PBF Energy Inc. (PBF)

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, 2024 and 2023 and comparisons of the results for the years ended December 31, 2024 and 2023. Discussions of results for the year ended December 31, 2022 and comparisons of the results for the years ended December 31, 2023 and 2022 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, 2023.

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 by the new presidential administration, 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 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;

•our ability to manage our costs and expenses;

•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 ABx 2-1, or from actions taken by environmental interest groups;

•the risk of cyber-attacks;

•our increased dependence on technology;

• the effects of competition in our markets;

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

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

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

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

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

•our expectations and timing with respect to our acquisition and investment activity 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;

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•restrictive covenants in our indebtedness that may adversely affect our operational flexibility;

•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.

Debt and Credit Facilities

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 $200.0 million outstanding borrowings under the Revolving Credit Facility as of December 31, 2024. There were no outstanding borrowings as of December 31, 2023.

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.

Senior Notes

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

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

During the year ended December 31, 2022, we exercised our rights under the indenture governing the 9.25% senior secured notes due 2025 (the “2025 Senior Secured Notes”) to redeem all of the outstanding 2025 Senior Secured Notes at a price of 104.625% of the aggregate principal amount thereof plus accrued and unpaid interest. The aggregate redemption price for all 2025 Senior Secured Notes approximated $1.3 billion plus accrued and unpaid interest. The difference between the carrying value of the 2025 Senior Secured Notes on the date they were redeemed and the amount for which they were redeemed was $69.9 million and was recorded as a Loss on extinguishment of debt in the Consolidated Statements of Operations.

During the year ended December 31, 2022, we made a number of open market repurchases of our 2028 Senior Notes and our 2025 Senior Notes that resulted in the extinguishment of $24.9 million in principal of the 2028 Senior Notes and $5.0 million in principal of the 2025 Senior Notes. Total cash consideration paid to repurchase the principal amount outstanding of the 2028 Senior Notes and the 2025 Senior Notes, excluding accrued interest, totaled $25.9 million and we recognized a $3.8 million gain on the extinguishment of this debt during the year ended December 31, 2022.

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

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. 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) (the “Refineries”) and delivered into the storage tanks at the Refineries (the “Storage Tanks”). The J. Aron Products were sold back to us as the J. Aron Products were discharged out of the Storage Tanks.

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

Equity Method Investment in SBR

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

Transactions with SBR

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

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Share Repurchase Program

On December 12, 2022, our Board of Directors authorized the Repurchase Program. As further approved on February 13, 2024, the Repurchase Program currently allows for repurchases of up to $1.75 billion and has a program expiration date of December 2025. During the year ended December 31, 2024, we purchased 7,554,269 shares of PBF Energy's Class A common stock for $329.1 million, inclusive of commissions paid, through open market transactions. During the year ended December 31, 2023, we purchased 12,367,073 shares of PBF Energy's Class A common stock for $532.5 million, inclusive of commissions paid, through open market transactions. During the year ended December 31, 2022, we purchased 4,192,555 shares of PBF Energy's Class A common stock for $156.4 million, inclusive of commissions paid, through open market transactions.

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.

Merger Transaction

On November 30, 2022, PBF Energy, PBF LLC, PBFX Holdings Inc., a Delaware corporation and wholly-owned subsidiary of PBF LLC (“PBFX Holdings”), Riverlands Merger Sub LLC, a Delaware limited liability company and wholly owned subsidiary of PBF LLC, PBFX, and PBFX GP closed on a definitive agreement (the “Merger Agreement”) pursuant to which PBF Energy and PBF LLC acquired all of the publicly held common units in PBFX representing limited partner interests in the master limited partnership not already owned by certain wholly-owned subsidiaries of PBF Energy and its affiliates (the “Merger Transaction”). Subsequent to closing on the Merger Transaction, PBFX became an indirect wholly-owned subsidiary of PBF Energy and PBF LLC.

At the effective time of the closing of the Merger Transaction, pursuant to the terms of the Merger Agreement, each PBFX Public Common Unit was converted into the right to receive: (i) 0.270 of a share of Class A Common Stock, par value $0.001 per share, of PBF Energy, (ii) $9.25 in cash, without interest and (iii) any cash in lieu of fractional shares of PBF Energy Common Stock to which the holder thereof became entitled upon surrender of such PBFX Public Common Units in accordance with the Merger Agreement. Such Merger Agreement consideration totaled $303.7 million in cash and resulted in the issuance of 8,864,684 shares of PBF Energy Class A common stock. The PBFX Common Units owned by PBF LLC and PBFX Holdings and the non-economic general partner interest remain outstanding and were unaffected by the Merger Transaction. There was no change in ownership of the non-economic general partner interest.

