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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark one)


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

For the fiscal year ended: December 31, 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: 001-35764

PBF ENERGY INC.

(Exact name of registrant as specified in its charter)


Delaware		45-3763855

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

One Sylvan Way, Second Floor
Parsippany,	New Jersey	07054
(Address of principal executive offices)		(Zip Code)

(973) 455-7500

(Registrant’s telephone number, including area code)

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


Title of Each Class	Trading Symbol	Name of Each Exchange on Which Registered
Class A Common Stock, par value $.001	PBF	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. x Yes o 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. o Yes x No

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. x Yes o No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x Yes o 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. o

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

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. o

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes ☒ No

The aggregate market value of the Common Stock of PBF Energy Inc. held by non-affiliates as of June 30, 2025, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $2.5 billion based upon the New York Stock Exchange Composite Transaction closing price.

As of February 6, 2026, PBF Energy Inc. had 116,926,814 shares of Class A common stock and 12 shares of Class B common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

PBF Energy Inc. intends to file with the Securities and Exchange Commission a definitive Proxy Statement for its Annual Meeting of Stockholders within 120 days after December 31, 2025. Portions of the Proxy Statement are incorporated by reference in Part III of this Form 10-K to the extent stated herein.

PBF ENERGY INC.

TABLE OF CONTENTS


PART I

	Item 1.	Business	8
	Item 1A.	Risk Factors	27
	Item 1B.	Unresolved Staff Comments	55
	Item 1C.	Cybersecurity	56
	Item 2.	Properties	57
	Item 3.	Legal Proceedings	58
	Item 4.	Mine Safety Disclosures	60

PART II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	61
	Item 6.	[RESERVED]	63
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	64
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	101
	Item 8.	Financial Statements and Supplementary Data	102
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	102
	Item 9A.	Controls and Procedures	103
	Item 9B.	Other Information	103
	Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	103

PART III

	Item 10.	Directors, Executive Officers and Corporate Governance	104
	Item 11.	Executive Compensation	104
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	104
	Item 13.	Certain Relationships and Related Transactions, and Director Independence	104
	Item 14.	Principal Accountant Fees and Services	104

PART IV
	Item 15.	Exhibits and Financial Statement Schedules	105
	Item 16.	Form 10-K Summary

SIGNATURES

GLOSSARY OF SELECTED TERMS

Unless otherwise noted or indicated by context, the following terms used in this Annual Report on Form 10-K have the following meanings:

“AB 32” refers to the greenhouse gas emission control regulations in the state of California to comply with Assembly Bill 32.

“ANS” refers to Alaskan North Slope crude oil reflective of West Coast economics, characterized by an American Petroleum Institute (“API”) gravity between 28° and 35°.

“ASCI” refers to the Argus Sour Crude Index, a pricing index used to approximate market prices for sour, heavy crude oil.

“Bakken” refers to both a crude oil production region generally covering North Dakota, Montana and Western Canada, and the crude oil that is produced in that region.

“barrel” refers to a common unit of measure in the oil industry, which equates to 42 gallons.

“blendstocks” refers to various compounds that are combined with gasoline or diesel from the crude oil refining process to make finished gasoline and diesel; these may include natural gasoline, FCC unit gasoline, ethanol, reformate or butane, among others.

“bpd” is an abbreviation for barrels per day.

“CAM Pipeline” or “CAM Connection Pipeline” refers to the Clovelly-Alliance-Meraux pipeline in Louisiana.

“CARB” refers to the California Air Resources Board; gasoline and diesel fuel sold in the state of California are regulated by CARB and require stricter quality and emissions reduction performance than required by other states.

“catalyst” refers to a substance that alters, accelerates, or instigates chemical changes, but is not produced as a product of the refining process.

“coke” refers to a coal-like substance that is produced from heavier crude oil fractions during the refining process.

“complexity” refers to the number, type and capacity of processing units at a refinery, measured by the Nelson Complexity Index, which is often used as a measure of a refinery’s ability to process lower quality crude in an economic manner.

“crack spread” refers to a simplified calculation that measures the difference between the price for light products and crude oil. For example, we reference (a) the 2-1-1 crack spread, which is a general industry standard utilized by our Delaware City, Paulsboro and Chalmette refineries that approximates the per barrel refining margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of heating oil or ULSD, (b) the 4-3-1 crack spread, which is a benchmark utilized by our Toledo and Torrance refineries that approximates the per barrel refining margin resulting from processing four barrels of crude oil to produce three barrels of gasoline and one-half barrel of jet fuel and one-half barrel of ULSD and (c) the 3-2-1 crack spread, which is a benchmark utilized by our Martinez refinery that approximates the per barrel refining margin resulting from processing three barrels of crude oil to produce two barrels of gasoline and three-quarters of a barrel jet fuel and one-quarter of a barrel ULSD.

“Dated Brent” refers to Brent blend oil, a light, sweet North Sea crude oil, characterized by an API gravity of 38° and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for other crude oils.

“distillates” refers primarily to diesel, heating oil, kerosene and jet fuel.

“downstream” refers to the downstream sector of the energy industry generally describing oil refineries, marketing and distribution companies that refine crude oil and sell and distribute refined products. The opposite of the downstream sector is the upstream sector, which refers to exploration and production companies that search for and/or produce crude oil and natural gas underground or through drilling or exploratory wells.

“Eni” refers to Eni Sustainable Mobility US Inc., a subsidiary of Eni SpA.

“EPA” refers to the United States Environmental Protection Agency.

“ethanol” refers to a clear, colorless, flammable oxygenated liquid. Ethanol is typically produced chemically from ethylene, or biologically from fermentation of various sugars from carbohydrates found in agricultural crops. It is used in the United States as a gasoline octane enhancer and oxygenate.

“ExxonMobil” refers to Exxon Mobil Corporation.

“FCC” refers to fluid catalytic cracking.

“feedstocks” refers to crude oil and partially refined products that are processed and blended into refined products.

“GAAP” refers to U.S. generally accepted accounting principles developed by the Financial Accounting Standards Board for nongovernmental entities.

“GHG” refers to greenhouse gas.

“Group I base oils or lubricants” refers to conventionally refined products characterized by sulfur content less than 0.03% with a viscosity index between 80 and 120. Typically, these products are used in a variety of automotive and industrial applications.

“heavy crude oil” refers to a relatively inexpensive crude oil with a low API gravity characterized by high relative density and viscosity. Heavy crude oils require greater levels of processing to produce high value products such as gasoline and diesel.

“IPO” refers to the initial public offering of PBF Energy Class A common stock which closed on December 18, 2012.

“IRA” refers to the Inflation Reduction Act; a U.S. federal law enacted on August 16, 2022 that resulted in significant law changes related to tax, climate change, energy, and health care. The tax provision includes, but is not limited to, a corporate alternative minimum tax of 15%, excise tax of 1% on certain corporate stock buy-backs, energy-related tax credits and incentives, and additional Internal Revenue Service (“IRS”) funding.

“KV” refers to Kilovolts.

“LCM” refers to a GAAP requirement for inventory to be valued at the lower of cost or market.

“light crude oil” refers to a relatively expensive crude oil with a high API gravity characterized by low relative density and viscosity. Light crude oils require lower levels of processing to produce high value products such as gasoline and diesel.

“light products” refers to the group of refined products with lower boiling temperatures, including gasoline and distillates.

“LLS” refers to Light Louisiana Sweet benchmark for crude oil reflective of Gulf coast economics for light sweet domestic and foreign crudes. It is characterized by an API gravity of between 35° and 40° and a sulfur content of approximately .35 weight percent.

“LPG” refers to liquefied petroleum gas.

“Maya” refers to Maya crude oil, a heavy, sour crude oil characterized by an API gravity of approximately 22° and a sulfur content of approximately 3.3 weight percent that is used as a benchmark for other heavy crude oils.

“MMBTU” refers to million British thermal units.

“MOEM Pipeline” refers to a pipeline that originates at a terminal in Empire, Louisiana approximately 30 miles north of the mouth of the Mississippi River. The MOEM Pipeline is 14 inches in diameter, 54 miles long and transports crude from South Louisiana to the Chalmette refinery and transports Heavy Louisiana Sweet and South Louisiana Intermediate crude.

“MW” refers to Megawatt.

“Nelson Complexity Index” refers to the complexity of an oil refinery as measured by the Nelson Complexity Index, which is calculated on an annual basis by the Oil and Gas Journal. The Nelson Complexity Index assigns a complexity factor to each major piece of refinery equipment based on its complexity and cost in comparison to crude distillation, which is assigned a complexity factor of 1.0. The complexity of each piece of refinery equipment is then calculated by multiplying its complexity factor by its throughput ratio as a percentage of crude distillation capacity. Adding up the complexity values assigned to each piece of equipment, including crude distillation, determines a refinery’s complexity on the Nelson Complexity Index. A refinery with a complexity of 10.0 on the Nelson Complexity Index is considered ten times more complex than crude distillation for the same amount of throughput.

“NYH” refers to the New York Harbor market value of petroleum products.

“OSHA” refers to the Occupational Safety and Health Administration of the U.S. Department of Labor.

“PADD” refers to Petroleum Administration for Defense Districts.

“refined products” refers to petroleum products, such as gasoline, diesel and jet fuel, that are produced by a refinery.

“RFS” refers to the renewable fuel standard issued pursuant to the Energy Independence and Security Act of 2007 implementing mandates to blend renewable fuels into petroleum fuels produced and sold in the United States.

“Renewable Diesel Facility” refers to a biorefinery co-located with the Chalmette refinery in Louisiana.

“RINs” refers to renewable fuel credits required for compliance with the RFS.

“SBR” refers, collectively, to St. Bernard Renewables LLC and its subsidiaries, a jointly held investment of the Company and Eni.

“SEC” refers to the United States Securities and Exchange Commission.

“sour crude oil” refers to a crude oil that is relatively high in sulfur content, requiring additional processing to remove the sulfur. Sour crude oil is typically less expensive than sweet crude oil.

“Sunoco” refers to Sunoco, LLC.

“sweet crude oil” refers to a crude oil that is relatively low in sulfur content, requiring less processing to remove the sulfur than sour crude oil. Sweet crude oil is typically more expensive than sour crude oil.

“Syncrude” refers to a blend of Canadian synthetic oil, a light, sweet crude oil, typically characterized by API gravity between 30° and 32° and a sulfur content of approximately 0.1-0.2 weight percent.

“throughput” refers to the volume processed through a unit or refinery.

“turnaround” refers to a periodically required shutdown and comprehensive maintenance event to refurbish and maintain a refinery unit or units that involves the cleaning, repair, and inspection of such units and occurs generally on a periodic cycle.

“ULSD” refers to ultra-low-sulfur diesel.

“WCS” refers to Western Canadian Select, a heavy, sour crude oil blend typically characterized by API gravity between 20° and 22° and a sulfur content of approximately 3.5 weight percent that is used as a benchmark for heavy Western Canadian crude oil.

“WTI” refers to West Texas Intermediate crude oil, a light, sweet crude oil, typically characterized by API gravity between 38° and 40° and a sulfur content of approximately 0.3 weight percent that is used as a benchmark for other crude oils.

“WTS” refers to West Texas Sour crude oil, a sour crude oil characterized by API gravity between 30° and 33° and a sulfur content of approximately 1.28 weight percent that is used as a benchmark for other sour crude oils.

“yield” refers to the percentage of refined products that is produced from crude oil and other feedstocks.

Explanatory Note

This Annual Report on Form 10-K is filed by PBF Energy Inc. (“PBF Energy”) which is a holding company whose primary asset is an equity interest in PBF Energy Company LLC (“PBF LLC”). PBF Energy is the sole managing member of, and owner of an equity interest representing approximately 99.3% of the outstanding economic interests in PBF LLC as of December 31, 2025. PBF Energy operates and controls all of the business and affairs and consolidates the financial results of PBF LLC and its subsidiaries. PBF LLC is a holding company for the companies that directly and indirectly own and operate our business.

PART I

Unless the context indicates otherwise, the terms “Company”, “we,” “us,” and “our” refer to PBF Energy and its consolidated subsidiaries, including PBF LLC, PBF Holding Company LLC (“PBF Holding”), PBF Investments LLC, Toledo Refining Company LLC, Paulsboro Refining Company LLC (“PRC”), Delaware City Refining Company LLC (“DCR”), Chalmette Refining, L.L.C. (“Chalmette Refining”), PBF Energy Western Region LLC (“PBF Western Region”), Torrance Refining Company LLC (“Torrance Refining”), Torrance Logistics Company LLC, Martinez Refining Company LLC (“MRC”), PBF Green Fuels LLC, and PBF Logistics LP (“PBFX”) and its subsidiaries.

In this Annual Report on Form 10-K, we make certain forward-looking statements, including statements regarding our plans, strategies, objectives, expectations, intentions, and resources, under the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 to the extent such statements relate to the operations of an entity that is not a limited liability company or a partnership. You should read our forward-looking statements together with our disclosures under the heading: “Cautionary Statement for the Purpose of Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995.” When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in this Annual Report on Form 10-K under “Risk Factors” in Item 1A.

ITEM 1. BUSINESS

Overview and Corporate Structure

We are one of the largest independent petroleum refiners and suppliers of unbranded transportation fuels, heating oil, petrochemical feedstocks, lubricants and other petroleum products in the United States. We sell our products throughout the Northeast, Midwest, Gulf Coast and West Coast of the United States, as well as in other regions of the United States, Canada and Mexico and are able to ship products to other international destinations. We own and operate six domestic oil refineries and related assets and own a 50% interest in the Renewable Diesel Facility through our SBR equity method investment. Our refineries have a combined processing capacity, known as throughput, of approximately 1,000,000 bpd, and a weighted-average Nelson Complexity Index of 12.8 based on current operating conditions. The complexity and throughput capacity of our refineries are subject to change dependent upon configuration changes we make to respond to market conditions, as well as a result of investments made to improve our facilities and maintain compliance with environmental and governmental regulations. We operate in two reportable business segments: Refining and Logistics. Our six oil refineries are all engaged in the refining of crude oil and other feedstocks into petroleum products, and represent the Refining segment. PBFX operates certain logistical assets such as crude oil and refined products terminals, pipelines, and storage facilities, which represent the Logistics segment.

PBF Energy is a holding company whose primary asset is a controlling equity interest in PBF LLC. We are the sole managing member of PBF LLC and operate and control all of the business and affairs of PBF LLC. We consolidate the financial results of PBF LLC and its subsidiaries and record a noncontrolling interest in our consolidated financial statements representing the economic interests of the members of PBF LLC other than PBF Energy (as defined below). PBF LLC is a holding company for the companies that directly or indirectly own and operate our business. PBF Holding is a wholly-owned subsidiary of PBF LLC and is the parent company for our refining operations. PBFX is an indirect wholly-owned subsidiary of PBF LLC that owns and operates logistics assets that support our refining operations.

As of December 31, 2025, PBF Energy held 116,958,307 PBF LLC Series C Units and our current and former executive officers and directors and certain employees and others held 862,780 PBF LLC Series A Units (we refer to all of the holders of the PBF LLC Series A Units as “the members of PBF LLC other than PBF Energy”). As a result, the holders of PBF Energy’s issued and outstanding shares of its Class A common stock have approximately 99.3% of the voting power in PBF Energy, and the members of PBF LLC through their holdings of Class B common stock have approximately 0.7% of the voting power in PBF Energy.

The following map details the locations of our refineries (each as defined below):

Refining

Our six refineries are located in Delaware City, Delaware, Paulsboro, New Jersey, Toledo, Ohio, Chalmette, Louisiana, Torrance, California and Martinez, California. Each refinery is briefly described in the table below:

Refinery

Region

Nelson Complexity Index (1)

Throughput Capacity (in bpd) (1)

PADD

Crude Processed (2)

Source (2)

Delaware City

East Coast

13.6

180,000

light sweet through heavy sour

water, rail

Paulsboro

East Coast

9.1 (3)

155,000 (3)

light sweet through heavy sour

water

Toledo

Mid-Continent

11.0

180,000

light sweet

pipeline, truck, rail

Chalmette

Gulf Coast

13.0

185,000

light sweet through heavy sour

water, pipeline

Torrance

West Coast

13.8

166,000

medium and heavy

pipeline, water, truck

Martinez

West Coast

16.1

157,000

medium and heavy

water

________

(1) Reflects operating conditions at each refinery as of the date of this filing. Changes in complexity and throughput capacity reflect the result of current market conditions, in addition to investments made to improve our facilities and maintain compliance with environmental and governmental regulations. Configurations at each of our refineries are evaluated periodically and updated accordingly.

(2) Reflects the typical crude and feedstocks and related sources utilized under normal operating conditions and prevailing market environments.

(3) At full operating capacity and prevailing market environments, our Nelson Complexity Index and throughput capacity for the Paulsboro refinery would be 13.1 and 180,000, respectively. As a result of the reconfiguration of our East Coast refineries in 2020, and subsequent restart of several idled processing units at the Paulsboro refinery in 2022, our Nelson Complexity Index and throughput capacity were adjusted.

Logistics

PBFX, an indirect wholly-owned subsidiary of PBF Energy and PBF LLC, owns or leases, operates, develops and acquires crude oil and refined products terminals, pipelines, storage facilities and similar logistics assets. PBFX engages in the receiving, handling, storage and transferring of crude oil, refined products, natural gas and intermediates from sources located throughout the United States and Canada for PBF Energy in support of its refineries, as well as for third-party customers. The majority of PBFX’s revenues are derived from long-term, fee-based commercial agreements with PBF Holding, which include minimum volume commitments, for receiving, handling, storing and transferring crude oil, refined products and natural gas. PBF Energy also has agreements with PBFX that establish fees for certain general and administrative services and operational and maintenance services provided by PBF Holding to PBFX. These transactions, other than those with third parties, are eliminated by us in consolidation.

See “Item 1A. Risk Factors” and “Item 13. Certain Relationships and Related Transactions, and Director Independence.”

Recent Developments

On February 1, 2025, a fire occurred at MRC, while the refinery was in the preliminary stages of its previously announced turnaround (the “Martinez refinery fire”). As a result of the Martinez refinery fire, the refinery was fully shut down until April 2025, when certain unaffected units, including the crude unit, were restarted and the refinery began producing limited quantities of gasoline, jet fuel, and intermediates. Investigations are being conducted by various regulatory agencies, including the California Department of Industrial Relations - the Division of Occupational Safety and Health (“CalOSHA”), the Bay Area Air District (“BAAD”), Contra Costa County (“CCC”), the Department of Justice (“DOJ”), the United States Attorney’s Office (“USAO”), the EPA, and the Chemical Safety Board (“CSB”). There are uncertainties around these inquiries and investigations and potential results and consequences, including whether any financial penalties will be assessed or changes to the operations of the Martinez refinery will result therefrom. At this time, the potential liabilities, including regulatory penalties, arising from the incident are unknown, and the full financial impact of this incident cannot reasonably be estimated.

Construction activities are expected to be complete by February 16, 2026. The commissioning phase of utility systems and certain idled equipment has been underway since early January, and a sequenced restart of the refinery will progress following successful completion of quality assurance and control processes. We expect that start-up of the Catalytic Cracking Unit will be complete in the first week of March.

We expect that the cost of repairs to the fire-damaged units and restoring the refinery to full operational status will largely be covered under our property insurance coverage, subject to our deductible and retentions totaling $30.0 million. Our insurance policy also includes business interruption coverage, which contains a 60-day waiting period. This coverage commenced on April 3, 2025. While we expect our insurance coverage will significantly offset the financial impact of the Martinez refinery fire, other than for the business interruption waiting period, deductibles and retentions, the timing of insurance proceeds may impact our results and our cash flow in a given reporting period.

Our current expectations with respect to the full restart of the Martinez refinery following the Martinez refinery fire, the timing of the restart of certain units damaged by the Martinez refinery fire, the throughput of the Martinez refinery during this period, and anticipated costs and insurance recoveries related to the Martinez refinery fire are based on information available to us as of the date of this filing, and are preliminary and subject to revision. In addition, neither the total amount nor timing of insurance recoveries is certain. During 2025, we received unallocated insurance proceeds totaling $893.5 million, net of deductibles and retentions.

Available Information

Our website address is www.pbfenergy.com. Information contained on our website is not part of this Annual Report on Form 10-K. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any other materials filed with (or furnished to) the SEC by us are available on our website (under “Investors”) free of charge, soon after we file or furnish such material. In this same location, we also post our corporate governance guidelines, code of business conduct and ethics, and the charters of the committees of our Board of Directors. These documents are available free of charge in print to any stockholder that makes a written request to the Secretary, PBF Energy Inc., One Sylvan Way, Second Floor, Parsippany, New Jersey 07054.

The diagram below depicts our organizational structure as of December 31, 2025:

Operating Segments

We operate in two reportable business segments: Refining and Logistics. Our six oil refineries, including certain related logistics assets that are not owned by PBFX, are engaged in the refining of crude oil and other feedstocks into petroleum products, and represent the Refining segment. PBFX operates certain logistics assets such as crude oil and refined products terminals, pipelines and storage facilities. Certain of PBFX’s assets were previously operated and owned by various subsidiaries of PBF Holding and were acquired by PBFX in a series of transactions since its inception. PBFX is reported in the Logistics segment. A substantial majority of PBFX’s revenues are derived from long-term, fee-based commercial agreements with PBF Holding and its subsidiaries and these intersegment related revenues are eliminated in consolidation. See “Note 19 - Segment Information” of our Notes to Consolidated Financial Statements, for detailed information on our operating results by business segment.

Refining Segment

We own and operate six refineries (two of which are operated as a single unit) that provide us with geographic and market diversity. We produce a variety of products at each of our refineries, including gasoline, ULSD, heating oil, jet fuel, lubricants, petrochemicals and asphalt. We sell our products throughout the Northeast, Midwest, Gulf Coast and West Coast of the United States, as well as in other regions of the United States, Canada and Mexico, and are able to ship products to other international destinations.

Our refinery assets as of December 31, 2025 are described below.

East Coast Refining System (Delaware City refinery and Paulsboro refinery)

Overview. The Delaware City refinery is located on an approximately 5,000-acre site, with access to waterborne cargoes and an extensive distribution network of pipelines, barges and tankers, truck and rail. The Delaware City refinery is a fully integrated operation that receives crude via rail at our crude unloading facilities, or via ship or barge at its docks located on the Delaware River. The crude and other feedstocks are stored in an extensive tank farm prior to processing. In addition, there is a 15-lane, 76,000 bpd capacity truck loading rack located adjacent to the refinery and a 23-mile interstate pipeline that are used to distribute clean products. The Paulsboro refinery is located on approximately 950-acres on the Delaware River in Paulsboro, New Jersey, near Philadelphia and approximately 30 miles away from Delaware City. Paulsboro receives crude and feedstocks via its marine terminal on the Delaware River.

As a result of its configuration and process units, Delaware City has the capability of processing a slate of heavy crudes with a high concentration of high sulfur crudes, as well as other high sulfur feedstock when economically viable, and is one of the largest and most complex refineries on the East Coast. The Delaware City refinery is one of two heavy crude processing refineries, the other being our Paulsboro refinery, on the East Coast of the United States. The Delaware City coking capacity is equal to approximately 25% of crude capacity.

The Delaware City refinery primarily processes a variety of medium to heavy, sour crude oils, but can run light, sweet crude oils as well. The refinery has large conversion capacity with its 82,000 bpd FCC unit, 54,500 bpd fluid coking unit and 24,000 bpd hydrocracking unit.

The following table approximates the East Coast Refining System’s current major process unit capacities. Unit capacities are shown in barrels per stream day.


Delaware City Refinery Units						Nameplate Capacity
Crude Distillation Unit						180,000
Vacuum Distillation Unit						105,000
Fluid Catalytic Cracking Unit						82,000
Hydrotreating Units						180,000
Hydrocracking Unit						24,000
Catalytic Reforming Unit						43,000
Benzene / Toluene Extraction Unit						15,000
Butane Isomerization Unit						6,000
Alkylation Unit						12,500
Polymerization Unit						16,000
Fluid Coking Unit						54,500


Paulsboro Refinery Units						Nameplate Capacity
Crude Distillation Units						155,000
Vacuum Distillation Units						86,000
Fluid Catalytic Cracking Unit						Idled
Hydrotreating Units						102,000
Catalytic Reforming Unit						29,000
Alkylation Unit						Idled
Lube Oil Processing Unit						12,000
Delayed Coking Unit						Idled
Propane Deasphalting Unit						11,000

Feedstocks and Supply Arrangements. We source our crude oil and feedstock needs for the East Coast Refining System through waterborne deliveries, primarily through short-term, spot market, and term agreements.

Refined Product Yield and Distribution. The Delaware City refinery predominantly produces gasoline, jet fuel, ULSD and ultra-low sulfur heating oil as well as certain other products. Products produced at the Delaware City refinery are transferred to customers through pipelines, barges or at its truck rack. We market and sell all of our refined products to a variety of customers on the spot market or through term agreements. The Paulsboro refinery predominantly manufactures asphalt, jet fuel, ULSD, and Group I base oils or lubricants. Products produced at the Paulsboro refinery are transferred to customers primarily through pipelines, barges, or at its truck rack. We market and sell all of our refined products independently to a variety of customers on the spot market or through term agreements.

Tankage Capacity. The Delaware City refinery has total storage capacity of approximately 10.0 million barrels. Of the total, approximately 3.6 million barrels of storage capacity are dedicated to crude oil and other feedstock storage with the remaining 6.4 million barrels allocated to finished products, intermediates and other products. The Paulsboro refinery has total storage capacity of approximately 7.5 million barrels. Of the total, approximately 2.1 million barrels are dedicated to crude oil storage with the remaining 5.4 million barrels allocated to finished products, intermediates and other products.

Energy and Other Utilities. Under normal operating conditions, the Delaware City refinery consumes approximately 75,000 MMBTU per day of natural gas supplied via pipeline from third parties. The Delaware City refinery has a 280 MW power plant located on site that consists of two natural gas-fueled turbines with combined capacity of approximately 140 MW and four turbo generators with combined nameplate capacity of approximately 140 MW. Collectively, this power plant produces electricity in excess of Delaware City’s refinery load of approximately 90 MW. Excess electricity is sold into the Pennsylvania-New Jersey-Maryland, or PJM, grid. Steam is primarily produced by a combination of three dedicated boilers, two heat recovery steam generators on the gas turbines, and is supplemented by secondary boilers at the FCC and Coker. The Delaware City refinery has long-term contracts to purchase hydrogen from third-party suppliers.

Under normal operating conditions, the Paulsboro refinery currently consumes approximately 40,000 MMBTU per day of natural gas supplied via pipeline from third parties. The Paulsboro refinery is mostly self-sufficient for electrical power through a mix of gas and steam turbine generators. The Paulsboro refinery generation supplies all of the 20MW total refinery load. There are circumstances where available generation is greater than the total refinery load, and the Paulsboro refinery can export up to about 40MW of power to the utility grid if warranted. If necessary, supplemental electrical power is available on a guaranteed basis from the local utility. The Paulsboro refinery is connected to the grid via three separate 69KV aerial feeders and has the ability to run entirely on imported power. Steam is produced in three boilers and a heat recovery steam generator fed by the exhaust from the gas turbine. In addition, there are a number of waste heat boilers and furnace stack economizers throughout the refinery that supplement the steam generation capacity. The Paulsboro refinery’s hydrogen needs are met by the steam methane reformer and the catalytic reformer.

Toledo Refinery

Overview. The Toledo refinery primarily processes a slate of light, sweet crudes from Canada, the Mid-Continent, the Bakken region and the U.S. Gulf Coast. The Toledo refinery is located on a 282-acre site near Toledo, Ohio, approximately 60 miles from Detroit. Crude is delivered to the Toledo refinery through three primary pipelines: (1) Enbridge from the north, (2) Patoka from the west and (3) Mid-Valley from the south. Crude is also delivered to a nearby terminal by rail and from local sources by truck to a truck unloading facility within the refinery.

The following table approximates the Toledo refinery’s current major process unit capacities. Unit capacities are shown in barrels per stream day.


Toledo Refinery Units						Nameplate Capacity
Crude Distillation Unit						180,000
Fluid Catalytic Cracking Unit						82,000
Hydrotreating Units						95,000
Hydrocracking Unit						52,000
Catalytic Reforming Units						52,000
Alkylation Unit						11,000
Polymerization Unit						7,000
UDEX Unit						16,300

Feedstocks and Supply Arrangements. We source our crude oil and feedstock needs for the Toledo refinery through connections to the Marysville Pipeline and Maumee Pipeline, and via truck rack, primarily through short-term and spot market agreements.

Refined Product Yield and Distribution. The Toledo refinery produces finished products, including gasoline, jet and ULSD, in addition to a variety of high-value petrochemicals including benzene, toluene, xylene, nonene and tetramer. The Toledo refinery is connected, via pipelines, to an extensive distribution network throughout Ohio, Illinois, Indiana, Kentucky, Michigan, Pennsylvania and West Virginia. The finished products are transported on pipelines owned by Sunoco Logistics Partners L.P. and Buckeye Partners L.P. In addition, we have proprietary connections to a variety of smaller pipelines and spurs that help us optimize our clean products distribution. A significant portion of the Toledo refinery’s gasoline and ULSD are distributed through various terminals in this network.

We have an agreement with Sunoco whereby Sunoco purchases gasoline and distillate products representing approximately one-third of the Toledo refinery’s gasoline and distillates production. The agreement expires in June 2027, but may be extended for one additional year if mutually agreed upon, and is subject to certain early termination rights. We sell the bulk of the petrochemicals produced at the Toledo refinery through short-term contracts or on the spot market and the majority of the petrochemical distribution is done via rail.

Tankage Capacity. The Toledo refinery has total storage capacity of approximately 4.5 million barrels. The Toledo refinery receives its crude through pipeline connections and a truck rack. Of the total, approximately 1.3 million barrels are dedicated to crude oil storage with the remaining 3.2 million barrels allocated to intermediates and products.

Energy and Other Utilities. Under normal operating conditions, the Toledo refinery consumes approximately 25,000 MMBTU per day of natural gas supplied via pipeline from third parties. The Toledo refinery purchases its electricity from the PJM grid and has a long-term contract to purchase hydrogen and steam from a local third-party supplier. In addition to the third-party steam supplier, the Toledo refinery consumes a portion of the steam that is generated by its various process units.

Chalmette Refinery

Overview. The Chalmette refinery is located on a 400-acre site near New Orleans, Louisiana. It is a dual-train coking refinery and is capable of processing both light and heavy crude oil through its 185,000 bpd crude units and downstream units. Chalmette Refining owns 100% of the MOEM Pipeline, providing access to the Empire Terminal, as well as the CAM Connection Pipeline, providing access to the Louisiana Offshore Oil Port facility through a third-party pipeline. Chalmette Refining also owns 80% of each of the Collins Pipeline Company and T&M Terminal Company, both located in Collins, Mississippi, which provide a clean products outlet for the refinery to the Plantation and Colonial Pipelines. In addition, there is also a marine terminal capable of importing waterborne feedstocks and loading or unloading finished products. There is also a clean products truck rack that provides access to local markets and crude storage. The Renewable Diesel Facility is also co-located at our Chalmette refinery. The facility incorporates a repurposed hydrocracker, along with a newly-constructed pre-treatment unit with capacity to produce 20,000 bpd renewable diesel.

The following table approximates the Chalmette refinery’s current major process unit capacities. Unit capacities are shown in barrels per stream day.


Chalmette Refinery Units						Nameplate Capacity
Crude Distillation Units						185,000
Vacuum Distillation Unit						114,000
Fluid Catalytic Cracking Unit						75,000
Hydrotreating Units						189,000
Delayed Coking Unit						42,000
Catalytic Reforming Unit						42,000
Alkylation Unit						17,000
Aromatics Extraction Unit						17,000

Feedstocks and Supply Arrangements. We source our crude oil and feedstock needs for the Chalmette refinery through connections to the CAM Pipeline and MOEM Pipeline, and via waterborne deliveries, primarily through short-term and spot market agreements.

Refined Product Yield and Distribution. The Chalmette refinery predominantly produces gasoline and diesel fuels and also manufactures high-value petrochemicals including benzene and xylene. Products produced at the Chalmette refinery are transferred to customers through pipelines, the marine terminal and truck rack. The majority of our clean products are delivered to customers via pipelines. Our ownership of the Collins pipeline and T&M terminal provides the Chalmette refinery with strategic access to Southeast and East Coast markets through third-party logistics.

Tankage Capacity. The Chalmette refinery has a total tankage capacity of approximately 8.1 million barrels. Of this total, approximately 2.6 million barrels are allocated to crude oil storage with the remaining 5.5 million barrels allocated to intermediates and products.

Energy and Other Utilities. Under normal operating conditions, the Chalmette refinery consumes approximately 25,000 MMBTU per day of natural gas supplied via pipeline from third parties. The Chalmette refinery purchases its electricity from a local utility and has a long-term contract to purchase hydrogen from a third-party supplier. Steam is primarily produced by a combination of three dedicated boilers, various process units, and a secondary boiler at the FCC.

Torrance Refinery

Overview. The Torrance refinery is located on 750-acres in Torrance, California. It is a high-conversion crude, delayed-coking refinery capable of processing both heavy and medium crude oils through its crude unit and downstream units. In addition to refining assets, the Torrance refinery comprises a number of high-quality logistics assets including a sophisticated network of crude and products pipelines, product distribution terminals and refinery crude and product storage facilities. The most significant logistics asset is a crude gathering and transportation system which delivers San Joaquin Valley crude oils directly from the field to the refinery. Additionally, there are several pipelines serving the refinery that provide access to sources of waterborne crude oils including the Ports of Long Beach and Los Angeles, as well as clean product outlets with a direct pipeline that supplies jet fuel to the Los Angeles airport that are held by affiliates of the refinery.

The following table approximates the Torrance refinery’s current major process unit capacities. Unit capacities are shown in barrels per stream day.


Torrance Refinery Units						Nameplate Capacity
Crude Distillation Unit						166,000
Vacuum Distillation Unit						102,000
Fluid Catalytic Cracking Unit						90,000
Hydrotreating Units						155,500
Hydrocracking Unit						25,000
Alkylation Unit						25,500
Delayed Coking Unit						58,000

Feedstocks and Supply Arrangements. We source our crude oil and feedstock needs for the Torrance refinery mainly through connections to our own pipeline, and via waterborne deliveries and truck racks, primarily through short-term and spot market agreements.

Refined Product Yield and Distribution. The Torrance refinery predominantly produces gasoline, jet fuel and diesel fuels. Products produced at the Torrance refinery are transferred to customers through pipelines, the marine terminal and truck rack. The majority of clean products are delivered to customers via pipelines. We currently market and sell all of our refined products independently to a variety of customers either on the spot market or through term agreements.

Tankage Capacity. The Torrance refinery has a total tankage capacity of approximately 8.6 million barrels. Of this total, approximately 2.1 million barrels are allocated to crude oil storage with the remaining 6.5 million barrels allocated to intermediates and products.

Energy and Other Utilities. Under normal operating conditions, the Torrance refinery consumes approximately 47,000 MMBTU per day of natural gas supplied via pipeline from third parties. The Torrance refinery generates some power internally using a combination of steam and gas turbines and purchases any additional needed power from the local utility. The Torrance refinery has a long-term contract to purchase hydrogen from a third-party supplier. Steam is primarily produced by a combination of five dedicated boilers, various process units, and secondary boilers at the FCC and Hydrogen Units.

