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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


☐			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

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

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

Table of Contents

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.

Table of Contents

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 Transfer 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 unitholders.

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), including 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 successful 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, provincial 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 represent 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 percent. 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 distributor 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 approximately 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 any 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 reflected $3.03 billion of goodwill and $2.41 billion of intangible 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 diversified 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, among 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 costs 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 above 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.

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.

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 common 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 (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 aggregate 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 aggregate 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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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.

TanQuid Acquisition

Other Acquisitions

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 to 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 Partnership 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)Excludes $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 subsidiaries totaled $3.95 billion and $476 million, respectively, 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 interest 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.

/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 Partnership, 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 19.1 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

President & Chief Executive Officer and Director

Karl R. Fails

Executive Vice President, Chief Operating Officer

Brian A. Hand

Executive Vice President, Chief Sales Officer

Dylan A. Bramhall

Chief Financial Officer

Austin B. Harkness

Executive Vice President, Chief Commercial Officer

Ray W. Washburne

Chairman of the Board

Oscar A. Alvarez

Director

Bradley C. Barron

Director

David K. Skidmore

Director

W. Brett Smith

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 NuStar 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 executive 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) Reports

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 30th to 40th 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 achievement of the various budget targets sets a bonus pool under the Bonus Plan and the Amended Bonus Plan, actual bonus 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 to 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		—

Sunoco LP 10-K