PBF 10-K & 10-Q changes, risk factors and insider trading

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

•EnhancedContinued scrutiny on ESGsustainability matters;

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

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 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. At December 31, 2024 and December 31, 2023, the replacement value of inventories exceeded the LIFO carrying value, therefore no LCM inventory reserve was recorded. 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.

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.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.

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/WCSWCS, differential,Mars/Brent, whichand is a proxy for the difference betweenother light U.S. and heavy Canadian crude oil,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 continuedsanctions resolutionsagainst oil exporting countries and decisions by the Organization of the Petroleum Exporting Countries to restrict crude oil production levels and executive actions by the new 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.

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, a fire occurred at our Martinez refinery during preliminary turnaround activities, which resulted in the temporary shutdown of refinery operations. The cause of the fire is currently under investigation. We are assessing the extent of the property damage arising from the fire and potential recoveries from insurance coverage are also being evaluated. At this time, as the cost of repairs, the length of the shutdown and other potential liabilities, including regulatory penalties, arising from the incident are unknown, the operational and/or financial impact cannot be reasonably estimated.

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. We are assessing the extent of the property damage arising from the recent Martinez refinery fire and potential recoveries from insurance coverage are also being evaluated. At this time, as the cost of repairs, the length of the shutdown and other potential liabilities, including regulatory penalties, arising from the incident are unknown, the operational and/or financial impact cannot be reasonably estimated. In the event the Martinez refinery is forced to shut down for a significant period of time, it could have a material adverse effect on our earnings, our other results of operations and our financial condition as a whole.

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

Our Toledo, Chalmette, Torrance and MartinezTorrance 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 Pablo Bay Pipeline, San Ardo and Coastal Pipeline systems for supplying crude to our Torrance and Martinez refineries.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.

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 infrastructuresinfrastructures, 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.

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 $515.3$680.1 million in RINs costs during the year ended December 31, 20242025 as compared to $762.3$515.3 million and $1,225.5$762.3 million during the years ended December 31, 20232024 and 2022,2023, respectively. The fluctuations in our RINs costs are due primarily to volatility in prices for ethanol-linked RINs and increases in our production of on-road transportation fuels since 2012.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 ifas the volumes finalized by EPA differcontinues fromto whatadjust hasthe beenvolume proposed.requirements and potentially enacts further changes to the program.

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 Bay Area Air Quality Management District (“BAAQMD”)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.

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 will likelymay continue to receive scientific and political attention, with the potential for further laws and regulations that could materially adversely affect our ongoing operations.

Regulation of emissions of greenhouse gasesGHGs 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.

BothThe U.S. federal government under previous presidential administrations took a number of actions to address GHG emissions. For example, both houses of Congress have 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.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. TheseHowever, the current U.S. presidential administration has expressed a different approach with respect to U.S. climate, environmental, and similarenergy regulationspolicies couldand 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 usaction toby incurthe costsU.S. to monitor and report GHG emissionsCongress or reducea emissionsfederal ofagency GHGsor associated with our operations. In addition, various states, individuallydepartment, as well as inpending someor casesfuture onlitigation, aare regionalcurrently basis,unknown haveand takenare stepssubject to controlconsiderable GHG emissions, including adoption of GHG reporting requirements, cap and trade systems and renewable portfolio standards (such as AB 32). On September 23, 2020 the Governor of California issued an executive order effectively banning the sale of new gasoline-powered passenger cars and trucks by 2035 and requiring zero-emission medium to heavy duty vehicles by 2045 everywhere feasible. The executive order requires state agencies to build out sufficient electric vehicle charging infrastructure.uncertainty. It is notalso possiblecurrently atuncertain thiswhether timeand to predictwhat extent any U.S. state and local governments may still pursue the ultimateprior form,administration’s timing or extent of federal or state regulation. In the event we do incur increased costs as a result of increased efforts to control GHG emissions, we may not be able to passagenda on anysuch of these costs to our customers. 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.matters.

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. For example,Also, in September 2016, the stateState of California enacted Senate Bill 32, which further reduces greenhouse gasGHG emissions targets to 40 percent below 1990 levels by 2030. Two regulations implemented to achieve these goals are Cap-and-Trade and the LCFS.Low Carbon Fuel Standard (“LCFS”). In 2012, CARB implemented Cap-and-Trade. This program currently places a cap on GHGsGHG 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.