Martinez Refinery

Overview. The Martinez refinery is located on an 860-acre site in the City of Martinez, 30 miles northeast of San Francisco, California. The refinery is a high-conversion, dual-coking facility and one of the most complex refineries in the United States. The facility is strategically positioned in Northern California and provides for operating and commercial synergies with the Torrance refinery located in Southern California. In addition to refining assets, the Martinez refinery includes a number of high-quality onsite logistics assets including a deep-water marine facility, product distribution terminals and refinery crude and product storage facilities with approximately 8.8 million barrels of shell capacity.

The following table approximates the Martinez refinery’s current major process unit capacities. Unit capacities are shown in barrels per stream day.


Martinez Refinery Units						Nameplate Capacity
Crude Distillation Unit						157,000
Vacuum Distillation Unit						102,000
Fluid Catalytic Cracking Unit						72,000
Hydrotreating Units						268,000
Hydrocracking Unit						42,900
Alkylation Unit						12,500
Delayed Coking Unit						25,500
Flexi Coking Unit						22,500
Isomerization Unit						15,000

Feedstocks and Supply Arrangements. We source our crude oil and feedstock needs for the Martinez refinery via waterborne deliveries, primarily through short-term and spot market agreements.

Refined Product Yield and Distribution. We entered into certain offtake agreements for our West Coast system with Shell Oil Products for clean products with varying terms up to 15 years. We currently market and sell all of our refined products independently to a variety of customers either on the spot market or through term agreements.

Tankage Capacity. Martinez has a total tankage capacity of approximately 8.8 million barrels. Of this total, approximately 2.5 million barrels are allocated to crude oil storage with the remaining 6.3 million barrels allocated to intermediates and products.

Energy and Other Utilities. Under normal operating conditions, the Martinez refinery consumes approximately 80,000 MMBTU per day of natural gas (including natural gas consumed in hydrogen production) supplied via pipeline from third parties. The Martinez refinery generates some power internally using a combination of steam and gas turbines and purchases any additional needed power from the local utility. The Martinez refinery has a long-term contract to purchase hydrogen from a third-party supplier. Steam is primarily produced by a combination of two heat recovery steam generators on the gas turbines, various process units, and secondary boilers at the FCC and Hydrogen Units.

Logistics Segment

PBFX is an indirect wholly-owned subsidiary of PBF Energy and PBF LLC, that owns or leases, operates, develops and acquires crude oil and refined products terminals, pipelines, storage facilities and similar logistics assets. PBFX’s operations comprise the Logistics segment. PBFX engages in the receiving, handling, storage and transferring of crude oil, refined products, natural gas and intermediates from sources located throughout the United States and Canada for PBF Energy in support of its refineries, as well as for third-party customers. PBFX’s revenue from third-party transactions constituted approximately 9.0% of its revenues in 2025. All other revenues were generated from commercial agreements with PBF Holding. We also have agreements with PBFX that establish fees for certain general and administrative services and operational and maintenance services provided by PBF Holding to PBFX. These transactions, other than those with third parties, are eliminated by us in consolidation.

Principal Products

Our refineries make various grades of gasoline, distillates (including diesel fuel, jet fuel and ULSD) and other products from crude oil, other feedstocks, and blending components. We sell these products through our commercial accounts and sales with major oil companies. For the years ended December 31, 2025, 2024 and 2023, gasoline and distillates accounted for 88.0%, 86.5% and 88.7% of our revenues, respectively.

Customers

We sell a variety of refined products to a diverse customer base. The majority of our refined products are primarily sold through short-term contracts or on the spot market. In addition, we have product offtake arrangements for a portion of our clean products. For the years ended December 31, 2025 and December 31, 2024 only one customer, Shell plc (“Shell”), accounted for 10% or more of our revenues (approximately 13% and 13%, respectively). As of December 31, 2025 and December 31, 2024, only one customer, Shell, accounted for 10% or more of our total trade accounts receivable (approximately 14% and 18%, respectively).

Seasonality

Traditionally, demand for gasoline and diesel is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and construction work. Decreased demand during the winter months can lower gasoline and diesel prices.

Competition

The refining business is very competitive. We compete directly with various other refining companies on the East, Gulf and West Coasts and in the Mid-Continent, with integrated oil companies, with foreign refiners that import products into the United States and with producers and marketers in other industries supplying alternative forms of energy and fuels to satisfy the requirements of industrial, commercial and individual consumers. Some of our competitors have expanded the capacity of their refineries and internationally new refineries are coming on line which could also affect our competitive position.

Profitability in the refining industry depends largely on refined product margins, which can fluctuate significantly, as well as crude oil prices and differentials between the prices of different grades of crude oil, operating efficiency and reliability, product mix and costs of product distribution and transportation. Certain of our competitors that have larger and more complex refineries may be able to realize lower per-barrel costs or higher margins per barrel of throughput. Several of our principal competitors are integrated national or international oil companies that are larger and have substantially greater resources. Because of their integrated operations and larger capitalization, these companies may be more flexible in responding to volatile industry or market conditions, such as shortages of feedstocks or intense price fluctuations. Refining margins are frequently impacted by sharp changes in crude oil costs, which may not be immediately reflected in product prices.

The refining industry is also highly competitive with respect to feedstock supply. Unlike certain of our competitors that have access to proprietary controlled sources of crude oil production available for use at their own refineries, we obtain all of our crude oil and substantially all other feedstocks from unaffiliated sources. The availability and cost of crude oil and feedstock are affected by global supply and demand, as well as other geopolitical factors. We have no crude oil reserves and are not engaged in the exploration or production of crude oil. We believe, however, that we will be able to obtain adequate crude oil and other feedstocks at generally competitive prices for the foreseeable future.

Pursuant to its RFS, EPA has implemented mandates to blend renewable fuels into the petroleum fuels produced and sold in the United States. Because we do not directly produce renewable fuels, increasing the volume of renewable fuels that must be blended into our products could displace an increasing volume of our refineries’ product pool, potentially resulting in lower earnings and profitability. In addition, in order to meet certain of these and future EPA requirements, we may be required to continue to purchase RINs, which historically had, and we expect to have, fluctuating costs based on market conditions.

Corporate Offices

We currently lease approximately 75,700 square feet for our principal corporate offices in Parsippany, New Jersey. The lease for our principal corporate offices expires in 2033. Functions performed in the Parsippany office include overall corporate management, refinery and health, safety and environmental management, planning and strategy, corporate finance, commercial operations, logistics, contract administration, marketing, investor relations, governmental affairs, accounting, tax, treasury, information technology, legal and human resources support functions.

We lease approximately 8,800 square feet for our regional corporate office in Long Beach, California. The lease for our Long Beach office expires in 2027. Functions performed in the Long Beach office include overall regional corporate management, planning and strategy, commercial operations, logistics, contract administration, marketing and governmental affairs.

We lease approximately 11,000 square feet for our regional corporate office in The Woodlands, Texas. The lease for The Woodlands office expires in 2032. Functions performed in The Woodlands include pipeline control center operations, logistics support functions and commercial operations in support of SBR.

Employees and Human Capital

Safety

We believe our responsibility to our employees, neighbors, shareholders, other stakeholders and the environment is only fulfilled through our commitment to safety and reliability. Through rigorous training, sharing of expertise across our sites, continuous monitoring and through promoting a culture of excellence in operations, we continuously strive to keep our people, the communities in which we operate in and the environment safe.

We are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA Hazard Communication Standard requires 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 our operations are in compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances.

Development and Retention

The development, attraction and retention of employees is a critical success factor for our Company. To support the advancement of our employees, we offer rigorous training and development programs and encourage the sharing of expertise across our sites. We actively promote inclusion and diversity in our workforce at each of our locations and provide our employees with opportunities to give back through engagement in our local communities through supportive educational programs, philanthropic and volunteer activities.

We believe that a combination of competitive compensation and career growth and development opportunities help increase employee morale and reduce voluntary turnover. Our comprehensive benefit packages are competitive in the marketplace and we believe in recognizing and rewarding talent through our various cash and equity compensation programs.

Headcount

As of December 31, 2025, we had approximately 3,678 employees, of which 1,935 are covered by collective bargaining agreements. Our hourly employees are covered by collective bargaining agreements through the United Steel Workers (“USW”), the Independent Oil Workers (“IOW”) and the International Brotherhood of Electrical Workers (“IBEW”). We consider our relations with the represented employees to be satisfactory.

Location

Number of employees

Employees covered by collective bargaining agreements

Collective bargaining agreements

Expiration date

Headquarters

511

—

N/A

Delaware City refinery

495

369

USW

January 2026

Paulsboro refinery

300

181

IOW

March 2026

Toledo refinery

481

324

USW

February 2026

Chalmette refinery

545

312

USW

January 2026

Torrance refinery

570

317
13

USW
IBEW

January 2026
January 2026

*
*

Torrance logistics

4
40

USW
USW

January 2026
April 2027

Martinez refinery

591

316
23

USW
IBEW

January 2026
January 2026

*
*

Other Logistics assets

26
10

USW-East Coast Storage Assets
USW- East Coast Terminals

January 2026
May 2027

Total employees

3,678

1,935

*These collective bargaining agreements have expired. Terms related to the new agreements have been agreed to for all items associated with the National Oil Bargaining Program with ratification at the local level pending. The terms of the expired agreements will remain in place under 24-hour rolling extensions until the new agreements are executed.

Information About Our Executive Officers

The following is a list of our executive officers as of February 12, 2026:

Name

Age (as of December 31, 2025 )

Position

Matthew C. Lucey

President, Chief Executive Officer

Joseph Marino

Senior Vice President, Chief Financial Officer

T. Paul Davis

Senior Vice President, Supply, Trading and Optimization

Trecia M. Canty

Senior Vice President, General Counsel & Corporate Secretary

Michael A. Bukowski

Senior Vice President, Head of Refining

Wendy Ho Tai

Senior Vice President, Human Resources

Jim Fedena

Senior Vice President, Logistics, Renewable Fuels, and Strategic Assets

Matthew C. Lucey has served as our President since January 2015 and Chief Executive Officer and a member of our Board of Directors since July 1, 2023. Mr. Lucey is also a director and the Chief Executive Officer of certain of our subsidiaries. Mr. Lucey previously served as our Executive Vice President from April 2014 to December 2014 and served as our Senior Vice President, Chief Financial Officer from April 2010 to March 2014. Mr. Lucey joined us as our Vice President, Finance in April 2008. Prior thereto, Mr. Lucey served as a Managing Director of M.E. Zukerman & Co., a New York-based private equity firm specializing in several sectors of the broader energy industry, from 2001 to 2008. Before joining M.E. Zukerman & Co., Mr. Lucey spent six years in the banking industry.

Joseph Marino has served as our Chief Financial Officer since October 1, 2025. Mr. Marino is also a director and the Chief Financial Officer of certain of our subsidiaries. Previously, Mr. Marino served as our Treasurer from September 2020 to September 2025 and as our Assistant Controller from May 2015 to September 2020. Since joining us in November 2011, Mr. Marino has held numerous finance and accounting roles, including serving as our Director of Financial Reporting during our initial public offering. Prior to joining us, he was employed at Ernst & Young LLP, where he represented large public and private corporations in the oil and gas industry and the industrial products, retail consumer products and health science industries. Mr. Marino is a certified public accountant in New Jersey and New York.

T. Paul Davis has served as our Senior Vice President, Supply, Trading and Optimization since April 2022. He previously served as President, PBF Western Region from September 2017 to April 2022. Mr. Davis joined us in April 2012 and held various executive roles in our commercial operations, including Co-Head of Commercial from January to September 2015, prior to serving as Senior Vice President, Western Region Commercial Operations from September 2015 to September 2017. Previously, Mr. Davis was responsible for managing the U.S. clean products commercial operations for Hess Energy Trading Company from 2006 to 2012. Prior to that, Mr. Davis was responsible for Premcor’s U.S. Midwest clean products disposition group. Mr. Davis has over 42 years of experience in commercial operations in crude oil and refined products, including 16 years with ExxonMobil in various operational and commercial positions, including sourcing refinery feedstocks and crude oil and the disposition of refined products, as well as optimization roles within refineries.

Trecia M. Canty has served as our Senior Vice President, General Counsel and Corporate Secretary since September 2015. In her role, Ms. Canty is responsible for the legal support for the Company’s business activities, including corporate governance, compliance, litigations and mergers and acquisitions. Previously, Ms. Canty was Vice President, Senior Deputy General Counsel and Assistant Secretary from October 2014 and led our commercial and finance legal operations since joining us in November 2012. Ms. Canty is also a director of certain of our subsidiaries. Prior to joining us, Ms. Canty served as Associate General Counsel, Corporate and Assistant Secretary of Southwestern Energy Company, where her responsibilities included finance and mergers and acquisitions, securities and corporate compliance and corporate governance. She also provided legal support to Southwestern Energy Company’s midstream marketing and logistics businesses. Prior to joining Southwestern Energy Company in 2004, she was a senior associate with Cleary, Gottlieb, Steen & Hamilton LLP.

Michael A. Bukowski has served as our Senior Vice President, Head of Refining since March 2024 and has responsibility for our refining operations. Prior to joining us, from May 2023 until February 2024, Mr. Bukowski served as Vice President, Regional Refining for the Midcontinent and Atlantic Basin at Phillips 66. From August 2016 to May 2023, Mr. Bukowski’s prior roles with Phillips 66 included Vice President of Refining Transformation, Vice President, Strategy and various other positions with responsibility for designing a new refining organization and aligning employees with refining and corporate strategies. Mr. Bukowski also previously served as General Manager of Sunoco’s Philadelphia refinery.

Wendy Ho Tai has served as our Senior Vice President, Human Resources since April 2022. She previously served as Vice President, Human Resources from March 2015 to April 2022 and as Senior Director, Compensation and Benefits from October 2010 to February 2015. In her tenure, Ms. Ho Tai has established the PBF benefit plans, implemented the HR information system and assisted in the integration of the employees of all acquisitions. Previously, Ms. Ho Tai held human resources management positions with Petro, Inc. and MarketSmart Interactive.

Jim Fedena has served as our Senior Vice President, Logistics, Renewable Fuels, and Strategic Assets since April 2022. He previously served as a Senior Vice President of Health, Safety and Environment from June 2010 to January 2013. From June 2010 through February 2011, he also served as the Delaware City Refinery Manager during the reactivation period and, from January 2013 to April 2022, he served as Senior Vice President – Logistics. Prior to joining PBF Energy, he served as managing partner for PJF Associates providing consulting services for private equity firms on refining acquisitions in North America and Europe. Mr. Fedena has over 30 years of oil industry experience in refining, pipelines, and terminal operations. He also served in various positions with Premcor, ConocoPhillips, Phillips, Tosco and Coastal with responsibility for health, safety and environmental programs.

Environmental, Health and Safety Matters

Our refineries, pipelines and related operations are subject to extensive and frequently changing federal, state and local laws and regulations, including, but not limited to, those relating to the discharge of materials into the environment or that otherwise relate to the protection of the environment, waste management and the characteristics and the compositions of fuels. Compliance with existing and anticipated laws and regulations can increase the overall cost of operating the refineries, including remediation, operating costs and capital costs to construct, maintain and upgrade equipment and facilities. Permits are also required under these laws for the operation of our refineries, pipelines and related operations and these permits are subject to revocation, modification and renewal. Compliance with applicable environmental laws, regulations and permits will continue to have an impact on our operations, results of operations and capital requirements. We believe that our current operations are in substantial compliance with existing environmental laws, regulations and permits.

We incorporate by reference into this Item the environmental disclosures contained in the following sections of this report:

•Item 1A. “Risk Factors”

◦Our results of operations continue to be impacted by significant costs to comply with renewable fuels mandates. The market prices for RINs have been volatile and may harm our profitability;

◦We may have capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate;

◦We may incur significant liability under, or costs and capital expenditures to comply with, regulatory, environmental and health and safety regulations, which are complex and change frequently;

◦Potential further laws and regulations related to climate change could have a material adverse impact on our operations and adversely affect our facilities;

◦Regulation of emissions of GHGs could force us to incur increased capital expenditures and operating costs that could have a material adverse effect on our results of operations and financial condition;

◦Environmental clean-up and remediation costs of our sites and environmental litigation, including related to climate change, could decrease our net cash flow, reduce our results of operations and impair our financial condition;

◦Our pipelines are subject to federal and/or state regulations, which could reduce profitability and the amount of cash we generate;

◦We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with health, safety, environmental and other laws and regulations;

◦Continued scrutiny on sustainability matters and developments related to climate change may negatively impact our business and our access to capital markets; and

◦We are subject to strict laws and regulations regarding employee and process safety, and failure to comply with these laws and regulations could have a material adverse effect on our results of operations, financial condition and profitability.

•Item 3. “Legal Proceedings”

•Item 8. “Financial Statements and Supplementary Data”

◦ Note 8 - Accrued Expenses, and

◦ Note 11 - Commitments and Contingencies

Applicable Federal and State Regulatory Requirements

As is the case with all companies engaged in industries similar to ours, we face potential exposure to future claims and lawsuits involving environmental and safety matters. These matters include soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances which we manufactured, handled, used, released or disposed of.

Current and future environmental regulations are expected to require additional expenditures, including expenditures for investigation and remediation, which may be significant, at our refineries and at our other facilities. To the extent that future expenditures for these purposes are material and can be reasonably determined, these costs are disclosed and accrued.

Our operations are also subject to various laws and regulations relating to occupational health and safety. We maintain safety training and maintenance programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations. Compliance with applicable health and safety laws and regulations has required and continues to require substantial expenditures.

We cannot predict what additional health, safety and environmental legislation or regulations will be enacted or become effective in the future or how existing or future laws or regulations will be administered or interpreted with respect to our operations. Compliance with more stringent laws or regulations or adverse changes in the interpretation of existing requirements or discovery of new information such as unknown contamination could have an adverse effect on the financial position and the results of our operations and could require substantial expenditures for the installation and operation of systems and equipment that we do not currently possess.

We incorporate by reference into this Item the federal and state regulatory requirements disclosures contained in the following sections of this report:

•Item 8. “Financial Statements and Supplementary Data”

◦ Note 11 - Commitments and Contingencies

ITEM 1A. RISK FACTORS

Summary of Risk Factors

Investing in our common stock involves a degree of risk. These risks are discussed more fully below and include, but are not limited to, the following, any of which could have a material adverse effect on our financial condition, results of operations and cash flows:

Risks Relating to Our Business and Industry

•The price volatility of crude oil, other feedstocks, blendstocks, refined products and fuel and utility services;

•Volatility in commodity prices and refined product demand;

•Crude oil differentials and related factors, which fluctuate substantially;

•Significant interruptions or casualty losses at any of our refineries and related assets or logistics terminals, pipelines or other facilities owned by us or by SBR;

•Interruptions of supply and distribution at our refineries;

•Renewable fuels mandates and the cost of RINs;

•Uncertainty in U.S. trade policy, including uncertainty surrounding changes in tariffs, trade agreements or other trade restrictions imposed by the U.S. or other governments;

•Existence of capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate;

•Regulation related to climate change and emissions of GHGs and other regulatory, environmental and health and safety regulations;

•A cyber-attack on, or other failure of, our technology infrastructure;

•Successful management of the commercial operation of SBR;

•Continued scrutiny on sustainability matters;

•Rate of inflation, including increases due to tariffs and other trade measures that may be imposed or enacted, and its impacts on supply and demand, pricing, and supply chain disruption;

•The amount and the timing of cost savings and operational efficiencies to be achieved through our Refining Business Improvement (“RBI”) initiative;

•Actions taken by our competitors, including adjustments to refining capacity or renewable fuels production in response to regulations and market conditions;

•Volatility and uncertainty in the credit and capital markets, including as a result of higher interest rates;

•Any political instability, including as a result of Russia’s military action in Ukraine, armed hostilities in the middle east, disruption in international shipping resulting from attacks by armed groups on cargo ships, military strikes, sustained military campaigns, terrorist activity, changes in foreign policy, or other catastrophic events;

•Competition from other companies in the refining or renewable fuels industries;

•Delays or cost increases related to capital spending programs;

•Product liability claims, operational liability claims and other material litigation;

•Acquisition or integration of new assets into our business;

•Labor disruptions that would interfere with our operations;

•Discontinuation of employment of any of our senior executives or other key employees;

•Our activity in commodity derivatives markets.

Risks Related to Our Indebtedness

•Our levels of indebtedness;

•Our ability to secure necessary financing on acceptable terms;

•Changes in our credit ratings;

•Limitations on our operations arising out of restrictive covenants in our debt instruments;

•Anti-takeover provisions in our indentures.

Risks Related to Our Organizational Structure and PBF Energy Class A Common Stock

•PBF Energy’s dependence upon distributions from PBF LLC and its subsidiaries to pay taxes and meet its other obligations;

•The rights of other members of PBF LLC may conflict with the interests of PBF Energy Class A common stockholders;

•Obligations under the Tax Receivable Agreement, as defined below;

•Prospect that dividend payments may not be declared in the future;

•Anti-takeover provisions in our certificate of incorporation and bylaws and under Delaware law;

•Volatility of our stock price;

•Potential dilution of our current stockholders.

Risk Factors

You should carefully read the risks and uncertainties described below. The risks and uncertainties described below are not the only ones facing our Company. Additional risks and uncertainties may also impair our business operations. If any of the following risks actually occur, our business, financial condition, results of operations or cash flows would likely suffer. In that case, the trading price of PBF Energy Class A common stock could fall.

Risks Relating to Our Business and Industry

Demand for our refined products can significantly decline due to changes in global and regional economic conditions.

Business closings or reduced activity and layoffs in the markets we operate may adversely affect demand for our refined products. Deterioration of general economic conditions or weak demand levels could require additional actions on our part to lower our operating costs, including temporarily or permanently ceasing to operate units at our facilities. There may be significant incremental costs associated with such actions. Deterioration of global and regional economic conditions may negatively affect our margins and harm our liquidity and ability to repay our outstanding debt and the trading price of PBF Energy’s Class A common stock.

The price volatility of crude oil, other feedstocks, blendstocks, refined products and fuel and utility services may have a material adverse effect on our revenues, profitability, cash flows and liquidity.

Our profitability, cash flows and liquidity from operations depend primarily on the margin above operating expenses (including the cost of refinery feedstocks, such as crude oil, intermediate partially refined products, and natural gas liquids that are processed and blended into refined products) at which we are able to sell refined products. Refining is primarily a margin-based business and, to increase profitability, it is important to maximize the yields of high value finished products while minimizing the costs of feedstock and operating expenses. When the margin between refined product prices and crude oil and other feedstock costs contracts, our earnings, profitability and cash flows are negatively affected. Historically, refining margins have been volatile, and are likely to continue to be volatile, as a result of a variety of factors, including fluctuations in the prices of crude oil, other feedstocks, refined products and fuel and utility services. An increase or decrease in the price of crude oil will likely result in a similar increase or decrease in prices for refined products; however, there may be a time lag in the realization, or no such realization, of the similar increase or decrease in prices for refined products. The effect of changes in crude oil prices on our refining margins therefore depends in part on how quickly and how fully refined product prices adjust to reflect these changes.

The nature of our business has required us to maintain substantial crude oil, feedstock and refined product inventories. Because crude oil, feedstock and refined products are commodities, we have no control over the changing market value of these inventories. Our crude oil, feedstock and refined product inventories are valued at the LCM value under the last-in-first-out (“LIFO”) inventory valuation methodology. If the market value of our crude oil, feedstock and refined product inventory declines to an amount less than our LIFO cost, we would record a write-down of inventory and a non-cash impact to cost of products and other. For example, during the year ended December 31, 2025, we recorded an adjustment to value our inventories to the lower of cost or market which decreased income from operations and net income by $313.0 million and $231.6 million, respectively. At December 31, 2024, the replacement value of inventories exceeded the LIFO carrying value, therefore no LCM inventory reserve was recorded.

Prices of crude oil, other feedstocks, blendstocks, and refined products depend on numerous factors beyond our control, including the supply of and demand for crude oil, other feedstocks, gasoline, diesel, ethanol, asphalt and other refined products. Such supply and demand are affected by a variety of economic, market, environmental and political conditions.

Our direct operating expense structure also impacts our profitability. Our major direct operating expenses include employee and contract labor, maintenance and energy. Our predominant variable direct operating cost is energy, which is comprised primarily of fuel and other utility services. The volatility in costs of fuel, principally natural gas, and other utility services, principally electricity, used by our refineries and other operations affect our operating costs. Fuel and utility prices have been, and will continue to be, affected by factors outside our control, such as supply and demand for fuel and utility services in both local and regional markets, including increased demand resulting from data center development and liquefied natural gas infrastructure and export build-out. Natural gas prices have historically been volatile and, typically, electricity prices fluctuate with natural gas prices. Future increases in fuel and utility prices may have a negative effect on our refining margins, profitability and cash flows.

In addition, the operations, profitability and cash flows of SBR may similarly be impacted by volatility of renewable feedstock costs and operating expenses, which may negatively impact the anticipated benefits and operating synergies from the Renewable Diesel Facility or our equity method investment in SBR. See “We may not be able to successfully realize the anticipated benefits of our investment in SBR or meet our obligations to SBR” risk factor below.

Our working capital, cash flows and liquidity can be significantly impacted by volatility in commodity prices and refined product demand.

Payment terms for our crude oil purchases are typically longer than those terms we extend to our customers for sales of refined products. Additionally, reductions in crude oil purchases tend to lag demand decreases for our refined products. As a result of this timing differential, the payables for our crude oil purchases are generally proportionally larger than the receivables for our refined product sales. As we are normally in a net payables position, a decrease in commodity prices generally results in a use of working capital. Given we process a significant volume of crude oil, the impact can materially affect our working capital, cash flows and liquidity.

Our profitability is affected by crude oil differentials and related factors, which fluctuate substantially.

A significant portion of our profitability is derived from the ability to purchase and process crude oil feedstocks that historically have been less expensive than benchmark crude oils, such as the heavy, sour crude oils processed at our Delaware City, Paulsboro, Chalmette, Torrance and Martinez refineries. For our Toledo refinery, aside from recent crude differential volatility, purchased crude prices have historically been above the WTI benchmark, however, such crude slate typically results in favorable refinery production yield. For all locations, these crude oil differentials can vary significantly from quarter to quarter depending on overall economic conditions and trends and conditions within the markets for crude oil and refined products. Any change in these crude oil differentials may have an impact on our earnings. Our rail investment and strategy to acquire cost advantaged Mid-Continent and Canadian crude, which are priced based on WTI, could be adversely affected when the WTI/Dated Brent or related differentials narrow. A narrowing of the WTI/Dated Brent differential may result in our Toledo refinery losing a portion of its crude oil price advantage over certain of our competitors, which negatively impacts our profitability. In addition, imbalances between the production and capacity to export crude in Canada and reduced supply of heavy, sour grades of crude oil in general due to production curtailments or sanction restrictions may continue to result in price volatility and the narrowing of the WTI/WCS, Mars/Brent, and other light heavy differentials, and may reduce our refining margins and adversely affect our profitability and earnings. Divergent views have been expressed as to the expected magnitude of changes to these crude differentials in future periods. Any continued or further narrowing of these differentials could have a material adverse effect on our business and profitability.

Additionally, governmental and regulatory actions, including sanctions against oil exporting countries and decisions by the Organization of the Petroleum Exporting Countries to restrict crude oil production levels and executive actions by the U.S. presidential administration to advance certain energy infrastructure projects such as the Keystone XL pipeline or Enbridge's Line 5 pipeline, may continue to impact crude oil prices and crude oil differentials. Recent U.S. actions related to Venezuela’s oil sector have included sanction-related seizures of certain oil tankers, as well as public statements by the U.S. presidential administration indicating that authorized sales of Venezuelan crude oil into the U.S. have commenced. While these developments may present opportunities through increased crude oil supply and improved crude oil differentials, they also remain subject to significant political, regulatory, and geopolitical uncertainty. Any increase in crude oil prices or unfavorable movements in crude oil differentials due to such actions or changing regulatory environment may negatively impact our ability to acquire crude oil at economical prices and could have a material adverse effect on our business and profitability.

A significant interruption or casualty loss at any of our refineries and related assets or logistics terminals, pipelines or other facilities owned by us or by SBR, could reduce production, particularly if not fully covered by our insurance. Failure by one or more insurers to honor its coverage commitments for an insured event could materially and adversely affect our future cash flows, operating results and financial condition.

Our business currently consists of owning and operating six refineries and related assets, as well as logistics terminals, pipelines and other facilities and our investment in SBR. As a result, our operations could be subject to significant interruption if any of our refineries or other facilities were to experience a major accident, be damaged by severe weather, wildfires or other natural disasters, or otherwise be forced to shut down or curtail production due to unforeseen events, such as acts of God, nature, orders of governmental authorities, supply chain disruptions impacting our crude rail facilities or other logistics assets, power outages, acts of terrorism, fires, toxic emissions and maritime hazards. Any such shutdown or disruption would reduce the production from that refinery. There is also risk of mechanical failure and equipment shutdowns both in general and following unforeseen events. Further, in such situations, undamaged refinery processing units may be dependent on or interact with damaged sections of our refineries and, accordingly, are also subject to being shut down. In the event any of our refineries is forced to shut down for a significant period of time or permanently, it could have a material adverse effect on our earnings, our other results of operations and our financial condition as a whole. In addition, a shutdown or disruption of our Chalmette refinery could impact the operations of SBR.

On February 1, 2025, the Martinez refinery fire occurred while the refinery was in the preliminary stages of its previously announced turnaround, resulting in the temporary shutdown of refinery operations. As a result of the Martinez refinery fire, the refinery was fully shut down until April 2025 when certain unaffected units, including the crude unit, were restarted. Investigations are being conducted by various regulatory agencies, including the CalOSHA, the BAAD, CCC, the DOJ, the USAO, the EPA, and the CSB. There are uncertainties around these inquiries and investigations and potential results and consequences, including whether any financial penalties will be assessed or changes to the operations of the Martinez refinery will result therefrom. Although we expect that the cost of repairs to the fire-damaged units and the restoration of the refinery to full operational status will be largely covered under our property insurance coverage, there is no guarantee that all losses, including business interruption, will be fully collected as anticipated, in a timely manner. Restart of the units damaged by the Martinez refinery fire is expected to be completed by February 2026 and we expect to achieve planned operating rates by the beginning of March 2026. However, there is no guarantee that we will meet this restart timeline and additional work or repairs may be required that delay our planned restart. Such delays may negatively impact our earnings and cash flows. Furthermore, at this time, potential liabilities arising from the incident, including any regulatory penalties, remain unknown, and the full operational and/or financial impact cannot be reasonably estimated.

As protection against these hazards, we maintain insurance coverage for our refineries against some, but not all, such potential losses and liabilities, including claims against us by third parties relating to our operations and products. We or SBR may not be able to maintain or obtain insurance of the type and amount desired at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may increase substantially. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, coverage for hurricane damage can be limited, and coverage for terrorism risks can include broad exclusions. If we or SBR were to incur a significant liability that was not fully insured, it could have a material adverse effect on our financial position.

Our insurance program includes a number of insurance carriers. Significant disruptions in financial markets could lead to a deterioration in the financial condition of many financial institutions, including insurance companies and, therefore, we may not be able to obtain the full amount of our insurance coverage for insured events. Even where we have insurance in place, there can be no assurance that the carriers will honor their obligations under the policies.

Our refineries are subject to interruptions of supply and distribution, including due to severe weather events, as a result of our reliance on pipelines, waterborne logistics and railroads for transportation of crude oil and refined products.

Our Toledo, Chalmette, and Torrance refineries receive a significant portion of their crude oil through our owned, as well as third-party, pipelines. These pipelines include the Enbridge system, Capline and Mid-Valley pipelines for supplying crude to our Toledo refinery, the MOEM Pipeline and CAM Pipeline for supplying crude to our Chalmette refinery and the San Joaquin Pipeline, San Ardo and Coastal Pipeline systems for supplying crude to our Torrance refinery. Additionally, our Toledo, Chalmette, Torrance and Martinez refineries deliver a significant portion of the refined products through pipelines. These pipelines include pipelines such as the Sunoco Logistics Partners L.P. and Buckeye Partners L.P. pipelines at the Toledo refinery, the Collins pipeline at our Chalmette refinery, the Jet Pipeline to the Los Angeles International Airport, the Product Pipeline to Vernon and the Product Pipeline to Atwood at our Torrance refinery and the KinderMorgan SFPP North Pipeline at our Martinez refinery. We could experience an interruption of supply or delivery, or an increased cost of receiving crude oil and delivering refined products to market, if the ability of these pipelines to transport crude oil or refined products is disrupted because of accidents, weather interruptions, governmental regulation, terrorism, other third-party action or casualty or other events.

The Delaware City rail unloading facilities and the assets acquired in connection with the acquisition of CPI Operations LLC (the “East Coast Storage Assets”), allow our East Coast Refining System to source WTI-based crudes from Western Canada and the Mid-Continent, which may provide significant cost advantages versus traditional Brent-based international crudes in certain market environments. Any disruptions or restrictions to our supply of crude by rail due to problems with third-party logistics infrastructure or operations or as a result of increased regulations, could increase our crude costs and negatively impact our results of operations and cash flows.

Due to the common carrier regulatory obligation applicable to interstate oil pipelines, capacity allocation among shippers can become contentious in the event demand is in excess of capacity. Therefore, nominations by new shippers or increased nominations by existing shippers may reduce the capacity available to us. Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that we rely upon for transportation of crude oil and refined products could have a further material adverse effect on our business, financial condition, results of operations and cash flows.

In addition, substantial weather-related conditions could impact our relationships and arrangements with our major customers and suppliers by materially affecting the normal flow of crude oil and refined products, especially seaborne transactions. For example, natural disasters or severe weather events (such as hurricanes, earthquakes or extreme cold) could damage transportation infrastructures, impede access to waterways and lead to interruptions of our operations, including our ability to deliver our products, or increases in costs to receive crude oil.

Our results of operations continue to be impacted by significant costs to comply with renewable fuels mandates. The market prices for RINs have been volatile and may harm our profitability.

Pursuant to the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007, EPA has issued the RFS, implementing mandates to blend renewable fuels into the petroleum fuels produced and sold in the United States. Under the RFS, the volume of renewable fuels that obligated refineries must blend into their finished petroleum fuels historically has increased on an annual basis. In addition, certain states have passed legislation that requires minimum biodiesel blending in finished distillates. On October 13, 2010, EPA raised the maximum amount of ethanol allowed under federal law from 10% to 15% for cars and light trucks manufactured since 2007. The maximum amount allowed under federal law currently remains at 10% ethanol for all other vehicles. Existing laws and regulations could change, and the minimum volumes of renewable fuels that must be blended with refined petroleum fuels may increase, which could displace an increasing volume of our refinery’s product pool, potentially resulting in lower earnings and profitability. In addition, in order to meet certain of these and future EPA requirements, we may be required to purchase RINs, which may have fluctuating costs based on market conditions. Our results continue to be impacted by significant costs to comply with the RFS. While we have entered into agreements with SBR that allow us to purchase RINs at our election, we incurred approximately $680.1 million in RINs costs during the year ended December 31, 2025 as compared to $515.3 million and $762.3 million during the years ended December 31, 2024 and 2023, respectively. The fluctuations in our RINs costs are due primarily to volatility in prices for ethanol-linked RINs. Our RINs purchase obligation is dependent on our actual shipment of on-road transportation fuels domestically and the amount of blending achieved which can cause variability in our profitability. On June 21, 2023, EPA finalized the volumes of renewable fuels that obligated refineries must blend into their final petroleum fuels for years 2023, 2024, and 2025, and finalized volume requirements and percentage standards under the RFS program for 2023, 2024, and 2025. In June 2025, the EPA proposed volume requirements and percentage standards under the RFS program for 2026 and 2027, as well as making a series of important modifications to strengthen and expand the RFS program. As a result, we could also experience fluctuating compliance costs in the future as the EPA continues to adjust the volume requirements and potentially enacts further changes to the program.

