Exhibit 4.4 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on May 3, 2024)
4.28 |  |  | Third Supplemental Indenture, dated as of July 1, 2005, to Indenture dated as of July 15, 2002, as amended and supplemented, among Valero Logistics Operations, L.P., Valero L.P., Kaneb Pipe Line Operating Partnership, L.P., and The Bank of New York Trust Company, N.A. (incorporated by reference to Exhibit 4.5 of the current report on Form 8-K for (File Number 001-35653) filed by the registrant on May 3, 2024)
4.29 |  |  | Instrument of Resignation, Appointment and Acceptance, dated March 31, 2008, among NuStar Logistics, L.P., NuStar Energy L.P., Kaneb Pipeline Operating Partnership, L.P., The Bank of New York Trust Company N.A., and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.6 of the current report on Form 8-K for (File Number 001-35653) filed by the registrant on May 3, 2024)
4.30 |  |  | Eighth Supplemental Indenture, dated as of April 28, 2017, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, and Wells Fargo Bank, National Association, as Successor Trustee (incorporated by reference to Exhibit 4.7 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on May 3, 2024)
4.31 |  |  | Ninth Supplemental Indenture, dated as of May 22, 2019, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, and Wells Fargo Bank, National Association, as Successor Trustee (incorporated by reference to Exhibit 4.8 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on May 3, 2024)
4.32 |  |  | Tenth Supplemental Indenture, dated as of September 14, 2020, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, and Wells Fargo Bank, National Association, as Successor Trustee (incorporated by reference to Exhibit 4.9 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on May 3, 2024)
4.33 |  |  | Eleventh Supplemental Indenture, dated as of May 31, 2024, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, Sunoco LP, as Ultimate Parent Guarantor, the Guarantors party thereto and Computershare Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.19 of Sunoco LP’s Current Report on Form 8-K (File No. 001-35653) filed June 5, 2024)
4.34 |  |  | Indenture, dated as of January 22, 2013, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee, relating to Subordinated Debt Securities (i ncorporated by reference to Exhibit 4.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on May 3, 2024)
4.35 |  |  | Registration Rights Agreement, dated as of March 31, 2016, by and among Sunoco LP and Energy Transfer Equity, L.P. (i ncorporated by reference to Exhibit 4.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on April 1, 2016)
4.36 |  |  | Indenture, by and among Sunoco LP, Sunoco Finance Corp., the Guarantors party thereto and U.S. Bank National Association, as Trustee, dated January 23, 2018 (i ncorporated by reference to Exhibit 4.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on January 29, 2018)
4.37 |  |  | First Supplemental Indenture, dated as of January 24, 2019, by and among Sunoco LP, Sunoco Finance Corp., the subsidiary guarantors party thereto and AMID Refined Products LLC, AMID Caddo LLC, AMID NLR LLC, as guarantors, and U.S. Bank, N.A., as trustee (i ncorporated by reference to Exhibit 4.4 of the annual report on Form 10-K (File Number 001-35653) filed by the registrant on February 22, 2019)
4.38 |  |  | Second Supplemental Indenture, dated as of May 31, 2024, by and among Sunoco LP, Sunoco Finance Corp., the Guarantors party thereto and U.S. Bank National Association, as Trustee, dated May 31 (i ncorporated by reference to Exhibit 4.3 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on June 5, 2024)
4.39 |  |  | Indenture, dated as of March 14, 2019, by and among Sunoco LP, Sunoco Finance Corp., the Guarantors party thereto and U.S. Bank National Association, as Trustee (i ncorporated by reference to Exhibit 4.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on March 14, 2019)
4.40 |  |  | First Supplemental Indenture, dated as of May 31, 2024, by and among Sunoco LP, Sunoco Finance Corp., the Guarantors party thereto and U.S. Bank National Association, as Trustee (i ncorporated by reference to Exhibit 4.5 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on June 5, 2024)
4.41 |  |  | Indenture, by and among Sunoco LP, Sunoco Finance Corp., the Guarantors party thereto and U.S. Bank National Association, as Trustee, dated November 24, 2020 (i ncorporated by reference to Exhibit 4.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 24, 2020)
4.42 |  |  | First Supplemental Indenture, dated as of May 31, 2024, by and among Sunoco LP, Sunoco Finance Corp., the Guarantors party thereto and U.S. Bank National Association, as Trustee (i ncorporated by reference to Exhibit 4.7 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on June 5, 2024)
4.43 |  |  | Indenture, by and among Sunoco LP, Sunoco Finance Corp., the Guarantors party thereto and U.S. Bank National Association, as Trustee, dated October 20, 2021 (i ncorporated by reference to Exhibit 4.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on October 20, 2021)
4.44 |  |  | First Supplemental Indenture, dated as of May 31, 2024, by and among Sunoco LP, Sunoco Finance Corp., the Guarantors party thereto and U.S. Bank National Association, as Trustee (i ncorporated by reference to Exhibit 4.9 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on June 5, 2024)
4.45 |  |  | Indenture, by and among Sunoco LP, Sunoco Finance Corp., the Guarantors party thereto and U.S. Bank Trust Company, National Association, as Trustee, dated September 20, 2023 (i ncorporated by reference to Exhibit 4.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on September 20, 2023)

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4.46 |  |  | First Supplemental Indenture, dated as of May 31, 2024, by and among Sunoco LP, Sunoco Finance Corp., the Guarantors party thereto and U.S. Bank National Association, as Trustee (i ncorporated by reference to Exhibit 4.11 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on June 5, 2024)
4.47 |  |  | Indenture, dated as of April 30, 2024, by and among Sunoco LP, the Guarantors party thereto and U.S. Bank Trust Company, National Association, as Trustee (i ncorporated by reference to Exhibit 4.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on April 30, 2024)
4.48 |  |  | First Supplemental Indenture, dated as of May 31, 2024, by and among Sunoco LP, the Guarantors party thereto and U.S. Bank National Association, as Trustee (i ncorporated by reference to Exhibit 4.13 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on June 5, 2024)
4.49 |  |  | Second Supplement and Amendment to Series 2008 Indenture, dated as of July 15, 2024, among the Parish of St. James, State of Louisiana, Sunoco LP, Sunoco Finance Corp., the Guarantors party thereto and U.S. Bank Trust Company, National Association, as trustee (i ncorporated by reference to Exhibit 4.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on July 18, 2024)
4.50 |  |  | Second Supplement and Amendment to Series 2010 Indenture, dated as of July 15, 2024, among the Parish of St. James, State of Louisiana, Sunoco LP, Sunoco Finance Corp., the Guarantors party thereto and U.S. Bank Trust Company, National Association, as trustee (i ncorporated by reference to Exhibit 4.2 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on July 18, 2024)
4.51 |  |  | Second Supplement and Amendment to Series 2010A Indenture, dated as of July 15, 2024, among the Parish of St. James, State of Louisiana, Sunoco LP, Sunoco Finance Corp., the Guarantors party thereto and U.S. Bank Trust Company, National Association, as trustee (i ncorporated by reference to Exhibit 4.3 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on July 18, 2024)
4.52 |  |  | Second Supplement and Amendment to Series 2010B Indenture, dated as of July 15, 2024, among the Parish of St. James, State of Louisiana, Sunoco LP, Sunoco Finance Corp., the Guarantors party thereto and U.S. Bank Trust Company, National Association, as trustee (i ncorporated by reference to Exhibit 4.4 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on July 18, 2024)
4.53 |  |  | Second Supplement and Amendment to Series 2011 Indenture, dated as of July 15, 2024, among the Parish of St. James, State of Louisiana, Sunoco LP, Sunoco Finance Corp., the Guarantors party thereto and U.S. Bank Trust Company, National Association, as trustee (i ncorporated by reference to Exhibit 4.5 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on July 18, 2024)
10.1 |  |  | Lease Agreement between the Parish of St. James, State of Louisiana and NuStar Logistics, L.P. dated as of June 1, 2008 (i ncorporated by reference to Exhibit 10.18 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on May 3, 2024)
10.2 |  |  | First Supplement and Amendment to Lease Agreement (Series 2008), dated June 1, 2020, among the Parish of St. James, State of Louisiana, NuStar Logistics, L.P., NuStar Energy L.P. and NuStar Pipeline Operating Partnership L.P. (i ncorporated by reference to Exhibit 10.19 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on May 3, 2024)
10.3 |  |  | Second Supplement and Amendment to Lease Agreement (Series 2008), dated July 15, 2024, among the Parish of St. James, State of Louisiana, NuStar Logistics, L.P., Sunoco LP and certain of Sunoco LP’s subsidiaries (i ncorporated by reference to Exhibit 10.3 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on July 18, 2024)
10.4 |  |  | Lease Agreement Between Parish of St. James, State of Louisiana and NuStar Logistics, L.P. dated as of July 1, 2010 (i ncorporated by reference to Exhibit 10.20 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on May 3, 2024)
10.5 |  |  | First Supplement and Amendment to Lease Agreement (Series 2010), dated June 1, 2020, among the Parish of St. James, State of Louisiana, NuStar Logistics, L.P., NuStar Energy L.P. and NuStar Pipeline Operating Partnership L.P. (i ncorporated by reference to Exhibit 10.21 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on May 3, 2024)
10.6 |  |  | Second Supplement and Amendment to Lease Agreement (Series 2010), dated July 15, 2024, among the Parish of St. James, State of Louisiana, NuStar Logistics, L.P., Sunoco LP and certain of Sunoco LP’s subsidiaries (i ncorporated by reference to Exhibit 10.6 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on July 18, 2024)
10.7 |  |  | Lease Agreement between the Parish of St. James, State of Louisiana and NuStar Logistics, L.P. dated as of October 1, 2010 (i ncorporated by reference to Exhibit 10.22 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on May 3, 2024)
10.8 |  |  | First Supplement and Amendment to Lease Agreement (Series 2010A), dated June 1, 2020, among the Parish of St. James, State of Louisiana, NuStar Logistics, L.P., NuStar Energy L.P. and NuStar Pipeline Operating Partnership L.P. (i ncorporated by reference to Exhibit 10.23 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on May 3, 2024)
10.9 |  |  | Second Supplement and Amendment to Lease Agreement (Series 2010A), dated July 15, 2024, among the Parish of St. James, State of Louisiana, NuStar Logistics, L.P., Sunoco LP and certain of Sunoco LP’s subsidiaries (i ncorporated by reference to Exhibit 10.9 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on July 18, 2024)
10.10 |  |  | Lease Agreement between Parish of St. James, State of Louisiana and NuStar Logistics, L.P. dated as of December 1, 2010 (i ncorporated by reference to Exhibit 10.24 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on May 3, 2024)
10.11 |  |  | First Supplement and Amendment to Lease Agreement (Series 2010B), dated June 1, 2020, among the Parish of St. James, State of Louisiana, NuStar Logistics, L.P., NuStar Energy L.P. and NuStar Pipeline Operating Partnership L.P. (i ncorporated by reference to Exhibit 10.25 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on May 3, 2024)

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10.12 |  |  | Second Supplement and Amendment to Lease Agreement (Series 2010B), dated July 15, 2024, among the Parish of St. James, State of Louisiana, NuStar Logistics, L.P., Sunoco LP and certain of Sunoco LP’s subsidiaries (i ncorporated by reference to Exhibit 10.12 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on July 18, 2024)
10.13 |  |  | Lease Agreement between Parish of St. James, State of Louisiana and NuStar Logistics, L.P. dated as of August 1, 2011 (i ncorporated by reference to Exhibit 10.26 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on May 3, 2024)
10.14 |  |  | First Supplement and Amendment to Lease Agreement (Series 2011), dated June 1, 2020, among the Parish of St. James, State of Louisiana, NuStar Logistics, L.P., NuStar Energy L.P. and NuStar Pipeline Operating Partnership L.P. (i ncorporated by reference to Exhibit 10.27 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on May 3, 2024)
10.15 |  |  | Second Supplement and Amendment to Lease (Series 2011), dated July 15, 2024, among the Parish of St. James, State of Louisiana, NuStar Logistics, L.P., Sunoco LP and certain of Sunoco LP’s subsidiaries (i ncorporated by reference to Exhibit 10.15 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on July 18, 2024)
10.16+ |  | Susser Petroleum Partners LP 2012 Long-Term Incentive Plan (i ncorporated by reference to Exhibit 10.2 of the registration statement on Form S-1 (File Number 333-182276), as amended, originally filed by the registrant on June 22, 2012)
10.17+ |  | First Amendment to the Susser Petroleum Partners LP 2012 Long Term Incentive Plan, dated November 4 2014 (i ncorporated by reference to Exhibit 10.24 of the annual report on Form 10-K (File Number 001-35653) filed by the registrant on February 27, 2015)
10.18+ |  | Sunoco GP LLC Annual Bonus Plan (i ncorporated by reference to Exhibit 10.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on July 13, 2018)
10.19+ |  | Sunoco GP LLC Amended and Restated Annual Bonus Plan (i ncorporated by reference to Exhibit 10.7 of the annual report on Form 10-K (File Number 001-35653) filed by the registrant on February 16, 2024)
10.20+ |  | Sunoco LP 2018 Long-Term Incentive Plan (i ncorporated by reference to Exhibit 10.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 20, 2018)
10.21+ |  | Form of Time Vested Restricted Unit/Phantom Unit Agreement (i ncorporated by reference to Exhibit 10.32 of the annual report on Form 10-K (File number 001-35653) filed by the registrant on February 22, 2019)
10.22+ |  | Sunoco LP Long-Term Cash Restricted Unit Plan (incorporated by reference to Exhibit 10.25 of the annual report on Form 10-K (File Number 001-35653) filed by the registrant on February 14, 2025)
10.23+ |  | Form of Cash Unit Award Agreement Under the Sunoco LP Long-Term Cash Restricted Unit Plan (incorporated by reference to Exhibit 10.26 of the annual report on Form 10-K (File Number 001-35653) filed by the registrant on February 14, 2025)
10.24 |  |  | Revised Form of Director Indemnification Agreement (i ncorporated by reference to Exhibit 10.10 of the annual report on Form 10-K (File Number 001-35653) filed by the registrant on March 14, 2014)
10.25 |  |  | Purchase and Sale Agreement, dated as of June 15, 2015, by and among NuStar Finance, as borrower, NuStar Energy L.P., as servicer, and NuStar and the subsidiaries of NuStar named therein, as originators (incorporated by reference to Exhibit 10.15 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on May 3, 2024)
10.26 |  |  | Second Amendment to Purchase and Sale Agreement, dated as of September 20, 2017, by and among, NuStar Energy L.P., NS Finance and certain affiliates of NuStar as original originators and additional originators (incorporated by reference to Exhibit 10.16 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on May 3, 2024)
10.27 |  |  | Third Amendment to Purchase and Sale Agreement, dated as of May 3, 2024, by and among NuStar Finance LLC, as buyer, NuStar Energy L.P., as servicer, and NuStar Energy L.P. and its subsidiaries named therein, as originators (incorporated by reference to Exhibit 10.17 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on May 3, 2024)
10.28 |  |  | Guarantee Agreement by and among Sunoco LP, Sunoco, LLC, 7-Eleven, Inc. and SEI Fuel Services, Inc., dated as of April 6, 2017 (incorporated by reference to Exhibit 10.2 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on April 6, 2017)
10.29 |  |  | Guarantee of Collection, by Energy Transfer Operating, L.P. to Sunoco LP and Sunoco Finance Corp., dated May 1, 2020 (incorporated by reference to Exhibit 10.12 of the annual report on Form 10-K (File Number 001-35653) filed by the registrant on February 19, 2021)
10.30 |  |  | Amended and Restated Support Agreement, by and among ETC Sunoco Holdings LLC, Sunoco LP, Sunoco Finance Corp. and Energy Transfer Operating, L.P., dated May 1, 2020 (incorporated by reference to Exhibit 10.13 of the annual report on Form 10-K (File Number 001-35653) filed by the registrant on February 19, 2021)
10.31 |  |  | Common Unit Repurchase Agreement, by and among Sunoco LP, Heritage Holdings, Inc. and ETP Holdco Corporation, dated January 24, 2018 (incorporated by reference to Exhibit 10.3 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on January 29, 2018)
10.32 |  |  | Distribution Motor Fuel Agreement by and between Sunoco, LLC and 7-Eleven, Inc. and SEI Fuel Services, Inc. dated January 23, 2018 (asterisks located within the exhibit denote information which has been deleted pursuant to a confidential treatment request filed with the Securities and Exchange Commission) (incorporated by reference to Exhibit 10.37 of the annual report on Form 10-K (File Number 001-35653) filed by the registrant on February 23, 2018)
10.33 |  |  | First Amendment, dated as of March 29, 2019, to Distributor Motor Fuel Agreement by and between Sunoco, LLC and 7-Eleven, Inc. and SEI Fuel Services, Inc. dated as of January 23, 2018 (asterisks located within the exhibit denote information which has been redacted) (incorporated by reference to Exhibit 10.1 of the quarterly report on Form 10-Q (File Number 001-35653) filed by the registrant on May 9, 2019)

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10.34 |  |  | Third Amended and Restated Credit Agreement, dated as of May 3, 2024, by and among Sunoco LP, as borrower, the lenders from time to time party thereto and Bank of America, N.A., as administrative agent, swingline lender and an LC issuer (incorporated by reference to Exhibit 10.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on May 3, 2024)
10.35 |  |  | Amendment No. 1 to Third Amended and Restated Credit Agreement, dated as of May 16, 2025, by and among Sunoco LP, as borrower, certain subsidiaries of Sunoco LP, as guarantors, Bank of America N.A., as administrative agent and an LC issuer, and the lenders and LC issuers party thereto (incorporated by reference to Exhibit 10.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on May 20, 2025)
10.36 |  |  | Amendment No. 2 to Third Amended and Restated Credit Agreement, dated as of June 17, 2025, by and among Sunoco LP, as borrower, certain subsidiaries of Sunoco LP, as guarantors, Bank of America N.A., as administrative agent and swingline lender and the lenders and LC issuers party thereto (incorporated by reference to Exhibit 10.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on June 23, 2025)
10.37 |  |  | Amendment No. 3 to Third Amended and Restated Credit Agreement, dated as of August 8, 2025, by and among Sunoco LP, as borrower, certain subsidiaries of Sunoco LP, as guarantors, Bank of America N.A., as administrative agent and the lenders and LC issuers party thereto (incorporated by reference to Exhibit 10.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on August 8, 2025)
10.38 |  |  | Amendment No. 4 to Third Amended and Restated Credit Agreement, dated as of October 3, 2025, by and among Sunoco LP, as borrower, certain subsidiaries of Sunoco LP, as guarantors, Bank of America N.A., as administrative agent and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on October 6, 2025)
10.39* |  | Amendment No. 5 to Third Amended and Restated Credit Agreement, dated as of October 30, 2025, by and among Sunoco LP, as borrower, certain subsidiaries of Sunoco LP, as guarantors, Bank of America N.A., as administrative agent and the LC issuers party thereto
10.40* |  | Amendment No. 6 to Third Amended and Restated Credit Agreement, dated as of November 25, 2025, by and among Sunoco LP, as borrower, certain subsidiaries of Sunoco LP, as guarantors, and Bank of America N.A., as lender and administrative agent
10.41 |  |  | Omnibus Agreement, dated as of October 31, 2025, between Sunoco LP and SunocoCorp LLC (incorporated by reference to Exhibit 10.1 of the current report on Form 8-K (File Number 001-35653) filed by the registrant on November 3, 2025)
10.42* |  | Delegation Agreement, dated as of October 27, 2025, by and among SunocoCorp LLC, Energy Transfer LP and Sunoco GP LLC
19.1 |  |  | Sunoco LP Insider Trading Policy (incorporated by reference to Exhibit 19.1 of the annual report on Form 10-K (File Number 001-35653) filed by the registrant on February 14, 2025)
21.1* |  | List of Subsidiaries of the Registrant
22.1* |  | List of Guarantor and Issuer Subsidiaries
23.1* |  | Consent of Grant Thornton LLP, independent registered public accounting firm (Sunoco LP)
23.2* |  | Consent of Grant Thornton LLP, independent certified public accountants (ET-S Permian Holdings Company LP)
31.1* |  | Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934 as adopted pursuant to Section 302 of the Sarbanes-Oxley Act
31.2* |  | Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934 as adopted pursuant to Section 302 of the Sarbanes-Oxley Act
32.1** |  | Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002
32.2** |  | Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002
97.1 |  |  | Sunoco LP Executive Officer Incentive Compensation Clawback Policy (incorporated by reference to Exhibit 97.1 of the annual report on Form 10-K (File Number 001-35653) filed by the registrant on February 16, 2024)
99.1* |  | Audited financial statements of ET-S Permian Holdings Company LP
101* |  | Interactive data files pursuant to Rule 405 of Regulation S-T formatted in iXBRL (Inline eXtensible Business Reporting Language) in this Form 10-K include: (i) our Consolidated Balance Sheets; (ii) our Consolidated Statements of Operations; (iii) our Consolidated Statements of Comprehensive Income; (iv) our Consolidated Statements of Equity; (v) our Consolidated Statements of Cash Flows; and (vi) the notes to our Consolidated Financial Statements
104 |  | Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)

* |  | Filed herewith.
** |  | Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this Annual Report on Form 10-K and not “filed” as part of such report for purposes of Section 18 of the Exchange Act, as amended, or otherwise subject to the liability of Section 18 of the Exchange Act and this certification will not be deemed to be incorporated by reference into any filing under the Exchange Act except to the extent that the registrant specifically incorporates it by reference.
+ |  | Denotes a management contract or compensatory plan or arrangement.