As noted above,Additionally, on September 23, 2020, the California Governor issued Executive Order N-79-20 (“N-79-20 Order”) intended to further reduce GHGsGHG 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. As to the 2045 goal, it is currently uncertain how the N-79-20 Order may be ultimately implemented by various California regulatory agencies. 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.

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

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 gross gasoline refining margin,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 gross gasoline refining marginGGRM and (ii) the timing of refinery turnarounds and maintenance. Consequently, the CEC adopted an order requiring an informational proceeding on a maximum gross gasoline refining marginGGRM 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.

To the extent that the CEC in the future establishes a maximum gross gasoline refining marginGGRM and imposes a financial penalty for profits above such maximum gross gasoline refining margin,GGRM, inventory requirements, or timing of turnaround schedulesschedules, 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 recently adopted 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.

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.

Further, our business interruption insurance may not compensate us adequately for losses that may occur. We do not carry insurance specifically for cybersecurity eventsinsurance; however,with certain of our insurance policies may allowallowing for potential coverage for a cyber-event resulting in ensuinginsured property damage resulting from ana otherwisecyber-security insuredevent peril.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.

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

EnhancedContinued scrutiny on ESGsustainability 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 ESGsustainability 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 ESGsustainability 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 costscost 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.

CurrentInflationary inflationpressures withinhave thecontributed economy has resulted into increased interest rates and capital costs, contributed to supply shortages,chain disruptions, increased the cost of living and labor, and other related items. AsAlthough ainflation resulthas offluctuated, inflation,inflationary whichpressures may continue,persist or re-emerge, including due to tariffs and other trade measures that may be imposed byor the new U.S. presidential administration,enacted, we expect to potentially continue to encounterexperience 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, ifthere thesecan be no assurance that such actions arewill notbe effectiveeffective, itand sustained or renewed inflationary pressures could have a material adverse effect on our business, results of operations and financial condition. Additionally, higher futureinflation, inflationelevated interest rates, or concerns of aan economic slowdown or recession could impact the demand for our products and services.

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 conflictsactions and social upheavals is highly unpredictable, these warsconflicts 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 UK,United Kingdom, the EU,European Union, Canada and others, such as the United States ban on import of Russian oil effective March 8, 2022 and the EUEuropean 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.

We are subject to the requirements of the 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.

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.

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 parta 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 consideringexploring 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.

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.performance and make meaningful period to period comparisons more difficult.

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, ESGsustainability 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.

The 6.0%6.00% senior unsecured notes due 2028 (the “2028 6.00% Senior Notes”) and, 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 Ba3B1 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.

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 NotesNotes, 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.

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.

PBF Energy has recognized, as of December 31, 2024,2025, a total liability for the Tax Receivable Agreement of $293.6$168.2 million, of which $125.4 million is recorded as a current liability and was paid in January 2025 related to the 2023 tax year.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.

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.

•supply, demand, pricesprices, 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 byor the new presidential administration,enacted, and its impact on supply and demand, pricing, and supply chain disruption;

•the impact of current and future laws, rulingsrulings, 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;

•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 ABxAB 2-1,X2-1 and Senate Bill X1-2, or from actions taken by environmental interest groups;

•our expectations and timing with respect to ourany acquisitionacquisitions and investment activityactivities 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;

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

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

There were $100.0 million and $200.0 million outstanding borrowings under the Revolving Credit Facility as of December 31, 2024.2025 There were no outstanding borrowings as ofand December 31, 2023.2024, respectively.

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. During the year ended December 31, 2022, we settled certain of our precious metals financing arrangements, resulting in reductions of debt of approximately $56.2 million.

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.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 December 12, 2022, ourOur Board of Directors has authorized the Repurchase Program. As further approved on February 13, 2024, theThe Repurchase Program currently allows for share repurchases of up to $1.75 billion and hasdoes anot programhave an expiration datedate. During the year ended December 31, 2025, we did not purchase any shares of DecemberPBF 2025.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. During the year ended December 31, 2022, we purchased 4,192,555 shares of PBF Energy's Class A common stock for $156.4 million, inclusive of commissions paid, through open market transactions.

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, 2024,2025, a liability for the Tax Receivable Agreement of $293.6$168.2 million was recorded ($336.6$293.6 million and $338.6$336.6 million as of December 31, 20232024 and December 31, 2022,2023, respectively) reflecting our estimate of the undiscounted amounts that we expect to pay under the agreement. As of December 31, 2024, $125.4 million of the Tax Receivable Agreement obligation was recorded as a Current liability and represents the amount paid in January 2025 related to the 2023 tax year. 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.