East Coast Refining Reconfiguration

In 2022, we restarted several processing units at the Paulsboro refinery, that were temporarily idled in 2020 as part of the East Coast Refining Reconfiguration. Based on this reconfiguration and subsequent restart of several processing units, our East Coast throughput capacity currently approximates 335,000 barrels per day.

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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, 2024, a liability for the Tax Receivable Agreement of $293.6 million ($336.6 million and $338.6 million as of December 31, 2023 and December 31, 2022, respectively) reflecting our estimate of the undiscounted amounts that we expect to pay under the agreement. As of December 31, 2024, $125.4 million of the Tax Receivable Agreement obligation was recorded as a Current liability and represents the amount paid in January 2025 related to the 2023 tax year. As future taxable income is recognized, increases in our Tax Receivable Agreement liability may be necessary in conjunction with the revaluation of deferred tax assets. Refer to “Note 11 - Commitments and Contingencies” and “Note 18 - Income Taxes” of our Notes to Consolidated Financial Statements for more details.

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 $515.3 million in RINs costs during the year ended December 31, 2024 as compared to $762.3 million and $1,225.5 million during the years ended December 31, 2023 and 2022, 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.

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

Benchmark Refining Margins

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

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

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

Credit Risk Management

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

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

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

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

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

Refinery-Specific Information

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

East Coast Refining System (Delaware City and Paulsboro Refineries). The benchmark refining margin for the East Coast Refining System is calculated by assuming that two barrels of Dated Brent crude oil are converted into one barrel of gasoline and one barrel of diesel. We calculate this benchmark using the NYH market value of reformulated blendstock for oxygenate blending (“RBOB”) and ULSD against the market value of Dated Brent and refer to the benchmark as the Dated Brent (NYH) 2-1-1 benchmark refining margin. The East Coast Refining System has a product slate of approximately 35% gasoline, 36% distillate, 2% high-value Group I lubricants, 1% high-value petrochemicals, with the remaining portion of the product slate comprised of lower-value products (3% LPGs, 18% black oil and 5% 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;

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•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 priced at a significant discount to RBOB and ULSD; and

•the Paulsboro refinery produces Group I lubricants, which 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 54% gasoline, 37% distillate, 4% high-value petrochemicals (including nonene, tetramer, benzene, xylene and toluene) with the remaining portion of the product slate comprised of lower-value products (3% LPGs and 2% black oil). For this reason, we believe the WTI (Chicago) 4-3-1 is an appropriate benchmark industry refining margin. The majority of Toledo revenues are generated off Chicago-based market prices.

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

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

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

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

Chalmette Refinery. The benchmark refining margin for the Chalmette refinery is calculated by assuming two barrels of LLS crude oil are converted into one barrel of gasoline and one barrel of diesel. We calculate this benchmark using the US Gulf Coast market value of 87 conventional gasoline and ULSD against the market value of LLS and refer to this benchmark as the LLS (Gulf Coast) 2-1-1 benchmark refining margin. Our Chalmette refinery has a product slate of approximately 42% gasoline and 35% 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 has recently 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 heavy, sour crude slate processed at Chalmette, we produce lower-value products including sulfur and petroleum coke. These products are priced at a significant discount to 87 conventional gasoline and ULSD.

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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 59% gasoline and 26% distillate with the remaining portion of the product slate comprised of lower-value products (3% LPG, 2% black oil and 10% 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 65% 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 priced at a significant discount to gasoline and diesel.

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

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

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

•as a result of the heavy, sour crude slate processed at Martinez, we produce lower-value products including petroleum coke and sulfur. These products are 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, 2024, 2023 and 2022 (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.

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(1) See Non-GAAP Financial Measures.

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Operating Highlights

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(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.