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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Sunoco LP
By: | Sunoco GP LLC, its general partner
By: | /s/ Joseph Kim
| Joseph Kim
| President and Chief Executive Officer
| (On behalf of the registrant, and in his capacity as principal executive officer)
Date: | February 19, 2026

Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report on Form 10-K 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/ Joseph Kim |  | Director, President and Chief Executive Officer |  | February 19, 2026
Joseph Kim |  | (Principal Executive Officer) |  |
/s/ Dylan A. Bramhall |  | Chief Financial Officer |  | February 19, 2026
Dylan A. Bramhall |  | (Principal Financial Officer) |  |
/s/ Rick J. Raymer |  | Vice President, Controller and Principal Accounting Officer |  | February 19, 2026
Rick J. Raymer |  | (Principal Accounting Officer) |  |
/s/ Ray W. Washburne |  | Chairman of the Board |  | February 19, 2026
Ray W. Washburne |  |  |  |
/s/ Oscar A. Alvarez |  | Director |  | February 19, 2026
Oscar A. Alvarez |  |  |  |
/s/ Bradley C. Barron |  | Director |  | February 19, 2026
Bradley C. Barron |  |  |  |
/s/ David K. Skidmore |  | Director |  | February 19, 2026
David K. Skidmore |  |  |  |
/s/ W. Brett Smith |  | Director |  | February 19, 2026
W. Brett Smith |  |  |  |

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm (PCAOB ID Number 248) | F-2
Consolidated Balance Sheets | F-4
Consolidated Statements of Operations | F-5
Consolidated Statements of Comprehensive Income | F-6
Consolidated Statements of Equity | F-7
Consolidated Statements of Cash Flows | F-8
Notes to Consolidated Financial Statements | F-9
1. Organization and Principles of Consolidation | F-9
2. Summary of Significant Accounting Policies | F-9
3. Acquisitions, Divestitures and Other Transactions | F-15
4. Cash and Cash Equivalents | F-20
5. Accounts Receivable, net | F-21
6. Inventories, net | F-21
7. Investments in Unconsolidated Affiliates | F-21
8. Property, Plant and Equipment, net | F-23
9. Goodwill and Intangible Assets, net | F-23
10. Accrued Expenses and Other Current Liabilities | F-24
11. Debt Obligations | F-25
12. Other Non-Current Liabilities | F-29
13. Related Party Transactions | F-29
14. Revenue | F-30
15. Commitments and Contingencies | F-33
16. Lease Accounting | F-33
17. Interest Expense, net | F-35
18. Income Tax Expense | F-36
19. Partners’ Capital | F-38
20. Employee Benefit Plans | F-40
21. Unit-Based Compensation | F-41
22. Segment Reporting | F-42
23. Net Income per Common Unit | F-46

F-1

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Index to Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors of Sunoco GP LLC and
Unitholders of Sunoco LP
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Sunoco LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2025 and 2024, the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as 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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.
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, 2025, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 19, 2026 expressed an unqualified opinion.
Basis for opinion
These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s 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 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 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 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 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 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 financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the 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.
Fair values of property and equipment and intangible assets acquired in the acquisition of Parkland Corporation
As described further in Note 3 to the consolidated financial statements, on October 31, 2025, the Partnership completed the acquisition of Parkland Corporation (“Parkland”) and the assets acquired and liabilities assumed were recorded at fair value as of the transaction date. The fair values of property and equipment and intangible assets recorded in the Parkland acquisition were $5.61 billion and $1.87 billion, respectively. Management utilized third-party valuation specialists to determine the fair values of the acquired property and equipment and intangible assets. We identified the estimation of the fair values of the acquired property and equipment and intangible assets as a critical audit matter.
The principal consideration for our determination that the estimation of the fair values of the acquired property and equipment and intangible assets is a critical audit matter is that there was estimation uncertainty due to significant judgments required by management when determining the fair value. In particular, the significant judgments were the replacement cost and market assumptions and methodology used for property and equipment as well as the estimated long-term cash flows and the discount rate related to the fair value of the intangible assets. This in turn led to a higher degree of auditor judgment and subjectivity, in performing procedures and evaluating audit evidence related to management’s forecasted future cash flows and assumptions. In addition, the audit effort involved the use of specialists to assist in performing these procedures and evaluating the audit evidence.
Our audit procedures related to the estimation of the fair value of the acquired property and equipment and intangible assets included the following procedures, among others. We tested the effectiveness of controls relating to management’s review of the assumptions
F-2

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Index to Financial Statements
used to project future cash flows, the reconciliation of the future cash flows prepared by management to the data used in the valuation report prepared by the third-party specialists, and review of the valuation methodologies and assumptions applied by the third-party valuation specialists. In addition to testing the effectiveness of controls, we also performed the following:
•Assessed the reasonableness of management’s future cash flows by:
◦evaluating management’s significant assumptions used to project future cash flows, which included forecasted gross profit, earnings before interest, taxes, depreciation, and amortization, capital expenditures and discount rates, and
◦testing the projected future cash flows by comparing forecasted amounts to actual historical results to identify material changes and corroborating the basis for the changes, as applicable.
•Utilized an internal valuation specialist to evaluate:
◦the qualifications of the third-party valuation specialists engaged by management based on their credentials and experience,
◦the process used by management to develop the estimate, including valuation methodologies and assumptions used by the third-party valuation specialists and whether they were acceptable for the underlying assets and applied correctly,
◦the estimates of fair values for assets which were valued based on comparable market data and the appropriateness of the replacement costs, by performing independent market research and analyses, and
◦the appropriateness of the discount rate used by developing an independent range of acceptable discount rates and comparing those ranges to the amounts selected and applied by management.
/s/ GRANT THORNTON LLP
We have served as the Partnership’s auditor since 2015.
Dallas, Texas
February 19, 2026
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Index to Financial Statements
SUNOCO LP
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)

| December 31, 2025 |  | December 31, 2024
ASSETS
Current assets: |  |  |
Cash and cash equivalents | $ | 891 |  |  | $ | 94 |
Accounts receivable, net | 1,972 |  |  | 1,162 |
Inventories, net | 2,383 |  |  | 1,068 |
Other current assets | 270 |  |  | 141 |
Total current assets | 5,516 |  |  | 2,465 |
Property, plant and equipment | 15,256 |  |  | 8,914 |
Accumulated depreciation | (1,848) |  |  | (1,240) |
Property, plant and equipment, net | 13,408 |  |  | 7,674 |
Other assets: |  |  |
Operating lease right-of-use assets, net | 1,449 |  |  | 477 |
Goodwill | 3,026 |  |  | 1,477 |
Intangible assets, net | 2,411 |  |  | 547 |
Other non-current assets | 928 |  |  | 400 |
Investments in unconsolidated affiliates | 1,624 |  |  | 1,335 |
Total assets | $ | 28,362 |  |  | $ | 14,375 |
LIABILITIES AND EQUITY
Current liabilities: |  |  |
Accounts payable | $ | 2,485 |  |  | $ | 1,255 |
Accounts payable to affiliates | 331 |  |  | 199 |
Accrued expenses and other current liabilities | 953 |  |  | 457 |
Operating lease current liabilities | 211 |  |  | 34 |
Current maturities of long-term debt | 17 |  |  | 2 |
Total current liabilities | 3,997 |  |  | 1,947 |
Operating lease non-current liabilities | 1,255 |  |  | 479 |
Long-term debt, net | 13,372 |  |  | 7,484 |
Advances from affiliates | 78 |  |  | 82 |
Deferred tax liabilities | 1,139 |  |  | 157 |
Other non-current liabilities | 512 |  |  | 158 |
Total liabilities | 20,353 |  |  | 10,307 |
Commitments and contingencies (Note 15) |  |  |
Equity: |  |  |
Limited partners: |  |  |
Preferred un itholders (1,500,000 units iss ued and outstanding as of December 31, 2025) | 1,507 |  |  | — |
Common unitholders (136,866,854 and 136,228,535 units issued and outstanding as of December 31, 2025 and 2024, respectively) | 3,970 |  |  | 4,066 |
Class C unitholders - held by sub sidiary (16,410,780 units issued an d outstanding as of December 31, 2025 and 2024) | — |  |  | — |
Class D unitholder (51,517,198 units issued and outstanding as of December 31, 2025) | 2,538 |  |  | — |
Accumulated other comprehensive income (loss) | (6) |  |  | 2 |
Total equity | 8,009 |  |  | 4,068 |
Total liabilities and equity | $ | 28,362 |  |  | $ | 14,375 |

The accompanying notes are an integral part of these consolidated financial statements.
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Index to Financial Statements
SUNOCO LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per unit data)

| Year Ended December 31,
| 2025 |  | 2024 |  | 2023
REVENUES: |  |  |  |  |
Sales revenue | $ | 23,702 |  |  | $ | 21,588 |  |  | $ | 22,663 |
Service revenue | 1,369 |  |  | 980 |  |  | 254 |
Lease revenue | 130 |  |  | 125 |  |  | 151 |
Total revenues | 25,201 |  |  | 22,693 |  |  | 23,068 |
COSTS AND EXPENSES: |  |  |  |  |
Cost of sales (excluding items shown separately below) | 22,409 |  |  | 20,595 |  |  | 21,703 |
Operating expenses | 765 |  |  | 545 |  |  | 356 |
General and administrative | 296 |  |  | 277 |  |  | 126 |
Lease expense | 114 |  |  | 72 |  |  | 68 |
(Gain) loss on disposal of assets and impairment charges | (6) |  |  | 45 |  |  | (7) |
Depreciation, amortization and accretion | 688 |  |  | 368 |  |  | 187 |
Total cost of sales and operating expenses | 24,266 |  |  | 21,902 |  |  | 22,433 |
OPERATING INCOME | 935 |  |  | 791 |  |  | 635 |
OTHER INCOME (EXPENSE): |  |  |  |  |
Interest expense, net | (541) |  |  | (391) |  |  | (217) |
Equity in earnings of unconsolidated affiliates | 143 |  |  | 60 |  |  | 5 |
Gain on West Texas Sale | — |  |  | 586 |  |  | — |
Loss on extinguishment of debt | (31) |  |  | (2) |  |  | — |
Other, net | 83 |  |  | 5 |  |  | 7 |
INCOME BEFORE INCOME TAXES | 589 |  |  | 1,049 |  |  | 430 |
Income tax expense | 62 |  |  | 175 |  |  | 36 |
NET INCOME | 527 |  |  | 874 |  |  | 394 |
Less: Net income attributable to noncontrolling interests | — |  |  | 8 |  |  | — |
NET INCOME ATTRIBUTABLE TO PARTNERS | 527 |  |  | 866 |  |  | 394 |
Less: Preferred unitholders’ interest in net income | 34 |  |  | — |  |  | — |
Less: Class D unitholder’s interest in net income (loss) | (9) |  |  | — |  |  | — |
NET INCOME ATTRIBUTABLE TO COMMON UNITS | $ | 502 |  |  | $ | 866 |  |  | $ | 394 |
NET INCOME PER COMMON UNIT |  |  |  |  |
Common units - basic | $ | 2.29 |  |  | $ | 6.04 |  |  | $ | 3.70 |
Common units - diluted | $ | 2.28 |  |  | $ | 6.00 |  |  | $ | 3.65 |
WEIGHTED AVERAGE COMMON UNITS OUTSTANDING |  |  |  |  |
Common units - basic | 136,492,204 |  |  | 118,529,390 |  |  | 84,081,083 |
Common units - diluted | 137,198,218 |  |  | 119,342,038 |  |  | 85,093,497 |
CASH DISTRIBUTION PER COMMON UNIT | $ | 3.6583 |  |  | $ | 3.5133 |  |  | $ | 3.3680 |

The accompanying notes are an integral part of these consolidated financial statements.
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SUNOCO LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions, except per unit data)

| Year Ended December 31,
| 2025 |  | 2024 |  | 2023
Net income | $ | 527 |  |  | $ | 874 |  |  | $ | 394 |
Other comprehensive income (loss), net of tax |  |  |  |  |
Foreign currency translation adjustment | 1 |  |  | (1) |  |  | — |
Actuarial gain (loss) related to pension and other postretirement benefit plans | (3) |  |  | 3 |  |  | — |
| (2) |  |  | 2 |  |  | — |
Comprehensive income | 525 |  |  | 876 |  |  | 394 |
Less: Comprehensive income attributable to noncontrolling interests | — |  |  | 8 |  |  | — |
Less: Comprehensive income attributable to Preferred unitholders | 34 |  |  | — |  |  | — |
Less: Comprehensive loss attributable to Class D unitholder | (9) |  |  | — |  |  | — |
Comprehensive income attributable to common units | $ | 500 |  |  | $ | 868 |  |  | $ | 394 |

The accompanying notes are an integral part of these consolidated financial statements.
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SUNOCO LP
CONSOLIDATED STATEMENTS OF EQUITY
(Dollars in millions)

| Common Unitholders |  | Class D Unitholder |  | Series A Preferred Unitholders |  | Accumulated Other Comprehensive Income |  | Noncontrolling Interest |  | Total
Balance at December 31, 2022 | $ | 942 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 942 |
Cash distribution to unitholders, including incentive distributions | (371) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (371) |
Unit-based compensation | 17 |  |  | — |  |  | — |  |  | — |  | — |  |  | 17 |
Other | (4) |  |  | — |  |  | — |  |  | — |  | — |  |  | (4) |
Net income | 394 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 394 |
Balance at December 31, 2023 | 978 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 978 |
Cash distributions to unitholders, including incentive distributions | (566) |  |  | — |  |  | — |  |  | — |  |  | (8) |  |  | (574) |
Unit-based compensation | 17 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 17 |
Other comprehensive income, net of tax | — |  |  | — |  |  | — |  |  | 2 |  |  | — |  |  | 2 |
NuStar Acquisition | 2,850 |  |  | — |  |  | — |  |  | — |  |  | 801 |  |  | 3,651 |
Preferred unit redemption | 17 |  |  | — |  |  | — |  |  | — |  |  | (801) |  |  | (784) |
Common control transaction | (83) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (83) |
Other | (13) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (13) |
Net income | 866 |  |  | — |  |  | — |  |  | — |  |  | 8 |  |  | 874 |
Balance at December 31, 2024 | 4,066 |  |  | — |  |  | — |  |  | 2 |  |  | — |  |  | 4,068 |
Cash distributions to unitholders, including incentive distributions | (657) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (657) |
Unit-based compensation | 19 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 19 |
Other comprehensive loss, net of tax | — |  |  | — |  |  | — |  |  | (2) |  |  | — |  |  | (2) |
Parkland Acquisition | — |  |  | 2,547 |  |  | — |  |  | — |  |  | — |  |  | 2,547 |
Preferred unit issuance | — |  |  | — |  |  | 1,473 |  |  | — |  |  | — |  |  | 1,473 |
Units issued in other acquisitions | 18 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 18 |
Other | 22 |  |  | — |  |  | — |  |  | (6) |  |  | — |  |  | 16 |
Net income (loss) | 502 |  |  | (9) |  |  | 34 |  |  | — |  |  | — |  |  | 527 |
Balance at December 31, 2025 | $ | 3,970 |  |  | $ | 2,538 |  |  | $ | 1,507 |  |  | $ | (6) |  |  | $ | — |  |  | $ | 8,009 |

The accompanying notes are an integral part of these consolidated financial statements.
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SUNOCO LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)

|  | Year Ended December 31,
|  | 2025 |  | 2024 |  | 2023
OPERATING ACTIVITIES: |  |  |  |  |  |
Net income |  | $ | 527 |  |  | $ | 874 |  |  | $ | 394 |
Reconciliation of net income to net cash provided by operating activities: |  |  |  |  |  |
Depreciation, amortization and accretion |  | 688 |  |  | 368 |  |  | 187 |
Amortization of deferred financing fees |  | 27 |  |  | 24 |  |  | 8 |
(Gain) loss on disposal of assets and impairment charges |  | (6) |  |  | 45 |  |  | (7) |
Loss on extinguishment of debt |  | 31 |  |  | 2 |  |  | — |
Gain on West Texas Sale |  | — |  |  | (586) |  |  | — |
Other non-cash, net |  | 40 |  |  | (7) |  |  | — |
Non-cash unit-based compensation expense |  | 19 |  |  | 17 |  |  | 17 |
Deferred income tax expense (benefit) |  | 38 |  |  | (14) |  |  | 13 |
Inventory valuation adjustments |  | 156 |  |  | 86 |  |  | 114 |
Equity in earnings of unconsolidated affiliates |  | (143) |  |  | (60) |  |  | (5) |
Distribution from unconsolidated affiliates |  | 196 |  |  | — |  |  | — |
Net change in operating assets and liabilities, net of effects of acquisitions and divestitures |  | (381) |  |  | (200) |  |  | (121) |
Net cash provided by operating activities |  | 1,192 |  |  | 549 |  |  | 600 |
INVESTING ACTIVITIES: |  |  |  |  |  |
Capital expenditures |  | (577) |  |  | (344) |  |  | (215) |
Parkland Acquisition, net of cash acquired |  | (2,004) |  |  | — |  |  | — |
NuStar Acquisition, net of cash acquired |  | — |  |  | 27 |  |  | — |
Cash paid for other acquisitions |  | (253) |  |  | (224) |  |  | (111) |
Contributions to unconsolidated affiliate |  | (73) |  |  | — |  |  | — |
Proceeds from West Texas Sale |  | — |  |  | 987 |  |  | — |
Distributions from unconsolidated affiliates in excess of cumulative earnings |  | 72 |  |  | 8 |  |  | 9 |
Proceeds from disposal of property, plant and equipment |  | 28 |  |  | 23 |  |  | 31 |
Other |  | — |  |  | — |  |  | (2) |
Net cash provided by (used in) investing activities |  | (2,807) |  |  | 477 |  |  | (288) |
FINANCING ACTIVITIES: |  |  |  |  |  |
Senior notes borrowings |  | 2,900 |  |  | 1,500 |  |  | 500 |
Senior notes repayments |  | (600) |  |  | (421) |  |  | — |
GoZone bond repayment |  | (75) |  |  | — |  |  | — |
GoZone bond remarketing |  | 75 |  |  | — |  |  | — |
Credit Facility borrowings |  | 2,081 |  |  | 2,786 |  |  | 3,283 |
Credit Facility repayments |  | (2,284) |  |  | (3,449) |  |  | (3,772) |
Parkland credit facility repayment |  | (444) |  |  | — |  |  | — |
Loan origination costs |  | (57) |  |  | (19) |  |  | (5) |
Series A Preferred Units issuance |  | 1,473 |  |  | — |  |  | — |
Preferred units redemption |  | — |  |  | (784) |  |  | — |
Cash distributions to unitholders, including incentive distributions |  | (657) |  |  | (566) |  |  | (371) |
Cash distributions to noncontrolling interests |  | — |  |  | (8) |  |  | — |
Net cash provided by (used in) financing activities |  | 2,412 |  |  | (961) |  |  | (365) |
Net increase (decrease) in cash and cash equivalents |  | 797 |  |  | 65 |  |  | (53) |
Cash and cash equivalents, beginning of period |  | 94 |  |  | 29 |  |  | 82 |
Cash and cash equivalents, end of period |  | $ | 891 |  |  | $ | 94 |  |  | $ | 29 |