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.credit when deemed necessary.

Currently, crude oil delivered by rail ismay 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.

The following section includes refinery-specific information related to our operations,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 35%39% distillate, 37% gasoline, 36% distillate, 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, 18% black oil and 5%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.

•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.

•the Chalmette refinery hascrude 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.

•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 cokecoke, 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.

•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.

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 compared to net income of $2,162.0 million for the year ended December 31, 2023.2024. 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) compared to net income attributable to PBF Energy stockholders of $2,140.5 million, or $16.52 per diluted share, for the year ended December 31, 2023 ($16.52 per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income, or $11.32 per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income 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, 20242025 and 2023.2024.

Excluding the impact of these special items, when comparing our results tofor the year ended December 31, 2023,2025 we experiencedreflected an overall decreaseincrease in our refining margins duecompared to unfavorablethe same period in 2024. This improvement was primarily driven by favorable movements in crack spreadsspreads, andpartially offset by lower crude oil differentialsdifferentials, as well as lower throughput volumes and barrels sold at the majority of our refineries. In addition, the plannedtemporary andshutdown unplanned maintenance experienced at our West Coast refineries duringof the fourthMartinez quarterrefinery of 2023 extended intofollowing the first half of 2024. These decreasing metrics combined with the timing of our maintenance activities havefire negatively impacted ourresults revenues,due grossto margin,lower and operatingsub-optimal incomerefinery yields for most of the year. Higher interest expense resulting from increased debt balances also weighed on earnings in comparison to the prior year.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 compared to $38.3 billion for the year ended December 31, 2023,2024, a decrease of approximately $5.2$3.8 billion or 13.6%.11.5%. Revenues per barrel sold were $90.47$82.02 and $100.85$90.47 for the years ended December 31, 20242025 and 2023,2024, respectively, a decrease of 10.3%9.3% directly related to lower hydrocarbon commodity prices.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, 2023,2025, the total throughputbarrels ratessold at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 327,600344,000 bpd, 136,400155,800 bpd, 174,200167,500 bpd and 271,200312,700 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. For the year ended December 31, 2023, the total barrels sold at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 373,700 bpd, 148,700 bpd, 187,300 bpd and 340,800 bpd, respectively.

Overall average throughput rates at our refineries were slightly lower in the year ended December 31, 20242025 primarily due to increasedunplanned maintenancedowntime activityat andour lowerWest demandCoast refineries when compared to the same period in 2023.2024. 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, compared to $2,398.6 million for the year ended December 31, 2023, a decrease of $2,770.8$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, 20242024, compareda todecrease $5,287.7of approximately $140.1 million. Gross refining margin excluding special items totaled $2,665.9 million, or $16.07$8.77 per barrel of throughput, for the year ended December 31, 2023,2025 acompared decrease of approximately $2,800.1 million. Gross refining margin excluding special items totaledto $2,612.1 million, or $7.89 per barrel of throughput, for the year ended December 31, 2024 compared to $5,287.7 million, or $16.07 per barrel of throughput, for the year ended December 31, 2023, a decrease of $2,675.6 million. Consolidated gross margin and gross refining margin decreased due to unfavorable movements in crack spreads and crude oil differentials at the majority of our refineries.2024.

Average industry margins were unfavorablefavorable during the year ended December 31, 20242025 in comparison to the prior year, primarily due to decreasedincreased refining margins as a result of unfavorablefavorable movements in crack spreads and crude oil differentials at the majorityall of our refineries.refineries offset by narrowing crude differentials, particularly between light and heavy crude grades.

On the East Coast, the Dated Brent (NYH) 2-1-1 industry crack spread was approximately $18.24$22.59 per barrel, or 38.5%23.8% lower,higher, in the year ended December 31, 2024,2025, as compared to $29.67$18.24 per barrel in the same period in 2023.2024. Our margins were positivelynegatively impacted from our refinery specific slate on the East Coast by strengthenedweakened WTI/Bakkenlight-heavy differential,crude whichspreads increased by $2.67 per barrel, offset by weakenedincluding Dated Brent/Maya differential,and Dated Brent/ASCI differentials, which decreased by $1.40$3.00 and $1.11 per barrelbarrel, respectively, compared to the same period in 2023.2024. Additionally, the WTI/WCS differential decreased to $12.17 per barrel in 2025 compared to $14.82 per barrel in 2024 compared to $18.32 per barrel in 2023,2024, which unfavorably impacted our cost of heavy Canadian crude.

