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PBF Energy Inc. (PBF)

CIK: 0001534504. SIC: 2911 Petroleum Refining. Latest 10-K as of: 2026-02-12.

SIC breadcrumb: Manufacturing > Petroleum Refining And Related Industries > SIC 2911 Petroleum Refining

SEC company page: https://www.sec.gov/edgar/browse/?CIK=1534504. Latest filing source: 0001534504-26-000010.

Selected Fundamentals

MetricValueUnitFYFiled
Revenue29,332,300,000USD20252026-02-12
Net income-158,500,000USD20252026-02-12
Assets13,019,900,000USD20252026-02-12

Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-12. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001534504.json. Derived margins are computed from the extracted annual SEC facts.

Flow metrics use full-year FY periods from 10-K/10-K/A filings; balance-sheet metrics use FY-end instants. Missing metrics are omitted rather than fabricated.

Metric2016201720182019202020212022202320242025
Revenue21,786,600,00027,186,100,00024,508,200,00015,115,900,00027,253,400,00046,830,300,00038,324,800,00033,115,300,00029,332,300,000
Net income170,811,000415,600,000128,300,000319,400,000-1,392,400,000231,000,0002,876,800,0002,140,500,000-533,800,000-158,500,000
Operating income499,463,000731,600,000358,100,000649,000,000-1,416,800,000597,200,0004,153,200,0002,951,500,000-699,000,000-54,300,000
Diluted EPS1.743.731.102.64-11.641.9022.8416.52-4.60-1.39
Assets7,621,927,0008,117,993,0008,005,400,0009,132,400,00010,499,800,00011,641,400,00013,549,100,00014,387,800,00012,703,200,00013,019,900,000
Liabilities5,051,243,0005,215,044,0004,756,900,0005,546,900,0008,297,500,0009,108,600,0008,493,100,0007,756,500,0007,024,600,0007,570,000,000
Stockholders' equity2,025,044,0002,336,654,0002,676,500,0003,039,600,0001,642,800,0001,926,200,0004,929,200,0006,488,300,0005,544,200,0005,319,500,000
Cash and cash equivalents746,300,000573,000,000597,300,000814,900,0001,609,500,0001,341,500,0002,203,600,0001,783,500,000536,100,000527,900,000
Net margin1.91%0.47%1.30%-9.21%0.85%6.14%5.59%-1.61%-0.54%
Operating margin3.36%1.32%2.65%-9.37%2.19%8.87%7.70%-2.11%-0.19%

Financial Charts

Quarterly

Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-04-30. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001534504.json.

Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived.

QuarterEnd DateRevenueNet IncomeDiluted EPSMethod
2022-Q22022-06-309.65reported discrete quarter
2022-Q32022-09-308.40reported discrete quarter
2023-Q12023-03-312.86reported discrete quarter
2023-Q22023-06-309,157,600,0001,020,400,0007.88reported discrete quarter
2023-Q32023-09-3010,733,500,000786,400,0006.11reported discrete quarter
2023-Q42023-12-319,138,700,000-48,400,000derived Q4 = FY annual - nine-month YTD
2024-Q12024-03-318,645,600,000106,600,0000.86reported discrete quarter
2024-Q22024-06-308,736,100,000-65,200,000-0.56reported discrete quarter
2024-Q32024-09-308,382,300,000-285,900,000-2.49reported discrete quarter
2024-Q42024-12-317,351,300,000-289,300,000derived Q4 = FY annual - nine-month YTD
2025-Q12025-03-317,066,400,000-401,800,000-3.53reported discrete quarter
2025-Q22025-06-307,475,300,000-5,200,000-0.05reported discrete quarter
2025-Q32025-09-307,651,100,000170,100,0001.45reported discrete quarter
2025-Q42025-12-317,139,500,00078,400,000derived Q4 = FY annual - nine-month YTD
2026-Q12026-03-317,904,300,000198,300,0001.65reported discrete quarter

Quarterly Charts

Macro Cross-References

Latest quarter (10-Q)

Latest 10-Q source: 0001534504-26-000018.

Extracted between Part I Item 2 and the next Item 3/4 or Part II heading after HTML sanitization. Confidence: high. Filing date: 2026-04-30. Report date: 2026-03-31.