Our financial results could be impacted by uncertainty in U.S. trade policy, including uncertainty surrounding changes in tariffs, trade agreements or other trade restrictions imposed by the U.S. or other governments.

Our business can be impacted by changes in tariffs, changes or repeals of trade agreements or the imposition of other trade restrictions or retaliatory actions imposed by various governments, the status, duration and scope of which remain uncertain and unpredictable. Throughout 2025, the U.S. presidential administration announced broad-based tariffs on goods imported from certain countries where we purchase feedstocks. Certain tariffs remain in effect and continue to apply to certain of our purchases, which could increase our costs and adversely affect our results of operations. If the provisions of those tariffs are maintained, we would expect added market volatility, with the longer term impacts to our refining and marketing margin uncertain. In addition, evolving legal, political or regulatory developments relating to tariffs, and their impact on global trade relationships and geopolitical tensions, remain uncertain. Other effects of these changes, including responsive actions from governments and the unpredictability of U.S. governmental action and response, could also have significant impacts on our business, capital expenditures, and results of operations.

We may have capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate.

If we cannot generate sufficient cash flows or otherwise secure sufficient liquidity to support our short-term and long-term capital requirements, we may not be able to meet our payment obligations or our future debt obligations, comply with certain deadlines related to environmental regulations and standards, or pursue our business strategies, including acquisitions, in which case our operations may not perform as we currently expect. We have substantial short-term capital needs and may have substantial long-term capital needs. Our short-term working capital needs are primarily related to financing certain of our crude oil and refined products inventory.

If we cannot adequately handle our crude oil and feedstock requirements or if we are required to obtain our crude oil supply at our other refineries without the benefit of the existing supply arrangements or the applicable counterparty defaults in its obligations, our crude oil pricing costs may increase as the number of days between when we pay for the crude oil and when the crude oil is delivered to us increases. We fund all inventory purchases with existing working capital or other available sources of liquidity. Further, if we are not able to market and sell our finished products to credit worthy customers, we may be subject to delays in the collection of our accounts receivable and exposure to additional credit risk. Such increased exposure could negatively impact our liquidity due to our increased working capital needs as a result of the increase in the amount of crude oil inventory and accounts receivable we would have to carry on our balance sheet. Our long-term needs for cash include those to repay our indebtedness and other contractual obligations, support ongoing capital expenditures for equipment maintenance and upgrades, including during turnarounds at our refineries, and to complete our routine and normally scheduled maintenance, regulatory and security expenditures.

In addition, from time to time, we may be required to spend significant amounts for repairs when one or more processing units experiences temporary shutdowns. We continue to utilize significant capital to upgrade equipment, improve facilities, and reduce operational, safety and environmental risks. In connection with the Paulsboro, Torrance and Martinez acquisitions, we assumed certain significant environmental obligations, and may similarly do so in future acquisitions. We will likely incur substantial compliance costs in connection with new or changing environmental, health and safety regulations. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Our liquidity and financial condition will affect our ability to satisfy any and all of these needs or obligations.

We may incur significant liability under, or costs and capital expenditures to comply with, regulatory, environmental and health and safety regulations, which are complex and change frequently.

Our operations are subject to federal, state and local laws regulating, among other things, the use and/or handling of petroleum and other regulated materials, the emission and discharge of materials into the environment, waste management, and remediation of discharges of petroleum and petroleum products, characteristics and composition of gasoline and distillates and other matters otherwise relating to the protection of the environment and the health and safety of the surrounding community. Our operations are also subject to extensive laws and regulations relating to occupational health and safety.

We cannot predict what additional environmental, health and safety legislation or regulations may be adopted in the future, or how existing or future laws or regulations may be administered or interpreted with respect to our operations. Many of these laws and regulations have become increasingly stringent over time, and the cost of compliance with these requirements can be expected to increase over time. In addition, a failure to comply with these laws and regulations could adversely impact our ability to operate. For example, MRC is subject to amendments to “Regulation 6-5: Particulate Emissions from Refinery Fluidized Catalytic Cracking Units - 2021 Amendment” (“Rule 6-5 Amendment”) requiring compliance with more stringent standards for particulate emissions from FCC units at refineries in the Bay Area that will be effective in 2026. Although MRC believes that it will achieve compliance through the alternative emissions monitoring system (“AEMS”) approved by the BAAD and subject to validation as part of the settlement agreement entered into on February 12, 2024, there can be no assurance that the AEMS will be validated or achieve the required emissions reductions or that we will not incur significant additional costs to comply with the Rule 6-5 Amendment.

Certain environmental laws impose strict, and in certain circumstances, joint and several, liability for costs of investigation and cleanup of spills, discharges or releases on owners and operators of, as well as persons who arrange for treatment or disposal of regulated materials at, contaminated sites. Under these laws, we may incur liability or be required to pay penalties for past contamination, and third parties may assert claims against us for damages allegedly arising out of any past or future contamination. The potential penalties and clean-up costs for past or future spills, discharges or releases, the failure of prior owners of our facilities to complete their clean-up obligations, the liability to third parties for damage to their property, or the need to address newly-discovered information or conditions that may require a response could be significant, and the payment of these amounts could have a material adverse effect on our business, financial condition, cash flows and results of operations.

See also “Recent record refining industry profits have raised the concern of public policy experts and federal and state policymakers, who have questioned whether these profits are justified, or whether they constituted a “windfall” to the industry and have enacted or could enact legislation that could adversely affect our operations and our profitability” risk factor below for additional regulatory risks that are not environmental, health or safety-related.

Potential further laws and regulations related to climate change could have a material adverse impact on our operations and adversely affect our facilities.

Some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. We believe the issue of climate change may continue to receive scientific and political attention, with the potential for further laws and regulations that could materially adversely affect our ongoing operations.

In addition, as many of our facilities are located near coastal areas, rising sea levels may disrupt our ability to operate those facilities or transport crude oil and refined products. Extended periods of such disruption could have an adverse effect on our results of operation. We could also incur substantial costs to protect or repair these facilities.

Regulation of emissions of GHGs could force us to incur increased capital expenditures and operating costs and could have a material adverse effect on our results of operations and financial condition.

The U.S. federal government under previous presidential administrations took a number of actions to address GHG emissions. For example, both houses of Congress actively considered legislation to reduce emissions of GHGs, such as carbon dioxide and methane, including proposals to: (i) establish a cap and trade system, (ii) create a federal renewable energy or “clean” energy standard requiring electric utilities to provide a certain percentage of power from such sources, and (iii) create enhanced incentives for use of renewable energy and increased efficiency in energy supply and use. In addition, EPA has taken steps to regulate GHGs under the existing federal Clean Air Act (“CAA”). EPA has adopted regulations limiting GHG emissions for light- and medium-duty vehicles and heavy-duty highway vehicles. EPA has also adopted regulations addressing the permitting of GHG emissions from stationary sources, and requiring the reporting of GHG emissions from specified large GHG emission sources, including refineries. However, the current U.S. presidential administration has expressed a different approach with respect to U.S. climate, environmental, and energy policies and has revoked many of the existing executive orders and directives, and has indicated an intention to modify or eliminate many of the aforementioned laws and regulations, several of which are also currently being litigated, or may be subject to future legal challenges. However, the ultimate timing and outcome with respect to any modifications or eliminations of such laws and regulations, which may require action by the U.S. Congress or a federal agency or department, as well as pending or future litigation, are currently unknown and are subject to considerable uncertainty. It is also currently uncertain whether and to what extent any U.S. state and local governments may still pursue the prior administration’s agenda on such matters.

In addition, various states, individually as well as in some cases on a regional basis, have taken steps to control GHG emissions, including adoption of GHG reporting requirements, cap and trade systems and renewable portfolio standards. For example, the State of California’s AB 32 imposes a statewide cap on GHG emissions, including emissions from transportation fuels, with the aim of returning the state to 1990 emission levels by 2020.

Also, in September 2016, the State of California enacted Senate Bill 32, which further reduces GHG emissions targets to 40 percent below 1990 levels by 2030. Two regulations implemented to achieve these goals are Cap-and-Trade and the Low Carbon Fuel Standard (“LCFS”). In 2012, CARB implemented Cap-and-Trade. This program currently places a cap on GHG emissions and we are required to acquire a sufficient number of credits to cover emissions from our refineries and our in-state sales of gasoline and diesel. In 2009, CARB adopted the LCFS, which required a 10% reduction in the carbon intensity of gasoline and diesel by 2020. In 2022, California enacted Assembly Bill 1279 which requires the state to achieve a GHG reduction target of 85 percent below 1990 levels by 2045 and overall carbon neutrality by 2045. CARB also amended the LCFS in 2024, which requires a 30 percent reduction by 2030 and 90 percent reduction by 2045 in the carbon intensity of transportation fuels (compared to a 2010 baseline). Compliance is achieved through blending lower carbon intensity biofuels into gasoline and diesel or by purchasing credits. Compliance with each of these programs is facilitated through a market-based credit system. If sufficient credits are unavailable for purchase or we are unable to pass through costs to our customers, we may have to pay a higher price for credits or if we are otherwise unable to meet our compliance obligations, our financial condition and results of operations could be adversely affected.

Additionally, on September 23, 2020, the California Governor issued Executive Order N-79-20 (“N-79-20 Order”) intended to further reduce GHG emissions within the state. The N-79-20 Order sets a 2035 goal of no new sale of internal combustion engines for passenger cars and pickup trucks within California, and a 2045 goal of no new sale of internal combustion engine medium- and heavy-duty trucks, and off-road vehicles and equipment. However, the N-79-20 Order would still allow used internal combustion engine vehicles to be used and sold after these dates. In an effort to accomplish the 2035 goal, on August 25, 2022, CARB voted unanimously to adopt the Advanced Clean Cars II (“ACCII”) regulations. According to CARB, the ACCII regulations will rapidly scale down light-duty passenger car, truck, and SUV emissions starting with the 2026 model year through 2035. The regulations are two-pronged. First, they amend the California Zero-emission Vehicle Regulation to require an increasing number of zero-emission vehicles, and rely on advanced vehicle technologies, including battery-electric, hydrogen fuel cell electric, and plug-in hybrid electric vehicles, to meet air quality and climate change emissions standards. Second, the regulations amend the California Low-emission Vehicle Regulations to include increasingly stringent standards for gasoline cars and heavier passenger trucks to continue to reduce smog-forming emissions while the sector transitions toward 100% electrification by 2035. Similar to the ACCII, on April 28, 2023, CARB voted unanimously to adopt the Advanced Clean Fleet (“ACF”) regulations with the goal of achieving a zero-emission truck and bus fleet by 2045 everywhere feasible, and significantly earlier for certain market segments such as last mile delivery and drayage applications. The initial focus of ACF is on high-priority fleets with vehicles that are suitable for early electrification, their subhaulers, and entities that hire them.

However, in June 2025, the current U.S. presidential administration signed into law three Congressional Review Act resolutions, approved by congress, revoking CAA waivers that were granted by the previous presidential administration that allowed California to set its own stringent vehicle emissions standards (i.e., ACCII and ACF). California and other states have challenged the revocation of the CAA waivers. While the CAA resolutions are currently being litigated, it is currently uncertain whether and to what extent California, other states and local governments will still pursue the vehicle emission standards. In the event we do incur increased costs as a result of increased efforts to control GHG emissions through future adopted regulatory requirements, we may not be able to pass these costs to our customers. These future regulatory requirements also could adversely affect demand for the refined products that we produce. Any increased costs or reduced demand could materially and adversely affect our business and results of operations.

Environmental clean-up and remediation costs of our sites and environmental litigation, including related to climate change, could decrease our net cash flow, reduce our results of operations and impair our financial condition.

We may be subject to liability for the investigation and clean-up of environmental contamination at each of the properties that we own, lease, occupy or operate and at off-site locations where we arrange for the treatment or disposal of regulated materials. We may become involved in litigation or other proceedings related to the foregoing. If we were to be held responsible for damages in any such litigation or proceedings, such costs may not be covered by insurance and may be material. Historical soil and groundwater contamination has been identified at our refineries. Currently, remediation projects for such contamination are underway in accordance with regulatory requirements at our refineries.

In connection with the acquisitions of certain of our refineries and logistics assets, the prior owners have retained certain liabilities or indemnified us for certain liabilities, including those relating to pre-acquisition soil and groundwater conditions, and in some instances we have assumed certain liabilities and environmental obligations, including certain existing and potential remediation obligations. If the prior owners fail to satisfy their obligations for any reason, or if significant liabilities arise in the areas in which we assumed liability, we may become responsible for remediation expenses and other environmental liabilities, which could have a material adverse effect on our business, financial condition, results of operations and cash flow. As a result, in addition to making capital expenditures or incurring other costs to comply with environmental laws, we also may be liable for significant environmental litigation or for investigation and remediation costs and other liabilities arising from the ownership or operation of these assets by prior owners, which could materially

adversely affect our business, financial condition, results of operations and cash flow. See “Item 1. Business—Environmental, Health and Safety Matters” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Material Cash Requirements”.

We may also face liability arising from current or future claims alleging personal injury or property damage due to exposure to chemicals or other regulated materials, such as various perfluorinated compounds, including perfluorooctanoate, perfluorooctane sulfonate, perfluorohexane sulfonate, or other per-and polyfluoroalkyl substances (collectively, “PFAS”), asbestos, benzene, silica dust and petroleum hydrocarbons, at or from our facilities. We may also face liability for personal injury, property damage, natural resource damage or clean-up costs for the alleged migration of contamination from our properties. A significant increase in the number or success of these claims could materially adversely affect our business, financial condition, results of operations and cash flow. Recently, we have been voluntarily cooperating with various local, state and federal agencies in their review of the environmental and health effects of PFAS and additional PFAS-related laws may be developed at the local, state and federal level that could lead to our incurring liability for damages or other costs, civil or criminal proceedings, the imposition of fines and penalties, or other remedies or otherwise affect our business. Governmental inquiries or lawsuits involving PFAS could lead to our incurring liability for damages or other costs, civil or criminal proceedings, the imposition of fines and penalties, or other remedies, as well as restrictions on or added costs for our business operations going forward, including in the form of restrictions on discharges at our manufacturing facilities or otherwise. We may be subject to asserted or unasserted claims and governmental regulatory proceedings and inquiries related to the use of PFAS in a variety of jurisdictions.

Changes in law or interpretation of settled law and changes in policy, including with respect to climate change, other environmental regulations or regulations mandating efficiency standards or the use of alternative fuels or uncompetitive fuel components, could adversely affect our operations and results by increasing our cost of compliance, delaying or eliminating available business opportunities and/or preventing or limiting existing operations. Our operations also may give rise to federal, state or local government enforcement proceedings alleging non-compliance with applicable laws or regulations.

We operate in jurisdictions where very large and unpredictable punitive damage awards may occur in the context of litigation. Private plaintiffs may also initiate legal action against us for alleged environmental impacts. These parties may attempt to use the legal system to promote public policy agendas (including seeking to reduce the production and sale of hydrocarbon products through litigation targeting the company or other industry participants), gain political notoriety, or obtain monetary awards from the company. For example, in recent years, private litigation has been increasingly initiated against oil and gas companies by local and state agencies and private parties alleging climate change impacts arising from their operations and seeking damages and equitable relief. We have not had any climate change litigation initiated against us to date and we cannot reasonably predict whether any such litigation will be initiated against us or, if initiated, what the outcome would be. If any such litigation were to be initiated against us, at a minimum, we would incur legal and other expenses to defend such lawsuits, which amounts could be significant. If we failed to prevail in any such litigation and were required to pay significant damages and/or materially alter the manner in which we conduct our business, there could be a material adverse impact on our operations, financial condition or results of operations.

Our transportation modes, including pipelines, are subject to federal and/or state regulations, which could reduce profitability and the amount of cash we generate.

Our transportation activities are subject to regulation by multiple governmental agencies. The regulatory burden on the industry increases the cost of doing business and affects profitability. Additional proposals and proceedings that affect the oil industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission, the United States Department of Transportation, and the courts. We cannot predict when or whether any such proposals may become effective or what impact such proposals may have. Projected operating costs related to our pipelines reflect the recurring costs resulting from compliance with these regulations, and these costs may increase due to future acquisitions, changes in regulation, changes in use, or discovery of existing but unknown compliance issues.

Recent record refining industry profits have raised the concern of public policy experts and federal and state policymakers, who have questioned whether these profits are justified, or whether they constituted a “windfall” to the industry and have enacted or could enact legislation that could adversely affect our operations and our profitability.

Beginning in 2022, record refining industry profits raised the concern of many public policy experts and federal and state policymakers, who have questioned whether these profits were justified, or whether they constituted a “windfall” to the industry and have proposed legislation that if enacted could adversely affect our profitability. In September 2022, California adopted Senate Bill No. 1322 (“SB 1322”), which requires refineries in California to report monthly on the volume and cost of the crude oil they buy, the quantity and price of the wholesale gasoline they sell, and the gross gasoline margin per barrel, among other information. The provisions of SB 1322 were effective January 2023. In March 2023, California adopted Senate Bill No. 2 (such statute, together with any regulations contemplated or issued thereunder, “SBx 1-2”), which, among other things, (i) authorized the establishment of a maximum gross gasoline refining margin (“GGRM”) and the imposition of a financial penalty for profits above a maximum GGRM, (ii) significantly expanded the reporting obligations under SB 1322 and the Petroleum Industry Information Reporting Act of 1980, which include reporting requirements to the California Energy Commission (“CEC”) for all participants in the petroleum industry supply chain in California (e.g., refiners, marketers, importers, transporters, terminals, producers, renewables producers, pipelines, and ports), (iii) created the Division of Petroleum Market Oversight within the CEC to analyze the data provided under SBx 1-2, and (iv) authorized the CEC to regulate the timing and other aspects of refinery turnaround and maintenance activities in certain instances. SBx 1-2 imposes increased and substantial reporting requirements, which include daily, weekly, monthly, and annual reporting of detailed operational and financial data on all aspects of our operations in California. The operational data includes any plans for turnaround and maintenance activities at our two California refineries and the way we expect to address the potential impacts on feedstock and product inventories in California as a result of such turnaround and maintenance activities. The provisions of SBx 1-2 became effective June 26, 2023.

In September 2023, the Governor of the State of California directed the CEC to begin the regulatory processes concerning (i) potential penalties for exceeding a maximum GGRM and (ii) the timing of refinery turnarounds and maintenance. Consequently, the CEC adopted an order requiring an informational proceeding on a maximum GGRM and penalty under SBx 1-2. It also adopted an order initiating rulemaking activity under SBx 1-2 that will be focused on refinery maintenance and turnarounds. However, in August 2025, CEC adopted a resolution to pause rulemaking on a maximum GGRM and penalty for five years, but will continue to collect and analyze information to assess a maximum GGRM and penalty during the five-year pause.

Following the adoption of SBx 1-2, in October 2024, California adopted Assembly Bill No. 1 (such statute, together with any regulations contemplated or issued thereunder, “ABx 2-1”) which authorizes the CEC to consider the effects of refiners’ inventories of fuel and feedstocks and blending components on the price of transportation fuels in California. The bill further authorizes the CEC, by regulation, to develop and impose requirements for refiners operating in the state to maintain minimum levels of inventories of refined transportation fuels meeting California specifications, including any feedstocks and blending components, as specified. Specifically, the bill provides that the CEC: (i) may establish criteria that refiners must meet before commencing a turnaround or maintenance event, including requiring California’s petroleum refiners to have resupply plans and arrangements to cover their loss in production, as specified; (ii) is authorized to develop and impose requirements on California refiners to maintain minimum levels of inventories of refined transportation fuels meeting California specifications; (iii) is prohibited from adopting minimum inventory regulations unless it finds that the benefits outweigh the potential costs to consumers; and (iv) is required to annually re-evaluate these factors and provide a report to the Legislature concluding whether the regulation meets the cost effectiveness test.

To the extent that the CEC in the future establishes a maximum GGRM and imposes a financial penalty for profits above such maximum GGRM, inventory requirements, or timing of turnaround schedules, our financial results and profitability could be adversely affected. Our results of operations and our financial performance could also be adversely impacted to the extent that restrictions on turnaround and maintenance activities are imposed by the CEC. We cannot reasonably predict the impact that the full implementation of SBx 1-2 or ABx 2-1 will have on our California operations or our Company nor can we predict the impact that similarly focused legislation or actions in other jurisdictions in which we operate our refineries may have. The legislation in California, and the future enactment of similar legislation in any of the other jurisdictions could adversely impact our business, results of operations, profitability and cash.

We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with health, safety, environmental and other laws and regulations.

Our operations require numerous permits and authorizations under various laws and regulations. These authorizations and permits are subject to revocation, renewal or modification and can require operational changes to limit impacts or potential impacts on the environment and/or health and safety. A violation of authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions, and/or facility shutdowns. In addition, major modifications of our operations could require modifications to our existing permits or upgrades to our existing pollution control equipment. Any or all of these matters could have a negative effect on our business, results of operations and cash flows.

We may incur significant liabilities under, or costs and capital expenditures to comply with, health, safety, environmental and other laws and regulations, which are complex and change frequently. Our operations are subject to federal, state and local laws regulating, among other things, the handling of petroleum and other regulated materials, the emission and discharge of materials into the environment, waste management, and remediation of discharges of petroleum and petroleum products, characteristics and composition of gasoline and distillates and other matters otherwise relating to the protection of the environment. Our operations are also subject to extensive laws and regulations relating to occupational health and safety, in addition to laws and regulations affecting the transportation of crude oil by rail in North America.

Certain environmental laws impose strict, and in certain circumstances joint and several liability for, costs of investigation and cleanup of such spills, discharges or releases on owners and operators of, as well as persons who arrange for treatment or disposal of regulated materials at contaminated sites. Under these laws, we may incur liability or be required to pay penalties for past contamination, and third parties may assert claims against us for damages allegedly arising out of any past or future contamination. The potential penalties and clean-up costs for past or future releases or spills, the failure of prior owners of our facilities to complete their clean-up obligations, the liability to third parties for damage to their property, or the need to address newly-discovered information or conditions that may require a response could be significant, and the payment of these amounts could have a material adverse effect on our business, financial condition and results of operations.

A cyber-attack on, or other failure of, our technology infrastructure could affect our business and assets, and have a material adverse effect on our financial condition, results of operations and cash flows.

We are becoming increasingly dependent on our technology infrastructure and certain critical information systems which process, transmit and store electronic information, including information we use to safely and effectively operate our respective assets and businesses. These information systems include data network and telecommunications, internet access, our websites, and various computer hardware equipment and software applications, including those that are critical to the safe operation of our refineries and logistics assets. We have invested, and expect to continue to invest, significant time, manpower and capital in our technology infrastructure and information systems. These information systems are subject to damage or interruption from a number of potential sources including natural disasters, software viruses or other malware, power failures, cybersecurity threats to gain unauthorized access to sensitive information, cyber-attacks, which may render data systems unusable, and physical threats to the security of our facilities and infrastructure. Additionally, our business is highly dependent on financial, accounting and other data processing systems and other communications and information systems, including our enterprise resource planning tools. We process a large number of transactions on a daily basis and rely upon the proper functioning of computer systems. Furthermore, we rely on information systems across our respective operations, including the management of supply chain and various other processes and transactions. As a result, a disruption on any information systems at our refineries or logistics assets, may cause disruptions to our collective operations.

The potential for such security threats or system failures has subjected our operations to increased risks that could have a material adverse effect on our business. To the extent that these information systems are under our control, we have implemented measures such as virus protection software, emergency recovery processes and a formal disaster recovery plan to address the outlined risks. However, security measures for information systems cannot be guaranteed to be failsafe, and our formal disaster recovery plan and other implemented measures may not prevent delays or other complications that could arise from an information systems failure. If a key system were hacked or otherwise interfered with by an unauthorized user, or were to fail or experience unscheduled downtime for any reason, even if only for a short period, or any compromise of our data security or our inability to use or access these information systems at critical points in time, it could unfavorably impact the timely and efficient operation of our business, damage our reputation and subject us to additional costs and liabilities. The increase in companies and individuals working remotely has increased the frequency and scope of cyber-attacks and the risk of potential cybersecurity incidents, both deliberate attacks and unintentional events. Emerging artificial intelligence technologies may also improve or expand the capabilities of malicious third parties in a way we cannot predict at this time, including being used to develop new hacking tools, exploit vulnerabilities, using phishing to trick employees into making payments or granting access to internal systems, obscure malicious activities, and increase the difficulty of detecting threats, which may result in new or expanded risks and liabilities. While, to date, we have not had a significant cybersecurity breach or attack that had a material impact on our business or results of operations, if we were to be subject to a material successful cyber intrusion, it could result in remediation or service restoration costs, increased cyber protection costs, lost revenues, litigation or regulatory actions by governmental authorities, increased insurance premiums, reputational damage and damage to our competitiveness, financial condition, results of operations and cash flows.

Cyber-attacks against us or others in our industry could result in additional regulations, and U.S. government warnings have indicated that infrastructure assets, including pipelines, may be specifically targeted by certain groups. These attacks include, without limitation, malicious software, ransomware, attempts to gain unauthorized access to data, and other electronic security breaches. These attacks may be perpetrated by state-sponsored groups, “hacktivists”, criminal organizations or private individuals (including employee malfeasance). Efforts by the federal government, including the Strengthening the Cybersecurity of Federal Networks and Critical Infrastructure executive order, the issuance of new cybersecurity requirements for critical pipeline owners and operators issued by the Department of Homeland Security’s Transportation Security Administration following a cyber-attack on a major petroleum pipeline in 2021, and other existing or future regulations could lead to increased regulatory compliance costs, insurance coverage cost or capital expenditures. We cannot predict the potential impact to our business or the energy industry resulting from additional regulations.

Further, our business interruption insurance may not compensate us adequately for losses that may occur. We carry cybersecurity insurance; with certain of our insurance policies allowing for potential coverage for insured property damage resulting from a cyber-security event subject to certain limitations and exclusions. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, results of operations and cash flows. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

We may not be able to successfully realize the anticipated benefits of our investment in SBR or meet our obligations to SBR.

On June 27, 2023, together with our partner, Eni, we closed on the jointly held investment in SBR, which owns the Renewable Diesel Facility. Following its completion, we have certain obligations and liabilities related to SBR as the construction manager, operator and provider of services. Further, SBR is operated as a separate entity and we do not fully control its operations. There can be no assurance that we will realize the anticipated benefits and operating synergies of the Renewable Diesel Facility or the equity method investment. Our estimates regarding the earnings, operating cash flow, capital expenditures and liabilities resulting from this investment may prove to be incorrect. This equity method investment involves risks, including:

•diversion of management time and attention from our existing business;

•reliance on Eni and their financial condition;

•risk that Eni does not always share our goals and objectives; and

•certain obligations that we have to fund capital expenditures relating to this investment.

Continued scrutiny on sustainability matters and developments related to climate change may negatively impact our business and our access to capital markets.

Continued scrutiny on sustainability matters may impact our business as it relates to the use of refined products, climate change, increasing public expectations on companies to address climate change, and potential use of substitutes or replacements to our products may result in increased costs, reduced demand for our products, reduced profits, increased regulations and litigation, and adverse impacts on our stock price and access to capital markets. In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings for evaluating companies on their approach to sustainability matters. Such ratings are used by some investors to inform and advise their investment and voting decisions. Also, some stakeholders may advocate for divestment of fossil fuel investments and encourage lenders to limit funding to companies engaged in the manufacturing of refined products. Unfavorable sustainability ratings and investment community divestment initiatives may lead to negative investor and public sentiment toward the Company and to the diversion of capital from our industry, which could have a negative impact on our stock price and our access to, and cost of, capital. This scrutiny, coupled with changes in consumer behavior, attitudes and preferences with respect to the generation and consumption of energy and the use of fossil fuels, may continue to result in (a) the enactment of climate change related regulations, policies and initiatives, including alternative energy requirements, (b) further technological advances related to the generation, storage and consumption of energy through alternative methods such as wind and solar and (c) increased demand for and/or availability of non-fossil fuel energy sources and related consumer products such as electric and hybrid vehicles and renewable power supplies. These developments may also lead to reduced demand for our products, a reduction in our revenue, higher costs and an overall decrease in our profitability.

Additionally, increased attention and scrutiny regarding climate change has resulted in increased investor attention and an increased risk of public and private litigation, which could increase our costs and/or otherwise negatively affect our operations and overall profitability, and cause the market price of our Class A common stock to decline.

Some of our competitors may have a competitive advantage by providing alternative energy sources or by owning their own retail sites.

We compete with other companies and industries that may provide alternative means to satisfy fuel and energy requirements to their customers or own their own retail network. The refining industry is highly competitive with respect to petroleum product capacity and feedstock supply. We compete with many companies for available supplies of crude oil and other feedstocks, and for third-party retail outlets for our refined petroleum products. Such companies that produce alternative energy sources or own their own retail sites may be better positioned to deal with changes in refining capacity, depressed refining margins or feedstock shortages.

We may be negatively affected by the rate of inflation and its impact on the global economy.

Inflationary pressures have contributed to increased interest rates and capital costs, supply chain disruptions, increased cost of living and labor, and other related items. Although inflation has fluctuated, inflationary pressures may persist or re-emerge, including due to tariffs and other trade measures that may be imposed or enacted, we expect to continue to experience increases in the cost of feedstocks, labor, materials, and other inputs necessary in the refining of crude oil and other feedstocks. Although we may take actions to counteract or mitigate the impacts of inflation, there can be no assurance that such actions will be effective, and sustained or renewed inflationary pressures could have a material adverse effect on our business, results of operations and financial condition. Additionally, higher inflation, elevated interest rates, or concerns of an economic slowdown or recession could impact the demand for our products and services.

We may not be able to obtain funding on acceptable terms or at all, including because of volatility and uncertainty in the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.

In the past, global financial markets and economic conditions have been, and may again be, subject to disruption and volatility due to a variety of factors, including uncertainty in the financial services sector, low consumer confidence, falling commodity prices, geopolitical issues and generally weak economic conditions. In addition, the fixed income and bank markets could experience periods of extreme volatility or stress that may negatively impact market liquidity conditions. As a result, the cost of raising money in the debt and equity capital markets could increase substantially at times while the availability of funds from those markets diminishes significantly. In particular, as a result of concerns about the stability of financial markets generally, which may be subject to unforeseen disruptions, the cost of obtaining money from the credit markets may increase as many lenders and institutional investors increase interest rates, enact tighter lending standards, refuse to refinance existing debt on similar terms or at all and reduce or, in some cases, cease to provide funding to borrowers. Due to these factors, we cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due. Moreover, without adequate funding, we may be unable to execute our business strategy, complete future acquisitions or growth projects, take advantage of other business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.

Any political instability, military strikes, sustained military campaigns, terrorist activity, changes in foreign policy, or other catastrophic events could have a material adverse effect on our business, results of operations and financial condition.

U.S. and global markets have experienced volatility and disruption following the escalation of geopolitical tensions and Russia’s military action in Ukraine since February 2022, armed hostilities and protests in the middle east and disruptions in international shipping resulting from attacks by armed groups on cargo ships. Although the length and impact of these ongoing military actions and social upheavals is highly unpredictable, these conflicts have led to market disruptions, including significant volatility in the financial markets and the global macroeconomic and geopolitical environment. Furthermore, a protracted conflict between Ukraine and Russia, or any escalation of this conflict, may result in additional financial and economic sanctions and import and/or export controls imposed on Russia by the United States, the United Kingdom, the European Union, Canada and others, such as the United States ban on import of Russian oil effective March 8, 2022 and the European Union ban on oil products from Russia effective February 5, 2023, which may have adverse impacts on the wider global economy and market conditions and could, in turn, have a material adverse impact on our business, financial condition, cash flows and results of operations and could cause the market value of PBF Energy’s Class A common stock to decline.

Any further political instability, military strikes, sustained military campaigns, terrorist activity, changes in foreign policy in areas or regions of the world where we acquire crude oil and other raw materials or sell our refined products may affect our business in unpredictable ways, including forcing us to increase security measures and causing disruptions of supplies and distribution markets. We may also be subject to United States trade and economic sanctions laws, which change frequently as a result of foreign policy developments, and which may necessitate changes to our crude oil acquisition activities. Further, like other industrial companies, our facilities may be the target of terrorist activities or subject to catastrophic events such as natural disasters and pandemic illness. Any act of war, terrorism, or other catastrophic events that resulted in damage to, or otherwise disrupts the operating activities of, any of our refineries or third-party facilities upon which we are dependent for our business operations could have a material adverse effect on our business, results of operations and financial condition.

Competition from companies that produce their own supply of feedstocks, have extensive retail outlets, make alternative fuels or have greater financial and other resources than we do, could materially and adversely affect our business and results of operations.

Our refining operations compete with domestic refiners and marketers in regions of the United States in which we operate, as well as with domestic refiners in other regions and foreign refiners that import products into the United States. In addition, we compete with other refiners, producers and marketers in other industries that provide means to satisfy the energy and fuel requirements of our industrial, commercial and individual consumers. Certain of our competitors have larger and more complex refineries, and may be able to realize lower per-barrel costs or higher margins per barrel of throughput. Several of our principal competitors are integrated national or international oil companies that are larger and have substantially greater resources than we do and access to proprietary sources of controlled crude oil production. Unlike these competitors, we obtain substantially all of our feedstocks from unaffiliated sources. We are not engaged in the petroleum exploration and production business and therefore do not produce any of our crude oil feedstocks. We do not have a retail business and therefore are dependent upon others for outlets for our refined products. Because of their integrated operations and larger capitalization, these companies may be more flexible in responding to volatile industry or market conditions, such as shortages of crude oil supply and other feedstocks or intense price fluctuations and they may also be able to obtain more favorable trade credit terms.

Newer or upgraded refineries will often be more efficient than our refineries, which may put us at a competitive disadvantage. We have taken significant measures to maintain our refineries including the installation of new equipment and redesigning older equipment to improve our operations. However, these actions involve significant uncertainties, since upgraded equipment may not perform at expected throughput levels, the yield and product quality of new equipment may differ from design specifications and modifications may be needed to correct equipment that does not perform as expected. Any of these risks associated with new equipment, redesigned older equipment or repaired equipment could lead to lower revenues or higher costs or otherwise have an adverse effect on future results of operations and financial condition. Over time, our refineries or certain refinery units may become obsolete, or be unable to compete, because of the construction of new, more efficient facilities by our competitors.

We must make substantial capital expenditures on our operating facilities to maintain their reliability and efficiency. If we are unable to complete capital projects at their expected costs and/or in a timely manner, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations or cash flows could be materially and adversely affected.

Delays or cost increases related to capital spending programs involving engineering, procurement and construction of new facilities (or improvements and repairs to our existing facilities and equipment, including turnarounds) could adversely affect our ability to achieve targeted internal rates of return and operating results. Such delays or cost increases may arise as a result of unpredictable factors in the marketplace, many of which are beyond our control, including:

•denial or delay in obtaining regulatory approvals and/or permits;

•unplanned increases in the cost of construction materials or labor;

•disruptions in transportation of modular components and/or construction materials;

•severe adverse weather conditions, natural disasters, wildfires or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors and suppliers;

•shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;

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

•non-performance or force majeure by, or disputes with, vendors, suppliers, contractors or sub-contractors involved with a project.