Across the Mid-Continent, the WTI (Chicago) 4-3-1 industry crack spread was $16.27$18.31 per barrel, or 31.4%12.5% lower,higher, in the year ended December 31, 2024,2025, as compared to $23.71$16.27 per barrel in the prior year. Our margins were positivelynegatively impacted from our refinery specific slate in the Mid-Continent by ana increasingdecreasing WTI/Bakken differential, which averaged a discount of $1.39$1.21 per barrel in the year ended December 31, 2024,2025, as compared to a premiumdiscount of $1.28$1.39 per barrel in the prior year. Additionally,However, the WTI/Syncrude differential averaged a discount of $0.75$0.97 per barrel for the year ended December 31, 20242025 as compared to a premiumdiscount of $0.91$0.75 per barrel in the prior year.

On the Gulf Coast, the LLS (Gulf Coast) 2-1-1 industry crack spread was $18.21$21.76 per barrel, or 37.5%19.5% lower,higher, in the year ended December 31, 20242025 as compared to $29.13$18.21 per barrel in the prior year. Margins on the Gulf Coast were positivelynegatively impacted from our refinery specific slate by a strengtheningnarrowing WTIlight-heavy crude spreads including Dated Brent/LLS differential,WTS, which averaged a premiumdiscount of $2.45$4.34 per barrel for the year ended December 31, 20242025 as compared to a premiumdiscount of $2.48$4.85 per barrel in the prior year.

On the West Coast, the ANS (West Coast) 4-3-1 industry crack spread was $23.36$27.52 per barrel, or 36.7%17.8% lower,higher, in the year ended December 31, 20242025 as compared to $36.88$23.36 per barrel in the prior year. Additionally, the ANS (West Coast) 3-2-1 industry crack spread was $24.62$30.14 per barrel, or 33.3%22.4% lower,higher, in the year ended December 31, 20242025 as compared to $36.89$24.62 per barrel in the prior year. Our margins on the West Coast were positivelynegatively impacted from our refinery specific slate by a strengtheningweakening crude spreads including WTI/ANSWCS differential, which averaged a premium of $4.36$12.17 per barrel for the year ended December 31, 20242025 as compared to a premium of $4.70$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, 20242024, comparedan to $2,694.9 million for the year ended December 31, 2023, a decreaseincrease of approximately $88.7$39.8 million, or 3.3%.1.5%. Of the total $2,606.2$2,646.0 million in operating expenses, $2,487.8$2,547.0 million, or $7.52$8.38 per barrel of throughput, related to expenses incurred by the Refining segment, while the remaining $118.4$99.0 million related to expenses incurred by the Logistics segment ($2,581.3$2,487.8 million or $7.85$7.52 per barrel of throughput, and $113.6$118.4 million of operating expenses for the year ended December 31, 20232024 related to the Refining and Logistics segments, respectively). The decreaseincrease in operating expenses in comparison to the same period in 2024 was mainly attributable to lowerhigher maintenance andexpenses lowerat energyour costsMartinez refinery due to athe decreaseMartinez inrefinery overallfire, naturalpartially gasoffset pricesby lower outside services, including lower legal expenses, as well as realized RBI cost savings mainly attributable to reduced energy, utilities, and electricity.maintenance costs.

As of MarchJune 31,30, 2026, PBF Energy owned 118,317,756118,537,421 PBF LLC Series C Units and our current and former executive officers and directors and certain employees and others held 860,839 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 our issued and outstanding shares of our PBF Energy Class A common stock have approximately 99.3% of the voting power in us, and the members of PBF LLC other than PBF Energy through their holdings of Class B common stock have approximately 0.7% of the voting power in us (99.3% and 0.7% as of December 31, 2025, respectively).

On February 1, 2025, the Martinez refinery fire occurred. As a result of the Martinez refinery fire, the Martinez refinery was fully shut down until April 2025, when certain unaffected units, including the crude unit, were restarted and the Martinez 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,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”), and the Environmental Protection Agency (“EPA”). 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.

We expect that the cost of repairs to the fire-damaged units and restoring the Martinez refinery to full operational status will be largely 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.