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the audited financial statements of PBF Energy included in the Annual Report on Form 10-K for the year ended December 31, 2025 and the unaudited financial statements and related notes included in this report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements as a result of a number of factors. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. Please see “Cautionary Note Regarding Forward-Looking Statements.”

Unless the context indicates otherwise, the terms “we,” “us,” and “our” refer to PBF Energy and its consolidated subsidiaries, including PBF LLC, PBF Holding and its subsidiaries and PBFX and its subsidiaries, and our 50% interest in SBR. 

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Overview

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

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

Refinery

Region

Nelson Complexity Index (1)

Throughput Capacity (in bpd) (1)

PADD

Crude Processed (2)

Source (2)

Delaware City

East Coast

13.6

180,000

1

light sweet through heavy sour

water, rail

Paulsboro

East Coast

9.1 (3)

155,000 (3)

1

light sweet through heavy sour

water

Toledo

Mid-Continent

11.0

180,000

2

light sweet

pipeline, truck, rail

Chalmette

Gulf Coast

13.0

185,000

3

light sweet through heavy sour

water, pipeline

Torrance

West Coast

13.8

166,000

5

medium and heavy

pipeline, water, truck

Martinez

West Coast

16.1

157,000

5

medium and heavy

water

_____________________

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

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

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

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As of March 31, 2026, PBF Energy owned 118,317,756 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).

Recent Developments

Martinez Refinery Fire

On February 1, 2025, the Martinez refinery fire occurred. As a result of the Martinez refinery fire, the refinery was fully shut down until April 2025, when certain unaffected units, including the crude unit, were restarted and the refinery began producing limited quantities of gasoline, jet fuel, and intermediates. Investigations are being conducted by various regulatory agencies, including the California Department of Industrial Relations, the Division of Occupational Safety and Health (“CalOSHA”), the Bay Area Air District (“BAAD”), Contra Costa County (“CCC”), the Department of Justice (“DOJ”), the United States Attorney’s Office (“USAO”), 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.

Following completion of the construction activities in February, assets were transferred to Refinery Operations for commissioning and restart. The startup process extended beyond previous expectations due to the volume of safety and process checks required to ensure successful restoration of full operations. The Alkylation unit and Cat Feed Hydrotreater were successfully restarted and are producing finished products and intermediates required for the sequential startup of downstream units. The Fluid Catalytic Cracking unit is now in the restart process and expected to be producing finished products in early May.

We expect that the cost of repairs to the fire-damaged units and restoring the 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 months ended March 31, 2026, we received $106.5 million of unallocated insurance proceeds. Since the date of the fire, we have received cumulative insurance proceeds, net of deductibles and retentions, of $1.0 billion.

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Factors Affecting Comparability Between Periods

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

Martinez Refinery Fire

On February 1, 2025, the Martinez refinery fire occurred. As a result, the refinery was fully shut down until April 2025, when certain unaffected units, including the crude unit, were restarted and the refinery began producing limited quantities of gasoline, jet fuel, and intermediates, while the remaining units remained offline. Investigations by various regulatory agencies are ongoing. Consequently, throughput volumes at the Martinez refinery in 2026 were significantly above 2025 levels.

During the three months ended March 31, 2026, we received $106.5 million of unallocated insurance proceeds, which were recognized as a Gain on insurance recoveries in the Condensed Consolidated Statements of Operations.

In addition, during the three months ended March 31, 2026 and 2025, we recorded operating expenses associated with the Martinez refinery fire of approximately $11.5 million and $78.1 million, respectively.

Costs Related to RBI Initiative

During the second quarter of 2025, we launched our RBI initiative as part of our ongoing strategic efforts to extract incremental value across our business. For the three months ended March 31, 2026, we recorded $9.4 million in expenses related to this initiative. These charges are reflected in General and administrative expenses on the Condensed Consolidated Statements of Operations.