Our refineries contain many processing units, a number of which have been in operation for many years. Equipment, even if properly maintained, may require significant capital expenditures and expenses to keep it operating at optimum efficiency. One or more of the units may require unscheduled downtime for unanticipated maintenance or repairs that are more frequent than our scheduled turnarounds for such units. Scheduled and unscheduled maintenance could reduce our revenues during the period of time that the units are not operating.

Our forecasted internal rates of return are also based upon our projections of future market fundamentals, which are not within our control, including changes in general economic conditions, inflation, slow growth, recession, impact of new regulations, available alternative supply and customer demand. Any one or more of these factors could have a significant impact on our business. If we were unable to make up the delays associated with such factors or to recover the related costs, or if market conditions change, it could materially and adversely affect our financial position, results of operations or cash flows.

We are subject to strict laws and regulations regarding employee and process safety, and failure to comply with these laws and regulations could have a material adverse effect on our results of operations, financial condition and profitability.

We are subject to the requirements of OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, OSHA requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees, state and local governmental authorities, and local residents. Failure to comply with OSHA requirements, including general industry standards, process safety standards and control of occupational exposure to regulated substances, could result in claims against us that could have a material adverse effect on our results of operations, financial condition and the cash flows of the business if we are subjected to significant fines or compliance costs.

Product liability and operational liability claims and litigation could adversely affect our business and results of operations.

Product liability and liability arising from our operations are significant risks. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers of petroleum products based upon claims for injuries and property damage caused by the use of or exposure to various products. Failure of our products to meet required specifications or claims that a product is inherently defective could result in product liability claims from third parties, including our shippers and customers, and also arise from contaminated or off-specification product in commingled pipelines and storage tanks and/or defective fuels. We may also be subject to personal injury claims arising from incidents that occur in connection with or relating to our operations. Product liability and personal injury claims against us could have a material adverse effect on our business, financial condition or results of operations.

Compliance with and changes in tax laws could adversely affect our performance.

We are subject to extensive tax liabilities, including federal, state, local and foreign taxes such as income, excise, sales/use, payroll, franchise, property, gross receipts, withholding and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations, such as the IRA, are continuously being enacted or proposed and could result in increased expenditures for tax liabilities in the future. These liabilities are subject to periodic audits by the respective taxing authorities, which could increase our tax liabilities. Subsequent changes to our tax liabilities as a result of these audits may also subject us to interest and penalties. Also, uncertainties remain with respect to current or contemplated legal, political or regulatory developments that may impose taxes or penalties on profits, windfalls, or margins above certain levels. There can be no certainty that our federal, state, local or foreign taxes could be passed on to our customers.

Acquisitions or other investments that we may undertake in the future involve a number of risks, any of which could cause us not to realize the anticipated benefits.

We may not be successful in acquiring additional assets or making investments in new business, and any acquisitions or other investments that we do consummate may not produce the anticipated benefits or may have adverse effects on our business and operating results. We may selectively consider strategic acquisitions and other investments in the future within the refining, mid-stream and renewable diesel or alternative energy sectors based on performance through the cycle, advantageous access to crude oil supplies, attractive refined products market fundamentals and access to distribution and logistics infrastructure. For example, we are a key participant of the Mid-Atlantic Clean Hydrogen Hub (“MACH2”) initiative, a broad consortium exploring the development of a clean energy and logistics hub on 2,500 acres adjacent to our Delaware City refinery, that was selected by the Department of Energy to receive up to $750.0 million to advance the development of a clean hydrogen production and distribution hub. In connection with MACH2, we are exploring investments in renewable electricity, green hydrogen production, development of 10 million square feet of distribution warehouses and office space, and hydrogen fueling facilities for a large fleet of medium duty trucks. In addition, we own a significant portfolio and are actively pursuing real estate development opportunities, which may entail incremental investment. Our ability to acquire additional assets or invest in new businesses will be dependent upon a number of factors, including our ability to identify acceptable acquisition or investment opportunities, consummate acquisitions or other investments on acceptable terms, successfully integrate acquired assets and obtain financing to fund acquisitions and to support our growth and many other factors beyond our control. Risks associated with acquisitions and other investments include those relating to the diversion of management time and attention from our existing business, liability for known or unknown environmental conditions or other contingent liabilities and greater than anticipated expenditures required for compliance with environmental, safety or other regulatory standards or for investments to improve operating results, and the incurrence of additional indebtedness to finance acquisitions or capital expenditures relating to acquired assets. We may also enter into transition services agreements in the future with sellers of any additional refineries we acquire or otherwise invest in. Such services may not be performed timely and effectively, and any significant disruption in such transition services or unanticipated costs related to such services could adversely affect our business and results of operations. In addition, it is likely that, when we acquire or otherwise invest in refineries, we will not have access to the type of historical financial information that we will require regarding the prior operation of the refineries. As a result, it may be difficult for investors to evaluate the probable impact of significant acquisitions or other investments on our financial performance until we have operated the acquired refineries for a substantial period of time.

A portion of our workforce is unionized, and we may face labor disruptions that would interfere with our operations.

Most hourly employees at our refineries are covered by collective bargaining agreements through the USW, the IOW and the IBEW. These agreements are scheduled to expire on various dates in 2026 through 2028 (See “Item 1. Business” - Employees). Future negotiations prior to the expiration of our collective agreements may result in labor unrest for which a strike or work stoppage is possible. Strikes and/or work stoppages could negatively affect our operational and financial results and may increase operating expenses at the refineries.

Our business may suffer if any of our senior executives or other key employees discontinues employment with us. Furthermore, a shortage of skilled labor or disruptions in our labor force may make it difficult for us to maintain labor productivity.

Our future success depends to a large extent on the services of our senior executives and other key employees. Our business depends on our continuing ability to recruit, train and retain highly qualified employees in all areas of our operations, including engineering, accounting, business operations, finance and other key back-office and mid-office personnel. Furthermore, our operations require skilled and experienced employees with proficiency in multiple tasks. The competition for these employees is intense, and the loss of these executives or employees could harm our business. If any of these executives or other key personnel resigns or becomes unable to continue in his or her present role and is not adequately replaced, our business operations could be materially adversely affected.

If we fail to realize the expected benefits from our RBI initiative, our financial results may be negatively impacted.

During 2025, we launched our RBI initiative as part of our ongoing strategic efforts to extract incremental value across our business through improved reliability and efficiency. We are focused on several main areas, including projects and turnarounds, strategic procurement opportunities, our six-refinery system, and the corporate and refining organizational structures. We may experience delays or unanticipated costs in implementing our cost saving plans, and may not be able to timely or fully achieve and sustain the expected savings. Certain of these cost saving measures could also have a negative impact on our operations and our financial results.

Our hedging activities may limit our potential gains, exacerbate potential losses and involve other risks.

We may enter into commodity derivatives contracts to hedge our crude price risk or crack spread risk with respect to a portion of our expected gasoline and distillate production on a rolling basis or to hedge our exposure to the price of natural gas, which is a significant component of our refinery operating expenses. Consistent with that policy we may hedge some percentage of our future crude and natural gas supply. We may enter into hedging arrangements with the intent to secure a minimum fixed cash flow stream on the volume of products hedged during the hedge term and to protect against volatility in commodity prices. Our hedging arrangements may fail to fully achieve these objectives for a variety of reasons, including our failure to have adequate hedging arrangements, if any, in effect at any particular time and the failure of our hedging arrangements to produce the anticipated results. We may not be able to procure adequate hedging arrangements due to a variety of factors. Moreover, such transactions may limit our ability to benefit from favorable changes in crude oil, refined product and natural gas prices.

In addition, our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which:

•the volumes of our actual use of crude oil or natural gas or production of the applicable refined products is less than the volumes subject to the hedging arrangement;

•accidents, interruptions in feedstock transportation, inclement weather or other events cause unscheduled shutdowns or otherwise adversely affect our refineries, or those of our suppliers or customers;

•changes in commodity prices have a material impact on collateral and margin requirements under our hedging arrangements, resulting in us being subject to margin calls;

•the counterparties to our derivative contracts fail to perform under the contracts; or

•a sudden, unexpected event materially impacts the commodity or crack spread subject to the hedging arrangement.

As a result, the effectiveness of our hedging strategy could have a material impact on our financial results. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

In addition, these hedging activities involve basis risk. Basis risk in a hedging arrangement occurs when the price of the commodity we hedge is more or less variable than the index upon which the hedged commodity is based, thereby making the hedge less effective. For example, a New York Mercantile Exchange index used for hedging certain volumes of our crude oil or refined products may have more or less variability than the actual cost or price we realize for such crude oil or refined products. We may not hedge all the basis risk inherent in our hedging arrangements and derivative contracts.

Our commodity derivative activities could result in period-to-period earnings volatility.

We do not currently apply hedge accounting to any of our commodity derivative contracts and, as a result, unrealized gains and losses will be charged to our earnings based on the increase or decrease in the market value of such unsettled positions. These gains and losses may be reflected in our income statement in periods that differ from when the settlements of the underlying hedged items are reflected in our income statement. Such derivative gains or losses in earnings may produce significant period-to-period earnings volatility that is not necessarily reflective of our underlying operational performance and make meaningful period to period comparisons more difficult.

Risks Related to Our Indebtedness

Our indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under our indebtedness.

Our indebtedness may significantly affect our financial flexibility in the future. As of December 31, 2025, we have total debt of $2,189.3 million, excluding unamortized deferred debt issuance costs of $41.0 million, and we could incur additional borrowings under PBF Holding’s asset-based revolving credit facility (the “Revolving Credit Facility”). We may incur additional indebtedness in the future including additional secured indebtedness, subject to the satisfaction of any debt incurrence and, if applicable, lien incurrence limitation covenants in our existing financing agreements.

The level of our indebtedness has several important consequences for our future operations, including that:

•a portion of our cash flow from operations will be dedicated to the payment of principal of, and interest on, our indebtedness and will not be available for other purposes;

•under certain circumstances, covenants contained in our existing debt arrangements limit our ability to borrow additional funds, dispose of assets and make certain investments;

•in certain circumstances these covenants also require us to meet or maintain certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our industry, such as being able to take advantage of acquisition opportunities when they arise;

•our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited; and

•we may be at a competitive disadvantage to those of our competitors that are less leveraged; and we may be more vulnerable to adverse economic and industry conditions.

Our indebtedness increases the risk that we may default on our debt obligations, certain of which contain cross-default and/or cross-acceleration provisions. Our, and our subsidiaries’, ability to meet future principal obligations will be dependent upon our future performance, which in turn will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our business may not continue to generate sufficient cash flow from operations to repay our indebtedness. If we are unable to generate sufficient cash flow from operations, we may be required to sell assets, to refinance all or a portion of our indebtedness or to obtain additional financing. Refinancing may not be possible and additional financing may not be available on commercially acceptable terms, or at all.

We may not be able to secure necessary financing on acceptable terms, or at all.

We currently have notes outstanding with maturity dates in 2028 and 2030. Additionally, our Revolving Credit Facility matures in 2028. We can make no assurance that we will be able to refinance these agreements on acceptable terms prior to their maturity dates. Market disruptions or other credit factors, such as rising inflation and higher interest rates, may increase our cost of borrowing or adversely affect our ability to refinance our obligations as they become due. Further, sustainability concerns and other pressures on the oil and gas industry could lead to increased costs of financing or limit our access to the capital markets. If we are unable to refinance our indebtedness or access additional credit, or if short-term or long-term borrowing costs significantly increase, our ability to finance current operations and meet our short-term and long-term obligations could be adversely affected.

Despite our level of indebtedness, we and our subsidiaries may be able to incur substantially more debt, which could exacerbate the risks described above.

We and our subsidiaries are able to incur additional indebtedness in the future including additional secured or unsecured debt. Although our debt instruments contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions, and the indebtedness incurred in compliance with these restrictions could be substantial. To the extent new debt is added to our current debt levels, the leverage risks described above would increase. Also, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness.

Our future credit ratings could adversely affect our business, the cost of our borrowing, and our ability to obtain credit in the future.

Changes in our credit profile could affect the way crude oil and other suppliers view our ability to make payments and induce them to shorten the payment terms for our purchases or require us to post security or letters of credit prior to payment. Due to the large dollar amounts and volume of our crude oil and other feedstock purchases, any imposition by these suppliers of more burdensome payment terms on us may have a material adverse effect on our liquidity and our ability to make payments to our suppliers. This, in turn, could reduce our access to supply and cause us to be unable to operate one or more of our refineries at full capacity.

The 6.00% senior unsecured notes due 2028 (the “2028 6.00% Senior Notes”), the 7.875% senior unsecured notes due 2030 (the “2030 7.875% Senior Notes”) and the 9.875% senior unsecured notes due 2030 (the “2030 9.875% Senior Notes”) are rated B1 by Moody’s, BB by S&P, and BB by Fitch. Any adverse changes in our credit ratings may negatively impact the terms of credit we receive from our suppliers and our requirements to prepay or post collateral. Additionally, adverse actions taken by the rating agencies on our corporate credit rating or the rating of our notes may increase our cost of borrowings or hinder our ability to raise financing in the capital markets or have an unfavorable impact on the credit terms we have with our suppliers, which could impair our ability to grow our business, maintain adequate levels of liquidity and make cash distributions to our shareholders.

Restrictive covenants in our debt instruments, including the indentures governing our notes, may limit our ability to undertake certain types of transactions, which could adversely affect our business, financial condition, results of operations and our ability to service our indebtedness.

Various covenants in our current and future debt instruments and other financing arrangements, including the indentures governing our notes, may restrict our and our subsidiaries’ financial flexibility in a number of ways. Our current indebtedness and the indentures that govern our notes subject us to significant financial and other restrictive covenants, including restrictions on our ability to incur additional indebtedness, place liens upon assets, pay dividends or make certain other restricted payments and investments, consummate certain asset sales or asset swaps, conduct businesses other than our current businesses, or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of our assets. Some of our debt instruments also require our subsidiaries to satisfy or maintain certain financial condition tests in certain circumstances. Our ability to meet these financial condition tests can be affected by events beyond our control and we may not meet such tests in the future. In addition, a failure to comply with the provisions of our existing debt could result in an event of default that could enable our lenders, subject to the terms and conditions of such debt, to declare the outstanding principal, together with accrued interest, to be immediately due and payable. Events beyond our control may affect our ability to comply with our covenants. If we were unable to repay the accelerated amounts, our lenders could proceed against the collateral granted to them to secure such debt. If the payment of our debt is accelerated, defaults under our other debt instruments, if any, may be triggered, and our assets may be insufficient to repay such debt in full.

Provisions in our indentures and other agreements could discourage an acquisition of us by a third-party.

Certain provisions of our indentures could make it more difficult or more expensive for a third-party to acquire us. Upon the occurrence of certain transactions constituting a “change of control” as described in the indentures governing the 2028 6.00% Senior Notes, the 2030 7.875% Senior Notes, and the 2030 9.875% Senior Notes, holders of our notes could require us to repurchase all outstanding notes at 101% of the principal amount thereof, plus accrued and unpaid interest, if any, at the date of repurchase. Certain other significant agreements of ours such as the agreement governing the Revolving Credit Facility (the “Revolving Credit Agreement”) and the Tax Receivable Agreement (as defined below) also contain provisions related to a change in control that could make it more difficult or expensive for a third-party to acquire us.

Risks Related to Our Organizational Structure and PBF Energy Class A Common Stock

PBF Energy is the managing member of PBF LLC and its only material asset is its interest in PBF LLC. Accordingly, PBF Energy depends upon distributions from PBF LLC and its subsidiaries to pay its taxes, meet its other obligations and/or pay dividends in the future.

PBF Energy is a holding company, and all of its operations are conducted through subsidiaries of PBF LLC. PBF Energy has no independent means of generating revenue and no material assets other than its ownership interest in PBF LLC. We depend on the earnings and cash flow of our subsidiaries to meet our obligations, including our indebtedness, tax liabilities and obligations to make payments under a tax receivable agreement entered into with PBF LLC Series A and PBF LLC Series B unitholders (the “Tax Receivable Agreement”). If we do not receive such cash distributions, dividends or other payments from our subsidiaries, we may be unable to meet our obligations and/or pay dividends.

PBF Energy, as the sole managing partner of PBF LLC, may cause PBF LLC to make distributions to its members in an amount sufficient to enable PBF Energy to cover all applicable taxes at assumed tax rates, to make payments owed by PBF Energy under the Tax Receivable Agreement, and to pay other obligations and dividends, if any, declared by PBF Energy. To the extent we need funds and any of our subsidiaries is restricted from making such distributions under applicable law or regulation or under the terms of our financing or other contractual arrangements, or is otherwise unable to provide such funds, such restrictions could materially adversely affect our liquidity and financial condition.

The Revolving Credit Facility, the 2028 6.00% Senior Notes, the 2030 7.875% Senior Notes, the 2030 9.875% Senior Notes, and certain of our other outstanding debt arrangements include a restricted payment covenant, which restricts the ability of PBF Holding to make distributions to us, and we anticipate our future debt will contain a similar restriction. In addition, there may be restrictions on payments by our subsidiaries under applicable laws, including laws that require companies to maintain minimum amounts of capital and to make payments to stockholders only from profits. For example, PBF Holding is generally prohibited under Delaware law from making a distribution to a member to the extent that, at the time of the distribution, after giving effect to the distribution, liabilities of the limited liability company (with certain exceptions) exceed the fair value of its assets. As a result, we may be unable to obtain that cash to satisfy our obligations and make payments to PBF Energy stockholders, if any.

The rights of other members of PBF LLC may conflict with the interests of PBF Energy Class A common stockholders.

The interests of the other members of PBF LLC, which include current and former directors and officers, may not in all cases be aligned with PBF Energy Class A common stockholders’ interests. For example, these members may have different tax positions that could influence their positions, including regarding whether and when we dispose of assets and whether and when we incur new or refinance existing indebtedness, especially in light of the existence of the Tax Receivable Agreement. In addition, the structuring of future transactions may take into consideration these tax or other considerations even where no similar benefit would accrue to PBF Energy Class A common stockholders or us. See “Certain Relationships and Related Transactions—IPO Related Agreements” in our 2026 Proxy Statement incorporated herein by reference.

Under the Tax Receivable Agreement, PBF Energy is required to pay the former and current holders of PBF LLC Series A Units and PBF LLC Series B Units, or other permitted assignees, for certain realized or assumed tax benefits PBF Energy may claim arising in connection with prior offerings and future exchanges of PBF LLC Series A Units for shares of its Class A common stock and related transactions. The indentures governing the senior notes allow PBF LLC, under certain circumstances, to make distributions sufficient for PBF Energy to pay its obligation under the Tax Receivable Agreement.

PBF Energy is party to a Tax Receivable Agreement that provides for the payment from time to time by PBF Energy to the current and former holders of PBF LLC Series A Units and PBF LLC Series B Units, or other permitted assignees, of 85% of the benefits, if any, that PBF Energy is deemed to realize as a result of (i) the increases in tax basis resulting from its acquisitions of PBF LLC Series A Units, including such acquisitions in connection with its prior offerings or in the future and (ii) certain other tax benefits related to its entering into the Tax Receivable Agreement, including tax benefits attributable to payments under the Tax Receivable Agreement. See “Item 13. Certain Relationships and Related Transactions, and Director Independence.”

PBF Energy has recognized, as of December 31, 2025, a total liability for the Tax Receivable Agreement of $168.2 million. As future taxable income is recorded, increases in our Tax Receivable Agreement liability may be necessary in conjunction with the revaluation of deferred tax assets. If PBF Energy does not have taxable income, PBF Energy generally is not required (absent a change of control or circumstances requiring an early termination payment) to make payments under the Tax Receivable Agreement for that taxable year because no benefit will have been actually realized. However, any tax benefits that do not result in realized benefits in a given tax year will likely generate tax attributes that may be utilized to generate benefits in previous or future tax years. The utilization of such tax attributes will result in payments under the Tax Receivable Agreement. The foregoing are merely estimates based on assumptions that are subject to change due to various factors, including, among other factors, the timing of exchanges of PBF LLC Series A Units for shares of PBF Energy Class A common stock as contemplated by the Tax Receivable Agreement, the price of PBF Energy Class A common stock at the time of such exchanges, the extent to which such exchanges are taxable, and the amount and timing of PBF Energy’s income. The actual payments under the Tax Receivable Agreement could differ materially.

It is possible that future transactions or events could increase the actual tax benefits realized and the corresponding Tax Receivable Agreement payments. There may be a material negative effect on our liquidity if, as a result of timing discrepancies or otherwise, (i) the payments under the Tax Receivable Agreement exceed the actual benefits PBF Energy realizes in respect of the tax attributes subject to the Tax Receivable Agreement, and/or (ii) distributions to PBF Energy by PBF LLC are not sufficient to permit PBF Energy, after it has paid its taxes and other obligations, to make payments under the Tax Receivable Agreement. The payments under the Tax Receivable Agreement are not conditioned upon any recipient’s continued ownership of us.

In certain cases, payments by PBF Energy under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits it realizes in respect of the tax attributes subject to the Tax Receivable Agreement. These provisions may deter a change in control of the Company.

The Tax Receivable Agreement provides that upon certain changes of control, or if, at any time, PBF Energy elects an early termination of the Tax Receivable Agreement, PBF Energy’s (or its successor’s) obligations with respect to exchanged or acquired PBF LLC Series A Units (whether exchanged or acquired before or after such transaction) would be based on certain assumptions, including (i) that PBF Energy would have sufficient taxable income to fully utilize the deductions arising from the increased tax deductions and tax basis and other benefits related to entering into the Tax Receivable Agreement and (ii) that the subsidiaries of PBF LLC will sell certain nonamortizable assets (and realize certain related tax benefits) no later than a specified date. Moreover, in each of these instances, PBF Energy would be required to make an immediate payment equal to the present value (at a discount rate equal to LIBOR plus 100 basis points) of the anticipated future tax benefits (based on the foregoing assumptions).

Accordingly, payments under the Tax Receivable Agreement may be made years in advance of the actual realization, if any, of the anticipated future tax benefits and may be significantly greater than the actual benefits PBF Energy realizes in respect of the tax attributes subject to the Tax Receivable Agreement. In these situations, PBF Energy’s obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity. PBF Energy may not be able to finance its obligations under the Tax Receivable Agreement and its existing indebtedness may limit its subsidiaries’ ability to make distributions to PBF Energy to pay these obligations. In the case of certain changes of control, payments under the Tax Receivable Agreement will be accelerated and may significantly exceed the actual benefits we realize in respect of the tax attributes subject to the Tax Receivable Agreement. We expect that the payments that we may make under the Tax Receivable Agreement in the event of a change of control will be substantial. As a result, our accelerated payment obligations and/or the assumptions adopted under the Tax Receivable Agreement in the case of a change of control may deter a potential sale of our Company to a third-party and may otherwise make it less likely that a third-party would enter into a change of control transaction with us or negatively impact the value received by owners of our Class A common stock in a change of control transaction.

Moreover, payments under the Tax Receivable Agreement will be based on the tax reporting positions that PBF Energy determines in accordance with the Tax Receivable Agreement. PBF Energy will not be reimbursed for any payments previously made under the Tax Receivable Agreement if the IRS subsequently disallows part or all of the tax benefits that gave rise to such prior payments. As a result, in certain circumstances, payments could be made under the Tax Receivable Agreement that are significantly in excess of the benefits that PBF Energy actually realized in respect of (i) the increases in tax basis resulting from our purchases or exchanges of PBF LLC Series A Units and (ii) certain other tax benefits related to PBF Energy entering into the Tax Receivable Agreement, including tax benefits attributable to payments under the Tax Receivable Agreement.

PBF Energy cannot assure you that it will continue to declare dividends or have the available cash to make dividend payments.

Although PBF Energy currently intends to continue to pay quarterly cash dividends on its Class A common stock, the declaration, amount and payment of any dividends will be at the sole discretion of our Board of Directors. PBF Energy is not obligated under any applicable laws, its governing documents or any contractual agreements with its existing and prior owners or otherwise to declare or pay any dividends or other distributions (other than the obligations of PBF LLC to make tax distributions to its members). Our Board of Directors may take into account, among other things, general economic conditions, our financial condition and operating results, our available cash and current and anticipated cash needs, capital requirements, plans for expansion, including acquisitions, tax, legal, regulatory and contractual restrictions and implications, including under our subsidiaries’ outstanding debt documents, and such other factors as our Board of Directors may deem relevant in determining whether to declare or pay any dividend. Because PBF Energy is a holding company with no material assets (other than the equity interests of its direct subsidiary), its cash flow and ability to pay dividends is dependent upon the financial results and cash flows of its indirect subsidiaries PBF Holding and PBFX and their respective operating subsidiaries and the distribution or other payment of cash to it in the form of dividends or otherwise. The direct and indirect subsidiaries of PBF Energy are separate and distinct legal entities and have no obligation to make any funds available to it other than in the case of certain intercompany transactions. As a result, if PBF Energy does not declare or pay dividends you may not receive any return on an investment in PBF Energy Class A common stock unless you sell PBF Energy Class A common stock for a price greater than that which you paid for it.

Anti-takeover and certain other provisions in our certificate of incorporation and bylaws and Delaware law may discourage or delay a change in control.

Our certificate of incorporation and bylaws contain provisions that could make it more difficult for stockholders to effect certain corporate actions. Among other things, these provisions:

•authorize the issuance of undesignated preferred stock, the terms of which may be established and the shares of which may be issued without stockholder approval;

•prohibit stockholder action by written consent;

•restrict certain business combinations with stockholders who obtain beneficial ownership of a certain percentage of our outstanding common stock;

•provide that special meetings of stockholders may be called only by the chairman of the Board of Directors, the chief executive officer or the Board of Directors, and establish advance notice procedures for the nomination of candidates for election as directors or for proposing matters that can be acted upon at stockholder meetings; and

•provide that our stockholders may only amend our bylaws with the approval of 75% or more of all of the outstanding shares of our capital stock entitled to vote.

These anti-takeover provisions and other provisions of Delaware law may have the effect of delaying or deterring a change of control of our Company. Certain provisions could also discourage proxy contests and make it more difficult for you and other stockholders to elect directors of your choosing and to cause us to take other corporate actions you desire. These provisions could limit the price that certain investors might be willing to pay in the future for shares of PBF Energy Class A common stock.

The market price of PBF Energy Class A common stock may be volatile, and you could lose all or part of your investment.

The market price of PBF Energy Class A common stock has in the past been and may continue to be highly volatile and subject to wide fluctuations due to a number of factors including:

•market conditions in the oil refining industry and volatility in commodity prices;

•changes in, or failure to meet, earnings estimates of securities analysts;

•variations in actual or anticipated operating results or dividends, if any, to stockholders;

•the impact of disruptions to crude or feedstock supply to any of our refineries or our Renewable Diesel Facility, including disruptions due to problems with third-party logistics infrastructure;

•litigation and government investigations;

•the timing and announcement of any potential acquisitions or divestitures and subsequent impact of any future acquisitions or divestitures on our capital structure, financial condition or results of operations;

•changes or proposed changes in laws or regulations or differing interpretations or enforcement thereof;

•general economic and stock market conditions; and

•the availability for sale, or sales by PBF Energy or its senior management, of a significant number of shares of its Class A common stock in the public market.

In recent years, the stock market in general, and the market for energy companies in particular, has experienced significant price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of those companies. This volatility has had a significant impact on the market price of securities issued by many companies, including companies in our industry. In addition, the stock markets generally may experience significant volatility, often unrelated to the operating performance of the individual companies whose securities are publicly-traded. These and other factors may cause the market price of PBF Energy Class A common stock to decrease significantly, which in turn would adversely affect the value of your investment.

In the past, following periods of volatility in the market price of a company’s securities, stockholders have often instituted class action securities litigation against those companies. Such litigation, if instituted, could result in substantial costs and a diversion of management’s attention and resources, which could significantly harm our profitability and reputation.

Our current stockholders could experience dilution, which could further depress the price of our Class A common stock.

We continue to require substantial capital investment and working capital to fund our business. We may sell equity securities or convertible securities or other derivative securities in the public or private markets to assist in funding our capital needs even when conditions or terms are not otherwise favorable, including at prices at or below the then current market price of our shares of Class A common stock. As a result, stockholders may experience substantial dilution, and the market price of our Class A common stock could decline as a result of the introduction of a large number of shares of our Class A common stock, or securities convertible into or exchangeable or exercisable for our Class A common stock, into the market or the perception that these sales could occur. Sales of a large number of shares of our Class A common stock, or securities convertible into or exchangeable or exercisable for our Class A common stock, or the possibility that these sales may occur, also might make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. In addition, any equity securities we issue may have rights, preferences or privileges senior to those of our Class A common stock, and our current debt agreements contain, and any agreements for future debt or preferred equity financings, if available, are likely to contain, covenants limiting or restricting our ability to take specific actions, such as incurring additional debt. Holders of Class A common stock are not entitled to preemptive rights or other protections against dilution. Because our decision to issue securities in any future offering will depend on our capital needs as well as market conditions and other factors beyond our control, we cannot predict or estimate the amount, timing, nature or impact of future issuances, if any. Our Class A common stockholders bear the risk of our future offerings reducing the per share market price of our Class A common stock.

PBF Energy will be required to pay taxes on its share of taxable income from PBF LLC and its other subsidiary flow-through entities, regardless of the amount of cash distributions PBF Energy receives from PBF LLC.

The holders of limited liability company interests in PBF LLC, including PBF Energy, generally have to include for purposes of calculating their U.S. federal, state and local income taxes their share of any taxable income of PBF LLC, regardless of whether such holders receive cash distributions from PBF LLC. PBF Energy ultimately may not receive cash distributions from PBF LLC equal to its share of the taxable income of PBF LLC or even equal to the actual tax due with respect to that income.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 1C. CYBERSECURITY

Cybersecurity risk management and strategy

Our cybersecurity risk management program is managed by our current Chief Information Officer (“CIO”) who reports to our Chief Financial Officer and provides regular updates to the Board of Directors. Our CIO establishes our overall Information Technology (“IT”) security strategy, oversees our information, cyber, and technology security and manages our IT department, which includes our Cybersecurity team. His responsibilities include developing, implementing, and enforcing security policies to protect critical data. The head of our Cybersecurity team, our Director of Information Security, who reports to our CIO, runs the day-to-day management of our cybersecurity risks. Our IT department overall assists in implementing cybersecurity strategies and policies under the direction of the Cybersecurity team, as applicable.

Our cybersecurity risk management program aligns with the National Institute of Standards and Technology Cyber Security Framework, which establishes five areas of focus: identify, protect, detect, respond and recover. Our cybersecurity risk management program is designed to manage industry-specific threats, as well as threats arising from the overall evolving cybersecurity landscape and consists of two principal areas of focus: (i) enterprise systems, which consists of all business systems used in our daily operations and (ii) operational technology, which consists of all process control, supervisory control and data acquisition systems. Key elements of our cybersecurity management program include:

•identifying, monitoring and mitigating the cybersecurity risks to our systems, assets, data and capabilities;

•a critical response process for cybersecurity incidents, including the process for detection, investigation, containment and remediation of any such incidents;

•establishment of disaster recovery plans;

•testing, at least bi-annually, of select critical systems for disaster recovery and periodic walk-throughs of procedures for disaster recovery;

•identity access policies that aim to identify and monitor for potential cyber intrusions;

•periodic security tests, including monthly internal vulnerability scans, weekly external vulnerability scans, monthly phishing campaigns and recurring penetration testing by third-party cybersecurity firms;

•table-top exercises, at least quarterly, for incident response preparedness for the Cybersecurity team and Information Technology department; and

•annual drills for potential threats on various aspects of our technology assets based on the then-existing IT threat landscape for our industry.

Pursuant to our incident response plan, the Cybersecurity team has defined roles in responding to all cybersecurity incidents to provide an efficient and organized approach to handling cybersecurity threats, with the CIO receiving all reports and status updates regarding cybersecurity threats. The incident response plan provides a documented framework for when and how the CIO informs and updates our Board, the executive officers and other internal parties and when external parties are notified or consulted about a cybersecurity threat and the status thereof.

We also utilize third-party cybersecurity vendors to assist us with various aspects of our cybersecurity risk management program. For example, in order to support our cybersecurity incident response procedures, we have retained several third-party cybersecurity firms to monitor the IT threat landscape for our industry. As part of our efforts to manage the risk of cybersecurity threats associated with the use of third parties, we monitor and evaluate the cybersecurity risk profiles of third-party technology providers and consider such risk profiles when selecting third-party technology providers. Any third-party service provider that is granted access to our network is required to comply with our policies regarding information technology and cybersecurity. We also engage several third-party cybersecurity firms to perform independent assessments of the effectiveness of our cybersecurity risk management program and assist us in the continued review of our cybersecurity risk management program in order to reflect the evolving landscape of cybersecurity.

To date, there have been no significant threats, including as a result of any significant cybersecurity breaches or attacks, that have materially affected our business, results of operations or financial condition. However, if we were to be subject to a material successful cyber intrusion, it could result in remediation or service restoration costs, increased cybersecurity protection costs, lost revenues, litigation or regulatory actions by governmental authorities, increased insurance premiums, reputational damage and damage to our competitiveness, financial condition, results of operations and cash flows. See “Item 1A. Risk Factors−Risks Relating to Our Business and Industry−A cyber-attack on, or other failure of, our technology infrastructure could affect our business and assets, and have a material adverse effect on our financial condition, results of operations and cash flows.”

Cybersecurity governance

Our CIO assumed his position effective June 1, 2024, following the retirement of his predecessor. He previously served as the head of our Cybersecurity team. Our CIO has 30 years of experience in highly regulated industries managing information security in complex, matrixed environments. He has created and maintained enterprise-level information security programs for our Company and other US and international companies in the refining industry.

Our CIO, along with the head of our Cybersecurity team, periodically reports, no less than quarterly, to our Board and our executive officers regarding the state of our cybersecurity risk management program, including information on the status of ongoing efforts to manage and mitigate cybersecurity risks, as well as recent cybersecurity trends and events and any updates to cybersecurity matters.

The Audit Committee reviews our disclosures with respect to cybersecurity and information technology risks. The Audit Committee also reviews with management guidelines and policies to govern the process by which risk assessment and risk management is undertaken, including but not limited to cybersecurity and information technology risks. As part of the Company’s enterprise-wide risk management program, our Internal Audit team also reports to our Audit Committee regarding assessments of our cybersecurity and information technology risks, at least annually, based on regular updates by our CIO regarding such risks. Our Internal Audit team periodically reports to our executive officers and the Audit Committee regarding such risks.

ITEM 2. PROPERTIES

See “Item 1. Business”.

ITEM 3. LEGAL PROCEEDINGS

In connection with the acquisition of the Torrance refinery and related logistics assets, we assumed certain pre-existing environmental liabilities related to certain environmental remediation obligations to address existing soil and groundwater contamination and monitoring activities, which reflect the estimated cost of the remediation obligations. In addition, in connection with the acquisition of the Torrance refinery and related logistics assets, we purchased a ten-year, $100.0 million environmental insurance policy to insure against unknown environmental liabilities.