Following the full restart of the Martinez refinery, it has achieved planned operating rates. 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 the three and six months ended MarchJune 31,30, 2026, we received $106.5$250.0 million and $356.5 million, respectively, of unallocated insurance proceeds. Since the date of the Martinez refinery fire, we have received cumulative insurance proceeds, net of deductibles and retentions, of $1.0$1.25 billion.

On February 1, 2025, theThe Martinez refinery fire occurred.occurred on February 1, 2025. As a result, the Martinez refinery was fully shut down until April 2025, when certain unaffected units, including the crude unit, were restarted and the Martinez refinery began producing limited quantities of gasoline, jet fuel, and intermediates, while the remaining units remained offline. During the second quarter in 2026, assets were transferred to refinery operations for commissioning and restart. All units affected by the Martinez refinery fire have returned to operational status and are running at planned rates. Investigations by various regulatory agencies are ongoing. Consequently, throughput volumes at the Martinez refinery in 2026 were significantly above 2025 levels.

During the three and six months ended MarchJune 31,30, 2026, we received $106.5$250.0 million and $356.5 million of unallocated insurance proceeds, respectively, which were recognized as a Gain on insurance recoveries inon the Condensed Consolidated Statements of Operations. During the three and six months ended June 30, 2025, we received an unallocated installment of $250.0 million after deductibles and retentions. As a result, we recorded a Gain on insurance recoveries of $189.0 million on the Condensed Consolidated Statements of Operations, which was net of the $61.0 million receivable that was recorded at March 31, 2025.

In addition, during the three and six months ended MarchJune 31,30, 2026 and 2025,2026, we recordedincurred operating expenses associated with the Martinez refinery fire of approximately $11.5$22.7 million and $78.1$34.2 million, respectively.respectively (compared to $30.4 million and $108.5 million, respectively, during the three and six months ended June 30, 2025).

On MarchMay 17,28, 2025,2026, we issued $800.0$500.0 million in aggregate principal amount of 9.875%7.25% senior unsecured notes due 20302034 (the “20302034 9.875%7.25% Senior Notes”). The netNet proceeds from the offering waswere approximately $776.0$492.1 million after deducting the initial purchasers’ discount and offering expenses. We used the net proceeds,proceeds from the offering and available cash to repayfully outstandingredeem borrowingsthe under6.00% PBFsenior Holding’sunsecured asset-basednotes revolvingdue credit facility2028 (the “Revolving2028 Credit6.00% FacilitySenior Notes”), plus accrued and forunpaid general corporate purposes.interest.

The Revolving Credit Facility matures in August 2028 and has a maximum commitment of $3.5 billion, as stated in the amended and restated asset-based revolving credit agreement (the “Revolving Credit Agreement”). We may borrow or repay outstanding amounts on the Revolving Credit Facility from time to time depending on working capital or other cash flow needs of the business. There were $750.00 million and $100.00 millionno outstanding borrowings under the Revolving Credit Facility as of MarchJune 31,30, 20262026, andcompared with $100.0 million as of December 31, 2025, respectively.2025.

As of both MarchJune 31,30, 2026 and December 31, 2025, PBF Energy recognized a liability for the Tax Receivable Agreement of $168.2 million, reflecting the estimate of the undiscounted amounts that we expected 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. In January 2025, we made payments under the Tax Receivable Agreement related to the 2023 tax year totaling $130.8 million, inclusive of $5.4 million of interest.

The tables below reflect our consolidated financial and operating highlights for the three and six months ended MarchJune 31,30, 2026 and 2025 (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,refineries are all engaged in the refining of crude oil and other feedstocks into petroleum products, andand, excluding the assets operated by PBFX, 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.

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.

Three Months Ended MarchJune 31,30, 2026 Compared to the Three Months Ended MarchJune 31,30, 2025

Overview— PBF Energy net income was $200.2$915.0 million for the three months ended MarchJune 31,30, 2026 compared to net loss of $405.9$5.4 million for the three months ended MarchJune 31,30, 2025. Net income attributable to PBF Energy stockholders was $198.3$906.4 million, or $1.65$7.54 per diluted share, for the three months ended MarchJune 31,30, 20262026, ($1.65$7.54 per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income, or $(0.88)$6.22 per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net lossincome excluding special items, as described below in Non-GAAP Financial Measures), compared to net loss attributable to PBF Energy stockholders of $401.8$5.2 million, or $(3.530.05) per diluted share, for the three months ended MarchJune 31,30, 2025 ($(3.530.05) per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net loss, or $(3.091.03) 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 benefitexpense (expensebenefit). PBF Energy’s weighted-average equity interest in PBF LLC was 99.3% for both the three months ended MarchJune 31,30, 2026 and 2025.