2024 Compared to 2023

Overview— PBF Energy net loss was $540.2 million for the year ended December 31, 2024 compared to net income of $2,162.0 million for the year ended December 31, 2023. Net loss attributable to PBF Energy stockholders was $533.8 million, or $(4.60) per diluted share, for the year ended December 31, 2024 ($(4.60) per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net loss, or $(3.89) per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net loss excluding special items, as described below in Non-GAAP Financial Measures) compared to net income attributable to PBF Energy stockholders of $2,140.5 million, or $16.52 per diluted share, for the year ended December 31, 2023 ($16.52 per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income, or $11.32 per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income excluding special items, as described below in Non-GAAP Financial Measures). The net income (loss) attributable to PBF Energy stockholders represents PBF Energy’s equity interest in PBF LLC’s pre-tax income (loss), less applicable income tax (benefit) expense. PBF Energy’s weighted-average equity interest in PBF LLC was 99.3% for both the years ended December 31, 2024 and 2023.

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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 obligation associated with the acquisition of the Martinez refinery and logistic assets (the “Martinez Contingent Consideration”). Our results for the year ended December 31, 2023 were positively impacted by special items consisting of a gain on the formation of the SBR equity method investment of $925.1 million, or $684.6 million net of tax, a change in fair value of contingent consideration of $45.8 million, or $33.9 million net of tax, pre-tax benefit associated with the change in the Tax Receivable Agreement liability of $2.0 million, or $1.5 million net of tax and a gain on the sale of a parcel of land at our Torrance refinery of $1.7 million or $1.3 million net of tax, partially offset by our share of the SBR LCM inventory reserve of $38.7 million, or $28.6 million net of tax, a $5.7 million, or $4.2 million net of 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, and exit costs associated with the early termination of the Inventory Intermediation Agreement of $13.5 million, or $10.0 million, net of tax.

Excluding the impact of these special items, when comparing our results to the year ended December 31, 2023, we experienced an overall decrease in our refining margins due to unfavorable movements in crack spreads and crude oil differentials sold at the majority of our refineries. In addition, the planned and unplanned maintenance experienced at our West Coast refineries during the fourth quarter of 2023 extended into the first half of 2024. These decreasing metrics combined with the timing of our maintenance activities have negatively impacted our revenues, gross margin, and operating income in comparison to the prior year.

Revenues— Revenues totaled $33.1 billion for the year ended December 31, 2024 compared to $38.3 billion for the year ended December 31, 2023, a decrease of approximately $5.2 billion or 13.6%. Revenues per barrel sold were $90.47 and $100.85 for the years ended December 31, 2024 and 2023, respectively, a decrease of 10.3% directly related to lower hydrocarbon commodity prices. For the year ended December 31, 2024, the total throughput rates at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 305,200 bpd, 140,700 bpd, 162,200 bpd and 295,900 bpd, respectively. For the year ended December 31, 2023, the total throughput rates at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 327,600 bpd, 136,400 bpd, 174,200 bpd and 271,200 bpd, respectively. For the year ended December 31, 2024, the total barrels sold at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 347,700 bpd, 148,500 bpd, 158,700 bpd and 345,300 bpd, respectively. For the year ended December 31, 2023, the total barrels sold at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 373,700 bpd, 148,700 bpd, 187,300 bpd and 340,800 bpd, respectively.

Overall average throughput rates at our refineries were slightly lower in the year ended December 31, 2024 due to increased maintenance activity and lower demand compared to the same period in 2023. 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.

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Consolidated gross margin— Consolidated gross margin totaled $(372.2) million for the year ended December 31, 2024, compared to $2,398.6 million for the year ended December 31, 2023, a decrease of $2,770.8 million. Gross refining margin (as described below in Non-GAAP Financial Measures) totaled $2,487.6 million, or $7.51 per barrel of throughput, for the year ended December 31, 2024 compared to $5,287.7 million, or $16.07 per barrel of throughput, for the year ended December 31, 2023, a decrease of approximately $2,800.1 million. Gross refining margin excluding special items totaled $2,612.1 million, or $7.89 per barrel of throughput, for the year ended December 31, 2024 compared to $5,287.7 million, or $16.07 per barrel of throughput, for the year ended December 31, 2023, a decrease of $2,675.6 million. Consolidated gross margin and gross refining margin decreased due to unfavorable movements in crack spreads and crude oil differentials at the majority of our refineries.

Consolidated gross margin and gross refining margin were negatively impacted in the current year by a LIFO inventory decrement charge of $124.5 million mainly related to our East Coast and Gulf Coast LIFO inventory layers. During the year ended December 31, 2023, our margin calculations were not impacted by special items.

Additionally, our results continue to be impacted by significant costs to comply with the RFS. Total RFS compliance costs were $515.3 million for the year ended December 31, 2024 compared to $762.3 million for the year ended December 31, 2023.