We currently have multiple outstanding notices of violation (“NOVs”) issued by regulatory authorities for various alleged regulation and permit violations at our refineries. It is not possible to predict the outcome of any of these NOVs or the amount of the penalties that will be assessed in connection with any NOV. If any one or more of them were decided against us, we believe that there would be no material effect on our financial position, results of operations, or liquidity. SEC regulations require us to disclose certain information about proceedings arising under federal, state, or local provisions regulating the discharge of materials into the environment or primarily for the purpose of protecting the environment, if a governmental authority is a party to such proceeding and such proceeding involves potential monetary sanctions, exclusive of interest and costs, that exceeds a specified threshold. We use a threshold of $1 million for such determination because we believe that such threshold is reasonably designed to result in disclosure of any such proceeding that is material to the business or financial condition.

On November 24, 2022, the Martinez refinery experienced a catalyst release that is currently being investigated by the BAAD, CCC, the DOJ, the USAO, the EPA, and the California Department of Fish and Wildlife (“CDFW”). To date, the BAAD has issued thirty-five (35) NOVs, CCC has issued two (2) NOVs, and the CDFW has made findings relating to the catalyst incident. On July 11, 2023 and October 6, 2023, the Martinez refinery experienced unintentional releases of petroleum coke dust and received inquiries or notices of investigation from the BAAD, the CalOSHA, CCC, and the EPA. The BAAD also issued NOVs relating to the July 11, 2023 coke dust incident and NOVs relating to the October 6, 2023 coke dust incident. On December 15, 2023, the Martinez refinery experienced an unexpected flaring incident, and subsequently on December 18, 2023 a brush fire incident, and has received inquiries or notices of investigation from the BAAD, the CalOSHA, and CCC. The BAAD additionally issued NOVs relating to the December 15, 2023 flaring incident and NOVs relating to the December 18, 2023 brush fire incident. The CDFW, CCC, and the BAAD have referred their findings and/or NOVs to the CCC District Attorney for the catalyst incident and various other incidents. On November 16, 2023, the CCC District Attorney and the BAAD announced a joint civil enforcement action against MRC that will include enforcement of the BAAD’s, CCC’s, and the CDFW’s claims from the catalyst incident, as well as additional enforcement claims from various incidents. For the catalyst, coke dust, flaring, brush fire, and other incidents, no definitive penalties have been assessed to date by the various agencies but there have been settlement communications with the CCC District Attorney and the BAAD. We presently believe the outcomes will not have a material impact on our financial position, results of operations, or cash flows.

In connection with the Martinez refinery fire, investigations are being conducted by various regulatory agencies, including the CalOSHA, the BAAD, CCC, the DOJ, the USAO, the EPA, and the CSB. There are uncertainties around these inquiries and investigations and potential results and consequences, including whether any financial penalties will be assessed or changes to the operations of the Martinez refinery will result therefrom. On May 1, 2025, following a review of the Martinez refinery’s causal report for flaring associated with the Martinez refinery fire as part of its ongoing investigation of the event, to date, the BAAD has issued a total of twenty-two (22) NOVs relating to the Martinez refinery fire. At this time, the potential liabilities, including regulatory penalties, arising from the incident are unknown, and the full financial impact of this incident cannot reasonably be estimated.

On February 17, 2017, in Arnold Goldstein, et al. v. Exxon Mobil Corporation, et al., we and PBF LLC, PBF Western Region, Torrance Refining and the manager of our Torrance refinery along with ExxonMobil were named as defendants in a putative class action filed in the Superior Court of California, County of Los Angeles, alleging negligence, nuisance, trespass, and strict liability claims arising from a February 18, 2015 electrostatic precipitator (“ESP”) explosion at the Torrance refinery, which at the time was owned and operated by ExxonMobil, and subsequent operations by Torrance Refining after the acquisition of the Torrance refinery in July 2016. To the extent the claims relate to the ESP explosion, ExxonMobil retained responsibility for any resulting liabilities pursuant to the agreement relating to the acquisition of the Torrance refinery. On July 2, 2018, the Court granted leave for plaintiffs to file a second amended complaint alleging groundwater contamination and added an additional plaintiff, Youssef. On October 15, 2019, the Court granted certification of two limited classes of with Youssef as the sole class representative and named plaintiff, related to trespass claims for ground contamination (“Ground Subclass”) and nuisance for air emissions (“Air Subclass”). On May 5, 2021, the Court granted leave for plaintiffs to a third amended complaint to substitute Navarro for Youssef. On July 5, 2022, the Court issued a final order ruling that plaintiffs’ motion to substitute Navarro as class Representative was denied and decertifying both of plaintiffs’ proposed Air and Ground Subclasses. The order provided that the case will proceed with Navarro as the sole plaintiff. On October 30, 2023, plaintiff appealed the Court’s ruling to the Ninth Circuit. On April 15, 2025, the Ninth Circuit issued a ruling that reversed the Court’s dismissal of the individual trespass claim and vacated the decertification of the Ground Subclass. The Ninth Circuit, however, affirmed the Court’s grant of summary judgment as to plaintiff’s individual nuisance claims and decertification of the Air Subclass. On August 12, 2025, the Ninth Circuit remanded the case back to the Court regarding the trespass claim and Ground Subclass decertification for reconsideration. On January 12, 2026, the Court directed the parties to file a joint status report by March 2, 2026, to propose a briefing schedule regarding class representative substitution, renewed class certification for the Ground Subclass, and a discovery schedule. We intend to continue to defend this matter vigorously. Based on information currently available, we do not believe that the ultimate resolution of this matter will have a material adverse effect on our financial position, results of operations, or cash flows.

Beginning in August 2023, MRC and, in certain cases, we and PBF Western Region, have been named as defendants in a series of related class and individual actions arising from MRC’s operations in Martinez, California (collectively, the “Martinez Actions”). The complaints generally allege claims including negligence, public and private nuisance, trespass, premises liability, strict liability for ultrahazardous activities, and, in one action, alleged CAA violations and claims for medical and environmental monitoring. The actions are pending in the U.S. District Court for the Northern District of California. The first-filed action, Piscitelli et al. v. Martinez Refining Company LLC, commenced on August 16, 2023, as a putative class action. On April 10, 2024, plaintiffs filed a first amended complaint to add plaintiff Malan and dismiss plaintiff Zanzucchi. On June 17, 2024, the Court granted plaintiffs’ motion to dismiss plaintiff Piscitelli. On September 30, 2025, the Court denied plaintiffs’ motion for class certification. Plaintiffs did not appeal that ruling. The other actions that have been filed include Alena Cruz and Shannon Payne vs. PBF Energy Inc., et. al, a putative class action; Jennifer Frye, et al. v. Martinez Refining Company LLC, filed by 18 individual plaintiffs; Alice Saliba, et al. v. Martinez Refining Company LLC, filed by 285 individual plaintiffs; Elizabeth Silvestri, et al. v. Martinez Refining Company LLC, filed by 195 individual plaintiffs; Robert Manning, et al. v. Martinez Refining Company LLC filed by 204 individual plaintiffs; and Canning v. Martinez Refining Company LLC, filed by two individual plaintiffs. In the Cruz case, on April 4, 2024, the Cruz Court dismissed all wrongly named PBF entities and plaintiffs’ CAA and medical monitoring claims. In the Frye case, on December 17, 2024, the Frye Court issued a ruling partially dismissing some of plaintiffs’ claims. In the Canning Case, the case was removed from state to federal court, and on November 14, 2025, plaintiffs filed a first amended complaint limiting their claims to only alleged property damages associated with the November 24, 2022 catalyst release. On April 15, 2025, the Piscitelli Court ordered the Piscitelli, Cruz, Frye, Saliba, Silvestri, and Manning cases related for coordination of common core issues. Subsequently, on July 16, 2025, the Piscitelli Court also related the Canning case for common core issues. On January 29, 2026, the Piscitelli Court issued a scheduling order for the Martinez Actions with discovery and certain motion practice continuing through first quarter 2028. Based on information

currently available, we do not believe that the ultimate resolution of the Martinez Actions will have a material adverse effect on our financial position, results of operations, or cash flows.

On December 21, 2023, the EPA Region 5 issued a Finding of Violation (“FOV”) alleging violations of the CAA, 42 U.S.C. §§ 7411, 7412, and regulations promulgated under those sections, of the National Emission Standard for Benzene Waste Operations at 40 C.F.R. Part 61, Subpart FF, of the New Source Performance Standards for Volatile Organic Compounds from Petroleum Wastewater Systems at 40 C.F.R. Part 60, Subpart QQQ, and of our CAA Title V operating permit for the Wastewater Treatment Unit at our Toledo refinery. This FOV followed an EPA compliance inspection at the Toledo refinery conducted in September 2023. We have recently been engaged in discussions with the EPA to resolve these matters, but we cannot currently estimate the timing of the resolution or the amount of any potential civil penalties. We presently believe the outcome will not have a material impact on our financial position, results of operations, or cash flows.

The federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances. Under CERCLA, such persons may be subject to joint and several liability for investigation and the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. As discussed more fully above, certain of our sites are subject to these laws and we may be held liable for investigation and remediation costs or claims for natural resource damages. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Analogous state laws impose similar responsibilities and liabilities on responsible parties. In our current normal operations, we have generated waste, some of which falls within the statutory definition of a “hazardous substance” and some of which may have been disposed of at sites that may require cleanup under Superfund.

As the ultimate outcomes of the pending matters discussed above are uncertain, we cannot currently estimate the final amount or timing of their resolution, but any such amount is not expected to have a material impact on our financial position, results of operations, or cash flows, individually or in the aggregate.

ITEM 4. MINE SAFETY DISCLOSURES

None.

PART II

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

Market Information

PBF Energy Class A common stock trades on the New York Stock Exchange under the symbol “PBF”. PBF Energy Class B common stock is not publicly-traded.

As of February 6, 2026, there were 281 holders of record of PBF Energy Class A common stock and 12 holders of record of PBF Energy Class B common stock.

Dividend and Distribution Policy

Subject to the following paragraphs, PBF Energy currently intends to continue to pay quarterly cash dividends of approximately $0.275 per share on its Class A common stock.

PBF Energy is a holding company and has no material assets other than its ownership interests of PBF LLC. In order for PBF Energy to pay any dividends, it needs to cause PBF LLC to make distributions to it and the holders of PBF LLC Series A Units, and PBF LLC needs to cause PBF Holding and/or PBFX to make distributions to it, in at least an amount sufficient to cover cash dividends, if any, declared by PBF Energy. Each of PBF Holding and PBFX is generally prohibited under Delaware law from making a distribution to a member to the extent that, at the time of the distribution, after giving effect to the distribution, liabilities of the limited liability company (with certain exceptions) exceed the fair value of its assets. As a result, PBF LLC may be unable to obtain cash from PBF Holding and/or PBFX to satisfy its obligations and make distributions to PBF Energy for dividends, if any, to PBF Energy’s stockholders. If PBF LLC makes such distributions to PBF Energy, the holders of PBF LLC Series A Units will also be entitled to receive pro rata distributions. The ability of PBF Holding to make distributions to PBF LLC is, and in the future may be, limited by covenants in its Revolving Credit Facility, the 2028 6.00% Senior Notes, the 2030 7.875% Senior Notes, the 2030 9.875% Senior Notes, and other debt instruments. Subject to certain exceptions, the Revolving Credit Facility and the indentures governing the senior notes prohibit PBF Holding from making distributions to PBF LLC if certain defaults exist. In addition, both the indentures and the Revolving Credit Facility contain additional restrictions limiting PBF Holding’s ability to make distributions to PBF LLC.

PBF Holding made $241.7 million in distributions to PBF LLC during the year ended December 31, 2025. In addition, during the year ended December 31, 2025 PBF LLC used $126.5 million to make non-tax distributions to its members, of which $125.6 million was distributed to PBF Energy and the balance was distributed to PBF LLC’s other members. PBF Energy used this $125.6 million to pay cash dividends of $0.275 per share of its Class A common stock on March 14, 2025, May 29, 2025, August 28, 2025, and November 26, 2025.

The declaration, amount and payment of any future dividends on shares of PBF Energy Class A common stock will be at the sole discretion of PBF Energy’s Board of Directors, and we are not obligated under any applicable laws, our governing documents or any contractual agreements with our existing owners or otherwise to declare or pay any dividends or other distributions (other than the obligations of PBF LLC to make tax distributions to its members).

Stock Performance Graph

In accordance with SEC rules, the information contained in the Stock Performance Graph below shall not be deemed to be “soliciting material,” or to be “filed” with the SEC, or subject to the SEC’s Regulation 14A or 14C, other than as provided under Item 201(e) of Regulation S-K, or to the liabilities of Section 18 of the Securities Exchange Act of 1934, as amended, except to the extent that we specifically request that the information be treated as soliciting material or specifically incorporate it by reference into a document filed under the Securities Act of 1933, as amended.

The graph below matches the cumulative 5-year total return of holders of PBF Energy Inc.'s common stock with the cumulative total returns of the S&P 500 index and a customized peer group of six companies that includes: Delek US Holdings Inc, HF Sinclair Corporation, Marathon Petroleum Corporation, Phillips 66, CVR Energy, Inc. and Valero Energy Corporation. The graph assumes that the value of the investment in our common stock, in each index, and in the peer group (including reinvestment of dividends) was $100 on 12/31/2020 and tracks it through 12/31/2025.


	12/31/2020		12/31/2021		12/31/2022		12/31/2023		12/31/2024		12/31/2025
PBF Energy Class A common stock	$	100.00	$	182.68	$	576.83	$	634.34	$	393.36	$	419.88
S&P 500	100.00		128.71		105.40		133.10		166.40		196.16
Peer Group	100.00		134.11		230.55		281.70		256.95		321.54

Recent Sales of Unregistered Securities—Exchange of PBF LLC Series A Units for PBF Energy Class A Common Stock

In the fourth quarter of 2025, there were no exchanges of PBF LLC Series A Units for shares of PBF Energy Class A common stock in transactions exempt from registration under Section 4(a)(2) of the Securities Act. No exchanges were made by any of our directors or current executive officers.

Share Repurchase Program

Our Board of Directors has authorized the repurchase of PBF Energy's Class A common stock (as amended from time to time, the “Repurchase Program”). The Repurchase Program currently allows for share repurchases of up to $1.75 billion and has no expiration date. These repurchases can be made from time to time through various methods, including open market transactions, block trades, accelerated share repurchases, privately negotiated transactions or otherwise, certain of which could be effected through Rule 10b5-1 plans. The timing and number of shares repurchased depends on a variety of factors, including price, capital availability, legal requirements, and economic and market conditions. We are not obligated to purchase any shares under the Repurchase Program, and repurchases could be suspended or discontinued at any time without prior notice.

During the year ended December 31, 2025, we did not purchase any shares of PBF Energy’s Class A common stock under the Repurchase Program. Approximately $732.0 million of shares remain available for purchase under the plan.

ITEM 6. [RESERVED]

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following review of our results of operations and financial condition should be read in conjunction with “Item 1. Business”, “Item 1A. Risk Factors”, “Item 2. Properties”, and “Item 8. Financial Statements and Supplementary Data,” respectively, included in this Annual Report on Form 10-K.

In this Item 7, we discuss results for the years ended December 31, 2025 and 2024 and comparisons of the results for the years ended December 31, 2025 and 2024. Discussions of results for the year ended December 31, 2023 and comparisons of the results for the years ended December 31, 2024 and 2023 can be found in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of the Company's annual report on Form 10-K for the year ended December 31, 2024.

CAUTIONARY STATEMENT FOR THE PURPOSE OF SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This Annual Report on Form 10-K contains certain “forward-looking statements,” as defined in the Private Securities Litigation Reform Act of 1995 (“PSLRA”), of expected future developments that involve risks and uncertainties. You can identify forward-looking statements because they contain words such as “believes,” “expects,” “may,” “should,” “seeks,” “approximately,” “intends,” “plans,” “estimates,” “anticipates” or similar expressions that relate to our strategy, plans or intentions. All statements we make relating to our estimated and projected earnings, margins, costs, expenditures, cash flows, growth rates and financial results or to our strategies, objectives, intentions, resources and expectations regarding future industry trends are forward-looking statements made under the safe harbor provisions of the PSLRA except to the extent such statements relate to the operations of a partnership or limited liability company. In addition, we, through our senior management, from time to time make forward-looking public statements concerning our expected future operations and performance and other developments. These forward-looking statements are subject to risks and uncertainties that may change at any time, and, therefore, our actual results may differ materially from those that we expected. We derive many of our forward-looking statements from our operating budgets and forecasts, which are based on many detailed assumptions. While we believe that our assumptions are reasonable, we caution that it is very difficult to predict the impact of known factors, and, of course, it is impossible for us to anticipate all factors that could affect our actual results.

Important factors that could cause actual results to differ materially from our expectations, which we refer to as “cautionary statements,” are disclosed under “Item 1A. Risk Factors,” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Annual Report on Form 10-K. All forward-looking information in this Annual Report on Form 10-K and subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements. Some of the factors that we believe could affect our results include:

•supply, demand, prices, and other market conditions for our products or crude oil, including volatility in commodity prices or constraints arising from federal, state or local governmental actions or environmental and/or social activists that reduce crude oil production or availability in the regions in which we operate our pipelines and facilities;

•rate of inflation, including increases due to tariffs and other trade measures that may be proposed or enacted, and its impact on supply and demand, pricing, and supply chain disruption;

•the effects related to, or resulting from, geopolitical conflict around the world, including Russia's military action in Ukraine, armed hostilities in the middle east and disruptions in international shipping, resulting from attacks by armed groups on cargo ships, including the imposition of additional sanctions and export controls, the potential expansion of such conflicts to other nations or regions, as well as the broader impacts to financial markets and the global macroeconomic and geopolitical environment;

•the risk and uncertainties associated with the Martinez refinery fire, including our expectations with respect to the full restart of the Martinez refinery, our ability to procure necessary permits and equipment and materials required to rebuild the Martinez refinery, the timing of the restart of certain units damaged by the Martinez refinery fire, the throughput of the Martinez refinery during this period, estimated costs, the anticipated amount and timing of the remaining insurance recoveries related to the Martinez refinery fire, and the results and consequences of any governmental and regulatory investigations related to the Martinez refinery fire;

•the amount and the timing of cost savings and operational efficiencies to be achieved through our RBI initiative;

•the effectiveness of our crude oil sourcing strategies, including our crude by rail strategy and related commitments;

•our obligation to buy RINs and market risks related to the volatility in the price of RINs required to comply with the RFS and GHG emission credits required to comply with various GHG emission programs, such as AB 32;

•our ability to operate our businesses efficiently, manage capital expenditures and costs (including general and administrative expenses) and generate earnings and cash flow;

•our expectations with respect to our capital spending and turnaround projects;

•the impact of current and future laws, rulings, and governmental regulations, including restrictions on the exploration and/or production of crude oil in the state of California, the implementation of rules and regulations regarding transportation of crude oil by rail or in response to the potential impacts of climate change, decarbonization and future energy transition and public policy in opposition to recent refining industry profits;

•adverse impacts related to legislation by the federal government lifting the restrictions on exporting U.S. crude oil or subjecting us to trade and sanctions laws, which change frequently as a result of foreign policy developments, and which may necessitate changes to our crude oil acquisition activities;

•political pressure and influence of environmental groups and other stakeholders on decisions and policies related to the refining, processing and storage of crude oil and refined products, and the related adverse impacts from changes in our regulatory environment, such as the effects of compliance with AB 32 and/or AB X2-1 and Senate Bill X1-2, or from actions taken by environmental interest groups;

•the risk of cyber-attacks;

•our increased dependence on technology;

• the effects of competition in our markets;

•the possibility that we might reduce or not pay dividends in the future;

•the inability of our subsidiaries to freely make distributions to us;

•our ability to make acquisitions or investments, including in renewable diesel production, and to realize the benefits from such acquisitions or investments;

•our ability to successfully manage the operations of SBR, which owns the Renewable Diesel Facility, together with our partner, Eni;

•liabilities arising from recent acquisitions or investments, that are unforeseen or exceed our expectations;

•our expectations and timing with respect to any acquisitions and investment activities and whether such acquisitions and investments are accretive or dilutive to shareholders;

•adverse developments in our relationship with both our key employees and unionized employees;

•our indebtedness, including the impact of potential downgrades to our corporate credit rating and/or unsecured notes;

•changes in currency exchange rates, interest rates, and capital costs;

•restrictive covenants in our indebtedness that may adversely affect our operational flexibility or ability to make distributions;

•counterparty credit and performance risk exposure related to our supply and inventory intermediation arrangements, if any;

•payments by PBF Energy to the current and former holders of PBF LLC Series A Units and PBF LLC Series B Units, or their permitted assignees, under PBF Energy’s Tax Receivable Agreement for certain tax benefits we may claim;

•our assumptions regarding payments arising under PBF Energy’s Tax Receivable Agreement and other arrangements relating to our organizational structure are subject to change due to various factors, including, among other factors, the timing of exchanges of PBF LLC Series A Units for shares of PBF Energy Class A common stock as contemplated by the Tax Receivable Agreement, the price of PBF Energy Class A common stock at the time of such exchanges, the extent to which such exchanges are taxable, and the amount and timing of our income; and

•the impact of disruptions to crude or feedstock supply to any of our refineries or our Renewable Diesel Facility, or with third-party logistics infrastructure or operations, including pipeline, marine and rail transportation.

We caution you that the foregoing list of important factors may not contain all of the material factors that are important to you. In addition, in light of these risks and uncertainties, the matters referred to in the forward-looking statements contained in this Annual Report on Form 10-K may not in fact occur. Accordingly, investors should not place undue reliance on those statements.

Our forward-looking statements speak only as of the date of this Annual Report on Form 10-K. Except as required by applicable law, including the securities laws of the United States, we do not intend to update or revise any forward-looking statements. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the foregoing.

Executive Summary

Our business operations are conducted by our subsidiaries. We own and operate six domestic oil refineries and related assets located in Delaware City, Delaware, Paulsboro, New Jersey, Toledo, Ohio, Chalmette, Louisiana, Torrance, California, and Martinez, California, and own a 50% interest in the Renewable Diesel Facility through our SBR equity method investment. Our refineries have a combined processing capacity, known as throughput, of approximately 1,000,000 bpd, and a weighted-average Nelson Complexity Index of 12.8 based on current operating conditions. The complexity and throughput capacity of our refineries are subject to change dependent upon configuration changes we make to respond to market conditions, as well as a result of investments made to improve our facilities and maintain compliance with environmental and governmental regulations. We operate in two reportable business segments: Refining and Logistics. Our six refineries are all engaged in the refining of crude oil and other feedstocks into petroleum products, and represent the Refining segment. PBFX operates certain logistical assets such as crude oil and refined products terminals, pipelines, and storage facilities, which represent the Logistics segment.

Factors Affecting Comparability

Our results over the past three years have been affected by the following events, the understanding of which will aid in assessing the comparability of our period to period financial performance and financial condition.

Martinez Refinery Fire

On February 1, 2025, the Martinez refinery fire occurred. As a result, the refinery was fully shut down until April 2025, when certain unaffected units, including the crude unit, were restarted and the refinery began producing limited quantities of gasoline, jet fuel, and intermediates. Investigations by various regulatory agencies are ongoing. Consequently, throughput volumes at the Martinez refinery in 2025 were significantly below 2024 levels.

During the year ended December 31, 2025, we received unallocated insurance proceeds totaling $893.5 million, net of deductibles and retentions. As a result, we recognized $832.5 million as Gain on insurance recoveries in the Consolidated Statements of Operations for the year ended December 31, 2025. This amount is net of the $61.0 million receivable previously recorded at March 31, 2025, related to the recovery of the write-down of the net book value of the damaged refinery units and certain fire response costs.

In addition, during the year ended December 31, 2025, we recorded operating expenses associated with the Martinez refinery fire of approximately $163.7 million.

Sale of Terminal Assets

On September 30, 2025, through a subsidiary of PBFX, we closed on the sale of two non-core refined product terminal facilities located in Philadelphia, PA and Knoxville, TN, for $175.4 million, excluding commissions and customary closing costs. The sale resulted in a gain of approximately $94.0 million for the year ended December 31, 2025, which is included within Gain on sale of assets in the Consolidated Statements of Operations.

Costs Related to RBI Initiative

During 2025, we launched our RBI initiative as part of our ongoing strategic efforts to extract incremental value across our business. For the year ended December 31, 2025, we recorded $29.6 million in expenses related to this initiative, which includes $4.7 million in severance charges recognized during the second quarter of 2025. These charges are reflected in General and administrative expenses in the Consolidated Statements of Operations.

Debt and Credit Facilities

Senior Notes

On March 17, 2025, we issued $800.0 million in aggregate principal amount of the 2030 9.875% Senior Notes. The net proceeds from the offering were approximately $776.0 million after deducting the initial purchasers’ discount and offering expenses. We used the net proceeds, to repay outstanding borrowings under the Revolving Credit Facility and for general corporate purposes.

On August 21, 2023, we issued $500.0 million in aggregate principal amount of the 2030 7.875% Senior Notes. The net proceeds from the offering were approximately $488.8 million after deducting the initial purchasers’ discount and offering expenses. We used the net proceeds, together with cash on hand, to fully redeem the outstanding 7.25% senior unsecured notes due 2025 (the “2025 Senior Notes”), including accrued and unpaid interest, on September 13, 2023 for approximately $664.5 million.

On February 2, 2023, we exercised our rights under the indenture governing PBFX’s 6.875% senior notes (the “PBFX 2023 Senior Notes”) to redeem all of the outstanding PBFX 2023 Senior Notes at a price of 100% of the aggregate principal amount thereof, plus accrued and unpaid interest through the date of redemption. The aggregate redemption price for the PBFX 2023 Senior Notes approximated $525.0 million, inclusive of unamortized premium and deferred financing costs. The redemption was funded using cash on hand.

PBF Holding Revolving Credit Facility

On August 23, 2023, we entered into the Revolving Credit Agreement. The Revolving Credit Agreement amended and restated the previously existing revolving credit agreement dated as of May 2, 2018 (as amended from time to time, the “Prior Credit Agreement”). Among other things, the Revolving Credit Agreement extended the Revolving Credit Facility through August 2028 and increased the maximum commitment amount under the facility to $3.5 billion from $2.85 billion. The commitment fees on the unused portion, the interest rate on advances and the fees for letters of credit are generally consistent with the Prior Credit Agreement.

There were $100.0 million and $200.0 million outstanding borrowings under the Revolving Credit Facility as of December 31, 2025 and December 31, 2024, respectively.

PBFX Revolving Credit Facility

On June 20, 2023, we terminated the $500.0 million PBFX senior secured revolving credit facility (the “PBFX Revolving Credit Facility”), which was originally set to mature on July 30, 2023. There were no outstanding borrowings under the PBFX Revolving Credit Facility as of the termination date.

Catalyst Financing Obligations

During the year ended December 31, 2023, we settled our last remaining outstanding precious metal financing arrangement, which represented a reduction of debt of approximately $3.1 million.

Refer to “Note 9 - Credit Facilities and Debt” of our Notes to Consolidated Financial Statements, for further information.

Inventory Intermediation Agreement

Prior to 2023, PBF Holding and its subsidiaries, DCR, PRC, and Chalmette Refining (collectively, the “PBF Entities”), entered into the third amended and restated inventory intermediation agreement (the “Inventory Intermediation Agreement”) with J. Aron & Company, a subsidiary of The Goldman Sachs Group, Inc. (“J. Aron”). Pursuant to the Inventory Intermediation Agreement, J. Aron purchased and held title to certain crude oil, intermediates, and finished products (the “J. Aron Products”) purchased or produced by the Paulsboro and Delaware City refineries (and at the election of the PBF Entities, the Chalmette refinery) (collectively, the “Refineries”) and delivered into the storage tanks at the Refineries (the “Storage Tanks”). The J. Aron Products were sold back to us as the J. Aron Products were discharged out of the Storage Tanks.

On June 28, 2023, the PBF Entities entered into an amendment to the Inventory Intermediation Agreement to amend certain provisions in order to allow for the early termination of the Inventory Intermediation Agreement effective as of July 31, 2023. In conjunction with this early termination, we made a payment of $268.0 million for the inventory previously held by J. Aron, inclusive of $13.5 million of related costs associated with exiting the agreement.

Equity Method Investment in SBR

On June 27, 2023, we and our partner, Eni, completed the closing of the equity method investment transaction and the capitalization of SBR, a jointly held investee designed to own, develop, and operate the Renewable Diesel Facility. We contributed the SBR business, which had a total estimated fair value of $1.69 billion, excluding working capital. Eni contributed $845.6 million of total consideration, which consisted of $431.0 million of cash distributed to us at close and an additional $414.6 million of cash contributed after the commercial start-up of the pre-treatment unit in July 2023. SBR now owns the Renewable Diesel Facility. As stipulated in the agreements with Eni, we managed project execution and continue to serve as the operator of the facility. During the year ended December 31, 2023, we recorded a gain of $925.1 million resulting from the difference between the fair value of the consideration received, including our 50% noncontrolling interest, and the carrying value of the related assets contributed. During the year ended December 31, 2024, we recorded an $8.7 million reduction to the gain.

Transactions with SBR

We and our subsidiaries have entered into various agreements with SBR, primarily related to the sale and purchase of environmental credits and hydrocarbon products. Refer to “Note 10 - Related Party Transactions” of our Notes to Consolidated Financial Statements for transactions with SBR.

Share Repurchase Program

Our Board of Directors has authorized the Repurchase Program. The Repurchase Program currently allows for share repurchases of up to $1.75 billion and does not have an expiration date. During the year ended December 31, 2025, we did not purchase any shares of PBF Energy's Class A common stock under the Repurchase Program. During the year ended December 31, 2024, we purchased 7,554,269 shares of PBF Energy's Class A common stock for $329.1 million, inclusive of commissions paid, through open market transactions. During the year ended December 31, 2023, we purchased 12,367,073 shares of PBF Energy's Class A common stock for $532.5 million, inclusive of commissions paid, through open market transactions.

Land Sales

During the year ended December 31, 2023, we closed on a third-party sale of a parcel of real property acquired as part of the Torrance refinery, but not part of the refinery itself. The sale resulted in a gain of approximately $1.7 million, included within Gain on sale of assets in the Consolidated Statements of Operations.

Tax Receivable Agreement

In connection with our IPO, we entered into a Tax Receivable Agreement pursuant to which we are required to pay the members of PBF LLC or their permitted assignees, who exchange their units for PBF Energy Class A common stock or whose units PBF Energy purchases, approximately 85% of the cash savings in income taxes that we realize as a result of the increase in the tax basis of our interest in PBF LLC, including tax benefits attributable to payments made under the Tax Receivable Agreement. As of December 31, 2025, a liability for the Tax Receivable Agreement of $168.2 million was recorded ($293.6 million and $336.6 million as of December 31, 2024 and December 31, 2023, respectively) reflecting our estimate of the undiscounted amounts that we expect to pay under the agreement. As future taxable income is recognized, increases in our Tax Receivable Agreement liability may be necessary in conjunction with the revaluation of deferred tax assets. Refer to “Note 11 - Commitments and Contingencies” and “Note 18 - Income Taxes” of our Notes to Consolidated Financial Statements for more details.

Renewable Fuel Standard

We are subject to obligations to purchase RINs required to comply with RFS. Our overall RINs obligation is based on a percentage of domestic shipments of on-road fuels as established by EPA. To the degree we are unable to blend the required amount of biofuels to satisfy our RINs obligation, RINs must be purchased on the open market to avoid penalties and fines. We record our RINs obligation on a net basis in Accrued expenses when our RINs liability is greater than the amount of RINs earned and purchased in a given period and in Prepaid and other current assets when the amount of RINs earned and purchased is greater than the RINs liability. We incurred approximately $680.1 million in RINs costs during the year ended December 31, 2025 as compared to $515.3 million and $762.3 million during the years ended December 31, 2024 and 2023, respectively. The fluctuations in RINs costs are due primarily to volatility in prices for ethanol-linked RINs and changes in our production of on-road transportation fuels. Our RINs purchase obligation is dependent on our actual shipment of on-road transportation fuels domestically and the amount of blending achieved.

Factors Affecting Operating Results

Overview

Our earnings and cash flows from operations are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks. The cost to acquire crude oil and other feedstocks and the price of refined products ultimately sold depends on numerous factors beyond our control, including the supply of, and demand for, crude oil, gasoline, diesel and other refined products, which, in turn, depend on, among other factors, changes in global and regional economies, weather conditions, global and regional political affairs, production levels, the availability of imports, the marketing of competitive fuels, pipeline capacity, prevailing exchange rates and the extent of government regulation. Our revenue and income from operations fluctuate significantly with movements in industry refined product prices, our materials cost fluctuate significantly with movements in crude oil prices and our other operating expenses fluctuate with movements in the price of energy to meet the power needs of our refineries. In addition, the effect of changes in crude oil prices on our operating results is influenced by how the prices of refined products adjust to reflect such changes.

Crude oil and other feedstock costs and the prices of refined products have historically been subject to wide fluctuation. Expansion and upgrading of existing facilities and installation of additional refinery distillation or conversion capacity, price volatility, governmental regulations, international political and economic developments and other factors beyond our control are likely to continue to play an important role in refining industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction or increase in product margins. Moreover, the industry typically experiences seasonal fluctuations in demand for refined products, such as for gasoline and diesel, during the summer driving season and for home heating oil during the winter.

Benchmark Refining Margins

In assessing our operating performance, we compare the refining margins (revenue less materials cost) of each of our refineries against a specific benchmark industry refining margin based on crack spreads. Benchmark refining margins take into account both crude and refined product prices. When these prices are combined in a formula they provide a single value—a gross margin per barrel—that, when multiplied by throughput, provides an approximation of the gross margin generated by refining activities.

The performance of our East Coast refineries generally follows the Dated Brent (NYH) 2-1-1 benchmark refining margin. Our Toledo refinery generally follows the WTI (Chicago) 4-3-1 benchmark refining margin. Our Chalmette refinery generally follows the LLS (Gulf Coast) 2-1-1 benchmark refining margin. Our Torrance refinery generally follows the ANS (West Coast) 4-3-1 benchmark refining margin. Our Martinez refinery generally follows the ANS (West Coast) 3-2-1 benchmark refining margin.

While the benchmark refinery margins presented below under “Results of Operations—Market Indicators” are representative of the results of our refineries, each refinery’s realized gross margin on a per barrel basis will differ from the benchmark due to a variety of factors affecting the performance of the relevant refinery to its corresponding benchmark. These factors include the refinery’s actual type of crude oil throughput, product yield differentials and any other factors not reflected in the benchmark refining margins, such as transportation costs, storage costs, credit fees, fuel consumed during production and any product premiums or discounts, as well as inventory fluctuations, timing of crude oil and other feedstock purchases, a rising or declining crude and product pricing environment and commodity price management activities. As discussed in more detail below, each of our refineries, depending on market conditions, has certain feedstock-cost and product-value advantages and disadvantages as compared to the refinery’s relevant benchmark.

Credit Risk Management

Credit risk refers to the risk that a counterparty will default on its contractual obligations resulting in financial loss to us. Our exposure to credit risk is reflected in the carrying amount of the receivables that are presented in our Consolidated Balance Sheets. To minimize credit risk, all customers are subject to extensive credit verification procedures and extensions of credit above defined thresholds are to be approved by the senior management. Our intention is to trade only with recognized creditworthy third parties. In addition, receivable balances are monitored on an ongoing basis. We also limit the risk of bad debts by obtaining security such as guarantees or letters of credit when deemed necessary.

We continually monitor our market risk exposure for market developments that could introduce significant volatility in the financial markets.