Geopolitical Conflicts

Recent hostilities involving the United States, Israel, and Iran have disrupted global energy markets and trade flows, contributing to increased volatility in crude oil and refined product prices. Actions affecting regional shipping routes, including through the Strait of Hormuz, and impacts to certain Middle Eastern energy infrastructure have led to higher freight costs, longer transit times and supply chain disruptions. These conditions have supported higher global refining margins and increased demand for U.S. refined products during the period, while also resulting in higher and more volatile crude oil prices, increased feedstock costs and elevated working capital requirements. The net impact on our results of operations has varied based on the timing and magnitude of changes in crude oil prices and refined product margins. The extent to which these conditions will continue remains uncertain and dependent on future developments, including the duration and scope of the conflict, potential further disruptions to supply or transit routes and the response of global markets. We continue to monitor the situation and adjust our operations as appropriate.

Debt and Credit Facilities

Senior Notes

On March 17, 2025, we issued $800.0 million in aggregate principal amount of 9.875% senior unsecured notes due 2030 (the “2030 9.875% Senior Notes”). The net proceeds from the offering was approximately $776.0 million after deducting the initial purchasers’ discount and offering expenses. We used the net proceeds, to repay outstanding borrowings under PBF Holding’s asset-based revolving credit facility (the “Revolving Credit Facility”) and for general corporate purposes.

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PBF Holding Revolving Credit Facility

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”). There were $750.00 million and $100.00 million outstandi

[Excerpt truncated for page length; source filing is linked above.]

Latest 10-K MD&A

Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization. Confidence: high. Filing date: 2026-02-12. Report date: 2025-12-31.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

•the risk of cyber-attacks;

•our increased dependence on technology;

• the effects of competition in our markets;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Executive Summary

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

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Factors Affecting Comparability

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

Martinez Refinery Fire

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

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

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

Sale of Terminal Assets

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

Costs Related to RBI Initiative

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

Debt and Credit Facilities

Senior Notes

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

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

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

PBF Holding Revolving Credit Facility

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

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

PBFX Revolving Credit Facility

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

Catalyst Financing Obligations

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

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

Inventory Intermediation Agreement

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

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

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Equity Method Investment in SBR

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

Transactions with SBR

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

Share Repurchase Program

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

Land Sales

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

Tax Receivable Agreement

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

69

Renewable Fuel Standard

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

Factors Affecting Operating Results

Overview

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

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

Benchmark Refining Margins

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

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

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

Credit Risk Management

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

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

Other Factors

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

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

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

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

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Refinery-Specific Information

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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Results of Operations

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

PBF Energy

Year Ended December 31,

2025

2024

2023

Revenues

$

29,332.3 

$

33,115.3 

$

38,324.8 

Cost and expenses:

Cost of products and other

26,627.0 

30,266.7 

32,671.3 

Operating expenses (excluding depreciation and amortization expense as reflected below)

2,646.0 

2,606.2 

2,694.9 

Depreciation and amortization expense

630.3 

614.6 

560.0 

Cost of sales

29,903.3 

33,487.5 

35,926.2 

General and administrative expenses (excluding depreciation and amortization expense as reflected below)

332.3 

260.4 

362.5 

Depreciation and amortization expense

14.4 

13.2 

11.5 

Gain on insurance recoveries, net

(832.5)

— 

— 

Change in fair value of contingent consideration, net

— 

(3.3)

(45.8)

Equity loss in investee

62.2 

47.4 

45.3 

Loss (gain) on formation of SBR equity method investment

— 

8.7 

(925.1)

(Gain) loss on sale of assets

(93.1)

0.4 

(1.3)

Total cost and expenses

29,386.6 

33,814.3 

35,373.3 

Income (loss) from operations

(54.3)

(699.0)

2,951.5 

Other income (expense):

Interest expense (net of interest income of $24.3, $51.2, and $75.0, respectively)

(181.6)

(72.0)

(63.8)

Change in Tax Receivable Agreement liability

— 

— 

2.0 

Change in fair value of catalyst obligations

— 

— 

1.1 

Loss on extinguishment of debt

— 

— 

(5.7)

Other non-service components of net periodic benefit cost

1.3 

2.4 

0.7 

Income (loss) before income taxes

(234.6)

(768.6)

2,885.8 

Income tax (benefit) expense

(74.1)

(228.4)

723.8 

Net income (loss)

(160.5)

(540.2)