Average industry margins were unfavorable during the year ended December 31, 2024 in comparison to the prior year, primarily due to decreased refining margins as a result of unfavorable movements in crack spreads and crude oil differentials at the majority of our refineries.

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 $18.24 per barrel, or 38.5% lower, in the year ended December 31, 2024, as compared to $29.67 per barrel in the same period in 2023. Our margins were positively impacted from our refinery specific slate on the East Coast by strengthened WTI/Bakken differential, which increased by $2.67 per barrel, offset by weakened Dated Brent/Maya differential, which decreased by $1.40 per barrel compared to the same period in 2023. Additionally, the WTI/WCS differential decreased to $14.82 per barrel in 2024 compared to $18.32 per barrel in 2023, which unfavorably impacted our cost of heavy Canadian crude.

Across the Mid-Continent, the WTI (Chicago) 4-3-1 industry crack spread was $16.27 per barrel, or 31.4% lower, in the year ended December 31, 2024, as compared to $23.71 per barrel in the prior year. Our margins were positively impacted from our refinery specific slate in the Mid-Continent by an increasing WTI/Bakken differential, which averaged a discount of $1.39 per barrel in the year ended December 31, 2024, as compared to a premium of $1.28 per barrel in the prior year. Additionally, the WTI/Syncrude differential averaged a discount of $0.75 per barrel for the year ended December 31, 2024 as compared to a premium of $0.91 per barrel in the prior year.

On the Gulf Coast, the LLS (Gulf Coast) 2-1-1 industry crack spread was $18.21 per barrel, or 37.5% lower, in the year ended December 31, 2024 as compared to $29.13 per barrel in the prior year. Margins on the Gulf Coast were positively impacted from our refinery specific slate by a strengthening WTI/LLS differential, which averaged a premium of $2.45 per barrel for the year ended December 31, 2024 as compared to a premium of $2.48 per barrel in the prior year.

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On the West Coast, the ANS (West Coast) 4-3-1 industry crack spread was $23.36 per barrel, or 36.7% lower, in the year ended December 31, 2024 as compared to $36.88 per barrel in the prior year. Additionally, the ANS (West Coast) 3-2-1 industry crack spread was $24.62 per barrel, or 33.3% lower, in the year ended December 31, 2024 as compared to $36.89 per barrel in the prior year. Our margins on the West Coast were positively impacted from our refinery specific slate by a strengthening WTI/ANS differential, which averaged a premium of $4.36 per barrel for the year ended December 31, 2024 as compared to a premium of $4.70 per barrel in the prior year.

Operating expenses— Operating expenses totaled $2,606.2 million for the year ended December 31, 2024 compared to $2,694.9 million for the year ended December 31, 2023, a decrease of approximately $88.7 million, or 3.3%. Of the total $2,606.2 million in operating expenses, $2,487.8 million, or $7.52 per barrel of throughput, related to expenses incurred by the Refining segment, while the remaining $118.4 million related to expenses incurred by the Logistics segment ($2,581.3 million or $7.85 per barrel of throughput, and $113.6 million of operating expenses for the year ended December 31, 2023 related to the Refining and Logistics segments, respectively). The decrease in operating expenses was mainly attributable to lower maintenance and lower energy costs due to a decrease in overall natural gas prices and electricity.

General and administrative expenses— General and administrative expenses totaled $260.4 million for the year ended December 31, 2024, compared to $362.5 million for the year ended December 31, 2023, a decrease of $102.1 million or 28.2%. The decrease in general and administrative expenses in comparison to the year 2023 was due to lower employee-related expenses, including incentive compensation. General and administrative expenses are comprised of personnel, facilities, and other infrastructure costs necessary to support our refineries and related logistics assets.

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 a gain of $925.1 million for the year ended December 31, 2023, resulting from the difference between the carrying value and fair value of the assets associated with the business contributed to SBR.

Equity loss in investee— There was a loss of $47.4 million and $45.3 million for the years ended December 31, 2024 and December 31, 2023, respectively, related to our equity share of our investments in SBR.

Loss (gain) on sale of 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. There was a net gain of $1.3 million for the year ended December 31, 2023 related primarily to the sale of a parcel of land at our Torrance refinery.