Excluding the impact of special items, our results for the three months ended MarchJune 31,30, 2026 reflect an overall increase in refining margins compared to the same period in 2025. The refining margins increase was primarily driven by favorable crack spreads and certain crude oil differentials, as well as higher throughput volumes and increased barrels sold across the majority of our refineries, partially offset by higher RFS compliance costs and interest expenses.costs. Ongoing geopolitical conflicts affecting global supply and trade flows also contributed to these improvements.dynamic market conditions.

Revenues— Revenues totaled $7.9$11.7 billion for the three months ended MarchJune 31,30, 2026 compared to $7.1$7.5 billion for the three months ended MarchJune 31,30, 2025, an increase of approximately $0.8$4.2 billion, or 11.3%.56.0%. Revenues per barrel were $92.88$127.39 and $88.33$81.30 for the three months ended MarchJune 31,30, 2026 and 2025, respectively, an increase of 5.2%56.7% directly related to higher hydrocarbon commodity prices and sale volumes.prices. For the three months ended MarchJune 31,30, 2026, the total throughput rates at our East Coast, Mid-Continent, Gulf Coast, and West Coast refineries averaged approximately 304,400309,100 bpd, 144,000130,900 bpd, 185,100177,400 bpd, and 210,700269,900 bpd, respectively. For the three months ended MarchJune 31,30, 2025, the total throughput rates at our East Coast, Mid-Continent, Gulf Coast, and West Coast refineries averaged approximately 262,200299,800 bpd, 137,400162,200 bpd, 157,800173,600 bpd and 173,000203,500 bpd, respectively. For the three months ended MarchJune 31,30, 2026, the total barrels sold at our East Coast, Mid-Continent, Gulf Coast, and West Coast refineries averaged approximately 332,200346,300 bpd, 154,200145,800 bpd, 168,600163,700 bpd, and 280,200351,500 bpd, respectively. For the three months ended MarchJune 31,30, 2025, the total barrels sold at our East Coast, Mid-Continent, Gulf Coast, and West Coast refineries averaged approximately 300,300348,800 bpd, 143,000166,600 bpd, 154,000169,700 bpd and 291,600325,300 bpd, respectively. 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.

Overall average throughput rates at our refineries were higher for the three months ended MarchJune 31,30, 2026, primarily due to the restart of the Martinez refinery, partially offset by unplanned downtime at our Mid-Continent refinery. In the prior-year period, increased maintenance activity and unplanned downtime relatedresulting tofrom the Martinez refinery fire negatively impacted throughput. We plan to continue operating our refineries in line with demand and prevailing 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 $278.5$1,146.8 million for the three months ended MarchJune 31,30, 2026,2026 compared to $(420.258.0) million for the three months ended MarchJune 31,30, 2025, an increase of approximately $698.7$1,204.8 million. Gross refining margin totaled $1,036.9$1,889.4 million, or $13.65$23.40 per barrel of throughput for the three months ended MarchJune 31,30, 2026 compared to $391.7$640.1 million, or $5.96$8.38 per barrel of throughput for the three months ended MarchJune 31,30, 2025, an increase of approximately $645.2$1,249.3 million. Gross refining margin excluding special items totaled $723.9 million, or $9.53 per barrel of throughput for the three months ended March 31, 2026. During the three months ended MarchJune 31,30, 2026 and 2025, our refining margin calculations were not impacted by special items.

Additionally, our results continue to be impacted by significant costs to comply with the RFS. On March 27, 2026, the EPA finalized new RFS requirements for 2026 and 2027, which included a partial reallocation of small refinery exemptions that were granted for years 2023 to 2025 and revised renewable fuel volume requirements for 2026. Total RFS compliance costs were $278.0$331.3 million for the three months ended MarchJune 31,30, 2026 compared to $120.0$165.0 million for the three months ended MarchJune 31,30, 2025. The increase was primarily attributable to the newly finalized RFS requirements for 2026 and 2027, which has resulted in addition to higher RIN prices in 2026 compared to 2025.

Average industry margins were notably more favorable during the three months ended MarchJune 31,30, 2026 in comparison to the same period in 2025, primarily due to geopolitical impactsconflicts onnegatively impacting supply andwith demand dynamics.remaining relatively resilient.