The accompanying notes are an integral part of these consolidated financial statements.
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SUNOCO LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular dollar amounts, except per unit data, are in millions)
1.Organization and Principles of Consolidation
As used in this document, the terms “Partnership,” “Sunoco,” “we,” “us” and “our” should be understood to refer to Sunoco LP and our consolidated subsidiaries, unless the context clearly indicates otherwise.
We are a Delaware master limited partnership. We are managed by our General Partner, which is owned by Energy Transfer. As of December 31, 2025, Energy Transfer and its subsidiaries owned 100% of the membership interest in our General Partner, 28,463,967 of our common units and all of our IDRs. In addition, Energy Tra nsfer controls SunocoCorp, which owns all of the outstanding Class D Units and currently holds the rights to appoint and remove members of our General Partner.
We are primarily engaged in energy infrastructure and distribution of motor fuels across 32 countries and territories in North America, the Greater Caribbean and Europe. Our midstream operations include an extensive network of over 14,000 miles of pipeline and over 160 terminals. Our fuel distribution operations distribute over 15 billion gallons annually to approximately 11,000 Sunoco and partner branded locations, as well as independent dealers and commercial customers.
The consolidated financial statements of Sunoco presented herein for the years ended December 31, 2025, 2024 and 2023, have been prepared in accordance with GAAP and pursuant to the rules and regulations of the SEC. We consolidate all wholly owned subsidiaries. All significant intercompany transactions and accounts are 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.
Certain prior period amounts have been reclassified to conform to the current period presentation. These reclassifications had no impact on net income, total equity or cash flows.
2.Summary of Significant Accounting Policies
Use of Estimates
The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Fair Value Measurements
We use fair value measurements to measure, among other items, purchased assets, investments, leases and derivative contracts. We also use them to assess impairment of properties, equipment, intangible assets and goodwill. An asset’s fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. A liability’s fair value is defined as the amount that would be paid to transfer the liability to a new obligor, not the amount that would be paid to settle the liability with the creditor. Where available, fair value is based on observable market prices or parameters, or is derived from such prices or parameters. Where observable prices or inputs are not available, unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.
ASC 820 “Fair Value Measurements and Disclosures” prioritizes the inputs used in measuring fair value into the following hierarchy:
Level 1 Quoted prices (unadjusted) in active markets for identical assets or liabilities;
Level 2 Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable;
Level 3 Unobservable inputs in which little or no market activity exists, therefore requiring an entity to develop its own assumptions about the assumptions that market participants would use in pricing.
Cash, accounts receivable, certain other current assets, marketable securities, accounts payable, accrued expenses and certain other current liabilities are reflected in the consolidated balance sheets at carrying amounts, which approximate the fair value due to their short term nature.
Segment Reporting
We operate our business in four reportable segments: Fuel Distribution, Pipeline Systems, Terminals and Refinery. Our Fuel Distribution segment supplies motor fuel to independently-operated dealer stations, distributors, commission agents and other
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consumers. Also included in our Fuel Distribution segment is lease income from properties that we lease or sublease, as well as the Partnership’s credit card services, franchise royalties and retail operations. Our Pipeline Systems segment includes an integrated pipeline and terminal network comprised of refined product, c rude oil and ammonia pipelines and terminals, including our investments in the J.C. Nolan and ET-S Permian joint ventures. Our Terminals segment is composed of four transmix processing facilities and 83 refined product terminals (two in Europe, six in Hawaii, nine in Canada and 53 in the continental United States). Our Refinery segment is composed of the Burnaby Refinery, which is responsible for the refining of fuel products and engaged in renewable business activities.
Acquisition Accounting
Acquisitions of assets or entities that include inputs and processes and have the ability to create outputs are accounted for as business combinations. A purchase price allocation is recorded for tangible and intangible assets acquired and liabilities assumed based on their fair value. The excess of fair value of consideration conveyed over fair value of net assets acquired is recorded as goodwill. The consolidated statements of operations and comprehensive income for the periods presented include the results of operations for each acquisition from their respective dates of acquisition.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand, demand deposits and short-term investments with original maturities of three months or less.
Sunoco, LLC and Sunoco Retail have treasury services agreements with Energy Transfer (R&M), LLC, an indirect wholly owned subsidiary of Energy Transfer, for certain cash management activities, for which the net balance is reflected in either “Advances to affiliates” or “Advances from affiliates” on the consolidated balance sheets.
Accounts Receivable
The majority of trade receivables are from wholesale fuel customers or from credit card companies related to retail credit card transactions. Wholesale customer credit is extended based on an evaluation of the customer’s financial condition. We maintain allowances for expected credit losses based on the best estimate of the amount of expected credit losses in existing accounts receivable. Credit losses are recorded against the allowance when accounts are deemed uncollectible.
Receivables from affiliates arise from fuel sales and other miscellaneous transactions with non-consolidated affiliates. These receivables are recorded at face value, without interest or discount.
7-Eleven, Inc. is the only third-party dealer or distributor which is individually over 10% of our Fuel Distribution segment or individually over 10%, in terms of revenue, of our aggregate business.
Inventories
Fuel inventories, other than in the Caribbean, are stated at the lower of cost or market using the LIFO method. Under this methodology, the cost of fuel sold consists of actual acquisition costs, which includes transportation and storage costs. Such costs are adjusted to reflect increases or decreases in inventory quantities which are valued based on changes in LIFO inventory layers.
Fuel inventories in the Caribbean are stated at the lower of cost or market using the FIFO method. Under this methodology, the cost of fuel sold consists of older acquisition costs, which includes transportation and storage costs.
Merchandise inventories are stated at the lower of average cost, as determined by the retail inventory method, or market. We record an allowance for shortages and obsolescence relating to merchandise inventory based on historical trends and any known changes. Shipping and handling costs are included in the cost of merchandise inventories.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost. Depreciation is computed on a straight-line basis over the useful lives of assets. Assets under finance leases are depreciated over the life of the corresponding lease.
Amortization of leasehold improvements is based upon the shorter of the remaining terms of the leases including renewal periods that are reasonably assured, or the estimated useful lives. Expenditures for major renewals and betterments that extend the useful lives of property, plant and equipment are capitalized. Maintenance and repairs are charged to operations as incurred. Gains or losses on the disposition of property, plant and equipment are recorded in the period incurred.
Long-Lived Assets and Assets Held for Sale
Long-lived assets are tested for possible impairment whenever events or changes in circumstances indicate the carrying amount of the asset may not be recoverable. If such indicators exist, the estimated undiscounted future cash flows related to the asset are compared to the carrying value of the asset. If the carrying value is greater than the estimated undiscounted future cash flows, an impairment charge is recorded in the consolidated statements of operations and comprehensive income for amounts necessary to
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reduce the corresponding carrying value of the asset to fair value. The impairment loss calculations require management to apply judgment in estimating future cash flows.
Properties that have been closed and other excess real property are recorded as assets held for sale, and are written down to the lower of cost or estimated net realizable value at the time we close such stores or determine that these properties are in excess and intend to offer them for sale. We estimate the net realizable value based on our experience in utilizing or disposing of similar assets and on estimates provided by our own and third-party real estate experts. Although we have not experienced significant changes in our estimate of net realizable value, changes in real estate markets could significantly impact the net values realized from the sale of assets.
Goodwill and Indefinite-Lived Intangible Assets
Goodwill represents the excess of consideration paid over fair value of net assets acquired. Goodwill and intangible assets acquired in a purchase business combination are recorded at fair value as of the date acquired. Acquired intangible assets determined to have an indefinite useful life are not amortized, but are instead tested for impairment at least annually, or more frequently if events and circumstances indicate that the asset might be impaired. The annual impairment test of goodwill and indefinite lived intangible assets is performed as of the first day of the fourth quarter of each fiscal year.
The Partnership uses qualitative factors to determine whether it is more likely than not (likelihood of more than 50%) that the fair value of a reporting unit exceeds its carrying amount, including goodwill. Some of the qualitative factors considered in applying this test include consideration of macroeconomic conditions, industry and market conditions, cost factors affecting the business, overall financial performance of the business and performance of the unit price of the Partnership.
If qualitative factors are not deemed sufficient to conclude that the fair value of the reporting unit more likely than not exceeds its carrying value, then a quantitative approach is applied in making an evaluation. The quantitative evaluation utilizes multiple valuation methodologies, including a market approach (market price multiples of comparable companies), an income approach (discounted cash flow analysis), or a weighted combination of these methods. The computations require management to make significant estimates and assumptions, including, among other things, selection of comparable publicly traded companies, the discount rate applied to future earnings reflecting a weighted average cost of capital and earnings growth assumptions. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. A discounted cash flow analysis requires management to make various assumptions about future sales, operating margins, capital expenditures, working capital and growth rates. Cash flow projections are derived from one-year budgeted amounts plus an estimate of later period cash flows, all of which are determined by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determined the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three-year average. In addition, the Partnership estimated a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business. If the evaluation results in the fair value of the reporting unit being lower than the carrying value, an impairment charge is recorded.
Indefinite-lived intangible assets are composed of certain tradenames and liquor licenses which are not amortized but are evaluated for impairment annually or more frequently if events or changes occur that suggest an impairment in carrying value, such as a significant adverse change in the business climate. Indefinite-lived intangible assets are evaluated for impairment by comparing each asset’s fair value to its book value. Management first determines qualitatively whether it is more likely than not that an indefinite‑lived asset is impaired. If management concludes that it is more likely than not that an indefinite-lived asset is impaired, then its fair value is determined by using the discounted cash flow model based on future revenues estimated to be derived in the use of the asset.
Other Intangible Assets
Other finite-lived intangible assets consist of supply agreements, customer relations, non-compete agreements and loan origination costs. Separable intangible assets that are not determined to have an indefinite life are amortized over their useful lives and assessed for impairment only if and when circumstances warrant. Determination of an intangible asset’s fair value and estimated useful life are based on an analysis of pertinent factors including: (1) the use of widely-accepted valuation approaches, such as the income approach or the cost approach, (2) the expected use of the asset by the Partnership, (3) the expected useful life of related assets, (4) any legal, regulatory or contractual provisions, including renewal or extension periods that would cause substantial costs or modifications to existing agreements and (5) the effects of obsolescence, demand, competition and other economic factors. Should any of the underlying assumptions indicate that the value of the intangible assets might be impaired, we may be required to reduce the carrying value and remaining useful life of the asset. If the underlying assumptions governing the amortization of an intangible asset were later determined to have significantly changed, we may be required to adjust its
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amortization period to reflect a new estimate of its useful life. Any write-down of the value or unfavorable change in the useful life of an intangible asset would increase expense at that time.
Customer relations and supply agreements are amortized on a straight-line basis over the remaining terms of the agreements, which generally range from five to 20 years. Non-compete agreements are amortized over the terms of the respective agreements.
Investments in Unconsolidated Affiliates
We own interests in a number of related businesses, including joint ventures with Energy Transfer, that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other-than-temporary.
Asset Retirement Obligations
The estimated future cost to remove an underground storage tank is recognized over the estimated useful life of the storage tank. We record a discounted liability for the future fair value of an asset retirement obligation along with a corresponding increase to the carrying value of the related long-lived asset at the time an underground storage tank is installed. We then depreciate the amount added to property, plant and equipment and recognize accretion expense in connection with the discounted liability over the remaining life of the tank. We base our estimates of the anticipated future costs for tank removal on our prior experience with removals. We review assumptions for computing the estimated liability for tank removal on an annual basis. Any change in estimated cash flows are reflected as an adjustment to both the liability and the associated asset.
Long-lived assets related to asset retirement obligations aggregated $178 million and $12 million as of December 31, 2025 and 2024, respectively, and were reflected as property, plant and equipment, net, on our consolidated balance sheets.
Environmental Liabilities
Environmental expenditures related to existing conditions, resulting from past or current operations and from which no current or future benefit is discernible, are expensed. Expenditures that extend the life of the related property or prevent future environmental contamination are capitalized. We determine and establish a liability on a site-by-site basis when future environmental expenditures are probable and can be reasonably estimated. A related receivable is recorded for estimable and probable reimbursements.
Revenue Recognition
Revenues from our Fuel Distribution segment are derived from the sale of fuel, non-fuel and lease income. Fuel sales consist primarily of the sale of motor fuel under supply agreements with third-party customers and affiliates. Fuel supply contracts with our customers generally provide that we distribute motor fuel at a price based on a formula which includes published rates, volume-based profit margin and other terms specific to the agreement. The customer is invoiced the agreed-upon price with most payment terms ranging less than 30 days. If the consideration promised in a contract includes a variable amount, the Partnership estimates the variable consideration amount and factors in such estimate to determine the transaction price under the expected value method. Revenue is recognized under the motor fuel contracts at the point in time the customer takes control of the fuel. At the time control is transferred to the customer the sale is considered final, because the agreements do not grant customers the right to return motor fuel. To determine when control transfers to the customer, the shipping terms of the contract are assessed as a primary indicator of the transfer of control. For free on board (“FOB”) shipping point terms, revenue is recognized at the time of shipment. The performance obligation with respect to the sale of goods is satisfied at the time of shipment since the customer gains control at this time under the terms. Shipping and/or handling costs that occur before the customer obtains control of the goods are deemed to be fulfillment activities and are accounted for as fulfillment costs. Once the goods are shipped, the Partnership is precluded from redirecting the shipment to another customer and revenue is recognized. Non-fuel revenue includes merchandise revenue that comprises the in-store merchandise and food service sales at company-operated retail stores and other revenue such as credit card processing, car washes, lottery and other services. Lease revenue is derived from leasing arrangements for which we are the lessor and recognized ratably over the term of the underlying lease.
Revenues from our Pipeline Systems 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 from our Terminals 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 and throughput agreements, under which a customer pays a fee per barrel for volumes moving through our terminals. Our terminals also provide blending, additive injections, handling and filtering services for which we charge additional fees.
Revenues from our Refinery segment are derived from refined products, generated environmental compliance credits and excess crude oil sales are recognized when delivered and the customer obtains control of such inventory, which is typically when title
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passes and the customer is billed. All revenues are reported inclusive of shipping and handling costs billed and exclusive of any sales taxes billed to customers where applicable. Shipping and handling costs incurred are reported in cost of sales.
Lease Income
Lease income from leasing or subleasing of real estate is recognized on a straight-line basis over the term of the lease.
Cost of Sales
We include in cost of sales all costs incurred to acquire fuel and merchandise, including the costs of purchasing, storing and transporting inventory prior to delivery to our customers. Items are removed from inventory and are included in cost of sales based on the retail inventory method for merchandise and the LIFO method for motor fuel. Cost of sales does not include depreciation of property, plant and equipment. Depreciation is classified within operating expenses in the consoli dated statements of operations and comprehensive income.
Motor Fuel and Sales Taxes
Certain motor fuel and sales taxes are collected from customers and remitted to governmental agencies either directly by the Partnership or through suppliers. The Partnership’s accounting policy for wholesale direct sales to dealers, distributors and commercial customers is to exclude the collected motor fuel tax from sales and cost of sales.
For retail locations where the Partnership holds inventory, including commission agent locations, motor fuel sales and motor fuel cost of sales include motor fuel taxes. Such amounts were $261 million, $164 million and $274 million for the years ended December 31, 2025, 2024 and 2023, respectively. Merchandise sales and cost of merchandise sales are reported net of sales tax in our consolidated statements of operations and comprehensive income.
Deferred Branding Incentives
We receive payments for branding incentives related to fuel supply contracts. Unearned branding incentives are deferred and amortized on a straight-line basis over the term of the agreement as a credit to cost of sales.
Lease Accounting
At the inception of each lease arrangement, we determine if the arrangement is a lease or contains an embedded lease and review the facts and circumstances of the arrangement to classify lease assets as operating or finance leases under Topic 842. The Partnership has elected not to record any leases with terms of 12 months or less on our consolidated balance sheets.
Balances related to operating leases are included in operating lease right-of-use assets, net, operating lease current liabilities and non-current operating lease liabilities on our consolidated balance sheets. Finance leases represent a small portion of the active lease agreements and are included in other non-current assets and long-term debt, net on our consolidated balance sheets. The right-of-use assets represent the Partnership’s right to use an underlying asset for the lease term and lease liabilities represent the obligation of the Partnership to make minimum lease payments arising from the lease for the duration of the lease term.
The Partnership leases a portion of its properties under non-cancelable operating leases, whose initial terms are typically five to 15 years, with options permitting renewal for additional periods. Most leases include one or more options to renew, with renewal terms that can extend the lease term from five to 10 years or greater. The exercise of lease renewal options is typically at the sole discretion of the Partnership and lease extensions are evaluated on a lease-by-lease basis. Leases containing early termination clauses typically require the agreement of both parties to the lease. At the inception of a lease, all renewal options reasonably certain to be exercised are considered when determining the lease term. The depreciable life of lease assets and leasehold improvements are limited by the expected lease term.
To determine the present value of future minimum lease payments, we use the implicit rate when readily determinable. Presently, because many of our leases do not provide an implicit rate, the Partnership applies its incremental borrowing rate based on the information available at the lease commencement date to determine the present value of minimum lease payments. The operating and finance lease right-of-use assets include any lease payments made and exclude lease incentives.
Minimum rent is expensed on a straight-line basis over the term of the lease, including renewal periods that are reasonably assured at the inception of the lease. The Partnership is typically responsible for payment of real estate taxes, maintenance expenses and insurance.
For short-term leases (leases that have term of 12 months or less upon commencement), lease payments are recognized on a straight-line basis and no right-of-use assets are recorded.
Earnings Per Unit
In addition to limited partner units, we have IDRs as participating securities and compute net income per common unit using the two-class method under which any excess of distributions declared over net income shall be allocated to the partners based on
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their respective sharing of income specified in the Partnership Agreement. Net income per unit applicable to limited partners is computed by dividing limited partners’ interest in net income, after deducting any incentive distributions and distributions on unvested phantom unit awards, by the weighted average number of outstanding common units.
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 of our control.
Unit-Based Compensation
Under the Partnership's long-term incentive plans, various types of awards may be granted to employees, consultants and directors of our General Partner who provide services for us. Compensation expense related to outstanding awards is recognized over the vesting period based on the grant-date fair value. The grant-date fair value is determined based on the market price of our common units on the grant date. We amortize the grant-date fair value of these awards over their vesting period using the straight-line method. Expenses related to unit-based compensation are included in general and administrative expenses.
Foreign Currency Translation
The functional currencies of our foreign subsidiaries are the local currencies of the countries in which the subsidiaries are located. Transactions in foreign currencies are translated to the respective functional currencies at the exchange rates applicable on the dates of the transactions. Monetary assets and liabilities denominated in foreign currencies are translated to the appropriate functional currency at the exchange rate at the consolidated balance sheet date. Foreign exchange gains and losses are recorded in the consolidated statements of income (loss). Non-monetary assets and liabilities denominated in foreign currencies are measured at cost using the exchange rates on the dates of initial recognition.
On consolidation, the financial statements of foreign operations are translated to U.S. dollars. The assets and liabilities of foreign operations are translated to U.S. dollars at the exchange rate prevailing at the consolidated balance sheet date. Income and expenses of foreign operations are translated to U.S. dollars at the exchange rates that approximate those on the dates of the transactions. Foreign exchange differences arising on translation for consolidation are recognized in other comprehensive income (loss). The results and financial position of subsidiaries with the functional currencies of hyperinflationary economies, after being restated for the effects of inflation in line with the Partnership’s policy over hyperinflation accounting, are translated to U.S. dollars at the exchange rate prevailing at the consolidated balance sheet date.
In connection with certain internal restructuring transactions subsequent to the Parkland Acquisition, Sunoco and Parkland established an intercompany loan between subsidiaries having different functional currencies. Foreign currency translation gains and losses related to this intercompany loan are recorded in “Other, net” within net income on the Partnership’s consolidated statement of operations.
Income Taxes
The Partnership is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and most state purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial basis of assets and liabilities, differences between the tax accounting and financial accounting treatment of certain items, and due to allocation requirements related to taxable income under our Partnership Agreement. We do not have access to information regarding each partner's individual tax basis in our limited partner interests.
As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income were not to meet this statutory requirement, the Partnership would be taxed as a corporation for federal and state income tax purp oses. For the years ended December 31, 2025, 2024 and 2023, our qualifying income met the statutory requirement.
The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state, local and foreign income taxes. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method.
Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in
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earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.
The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our consolidated financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.
The acquisition of Parkland brought the Partnership into scope for Pillar Two global minimum tax regime, a legislative framework established by Organization for Economic Co-operation and Development (“OECD”), as several jurisdictions in which the Partnership now operates have enacted Pillar Two global minimum tax legislation.
Consistent with ASC 740 and current industry guidance, the Partnership has applied a temporary exception and has not recognized deferred tax assets or liabilities related to Pillar Two tax liability.
The Partnership has elected to account for the tax on global intangible low-taxed income (“GILTI”) under IRC §951A as a period cost in the year the tax is incurred, rather than recognizing deferred taxes on basis differences in its controlled foreign corporations that may give rise to future GILTI inclusions.
Recent Accounting Pronouncements
In November 2024, the FASB issued Accounting Standards Update (“ASU”) 2024-03, Income Statement–Reporting Comprehensive Income–Expense Disaggregation Disclosures (Subtopic 220-40). ASU 2024-03 requires disclosure of specified information about certain costs and expenses in the notes to the consolidated financial statements. ASU 2024-03 is effective for annual periods beginning after December 15, 2026, and interim periods within annual periods beginning after December 15, 2027, with early adoption permitted. ASU 2024-03 is to be applied on a prospective basis, with retrospective application permitted. We are currently evaluating the impact, if any, of ASU 2024-03 on our consolidated financial statements and related disclosures.
In December 2023, FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. ASU 2023-09 improves and enhances income tax disclosure requirements, including new disclosures related to tax rate reconciliation and income taxes paid. The Partnership retrospectively adopted ASU 2023-09 during the year ended December 31, 2025 and has revised its disclosures accordingly, as reflected in Notes 4 and 18.
3.Acquisitions, Divestitures and Other Transactions
Parkland Acquisition
On October 31, 2025, we completed the previously announced acquisition of Parkland, whereby Sunoco Retail, a wholly owned corporate subsidiary of the Partnership, indirectly acquired all the outstanding shares of Parkland, in exchange for cash and SunocoCorp units that were contributed by SunocoCorp to the Partnership at the close of the Parkland Acquisition. Under the terms of the agreement, Parkland shareholders received 0.295 SunocoCorp units and C$19.80 for each Parkland share. Parkland shareholders could elect, in the alternative, to receive C$44.00 per Parkland share in cash or 0.536 SunocoCorp units for each Parkland share, subject to proration to ensure that the aggregate consideration payable in connection with the transaction would not exceed C$19.80 in cash per Parkland share outstanding as of immediately before close and 0.295 SunocoCorp units per Parklan d share outstanding as of immediately before close. In connection with the closing of the Parkland Acquisition, we paid approximately $2.60 billion to Parkland’s shareholders and transferred 51,517,198 SunocoCorp common units, which we had received from SunocoCorp in exchange for our issuance of 51,517,198 Sunoco Class D Un its to SunocoCorp.
Parkland is a leading international fuel distributor, marketer and convenience retailer with operations in 26 countries across the Americas. Parkland’s functional currency is the Canadian dollar, and its consolidated structure includes subsidiaries with multiple other functional currencies.
As part of the transaction, the Partnership repurposed and renamed an existing subsidiary as SunocoCorp. Prior to the Parkland Acquisition, SunocoCorp did not have any significant assets, liabilities or operations; in connection with the Parkland Acquisition, the Partnership deconsolidated SunocoCorp and SunocoCorp became a publicly traded entity classified as a corporation for U.S. federal income tax purposes. SunocoCorp units began trading on the NYSE effective November 6, 2025. Subsequent to the Parkland Acquisition, SunocoCorp holds Sunoco Class D Units, representing limited partnership interests in Sunoco that are generally economically equivalent to Sunoco’s publicly traded common units on the basis of one Sunoco Common Unit for each outstanding SunocoCorp unit. For a period of two years following closing of the transaction, Sunoco will ensure that SunocoCorp unitholders receive distributions on a per unit basis that are equivalent to the per unit distributions to Sunoco unithold ers.
The acquisition was recorded using the acquisition method of accounting which requires, among other things, that assets and liabilities assumed be recognized on the balance sheet at their estimated fair values as of the date of acquisition, with any excess
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purchase price over the fair value of net assets acquired recorded to goodwill. Management, with the assistance of a third-party valuation specialist, determined the fair value of assets and liabilities as of the date of the acquisition. Determining the fair value involves the use of management's judgment as well as the use of significant estimates and assumptions.
As of the date these financial statements were issued, management and the third-party valuation specialist continue to evaluate certain assumptions, which could result in a change to the allocation of the fair value among reporting units or between line items on the consolidated balance sheet, potentially impacting deferred tax balances and/or goodwill. The following table summarizes the preliminary allocation of the purchase price among assets acquired and liabilities assumed.