2,162.0 

Less: net income (loss) attributable to noncontrolling interests

(2.0)

(6.4)

21.5 

Net income (loss) attributable to PBF Energy Inc. stockholders

$

(158.5)

$

(533.8)

$

2,140.5 

Consolidated gross margin

$

(571.0)

$

(372.2)

$

2,398.6 

Gross refining margin (1)

$

2,347.5 

$

2,487.6 

$

5,287.7 

Net income (loss) available to Class A common stock per share:

Basic

$

(1.39)

$

(4.59)

$

17.13 

Diluted

$

(1.39)

$

(4.60)

$

16.52 

——————————

(1) See Non-GAAP Financial Measures.

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Operating Highlights

Year Ended December 31,

2025

2024

2023

Key Operating Information

Production (bpd in thousands)

838.5 

913.1 

918.3 

Crude oil and feedstocks throughput (bpd in thousands)

832.9 

904.0 

909.4 

Total crude oil and feedstocks throughput (millions of barrels)

304.0 

330.9 

329.0 

Consolidated gross margin per barrel of throughput

$

(1.87)

$

(1.13)

$

7.29 

Gross refining margin, excluding special items, per barrel of throughput (1)

$

8.77 

$

7.89 

$

16.07 

Refinery operating expense, per barrel of throughput

$

8.38 

$

7.52 

$

7.85 

Crude and feedstocks (% of total throughput) (2)

Heavy

25 

%

31 

%

27 

%

Medium

37 

%

38 

%

35 

%

Light

21 

%

17 

%

20 

%

Other feedstocks and blends

17 

%

14 

%

18 

%

Total throughput

100 

%

100 

%

100 

%

Yield (% of total throughput)

Gasoline and gasoline blendstocks

45 

%

47 

%

47 

%

Distillates and distillate blendstocks

35 

%

34 

%

34 

%

Lubes

1 

%

1 

%

1 

%

Chemicals

1 

%

1 

%

1 

%

Other

19 

%

18 

%

18 

%

Total yield

101 

%

101 

%

101 

%

——————————

(1) See Non-GAAP Financial Measures.

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

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

Year Ended December 31,

(dollars per barrel, except as noted)

2025

2024

2023

Dated Brent crude oil

$

69.03 

$

80.72 

$

82.64 

West Texas Intermediate (WTI) crude oil

$

64.87 

$

75.87 

$

77.67 

Light Louisiana Sweet (LLS) crude oil

$

67.08 

$

78.33 

$

80.14 

Alaska North Slope (ANS) crude oil

$

69.67 

$

80.24 

$

82.36 

Crack Spreads

Dated Brent (NYH) 2-1-1

$

22.59 

$

18.24 

$

29.67 

WTI (Chicago) 4-3-1

$

18.31 

$

16.27 

$

23.71 

LLS (Gulf Coast) 2-1-1

$

21.76 

$

18.21 

$

29.13 

ANS (West Coast-LA) 4-3-1

$

27.52 

$

23.36 

$

36.88 

ANS (West Coast-SF) 3-2-1

$

30.14 

$

24.62 

$

36.89 

Crude Oil Differentials

Dated Brent (foreign) less WTI

$

4.16 

$

4.84 

$

4.97 

Dated Brent less Maya (heavy, sour)

$

9.31 

$

12.31 

$

13.71 

Dated Brent less WTS (sour)

$

4.34 

$

4.85 

$

4.99 

Dated Brent less ASCI (sour)

$

4.12 

$

5.23 

$

5.73 

WTI less WCS (heavy, sour)

$

12.17 

$

14.82 

$

18.32 

WTI less Bakken (light, sweet)

$

1.21 

$

1.39 

$

(1.28)

WTI less Syncrude (light, sweet)

$

0.97 

$

0.75 

$

(0.91)

WTI less LLS (light, sweet)

$

(2.21)

$

(2.45)

$

(2.48)

WTI less ANS (light, sweet)

$

(4.80)

$

(4.36)

$

(4.70)

Effective RIN basket price

$

5.85 

$

3.75 

$

7.02 

Natural gas (dollars per MMBTU)