Other Factors

We currently source our crude oil for our refineries on a global basis through a combination of market purchases and short-term purchase contracts, and through our crude oil supply agreements. We believe purchases based on market pricing has given us flexibility in obtaining crude oil at lower prices and on a more accurate “as needed” basis. Since our East Coast refineries access their crude slates from the Delaware River via ship or barge and through our rail facilities at Delaware City, these refineries have the flexibility to purchase crude oils from the Mid-Continent and Western Canada, as well as a number of different countries.

Currently, crude oil delivered by rail may be consumed at our East Coast refineries. The Delaware City rail unloading facilities, and the East Coast Storage Assets, allow our East Coast refineries to source WTI-based crude oils from Western Canada and the Mid-Continent, which we believe, at times, may provide cost advantages versus traditional Brent-based international crude oils. In support of this rail strategy, we have at times entered into agreements to lease or purchase crude railcars. In subsequent periods, we have sold or returned railcars to optimize our railcar portfolio. Our railcar fleet provides transportation flexibility within our crude oil sourcing strategy that allows our East Coast refineries to process cost advantaged crude from Canada and the Mid-Continent.

Our operating cost structure is also important to our profitability. Major operating costs include costs relating to employees and contract labor, energy, maintenance and environmental compliance, and emission control regulations, including the cost of RINs required for compliance with RFS. The predominant variable cost is energy, in particular, the price of utilities, natural gas and electricity.

Our operating results are also affected by the reliability of our refinery operations. Unplanned downtime of our refinery assets generally results in lost margin opportunity and increased maintenance expense. The financial impact of planned downtime, such as major turnaround maintenance, is managed through a planning process that considers such things as the margin environment, the availability of resources to perform the needed maintenance and feed logistics, whereas unplanned downtime does not afford us this opportunity.

Refinery-Specific Information

The following section includes refinery-specific information related to our operations under normal operating conditions, crude oil differentials, ancillary costs, and local premiums and discounts.

East Coast Refining System (Delaware City and Paulsboro Refineries). The benchmark refining margin for the East Coast Refining System is calculated by assuming that two barrels of Dated Brent crude oil are converted into one barrel of gasoline and one barrel of diesel. We calculate this benchmark using the NYH market value of reformulated blendstock for oxygenate blending (“RBOB”) and ULSD against the market value of Dated Brent and refer to the benchmark as the Dated Brent (NYH) 2-1-1 benchmark refining margin. The East Coast Refining System has a product slate of approximately 39% distillate, 37% gasoline, 2% high-value Group I lubricants, 1% high-value petrochemicals, with the remaining portion of the product slate comprised of lower-value products (14% black oil, 3% LPGs, and 4% other). For this reason, we believe the Dated Brent (NYH) 2-1-1 is an appropriate benchmark industry refining margin. The majority of East Coast refining revenues are generated off NYH-based market prices.

The East Coast Refining System’s realized gross margin on a per barrel basis is projected to differ from the Dated Brent (NYH) 2-1-1 benchmark refining margin due to the following factors:

•the system processes a slate of primarily medium and heavy sour crude oils, which has constituted approximately 50% to 75% of total throughput. The remaining throughput consists of sweet crude oil and other feedstocks and blendstocks. In addition, we have the capability to process a significant volume of light, sweet crude oil depending on market conditions. Our total throughput costs have historically priced at a discount to Dated Brent;

•as a result of the heavy, sour crude slate processed at our East Coast Refining System, we produce lower value products including sulfur, carbon dioxide and petroleum coke. These products are typically priced at a significant discount to RBOB and ULSD; and

•the Paulsboro refinery produces Group I lubricants, which generally carry a premium sales price to RBOB and ULSD, and the black oil is sold as asphalt, which may be sold at a premium or discount to Dated Brent based on the market.

Toledo Refinery. The benchmark refining margin for the Toledo refinery is calculated by assuming that four barrels of WTI crude oil are converted into three barrels of gasoline, one-half barrel of ULSD and one-half barrel of jet fuel. We calculate this refining margin using the Chicago market values of CBOB and ULSD and the United States Gulf Coast value of jet fuel against the market value of WTI and refer to this benchmark as the WTI (Chicago) 4-3-1 benchmark refining margin. Our Toledo refinery has a product slate of approximately 52% gasoline, 38% distillate, 3% high-value petrochemicals (including nonene, tetramer, benzene, xylene and toluene) with the remaining portion of the product slate comprised of lower-value products (4% LPGs and 3% black oil). For this reason, we believe the WTI (Chicago) 4-3-1 is an appropriate benchmark industry refining margin. The majority of Toledo revenues are generated off Chicago-based market prices.

The Toledo refinery’s realized gross margin on a per barrel basis has historically differed from the WTI (Chicago) 4-3-1 benchmark refining margin due to the following factors:

•the Toledo refinery processes a slate of domestic sweet and Canadian synthetic crude oil. Historically, Toledo’s blended average crude costs have differed from the market value of WTI crude oil;

•the Toledo refinery configuration enables it to produce more barrels of product than throughput which generates a pricing benefit; and

•the Toledo refinery generates a pricing benefit on some of its refined products, primarily its petrochemicals.

Chalmette Refinery. The benchmark refining margin for the Chalmette refinery is calculated by assuming two barrels of LLS crude oil are converted into one barrel of gasoline and one barrel of diesel. We calculate this benchmark using the US Gulf Coast market value of 87 conventional gasoline and ULSD against the market value of LLS and refer to this benchmark as the LLS (Gulf Coast) 2-1-1 benchmark refining margin. Our Chalmette refinery has a product slate of approximately 46% gasoline and 31% distillate, 1% high-value petrochemicals with the remaining portion of the product slate comprised of lower-value products (9% black oil, 5% LPGs, and 8% other). For this reason, we believe the LLS (Gulf Coast) 2-1-1 is an appropriate benchmark industry refining margin. The majority of Chalmette revenues are generated off Gulf Coast-based market prices.

The Chalmette refinery’s realized gross margin on a per barrel basis has historically differed from the LLS (Gulf Coast) 2-1-1 benchmark refining margin due to the following factors:

•the Chalmette refinery crude slate can vary widely and recently has processed a slate of primarily light and medium crude oils, which represents approximately 60% to 75% of total throughput. The remaining throughput consists of heavy crude oils and other feedstocks and blendstocks; and

•as a result of the significant portion of heavy, sour crude slate processed at Chalmette, we produce lower-value products including sulfur and petroleum coke. These products are typically priced at a significant discount to 87 conventional gasoline and ULSD.

Torrance Refinery. The benchmark refining margin for the Torrance refinery is calculated by assuming that four barrels of ANS crude oil are converted into three barrels of gasoline, one-half barrel of diesel and one-half barrel of jet fuel. We calculate this benchmark using the West Coast Los Angeles market value of California reformulated blendstock for oxygenate blending (“CARBOB”), CARB diesel and jet fuel and refer to the benchmark as the ANS (West Coast) 4-3-1 benchmark refining margin. Our Torrance refinery has a product slate of approximately 57% gasoline and 29% distillate with the remaining portion of the product slate comprised of lower-value products (3% LPG, 2% black oil and 9% other). For this reason, we believe the ANS (West Coast) 4-3-1 is an appropriate benchmark industry refining margin. The majority of Torrance revenues are generated off West Coast Los Angeles-based market prices.

The Torrance refinery’s realized gross margin on a per barrel basis has historically differed from the ANS (West Coast) 4-3-1 benchmark refining margin due to the following factors:

•the Torrance refinery has generally processed a slate of primarily heavy sour crude oils, which has historically constituted approximately 60% to 80% of total throughput. The Torrance crude slate has the lowest API gravity (typically an API gravity of less than 20 degrees) of all of our refineries. The remaining throughput consists of other feedstocks and blendstocks; and

•as a result of the heavy, sour crude slate processed at Torrance, we produce lower-value products including petroleum coke and sulfur. These products are typically priced at a significant discount to gasoline and diesel.

Martinez Refinery. The benchmark refining margin for the Martinez refinery is calculated by assuming that three barrels of ANS crude oil are converted into two barrels of gasoline, one-quarter barrel of diesel and three-quarter barrel of jet fuel. We calculate this benchmark using the West Coast San Francisco market value of CARBOB, CARB diesel and jet fuel and refer to the benchmark as the ANS (West Coast) 3-2-1 benchmark refining margin. Our Martinez refinery has a product slate of approximately 58% gasoline and 31% distillate with the remaining portion of the product slate comprised of lower-value products (4% LPG, 3% black oil petroleum coke, and 4% other). For this reason, we believe the ANS (West Coast) 3-2-1 is an appropriate benchmark industry refining margin. The majority of Martinez revenues are generated off West Coast San Francisco-based market prices.

The Martinez refinery’s realized gross margin on a per barrel basis has historically differed from the ANS (West Coast) 4-3-1 benchmark refining margin due to the following factors:

•the Martinez refinery has generally processed a slate of primarily heavy sour crude oils, which has historically constituted approximately 45% to 70% of total throughput. The remaining throughput consists of other feedstocks and blendstocks; and

•as a result of the heavy, sour crude slate processed at Martinez, we produce lower-value products including petroleum coke and sulfur. These products are typically priced at a significant discount to gasoline and CARB diesel.

Results of Operations

The tables below reflect our consolidated financial and operating highlights for the years ended December 31, 2025, 2024 and 2023 (amounts in millions, except per share data). We operate in two reportable business segments: Refining and Logistics. Our oil refineries, excluding the assets operated by PBFX, are all engaged in the refining of crude oil and other feedstocks into petroleum products, and represent the Refining segment. PBFX is an indirect wholly-owned subsidiary of PBF Energy that operates certain logistics assets such as crude oil and refined products terminals, pipelines and storage facilities. PBFX’s operations represent the Logistics segment. We do not separately discuss our results by individual segments as our Logistics segment did not have any significant third-party revenues and a significant portion of its operating results are eliminated in consolidation.


PBF Energy	Year Ended December 31,
	2025		2024		2023
Revenues	$	29,332.3	$	33,115.3	$	38,324.8

Cost and expenses:
Cost of products and other	26,627.0		30,266.7		32,671.3
Operating expenses (excluding depreciation and amortization expense as reflected below)	2,646.0		2,606.2		2,694.9
Depreciation and amortization expense	630.3		614.6		560.0
Cost of sales	29,903.3		33,487.5		35,926.2
General and administrative expenses (excluding depreciation and amortization expense as reflected below)	332.3		260.4		362.5
Depreciation and amortization expense	14.4		13.2		11.5
Gain on insurance recoveries, net	(832.5)		—		—
Change in fair value of contingent consideration, net	—		(3.3)		(45.8)
Equity loss in investee	62.2		47.4		45.3
Loss (gain) on formation of SBR equity method investment	—		8.7		(925.1)

(Gain) loss on sale of assets	(93.1)		0.4		(1.3)
Total cost and expenses	29,386.6		33,814.3		35,373.3

Income (loss) from operations	(54.3)		(699.0)		2,951.5

Other income (expense):
Interest expense (net of interest income of $24.3, $51.2, and $75.0, respectively)	(181.6)		(72.0)		(63.8)
Change in Tax Receivable Agreement liability	—		—		2.0
Change in fair value of catalyst obligations	—		—		1.1
Loss on extinguishment of debt	—		—		(5.7)
Other non-service components of net periodic benefit cost	1.3		2.4		0.7
Income (loss) before income taxes	(234.6)		(768.6)		2,885.8
Income tax (benefit) expense	(74.1)		(228.4)		723.8
Net income (loss)	(160.5)		(540.2)		2,162.0
Less: net income (loss) attributable to noncontrolling interests	(2.0)		(6.4)		21.5
Net income (loss) attributable to PBF Energy Inc. stockholders	$	(158.5)	$	(533.8)	$	2,140.5

Consolidated gross margin	$	(571.0)	$	(372.2)	$	2,398.6

Gross refining margin (1)	$	2,347.5	$	2,487.6	$	5,287.7

Net income (loss) available to Class A common stock per share:
Basic	$	(1.39)	$	(4.59)	$	17.13
Diluted	$	(1.39)	$	(4.60)	$	16.52

——————————

(1) See Non-GAAP Financial Measures.

Operating Highlights


	Year Ended December 31,
	2025			2024			2023
Key Operating Information
Production (bpd in thousands)	838.5			913.1			918.3
Crude oil and feedstocks throughput (bpd in thousands)	832.9			904.0			909.4
Total crude oil and feedstocks throughput (millions of barrels)	304.0			330.9			329.0
Consolidated gross margin per barrel of throughput	$	(1.87)		$	(1.13)		$	7.29
Gross refining margin, excluding special items, per barrel of throughput (1)	$	8.77		$	7.89		$	16.07
Refinery operating expense, per barrel of throughput	$	8.38		$	7.52		$	7.85

Crude and feedstocks (% of total throughput) (2)
Heavy	25		%	31		%	27		%
Medium	37		%	38		%	35		%
Light	21		%	17		%	20		%
Other feedstocks and blends	17		%	14		%	18		%
Total throughput	100		%	100		%	100		%

Yield (% of total throughput)
Gasoline and gasoline blendstocks	45		%	47		%	47		%
Distillates and distillate blendstocks	35		%	34		%	34		%
Lubes	1		%	1		%	1		%
Chemicals	1		%	1		%	1		%
Other	19		%	18		%	18		%
Total yield	101		%	101		%	101		%

——————————

(1) See Non-GAAP Financial Measures.

(2) We define heavy crude oil as crude oil with an API gravity of less than 24 degrees. We define medium crude oil as crude oil with an API gravity between 24 and 35 degrees. We define light crude oil as crude oil with an API gravity higher than 35 degrees.

The table below summarizes certain market indicators relating to our operating results as reported by Platts, a division of The McGraw-Hill Companies. Effective RIN basket price is recalculated based on information as reported by Argus.


	Year Ended December 31,
(dollars per barrel, except as noted)	2025		2024		2023
Dated Brent crude oil	$	69.03	$	80.72	$	82.64
West Texas Intermediate (WTI) crude oil	$	64.87	$	75.87	$	77.67
Light Louisiana Sweet (LLS) crude oil	$	67.08	$	78.33	$	80.14
Alaska North Slope (ANS) crude oil	$	69.67	$	80.24	$	82.36
Crack Spreads
Dated Brent (NYH) 2-1-1	$	22.59	$	18.24	$	29.67
WTI (Chicago) 4-3-1	$	18.31	$	16.27	$	23.71
LLS (Gulf Coast) 2-1-1	$	21.76	$	18.21	$	29.13
ANS (West Coast-LA) 4-3-1	$	27.52	$	23.36	$	36.88
ANS (West Coast-SF) 3-2-1	$	30.14	$	24.62	$	36.89
Crude Oil Differentials
Dated Brent (foreign) less WTI	$	4.16	$	4.84	$	4.97
Dated Brent less Maya (heavy, sour)	$	9.31	$	12.31	$	13.71
Dated Brent less WTS (sour)	$	4.34	$	4.85	$	4.99
Dated Brent less ASCI (sour)	$	4.12	$	5.23	$	5.73
WTI less WCS (heavy, sour)	$	12.17	$	14.82	$	18.32
WTI less Bakken (light, sweet)	$	1.21	$	1.39	$	(1.28)
WTI less Syncrude (light, sweet)	$	0.97	$	0.75	$	(0.91)
WTI less LLS (light, sweet)	$	(2.21)	$	(2.45)	$	(2.48)
WTI less ANS (light, sweet)	$	(4.80)	$	(4.36)	$	(4.70)
Effective RIN basket price	$	5.85	$	3.75	$	7.02
Natural gas (dollars per MMBTU)	$	3.62	$	2.41	$	2.66

2025 Compared to 2024

Overview— PBF Energy net loss was $160.5 million for the year ended December 31, 2025 compared to net loss of $540.2 million for the year ended December 31, 2024. Net loss attributable to PBF Energy stockholders was $158.5 million, or $(1.39) per diluted share, for the year ended December 31, 2025 ($(1.39) per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net loss, or $(4.13) per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net loss excluding special items, as described below in Non-GAAP Financial Measures) compared to net loss attributable to PBF Energy stockholders of $533.8 million, or $(4.60) per diluted share, for the year ended December 31, 2024 ($(4.60) per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net loss, or $(3.89) per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net loss excluding special items, as described below in Non-GAAP Financial Measures). The net income (loss) attributable to PBF Energy stockholders represents PBF Energy’s equity interest in PBF LLC’s pre-tax income (loss), less applicable income tax (benefit) expense. PBF Energy’s weighted-average equity interest in PBF LLC was 99.3% for both the years ended December 31, 2025 and 2024.

Our results for the year ended December 31, 2025 were positively impacted by special items consisting of a gain on insurance recoveries, net of $832.5 million, or $616.1 million net of tax, gain on the sale of terminal assets of $94.0 million, or $69.6 million net of tax, and our share of the adjustment to the SBR LCM inventory reserve of $10.4 million, or $7.7 million net of tax, partially offset by a non-cash, pre-tax LCM inventory adjustment of approximately $313.0 million, or $231.6 million net of tax, expenses associated with the Martinez refinery fire of $163.7 million, or $121.1 million net of tax, costs related to the RBI initiative of approximately $29.6 million, or $21.9 million net of tax, and a LIFO inventory decrement of $5.4 million, or $4.0 million net of tax. Our results for the year ended December 31, 2024 were negatively impacted by special items consisting of a LIFO inventory decrement of $124.5 million, or $92.1 million net of tax, and a decrease to our gain on the formation of the SBR equity method investment of $8.7 million, or $6.4 million net of tax, partially offset by our share of the adjustment to the SBR LCM inventory reserve of $18.9 million, or $14.0 million net of tax, and a change in fair value of contingent consideration of $3.3 million, or $2.4 million net of tax, related to changes in our earn-out obligations associated with the acquisition of the Martinez refinery and logistic assets (the “Martinez Contingent Consideration”).

Excluding the impact of these special items, our results for the year ended December 31, 2025 reflected an overall increase in refining margins compared to the same period in 2024. This improvement was primarily driven by favorable movements in crack spreads, partially offset by lower crude oil differentials, as well as lower throughput volumes and barrels sold at the majority of our refineries. In addition, the temporary shutdown of the Martinez refinery following the fire negatively impacted results due to lower and sub-optimal refinery yields for most of the year. Higher interest expense resulting from increased debt balances also weighed on earnings in 2025.

Revenues— Revenues totaled $29.3 billion for the year ended December 31, 2025 compared to $33.1 billion for the year ended December 31, 2024, a decrease of approximately $3.8 billion or 11.5%. Revenues per barrel sold were $82.02 and $90.47 for the years ended December 31, 2025 and 2024, respectively, a decrease of 9.3% directly related to lower hydrocarbon commodity prices and sale volumes. For the year ended December 31, 2025, the total throughput rates at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 300,300 bpd, 147,000 bpd, 174,800 bpd and 210,800 bpd, respectively. For the year ended December 31, 2024, the total throughput rates at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 305,200 bpd, 140,700 bpd, 162,200 bpd and 295,900 bpd, respectively. For the year ended December 31, 2025, the total barrels sold at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 344,000 bpd, 155,800 bpd, 167,500 bpd and 312,700 bpd, respectively. For the year ended December 31, 2024, the total barrels sold at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 347,700 bpd, 148,500 bpd, 158,700 bpd and 345,300 bpd, respectively.

Overall average throughput rates at our refineries were lower in the year ended December 31, 2025 primarily due to unplanned downtime at our West Coast refineries when compared to the same period in 2024. We plan to continue operating our refineries based on demand and current market conditions. Total refined product barrels sold were higher than throughput rates, reflecting sales from inventory as well as sales and purchases of refined products outside our refineries.

Consolidated gross margin— Consolidated gross margin totaled $(571.0) million for the year ended December 31, 2025, compared to $(372.2) million for the year ended December 31, 2024, a decrease of $198.8 million. Gross refining margin (as described below in Non-GAAP Financial Measures) totaled $2,347.5 million, or $7.72 per barrel of throughput, for the year ended December 31, 2025 compared to $2,487.6 million, or $7.51 per barrel of throughput, for the year ended December 31, 2024, a decrease of approximately $140.1 million. Gross refining margin excluding special items totaled $2,665.9 million, or $8.77 per barrel of throughput, for the year ended December 31, 2025 compared to $2,612.1 million, or $7.89 per barrel of throughput, for the year ended December 31, 2024.

Consolidated gross margin and gross refining margin for the year ended December 31, 2025 were negatively impacted by a non-cash LCM adjustment of $313.0 million resulting from the decrease in crude oil and refined product prices from the prior year, and a LIFO inventory decrement charge of $5.4 million primarily associated with the Martinez refinery. Consolidated gross margin and gross refining margin for the year ended December 31, 2024 were negatively impacted by a LIFO inventory decrement charge of $124.5 million mainly related to our East Coast and Gulf Coast LIFO inventory layers. Consolidated gross margin and gross refining margin excluding special items increased primarily due to favorable movements in crack spreads, partially offset by lower crude oil differentials, as well as lower throughput volumes and barrels sold at the majority of our refineries. In addition, the temporary shutdown of the Martinez refinery following the fire negatively affected our margins.

Additionally, our results continue to be impacted by significant costs to comply with the RFS. Total RFS compliance costs were $680.1 million for the year ended December 31, 2025 compared to $515.3 million for the year ended December 31, 2024.

Average industry margins were favorable during the year ended December 31, 2025 in comparison to the prior year, primarily due to increased refining margins as a result of favorable movements in crack spreads at all of our refineries offset by narrowing crude differentials, particularly between light and heavy crude grades.

Favorable movements in these benchmark crude differentials typically result in lower crude costs and positively impact our earnings, while reductions in these benchmark crude differentials typically result in higher crude costs and negatively impact our earnings.

On the East Coast, the Dated Brent (NYH) 2-1-1 industry crack spread was approximately $22.59 per barrel, or 23.8% higher, in the year ended December 31, 2025, as compared to $18.24 per barrel in the same period in 2024. Our margins were negatively impacted from our refinery specific slate on the East Coast by weakened light-heavy crude spreads including Dated Brent/Maya and Dated Brent/ASCI differentials, which decreased by $3.00 and $1.11 per barrel, respectively, compared to the same period in 2024. Additionally, the WTI/WCS differential decreased to $12.17 per barrel in 2025 compared to $14.82 per barrel in 2024, which unfavorably impacted our cost of heavy Canadian crude.

Across the Mid-Continent, the WTI (Chicago) 4-3-1 industry crack spread was $18.31 per barrel, or 12.5% higher, in the year ended December 31, 2025, as compared to $16.27 per barrel in the prior year. Our margins were negatively impacted from our refinery specific slate in the Mid-Continent by a decreasing WTI/Bakken differential, which averaged a discount of $1.21 per barrel in the year ended December 31, 2025, as compared to a discount of $1.39 per barrel in the prior year. However, the WTI/Syncrude differential averaged a discount of $0.97 per barrel for the year ended December 31, 2025 as compared to a discount of $0.75 per barrel in the prior year.

On the Gulf Coast, the LLS (Gulf Coast) 2-1-1 industry crack spread was $21.76 per barrel, or 19.5% higher, in the year ended December 31, 2025 as compared to $18.21 per barrel in the prior year. Margins on the Gulf Coast were negatively impacted from our refinery specific slate by a narrowing light-heavy crude spreads including Dated Brent/WTS, which averaged a discount of $4.34 per barrel for the year ended December 31, 2025 as compared to a discount of $4.85 per barrel in the prior year.

On the West Coast, the ANS (West Coast) 4-3-1 industry crack spread was $27.52 per barrel, or 17.8% higher, in the year ended December 31, 2025 as compared to $23.36 per barrel in the prior year. Additionally, the ANS (West Coast) 3-2-1 industry crack spread was $30.14 per barrel, or 22.4% higher, in the year ended December 31, 2025 as compared to $24.62 per barrel in the prior year. Our margins on the West Coast were negatively impacted from our refinery specific slate by a weakening crude spreads including WTI/WCS differential, which averaged $12.17 per barrel for the year ended December 31, 2025 as compared to $14.82 per barrel in the prior year.

Operating expenses— Operating expenses totaled $2,646.0 million for the year ended December 31, 2025 compared to $2,606.2 million for the year ended December 31, 2024, an increase of approximately $39.8 million, or 1.5%. Of the total $2,646.0 million in operating expenses, $2,547.0 million, or $8.38 per barrel of throughput, related to expenses incurred by the Refining segment, while the remaining $99.0 million related to expenses incurred by the Logistics segment ($2,487.8 million or $7.52 per barrel of throughput, and $118.4 million of operating expenses for the year ended December 31, 2024 related to the Refining and Logistics segments, respectively). The increase in operating expenses in comparison to the same period in 2024 was mainly attributable to higher maintenance expenses at our Martinez refinery due to the Martinez refinery fire, partially offset by lower outside services, including lower legal expenses, as well as realized RBI cost savings mainly attributable to reduced energy, utilities, and maintenance costs.

General and administrative expenses— General and administrative expenses totaled $332.3 million for the year ended December 31, 2025, compared to $260.4 million for the year ended December 31, 2024, an increase of $71.9 million or 27.6%. The increase in general and administrative expenses in comparison to the same period in 2024 was primarily due to higher employee related expenses and higher outside service costs incurred in connection with the RBI initiative. General and administrative expenses are comprised of personnel, facilities, and other infrastructure costs necessary to support our refineries and related logistics assets.

Gain on insurance recoveries, net— There was a gain on insurance recoveries of $832.5 million, associated with the Martinez refinery fire for the year ended December 31, 2025, which was net of the $61.0 million receivable that was recorded at March 31, 2025. There were no such gains for the year ended December 31, 2024.

Loss (gain) on formation of SBR equity method investment— There was a loss of $8.7 million for the year ended December 31, 2024, associated with a reduction of our gain on formation of the SBR equity method investment. There was no such gain or loss during the year ended December 31, 2025.

Equity loss in investee— There was a loss of $62.2 million and $47.4 million for the years ended December 31, 2025 and December 31, 2024, respectively, related to our equity share of our investment in SBR.

(Gain) loss on sale of assets— There was a net gain of $93.1 million for the year ended December 31, 2025 primarily related to the sale of terminal assets. There was a net loss of $0.4 million for the year ended December 31, 2024 related primarily to the sale of non-operating refinery assets.

Depreciation and amortization expense— Depreciation and amortization expense totaled $644.7 million for the year ended December 31, 2025 (including $630.3 million recorded within Cost of sales) compared to $627.8 million for the year ended December 31, 2024 (including $614.6 million recorded within Cost of sales), an increase of $16.9 million. The increase was a result of a general increase in our fixed asset base due to capital projects and turnarounds completed since the end of the prior year.

Change in fair value of contingent consideration, net— Change in fair value of contingent consideration represented a gain of $3.3 million for the year ended December 31, 2024. This gain was related to changes in the estimated fair value of the Martinez Contingent Consideration. Our final earn-out payment of $18.8 million was paid in full during the second quarter of 2024.

Interest expense, net— Interest expense, net totaled $181.6 million for the year ended December 31, 2025, compared to $72.0 million for the year ended December 31, 2024, an increase of $109.6 million. The net increase is mainly attributable to higher interest cost associated with the issuance of the 2030 9.875% Senior Notes in March 2025 and higher average outstanding borrowings on our Revolving Credit Facility. Additionally, there was a $26.9 million decrease in interest income earned during the year ended December 31, 2025 driven by lower interest rates and cash deposits in comparison to the prior year. For the year ended December 31, 2025, interest expense includes interest on long-term debt, letter of credit fees associated with the purchase of certain crude oils and the amortization of deferred financing costs.

Income tax (benefit) expense— PBF LLC is organized as a limited liability company and PBFX is a partnership, both of which are treated as “flow-through” entities for federal income tax purposes and therefore are not subject to income tax. However, two subsidiaries of Chalmette Refining and our Canadian subsidiary, PBF Energy Limited, are treated as C-Corporations for income tax purposes and may incur income taxes with respect to their earnings, as applicable. The members of PBF LLC are required to include their proportionate share of PBF LLC’s taxable income or loss, on their respective tax returns. PBF LLC generally makes distributions to its members, per the terms of PBF LLC’s amended and restated limited liability company agreement, related to such taxes on a pro-rata basis. PBF Energy recognizes an income tax expense or benefit in our consolidated financial statements based on PBF Energy’s allocable share of PBF LLC’s pre-tax income or loss, which was approximately 99.3% on a weighted-average basis for both the year ended December 31, 2025 and 2024. PBF Energy’s Consolidated Financial Statements do not reflect any benefit or provision for income taxes on the pre-tax income or loss attributable to the noncontrolling interest in PBF LLC (although, as described above, PBF LLC must make tax distributions to all its members on a pro-rata basis). There was an increase in the state income tax rate attributed to state tax rate credit generation and prior year return to provision true-ups. PBF Energy’s effective tax rate, including the impact of noncontrolling interests, for the years ended December 31, 2025 and 2024 was 31.6% and 29.7%, respectively.

Noncontrolling Interest— PBF Energy is the sole managing member of, and has a controlling interest in, PBF LLC. As the sole managing member of PBF LLC, PBF Energy operates and controls all of the business and affairs of PBF LLC and its subsidiaries. PBF Energy consolidates the financial results of PBF LLC and its subsidiaries. With respect to the consolidation of PBF LLC, we record a noncontrolling interest for the economic interest in PBF LLC held by members other than PBF Energy, with respect to the consolidation of PBFX, we recorded a noncontrolling interest for the economic interests in PBFX held by the public unitholders of PBFX prior to the close of the Merger Transaction, and with respect to the consolidation of PBF Holding, we record a 20% noncontrolling interest for the ownership interests in two subsidiaries of Chalmette Refining held by a third-party. The total noncontrolling interest on the Consolidated Statements of Operations represents the portion of the Company’s earnings or loss attributable to the economic interests held by members of PBF LLC other than PBF Energy, by the public common unitholders of PBFX prior to the close of the Merger Transaction and by the third-party stockholders of certain of Chalmette Refining’s subsidiaries. The total noncontrolling interest on the Consolidated Balance Sheets represents the portion of the Company’s net assets attributable to the economic interests held by the members of PBF LLC other than PBF Energy, and by the third-party stockholders of the two Chalmette Refining subsidiaries. PBF Energy’s weighted-average equity noncontrolling interest ownership percentage in PBF LLC for both the year ended December 31, 2025 and 2024 was approximately 0.7%. The carrying amount of the noncontrolling interest on our Consolidated Balance Sheets attributable to the noncontrolling interest is not equal to the noncontrolling interest ownership percentage due to the effect of income taxes and related agreements that pertain solely to PBF Energy.

Non-GAAP Financial Measures

Management uses certain financial measures to evaluate our operating performance that are calculated and presented on the basis of methodologies other than in accordance with GAAP (“Non-GAAP”). These measures should not be considered a substitute for, or superior to, measures of financial performance prepared in accordance with GAAP, and our calculations thereof may not be comparable to similarly entitled measures reported by other companies.

Special Items

The Non-GAAP measures presented include Adjusted Fully-Converted Net Income (Loss) excluding special items, gross refining margin excluding special items, EBITDA excluding special items, and net debt to capitalization ratio excluding special items. Special items for the periods presented relate to LCM inventory adjustments, our share of the SBR LCM inventory adjustment, a LIFO inventory decrement, expenses associated with the Martinez refinery fire, gain on insurance recoveries, costs related to the RBI initiative, gain on sale of our terminal assets, net changes in fair value of contingent consideration, loss (gain) on formation of the SBR equity method investment, loss on extinguishment of debt and termination of the Inventory Intermediation Agreement, gains on land sales, and changes in the Tax Receivable Agreement liability. See “Notes to Non-GAAP Financial Measures” below for more details on all special items disclosed. Although we believe that Non-GAAP financial measures, excluding the impact of special items, provide useful supplemental information to investors regarding the results and performance of our business and allow for helpful period-over-period comparisons, such Non-GAAP measures should only be considered as a supplement to, and not as a substitute for, or superior to, the financial measures prepared in accordance with GAAP.

Adjusted Fully-Converted Net Income (Loss) and Adjusted Fully-Converted Net Income (Loss) Excluding Special Items

PBF Energy utilizes results presented on an Adjusted Fully-Converted basis that reflect an assumed exchange of all PBF LLC Series A Units for shares of PBF Energy Class A common stock. In addition, we present results on an Adjusted Fully-Converted basis excluding special items as described above. We believe that these Adjusted Fully-Converted measures, when presented in conjunction with comparable GAAP measures, are useful to investors to compare PBF Energy results across different periods and to facilitate an understanding of our operating results.

Neither Adjusted Fully-Converted Net Income (Loss) nor Adjusted Fully-Converted Net Income (Loss) excluding special items should be considered an alternative to net income (loss) presented in accordance with GAAP. Adjusted Fully-Converted Net Income (Loss) and Adjusted Fully-Converted Net Income (Loss) excluding special items presented by other companies may not be comparable to our presentation, since each company may define these terms differently. The differences between Adjusted Fully-Converted and GAAP results are as follows:

1.Assumed exchange of all PBF LLC Series A Units for shares of PBF Energy Class A common stock. As a result of the assumed exchange of all PBF LLC Series A Units, the noncontrolling interest related to these units is converted to controlling interest. Management believes that it is useful to provide the per-share effect associated with the assumed exchange of all PBF LLC Series A Units.

2.Income Taxes. Prior to PBF Energy’s IPO, PBF Energy was organized as a limited liability company treated as a “flow-through” entity for income tax purposes, and even after PBF Energy’s IPO, not all of its earnings are subject to corporate-level income taxes. Adjustments have been made to the Adjusted Fully-Converted tax provisions and earnings to assume that PBF Energy had adopted its post-IPO corporate tax structure for all periods presented and is taxed as a C-corporation in the U.S. at the prevailing corporate rates. These assumptions are consistent with the assumption in clause 1 above that all PBF LLC Series A Units are exchanged for shares of PBF Energy Class A common stock, as the assumed exchange would change the amount of PBF Energy’s earnings that are subject to corporate income tax.

The following table reconciles PBF Energy’s Adjusted Fully-Converted results with its results presented in accordance with GAAP for the years ended December 31, 2025, 2024 and 2023 (in millions, except share and per share amounts):


	Year Ended December 31,
	2025		2024		2023
Net income (loss) attributable to PBF Energy Inc. stockholders	$	(158.5)	$	(533.8)	$	2,140.5
Less: Income allocated to participating securities	0.1		0.1		—
Income (loss) available to PBF Energy Inc. stockholders - basic	(158.6)		(533.9)		2,140.5
Add: Net income (loss) attributable to noncontrolling interest (1)	(2.1)		(6.0)		20.5
Less: Income tax benefit (expense) (2)	0.6		1.6		(5.3)
Adjusted fully-converted net income (loss)	$	(160.1)	$	(538.3)	$	2,155.7
Special Items: (3)
Add: LCM inventory adjustment	313.0		—		—
Add: LCM inventory adjustment - SBR	(10.4)		(18.9)		38.7
Add: LIFO inventory decrement	5.4		124.5		—
Add: Martinez refinery fire expenses	163.7		—		—
Add: Gain on insurance recoveries, net	(832.5)		—		—
Add: Costs related to RBI initiative	29.6		—		—
Add: Gain on sale of terminal assets	(94.0)		—		—
Add: Change in fair value of contingent consideration, net	—		(3.3)		(45.8)
Add: Loss (gain) on formation of SBR equity method investment	—		8.7		(925.1)
Add: Loss on extinguishment of debt and termination of Inventory Intermediation Agreement	—		—		19.2
Add: Gain on land sales	—		—		(1.7)

Add: Change in Tax Receivable Agreement liability	—		—		(2.0)

Less: Recomputed income tax on special items	110.7		(28.8)		238.3
Adjusted fully-converted net income (loss) excluding special items	$	(474.6)	$	(456.1)	$	1,477.3

Weighted-average shares outstanding of PBF Energy Inc.	114,052,733		116,248,827		124,953,858
Conversion of PBF LLC Series A Units (4)	862,780		862,780		899,519
Common stock equivalents (5)	—		—		4,656,071

Fully-converted shares outstanding—diluted	114,915,513		117,111,607		130,509,448

Diluted net income (loss) per share	$	(1.39)	$	(4.60)	$	16.52
Adjusted fully-converted net income (loss) per fully exchanged, fully diluted shares outstanding (5)	$	(1.39)	$	(4.60)	$	16.52
Adjusted fully-converted net income (loss) excluding special items per fully exchanged, fully diluted shares outstanding (3) (5)	$	(4.13)	$	(3.89)	$	11.32

——————————

See Notes to Non-GAAP Financial Measures.