| As of October 31, 2025
Total current assets | $ | 2,814 |
Property, plant and equipment | 5,612 |
Operating lease right-of-use assets, net | 731 |
Goodwill (1) | 1,528 |
Intangible assets, net (2) | 1,871 |
Deferred tax assets | 210 |
Other non-current assets | 266 |
Investments in unconsolidated affiliates | 341 |
Total assets | 13,373 |
Total current liabilities | 2,490 |
Long-term debt, less current maturities | 3,797 |
Operating lease non-current liabilities | 731 |
Deferred tax liabilities | 965 |
Other non-current liabilities | 375 |
Total liabilities | 8,358 |
Total consideration | 5,015 |
Cash acquired | (464) |
Total consideration, net of cash acquired | $ | 4,551 |

(1)Goodwill represents expected commercial and operational synergies. Approximately $660 million of the goodwill recorded as a result of this transaction is expected to be deductible for IRC Sec. 951A GILTI and foreign earnings and profits purposes. The goodwill is not deductible for non-US jurisdictions.
(2)Intangible assets, net comprised of $1.49 billion of customer relationships, with a remaining weighted average life of approximately 20 years, $297 million of indefinite-lived tradenames, and $85 million of other intangibles with a remaining weighted average life of approximately 10 years.
Expenses Related to the Parkland Acquisition
As a result of the Parkland Acquisition, we recognized $67 million of merger-related expenses for the year ended December 31, 2025, which are included in general and administrative expenses in our consolidated statement of operation s.
TanQuid Acquisition
On January 16, 2026, the Partnership completed the previously announced acquisition of TanQuid for approximately €465 million (approximately $540 million as of January 16, 2026), includ ing approximately €300 million of assumed debt, less approximately €39 million of cash acquired. TanQuid owns and operates 15 fuel terminals in Germany and one fuel terminal in Poland. The transaction was funded using cash on hand and amounts available under the Partnership's Credit Facility. As of the date of this Form 10-K filing, the initial accounting for this business combination is incomplete due to the timing of the close of the acquisition and therefore has not been included herein.
Expenses Related to the TanQuid Acquisition
As a result of the acquisition, Sunoco recognized $3 million of merger-related expenses during the year ended December 31, 2025, which are included in general and administrative expenses in our consolidated statement of operations.
Other Acquisitions
In the first quarter of 2025, Sunoco acquired fuel equipment, motor fuel inventory and supply agreements in two separate transactions for total consideration of approximately $17 million. Aggregate consideration included $12 million in cash and 91,776 newly issued Sunoco Common Units, which had an aggregate acquisition-date fair value of approximately $5 million.
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In the second quarter of 2025, Sunoco acquired a total of 151 fuel distribution consignment sites in three separate transactions for total consideration of approximately $105 million, plus working capital. Aggregate consideration included $92 million in cash and 251,646 newly issued Sunoco Common Units which had an aggregate acquisition-date fair value of approximately $13 million.
In the third quarter of 2025, Sunoco acquired approximately 70 fuel distribution consignment sites and 100 supply agreements in five separate transactions for total cash consideration of approximately $85 million, plus working capital.
In the fourth quarter of 2025, Sunoco acquired a total of 27 fuel distribution consignment sites and 36 dealer sites, as well as commercial customers, in four separate transactions for total cash consideration of approximately $64 million, plus working capital.
These transactions were accounted for as asset acquisitions, and the purchase price was primarily allocated to inventories, property, plant and equipment and other non-current assets.
2024 Acquisitions
NuStar Acquisition
On May 3, 2024, Sunoco completed the acquisition of 100% of the common units of NuStar. Under the terms of the agreement, NuStar common unitholders received 0.400 Sunoco common units for each NuStar common unit. In connection with the acquisition, Sunoco issued approximately 51.5 million common units, which had a fair value of approximately $2.85 billion, assumed debt totaling approximately $3.5 billion, including approximately $56 million of lease related financing obligations, and assumed preferred units with a fair value of approximately $800 million. NuStar has approximately 9,500 miles of pipeline and 63 terminal and storage facilities that store and distribute crude oil, refined products, renewable fuels, ammonia and specialty liquids. The acquisition is expected to diversify the Partnership’s business, increase scale and provide vertical integration, as well as improving the Partnership’s credit profile and enhancing growth.
The acquisition was recorded using the acquisition method of accounting which requires, among other things, that assets and liabilities assumed be recognized on the balance sheet at their estimated fair values as of the date of acquisition, with any excess purchase price over the fair value of net assets acquired recorded to goodwill. Management, with the assistance of a third-party valuation specialist, determined the fair value of assets and liabilities as of the date of the acquisition. Determining the fair value involves the use of management's judgment as well as the use of significant estimates and assumptions.
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The following table summarizes the allocation of the purchase price among assets acquired and liabilities assumed:

| As of May 3, 2024
Total current assets | $ | 186 |
Property, plant and equipment | 6,958 |
Operating lease right-of-use assets, net | 136 |
Goodwill (1) | 16 |
Intangible assets, net (2) | 195 |
Other non-current assets | 127 |
Total assets | 7,618 |
Total current liabilities | 245 |
Long-term debt, less current maturities (3) | 3,500 |
Operating lease non-current liabilities | 136 |
Deferred tax liabilities | 4 |
Other non-current liabilities | 82 |
Total liabilities | 3,967 |
Preferred units (3) | 801 |
Total consideration | 2,850 |
Cash acquired | 27 |
Total consideration, net of cash acquired | $ | 2,823 |

(1)Goodwill primarily represents expected commercial and operational synergies. None of the goodwill recorded as a result of this transaction is deductible for tax purposes. Goodwill of $16 million relates to Sunoco’s Fuel Distribution segment.
(2)Intangible assets, net comprised $151 million of favorable contracts, with a remaining weighted average life of approximately 7 years, and $44 million of customer relationships with a remaining weighted average life of approximately 15 years.
(3)Subsequent to the closing of the NuStar Acquisition, the Partnership redeemed all outstanding NuStar preferred units, totaling $784 million, redeemed NuStar's subordinated notes totaling $403 million and repaid and terminated the NuStar credit facility totaling $455 million.
Subsequent to the NuStar Acquisition, the Partnership purchased a property previously leased by NuStar and cancelled the lease, resulting in an impairment of $50 million based on the value of comparable real property.
Expenses Related to the NuStar Acquisition
As a result of the acquisition, Sunoco recognized $103 million of merger-related expenses during the year ended December 31, 2024, which are included in general and administrative expenses in our consolidated statement of operations.
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Zenith European Terminals Acquisition
On March 13, 2024, Sunoco completed the acquisition of liquid fuels terminals in Amsterdam, Netherlands and Bantry Bay, Ireland from Zenith Energy for €170 million ($185 million), including working capital. The acquisition is expected to supply optimization for the Partnership’s existing East Coast business and continues its focus on growing its portfolio of stable midstream income. The acquisition was recorded using the acquisition method of accounting which requires, among other things, that assets and liabilities assumed be recognized on the balance sheet at their estimated fair values as of the date of acquisition. Management, with the assistance of a third-party valuation specialist, determined the fair value of assets and liabilities as of the date of the acquisition. Determining the fair value involves the use of management's judgment as well as the use of significant estimates and assumptions. The following table summarizes the allocation of the purchase price among assets acquired and liabilities assumed:

| As of March 13, 2024
Other current assets | $ | 6 |
Property, plant and equipment | 204 |
Other non-current assets | 36 |
Deferred tax assets | 6 |
Current liabilities | (14) |
Deferred tax liabilities | (4) |
Other non-current liabilities | (43) |
Net assets | 191 |
Bargain purchase gain | (6) |
Total cash consideration, net of cash acquired | $ | 185 |

Zenith European terminals revenue and net income since the acquisition date to December 31, 2024 included in our consolidated statement of operations were $43 million and $8 million, respectively.
Other Acquisition
On August 30, 2024, Sunoco acquired a terminal in Portland, Maine for approximately $24 million, including working capital. The purchase price was primarily allocated to property, plant and equipment.
West Texas Sale
On April 16, 2024, Sunoco completed the sale of 204 convenience stores located in West Texas, New Mexico and Oklahoma to 7-Eleven, Inc. for approximately $1.0 billion, including customary adjustments for fuel and merchandise inventory. As part of the sale, Sunoco also amended its existing take-or-pay fuel supply agreement with 7-Eleven, Inc. to incorporate additional fuel gross profit. As a result of the sale, the Partnership recorded a $586 million gain ($442 million net of tax).
ET-S Permian
Effective July 1, 2024, Sunoco and Energy Transfer formed ET-S Permian, a joint venture combining their respective crude oil and produced water gathering assets in the Permian Basin. Pursuant to the contribution agreement by and among the Partnership, Sun Pipeline Holdings LLC, NuStar Permian Transportation and Storage LLC, NuStar Permian Crude Logistics LLC, NuStar Permian Holdings LLC, NuStar Logistics, L.P., ET-S Permian Holdings Company LP, ET-S Permian Pipeline Company LLC, ET-S Permian Marketing Company LLC, Energy Transfer LP, and Energy Transfer Crude Marketing, LLC dated July 14, 2024, in a cashless transaction, Sunoco contributed all of its Permian crude oil gathering assets and operations to ET-S Permian. Energy Transfer contributed its Permian crude oil and produced water gathering assets and operations to ET-S Permian. Energy Transfer’s long-haul crude pipeline network that provides transportation of crude oil out of the Permian Basin to Nederland, Houston and Cushing is excluded from ET-S Permian.
ET-S Permian operates more than 5,000 miles of crude oil and water gathering pipelines with crude oil storage capacity in excess of 11 million barrels.
Sunoco holds a 32.5% interest, with Energy Transfer holding the remaining 67.5% interest in ET-S Permian. Energy Transfer serves as the operator of ET-S Permian.
2023 Acquisition
On May 1, 2023, Sunoco completed the acquisition of 16 refined product terminals located across the East Coast and Midwest from Zenith Energy for approximately $111 million, including working capital. The purchase price was primarily allocated to property, plant and equipment.
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Pro Forma Results of Operations
The following unaudited pro forma consolidated results of operations for the year ended December 31, 2025 and 2024 are presented as if the Parkland and NuStar acquisitions and the West Texas Sale had been completed on January 1, 2024.

|  |  | Year Ended December 31,
|  |  |  |  | 2025 |  | 2024
Revenues |  |  |  |  | $ | 41,457 |  |  | $ | 43,696 |
Net income (loss) |  |  |  |  | 313 |  |  | (12) |

The pro forma consolidated results of operations include adjustments to:
•include the results of Parkland and NuStar for all periods presented;
•include incremental expenses associated with the fair value adjustments recorded as a result of applying the acquisition method of accounting for Parkland and NuStar;
•include incremental interest expense related to financing the transactions;
•include $175 million of expenses representing one-time costs associated with completing the transaction;
•adjust for relative changes in ownership resulting from the acquisition;
•exclude the results from the convenience stores sold in the West Texas Sale; and
•exclude the gain on sale and related tax impact related to the West Texas Sale.
The pro forma information is not necessarily indicative of the results of operations that would have occurred had the Parkland Acquisition been made at the beginning of the periods presented or the future results of the combined operations.
Parkland's revenue and net income, excluding intercompany transactions, since the acquisition date to December 31, 2025 included in our consolidated statement of operations were $3.17 billion and $195 million, respectively.
4.Cash And Cash Equivalents
Cash and cash equivalents include cash on hand, demand deposits and short-term investments with original maturities of three months or less.
The net change in operating assets and liabilities, net of effects of acquisitions and divestitures, included in cash flows from operating activities is comprised as follows:

| Year Ended December 31,
| 2025 |  | 2024 |  | 2023
Accounts receivable, net | $ | 212 |  |  | $ | (212) |  |  | $ | 34 |
Accounts receivable from affiliates | — |  |  | 20 |  |  | (5) |
Inventories, net | (275) |  |  | (265) |  |  | (182) |
Other assets | (30) |  |  | 43 |  |  | 47 |
Accounts payable | (255) |  |  | 357 |  |  | (101) |
Accounts payable to affiliates | 129 |  |  | 29 |  |  | 61 |
Accrued expenses and other current liabilities | (86) |  |  | (66) |  |  | 43 |
Other non-current liabilities | (76) |  |  | (106) |  |  | (18) |
| $ | (381) |  |  | $ | (200) |  |  | $ | (121) |

Non-cash investing and financing activities were as follows:

|  | Year Ended December 31,
|  | 2025 |  | 2024 |  | 2023
Non-cash investing and financing activities and supplemental cash flow information: |  |  |  |  |  |
Senior notes redeemed and issued in exchange transaction |  | $ | 3,654 |  |  | $ | — |  |  | $ | — |
Units issued in connection with acquisitions |  | 4,038 |  |  | 2,850 |  |  | — |
Contribution of assets to ET-S Permian |  | — |  |  | 1,159 |  |  | — |
Lease assets obtained in exchange for new lease liabilities |  | 280 |  |  | 3 |  |  | — |
Interest paid |  | 434 |  |  | 339 |  |  | 202 |

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5.Accounts Receivable, net
Accounts receivable, net, consisted of the following:

| December 31, 2025 |  | December 31, 2024
Accounts receivable, trade | $ | 1,686 |  |  | $ | 1,058 |
Credit card receivables | 42 |  |  | 28 |
Other receivables | 286 |  |  | 78 |
Allowance for expected credit losses | (42) |  |  | (2) |
Accounts receivable, net | $ | 1,972 |  |  | $ | 1,162 |

6.Inventories, net
Fuel inventories included balances stated at the lower of cost or market using the LIFO method. As of December 31, 2025 and 2024, the Partnership’s fuel inventory balance included lower of cost or market reserves of $472 million and $316 million, respectively. For the years ended December 31, 2025, 2024 and 2023, the Partnership’s consolidated statements of operations and comprehensive income did not include any material amounts of income from the liquidation of LIFO fuel inventory. For the years ended December 31, 2025, 2024 and 2023, the Partnership’s cost of sales included unfavorable LIFO inventory adjustments of $156 million, $86 million and $114 million, respectively, which decreased net income.
Inventories, net consisted of the following:

| December 31, 2025 |  | December 31, 2024
Fuel | $ | 2,178 |  |  | $ | 1,054 |
Other | 205 |  |  | 14 |
Inventories, net | $ | 2,383 |  |  | $ | 1,068 |

The Partnership’s fuel inventories in the Caribbean, which tot aled $88 million at December 31, 2025, are stated at the lower of cost or market using the FIFO method. Under this methodology, the cost of fuel sold consists of older acquisition costs, which includes transportation and storage costs.
7.Investments in Unconsolidated Affiliates
Description of Investments
The following is a summary of the Partnership’s significant unconsolidated investments:
J.C. Nolan
Sunoco owns a 50% interest in J.C. Nolan, which provides diesel fuel storage in Midland, Texas with storage capacity of 130,000 barrels and transports diesel fuel from a tank farm in Hebert, Texas to Midland, Texas, on a 500 mile pipeline with a throughput capacity of approximately 36 thousand barrels per day.
ET-S Permian
Sunoco owns a 32.5% interest in ET-S Permian, which operates more than 5,000 miles of crude oil and water gathering pipelines with crude oil storage capacity in excess of 11 million barrels.
SARA
Sunoco owns a 29% interest in SARA, which is a refinery based in Martinique with operations to sell refined crude oil in Guadeloupe, French Guiana and Martinique.
Isla
Sunoco owns a 50% interest in Isla, which is comprised of over 200 retail locations alongside an integrated commercial and aviation business in Dominican Republic.
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Summary of Balances Related to Unconsolidated Affiliates
The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2025 and 2024 were as follows:

|  | December 31, 2025 |  | December 31, 2024
J.C. Nolan |  | $ | 121 |  |  | $ | 123 |
ET-S Permian |  | 1,161 |  |  | 1,212 |
SARA |  | 141 |  |  | — |
Isla |  | 171 |  |  | — |
Other |  | 30 |  |  | — |
|  | $ | 1,624 |  |  | $ | 1,335 |