$

3.62 

$

2.41 

$

2.66 

2025 Compared to 2024

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

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

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

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

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

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

78

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

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

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

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

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

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

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

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

79

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

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

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

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

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

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

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

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

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

80

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

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

81

Non-GAAP Financial Measures

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

Special Items

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

82

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

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

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

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

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

83

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

Year Ended December 31,

2025

2024

2023

Net income (loss) attributable to PBF Energy Inc. stockholders

$

(158.5)

$

(533.8)

$

2,140.5 

Less: Income allocated to participating securities

0.1 

0.1 

— 

Income (loss) available to PBF Energy Inc. stockholders - basic

(158.6)

(533.9)

2,140.5 

Add: Net income (loss) attributable to noncontrolling interest (1)

(2.1)

(6.0)

20.5 

Less: Income tax benefit (expense) (2)

0.6 

1.6 

(5.3)

Adjusted fully-converted net income (loss)

$

(160.1)

$

(538.3)

$

2,155.7 

Special Items: (3)

Add: LCM inventory adjustment

313.0 

— 

— 

Add: LCM inventory adjustment - SBR

(10.4)

(18.9)

38.7 

Add: LIFO inventory decrement

5.4 

124.5 

— 

Add: Martinez refinery fire expenses

163.7 

— 

— 

Add: Gain on insurance recoveries, net

(832.5)

— 

— 

Add: Costs related to RBI initiative

29.6 

— 

— 

Add: Gain on sale of terminal assets

(94.0)

— 

— 

Add: Change in fair value of contingent consideration, net

— 

(3.3)

(45.8)

Add: Loss (gain) on formation of SBR equity method investment

— 

8.7 

(925.1)

Add: Loss on extinguishment of debt and termination of Inventory Intermediation Agreement

— 

— 

19.2 

Add: Gain on land sales

— 

— 

(1.7)

Add: Change in Tax Receivable Agreement liability

— 

— 

(2.0)

Less: Recomputed income tax on special items

110.7 

(28.8)

238.3 

Adjusted fully-converted net income (loss) excluding special items

$

(474.6)

$

(456.1)

$

1,477.3 

Weighted-average shares outstanding of PBF Energy Inc.

114,052,733 

116,248,827 

124,953,858 

Conversion of PBF LLC Series A Units (4)

862,780 

862,780 

899,519 

Common stock equivalents (5)

— 

— 

4,656,071 

Fully-converted shares outstanding—diluted

114,915,513 

117,111,607 

130,509,448 

Diluted net income (loss) per share

$

(1.39)

$

(4.60)

$

16.52 

Adjusted fully-converted net income (loss) per fully exchanged, fully diluted shares outstanding (5)

$

(1.39)

$

(4.60)

$

16.52 

Adjusted fully-converted net income (loss) excluding special items per fully exchanged, fully diluted shares outstanding (3) (5)

$

(4.13)

$

(3.89)

$

11.32 

——————————

See Notes to Non-GAAP Financial Measures.

84

Gross Refining Margin and Gross Refining Margin Excluding Special Items

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

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

Year Ended December 31,

2025

2024

2023

$

per barrel of throughput

$

per barrel of throughput

$

per barrel of throughput

Calculation of consolidated gross margin:

Revenues

$

29,332.3 

$

96.49 

$

33,115.3 

$

100.08 

$

38,324.8 

$

116.48 

Less: Cost of sales

29,903.3 

98.36 

33,487.5 

101.21 

35,926.2 

109.19 

Consolidated gross margin

$

(571.0)

$

(1.87)

$

(372.2)

$

(1.13)

$

2,398.6 

$

7.29 

Reconciliation of consolidated gross margin to gross refining margin:

Consolidated gross margin

$

(571.0)

$

(1.87)

$

(372.2)

$

(1.13)

$

2,398.6 

$

7.29 

Add: Logistics operating expense

116.5 

0.38 

135.8 

0.41 

131.9 

0.40 

Add: Logistics depreciation expense

36.1 

0.12 

36.2 

0.11 

36.1 

0.11 

Less: Logistics gross margin

(375.3)

(1.24)

(378.4)

(1.15)

(384.1)

(1.17)