Depreciation and amortization expense— Depreciation and amortization expense totaled $627.8 million for the year ended December 31, 2024 (including $614.6 million recorded within Cost of sales) compared to $571.5 million for the year ended December 31, 2023 (including $560.0 million recorded within Cost of sales), an increase of $56.3 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 and $45.8 million for the years ended December 31, 2024 and December 31, 2023, respectively. These gains were primarily related to changes in the estimated fair value of the Martinez Contingent Consideration.

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Change in Tax Receivable Agreement liability— There was no change in the Tax Receivable Agreement liability for the year ended December 31, 2024. Changes in the Tax Receivable Agreement liability for the year ended December 31, 2023 represented a benefit of $2.0 million as a result of changes in the deferred tax asset valuation allowance recorded in accordance with Accounting Standards Codification (“ASC”) 740, Income Taxes (“ASC 740”), related to the reduction of deferred tax assets associated with the payments made or expected to be made in connection with the Tax Receivable Agreement liability.

Change in fair value of catalyst obligations— Change in fair value of catalyst obligations represented a gain of $1.1 million for the year ended December 31, 2023. This gain related to the change in fair value of the precious metals underlying the sale and leaseback of our refineries’ precious metal catalysts, which we were obligated to repurchase at fair market value upon lease termination. During 2023, we settled our remaining outstanding precious metal financing arrangement.

Loss on extinguishment of debt— There was a loss on extinguishment of debt of $5.7 million in the year ended December 31, 2023, related to the redemption of the 2025 Senior Notes and the amendment and restatement of the Revolving Credit Agreement.

Interest expense, net— Interest expense, net totaled $72.0 million for the year ended December 31, 2024, compared to $63.8 million for the year ended December 31, 2023, an increase of $8.2 million. The net increase is mainly attributable to lower interest income earned during the year ended December 31, 2024 driven by lower interest rates in comparison to the prior year, as well as higher outstanding borrowings on our Revolving Credit Facility, partially offset by lower interest expense due to the redemption of the PBFX 2023 Senior Notes during the first quarter of 2023, the redemption of the 2025 Senior Notes in the third quarter of 2023, and the issuance of our 2030 Senior Notes during the third quarter of 2023 at a reduced principal amount. For the year ended December 31, 2024, interest expense includes interest on long-term debt, letter of credit fees associated with the purchase of certain crude oils and the amortization of deferred financing costs.

Income tax (benefit) expense— PBF LLC is organized as a limited liability company and PBFX is a partnership, both of which are treated as “flow-through” entities for federal income tax purposes and therefore are not subject to income tax. However, two subsidiaries of Chalmette Refining and our Canadian subsidiary, PBF Energy Limited, are treated as C-Corporations for income tax purposes and may incur income taxes with respect to their earnings, as applicable. The members of PBF LLC are required to include their proportionate share of PBF LLC’s taxable income or loss, on their respective tax returns. PBF LLC generally makes distributions to its members, per the terms of PBF LLC’s amended and restated limited liability company agreement, related to such taxes on a pro-rata basis. PBF Energy recognizes an income tax expense or benefit in our consolidated financial statements based on PBF Energy’s allocable share of PBF LLC’s pre-tax income or loss, which was approximately 99.3% on a weighted-average basis for both the year ended December 31, 2024 and 2023. 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). PBF Energy’s effective tax rate, including the impact of noncontrolling interests, for the years ended December 31, 2024 and 2023 was 29.7% and 25.1%, respectively.

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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, 2024 and 2023 was approximately 0.7%. The carrying amount of the noncontrolling interest on our Consolidated Balance Sheets attributable to the noncontrolling interest is not equal to the noncontrolling interest ownership percentage due to the effect of income taxes and related agreements that pertain solely to PBF Energy.

Non-GAAP Financial Measures

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

Special Items

The Non-GAAP measures presented include Adjusted Fully-Converted Net Income (Loss) excluding special items, gross refining margin excluding special items, EBITDA excluding special items and net debt to capitalization ratio excluding special items. Special items for the periods presented relate to a LIFO inventory decrement, our share of the SBR LCM inventory adjustment, 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, changes in the Tax Receivable Agreement liability, gains on land sales, and net tax benefit on remeasurement of deferred tax assets. 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.

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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.

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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, 2024, 2023 and 2022 (in millions, except share and per share amounts):

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See Notes to Non-GAAP Financial Measures.

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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 Logistic 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 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):

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See Notes to Non-GAAP Financial Measures.