The following table presents equity in earnings (losses) of unconsolidated affiliates:

|  | Year Ended December 31,
|  | 2025 |  | 2024 |  | 2023
J.C. Nolan |  | $ | 7 |  |  | $ | 7 |  |  | $ | 5 |
ET-S Permian |  | 134 |  |  | 53 |  |  | — |
SARA |  | 1 |  |  | — |  |  | — |
Isla |  | 2 |  |  | — |  |  | — |
Other |  | (1) |  |  | — |  |  | — |
|  | $ | 143 |  |  | $ | 60 |  |  | $ | 5 |

Summarized Financial Information
The following tables present aggregated selected balance sheet and income statement data for Sunoco’s unconsolidated affiliates: J.C. Nolan, ET-S Permi an, SARA and Isla (o n a 100% basis), for all periods presented:

|  | December 31, 2025 |  | December 31, 2024
Current assets |  | $ | 511 |  |  | $ | 650 |
Property, plant and equipment, net |  | 3,912 |  |  | 3,542 |
Other assets |  | 361 |  |  | 310 |
Total assets |  | $ | 4,784 |  |  | $ | 4,502 |
Current liabilities |  | $ | 375 |  |  | $ | 477 |
Non-current liabilities |  | 159 |  |  | 49 |
Equity |  | 4,250 |  |  | 3,976 |
Total liabilities and equity |  | $ | 4,784 |  |  | $ | 4,502 |

|  | Year Ended December 31,
|  | 2025 |  | 2024 |  | 2023
Revenues |  | $ | 21,022 |  |  | $ | 8,267 |  |  | $ | 34 |
Operating income |  | 444 |  |  | 176 |  |  | 10 |
Net income |  | 437 |  |  | 176 |  |  | 10 |

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8.Property, Plant and Equipment, net
Components and useful lives of property, plant and equipment, net consisted of the following:

| December 31, 2025 |  | December 31, 2024
Land and improvements | $ | 2,081 |  |  | $ | 739 |
Buildings, equipment and leasehold improveme nts (1 to 40 years) | 4,695 |  |  | 1,315 |
Pipel ines (5 to 65 years) | 3,747 |  |  | 3,553 |
Product storage and related faciliti es (2 to 40 years) | 1,400 |  |  | 891 |
Right of w ay (20 to 65 years) | 1,728 |  |  | 1,727 |
Oth er (1 to 48 years) | 727 |  |  | 403 |
Construction work-in-process | 878 |  |  | 286 |
Total property, plant and equipment | 15,256 |  |  | 8,914 |
Less – Accumulated depreciation | 1,848 |  |  | 1,240 |
Property, plant and equipment, net | $ | 13,408 |  |  | $ | 7,674 |

Depreciation expense on property, plant and equipment was $638 million, $326 million and $139 million for the years ended December 31, 2025, 2024 and 2023, respectively.
9.Goodwill and Intangible Assets, net
Goodwill
Goodwill balances and activity for the years ended December 31, 2025 and 2024 consisted of the following:

| Segment |  |
| Fuel Distribution |  | Pipeline Systems |  | Terminals |  | Refinery |  | Consolidated
| (in millions)
Balance at December 31, 2023 | $ | 1,362 |  |  | $ | — |  |  | $ | 237 |  |  | $ | — |  |  | $ | 1,599 |
West Texas Sale | (138) |  |  | — |  |  | — |  |  | — |  |  | (138) |
NuStar Acquisition | 16 |  |  | — |  |  | — |  |  | — |  |  | 16 |
Balance at December 31, 2024 | 1,240 |  |  | — |  |  | 237 |  |  | — |  |  | 1,477 |
Parkland Acquisition | 1,070 |  |  | 38 |  |  | — |  |  | 420 |  |  | 1,528 |
Other | 15 |  |  | — |  |  | — |  |  | 6 |  |  | 21 |
Balance at December 31, 2025 | $ | 2,325 |  |  | $ | 38 |  |  | $ | 237 |  |  | $ | 426 |  |  | $ | 3,026 |

The Partnership determines the fair value of our reporting units using the discounted cash flow method, the guideline company method, or a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determines fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determines the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimates a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business. The fair value estimates used in the long-lived asset and goodwill tests were primarily based on Level 3 inputs of the fair value hierarchy.
During the fourth quarters of 2025, 2024 and 2023, we performed our annual impairment testing. No goodwill impairment was identified for the reporting units as a result of these tests.
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Index to Financial Statements
Intangible Assets, net
Gross carrying amounts and accumulated amortization for each major class of intangible assets, excluding goodwill, consisted of the following:

| December 31, 2025 |  | December 31, 2024
| Gross Carrying Amount |  | Accumulated Amortization |  | Net Book Value |  | Gross Carrying Amount |  | Accumulated Amortization |  | Net Book Value
Indefinite-lived |  |  |  |  |  |  |  |  |  |  |
Tradenames | $ | 606 |  |  | $ | — |  |  | $ | 606 |  |  | $ | 302 |  |  | $ | — |  |  | $ | 302 |
Finite-lived |  |  |  |  |  |  |  |  |  |  |
Customer relations including supply agreements | 2,241 |  |  | 520 |  |  | 1,721 |  |  | 721 |  |  | 477 |  |  | 244 |
Other intangibles | 93 |  |  | 9 |  |  | 84 |  |  | 8 |  |  | 7 |  |  | 1 |
Intangible assets, net | $ | 2,940 |  |  | $ | 529 |  |  | $ | 2,411 |  |  | $ | 1,031 |  |  | $ | 484 |  |  | $ | 547 |

During the fourth quarters of 2025, 2024 and 2023, we performed the annual impairment tests on Sunoco’s indefinite-lived intangible ass ets. No impairments were recorded in 2025, 2024 and 2023.
Total amortization expense on finite-lived intangibles included in depreciation, amortization and accretion was $45 million, $37 million and $44 million for the years ended December 31, 2025, 2024 and 2023, respectively.
Customer relations and supply agreements have a remaining weighted average life of approximately 18 years.
As of December 31, 2025, the Partnership’s estimate of amortization for each of the five succeeding fiscal years and thereafter for finite-lived intangibles was as follows:

| Amortization
2026 | $ | 124 |
2027 | 124 |
2028 | 124 |
2029 | 120 |
2030 | 118 |
Thereafter | 1,195 |
Total | $ | 1,805 |

10.Accrued Expenses and Other Current Liabilities
Accrued expenses and other current liabilities consisted of the following:

| December 31, 2025 |  | December 31, 2024
Wage and other employee-related accrued expenses | $ | 92 |  |  | $ | 64 |
Accrued tax expense | 187 |  |  | 152 |
Accrued insurance | 37 |  |  | 39 |
Accrued interest expense | 183 |  |  | 82 |
Dealer deposits | 21 |  |  | 24 |
Accrued capital expenditures | 46 |  |  | — |
Accrued environmental expense | 10 |  |  | 7 |
Contract liabilities | 102 |  |  | 17 |
Other | 275 |  |  | 72 |
Accrued expenses and other current liabilities | $ | 953 |  |  | $ | 457 |

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Index to Financial Statements
11.Debt Obligations
Sunoco’s debt obligations consisted of the following:

| December 31, 2025 |  | December 31, 2024
Credit Facility | $ | — |  |  | $ | 203 |
5.750% senior notes due 2025 | — |  |  | 600 |
6.000% senior notes due 2026 (1) | 500 |  |  | 500 |
3.875% CAD senior notes due 2026 (1)(2) | 400 |  |  | — |
Parkland 3.875% CAD senior notes due 2026 (1)(3) | 37 |  |  | — |
6.000% senior notes due 2027 | 600 |  |  | 600 |
5.625% senior notes due 2027 | 550 |  |  | 550 |
5.875% senior notes due 2027 (2) | 499 |  |  | — |
Parkland 5.875% senior notes due 2027 (3) | 1 |  |  | — |
5.875% senior notes due 2028 | 400 |  |  | 400 |
7.000% senior notes due 2028 | 500 |  |  | 500 |
6.000% CAD senior notes due 2028 (2) | 277 |  |  | — |
Parkland 6.000% CAD senior notes due 2028 (3) | 14 |  |  | — |
4.500% senior notes due 2029 | 800 |  |  | 800 |
7.000% senior notes due 2029 | 750 |  |  | 750 |
4.375% CAD senior notes due 2029 (2) | 397 |  |  | — |
Parkland 4.375% CAD senior notes due 2029 (3) | 40 |  |  | — |
4.500% senior notes due 2029 (2) | 790 |  |  | — |
Parkland 4.500% senior notes due 2029 (3) | 10 |  |  | — |
4.500% senior notes due 2030 | 800 |  |  | 800 |
6.375% senior notes due 2030 | 600 |  |  | 600 |
4.625% senior notes due 2030 (2) | 798 |  |  | — |
Parkland 4.625% senior notes due 2030 (3) | 2 |  |  | — |
5.625% senior notes due 2031 | 1,000 |  |  | — |
7.250% senior notes due 2032 | 750 |  |  | 750 |
6.625% senior notes due 2032 (2) | 493 |  |  | — |
Parkland 6.625% senior notes due 2032 (3) | 7 |  |  | — |
6.250% senior notes due 2033 | 1,000 |  |  | — |
5.875% senior notes due 2034 | 900 |  |  | — |
GoZone Bonds | 322 |  |  | 322 |
Lease-related financing obligations and other subsidiary debt | 233 |  |  | 132 |
Net unamortized premiums, discounts and fair value adjustments | 2 |  |  | 16 |
Deferred debt issuance costs | (83) |  |  | (37) |
Total debt | 13,389 |  |  | 7,486 |
Less: current maturities | 17 |  |  | 2 |
Total long-term debt, net | $ | 13,372 |  |  | $ | 7,484 |

(1)As of December 31, 2025, $937 million aggregate principal amount of senior notes due before December 31, 2026 were classified as long-term as management has the intent and ability to refinance the borrowings on a long-term basis.
(2)These senior notes, totaling $3.65 billion as of December 31, 2025, were assumed and exchanged by the Partnership in connection with the closing of the Parkland Acquisition. For additional information, see “Parkland Senior Note Exchange” below.
(3)These senior notes, totaling $111 million as of December 31, 2025, represent the aggregate principal amounts not tendered in the private exchange offers and remain outstanding obligations of Parkland. For additional information, see “Parkland Senior Note Exchange” below.
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Index to Financial Statements
At December 31, 2025, scheduled future debt maturities were as follows:

2026 | $ | 954 |
2027 | 1,661 |
2028 | 1,202 |
2029 | 2,797 |
2030 | 2,206 |
Thereafter | 4,650 |
Total | $ | 13,470 |

Recent Financing Transactions
March 2025 Senior Notes Offering and Redemption
In March 2025, the Partnership issued $1.00 billion aggregate principal amount of 6.250% senior notes due 2033 in a private offering. These notes will mature on July 1, 2033 and interest is payable semi-annually on January 1 and July 1 of each year. The Partnership used the net proceeds from the private offering to repay its $600 million aggregate principal amount of 5.750% senior notes due 2025 and to repay a portion of the outstanding borrowings under its Credit Facility.
September 2025 Senior Notes Offering
In September 2025, the Partnership issued $1.00 billion aggregate principal amount of 5.625% senior notes due 2031 and $900 million aggregate principal amount of 5.875% senior notes due 2034 in a private offering. These notes will mature on March 15, 2031 and March 15, 2034, respectively, and interest is payable semi-annually on March 15 and September 15 of each year, commencing on March 15, 2026. The Partnership used the net proceeds from this private offering (i) on the closing date of the Parkland Acquisition to fund a portion of the cash consideration for the Parkland Acquisition and related transaction costs, with the remaining proceeds used for general corporate purposes, and (ii) prior to the closing date of the Parkland Acquisition, to temporarily reduce the borrowings outstanding under the Partnership's Credit Facility and to pay interest and fees in connection therewith.
The 5.625% senior notes due 2031 and 5.875% senior notes due 2034 were originally subject to a special mandatory redemption requirement, which was eliminated upon closing of the Parkland Acquisition.
Parkland Senior Note Exchange
In October 2025, in connection with the Parkland Acquisition, the Partnership commenced a private offering to exchange up to C$1.60 billion Canadian dollar denominated notes issued by Parkland (collectively, the “PKI CAD Notes”) and up to $2.60 billion U.S. dollar denominated notes issued by Parkland (collectively, the “PKI USD Notes”) for new notes issued by the Partnership. The exchange offer closed on November 7, 2025 with approximately C$1.47 billion of the PKI CAD Notes and approximately $2.58 billion of the PKI USD Notes being validly tendered and not validly withdrawn.
Description of Debt Obligations
Sunoco Senior Notes
The terms of each tranche of Sunoco Senior Notes are governed by indentures among the Partnership and Sunoco Finance Corp. (together, the “Issuers”), and certain other subsidiaries of the Partnership and U.S. Bank National Association, as trustee. The Sunoco Senior Notes are senior obligations of the Issuers and are guaranteed by all of the Partnership’s existing subsidiaries and certain of its future subsidiaries. The Sunoco Senior Notes and guarantees are unsecured and rank equally with all of the Issuers’ and each Guarantor’s existing and future senior obligations. The Sunoco Senior Notes and guarantees are effectively subordinated to the Issuers’ and each Guarantor’s secured obligations, including obligations under the Partnership’s Credit Facility (as defined below), to the extent of the value of the collateral securing such obligations, and structurally subordinated to all indebtedness and obligations, including trade payables, of the Partnership’s subsidiaries that do not guarantee the Sunoco Senior Notes.
Energy Transfer guarantees collection to the Issuers with respect to the payment of the principal amount of the 5.875% senior notes due 2028. Energy Transfer is not subject to any of the covenants under the Indenture.
Credit Facility
The Partnership's $2.50 billion Credit Facility matures on June 17, 2030, which date may be extended in accordance with the terms of the Credit Facility. The Credit Facility can be increased from time to time upon Sunoco’s written request, subject to ce rtain conditions, up to an aggregate amount of $3.50 billion. As of December 31, 2025, Sunoco had no outstanding borrowings on the Credit Facility and $26 million in standby letters of credit were outstanding. The unused availability on the Credit Facility as of December 31, 2025 was $2.47 billion. The weighted average interest rate on the total amount outstanding as of
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Index to Financial Statements
December 31, 2025 was 6.38%. The Partnership was in compliance with all financial covenants as of December 31, 2025. The Partnership’s net leverage ratio was 4.03 to 1.00 at December 31, 2025.
Borrowings under the Credit Facility will bear interest, at the Borrower’s election, at a rate equal to Term SOFR (as defined therein) or a base rate (a rate based off of the higher of (a) the Federal Funds Rate (as defined therein) plus 0.500%, (b) Bank of America’s prime rate and (c) one-month Term SOFR (as defined therein) plus 1.00%), in each case plus an applicable margin ranging from 1.250% to 2.250%, in the case of a Term SOFR loan, or from 0.250% to 1.25%, in the case of a base rate loan (determined with reference to the Partnership’s Net Leverage Ratio as defined in the Credit Facility). Upon the first achievement by the Partnership of an investment grade credit rating, the applicable margin will decrease to a range of 1.125% to 1.750%, in the case of a Term SOFR loan, or from 0.125% to 0.750%, in the case of a base rate loan (determined with reference to the credit rating for the Partnership’s senior, unsecured, non-credit enhanced long-term debt and the Partnership’s corporate issuer rating). Interest is payable quarterly if the base rate applies, and at the end of the applicable interest period if Term SOFR applies. In addition, the unused portion of the Partnership’s Credit Facility will be subject to a commitment fee ranging from 0.250% to 0.350%, based on the Partnership’s Net Leverage Ratio. Upon the first achievement by the Partnership of an investment grade credit rating, the commitment fee will decrease to a range of 0.125% to 0.350%, based on the Partnership’s credit rating as described above.
The Credit Facility requires the Partnership to maintain a Net Leverage Ratio of not more than 5.50 to 1.00 before the first achievement by the Partnership of an investment grade credit rating, and from and after the first occurrence of an investment grade credit rating, a Net Leverage Ratio of not more than 5.00 to 1.00. The maximum Net Leverage Ratio is subject to upwards adjustment after the achievement by the Partnership of an investment grade credit rating to not more than 5.50 to 1.00 for a period not to exceed three fiscal quarters in the event the Partnership engages in certain specified acquisitions of not less than $50 million (as permitted under the Credit Facility). The Credit Facility also requires the Partnership to maintain an Interest Coverage Ratio (as defined in the Credit Facility) of not less than 2.25 to 1.00.
Indebtedness under the Credit Facility is guaranteed by material domestic subsidiaries of the Partnership and other subsidiaries for which the Partnership elects to provide guarantees.
On May 16, 2025, the Credit Facility was amended, effective as of the Parkland Acquisition closing date, to, among other things, (i) increase the letter of credit sublimit from $100 million to $250 million, (ii) exclude Parkland and its subsidiaries from any requirement to provide a guarantee of the Obligations (as defined in the Sunoco Credit Agreement) to the extent (x) such guarantee would not be permitted under any existing indebtedness of Parkland and its subsidiaries that remains outstanding after the Parkland Acquisition closing date or (y) such guarantee, if provided by a domestic subsidiary that is a direct or indirect subsidiary of a foreign subsidiary, could reasonably be expected to have material adverse tax consequences and (iii) permit the Partnership or any of its subsidiaries to incur (x) Parkland Acquisition bridge debt in an aggregate principal amount not to exceed $2.65 billion and (y) Parkland backstop bridge debt in an aggregate principal amount not to exceed $3.40 billion less reductions to such maximum amount as set forth in the Sunoco Credit Agreement.
On June 17, 2025, the Credit Facility was amended to, among other things, (i) extend the maturity date of the revolving credit facility from May 3, 2029 to June 17, 2030, (ii) increase the aggregate principal amount of the revolving loan commitments from $1.50 billion to approximately $2.50 billion, upon closing of the Parkland Acquisition, (iii) increase the swingline sublimit on and after the Parkland Acquisition closing from $100 million to $500 million, of which $250 million will be dedicated to swingline borrowings in Canadian Dollars and $250 million will be dedicated to swingline borrowings in U.S. Dollars, and (iv) add the ability to borrow revolving loans in Canadian Dollars.
On August 8, 2025, the Credit Facility was amended to, among other things, provide for up to $2.00 billion of cash that has been reserved by the Partnership to fund a portion of the cash consideration for the Parkland Acquisition to be netted in calculating the Net Leverage Ratio (as defined in the Sunoco Credit Agreement) for purposes of the financial maintenance covenant.
On October 3, 2025, the Credit Facility was amended to, among other things, (i) amend the maturity limitations on the incurrence of additional unsecured indebtedness by the Partnership and its subsidiaries to permit both (a) the new notes to be issued by the Partnership in connection with the previously announced private exchange offers (the “Exchange Offers”) and (b) the guaranty by the Partnership of any senior notes of Parkland that remain outstanding after giving effect to the settlement of the Exchange Offers and (ii) exclude any domestic subsidiaries that are “foreign subsidiary holding companies” or subsidiaries of “controlled foreign corporations” from an obligation to provide a guaranty under the Credit Facility.
On November 25, 2025, the Credit Facility was amended to increase the aggregate principal amount of the revolving loan commitments from approximately $2.46 billion to $2.50 billion.
NuStar Logistics Senior Notes
NuStar Logistics is the issuer of $2.25 billion of senior notes, including 5.750% senior notes due 2025, 6.000% senior notes due 2026, 5.625% senior notes due 2027 and 6.375% senior notes due 2030 (collectively, the “NuStar Logistics Senior Notes”).
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Index to Financial Statements
Subsequent to the closing of the NuStar Acquisition, the indentures related to the Partnership’s senior notes (“Sunoco Senior Notes”) and the indentures related to NuStar Logistics’ Senior Notes were amended to add certain subsidiaries as guarantors. Consequently, Sunoco and NuStar Logistics are each a guarantor of the other’s senior notes, along with other subsidiary guarantors of each.
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 Sunoco undergoes 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 Sunoco 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.
GoZone Bonds
NuStar Logistics’ obligations include revenue bonds issued by the Parish of St. James, Louisiana pursuant to the Gulf Opportunity Zone Act of 2005 (the “GoZone 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 may 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 Sunoco’s 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, 2025:

Series |  | Date Issued |  | Amount Outstanding |  | Interest Rate |  | Mandatory Purchase Date |  | Optional Redemption Date |  | Maturity Date
Series 2008 |  | June 26, 2008 |  | $ | 56 |  |  | 6.10 | % |  | June 1, 2030 |  | n/a |  | June 1, 2038
Series 2010 |  | July 15, 2010 |  | 100 |  |  | 6.35 | % |  | n/a |  | June 1, 2030 |  | July 1, 2040
Series 2010A |  | October 7, 2010 |  | 43 |  |  | 6.35 | % |  | n/a |  | June 1, 2030 |  | October 1, 2040
Series 2010B |  | December 29, 2010 |  | 48 |  |  | 6.10 | % |  | June 1, 2030 |  | n/a |  | December 1, 2040
Series 2011 |  | October 1, 2025 |  | 75 |  |  | 3.70 | % |  | June 1, 2030 |  | n/a |  | August 1, 2041

During 2025, the Partnership completed the remarketing of $75 million principal amount of Series 2011 GoZone Bonds, which were previously repurchased on the mandatory purchase date of June 1, 2025 but were not remarketed at that time. The remarketed bonds were issued on October 1, 2025 and have a 3.70% interest rate, a mandatory purchase date of June 1, 2030, and a maturity of August 1, 2041.
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 Sunoco undergoes 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. The Partnership and certain of its subsidiaries are guarantors to the agreements related to the GoZone Bonds.
Parkland Senior Notes
Parkland’s senior notes are unsecured obligations guaranteed by Parkland's subsidiaries and contain covenants that limit Parkland's ability to incur additional debt, make certain restricted payments and investments, create liens, enter into transactions with affiliates, and consolidate, merge, transfer or sell all or substantially all of its property and assets. Interest on the Parkland senior notes is paid semi-annually.
Receivables Financing Agreement
Upon the closing of the NuStar Acquisition, the commitments under NuStar’s receivables financing agreement were reduced to zero during a suspension period, for which the period end has not been determined. As of December 31, 2025, th is facility had no outstanding borrowings.
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Index to Financial Statements
Lease-Related Financing Obligations
Southside Oil, LLC, a subsidiary of the Partnership, is a party to a sale leaseback transaction that did not meet the criteria for sale leaseback accounting. This transaction was accounted for as a financing arrangement over the course of the lease agreement. The obligations mature in varying dates through 2058, require monthly interest and principal payments, and bear interest at 11.865%. As of December 31, 2025 and 2024, the balance of the sale leaseback financing obligation were $145 million and $85 million, respectively.
Lease-related financing obligations also include finance lease obligations of $87 million and $47 million as of December 31, 2025 and 2024, respectively. See further discussion in Note 16.
Fair Value of Debt
The aggregate estimated fair value and carrying amount of Sunoco’s consolidated debt obligations as of December 31, 2025 were $13.52 billion and $13.39 billion, respectively. As of December 31, 2024, the aggregate fair value and carrying amount of Sunoco’s consolidated debt obligations were $7.45 billion and $7.49 billion, respectively. The fair value of Sunoco’s consolidated debt obligations is a Level 2 valuation based on the respective debt obligations' observable inputs for similar liabilities.
12.Other Non-Current Liabilities
Other non-current liabilities consisted of the following:

| December 31, 2025 |  | December 31, 2024
Asset retirement obligations | $ | 254 |  |  | $ | 84 |
Accrued environmental expense, long-term | 158 |  |  | 21 |
Other | 100 |  |  | 53 |
Other non-current liabilities | $ | 512 |  |  | $ | 158 |

We record an asset retirement obligation for the estimated future cost to remove underground storage tanks. Revisions to the liability could occur due to changes in tank removal costs, tank useful lives or if federal and/or state regulators enact new guidance on the removal of such tanks. Changes in the carrying amount of asset retirement obligations for the years ended December 31, 2025 and 2024 were as follows:

| Year Ended December 31,
| 2025 |  | 2024
Balance at beginning of year | $ | 84 |  |  | $ | 84 |
Parkland Acquisition | 166 |  |  | — |
Liabilities incurred | — |  |  | 4 |
Liabilities settled | (3) |  |  | (8) |
Accretion expense | 7 |  |  | 4 |
Balance at end of year | $ | 254 |  |  | $ | 84 |

13.Related Party Transactions
We are party to fee-based commercial agreements with various affiliates of Energy Transfer for pipeline, terminalling and storage services. We also have agreements with subsidiaries of Energy Transfer for the purchase and sale of fuel. Additionally, under our Partnership Agreement, our General Partner does not receive a management fee or other compensation for its role as our general partner. However, our General Partner is reimbursed for all expenses incurred on our behalf. These expenses include shared service fees, as well as all other expenses necessary or appropriate to the conduct of our business that are allocable to us, as provided for in our Partnership Agreement. There is no cap on the amount that may be paid or reimbursed to our General Partner.
Summary of Related Party Transactions
Related party transactions for the years ended December 31, 2025, 2024 and 2023 were as follows:

| Year Ended December 31,
| 2025 |  | 2024 |  | 2023
Motor fuel sales to affiliates | $ | 24 |  |  | $ | 28 |  |  | $ | 42 |
Bulk fuel purchases from affiliates | 1,249 |  |  | 1,463 |  |  | 1,661 |
Expense reimbursement | 43 |  |  | 35 |  |  | 34 |

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Index to Financial Statements
Significant affiliate balances included on our consolidated balance sheets were as follows:
•Accounts payable to affiliates were $331 million and $199 million as of December 31, 2025 and 2024, respectively, which were attributable to operational expenses and bulk fuel purchases.
•Advances from affiliates were $78 million and $82 million at December 31, 2025 and 2024, respectively, which were related to treasury services agreements with Energy Transfer.
14.Revenue
Disaggregation of Revenue
Revenues from our Fuel Distribution segment are derived from the sale of fuel, non-fuel and lease income. Fuel sales consist primarily of the sale of motor fuel under supply agreements with third-party customers and affiliates. Fuel supply contracts with our customers generally provide that we distribute motor fuel at a price based on a formula which includes published rates, volume-based profit margin and other terms specific to the agreement. The customer is invoiced the agreed-upon price with most payment terms ranging less than 30 days. If the consideration promised in a contract includes a variable amount, the Partnership estimates the variable consideration amount and factors in such estimate to determine the transaction price under the expected value method. Revenue is recognized under the motor fuel contracts at the point in time the customer takes control of the fuel. At the time control is transferred to the customer the sale is considered final, because the agreements do not grant customers the right to return motor fuel. To determine when control transfers to the customer, the shipping terms of the contract are assessed as a primary indicator of the transfer of control. For FOB shipping point terms, revenue is recognized at the time of shipment. The performance obligation with respect to the sale of goods is satisfied at the time of shipment since the customer gains control at this time under the terms. Shipping and/or handling costs that occur before the customer obtains control of the goods are deemed to be fulfillment activities and are accounted for as fulfillment costs. Once the goods are shipped, the Partnership is precluded from redirecting the shipment to another customer and revenue is recognized. Non-fuel revenue includes merchandise revenue that comprises the in-store merchandise and food service sales at company-operated retail stores and other revenue such as credit card processing, car washes, lottery and other services. Lease revenue is derived from the leasing or subleasing of real estate used in the retail distribution of motor fuels.
Revenues from our Pipeline Systems 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 from our Terminals 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. Additionally, we lease certain of our storage tanks in exchange for a fixed fee, subject to an annual consumer price index adjustment. We recognized lease revenues from these leases of $47 million and $31 million for the years ended December 31, 2025 and 2024, respectively, which are included in "Service revenue" in our consolidated statements of operations.
Revenues from our Refinery segment are derived from refined products, generated environmental compliance credits and excess crude oil sales are recognized when delivered and the customer obtains control of such inventory, which is typically when title passes and the customer is billed. All revenues are reported inclusive of shipping and handling costs billed and exclusive of any sales taxes billed to customers where applicable. Shipping and handling costs incurred are reported in cost of sales.
The following table depicts the disaggregation of revenue:

| Year Ended December 31,
| 2025 |  | 2024 |  | 2023
Fuel | $ | 23,290 |  |  | $ | 21,362 |  |  | $ | 22,520 |
Non-fuel | 442 |  |  | 294 |  |  | 284 |
Lease income | 130 |  |  | 125 |  |  | 151 |
Pipeline throughput | 660 |  |  | 457 |  |  | — |
Terminal throughput | 117 |  |  | 102 |  |  | 61 |
Refinery throughput | 177 |  |  | — |  |  | — |
Other | 385 |  |  | 353 |  |  | 52 |
Total revenues | $ | 25,201 |  |  | $ | 22,693 |  |  | $ | 23,068 |

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Contract Balances with Customers
The Partnership satisfies its performance obligations by transferring goods or services in exchange for consideration from customers. The timing of performance may differ from the timing the associated consideration is paid to or received from the customer, thus resulting in the recognition of a contract asset or a contract liability.
The Partnership recognizes a contract asset when making upfront consideration payments to certain customers. The upfront considerations represent a pre-paid incentive, as these payments are not made for distinct goods or services provided by the customer. The pre-payment incentives are recognized as a contract asset upon payment and amortized as a reduction of revenue over the term of the specific agreement.
The Partnership recognizes a contract liability if the customer’s payment of consideration precedes the Partnership’s fulfillment of the performance obligations, which primarily result from contracts with an incentive pricing structure, contributions in aid of construction (“CIAC”) payments (as discussed below), and contracts with minimum volume commitment We maintain some franchise agreements requiring dealers to make one-time upfront payments for long-term license agreements. The Partnership recognizes a contract liability when the upfront payment is received and recognizes revenue over the term of the license.
The balances of the Partnership’s contract assets and contract liabilities as of December 31, 2025, 2024 and 2023 were as follows:

| December 31, 2025 |  | December 31, 2024 |  | December 31, 2023 |
Contract assets | $ | 480 |  |  | $ | 288 |  |  | $ | 256 |  |
Accounts receivable from contracts with customers | 1,686 |  |  | 1,084 |  |  | 809 |  |
Contract liabilities | 125 |  |  | 39 |  |  | — |  |

The following table summarizes the consolidated activity of our contract liabilities:

| Contract Liabilities
Balance, December 31, 2023 | $ | — |
NuStar Acquisition | 78 |
Zenith European terminals acquisition | 3 |
ET-S Permian | (29) |
Other additions | 26 |
Revenue recognized | (39) |
Balance, December 31, 2024 | 39 |
Parkland Acquisition | 84 |
Other additions | 40 |
Revenue recognized | (38) |
Balance, December 31, 2025 | $ | 125 |

Costs to Obtain or Fulfill a Contract
The Partnership recognizes an asset from the costs incurred to obtain a contract (e.g. sales commissions) only if it expects to recover those costs. On the other hand, the costs to fulfill a contract are capitalized if the costs are specifically identifiable to a contract, would result in enhancing resources that will be used in satisfying performance obligations in the future, and are expected to be recovered. These capitalized costs are recorded as a part of other current assets and other non-current assets on our consolidated balance sheets and are amortized as a reduction of revenue on a systematic basis consistent with the pattern of transfer of the goods or services to which such costs relate. The amount of amortization on these capitalized costs that the Partnership recognized in the years ended December 31, 2025, 2024 and 2023 was $41 million, $35 million and $29 million, respectively.
Performance Obligations
At contract inception, the Partnership assesses the goods and services promised in its contracts with customers and identifies a performance obligation for each promise to transfer a good or service (or bundle of goods or services) that is distinct. To identify the performance obligations, the Partnership considers all the goods or services promised in the contract, whether explicitly stated or implied based on customary business practices. For a contract that has more than one performance obligation, the Partnership allocates the total contract consideration to each distinct performance obligation on a relative standalone selling price basis. Revenue is recognized when (or as) the performance obligations are satisfied, that is, when the customer obtains control of the good or the service is provided.
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The Partnership distributes fuel under long-term contracts to branded distributors, branded and unbranded third-party dealers and branded and unbranded retail fuel outlets. Sunoco-branded supply contracts with distributors generally have both time and volume commitments that establish contract duration. These contracts have an initial term of approximately ten years, with an estimated, volume-weighted term remaining of approximately five years.
The Partnership is party to a 15-year take-or-pay fuel supply agreement with 7-Eleven, Inc. and SEI Fuel Services, Inc. (collectively, the “Distributor”) in which the Distributor is required to purchase a volume of fuel that provides the Partnership a minimum amount of gross profit annually. We expect to recognize this revenue in accordance with the contract as we transfer control of the product to the customer. However, in case of an annual shortfall we will recognize the amount payable by the Distributor at the sooner of the time at which the Distributor makes up the shortfall or becomes contractually or operationally unable to do so. The transaction price of the contract is variable in nature, fluctuating based on market conditions. The Partnership has elected to take the practical expedient not to estimate the amount of variable consideration allocated to wholly unsatisfied performance obligations. 7-Eleven, Inc. accounted for approximately 13%, 18% and 20% of total revenues for the years ended December 31, 2025, 2024 and 2023, respectively.
In some contractual arrangements, the Partnership grants dealers a franchise license to operate the Partnership’s retail stores over the life of a franchise agreement. In return for the grant of the retail store license, the dealer makes a one-time nonrefundable franchise fee payment to the Partnership plus sales based royalties payable to the Partnership at a contractual rate during the period of the franchise agreement. Under the requirements of ASC Topic 606, the franchise license is deemed to be a symbolic license for which recognition of revenue over time is the most appropriate measure of progress toward complete satisfaction of the performance obligation. Revenue from this symbolic license is recognized evenly over the life of the franchise agreement.
In certain instances, our customers reimburse us for capital projects, in arrangements referred to as CIAC. Typically, in these instances, we receive upfront payments for future services, which are included in the transaction price of the underlying service contract.
Remaining Performance Obligations
The following table presents our estimated revenues from contracts with customers for remaining performance obligations that have not yet been recognized, representing our contractually committed revenue as of December 31, 2025.

|  | Remaining Performance Obligations
2026 |  | $ | 336 |
2027 |  | 195 |
2028 |  | 161 |
2029 |  | 114 |
2030 |  | 100 |
Thereafter | 239 |
Total | $ | 1,145 |

Practical Expedients Selected by the Partnership
The Partnership elected the following practical expedients in accordance with ASC 606:
•Significant financing component - The Partnership elected not to adjust the promised amount of consideration for the effects of a significant financing component if the Partnership expects at contract inception that the period between the transfer of a promised good or service to a customer and when the customer pays for that good or service will be one year or less.
•Incremental costs of obtaining a contract - The Partnership elected to expense the incremental costs of obtaining a contract when the amortization period for such contracts would have been one year or less.
•Shipping and handling costs - The Partnership elected to account for shipping and handling activities that occur after the customer has obtained control of a good as fulfillment activities (i.e., an expense) rather than as a promised service.
•Measurement of transaction price - The Partnership has elected to exclude from the measurement of transaction price all taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction and collected by the Partnership from a customer (i.e., sales tax, value added tax, etc.).
•Variable consideration of wholly unsatisfied performance obligations - The Partnership has elected to exclude the estimate of variable consideration to the allocation of wholly unsatisfied performance obligations.
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15.Commitments and Contingencies
Litigation and Contingencies
We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to personal injury or property damage in the future. In addition, various regulatory agencies such as tax authorities, environmental agencies, or other such agencies may perform audits or reviews to ensure proper compliance with regulations. We are not fully insured for any claims that may arise from these various agencies and there can be no assurance that any claims arising from these activities would not have an adverse, material effect on our consolidated financial statements.
Environmental Remediation
We are subject to various federal, state and local environmental laws and make financial expenditures in order to comply with regulations governing underground storage tanks adopted by federal, state and local regulatory agencies. In particular, at the federal level, the Resource Conservation and Recovery Act of 1976, as amended, requires the EPA to establish a comprehensive regulatory program for the detection, prevention and cleanup of leaking underground storage tanks (e.g. overfills, spills and underground storage tank releases).
Federal and state regulations require us to provide and maintain evidence that we are taking financial responsibility for corrective action and compensating third parties in the event of a release from our underground storage tank systems and terminals. In order to comply with these requirements, we have historically obtained private insurance in the states in which we operate. These policies provide protection from third-party liability claims. During 2025, our coverage was $15 million per occurrence and in the aggregate. Our sites continue to be covered by these policies.
We are currently involved in the investigation and remediation of contamination at motor fuel storage and gasoline store sites where releases of regulated substances have been detected. We accrue for anticipated future costs and the related probable state reimbursement amounts for remediation activities. Accordingly, we have recorded estimated undiscounted liabilities for these sites totaling $168 million and $28 million as of December 31, 2025 and 2024, respectively, which are classified as accrued expenses and other current liabilities and other non-current liabilities.
New York Motor Fuel Excise Tax Audit
New York State issued a motor fuel excise tax assessment to Sunoco, LLC, a wholly owned subsidiary of the Partnership, in the amount of approximately $20 million, exclusive of penalties and interest, for the periods of March 2017 through May 2020. Sunoco, LLC filed an appeal with the New York State Division of Tax Appeals challenging the assessment. Sunoco, LLC cannot predict the outcome of this matter at this time.
16.Lease Accounting
Lessee Accounting
The Partnership leases retail stores, other property, plant and equipment under non-cancellable operating leases whose initial terms are typically five to 15 years, with options that permit renewals for additional periods. At the inception of each, we determine if the arrangement is a lease or contains an embedded lease and review the facts and circumstances of the arrangement to classify leased assets as operating or finance under Topic 842. The Partnership has elected not to record any leases with terms of 12 months or less on our consolidated balance sheets.
At this time, the majority of active leases within our portfolio are classified as operating leases. Operating leases are included in operating lease right-of-use assets, net, operating lease current liabilities and operating lease non-current liabilities on our consolidated balance sheets. Finance leases represent a small portion of the active lease agreements and are included in other non-current assets and long-term debt, net on our consolidated balance sheets. The right-of-use assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make minimum lease payments arising from the lease for the duration of the lease term.
Most leases include one or more options to renew, with renewal terms that can extend the lease term from five to 10 years or greater. The exercise of lease renewal options is typically at our discretion. Additionally, many leases contain early termination clauses, however early termination typically requires the agreement of both parties to the lease. At lease inception, all renewal options reasonably certain to be exercised are considered when determining the lease term. At this time, the Partnership does not
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have leases that include options to purchase or automatic transfer of ownership of the leased property to the Partnership. The depreciable life of leased assets and leasehold improvements are limited by the expected lease term.
To determine the present value of future minimum lease payments, we use the implicit rate when readily determinable. At this time, many of our leases do not provide an implicit rate, therefore to determine the present value of minimum lease payments we use our incremental borrowing rate based on the information available at lease commencement date. The right-of-use assets also include any lease payments made and exclude lease incentives.
Minimum rent payments are expensed on a straight-line basis over the term of the lease. In addition, some leases may require additional contingent or variable lease payments based on factors specific to the individual agreement. Variable lease payments we are typically responsible for include payment of real estate taxes, maintenance expenses and insurance.
The components of lease expense consisted of the following:

|  | Year Ended December 31,
Lease cost | Classification | 2025 |  | 2024
Operating lease costs: |  |  |  |
Operating lease cost | Lease expense | $ | 96 |  |  | $ | 50 |
Finance lease costs: |  |  |  |
Amortization of leased assets | Depreciation, amortization and accretion | 4 |  |  | 1 |
Interest on lease liabilities | Interest expense | 3 |  |  | 2 |
Short-term lease cost | Lease expense | 7 |  |  | 4 |
Variable lease cost | Lease expense | 11 |  |  | 18 |
Sublease income | Lease income | (35) |  |  | (45) |
Net lease cost |  | $ | 86 |  |  | $ | 30 |