On the East Coast, the Dated Brent (NYH) 2-1-1 industry crack spread was approximately $26.48$43.48 per barrel, or 56.8%95.5% higher, in the three months ended MarchJune 31,30, 2026, as compared to $16.89$22.24 per barrel in the same period in 2025. Our margins were positively impacted from our refinery specific slate on the East Coast by strengtheneda widening Dated Brent/Maya and WTI/WCS differentialsdifferential, which increased by $3.75 and $2.33$6.86 per barrel, respectively,slightly offset by a weakened WTI/Bakken differential, which decreased by $0.33 per barrel, in comparison to the same period in 2025. The WTI/WCS differential widened to $20.25 per barrel in the three months ended June 30, 2026 compared to $10.65 in the same period in 2025, which favorably impacted our cost of heavy crudes.crude.

Across the Mid-Continent, the WTI (Chicago) 4-3-1 industry crack spread was $19.39$44.62 per barrel, or 41.2%110.9% higher, in the three months ended MarchJune 31,30, 2026 as compared to $13.73$21.16 per barrel in the same period in 2025. Our margins were negatively impacted from our refinery specific slate in the Mid-Continent by a weakened WTI/Syncrude differential,and WTI/Bakken differentials, which decreased by $1.56$1.90 and $0.33 per barrel, respectively, in comparison to the same period in 2025.

On the Gulf Coast, the LLS (Gulf Coast) 2-1-1 industry crack spread was $29.95$48.66 per barrel, or 73.4%140.2% higher, in the three months ended MarchJune 31,30, 2026 as compared to $17.27$20.26 per barrel in the same period in 2025. Margins on the Gulf Coast were positively impacted from our refinery specific slate by aan strengthenedexpanded WTIDated Brent/WTS differential, which averaged a discount of 10.21$13.04 per barrel for the three months ended MarchJune 31,30, 2026 as compared to a discount of 3.86$4.03 per barrel in the same period of 2025.

On the West Coast, the ANS (West Coast - LA) 4-3-1 industry crack spread was $36.65$53.28 per barrel, or 58.7%84.7% higher, in the three months ended MarchJune 31,30, 2026 as compared to $23.09$28.85 per barrel in the same period in 2025. Additionally, the ANS (West Coast - SF) 3-2-1 industry crack spread was $40.92$58.27 per barrel, or 60.2%61.5% higher, in the three months ended MarchJune 31,30, 2026 as compared to $25.55$36.07 per barrel in the same period in 2025. Our margins on the West Coast were negatively impacted from our refinery specific slate by a weakened WTI/ANS differential, which averaged a premium of $4.82$9.93 per barrel for the three months ended MarchJune 31,30, 2026 as compared to a premium of $4.37$5.01 per barrel in the same period of 2025, slightly offset by an expanded Dated Brent/WTS differential, which averaged a discount of $13.04 per barrel for the three months ended June 30, 2026 as compared to a discount of $4.03 per barrel in the same period of 2025.

Operating expenses— Operating expenses totaled $688.9$670.1 million for the three months ended MarchJune 31,30, 2026 compared to $731.8$631.7 million for the three months ended MarchJune 31,30, 2025, aan decreaseincrease of approximately $42.9$38.4 million, or 5.9%.6.1%. Of the total $688.9$670.1 million inof operating expenses,expenses $661.2for millionthe three months ended June 30, 2026, $646.0 million, or $8.70$8.00 per barrel of throughput, related to expenses incurred by the Refining segment, while the remaining $27.7$24.1 million related to expenses incurred by the Logistics segment ($706.3$607.5 millionmillion, or $10.74$7.96 per barrel of throughput,barrel, and $25.5$24.2 million of operating expenses for the three months ended MarchJune 31,30, 2025 related to the Refining and Logistics segments, respectively). The decreaseincrease in operating expenses in comparison to the same period in 2025 was mainly attributable to lowerhigher maintenanceoutside expensesservices atas ourwell Martinezas refineryhigher relatedmaintenance, tocatalysts, and chemical costs driven by the Martinez refinery fire, partially offset by higher outside services.restart.