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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, LIFO inventory decrement, our share of the SBR LCM inventory adjustment, changes in the Tax Receivable Agreement liability, 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, 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):

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See Notes to Non-GAAP Financial Measures.

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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. 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.

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See Notes to Non-GAAP Financial Measures.

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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 both 2024 and 2023, and 25.9% for 2022, 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:

SBR LCM Inventory Adjustment - The LCM adjustment is a GAAP requirement related to inventory valuation that mandates inventory to be stated at the lower of cost or market. During the years ended December 31, 2024 and December 31, 2023, SBR recorded adjustments to the LCM, which increased and decreased its income from operations by $37.7 million and $77.4 million, respectively. Our Equity loss in investee includes our 50% share of these adjustments. For the years ended December 31, 2024 and December 31, 2023, these LCM adjustments increased and decreased our income from operations by $18.9 million and $38.7 million, respectively ($14.0 million and $28.6 million, respectively, net of tax). There were no such adjustments in 2022.

LIFO inventory decrement - The Company recorded a pre-tax charge to cost of products and other related to a LIFO inventory layer decrement. The majority of the decrement 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, for the year ended December 31, 2024. Decrements recorded in the years ended December 31, 2023 and December 31, 2022 were de minimis.

Change in fair value of contingent consideration, net - 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. During the year ended December 31, 2022, we recorded a net change in fair value of the Martinez Contingent Consideration, offset by the recognition of contingent assets associated with the acquisition. These changes in estimate decreased income from operations and net income by $48.3 million and $35.8 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 in 2022.

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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. During the year ended December 31, 2022, we recorded a net pre-tax loss on extinguishment of debt related to the redemption of the 2025 Senior Secured Notes, partially offset by the gain recognized on the repurchase of a portion of each of the 2028 Senior Notes and the 2025 Senior Notes, which decreased income before income taxes and net income by $66.1 million and $49.0 million, respectively. There were no such losses in 2024.

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 other periods presented.

Change in 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, we recorded a change in the Tax Receivable Agreement liability that increased income before income taxes and net income by $2.0 million and $1.5 million, respectively. During the year ended December 31, 2022, PBF Energy recorded a change in the Tax Receivable Agreement liability that decreased income before taxes and net income by $290.3 million and $215.1 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.

Net tax benefit on remeasurement of deferred tax assets - The deferred tax valuation allowance was reduced to zero as of December 31, 2022, therefore, there was no impact to our financial statements related to the remeasurement of deferred tax assets as of December 31, 2024 and December 31, 2023. During the year ended December 31, 2022, we recorded a decrease to our deferred tax valuation allowance of $308.5 million (reducing our deferred tax valuation allowance to zero), in accordance with ASC 740, of which $233.8 million related to a tax benefit with respect to the remeasurement of deferred tax assets and the balance related to our net changes in the Tax Receivable Agreement liability.

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.

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(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, 2024, 2023 and 2022, respectively. Common stock equivalents exclude the effects of performance share units and options and warrants to purchase 4,413,417, 18,431 and 3,877,035 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, 2024, 2023 and 2022, 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:

(a) Refer to the Company’s 2023 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 2024.

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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, as well as 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, 2024, 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 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, 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.

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 and emissions obligations, as a result of a decrease in our unfunded RINs obligation.

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Net cash provided by operating activities was $1,338.5 million for the year ended December 31, 2023 compared to net cash provided by operating activities of $4,772.0 million for the year ended December 31, 2022. Our operating cash flows for the year ended December 31, 2022 included our net income of $2,972.8 million, and net changes in operating assets and liabilities reflecting cash proceeds of $341.0 million, primarily driven by timing of payments for accrued expenses. Change in accrued expenses was due primarily to an increase in renewable energy credit and emissions obligations, as a result of an increase in our unfunded RINs obligation as of December 31, 2022. Our overall increase in cash provided by operating activities also included depreciation and amortization of $533.9 million, deferred income taxes of $420.2 million, change in the Tax Receivable Agreement liability of $290.3 million, net loss on extinguishment of debt primarily related to the redemption of our 2025 Senior Secured Notes of $66.1 million, stock-based compensation of $54.3 million, net change in the fair value of contingent consideration of $48.3 million, pension and other post-retirement benefits costs of $47.6 million, change in the fair value of our catalyst obligations of $2.0 million, and loss on sale of assets of $0.9 million, partially offset by a net non-cash charges related to the change in the fair value of our inventory repurchase obligations of $5.4 million.