Lease term and discount rate | December 31, 2025 |  | December 31, 2024
Weighted average remaining lease term (years) |  |  |
Operating leases | 16 |  | 19
Finance leases | 11 |  | 18
Weighted average discount rate (%) |  |  |
Operating leases | 6 | % |  | 6 | %
Finance leases | 5 | % |  | 6 | %

| Year Ended December 31,
Other information | 2025 |  | 2024
Cash paid for amount included in the measurement of lease liabilities: |  |  |
Operating cash flows from operating leases | $ | (92) |  |  | $ | (49) |
Operating cash flows from finance leases | (4) |  |  | (1) |
Financing cash flows from finance leases | (1) |  |  | (1) |
Leased assets obtained in exchange for new finance lease liabilities | 1 |  |  | — |
Leased assets obtained in exchange for new operating lease liabilities | 279 |  |  | 3 |

Maturities of lease liabilities as of December 31, 2025 were as follows:

| Operating leases |  | Finance leases |  | Total
2026 | $ | 240 |  |  | $ | 16 |  |  | $ | 256 |
2027 | 196 |  |  | 15 |  |  | 211 |
2028 | 171 |  |  | 15 |  |  | 186 |
2029 | 149 |  |  | 12 |  |  | 161 |
2030 | 138 |  |  | 6 |  |  | 144 |
Thereafter | 1,445 |  |  | 53 |  |  | 1,498 |
Total lease payments | 2,339 |  |  | 117 |  |  | 2,456 |
Less: interest | 873 |  |  | 30 |  |  | 903 |
Present value of lease liabilities | $ | 1,466 |  |  | $ | 87 |  |  | $ | 1,553 |

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Lessor Accounting
The Partnership leases or subleases a portion of its real estate portfolio to third-party companies as a stable source of long-term revenue. Our lessor and sublease portfolio consists mainly of operating leases with convenience store operators. At this time, most lessor agreements contain five-year terms with renewal options to extend and early termination options based on established terms specific to the individual agreement. Additionally, we lease certain of our storage tanks in exchange for a fixed fee, subject to an annual consumer price index adjustment.
Minimum future lease payments receivable as of December 31, 2025 were as follows:

2026 |  | $ | 154 |
2027 |  | 124 |
2028 |  | 98 |
2029 |  | 78 |
2030 |  | 68 |
Thereafter |  | 369 |
Total undiscounted cash flows |  | $ | 891 |

The balances of property, plant and equipment that are being leased to third parties were as follows:

| December 31, 2025 |  | December 31, 2024
Land and improvements | $ | 698 |  |  | $ | 513 |
Buildings, equipment and leasehold improvements | 1,045 |  |  | 556 |
Pipelines | 377 |  |  | 217 |
Product storage and related facilities | 410 |  |  | 283 |
Right of way | 105 |  |  | — |
Other | 81 |  |  | 39 |
Construction work-in-process | 54 |  |  | 64 |
Total property, plant and equipment | 2,770 |  |  | 1,672 |
Less: Accumulated depreciation | (829) |  |  | (449) |
Property, plant and equipment, net | $ | 1,941 |  |  | $ | 1,223 |

17.Interest Expense, net
Components of net interest expense were as follows:

| Year Ended December 31,
| 2025 |  | 2024 |  | 2023
Interest expense | $ | 535 |  |  | $ | 380 |  |  | $ | 212 |
Amortization of deferred financing fees | 27 |  |  | 24 |  |  | 8 |
Interest income | (21) |  |  | (13) |  |  | (3) |
Interest expense, net | $ | 541 |  |  | $ | 391 |  |  | $ | 217 |

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18.Income Tax Expense
As a partnership, we are generally not subject to federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes.
The Partnership’s income before income tax expense by geographic area were as follows:

|  | Year Ended December 31,
|  | 2025 |  | 2024 |  | 2023
United States |  | $ | 397 |  |  | $ | 1,040 |  |  | $ | 430 |
Foreign |  | 192 |  |  | 9 |  |  | — |
Total |  | $ | 589 |  |  | $ | 1,049 |  |  | $ | 430 |

The components of the federal and state income tax expense (benefit) of our taxable subsidiaries were summarized as follows:

| Year Ended December 31,
| 2025 |  | 2024 |  | 2023
Current: |  |  |  |  |
Federal | $ | 18 |  |  | $ | 152 |  |  | $ | 16 |
State | (1) |  |  | 37 |  |  | 7 |
Foreign | 7 |  |  | — |  |  | — |
Total current income tax expense | 24 |  |  | 189 |  |  | 23 |
Deferred: |  |  |  |  |
Federal | 22 |  |  | (19) |  |  | 9 |
State | (8) |  |  | 5 |  |  | 4 |
Foreign | 24 |  |  | — |  |  | — |
Total deferred tax expense (benefit) | 38 |  |  | (14) |  |  | 13 |
Income tax expense | $ | 62 |  |  | $ | 175 |  |  | $ | 36 |

Our effective tax rate differs from the statutory rate primarily due to Partnership earnings that are not subject to U.S. federal and most state income taxes at the Partnership level. A reconciliation of income tax expense at the U.S. federal statutory rate to net income tax expense is as follows:

| Year Ended December 31,
| 2025 |  | 2024 |  | 2023
| Amount |  | Percent |  | Amount |  | Percent |  | Amount |  | Percent
Income tax expense at United States statutory rate | $ | 124 |  |  | 21.00 | % |  | $ | 220 |  |  | 21.00 | % |  | $ | 90 |  |  | 21.00 | %
Increase (reduction) in income taxes resulting from: |  |  |  |  |  |  |  |  |  |  |
Non-taxable Partnership earnings | (67) |  |  | (11.40) |  |  | (84) |  |  | (8.04) |  |  | (64) |  |  | (14.85) |
State and local income tax, net of federal income tax effect (1) | 4 |  |  | 0.66 |  |  | 33 |  |  | 3.11 |  |  | 9 |  |  | 2.11 |
Foreign tax effects | (4) |  |  | (0.68) |  |  | — |  |  | — |  |  | — |  |  | — |
Effect of cross-border tax laws - subpart F income inclusion | 6 |  |  | 1.06 |  |  | — |  |  | — |  |  | — |  |  | — |
Changes in unrecognized tax benefits - state apportionment positions | (10) |  |  | (1.67) |  |  | 1 |  |  | 0.07 |  |  | 1 |  |  | 0.15 |
Other: |  |  |  |  |  |  |  |  |  |  |
Deferred tax remeasurement | 15 |  |  | 2.64 |  |  | — |  |  | — |  |  | — |  |  | — |
Discount on purchased tax credits | (4) |  |  | (0.64) |  |  | — |  |  | — |  |  | — |  |  | — |
Interest on federal refund | (5) |  |  | (0.93) |  |  | — |  |  | — |  |  | — |  |  | — |
Other adjustments | 3 |  |  | 0.56 |  |  | 5 |  |  | 0.48 |  |  | — |  |  | — |
Income tax expense | $ | 62 |  |  | 10.60 | % |  | $ | 175 |  |  | 16.62 | % |  | $ | 36 |  |  | 8.41 | %

(1)State taxes that made up the majority (greater than 50 percent) of the tax effect in this category were Pennsylvania in 2025, New Jersey, Pennsylvania and New York in 2024, and Pennsylvania, Hawaii and New Jersey in 2023.
The One Big Beautiful Bill Act (“OBBBA”), enacted in July 2025, is expected to impact the Partnership primarily through the ability to take higher tax depreciation deductions via 100% expensing on eligible property and higher interest expense deductions
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via more favorable interest expense limitation calculations. We will continue to monitor regulatory guidance and interpretations, which could have a material impact on our financials condition and results of operations.
Cash paid for taxes were as follows:

|  | Year Ended December 31,
|  | 2025 |  | 2024 |  | 2023
Cash paid for income taxes, net of refunds (excluding federal tax credits purchased from non-governmental third parties) |  |  |  |  |  |
Federal |  | $ | (68) |  |  | $ | 105 |  |  | $ | 21 |
State |  |  |  |  |  |
Pennsylvania |  | 2 |  |  | 7 |  |  | 2 |
New Jersey |  | 2 |  |  | 12 |  |  | 3 |
Other |  | 3 |  |  | 11 |  |  | 3 |
Foreign |  |  |  |  |  |
Canada |  | 62 |  |  | — |  |  | — |
Other |  | 2 |  |  | — |  |  | — |
Total |  | $ | 3 |  |  | $ | 135 |  |  | $ | 29 |
Cash paid for federal tax credits purchased from non-governmental third parties |  | $ | 41 |  |  | $ | 47 |  |  | $ | — |

Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The principal components of deferred tax assets and liabilities were as follows:

| December 31, 2025 |  | December 31, 2024
Deferred income tax assets: |  |  |
Net operating losses, credits and other carryforwards | $ | 233 |  |  | $ | 16 |
Other | 45 |  |  | 18 |
Total deferred income tax assets | 278 |  |  | 34 |
Valuation allowance | (62) |  |  | — |
Net deferred income tax assets | 216 |  |  | 34 |
Deferred income tax liabilities: |  |  |
Property, plant and equipment | 846 |  |  | 49 |
Trademarks and other intangibles | 239 |  |  | 82 |
Investments in affiliates | 54 |  |  | 53 |
Other | 38 |  |  | 1 |
Total deferred tax liabilities | 1,177 |  |  | 185 |
Net deferred income tax liabilities | $ | 961 |  |  | $ | 151 |

The completion of the Parkland transaction significantly increased the deferred tax assets (liabilities). The table below provides a rollforward of the net deferred income tax liability as follows:

| December 31, 2025 |  | December 31, 2024
Net deferred income tax liability, beginning of year | $ | (151) |  |  | $ | (166) |
Acquired via Parkland Acquisition | (755) |  |  | — |
Acquired via NuStar Acquisition | — |  |  | (3) |
Tax accrual | (55) |  |  | 18 |
Net deferred income tax liability, end of year | $ | (961) |  |  | $ | (151) |

As of December 31, 2025, Sunoco Retail had federal NOL carryforwards of $287 million, that may be carried forward indefinitely. Of this amount, $206 million is subject to limitations under IRC §382 (ownership-change limitation) and $35 million is limited under Separate Return Limitation Year (“SRLY”) rules. Although these federal NOLs are expected to be fully utilized, the amount utilized in a particular year may be limited. Sunoco Retail's foreign subsidiaries had NOL carryforwards of $425 million, of which, $279 million expire between 2026 and 2045. Our corporate subsidiaries have state NOL carryforward benefits of $6 million, net of federal tax, with some expiring between 2026 and 2044 and others carried forward indefinitely. Our
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corporate subsidiaries have cumulative excess business interest expense carryforwards of $159 million available for indefinite carryforward, all of which is limited under IRC §382. Although the excess business interest expense carryforwards are expected to be fully utilized, the amount utilized in a particular year may be limited. For the year ended December 31, 2025, the net change in the total valuation allowances was an increase of $62 million, and for the year ended December 31, 2024, there was no net change. Valuation allowances totaling $52 million and $10 million are attributable to foreign and federal NOLs, respectively.
The following table sets forth the changes in unrecognized tax benefits:

| December 31, 2025 |  | December 31, 2024
Balance at beginning of year | $ | 11 |  |  | $ | 11 |
Reduction attributable to tax positions taken in prior years | (8) |  |  | — |
Balance at end of year | $ | 3 |  |  | $ | 11 |

As of December 31, 2025, we h ad $3 million ($2 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate. During 2025, the Partnership recognized an $8 million tax benefit associated with certain prior tax positions that previously did not meet the criteria for recognition in the Partnership's consolidate d financial statements.
We accrue interest and pen alties on income tax underpayments (overpayments) as a component of income tax expense. During 2025, we recognized interest and penalties of $3 million. At December 31, 2025, we had interest and penalties accrued of $1 million, net of taxes.
The IRS closed its audit of a 2018 income tax refund claim filed by a wholly owned subsidiary of Sunoco with no change. In general, Sunoco and its U.S. subsidiaries are no longer subject to examination by the IRS and most state jurisdictions for the 2020 and prior tax years. Sunoco’s non-U.S. subsidiaries may be subject to examination in their local taxing jurisdictions for periods ranging from 3 to 12 years from the date the tax return is filed.
19.Partners’ Capital
As of December 31, 2025, Energy Transfer and its subsidiaries owned 28,463,967 common units, which constitutes a 13.9% limited partner interest in the Partnership. As of December 31, 2025, our wholly owned consolidated subsidiaries owned 16,410,780 Class C units representing limited partner interests in the Partnership (the “Class C Units”). In connection with the Parkland Acquisition, Sunoc o issued to SunocoCorp 51,517,198 Class D units which are economically equivalent to Sunoco’s publicly traded common units (the “Class D Units”). As of December 31, 2025 the public owned 108,402,887 common units.
Common Units
Common unit activity for the years ended December 31, 2025 and 2024 was as follows:

| Number of Units
Number of common units at December 31, 2023 | 84,408,014 |
Phantom unit vesting | 277,421 |
NuStar Acquisition | 51,543,100 |
Number of common units at December 31, 2024 | 136,228,535 |
Phantom unit vesting | 294,897 |
Units issued in acquisitions | 343,422 |
Number of common units at December 31, 2025 | 136,866,854 |

Allocation of Net Income
Our Partnership Agreement contains provisions for the allocation of net income and loss to the unitholders. For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage interest. Normal allocations according to percentage interests are made after giving effect, if any, to priority income allocations in an amount equal to incentive cash distributions allocated 100% to Energy Transfer.
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The calculation of net income allocated to common unitholders was as follows:

| Year Ended December 31,
| 2025 |  | 2024 |  | 2023
Attributable to Common Units |  |  |  |  |
Distributions declared | $ | 548 |  |  | $ | 478 |  |  | $ | 284 |
Distributions (in excess of) less than net income | (235) |  |  | 238 |  |  | 27 |
Common unitholders’ interest in net income | $ | 313 |  |  | $ | 716 |  |  | $ | 311 |

Class C Units
The Partners hip has outstanding an aggregate of 16,410,780 Class C Units, all of which are held by wholly owned subsidiaries of the Partnership.
Class C Units (i) are not convertible or exchangeable into Common Units or any other units of the Partnership and are non-redeemable; (ii) are entitled to receive distributions of available cash of the Partnership (other than available cash derived from or attributable to any distribution rec eived by the Partnership from Sunoco Retail, the proceeds of any sale of the membership interests of Sunoco Retail, or any interest or principal payments received by the Partnership with respect to indebtedness of Sunoco Retail or its subsidiaries) at a fixed rate equal to $0.8682 per quarter for each Class C Unit outstanding; (iii) do not have the right to vote on any matter except as otherwise required by any non-waivable provision of law; (iv) are not allocated any items of income, gain, loss, deduction or credit attributable to the Partnership’s ownership of, or sale or other disposition of, the membership interests of Sunoco Retail, or the Partnership’s ownership of any indebtedness of Sunoco Retail or any of its subsidiaries (“Sunoco Retail Items”); (v) will be allocated gross income (other than from Sunoco Retail Items) in an amount equal to the cash distributed to the holders of Class C Units and (vi) will be allocated depreciation, amortization and cost recovery deductions as if the Class C Units were Common Units and 1% of certain allocations of net termination gain (other than from Sunoco Retail Items).
Pursuant to the terms described above, these distributions do not have an impact on the Partnership’s consolidated cash flows and as such, are excluded from total cash distributions and allocation of limited partners’ interest in net income.
Class D Units
The Partnership has outstanding an aggregate of 51,517,198 Class D Units, all of which are held by SunocoCorp.
Class D Units (i) except as required by law and in addition to the voting rights established in the Partnership Agreement, are entitled to vote; (ii) shall represent limited partnership interests and common unit interests in the Partnership and shall be economically equivalent to other Partnership common units and no distribution may be made in respect of the Partnership’s common units unless an equal distribution is simultaneously made on the Class D Units; and (iii) provide dividend equalization rights for the period beginning on October 31, 2025 and ending December 31, 2027 (the “Equalization Period”), the Partnership shall ensure that SunocoCorp shall have cash necessary and sufficient to pay distributions on each SunocoCorp common unit for each quarter during the Equalization Period in an amount equal to 100% of the distributions paid by the Partnership on each Sunoco common unit during such quarter.
Preferred Units
In September 2025, the Partnership closed a private offering of 1.5 million of its 7.875% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units (the “Series A Preferred Units”) at an offering price of $1,000 per unit. The Partnership received net proceeds of approximately $1.47 billion from the sale of the Series A Preferred Units after deducting the initial purchasers' discount and other estimated offering expenses. The Partnership used the net proceeds from this private offering (i) on the closing date of the Parkland Acquisition to fund a portion of the cash consideration for the Parkland Acquisition, and (ii) prior to the closing date of the Parkland Acquisition, to temporarily reduce the borrowings outstanding under the Partnership's Credit Facility and to pay interest and fees in connection therewith.
Distributions on the Series A Preferred Units will be cumulative from the date of original issuance and will be payable semi-annually in arrears commencing on March 18, 2026, when, as, and if declared by Sunoco GP LLC out of legally available funds for such purpose. An initial distribution on the Series A Preferred Units will be paid on March 18, 2026 in an amount equal to approximately $39.38 per Series A Preferred Unit.
Incentive Distribution Rights
The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco’s common unitholders and the holder of Sunoco IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of our IDR holder and the common unitholders in any available cash from operating surplus it distributes up to and including the
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corresponding amount in the column “total quarterly distribution per common unit target amount.” The percentage interests shown for Sunoco’s common unitholders and Sunoco’s IDR holder for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. Energy Transfer currently owns Sunoco’s IDRs.

|  |  | Marginal percentage interest in distributions
| Total quarterly distribution per Common unit target amount |  | Common Unitholders |  | Holder of IDRs
Minimum Quarterly Distribution | $0.4375 |  | 100 | % |  | — |
First Target Distribution | Above $0.4375 up to $0.503125 |  | 100 | % |  | — |
Second Target Distribution | Above $0.503125 up to $0.546875 |  | 85 | % |  | 15 | %
Third Target Distribution | Above $0.546875 up to $0.656250 |  | 75 | % |  | 25 | %
Thereafter | Above $0.656250 |  | 50 | % |  | 50 | %

Cash Distributions
Our Partnership Agreement sets forth the calculation used to determine the amount and priority of cash distributions that the common unitholders receive.
Cash distributions paid or to be paid with respect to Sunoco common units and Class D Units were as follows:

|  |  |  |  |  | Limited Partners |  |
Period Ended |  | Record Date |  | Payment Date |  | Per Unit Distribution |  | Distributions on Common Units |  | Distributions on Class D Units |  | Distribution to IDR Holders
December 31, 2022 |  | February 7, 2023 |  | February 21, 2023 |  | $ | 0.8255 |  |  | $ | 69 |  |  | $ | — |  |  | $ | 18 |
March 31, 2023 |  | May 8, 2023 |  | May 22, 2023 |  | 0.8420 |  |  | 71 |  |  | — |  |  | 19 |
June 30, 2023 |  | August 14, 2023 |  | August 21, 2023 |  | 0.8420 |  |  | 71 |  |  | — |  |  | 19 |
September 30, 2023 |  | October 30, 2023 |  | November 20, 2023 |  | 0.8420 |  |  | 71 |  |  | — |  |  | 19 |
December 31, 2023 |  | February 7, 2024 |  | February 20, 2024 |  | 0.8420 |  |  | 71 |  |  | — |  |  | 19 |
March 31, 2024 |  | May 13, 2024 |  | May 20, 2024 |  | 0.8756 |  |  | 119 |  |  | — |  |  | 36 |
June 30, 2024 |  | August 9, 2024 |  | August 19, 2024 |  | 0.8756 |  |  | 119 |  |  | — |  |  | 36 |
September 30, 2024 |  | November 8, 2024 |  | November 19, 2024 |  | 0.8756 |  |  | 119 |  |  | — |  |  | 36 |
December 31, 2024 |  | February 7, 2025 |  | February 19, 2025 |  | 0.8865 |  |  | 121 |  |  | — |  |  | 37 |
March 31, 2025 |  | May 9, 2025 |  | May 20, 2025 |  | 0.8976 |  |  | 122 |  |  | — |  |  | 39 |
June 30, 2025 |  | August 8, 2025 |  | August 19, 2025 |  | 0.9088 |  |  | 124 |  |  | — |  |  | 41 |
September 30, 2025 |  | October 30, 2025 |  | November 19, 2025 |  | 0.9202 |  |  | 126 |  |  | — |  |  | 42 |
December 31, 2025 |  | February 6, 2026 |  | February 19, 2026 |  | 0.9317 |  |  | 128 |  |  | 48 |  |  | 60 |