Add: Refining operating expenses

2,547.0 

8.38 

2,487.8 

7.52 

2,581.3 

7.85 

Add: Refining depreciation expense

594.2 

1.95 

578.4 

1.75 

523.9 

1.59 

Gross refining margin

$

2,347.5 

$

7.72 

$

2,487.6 

$

7.51 

$

5,287.7 

$

16.07 

Special Items: (3)

Add: LCM inventory adjustment

313.0 

1.03 

— 

— 

— 

— 

Add: LIFO inventory decrement

5.4 

0.02 

124.5 

0.38 

— 

— 

Gross refining margin excluding special items

$

2,665.9 

$

8.77 

$

2,612.1 

$

7.89 

$

5,287.7 

$

16.07 

——————————

See Notes to Non-GAAP Financial Measures.

85

EBITDA, EBITDA Excluding Special Items and Adjusted EBITDA

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

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

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

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

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

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

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

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

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

Year Ended December 31,

2025

2024

2023

Reconciliation of net income (loss) to EBITDA and EBITDA excluding special items:

Net income (loss)

$

(160.5)

$

(540.2)

$

2,162.0 

Add: Depreciation and amortization expense

644.7 

627.8 

571.5 

Add: Interest expense, net

181.6 

72.0 

63.8 

Add: Income tax (benefit) expense

(74.1)

(228.4)

723.8 

EBITDA

$

591.7 

$

(68.8)

$

3,521.1 

 Special Items: (3)

Add: LCM inventory adjustment

313.0 

— 

— 

Add: LCM inventory adjustment - SBR

(10.4)

(18.9)

38.7 

Add: LIFO inventory decrement

5.4 

124.5 

— 

Add: Martinez refinery fire expenses

163.7 

— 

— 

Add: Gain on insurance recoveries, net

(832.5)

— 

— 

Add: Costs related to RBI initiative

29.6 

— 

— 

Add: Gain on sale of terminal assets

(94.0)

— 

— 

Add: Change in fair value of contingent consideration, net

— 

(3.3)

(45.8)

Add: Loss (gain) on formation of SBR equity method investment

— 

8.7 

(925.1)

Add: Loss on extinguishment of debt

— 

— 

5.7 

Add: Gain on land sales

— 

— 

(1.7)

Add: Change in Tax Receivable Agreement liability

— 

— 

(2.0)

EBITDA excluding special items

$

166.5 

$

42.2 

$

2,590.9 

Reconciliation of EBITDA to Adjusted EBITDA:

EBITDA

$

591.7 

$

(68.8)

$

3,521.1 

Add: Stock based compensation

39.0 

44.3 

51.5 

Add: Change in fair value of catalyst obligations

— 

— 

(1.1)

 Special Items: (3)

Add: LCM inventory adjustment

313.0 

— 

— 

Add: LCM inventory adjustment - SBR

(10.4)

(18.9)

38.7 

Add: LIFO inventory decrement

5.4 

124.5 

— 

Add: Martinez refinery fire expenses

163.7 

— 

— 

Add: Gain on insurance recoveries, net

(832.5)

— 

— 

Add: Costs related to RBI initiative

29.6 

— 

— 

Add: Gain on sale of terminal assets

(94.0)

— 

— 

Add: Change in fair value of contingent consideration, net

— 

(3.3)

(45.8)

Add: Loss (gain) on formation of SBR equity method investment

— 

8.7 

(925.1)

Add: Loss on extinguishment of debt

— 

— 

5.7 

Add: Gain on land sales

— 

— 

(1.7)

Add: Change in Tax Receivable Agreement liability

— 

— 

(2.0)

Adjusted EBITDA

$

205.5 

$

86.5 

$

2,641.3 

——————————

See Notes to Non-GAAP Financial Measures.

87

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

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

December 31,

December 31,

2025

2024

Balance Sheet Data:

Cash and cash equivalents

$

527.9 

$

536.1 

Inventories

2,563.1 

2,595.3 

Total assets

13,019.9 

12,703.2 

Total debt

2,148.3 

1,457.3 

Net debt

1,620.4 

921.2 

Total equity

5,449.9 

5,678.6 

Total equity excluding special items (6)

4,143.5 

4,686.8 

Total capitalization

7,598.2 

7,135.9 

Total debt to capitalization ratio

28 

%

20 

%

Total debt to capitalization ratio, excluding special items (6)

34 

%

24 

%

Net debt to capitalization ratio

23 

%

14 

%

Net debt to capitalization ratio, excluding special items (6)

28 

%

16 

%

——————————

See Notes to Non-GAAP Financial Measures.