General and administrative expenses— General and administrative expenses totaled $89.6$148.6 million for the three months ended MarchJune 31,30, 2026 compared to $70.4$80.3 million for the three months ended MarchJune 31,30, 2025, an increase of approximately $19.2$68.3 millionmillion, or 27.3%.85.1%. The increase in general and administrative expenses in comparison to the same period in 2025 was primarily due to higher legalemployee-related costsexpenses, including the recognition of incentive compensation, and costsoutside incurredservices, inincluding connectionhigher withlegal the RBI initiative.costs. General and administrative expenses are comprised of personnel, facilities, and other infrastructure costs necessary to support our refineries and related logistics assets.

Depreciation and amortization expense— Depreciation and amortization expense totaled $158.8$163.1 million for the three months ended MarchJune 31,30, 2026 (including $155.0$159.5 million recorded within Cost of sales), compared to $171.3$161.5 million for the three months ended MarchJune 31,30, 2025 (including $167.7$157.9 million recorded within Cost of sales), representing aan decreaseincrease of approximately $12.5$1.6 million. The decreaseincrease was primarily attributable to certain catalyst and turnaround costs that became fully amortized in 2025, partially offset by an increase in the fixed asset base resulting from capital projects and turnarounds completed since the firstsecond quarter of 2025.

Gain on insurance recoveries, net— ThereFor wasthe athree gainmonths ended June 30, 2026 and 2025, we recognized gains on insurance recoveries of $106.5 million, associated with the Martinez refinery fire forof the$250.0 threemillion monthsand ended$189.0 Marchmillion, 31, 2026. There were no such gains for the three months ended March 31, 2025.respectively.

Equity (gainincome) loss in investee— ThereFor wasthe three months ended June 30, 2026 and 2025, we recognized a gain of $8.3$27.5 million and a loss of $17.0$4.3 million for the three months ended March 31, 2026 and 2025,million, respectively, related to our equity share of our investment in SBR.

Loss(Gain) loss on sale of assets— There was a loss of $0.3 million forFor the three months ended MarchJune 31,30, 20262025, we recognized a gain of $0.2 million, primarily related to the sale of non-operating refinery assets. There werewas no such lossesgain for the three months ended MarchJune 31,30, 2025.2026.

Interest expense, net— Interest expense, net totaled $42.1$42.0 million for the three months ended MarchJune 31,30, 20262026, compared to $36.9$53.8 million for the three months ended MarchJune 31,30, 2025, ana increasedecrease of approximately $5.2$11.8 million. The net increasedecrease was primarily attributable to higherlower interest costexpense associatedresulting withfrom the issuance of the 2030 9.875% Senior Notes in March 2025 and higherlower average outstanding borrowings under our Revolving Credit Facility,Facility partially offset byand increased capitalized interest related to the Martinez refinery rebuild.rebuild, Forpartially offset by increased interest expense from the issuance of the 2034 7.25% Senior Notes in May 2026 prior to the redemption of the 2028 6.00% Senior Notes in June 2026. Additionally, interest income increased by $3.9 million during the three months ended MarchJune 31,30, 2026, driven by higher interest rates and higher cash deposits compared with the same period in the prior year. Interest expense for the three months ended June 30, 2026 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 expense (benefit)— 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,Refining L.L.C. (“Chalmette Refining”) and our Canadian subsidiary, PBF Energy Limited,Limited (“PBF Ltd.”) 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 Condensed Consolidated Financial Statements based on PBF Energy’s allocable share of PBF LLC’s pre-tax income or loss, which was approximately 99.3%99.3%, on a weighted-average basis for both the three months ended MarchJune 31,30, 2026 and 2025. PBF Energy’s Condensed 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 or PBFX (although, as described above, PBF LLC must make tax distributions to all its members on a pro-rata basis). PBF Energy’s effective tax rate, excluding the impact of noncontrolling interest, for the three months ended MarchJune 31,30, 2026 and 2025 was 22.7%25.7% and 26.1%,49.5%, respectively. For the three months ended MarchJune 31,30, 2026, PBF Energy’s effective tax rate differswas relatively consistent with the United States statutory rate. For the three months ended June 30, 2025, PBF Energy’s effective tax rate differed from the United States statutory rate, inclusive of state income taxestaxes, primarily due to additionalthe impact of certain permanent tax benefitdifference asitems ahad resulton ofthe equity-basedpretax compensationloss activity.for the quarter.

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, 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 Condensed 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 and by the third-party stockholders of certain of Chalmette Refining’s subsidiaries. The total noncontrolling interest on the Condensed 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 three months ended MarchJune 31,30, 2026 and 2025 was approximately 0.7%. The carrying amount of the noncontrolling interest on our Condensed 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.