Accumulated Other Comprehensive Income
The following table presents the components of AOCI, net of tax:

| December 31, 2025 |  | December 31, 2024
Foreign currency translation adjustment | $ | (6) |  |  | $ | (1) |
Actuarial gains related to pensions and other postretirement benefits | — |  |  | 3 |
Total accumulated other comprehensive income included in partners’ capital, net of tax | $ | (6) |  |  | $ | 2 |

20.Employee Benefit Plans
Pension and Other Postretirement Benefits
The NuStar Pension Plan (the “Pension Plan”) was a qualified non-contributory defined benefit pension plan that provided certain eligible NuStar employees with retirement income as calculated under a cash balance formula. Under the cash balance formula, benefits were 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.
NuStar had also maintained an excess pension plan (the “Excess Pension Plan”), which was a nonqualified deferred compensation plan that provided benefits to a select group of management or other highly compensated employees. Neither the Excess Thrift
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Plan nor the Excess Pension Plan was 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 were collectively referred to as the “Pension Plans” in the tables and discussion below. Other postretirement benefit plans included NuStar’s contributory medical benefits plan for U.S. employees who retired prior to April 1, 2014 and, for employees who retired on or after April 1, 2014, a partial reimbursement for eligible third-party health care premiums. We used December 31 as the measurement date for Sunoco’s pension and other postretirement plans.
Sunoco made no contributions to the Pension Plans subsequent to the NuStar Acquisition, and the Pension Plan was terminated on November 30, 2024.
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 Sunoco’s Pension Plans and other postretirement benefit plans as of December 31, 2025 were as follows:

| December 31, 2025 |  | December 31, 2024
| Pension Plans |  | Other Postretirement Benefit Plans |  | Pension Plans |  | Other Postretirement Benefit Plans
Change in benefit obligation: |  |  |  |  |  |  |
Benefit obligation at beginning of period | $ | 137 |  |  | $ | 1 |  |  | $ | — |  |  | $ | — |
NuStar Acquisition | — |  |  | — |  |  | 152 |  |  | 12 |
Service cost | — |  |  | — |  |  | 1 |  |  | — |
Interest cost | 3 |  |  | — |  |  | 5 |  |  | 1 |
Plan amendments | — |  |  | — |  |  | — |  |  | (11) |
Benefits paid, net | (136) |  |  | — |  |  | (36) |  |  | — |
Actuarial (gain) loss and other | (4) |  |  | — |  |  | 15 |  |  | (1) |
Benefit obligation at end of period | — |  |  | 1 |  |  | 137 |  |  | 1 |
Change in plan assets: |  |  |  |  |  |  |
Fair value of plan assets at beginning of period | $ | 160 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
NuStar Acquisition | — |  |  | — |  |  | 178 |  |  | — |
Actual return on plan assets | 2 |  |  | — |  |  | 12 |  |  | — |
Employer contributions | 1 |  |  | — |  |  | 5 |  |  | — |
Benefits paid, net | (136) |  |  | — |  |  | (35) |  |  | — |
Fair value of plan assets at end of period | 27 |  |  | — |  |  | 160 |  |  | — |
Amount (overfunded) underfunded at end of period | $ | (27) |  |  | $ | 1 |  |  | $ | (23) |  |  | $ | 1 |
Amounts recognized in the consolidated balance sheets consist of: |  |  |  |  |  |  |
Current assets | $ | 27 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Non-current assets | — |  |  | — |  |  | 24 |  |  | — |
Current liabilities | — |  |  | — |  |  | (1) |  |  | (1) |
Non-current liabilities | — |  |  | (1) |  |  | — |  |  | — |
| $ | 27 |  |  | $ | (1) |  |  | $ | 23 |  |  | $ | (1) |
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of: |  |  |  |  |  |  |
Net actuarial loss | $ | — |  |  | $ | — |  |  | $ | (9) |  |  | $ | — |
Prior service credit | — |  |  | — |  |  | — |  |  | 11 |
| $ | — |  |  | $ | — |  |  | $ | (9) |  |  | $ | 11 |

In 2024, the actuarial loss rel ated to the benefit obligation for Sunoco’s pension plans was primarily attributable to the termination of the Pension Plan. The fair value of Sunoco’s plan assets is affected by the return on plan assets resulting primarily from the performance of equity and bond markets during the period.
21.Unit-Based Compensation
Sunoco Phantom Units. The Partnership has issued phantom units to its employees and non-employee directors, which vest 60% after three years and 40% after five years. Phantom units have the right to receive distributions prior to vesting. The fair value of
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these units is the market price of Sunoco’s common units on the grant date, and is amortized over the five-year vesting period using the straight-line method. Unit-based compensation expense related to the Partnership included in our consolidated statements of operations and comprehensive income was $19 million, $17 million and $17 million for the years ended December 31, 2025, 2024 and 2023, respec tively. The total fair value of phantom units vested for the years ended December 31, 2025, 2024 and 2023, was $16 million, $14 million and $16 million, res pectively, based on the market price of Sunoco’s common units as of the vesting date. Unrecognized compensation expenses related to ou r unvested p hantom units totaled $68 million as of December 31, 2025, which are expected to be recognized over a weighted average period of 3.17 years.
Phantom unit award activity for the year ended December 31, 2025 consisted of the following:

| Number of Phantom Common Units |  | Weighted Average Grant Date Fair Value
Outstanding at January 1, 2025 | 1,542,700 |  |  | $ | 46.83 |
Granted | 730,078 |  |  | 54.79 |
Vested | (442,386) |  |  | 36.60 |
Forfeited | (59,020) |  |  | 48.22 |
Outstanding at December 31, 2025 | 1,771,372 |  |  | $ | 52.49 |

Sunoco Cash Restricted Units. Beginning in 2024, the Partnership also granted cash restricted units, which vest through three years of service. A cash rest ricted unit entitles the award recipient to receive cash equal to the market value of one Sunoco common unit upon vesting. For the years ended December 31, 2025 and 2024, the Partnership granted a total of 217,432 and 134,225 cash restricted units, respectively. As of December 31, 2025, the Partnership had outstanding grants of cash restricted units totaling 303,179.
SunocoCorp Long-Term Incentive Plan
SunocoCorp has established a long-term incentive plan, under which equity awards have been granted to its non-employee directors, as well as certain of the Partnership’s international employees. Compensation expense associated with grants to Partnership employees will be recognized by the Partnership over the vesting period.
SunocoCorp Phantom Units. As of December 31, 2025, SunocoCorp had granted 183,813 phantom units, which have similar vesting provisions to those issued by the Partnership, as discussed above. The fair value of these units is the market price of SunocoCorp common units on the grant date, and is amortized over the vesting period using the straight-line method. Total unrecognized compensation expenses related to SunocoCorp unvested phantom units totaled $9 million as of December 31, 2025, which are expected to be recognized over a weighted average period of 3.8 years. The fair value of unvested phantom units outstanding as of December 31, 2025 totaled $9 million.
Phantom unit award activity for the year ended December 31, 2025 consisted of the following:

| Number of Phantom Common Units |  | Weighted Average Grant Date Fair Value
Outstanding at January 1, 2025 | — |  |  | $ | — |
Granted | 183,813 |  |  | 51.24 |
Vested | — |  |  | — |
Forfeited | — |  |  | — |
Outstanding at December 31, 2025 | 183,813 |  |  | $ | 51.24 |

Cash Restricted Units. In December 2025, SunocoCorp issued 61,171 cash restricted units under its long-term incentive plan to the Partnership’s international employees who contributed to the Partnership’s international operations. The compensation expense associated with these awards will be recognized by the Partnership over the vesting period of three years.
22.Segment Reporting
Description of Segments
Our consolidated financial statements reflect four reportable segments: Fuel Distribution, Pipeline Systems, Terminals, and Refinery.
Fuel Distribution. Our Fuel Distribution segment supplies motor fuel to independently-operated dealer stations, distributors, commission agents and other consumers. Also included in our Fuel Distribution segment is lease income from properties that we lease or sublease, as well as the Partnership’s credit card services, franchise royalties and retail operations in North America and the Greater Caribbean.
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Pipeline Systems. Our Pipeline Systems segment includes an integrated pipeline and terminal network comprised of approximately 6,000 miles of refined product pipeline (including the pipeline of J.C. Nolan), approximately 6,000 miles of crude oil pipeline (including the pipelines of ET-S Permian), approximately 2,000 miles of ammonia pipeline and 69 terminals.
Terminals. Our Terminals segment is composed of four transmix processing facilities and 83 terminals (two in Europe, six in Hawaii, nine in Canada, 13 in the Greater Caribbean and 53 in the continental United States).
Refinery. Our Refinery segment is composed of the Burnaby Refinery, which was acquired in the Parkland Acquisition, with an operational capacity of approximately 55,000 barrels per day. The refinery consumes primarily sweet conventional crude oil and sweet synthetic crude oil to produce gasoline, diesel and jet fuel among other products. The refinery meets federal and provincial regulations for lower carbon intensity transportation fuels through a combination of co-processing of bio feedstocks (i.e. canola oil, tallow, tall oil and others) and blending of low-carbon intensity fuels such as bio-diesel, renewable diesel, ethanol and others. Fuel from the refinery is sold primarily through Sunoco-owned retail network in British Columbia (“BC”), directly to Vancouver International Airport, and to commercial and cardlock customers.
Segment Operating Results
The Partnership evaluates performance and allocates resources for all of its reportable segments based on Segment Adjusted EBITDA.
The Partnership’s chief operating decision maker (“CODM”) is its chief operating officer. The CODM uses Segment Adjusted EBITDA to allocate resources (including employees, property, and financial or capital resources) for each segment predominantly in the annual budget and forecasting process. The CODM considers forecast-to-actual variances on a monthly basis when making decisions about allocating capital and personnel to the segments. The CODM also uses Segment Adjusted EBITDA to assess the performance for each segment and in the compensation of certain employees. Assets by segment are not a measure used to assess our performance by the CODM and thus are not reported in our disclosures.
The Partnership’s reportable segments are business units that offer different products and services. The reportable segments are each managed separately because they provide different services and products.
We report Adjusted EBITDA by segment as a measure of segment performance. We define Adjusted EBITDA as net income before net interest expense, income tax expense, depreciation, amortization and accretion expense, non-cash compensation expense, gains and losses on disposal of assets and impairment charges, unrealized gains and losses on commodity derivatives, inventory adjustments, certain foreign currency transaction gains and losses and certain other operating expenses reflected in net income that we do not believe are indicative of ongoing core operations. Inventory valuation adjustments that are excluded from the calculation of Adjusted EBITDA represent changes in lower of cost or market reserves on the Partnership's inventory. These amounts are unrealized valuation adjustments applied to fuel volumes remaining in inventory at the end of the period.
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The following tables present financial information by segment for the years ended December 31, 2025, 2024 and 2023.

| Year Ended December 31,
| 2025 |  | 2024 |  | 2023
Revenues: |  |  |  |  |
Fuel Distribution |  |  |  |  |
Revenues from external customers | $ | 23,862 |  |  | $ | 21,781 |  |  | $ | 22,955 |
Intersegment revenues | 71 |  |  | 41 |  |  | 31 |
| 23,933 |  |  | 21,822 |  |  | 22,986 |
Pipeline Systems |  |  |  |  |
Revenues from external customers | 729 |  |  | 562 |  |  | 1 |
Intersegment revenues | 22 |  |  | 3 |  |  | — |
| 751 |  |  | 565 |  |  | 1 |
Terminals |  |  |  |  |
Revenues from external customers | 433 |  |  | 350 |  |  | 112 |
Intersegment revenues | 971 |  |  | 985 |  |  | 373 |
| 1,404 |  |  | 1,335 |  |  | 485 |
Refinery |  |  |  |  |
Revenues from external customers | 177 |  |  | — |  |  | — |
Intersegment revenues | 297 |  |  | — |  |  | — |
| 474 |  |  | — |  |  | — |
Eliminations | (1,361) |  |  | (1,029) |  |  | (404) |
Total | $ | 25,201 |  |  | $ | 22,693 |  |  | $ | 23,068 |

| Year Ended December 31,
| 2025 |  | 2024 |  | 2023
Cost of sales: |  |  |  |  |
Fuel Distribution | $ | 22,419 |  |  | $ | 20,635 |  |  | $ | 21,761 |
Pipeline Systems | 13 |  |  | 30 |  |  | (2) |
Terminals | 904 |  |  | 959 |  |  | 348 |
Refinery | 434 |  |  | — |  |  | — |
Eliminations | (1,361) |  |  | (1,029) |  |  | (404) |
Total | $ | 22,409 |  |  | $ | 20,595 |  |  | $ | 21,703 |

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| Year Ended December 31,
| 2025 |  | 2024 |  | 2023
Operating and lease expenses, excluding non-cash unit-based compensation: |  |  |  |  |
Fuel Distribution | $ | 492 |  |  | $ | 325 |  |  | $ | 350 |
Pipeline Systems | 196 |  |  | 136 |  |  | 2 |
Terminals | 181 |  |  | 150 |  |  | 67 |
Refinery | 5 |  |  | — |  |  | — |
Total | $ | 874 |  |  | $ | 611 |  |  | $ | 419 |

| Year Ended December 31,
| 2025 |  | 2024 |  | 2023
General and administrative expenses, excluding non-cash unit-based compensation: |  |  |  |  |
Fuel Distribution | $ | 206 |  |  | $ | 88 |  |  | $ | 113 |
Pipeline Systems | 42 |  |  | 123 |  |  | — |
Terminals | 33 |  |  | 55 |  |  | 1 |
Refinery | 1 |  |  | — |  |  | — |
Total | $ | 282 |  |  | $ | 266 |  |  | $ | 114 |

| Year Ended December 31,
| 2025 |  | 2024 |  | 2023
Other(1): |  |  |  |  |
Fuel Distribution | $ | (174) |  |  | $ | (134) |  |  | $ | (103) |
Pipeline Systems | (218) |  |  | (101) |  |  | (10) |
Terminals | (13) |  |  | (1) |  |  | (19) |
Refinery | (6) |  |  | — |  |  | — |
Total | $ | (411) |  |  | $ | (236) |  |  | $ | (132) |

(1) Other by segment includes Adjusted EBITDA from unconsolidated affiliates, unrealized gains and losses on commodity derivatives, inventory valuation adjustments and other less significant items, as applicable.

| Year Ended December 31,
| 2025 |  | 2024 |  | 2023
Segment Adjusted EBITDA: |  |  |  |  |
Fuel Distribution | $ | 990 |  |  | $ | 908 |  |  | $ | 865 |
Pipeline Systems | 718 |  |  | 377 |  |  | 11 |
Terminals | 299 |  |  | 172 |  |  | 88 |
Refinery | 40 |  |  | — |  |  | — |
Total | $ | 2,047 |  |  | $ | 1,457 |  |  | $ | 964 |

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| Year Ended December 31,
| 2025 |  | 2024 |  | 2023
Reconciliation of net income to Adjusted EBITDA: |  |  |  |  |
Net income | $ | 527 |  |  | $ | 874 |  |  | $ | 394 |
Depreciation, amortization and accretion | 688 |  |  | 368 |  |  | 187 |
Interest expense, net | 541 |  |  | 391 |  |  | 217 |
Non-cash unit-based compensation expense | 19 |  |  | 17 |  |  | 17 |
(Gain) loss on disposal of assets and impairment charges | (6) |  |  | 45 |  |  | (7) |
Loss on extinguishment of debt | 31 |  |  | 2 |  |  | — |
Unrealized (gains) losses on commodity derivatives | (11) |  |  | 12 |  |  | (21) |
Inventory valuation adjustments | 156 |  |  | 86 |  |  | 114 |
Equity in earnings of unconsolidated affiliates | (143) |  |  | (60) |  |  | (5) |
Adjusted EBITDA related to unconsolidated affiliates | 221 |  |  | 101 |  |  | 10 |
Gain on West Texas Sale | — |  |  | (586) |  |  | — |
Other non-cash adjustments | (38) |  |  | 32 |  |  | 22 |
Income tax expense | 62 |  |  | 175 |  |  | 36 |
Adjusted EBITDA (consolidated) | $ | 2,047 |  |  | $ | 1,457 |  |  | $ | 964 |

Additions to property, plant and equipment (excluding acquisitions) by reportable segment were as follows:

| Year Ended December 31,
| 2025 |  | 2024 |  | 2023
Fuel Distribution | $ | 339 |  |  | $ | 231 |  |  | $ | 182 |
Pipeline Systems | 87 |  |  | 44 |  |  | 5 |
Terminals | 124 |  |  | 69 |  |  | 28 |
Refinery | 27 |  |  | — |  |  | — |
Total | $ | 577 |  |  | $ | 344 |  |  | $ | 215 |

The following table shows total revenues by geographic area:

| Year Ended December 31,
| 2025 |  | 2024 |  | 2023
United States | $ | 22,495 |  |  | $ | 22,649 |  |  | $ | 23,068 |
Canada | 1,703 |  |  | — |  |  | — |
Foreign | 1,003 |  |  | 44 |  |  | — |
Total | $ | 25,201 |  |  | $ | 22,693 |  |  | $ | 23,068 |

The following table shows long-lived assets by geographic area:

| December 31, 2025 |  | December 31, 2024 |  |
United States | $ | 9,053 |  |  | $ | 7,907 |  |  |
Canada | 4,268 |  |  | — |  |  |
Foreign | 1,536 |  |  | 244 |  |  |
Total | $ | 14,857 |  |  | $ | 8,151 |  |  |

23.Net Income per Common Unit
Net income per common unit is computed by dividing common unitholders’ interest in net income by the weighted average number of outstanding common units. Our net income is allocated to common unitholders in accordance with their respective partnership percentages, after giving effect to any priority income allocations for incentive distributions and distributions on employee unit awards. Earnings in excess of distributions are allocated to common unitholders based on their respective ownership interests. Payments made to our common unitholders are determined in relation to actual distributions declared and are not based on the net income allocations used in the calculation of net income per unit.
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In addition to the common units, we identify the IDRs as participating securities and use the two-class method when calculating net income per unit applicable to limited partners, which is based on the weighted average number of common units outstanding during the period. Diluted net income per unit includes the effects of potentially dilutive units on our common units, consisting of unvested phantom units.
A reconciliation of the numerators and denominators of the basic and diluted per unit computations is as follows:

| Year Ended December 31,
| 2025 |  | 2024 |  | 2023
Net income | $ | 527 |  |  | $ | 874 |  |  | $ | 394 |
Less: |  |  |  |  |
Net income attributable to noncontrolling interests | — |  |  | 8 |  |  | — |
Incentive distribution rights | 182 |  |  | 145 |  |  | 77 |
Distributions on unvested phantom unit awards | 7 |  |  | 5 |  |  | 6 |
Preferred unitholders’ interest in net income | 34 |  |  | — |  |  | — |
Class D unitholder’s interest in net income | (9) |  |  | — |  |  | — |
Common unitholders’ interest in net income | $ | 313 |  |  | $ | 716 |  |  | $ | 311 |
Weighted average common units outstanding: |  |  |  |  |
Basic | 136,492,204 |  |  | 118,529,390 |  |  | 84,081,083 |
Dilutive effect of unvested phantom unit awards | 706,014 |  |  | 812,648 |  |  | 1,012,414 |
Diluted | 137,198,218 |  |  | 119,342,038 |  |  | 85,093,497 |
Net income per common unit: |  |  |  |  |
Basic | $ | 2.29 |  |  | $ | 6.04 |  |  | $ | 3.70 |
Diluted | $ | 2.28 |  |  | $ | 6.00 |  |  | $ | 3.65 |

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