Gross Refining Margin and Gross Refining Margin Excluding Special Items

Gross refining margin is defined as consolidated gross margin excluding refining depreciation, refining operating expenses, and gross margin of the Logistics segment. We believe both gross refining margin and gross refining margin excluding special items are important measures of operating performance and provide useful information to investors because they are helpful metric comparisons to the industry refining margin benchmarks, as the refining margin benchmarks do not include a charge for refining operating expenses and depreciation. In order to assess our operating performance, we compare our gross refining margin (revenues less cost of products and other) to industry refining margin benchmarks and crude oil prices as defined in the table below.

Neither gross refining margin nor gross refining margin excluding special items should be considered an alternative to consolidated gross margin, income from operations, net cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Gross refining margin and gross refining margin excluding special items presented by other companies may not be comparable to our presentation, since each company may define these terms differently. The following table presents our GAAP calculation of gross margin and a reconciliation of gross refining margin, and gross refining margin excluding special items, to the most directly comparable GAAP financial measure, consolidated gross margin, on a historical basis, as applicable, for each of the periods indicated (in millions, except per barrel amounts):


	Year Ended December 31,
	2025				2024				2023
	$		per barrel of throughput		$		per barrel of throughput		$		per barrel of throughput
Calculation of consolidated gross margin:
Revenues	$	29,332.3	$	96.49	$	33,115.3	$	100.08	$	38,324.8	$	116.48
Less: Cost of sales	29,903.3		98.36		33,487.5		101.21		35,926.2		109.19
Consolidated gross margin	$	(571.0)	$	(1.87)	$	(372.2)	$	(1.13)	$	2,398.6	$	7.29
Reconciliation of consolidated gross margin to gross refining margin:
Consolidated gross margin	$	(571.0)	$	(1.87)	$	(372.2)	$	(1.13)	$	2,398.6	$	7.29
Add: Logistics operating expense	116.5		0.38		135.8		0.41		131.9		0.40
Add: Logistics depreciation expense	36.1		0.12		36.2		0.11		36.1		0.11
Less: Logistics gross margin	(375.3)		(1.24)		(378.4)		(1.15)		(384.1)		(1.17)
Add: Refining operating expenses	2,547.0		8.38		2,487.8		7.52		2,581.3		7.85
Add: Refining depreciation expense	594.2		1.95		578.4		1.75		523.9		1.59
Gross refining margin	$	2,347.5	$	7.72	$	2,487.6	$	7.51	$	5,287.7	$	16.07
Special Items: (3)
Add: LCM inventory adjustment	313.0		1.03		—		—		—		—
Add: LIFO inventory decrement	5.4		0.02		124.5		0.38		—		—
Gross refining margin excluding special items	$	2,665.9	$	8.77	$	2,612.1	$	7.89	$	5,287.7	$	16.07

——————————

See Notes to Non-GAAP Financial Measures.

EBITDA, EBITDA Excluding Special Items and Adjusted EBITDA

Our management uses earnings before interest, income taxes, depreciation and amortization (“EBITDA”), EBITDA excluding special items and Adjusted EBITDA as measures of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with our Board of Directors, creditors, analysts and investors concerning our financial performance. Our outstanding indebtedness for borrowed money and other contractual obligations also include similar measures as a basis for certain covenants under those agreements which may differ from the Adjusted EBITDA definition described below.

EBITDA, EBITDA excluding special items and Adjusted EBITDA are not presentations made in accordance with GAAP and our computation of EBITDA, EBITDA excluding special items and Adjusted EBITDA may vary from others in our industry. In addition, Adjusted EBITDA contains some, but not all, adjustments that are taken into account in the calculation of the components of various covenants in the agreements governing our senior notes and other credit facilities. EBITDA, EBITDA excluding special items and Adjusted EBITDA should not be considered as alternatives to income from operations or net income as measures of operating performance. In addition, EBITDA, EBITDA excluding special items and Adjusted EBITDA are not presented as, and should not be considered, an alternative to cash flows from operations as a measure of liquidity. Adjusted EBITDA is defined as EBITDA before adjustments for items such as stock-based compensation expense, change in the fair value of catalyst obligations, LCM inventory adjustment, our share of the SBR LCM inventory adjustment, LIFO inventory decrement, expenses associated with the Martinez refinery fire, gain on insurance recoveries, costs related to RBI initiative, gain on sale of our terminal assets, net change in the fair value of contingent consideration, loss (gain) on the formation of the SBR equity method investment, loss on extinguishment of debt, gain on land sales, changes in the Tax Receivable Agreement liability, and certain other non-cash items. Other companies, including other companies in our industry, may calculate EBITDA, EBITDA excluding special items and Adjusted EBITDA differently than we do, limiting their usefulness as comparative measures. EBITDA, EBITDA excluding special items and Adjusted EBITDA also have limitations as analytical tools and should not be considered in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations include that EBITDA, EBITDA excluding special items and Adjusted EBITDA:

•do not reflect depreciation expense or our cash expenditures, or future requirements, for capital expenditures or contractual commitments;

•do not reflect changes in, or cash requirements for, our working capital needs;

•do not reflect our interest expense, or the cash requirements necessary to service interest or principal payments, on our debt;

•do not reflect realized and unrealized gains and losses from certain hedging activities, which may have a substantial impact on our cash flow;

•do not reflect certain other non-cash income and expenses; and

•exclude income taxes that may represent a reduction in available cash.

The following tables reconcile net income (loss) as reflected in PBF Energy’s results of operations to EBITDA, EBITDA excluding special items and Adjusted EBITDA for the periods presented (in millions):


	Year Ended December 31,
	2025		2024		2023
Reconciliation of net income (loss) to EBITDA and EBITDA excluding special items:
Net income (loss)	$	(160.5)	$	(540.2)	$	2,162.0
Add: Depreciation and amortization expense	644.7		627.8		571.5
Add: Interest expense, net	181.6		72.0		63.8
Add: Income tax (benefit) expense	(74.1)		(228.4)		723.8
EBITDA	$	591.7	$	(68.8)	$	3,521.1
Special Items: (3)
Add: LCM inventory adjustment	313.0		—		—
Add: LCM inventory adjustment - SBR	(10.4)		(18.9)		38.7
Add: LIFO inventory decrement	5.4		124.5		—
Add: Martinez refinery fire expenses	163.7		—		—
Add: Gain on insurance recoveries, net	(832.5)		—		—
Add: Costs related to RBI initiative	29.6		—		—
Add: Gain on sale of terminal assets	(94.0)		—		—
Add: Change in fair value of contingent consideration, net	—		(3.3)		(45.8)
Add: Loss (gain) on formation of SBR equity method investment	—		8.7		(925.1)
Add: Loss on extinguishment of debt	—		—		5.7
Add: Gain on land sales	—		—		(1.7)


Add: Change in Tax Receivable Agreement liability	—		—		(2.0)
EBITDA excluding special items	$	166.5	$	42.2	$	2,590.9

Reconciliation of EBITDA to Adjusted EBITDA:
EBITDA	$	591.7	$	(68.8)	$	3,521.1
Add: Stock based compensation	39.0		44.3		51.5
Add: Change in fair value of catalyst obligations	—		—		(1.1)
Special Items: (3)
Add: LCM inventory adjustment	313.0		—		—
Add: LCM inventory adjustment - SBR	(10.4)		(18.9)		38.7
Add: LIFO inventory decrement	5.4		124.5		—
Add: Martinez refinery fire expenses	163.7		—		—
Add: Gain on insurance recoveries, net	(832.5)		—		—
Add: Costs related to RBI initiative	29.6		—		—
Add: Gain on sale of terminal assets	(94.0)		—		—
Add: Change in fair value of contingent consideration, net	—		(3.3)		(45.8)
Add: Loss (gain) on formation of SBR equity method investment	—		8.7		(925.1)
Add: Loss on extinguishment of debt	—		—		5.7
Add: Gain on land sales	—		—		(1.7)


Add: Change in Tax Receivable Agreement liability	—		—		(2.0)
Adjusted EBITDA	$	205.5	$	86.5	$	2,641.3

——————————

See Notes to Non-GAAP Financial Measures.

Net Debt to Capitalization Ratio and Net Debt to Capitalization Ratio Excluding Special Items

The total debt to capitalization ratio is calculated by dividing total debt by the sum of total debt and total equity. This ratio is a measurement that management believes is useful to investors in analyzing our leverage. Net debt and the net debt to capitalization ratio are Non-GAAP measures and should not be considered an alternative to any other measure of financial performance or liquidity presented in accordance with GAAP. Net debt is calculated by subtracting cash and cash equivalents from total debt. Total capitalization is calculated by adding total debt and total equity. We believe these measurements are also useful to investors since we have the ability to and may decide to use a portion of our cash and cash equivalents to retire or pay down our debt. Additionally, we have also presented the total debt to capitalization and net debt to capitalization ratios excluding the cumulative effects of special items on equity.


		December 31,			December 31,
		2025			2024
Balance Sheet Data:
	Cash and cash equivalents	$	527.9		$	536.1
	Inventories	2,563.1			2,595.3
	Total assets	13,019.9			12,703.2
	Total debt	2,148.3			1,457.3
	Net debt	1,620.4			921.2
	Total equity	5,449.9			5,678.6
	Total equity excluding special items (6)	4,143.5			4,686.8
	Total capitalization	7,598.2			7,135.9

	Total debt to capitalization ratio	28		%	20		%
	Total debt to capitalization ratio, excluding special items (6)	34		%	24		%
	Net debt to capitalization ratio	23		%	14		%
	Net debt to capitalization ratio, excluding special items (6)	28		%	16		%

——————————

See Notes to Non-GAAP Financial Measures.

Notes to Non-GAAP Financial Measures

The following notes are applicable to the Non-GAAP Financial Measures above:

(1) Represents the elimination of the noncontrolling interest associated with the ownership by the members of PBF LLC other than PBF Energy, as if such members had fully exchanged their PBF LLC Series A Units for shares of PBF Energy Class A common stock.

(2) Represents an adjustment to reflect PBF Energy’s annualized statutory corporate tax rate of approximately 26.0% for the years ended December 31, 2025, 2024, and 2023, applied to net income (loss) attributable to noncontrolling interest for all periods presented. The adjustment assumes the full exchange of existing PBF LLC Series A Units as described in (1) above.

(3) Special items:

LCM inventory adjustment - LCM is a GAAP requirement for inventory valuation that mandates inventory to be stated at the lower of cost or market. Our inventories are valued at the lower of cost or market with cost determined using the LIFO methodology, under which the most recently incurred costs are charged to cost of sales and inventories are valued at base layer acquisition costs. Market price is determined based on an assessment of the current estimated replacement cost and net realizable selling price of the inventory. When the market price of our inventory declines substantially, cost values of inventory may exceed market values. In such instances, we record an adjustment to write down the value of inventory to market value in accordance with GAAP. In subsequent periods, the value of inventory is reassessed and an LCM inventory adjustment is recorded to reflect the net change in the LCM inventory reserve between periods. The net impact of these LCM inventory adjustments is included in the Refining segment’s income from operations, but excluded from the operating results presented, as applicable, to ensure comparability between periods.

PBF Energy LCM inventory adjustment - During the year ended December 31, 2025, we recorded an adjustment to value our inventories to the LCM which decreased income from operations and net income by $313.0 million and $231.6 million, respectively. There were no such adjustments in any of the other periods presented.

SBR LCM inventory adjustment - During the years ended December 31, 2025, December 31, 2024, and December 31, 2023, SBR recorded adjustments to the LCM reserve, which impacted its income from operations by $20.8 million, $37.7 million, $(77.4) million, respectively. Our Equity loss in investee includes our 50% share of these adjustments. For the years ended December 31, 2025, December 31, 2024, and December 31, 2023, these LCM adjustments impacted our income from operations by $10.4 million, $18.9 million, and $(38.7) million, respectively ($7.7 million, $14.0 million, and $(28.6) million, respectively, net of tax).

LIFO inventory decrement - During the year ended December 31, 2025, we recorded a pre-tax charge to cost of products and other related to a LIFO inventory layer decrement, primarily associated with the Martinez refinery. These charges decreased income from operations and net income by $5.4 million and $4.0 million, respectively. During the year ended December 31, 2024, we recorded a pre-tax charge to cost of products and other related to a LIFO inventory layer decrement, with the majority related to our East Coast and Gulf Coast LIFO inventory layers. These charges decreased income from operations and net income by $124.5 million and $92.1 million, respectively. Decrements recorded in the year ended December 31, 2023 were de minimis.

Martinez refinery fire expenses - During the year ended December 31, 2025, we recorded operating expenses associated with the Martinez refinery fire that decreased income from operations and net income by $163.7 million and $121.1 million, respectively. There were no such costs in any of the other periods presented.

Gain on insurance recoveries, net - During the year ended December 31, 2025, we recorded a gain on insurance recoveries associated with the Martinez refinery fire that increased income from operations and net income by $832.5 million and $616.1 million, respectively. There were no such gains in any of the other periods presented.

Costs related to RBI initiative - During the year ended December 31, 2025, we launched our RBI initiative as part of our ongoing strategic efforts to extract incremental value across our business. As a result, we recorded expenses related to the execution of this initiative that decreased income from operations and net income by $29.6 million and $21.9 million, respectively. These charges are included within General and administrative expenses. There were no such charges in any of the other periods presented.

Gain on sale of terminal assets - During the year ended December 31, 2025, we recorded a gain on the sale of our terminal assets, through a subsidiary of PBFX, which increased income from operations and net income by $94.0 million and $69.6 million, respectively. There were no such gains during any of the other periods presented.

Change in fair value of contingent consideration, net - The Martinez Contingent Consideration final earn-out payment of $18.8 million was paid in full during the second quarter of 2024. During the year ended December 31, 2024, we recorded a net change in fair value of the Martinez Contingent Consideration, which increased income from operations and net income by $3.3 million and $2.4 million, respectively. During the year ended December 31, 2023, we recorded a net change in fair value of the Martinez Contingent Consideration, which increased income from operations and net income by $45.8 million and $33.9 million, respectively.

Loss (gain) on formation of SBR equity method investment - During the year ended December 31, 2024, we recorded a reduction of our gain associated with the formation of the SBR equity method investment, which decreased income from operations and net income by $8.7 million and $6.4 million, respectively. During the year ended December 31, 2023, we recorded a net gain resulting from the difference between the carrying value and the fair value of the assets associated with the business contributed to SBR, which increased income from operations and net income by $925.1 million and $684.6 million, respectively. There were no such gains or losses in 2025.

Loss on extinguishment of debt and termination of Inventory Intermediation Agreement - During the year ended December 31, 2023, we recorded a pre-tax loss on extinguishment of debt related to the redemption of our 2025 Senior Notes and the amendment and restatement of the Revolving Credit Facility, which decreased income before income taxes and net income by $5.7 million and $4.2 million, respectively. There were no such losses in any of the other periods presented.

During the year ended December 31, 2023, in conjunction with the early termination of the Inventory Intermediation Agreement, we incurred certain one-time exit costs, which decreased income before income taxes and net income by $13.5 million and $10.0 million, respectively. These costs are included within Interest expense, net, in our Consolidated Statements of Operations.

Gain on land sales - During the year ended December 31, 2023, we recorded a gain on the sale of a separate parcel of real property acquired as part of the Torrance refinery, but not part of the refinery itself, which increased income from operations and net income by $1.7 million and $1.3 million, respectively. There were no such gains in any of the other periods presented.

Change in Tax Receivable Agreement liability - During the year ended December 31, 2025, there was no change in the Tax Receivable Agreement liability. During the year ended December 31, 2024, there was no change in the Tax Receivable Agreement liability. During the year ended December 31, 2023, PBF Energy recorded a change in the Tax Receivable Agreement liability that increased income before taxes and net income by $2.0 million and $1.5 million, respectively. The changes in the Tax Receivable Agreement liability reflect charges or benefits attributable to changes in PBF Energy’s obligation under the Tax Receivable Agreement due to factors out of our control such as changes in tax rates, as well as periodic adjustments to our liability based, in part, on an updated estimate of the amounts that we expect to pay, using assumptions consistent with those used in our concurrent estimate of the deferred tax asset valuation allowance.

Recomputed income tax on special items - The income tax impact on these special items, other than the net tax benefit special item discussed above, is calculated using the tax rates shown in (2) above.

(4) Represents an adjustment to weighted-average diluted shares outstanding to assume the full exchange of existing PBF LLC Series A Units as described in (1) above.

(5) Represents weighted-average diluted shares outstanding assuming the conversion of all common stock equivalents, including options and warrants for PBF LLC Series A Units and performance share units and options for shares of PBF Energy Class A common stock as calculated under the treasury stock method (to the extent the impact of such exchange would not be anti-dilutive) for the years ended December 31, 2025, 2024 and 2023, respectively. Common stock equivalents exclude the effects of performance share units and options and warrants to purchase 6,771,051, 4,413,417 and 18,431 shares of PBF Energy Class A common stock and PBF LLC Series A Units because they are anti-dilutive for the years ended December 31, 2025, 2024 and 2023, respectively. For periods showing a net loss, all common stock equivalents and unvested restricted stock are considered anti-dilutive.

(6) Total Equity excluding special items is calculated in the table below:


	December 31,		December 31,
(in millions)	2025		2024
Total equity	$	5,449.9	$	5,678.6
Special Items (Note 4)
Add: LCM inventory adjustments	$	313.0	$	—
Add: LCM inventory adjustment - SBR	(10.4)		—
Add: LIFO inventory decrement	5.4		—
Add: Martinez refinery fire expenses	163.7		—
Add: Gain on insurance recoveries, net	(832.5)		—
Add: Costs related to RBI initiative	29.6		—
Add: Gain on sale of terminal assets	(94.0)		—
Add: Cumulative historical equity adjustments (a)	(1,328.1)		(1,328.1)
Less: Recomputed income tax on special items	446.9		336.3
Net impact of special items to equity	(1,306.4)		(991.8)
Total equity excluding special items	$	4,143.5	$	4,686.8

(a) All prior year special items are reflected on an aggregate basis within “Cumulative historical equity adjustments” before recomputed income tax effect. Refer to the Company’s 2024 Annual Report on Form 10-K (“Notes to Non-GAAP Financial Measures” within Management’s Discussion and Analysis of Financial Condition and Results of Operations) for a listing of special items included in cumulative historical equity adjustments prior to 2025.

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are our cash flows from operations, cash and cash equivalents and borrowing availability under our credit facility, as described below. We believe that our cash flows from operations and available capital resources will be sufficient to meet our and our subsidiaries’ capital expenditures, working capital needs, dividend payments, debt service requirements, share repurchases under our share repurchase program, and PBF Energy’s obligations under the Tax Receivable Agreement, for the next twelve months. However, our ability to generate sufficient cash flow from operations depends, in part, on petroleum oil market pricing and general economic, political and other factors beyond our control. As of December 31, 2025, we are in compliance with all covenants, including financial covenants, in all our debt agreements.

Cash Flow Analysis

Cash Flows from Operating Activities

Net cash used in operating activities was $78.0 million for the year ended December 31, 2025 compared to net cash provided by operating activities of $43.4 million for the year ended December 31, 2024. Our operating cash flows for the year ended December 31, 2025 included our net loss of $160.5 million. This amount reflects a gain on insurance recoveries of $832.5 million, which was net of the $61.0 million receivable that was recorded at March 31, 2025. Of the $893.5 million in insurance proceeds received during the year ended December 31, 2025, $360.6 million relates to operating activities. In addition, operating cash flows include net changes in operating assets and liabilities reflecting uses of cash of $404.2 million, primarily driven by the timing of inventory purchases and payments made under the Tax Receivable Agreement, gain on sale of assets of $93.1 million, and deferred income taxes of $77.9 million, partially offset by depreciation and amortization of $662.8 million, non-cash LCM inventory adjustment of $313.0 million, loss from equity method investment of $62.2 million, pension and other post-retirement benefit costs of $52.6 million, and stock-based compensation of $39.0 million.

Our operating cash flows for the year ended December 31, 2024 included depreciation and amortization of $643.0 million, pension and other post-retirement benefit costs of $51.9 million, loss from equity method investment of $47.4 million, stock-based compensation of $44.3 million, loss on formation of the SBR equity method investment of $8.7 million, and loss on sale of assets of $0.4 million, partially offset by our net loss of $540.2 million, deferred income taxes of $239.2 million, and a net change in the fair value of the Martinez Contingent Consideration of $3.3 million. In addition, net changes in operating assets and liabilities reflected cash proceeds of $30.4 million driven by the timing of inventory purchases and collections of accounts receivable.

Net cash provided by operating activities was $43.4 million for the year ended December 31, 2024 compared to net cash provided by operating activities of $1,338.5 million for the year ended December 31, 2023. Our operating cash flows for the year ended December 31, 2023 included our net income of $2,162.0 million, depreciation and amortization of $591.6 million, deferred income taxes of $537.0 million, stock-based compensation of $51.5 million, pension and other post-retirement benefit costs of $47.9 million, loss from equity method investment of $45.3 million and loss on extinguishment of debt primarily related to the redemption of our 2025 Senior Notes and the amendment and restatement of the Revolving Credit Facility of $5.7 million, partially offset by a gain on formation of the SBR equity method investment of $925.1 million, net change in the fair value of the Martinez Contingent Consideration of $45.8 million, change in the Tax Receivable Agreement liability of $2.0 million, gain on sale of assets of $1.3 million, and changes in the fair value of our catalyst obligations of $1.1 million. In addition, net changes in operating assets and liabilities reflected uses of cash of $1,127.2 million driven by inventory purchases and payments for accrued expenses. The change in accrued expenses was due primarily to a decrease in renewable energy credit and emissions obligations, as a result of a decrease in our unfunded RINs obligation.

Cash Flows from Investing Activities

Net cash used in investing activities was $480.2 million for the year ended December 31, 2025 compared to $1,041.5 million for the year ended December 31, 2024. The net cash flows used in investing activities for the year ended December 31, 2025 was comprised of capital expenditures totaling $705.2 million, expenditures for refinery turnarounds of $379.5 million, expenditures for other assets of $77.1 million and contributions to our equity method investee of $25.0 million, partially offset by insurance proceeds of $532.9 million, proceeds from the sale of assets of $170.3 million, and return of capital from our equity method investee of $3.4 million. Net cash used in investing activities for the year ended December 31, 2024 was comprised of expenditures for refinery turnarounds of $576.7 million, capital expenditures totaling $390.9 million, expenditures for other assets of $40.7 million, and contributions to our equity method investee of $35.0 million, partially offset by return of capital from our equity method investee of $1.8 million.

Net cash used in investing activities was $1,041.5 million for the year ended December 31, 2024 compared to $338.6 million for the year ended December 31, 2023. Net cash used in investing activities for the year ended December 31, 2023 was comprised of capital expenditures totaling $659.6 million, expenditures for refinery turnarounds of $473.5 million, expenditures for other assets of $40.5 million, contributions to our equity method investee of $15.4 million, partially offset by return of capital from our equity method investee of $846.0 million and proceeds from the sale of assets of $4.4 million.

Cash Flows from Financing Activities

Net cash provided by financing activities was $550.0 million for the year ended December 31, 2025 compared to net cash used in financing activities of $249.3 million for the year ended December 31, 2024. For the year ended December 31, 2025, net cash provided by financing activities consisted of $788.5 million from the issuance of the 2030 9.875% Senior Notes, proceeds from insurance premium financing, net of $9.0 million, and transactions made in connection with stock-based compensation plans of $2.9 million, partially offset by dividends and distributions of $126.5 million, net repayments of our Revolving Credit Facility of $100.0 million, deferred financing costs and other costs of $12.7 million, and payments on finance leases of $11.2 million. For the year ended December 31, 2024, net cash provided by financing activities consisted of share repurchases of PBF Energy’s Class A common stock of $329.1 million, dividends and distributions of $120.6 million, payments on finance leases of $12.2 million, payments of insurance premium financing, net of $11.3 million, and deferred financing costs and other costs of $0.1 million, partially offset by cash proceeds from the Revolving Credit Facility of $200.0 million, and transactions made in connection with stock-based compensation plans of $1.4 million.

Net cash used in financing activities was $249.3 million for the year ended December 31, 2024 compared to net cash used in financing activities of $1,420.0 million for the year ended December 31, 2023. For the year ended December 31, 2023, net cash used in financing activities consisted of the redemption of our 2025 Senior Notes of $666.2 million, share repurchases of PBF Energy’s Class A common stock of $532.5 million, redemption of the PBFX 2023 Senior Notes of $525.0 million, dividends and distributions of $111.1 million, payments related to the Martinez Contingent Consideration of $80.1 million, deferred financing costs and other costs of $35.8 million, payments on finance leases of $14.1 million, and settlement of the final precious metal catalyst obligation of $3.1 million, partially offset by cash proceeds of $496.6 million from the issuance of the 2030 7.875% Senior Notes, net of discount, transactions made in connection with stock-based compensation plans of $38.3 million, and proceeds from insurance premium financing of $13.0 million.

Capitalization

Our capital structure was comprised of the following as of December 31, 2025 (in millions):


	December 31, 2025
Debt: (1)
2028 6.00% Senior Notes	$	801.6
2030 9.875% Senior Notes	800.0
2030 7.875% Senior Notes	500.0
Revolving Credit Facility	100.0
Total debt	$	2,201.6




Unamortized deferred financing costs	(41.0)
Unamortized discount	(12.3)
Total debt, net of unamortized deferred financing costs and discount	$	2,148.3

Total Equity	5,449.9
Total Capitalization (2)	$	7,598.2

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(1) Refer to “Note 9 - Credit Facilities and Debt” of our Notes to Consolidated Financial Statements for further disclosure related to debt.

(2) Total Capitalization refers to the sum of debt plus total equity.

2025 Debt Related Transactions

Revolving Credit Facility Overview

One of our primary sources of liquidity is our available borrowing capacity under our Revolving Credit Facility. As of December 31, 2025, we had $527.9 million of cash and cash equivalents and an outstanding balance of $100.0 million under the Revolving Credit Facility.

We had available capacity under our Revolving Credit Facility as of December 31, 2025 (in millions) as follows:


	Total Commitment		Amount Borrowed as of December 31, 2025		Outstanding Letters of Credit		Borrowing Base Availability		Expiration Date
Revolving Credit Facility (a)	$	3,500.0	$	100.0	$	167.3	$	2,296.6	August 2028

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(a) The amount available for borrowings and letters of credit under the Revolving Credit Facility is calculated according to a “borrowing base” formula based on (i) 90% of the book value of Eligible Accounts with respect to investment grade obligors plus (ii) 85% of the book value of Eligible Accounts with respect to non-investment grade obligors plus (iii) 80% of the cost of Eligible Hydrocarbon Inventory plus (iv) 100% of Cash and Cash Equivalents in deposit accounts subject to a control agreement, in each case as defined in the Revolving Credit Agreement. The borrowing base is subject to customary reserves and eligibility criteria and in any event cannot exceed $3.5 billion.

Additional Information on Indebtedness

Our debt, including our Revolving Credit Facility and senior notes, include certain typical financial covenants and restrictions on our subsidiaries’ ability to, among other things, incur or guarantee new debt, engage in certain business activities including transactions with affiliates and asset sales, make investments or distributions, engage in mergers or pay dividends in certain circumstances. These covenants are subject to a number of important exceptions and qualifications. We are in compliance as of December 31, 2025 with all covenants, including financial covenants, in all of our debt agreements. For further discussion of our indebtedness and these covenants and restrictions, see “Note 9 - Credit Facilities and Debt” of our Notes to Consolidated Financial Statements.

Liquidity

As of December 31, 2025, our operational liquidity was approximately $2.3 billion (approximately $2.4 billion as of December 31, 2024), which consists of approximately $0.5 billion of cash, and more than $1.8 billion of borrowing availability under our Revolving Credit Facility, which includes our cash on hand.

We may incur additional indebtedness in the future, including secured indebtedness, subject to the satisfaction of any debt incurrence and, if applicable, lien incurrence limitation covenants in our existing financing agreements. Although we were in compliance with incurrence covenants during the year ended December 31, 2025, there are no assurances in the future that we will be able to meet these incurrence covenants at the time we are required to do so. Failure to meet the incurrence covenants could impose certain incremental restrictions on, among other matters, our ability to incur new debt (including secured debt) and also may limit the extent to which we may pay future dividends, make acquisitions or investments, repurchase our outstanding debt or stock or incur new liens.

Share Repurchases

Our Repurchase Program currently allows for share repurchases up to $1.75 billion and does not have an expiration date. To date, we have purchased approximately 24,113,897 shares of PBF Energy's Class A common stock under the Repurchase Program for $1,018.0 million, inclusive of commissions paid, through open market transactions. We may make additional share repurchases in the future, but we are not obligated to purchase any shares under the Repurchase Program, and repurchases could be suspended or discontinued at any time without prior notice.

Working Capital

Our working capital at December 31, 2025 was approximately $782.5 million, consisting of $4,451.8 million in total current assets and $3,669.3 million in total current liabilities. Our working capital at December 31, 2024 was $917.8 million, consisting of $4,543.9 million in total current assets and $3,626.1 million in total current liabilities.

Martinez Refinery Fire

During 2025, we received unallocated insurance proceeds totaling $893.5 million, net of deductibles and retentions. We expect to be able to negotiate future interim payments through final settlement of the claim. The timing and amount of any agreed future interim payments will be dependent on the quantum of actual, covered expenditures and calculated losses.

Sale of Terminal Assets

On September 30, 2025, through a subsidiary of PBFX, we closed on the sale of two of our non-core refined product terminal facilities located in Philadelphia, PA and Knoxville, TN for $175.4 million, excluding commissions and customary closing costs. The combined assets include 38 storage tanks with approximately 1.9 million barrels of storage capacity, and associated truck racks. The sale resulted in a gain of approximately $94.0 million in the year ended December 31, 2025, included within Gain on sale of assets in the Consolidated Statements of Operations.

Crude and Feedstock Supply Agreements

We currently purchase all of our crude and feedstock needs from various suppliers, primarily through short-term and spot market agreements.

Capital Spending

Capital spending was $628.9 million for the year ended December 31, 2025, net of $532.9 million in costs related to the rebuild of units damaged in the Martinez refinery fire. As of December 31, 2025, all of the fire-related rebuild costs had been reimbursed through insurance proceeds. The 2025 net capital spend primarily comprised of annual maintenance and turnaround costs at our East Coast, Mid-Continent, and West Coast refineries. Capital spending also included costs associated with safety related enhancements and facility improvements at our refineries and logistics assets. Excluding Martinez rebuild costs, we currently expect to spend an aggregate of approximately $850.0 million to $900.0 million in 2026 for facility improvements and refinery maintenance and turnarounds, as well as expenditures to meet environmental, regulatory and safety requirements.

Material Cash Requirements

Our material cash requirements include the following known contractual and other obligations as of December 31, 2025 that are expected to be paid within the next year and thereafter (in millions). The table below does not include any intercompany contractual obligations with PBFX as these related party transactions are eliminated upon consolidation of our financial statements.


	Payments Due by Period
	Short-Term		Long-Term		Total
Credit facilities and debt (a)	$	—	$	2,201.6	$	2,201.6
Interest payments on credit facilities and debt	186.2		539.0		725.2
Leases and other rental-related commitments (b)	387.3		1,791.0		2,178.3
Purchase obligations (c)	3,549.9		546.0		4,095.9
Construction obligations	220.1		—		220.1
Environmental obligations (d)	9.8		152.8		162.6
Pension and post-retirement obligations (e)	42.8		520.6		563.4
Tax Receivable Agreement obligation (f)	—		168.2		168.2
Total material cash requirements	$	4,396.1	$	5,919.2	$	10,315.3

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(a) Credit facilities and debt

Credit facilities and debt represent the repayment of indebtedness incurred in connection with the 2028 6.00% Senior Notes, the 2030 7.875% Senior Notes, the 2030 9.875% Senior Notes, and the Revolving Credit Facility; we have no debt maturing before 2028.

Refer to “Note 9 - Credit Facilities and Debt” of our Notes to Consolidated Financial Statements for further disclosure related to debt.

(b) Leases and other rental-related commitments

Operating and Finance lease obligations include options to extend terms that are reasonably certain of being exercised. We have entered into certain agreements for the supply of hydrogen that contain both lease and non-lease components. The table above also includes such non-lease components of these agreements. See “Note 12 - Leases” of our Notes to Consolidated Financial Statements for further details and disclosures regarding our operating and finance lease obligations.

We also enter into contractual obligations with third parties for the right to use property for locating pipelines and accessing certain of our assets (also referred to as land easements) in the normal course of business. Our obligations regarding such land easements are included within Leases and other rental-related commitments in the table above.

Purchase obligations include commitments to purchase crude oil from certain counterparties under supply agreements, contracts for the transportation of crude oil and supply of hydrogen, nitrogen, oxygen, chemicals, steam, or natural gas to certain of our refineries, contracts for the treatment of wastewater, contracts for pipeline capacity, and forward purchase commitments to acquire AB 32, RINs or LCFS credits from third parties.

(d) Environmental obligations

In connection with certain of our refinery and logistics acquisitions, we have assumed certain environmental remediation obligations to address matters that were outstanding at the time of such acquisitions. In addition, in connection with most of these acquisitions, we have purchased environmental insurance policies to insure against unknown environmental liabilities at each site. The obligations in the table above reflect our undiscounted best estimate in cost and tenure to remediate our outstanding obligations and are further discussed in “Note 11 - Commitments and Contingencies” of our Notes to Consolidated Financial Statements.

(e) Pension and post-retirement obligations

Pension and post-retirement obligations include only those amounts we expect to pay out in benefit payments and are further explained in “Note 16 - Employee Benefit Plans” of our Notes to Consolidated Financial Statements.

(f) Tax Receivable Agreement obligation

The table reflects PBF Energy’s estimated timing of payments under the Tax Receivable Agreement, assuming that we earn sufficient taxable income to realize all tax benefits that are subject to the Tax Receivable Agreement as of December 31, 2025. Refer to “Note 11 - Commitments and Contingencies” of our Notes to the Consolidated Financial statements for further discussion of the Tax Receivable Agreement.

Tax Distributions

PBF LLC is required to make periodic tax distributions to the members of PBF LLC, including PBF Energy, pro rata in accordance with their respective percentage interests for such period (as determined under the amended and restated limited liability company agreement of PBF LLC), subject to available cash and applicable law and contractual restrictions (including pursuant to our debt instruments) and based on certain assumptions. Generally, these tax distributions will be an amount equal to our estimate of the taxable income of PBF LLC for the year multiplied by an assumed tax rate equal to the highest effective marginal combined U.S. federal, state and local income tax rate prescribed for an individual or corporate resident in New York, New York (taking into account the nondeductibility of certain expenses). If, with respect to any given calendar year, the aggregate periodic tax distributions were less than the actual taxable income of PBF LLC multiplied by the assumed tax rate, PBF LLC will make a “true up” tax distribution, no later than March 15 of the following year, equal to such difference, subject to the available cash and borrowings of PBF LLC. As these distributions are conditional, they have been excluded from the table above.