88

Notes to Non-GAAP Financial Measures

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

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

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

(3)    Special items:

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

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

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

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

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

89

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

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

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

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

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

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

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

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

90

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

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

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

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

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

December 31,

December 31,

(in millions)

2025

2024

Total equity

$

5,449.9 

$

5,678.6 

 Special Items (Note 4)

Add: LCM inventory adjustments

$

313.0 

$

— 

Add: LCM inventory adjustment - SBR

(10.4)

— 

Add: LIFO inventory decrement

5.4 

— 

Add: Martinez refinery fire expenses

163.7 

— 

Add: Gain on insurance recoveries, net

(832.5)

— 

Add: Costs related to RBI initiative

29.6 

— 

Add: Gain on sale of terminal assets

(94.0)

— 

Add: Cumulative historical equity adjustments (a)

(1,328.1)

(1,328.1)

Less: Recomputed income tax on special items

446.9 

336.3 

    Net impact of special items to equity

(1,306.4)

(991.8)

Total equity excluding special items

$

4,143.5 

$

4,686.8 

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

91

Liquidity and Capital Resources

Overview

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

Cash Flow Analysis

Cash Flows from Operating Activities

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

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

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

92

Cash Flows from Investing Activities

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

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

Cash Flows from Financing Activities

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

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

93

Capitalization

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

December 31, 2025

Debt: (1)

2028 6.00% Senior Notes

$

801.6 

2030 9.875% Senior Notes

800.0 

2030 7.875% Senior Notes

500.0 

Revolving Credit Facility

100.0 

Total debt

$

2,201.6 

Unamortized deferred financing costs

(41.0)

Unamortized discount

(12.3)

Total debt, net of unamortized deferred financing costs and discount

$

2,148.3 

Total Equity

5,449.9 

Total Capitalization (2)

$

7,598.2 

_______________________________________________

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

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

2025 Debt Related Transactions

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

Revolving Credit Facility Overview

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

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

Total Commitment

Amount Borrowed as of December 31, 2025

Outstanding Letters of Credit

Borrowing Base Availability

Expiration Date

Revolving Credit Facility (a)

$

3,500.0 

$

100.0 

$

167.3 

$

2,296.6 

August 2028

___________________________________

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

94

Additional Information on Indebtedness

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

Liquidity

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

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

Share Repurchases

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

Working Capital

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

Martinez Refinery Fire

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

95

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

Sale of Terminal Assets

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

Crude and Feedstock Supply Agreements

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

Capital Spending

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

96

Material Cash Requirements

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

Payments Due by Period

Short-Term

Long-Term

Total

Credit facilities and debt (a)

$

— 

$

2,201.6 

$

2,201.6 

Interest payments on credit facilities and debt

186.2 

539.0 

725.2 

Leases and other rental-related commitments (b)

387.3 

1,791.0 

2,178.3 

Purchase obligations (c)

3,549.9 

546.0 

4,095.9 

Construction obligations

220.1 

— 

220.1 

Environmental obligations (d)

9.8 

152.8 

162.6 

Pension and post-retirement obligations (e)

42.8 

520.6 

563.4 

Tax Receivable Agreement obligation (f)

— 

168.2 

168.2 

Total material cash requirements

$

4,396.1 

$

5,919.2 

$

10,315.3 

___________________________

(a)    Credit facilities and debt

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

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

(b)    Leases and other rental-related commitments

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

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

(c)    Purchase obligations

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

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(d)    Environmental obligations

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

(e)    Pension and post-retirement obligations

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

(f) Tax Receivable Agreement obligation

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

Tax Distributions

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

Critical Accounting Policies

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

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Environmental Matters

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

Impairment of Long-Lived Assets

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

Income Taxes and Tax Receivable Agreement

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

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

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

Recent Accounting Pronouncements

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

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