Critical Accounting Policies

The following summary provides further information about our critical accounting policies that involve critical accounting estimates and should be read in conjunction with “Note 2 - Summary of Significant Accounting Policies” of our Notes to Consolidated Financial Statements. The following accounting policies involve estimates that are considered critical due to the level of subjectivity and judgment involved, as well as the impact on our financial position and results of operations. We believe that all of our estimates are reasonable. Unless otherwise noted, estimates of the sensitivity to earnings that would result from changes in the assumptions used in determining our estimates is not practicable due to the number of assumptions and contingencies involved, and the wide range of possible outcomes.

Environmental Matters

Liabilities for future clean-up costs are recorded when environmental assessments and/or clean-up efforts are probable, and the costs can be reasonably estimated. Other than for periodic assessments, the timing and magnitude of these accruals generally are based on the completion of investigations or other studies or a commitment to a formal plan of action. Environmental liabilities are based on best estimates of probable future costs using currently available technology and applying current regulations, as well as our own internal environmental policies. The actual settlement of our liability for environmental matters could materially differ from our estimates due to a number of uncertainties such as the extent of contamination, changes in environmental laws and regulations, potential improvements in remediation technologies and the participation of other responsible parties. While we believe that our current estimates of the amounts and timing of the costs related to the remediation of these liabilities are reasonable, it is possible that our estimates of the costs and duration of the environmental remediation activities related to these liabilities could materially change.

Impairment of Long-Lived Assets

We evaluate long-lived assets for impairment on a continual basis and reassess the reasonableness of their related useful lives whenever events or changes in circumstances warrant assessment. Possible triggering events may include, among other things, significant adverse changes in the business climate, market conditions, environmental regulations or a determination that it is more likely than not that an asset or an asset group will be sold or retired before its estimated useful life. These possible triggering events of impairment may impact our assumptions related to future throughput levels, future operating revenues, expenses and gross margin, levels of anticipated capital expenditures and remaining useful life. Long-lived assets are tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. A long-lived asset is not recoverable if its carrying amount exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. Cash flows for long-lived assets/asset groups are determined at the lowest level for which identifiable cash flows exist. The cash flows from the refinery asset groups are evaluated individually regardless of product mix or fuel type produced. If a long-lived asset is not recoverable, an impairment loss is recognized for the amount by which the carrying amount of the long-lived asset exceeds its fair value, with fair value determined based on discounted estimated net cash flows or other appropriate methods. Our assumptions incorporate inherent uncertainties that are at times difficult to predict and could result in impairment charges or accelerated depreciation in future periods if actual results materially differ from the estimated assumptions used.

Income Taxes and Tax Receivable Agreement

As a result of PBF Energy’s acquisition of PBF LLC Series A Units or exchanges of PBF LLC Series A Units for PBF Energy Class A common stock, it expects to benefit from amortization and other tax deductions reflecting the step up in tax basis in the acquired assets. Those deductions will be allocated to PBF Energy and will be taken into account in reporting its taxable income. As a result of a federal income tax election made by PBF LLC, applicable to a portion of PBF Energy’s acquisition of PBF LLC Series A Units, the income tax basis of the assets of PBF LLC, underlying a portion of the units PBF Energy acquired, has been adjusted based upon the amount that PBF Energy paid for that portion of its PBF LLC Series A Units. PBF Energy entered into the Tax Receivable Agreement which provides for the payment by PBF Energy equal to 85% of the amount of the benefits, if any, that it is deemed to realize as a result of (i) increases in tax basis and (ii) certain other tax benefits related to entering into the Tax Receivable Agreement, including tax benefits attributable to payments under the Tax Receivable Agreement. As a result of these transactions, PBF Energy’s tax basis in its share of PBF LLC’s assets will be higher than the book basis of these same assets. This resulted in a deferred tax asset of $141.8 million as of December 31, 2025.

Deferred taxes are calculated using a liability method, whereby deferred tax assets are recognized for deductible temporary differences and deferred tax liabilities are recognized for taxable temporary differences. Temporary differences represent the differences between reported amounts of assets and liabilities and their tax bases. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effect of changes in tax laws and rates on the date of enactment. We recognize tax benefits for uncertain tax positions only if it is more likely than not that the position is sustainable based on its technical merits. Interest and penalties on uncertain tax positions are included as a component of the provision for income taxes on the Consolidated Statements of Operations. The amount of the deferred tax assets considered realizable, however, could be adjusted if estimates of future taxable income are reduced or increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as our projections for future taxable income.

Pursuant to the Tax Receivable Agreement PBF Energy entered into at the time of its initial public offering, it is required to pay the current and former PBF LLC Series A unitholders, or their permitted assignees, who exchange their units for PBF Energy stock or whose units we purchase, approximately 85% of the cash savings in income taxes that PBF Energy is deemed to realize as a result of the increase in the tax basis of its interest in PBF LLC, including tax benefits attributable to payments made under the Tax Receivable Agreement. These payment obligations are of PBF Energy and not of PBF LLC or any of its subsidiaries. PBF Energy has recognized a liability for the Tax Receivable Agreement reflecting its estimate of the undiscounted amounts that it expects to pay under the agreement. PBF Energy’s estimate of the Tax Receivable Agreement liability is based, in part, on forecasts of future taxable income over the anticipated life of PBF Energy’s future business operations, assuming no material changes in the relevant tax law. The assumptions used in the forecasts are subject to substantial uncertainty about PBF Energy’s future business operations and the actual payments that it is required to make under the Tax Receivable Agreement could differ materially from its current estimates. PBF Energy must adjust the estimated Tax Receivable Agreement liability each time we purchase PBF LLC Series A Units or upon an exchange of PBF LLC Series A Units for PBF Energy Class A common stock. Such adjustments will be based on forecasts of future taxable income and PBF Energy’s future business operations at the time of such purchases or exchanges. Periodically, PBF Energy may adjust the liability based on an updated estimate of the amounts that it expects to pay, using assumptions consistent with those used in its concurrent estimate of the deferred tax asset valuation allowance. These periodic adjustments to the Tax Receivable Agreement liability, if any, are recorded in general and administrative expense and may result in adjustments to our income tax expense and deferred tax assets and liabilities.

Recent Accounting Pronouncements

Refer to “Note 2 - Summary of Significant Accounting Policies” of our Notes to Consolidated Financial Statements, for Recently Issued Accounting Pronouncements.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risks, including changes in commodity prices and interest rates. Our primary commodity price risk is associated with the difference between the prices we sell our refined products and the prices we pay for crude oil and other feedstocks. We may use derivative instruments to manage the risks from changes in the prices of crude oil and refined products, natural gas, interest rates, or to capture market opportunities.

Commodity Price Risk

Our earnings, cash flow and liquidity are significantly affected by a variety of factors beyond our control, including the supply of, and demand for, crude oil, other feedstocks, refined products, and natural gas. The supply of and demand for these commodities depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, planned and unplanned downtime in refineries, pipelines and production facilities, production levels, the availability of imports, the marketing of competitive and alternative fuels, and the extent of government regulation. As a result, the prices of these commodities can be volatile. Our revenues fluctuate significantly with movements in industry refined product prices, our cost of sales fluctuates significantly with movements in crude oil and feedstock prices and our operating expenses fluctuate with movements in the price of natural gas. We manage our exposure to these commodity price risks through our supply and offtake agreements as well as through the use of various commodity derivative instruments.

We may use non-trading derivative instruments to manage exposure to commodity price risks associated with the purchase or sale of crude oil and feedstocks, finished products and natural gas outside of our supply and offtake agreements. The derivative instruments we use include physical commodity contracts and exchange-traded and over-the-counter financial instruments. We mark-to-market our commodity derivative instruments and recognize the changes in their fair value in our statements of operations.

At December 31, 2025 and December 31, 2024, we had gross open commodity derivative contracts representing 9.9 million barrels and 18.6 million barrels, respectively, with an unrealized net gain of $10.4 million and net gain of $2.0 million, respectively. The open commodity derivative contracts as of December 31, 2025 expire at various times during 2026.

We carry inventories of crude oil, intermediates, and refined products (“hydrocarbon inventories”) on our Consolidated Balance Sheets, the values of which are subject to fluctuations in market prices. Our hydrocarbon inventories totaled approximately 34.0 million barrels and 30.2 million barrels at December 31, 2025 and December 31, 2024, respectively. The average cost of our hydrocarbon inventories was approximately $79.36 and $80.46 per barrel on a LIFO basis at December 31, 2025 and December 31, 2024, respectively. The December 31, 2025 results exclude the net impact of an LCM inventory adjustment of approximately $313.0 million, whereas at December 31, 2024, the replacement value of inventory exceeded the LIFO carrying value. If market prices of our inventory decline to a level below our average cost, we may be required to write down the carrying value of our hydrocarbon inventories to market.

Our predominant variable operating cost is energy, which is comprised primarily of natural gas and electricity. We are therefore sensitive to movements in natural gas prices. Assuming normal operating conditions, we expect our annual consumption to range from 70 million to 100 million MMBTUs of natural gas amongst our six refineries. Accordingly, a $1.00 per MMBTU change in natural gas prices would increase or decrease our natural gas costs by approximately $70.0 million to $100.0 million.

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Compliance Program Price Risk

We are exposed to market risks related to our obligations to buy, and the volatility in the price of, credits needed to comply with various governmental and regulatory compliance programs, which include RINs, required to comply with the RFS. Our overall RINs obligation is based on a percentage of our domestic shipments of on-road fuels as established by the EPA. To the degree we are unable to blend the required amount of biofuels to satisfy our RINs obligation, we must purchase RINs on the open market. To mitigate the impact of the market risk relating to our obligations on our results of operations and cash flows, we may elect to purchase RINs or other environmental credits as part of our liability management strategy. We also have the ability to purchase RINs directly from SBR.

In addition, we are exposed to risks associated with complying with federal and state legislative and regulatory measures to address GHG and other emissions. Requirements to reduce emissions could result in increased costs to operate and maintain our facilities as well as implement and manage new emission controls and programs put in place. Compliance with such emission standards may require the purchase of emission credits or similar instruments.

Certain of these compliance contracts or instruments qualify as derivative instruments. For certain of these contracts, we elect the normal purchase normal sale exception under ASC 815, Derivatives and Hedging, for such instruments, and therefore do not record these contracts at their fair value.

Interest Rate Risk

The maximum commitment under our Revolving Credit Facility is $3.5 billion. Borrowings under the Revolving Credit Facility bear interest either at the Alternative Base Rate plus the Applicable Margin or at the Term SOFR plus the Applicable Margin, all as defined in the Revolving Credit Agreement. At December 31, 2025, we had a $100.0 million outstanding balance in variable interest debt. If this facility were fully drawn, a 1.0% change in the interest rate would increase or decrease our interest expense by approximately $23.2 million annually.

Credit Risk

We are subject to risk of losses resulting from nonpayment or nonperformance by our counterparties. We continue to closely monitor the creditworthiness of customers to whom we grant credit and establish credit limits in accordance with our credit policy.

Concentration Risk

For the years ended December 31, 2025 and December 31, 2024, only one customer, Shell, accounted for 10% or more of our revenues (approximately 13% and 13%, respectively).

As of December 31, 2025 and December 31, 2024, only one customer, Shell, accounted for 10% or more of our total trade accounts receivable (approximately 14% and 18%, respectively).

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by this item is set forth beginning on page F-1 of this Annual Report on Form 10-K.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

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ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We conducted evaluations, under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, of the effectiveness of the disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 as amended (the “Exchange Act”)) as of the end of the period covered by this report. Based upon these evaluations as required by Exchange Act Rule 13a-15(b), the principal executive officer and principal financial officer concluded that the disclosure controls and procedures are effective.

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) of the Exchange Act. Our internal control system is 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 in the United States of America. Due to its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2025, using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework (2013). Based on such assessment, management concluded that as of December 31, 2025, our internal control over financial reporting is effective.

Auditor Attestation Report

Our independent registered public accounting firm has issued an attestation report on the effectiveness of our internal control over financial reporting, which is on page F-5 of this report.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the quarter ended December 31, 2025 that has materially affected, or is reasonably likely to materially affect our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

Securities Trading Plans of Directors and Executive Officers

During the three months ended December 31, 2025, none of our directors or executive officers adopted or terminated any contract, instruction or written plan for the purchase or sale of PBF Energy securities that was intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or any “non-Rule 10b5-1 trading arrangement”.

ITEM 9C. DISCLOSURES REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

103

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required under this Item will be contained in our 2026 Proxy Statement, incorporated herein by reference, except as provided below.

We have adopted a Code of Business Conduct and Ethics that applies to our principal executive officer, principal financial officer and principal accounting officer. The Code of Business Conduct and Ethics is available on our website at www.pbfenergy.com under the heading “Investors”. Any amendments to the Code of Business Conduct and Ethics or any grant of a waiver from the provisions of the Code of Business Conduct and Ethics requiring disclosure under applicable Securities and Exchange Commission rules will be disclosed on the Company’s website.

See also Information About Our Executive Officers under “Item 1. Business” of this Annual Report on Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION

The information required under this Item will be contained in our 2026 Proxy Statement, incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information required by this Item, including Securities Authorized for Issuance Under Equity Compensation Plans, will be contained in our 2026 Proxy Statement, incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required under this Item will be contained in our 2026 Proxy Statement, incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information about fees billed to us by our principal accountant, KPMG LLP (PCAOB ID No. 185) will be contained in our 2026 Proxy Statement, incorporated herein by reference.

104

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) 1. Financial Statements. The consolidated financial statements of PBF Energy Inc., and its subsidiaries, required by Part II, Item 8, are included in Part IV of this report. See Index to Consolidated Financial Statements beginning on page F-1.

2. Financial Statement Schedules and Other Financial Information. No financial statement schedules are submitted because either they are not applicable or because the required information is included in the consolidated financial statements or notes thereto.

3. Exhibits. Filed as part of this Annual Report on Form 10-K are the following exhibits:


Number						Description

3.1						Amended and Restated Certificate of Incorporation of PBF Energy Inc. (incorporated by reference to Exhibit 3.1 filed with PBF Energy Inc.’s Amendment No. 4 to Registration Statement on Form S-1 (Registration No. 333-177933)).

3.2						Second Amended and Restated Bylaws of PBF Energy Inc. (incorporated by reference to Exhibit 3.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated February 15, 2017 (File No. 001-35764)).

4.1						Indenture dated as of January 24, 2020, among PBF Holding Company LLC, PBF Finance Corporation, the Guarantors named on the signature pages thereto, Wilmington Trust, National Association, as Trustee and Deutsche Bank Trust Company Americas, as Paying Agent, Registrar, Transfer Agent and Authenticating Agent and form of 6.00% Senior Notes due 2028 (included as Exhibit A) (incorporated by reference to Exhibit 4.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated January 24, 2020 (File No. 001-35764)).

4.2						First Supplemental Indenture dated February 3, 2020, among PBF Holding Company LLC, PBF Finance Corporation, Martinez Refining Company LLC, Martinez Terminal Company LLC, Wilmington Trust, National Association, as trustee, and Deutsche Bank Trust Company Americas, as paying agent, transfer agent, registrar and authenticating agent (6.00% Senior Notes due 2028) (incorporated by reference to Exhibit 4.3 filed with PBF Energy Inc.’s Quarterly Report on Form 10-Q dated May 15, 2020 (File No. 001-35764)).

4.3						Indenture dated as of August 21, 2023, among PBF Holding Company LLC, PBF Finance Corporation, the Guarantors named on the signature pages thereto, Wilmington Trust, National Association, as Trustee, and Deutsche Bank Trust Company Americas, as Paying Agent, Registrar, Transfer Agent and Authenticating Agent and form of 7.875% Senior Note due 2030 (included as Exhibit A) (incorporated by reference to Exhibit 4.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated August 21, 2023 (File No. 001-35764)).
4.4						Indenture dated as of March 17, 2025, among PBF Holding Company LLC, PBF Finance Corporation, the Guarantors named on the signature pages thereto, Wilmington Trust, National Association, as Trustee, and Deutsche Bank Trust Company Americas, as Paying Agent, Registrar, Transfer Agent, and Authenticating Agent and form of 9.875% Senior Note due 2030 (included as Exhibit A) (incorporated by reference to Exhibits 4.1 and 4.2 of PBF Energy Inc.’s Current Report on Form 8-K dated March 17, 2025 (File No. 001-35764)).

4.5						Amended and Restated Registration Rights Agreement of PBF Energy Inc. dated as of December 12, 2012 (incorporated by reference to Exhibit 4.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated December 18, 2012 (File No. 001-35764)).

4.6						Description of Registrant’s Securities (incorporated by reference to Exhibit 4.18 of PBF Energy Inc’s Annual Report on Form 10-K (File No. 001-35764) filed on February 18, 2021).

10.1**						Form of PBF Energy Inc. Performance Share Unit Award Agreement (2024-2026 performance period) under the Amended and Restated PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 with PBF Energy Inc.’s Current Report on Form 8-K dated November 2, 2023 (File No. 001-35764)).

105

10.2**

Form of PBF Energy Inc. Performance Unit Award Agreement (2024-2026 performance period) under the Amended and Restated PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.2 with PBF Energy Inc.’s Current Report on Form 8-K dated November 2, 2023 (File No. 001-35764)).

10.3**

Form of PBF Energy Inc. Performance Share Unit Award Agreement (2025-2027 performance period) under the Amended and Restated PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 with PBF Energy Inc.’s Current Report on Form 8-K dated December 6, 2024 (File No. 001-35764)).

10.4**

Form of PBF Energy Inc. Performance Unit Award Agreement (2025-2027 performance period) under the Amended and Restated PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.2 with PBF Energy Inc.’s Current Report on Form 8-K dated December 6, 2024 (File No. 001-35764)).

10.5**

PBF Energy Inc. Amended and Restated 2012 Equity Incentive Plan (incorporated by reference to Appendix A to PBF Energy Inc.’s Definitive Proxy Statement on Schedule 14A filed on March 22, 2016 (File No. 001-35764)).

10.6**

PBF Energy Inc. Amended and Restated 2017 Equity Incentive Plan (incorporated by reference to Appendix A to PBF Energy Inc.’s Definitive Proxy Statement on Schedule 14A filed on April 13, 2018 (File No. 001-35764)).

10.7**

Amendment No. 1 to PBF Energy Inc. Amended and Restated 2017 Equity Incentive Plan (incorporated by reference to Appendix A to PBF Energy Inc.’s Definitive Proxy Statement on Schedule 14A filed on April 13, 2022 (File No. 001-35764)).

10.8**

Form of PBF Energy Non-Qualified Stock Option Agreement (prior to 2020) under the Amended and Restated PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated November 2, 2018 (File No. 001-35764)).

10.9**

Form of PBF Energy Non-Qualified Stock Option Agreement (2020 and thereafter) under the Amended and Restated PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated November 13, 2020 (File No. 001-35764)).

10.10**

Form of Non-Qualified Stock Option Agreement under the PBF Energy Inc. 2012 Equity Incentive Plan (incorporated by reference to Exhibit 10.28 filed with PBF Energy Inc.’s Amendment No. 6 to Registration Statement on Form S-1 (Registration No. 333-177933)).

10.11**

Form of Amended and Restated Restricted Stock Agreement for non-employee Directors under the PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.3 of PBF Energy Inc.’s Annual Report on Form 10-K (File No. 001-35764) filed on February 23, 2018).

10.1 2 **

Form of Amended and Restated Restricted Stock Agreement for Employees, under PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.7 of PBF Energy Inc.’s Annual Report on Form 10-K (File No. 001-35764) filed on February 23, 2018).

10.13

Form of PBF Energy Amended and Restated 2017 Equity Incentive Plan, as Amended Restricted Stock Agreement for Special Employees Retention Award (incorporated by reference to Exhibit 10.15 filed with PBF Energy Inc.’s Annual Report on Form 10-K dated February 13, 2025 (File No. 001-35764)).

10.14**

Form of PBF Energy Amended and Restated 2017 Equity Incentive Plan, as Amended Restricted Stock Agreement for Employees (incorporated by reference to Exhibit 10.2 of PBF Energy Inc.’s Current Report on Form 8-K dated February 15, 2023 (File No. 001-35764)).

10.15

Form of PBF Energy Amended and Restated 2017 Equity Incentive Plan, as Amended Restricted Stock Agreement for Employee (incorporated by reference to Exhibit 10.2 filed with PBF Energy Inc.’s Current Report on Form 8-K dated December 2, 2022 (File No. 001-35764)).

106

10.16**

Form of Restricted Stock Agreement for Executives under the PBF Energy Inc. 2025 Equity Incentive Plan (incorporated by reference to Exhibit 10.2 filed with PBF Energy Inc.’s Quarterly Report on Form 10-Q dated October 30, 2025 (File No. 001-35764)).

10.17

Form of Restricted Stock Agreement for Employee under the PBF Energy Inc. 2025 Equity Incentive Plan (incorporated by reference to Exhibit 10.3 filed with PBF Energy Inc.’s Quarterly Report on Form 10-Q dated October 30, 2025 (File No. 001-35764)).

10.18**

Form of Restricted Stock Agreement for Non-Employee Directors under the PBF Energy Inc. 2025 Equity Incentive Plan (incorporated by reference to Exhibit 10.4 filed with PBF Energy Inc.’s Quarterly Report on Form 10-Q dated October 30, 2025 (File No. 001-35764)).

10.19**

Form of 2025 Equity Incentive Plan Performance Share Unit Award Agreement for the 2026-2028 Performance Cycle (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated October 27, 2025 (File No. 001-35764)).

10.20**

Form of 2025 Equity Incentive Plan Performance Unit Award Agreement for the 2026-2028 Performance Cycle (incorporated by reference to Exhibit 10.2 filed with PBF Energy Inc.’s Current Report on Form 8-K dated October 27, 2025 (File No. 001-35764)).

10.21

Amended and Restated Limited Liability Agreement by and among St. Bernard Renewables LLC, PBF Green Fuels LLC and Eni Sustainable Mobility US, Inc., dated as of June 27, 2023. (incorporated by reference to Exhibit 10.2 filed with PBF Energy Inc.’s Current Report on Form 8-K dated June 28, 2023 (File No. 001-35764)).

10.22

Amended and Restated Senior Secured Revolving Credit Agreement, dated August 23, 2023 (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated August 23, 2023 (File No. 001-35764)).

10.23

Amended and Restated Limited Liability Company Agreement of PBF Energy Company LLC (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated December 18, 2012 (File No. 001-35764)).

10.24

Exchange Agreement, dated as of December 12, 2012 (incorporated by reference to Exhibit 10.3 filed with PBF Energy Inc.’s Current Report on Form 8-K dated December 18, 2012 (File No. 001-35764)).

10.25

Tax Receivable Agreement, dated as of December 12, 2012 (incorporated by reference to Exhibit 10.2 filed with PBF Energy Inc.’s Current Report on Form 8-K dated December 18, 2012 (File No. 001-35764)).

10.26

Form of Indemnification Agreement between PBF Energy Inc. and each of the executive officers and directors of PBF Energy Inc. (incorporated by reference to Exhibit 10.5 filed with PBF Energy Inc.’s Current Report on Form 8-K dated December 18, 2012 (File No. 001-35764)).

10.27**

Employment Agreement dated as of April 1, 2014 between PBF Investments LLC and Timothy Paul Davis (incorporated by reference to Exhibit 10.4 filed with PBF Energy Inc.’s Quarterly Report on Form 10-Q dated May 7, 2014 (File No. 001-35764)).

10.28**

Employment Agreement dated as of September 29, 2015 between PBF Investments LLC and Trecia M. Canty (incorporated by reference to Exhibit 10.36 filed with PBF Energy Inc.’s Annual Report on Form 10-K dated February 16, 2023 (File No. 001-35764)).

10.29**

Third Amended and Restated Employment Agreement, dated as of May 3, 2023, between PBF Investments LLC and Matthew C. Lucey (incorporated by reference to Exhibit 10.2 filed with PBF Energy Inc.’s Current Report on Form 8-K dated May 4, 2023 (File No. 001-35764)).

10.30**

Employment Agreement dated as of March 4, 2024 between PBF Investments LLC and Michael Bukowski (incorporated by reference to Exhibit 10.29 filed with PBF Energy Inc.’s Annual Report on Form 10-K dated February 13, 2025 (File No. 001-35764)).

10.31**

Employment Agreement dated as of August 18, 2025 between Joseph Marino and PBF Investments LLC (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated August 20, 2025 (File No. 001-35764)).

107

16.1

Letter from Deloitte & Touche LLP to Securities and Exchange Commission dated February 16, 2024 (incorporated by reference to Exhibit 16.1 file with PBF Energy Inc.’s Current Report on Form 8-K dated February 12, 2024 (File No. 001-35764)).

19.1

Insider Trading Policy of PBF Energy Inc. (incorporated by reference to Exhibit 19.1 filed with PBF Energy Inc.’s Annual Report on Form 10-K dated February 13, 2025 (File No. 001-35764)).

21.1*

Subsidiaries of PBF Energy.

23.1*

Consent of KPMG.

23.2*

Consent of Deloitte & Touche LLP.

24.1*

Power of Attorney (included on signature page).

31.1*

Certification by Chief Executive Officer of PBF Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*

Certification by Chief Financial Officer of PBF Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*(1)

Certification by Chief Executive Officer of PBF Energy Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2*(1)

Certification by Chief Financial Officer of PBF Energy Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

97.1

Clawback Policy, effective as of October 2, 2023 (incorporated by reference to Exhibit 97.1 filed with PBF Energy Inc.’s Annual Report on Form 10-K dated February 15, 2024 (File No. 001-35764)).

101.INS

Inline XBRL Instance Document.

101.SCH

Inline XBRL Taxonomy Extension Schema Document.

101.CAL

Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF

Inline XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB

Inline XBRL Taxonomy Extension Label Linkbase Document.

101.PRE

Inline XBRL Taxonomy Extension Presentation Linkbase Document.

104

Cover Page Interactive Data File (formatted as Inline XBRL and contained in exhibit 101).

——————————


*			Filed herewith.

**			Indicates management compensatory plan or arrangement.



(1)			This exhibit should not be deemed to be “filed” for purposes of Section 18 of the Exchange Act.

108

PBF ENERGY INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


Reports of Independent Registered Public Accounting Firms						F-2



Consolidated Balance Sheets as of December 31, 2025 and 2024						F-7

Consolidated Statements of Operations For the Years Ended December 31, 2025, 2024 and 2023						F-8

Consolidated Statements of Comprehensive Income (Loss) For the Years Ended December 31, 2025, 2024 and 2023						F-9

Consolidated Statements of Changes in Equity For the Years Ended December 31, 2025, 2024 and 2023						F-10

Consolidated Statements of Cash Flows For the Years Ended December 31, 2025, 2024 and 2023						F-12













Notes to Consolidated Financial Statements						F-13

F- 1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

PBF Energy Inc.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of PBF Energy Inc. and subsidiaries (the Company) as of December 31, 2025 and 2024, the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for each of the years in the two-year period ended December 31, 2025, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2025, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 12, 2026 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

F- 2

Evaluation of long-lived assets for impairment

As discussed in Notes 2 and 5 to the consolidated financial statements, the Company evaluates long-lived assets for impairment on a continual basis. Possible triggering events may include, among other things, significant adverse changes in the business climate, market conditions, environmental regulations or a determination that it is more likely than not that an asset or an asset group will be sold or retired before its estimated useful life. The primary asset groups within long-lived assets are the Company’s property, plant, and equipment, net for which the Company had recorded $5.5 billion on the consolidated balance sheet as of December 31, 2025.

We identified the evaluation of impairment triggering events related to the recoverability of property, plant and equipment as a critical audit matter. A high degree of subjective auditor judgment was required in evaluating the Company’s assessment of current operations, financial results, current industry and market conditions and relevant industry data for impairment indicators.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the Company’s process for identifying and assessing potential triggering events related to its property, plant, and equipment, net, including controls over the Company’s assessment of current operations, financial results, current industry and market conditions and relevant industry data. We evaluated the Company’s identification and assessment of triggering events by:

•analyzing the financial results for the current period compared to historical results, including consideration of current industry and market considerations

•comparing relevant industry data used by the Company to external sources, including consideration of current industry and market considerations

•evaluating the Company’s analysis over the factors and considering whether the Company omitted any significant internal or external elements in its evaluation.

/s/ KPMG LLP

We have served as the Company's auditor since 2024.

Short Hills, New Jersey

February 12, 2026

F- 3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

PBF Energy Inc.:

Opinion on Internal Control Over Financial Reporting

We have audited PBF Energy Inc. and subsidiaries' (the Company) internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2025 and 2024, the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for each of the years in the two-year period ended December 31, 2025, and the related notes (collectively, the consolidated financial statements), and our report dated February 12, 2026 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’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 Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

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

Definition and Limitations of Internal Control Over Financial Reporting

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

F- 4

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

/s/ KPMG LLP

Short Hills, New Jersey

February 12, 2026

F- 5

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of PBF Energy Inc. and subsidiaries

Opinion on the Financial Statements

We have audited the accompanying consolidated statements of operations, comprehensive income, changes in equity, and cash flows, for the period ended December 31, 2023, and the related notes (collectively referred to as the "financial statements") of PBF Energy Inc. and subsidiaries (the “Company”). In our opinion, the financial statements present fairly, in all material respects, the results of the Company’s operations and its cash flows for the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

Change in Accounting Principle

As discussed in Note 2 to the financial statements, the accompanying financial statements have been retrospectively adjusted for the adoption of Accounting Standard Update 2023-07, “Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures.”

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company 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 the financial statements are free of material misstatement, whether due to error or fraud. Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.

/s/ Deloitte & Touche LLP

Morristown, New Jersey

February 15, 2024 (February 13, 2025 as to Note 19)

We began serving as the Company’s auditor in 2011. In 2024 we became the predecessor auditor.

F- 6

PBF ENERGY INC.

CONSOLIDATED BALANCE SHEETS

(in millions, except share and per share data)


	December 31, 2025		December 31, 2024
ASSETS
Current assets:
Cash and cash equivalents	$	527.9	$	536.1
Accounts receivable	1,166.7		1,165.0
Inventories	2,563.1		2,595.3


Prepaid and other current assets	194.1		247.5
Total current assets	4,451.8		4,543.9
Property, plant and equipment (net of accumulated depreciation of $2,393.1 and $2,165.6, respectively)	5,517.8		5,067.7
Equity method investment in SBR	826.3		866.8

Lease right of use assets	759.7		845.3
Deferred charges and other assets, net	1,464.3		1,379.5
Total assets	$	13,019.9	$	12,703.2
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	801.2	$	735.6
Accrued expenses	2,662.9		2,533.5
Payable pursuant to Tax Receivable Agreement	—		125.4

Deferred revenue	20.8		43.8
Current operating lease liabilities	184.4		187.8

Total current liabilities	3,669.3		3,626.1

Long-term debt	2,148.3		1,457.3
Payable pursuant to Tax Receivable Agreement	168.2		168.2
Deferred tax liabilities	763.6		836.0
Long-term operating lease liabilities	543.0		622.2
Long-term financing lease liabilities	25.8		35.4
Other long-term liabilities	251.8		279.4
Total liabilities	7,570.0		7,024.6
Commitments and contingencies (Note 11)
Equity:
PBF Energy Inc. equity
Class A common stock, $0.001 par value, 1,000,000,000 shares authorized, 116,937,076 shares outstanding at December 31, 2025, 115,311,992 shares outstanding at December 31, 2024	0.1		0.1
Class B common stock, $0.001 par value, 1,000,000 shares authorized, 12 shares outstanding at December 31, 2025, 12 shares outstanding at December 31, 2024	—		—
Preferred stock, $0.001 par value, 100,000,000 shares authorized, no shares outstanding at December 31, 2025 and December 31, 2024	—		—
Treasury stock, at cost, 32,042,692 shares outstanding at December 31, 2025 and 31,479,723 shares outstanding at December 31, 2024	(1,237.6)		(1,222.8)
Additional paid in capital	3,397.3		3,338.7
Retained earnings	3,149.9		3,436.2

Accumulated other comprehensive income (loss)	9.8		(8.0)
Total PBF Energy Inc. equity	5,319.5		5,544.2
Noncontrolling interest	130.4		134.4
Total equity	5,449.9		5,678.6
Total liabilities and equity	$	13,019.9	$	12,703.2

See notes to consolidated financial statements.

F- 7

PBF ENERGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except share and per share data)


	Year Ended December 31,
	2025		2024		2023
Revenues	$	29,332.3	$	33,115.3	$	38,324.8
Cost and expenses:
Cost of products and other	26,627.0		30,266.7		32,671.3
Operating expenses (excluding depreciation and amortization expense as reflected below)	2,646.0		2,606.2		2,694.9
Depreciation and amortization expense	630.3		614.6		560.0
Cost of sales	29,903.3		33,487.5		35,926.2
General and administrative expenses (excluding depreciation and amortization expense as reflected below)	332.3		260.4		362.5
Depreciation and amortization expense	14.4		13.2		11.5
Gain on insurance recoveries, net	(832.5)		—		—
Change in fair value of contingent consideration, net	—		(3.3)		(45.8)
Equity loss in investee	62.2		47.4		45.3
Loss (gain) on formation of SBR equity method investment	—		8.7		(925.1)

(Gain) loss on sale of assets	(93.1)		0.4		(1.3)
Total cost and expenses	29,386.6		33,814.3		35,373.3
Income (loss) from operations	(54.3)		(699.0)		2,951.5
Other income (expense):
Interest expense (net of interest income of $24.3, $51.2, and $75.0, respectively)	(181.6)		(72.0)		(63.8)
Change in Tax Receivable Agreement liability	—		—		2.0
Change in fair value of catalyst obligations	—		—		1.1
Loss on extinguishment of debt	—		—		(5.7)
Other non-service components of net periodic benefit cost	1.3		2.4		0.7
Income (loss) before income taxes	(234.6)		(768.6)		2,885.8
Income tax (benefit) expense	(74.1)		(228.4)		723.8
Net income (loss)	(160.5)		(540.2)		2,162.0
Less: net income (loss) attributable to noncontrolling interests	(2.0)		(6.4)		21.5
Net income (loss) attributable to PBF Energy Inc. stockholders	$	(158.5)	$	(533.8)	$	2,140.5

Weighted-average shares of Class A common stock outstanding
Basic	114,052,733		116,248,827		124,953,858
Diluted	114,915,513		117,111,607		130,509,448
Net income (loss) available to Class A common stock per share:
Basic	$	(1.39)	$	(4.59)	$	17.13
Diluted	$	(1.39)	$	(4.60)	$	16.52

See notes to consolidated financial statements.

F- 8

PBF ENERGY INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in millions)


	Year Ended December 31,
	2025		2024		2023
Net income (loss)	$	(160.5)	$	(540.2)	$	2,162.0
Other comprehensive income (loss):
Unrealized gain (loss) on available for sale securities	1.3		(0.3)		(0.4)
Net gain (loss) on pension and other post-retirement benefits	16.5		4.6		(10.4)
Total other comprehensive income (loss)	17.8

PBF Energy Inc. 10-K