Cash Flows from Investing Activities

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. The net cash flows 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 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.

Net cash used in investing activities was $338.6 million for the year ended December 31, 2023 compared to $1,010.9 million for the year ended December 31, 2022. Net cash used in investing activities for the year ended December 31, 2022 was comprised of capital expenditures totaling $633.3 million, expenditures for refinery turnarounds of $311.6 million and expenditures for other assets of $66.0 million.

Cash Flows from Financing Activities

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, 2024, net cash used in 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 of insurance premium financing of $111.9 million, payments on finance leases of $12.2 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, proceeds from insurance premium financing of $123.2 million, and transactions made in connection with stock-based compensation plans of $1.4 million. 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 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.

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Net cash used in financing activities was $1,420.0 million for the year ended December 31, 2023 compared to net cash used in financing activities of $2,899.0 million for the year ended December 31, 2022. For the year ended December 31, 2022, net cash used in financing activities consisted of the redemption of the 2025 Senior Secured Notes of $1,307.4 million, net repayments on the Revolving Credit Facility of $900.0 million, the purchase of PBFX publicly held shares in connection with the Merger Transaction of $303.7 million, share repurchases of PBF Energy’s Class A common stock of $156.4 million, net repayments on the PBFX Revolving Credit Facility of $100.0 million, dividends and distributions of $73.6 million, settlements of precious metal catalyst obligations of $56.2 million, deferred financing costs and other costs of $31.3 million, $25.9 million related to the repurchase of the principal amount outstanding of the 2028 Senior Notes and the 2025 Senior Notes, excluding accrued interest, payments on finance leases of $11.3 million, and PBFX Contingent Consideration payments of $3.1 million, partially offset by transactions made in connection with stock-based compensation plans of $67.8 million, and proceeds from insurance premium financing of $2.1 million.

Capitalization

Our capital structure was comprised of the following as of December 31, 2024 (in millions):

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

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

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, 2024, we had $536.1 million of cash and cash equivalents and an outstanding balance of $200.0 million under the Revolving Credit Facility.

We had available capacity under our Revolving Credit Facility as of December 31, 2024 (in millions) as follows:

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(a)    The amount available for borrowings and letters of credit under the Revolving Credit Facility is calculated according to a “borrowing base” formula based on (i) 90% of the book value of Eligible

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Accounts with respect to investment grade obligors plus (ii) 85% of the book value of Eligible Accounts with respect to non-investment grade obligors plus (iii) 80% of the cost of Eligible Hydrocarbon Inventory plus (iv) 100% of Cash and Cash Equivalents in deposit accounts subject to a control agreement, in each case as defined in the Revolving Credit Agreement. The borrowing base is subject to customary reserves and eligibility criteria and in any event cannot exceed $3.5 billion.

Additional Information on Indebtedness

Our debt, including our Revolving Credit Facility and senior notes, include certain typical financial covenants and restrictions on our subsidiaries’ ability to, among other things, incur or guarantee new debt, engage in certain business activities including transactions with affiliates and asset sales, make investments or distributions, engage in mergers or pay dividends in certain circumstances. These covenants are subject to a number of important exceptions and qualifications. We are in compliance as of December 31, 2024 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, 2024, our operational liquidity was approximately $2.4 billion (as compared to more than $4.6 billion as of December 31, 2023), which consists of approximately $0.5 billion of cash, and more than $1.9 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, 2024, 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 repurchases up to $1.75 billion and has a program expiration date of December 2025. 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, 2024 was approximately $917.8 million, consisting of $4,543.9 million in total current assets and $3,626.1 million in total current liabilities. Our working capital at December 31, 2023 was $2,379.3 million, consisting of $6,596.6 million in total current assets and $4,217.3 million in total current liabilities.

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. We also have a crude supply agreement with Saudi Aramco, the term of which is currently year to year, for up to approximately 100,000 bpd that is processed at the Paulsboro refinery and crude supply agreements with Shell Trading (US) Company (primarily serving our Martinez refinery) for up to approximately 65,000 bpd, through 2026.

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Capital Spending

Capital spending was $1,008.3 million for the year ended December 31, 2024 and was 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. We currently expect to spend an aggregate of approximately $850.0 million to $900.0 million in 2025 for facility improvements and refinery maintenance and turnarounds, as well as expenditures to meet environmental, regulatory and safety requirements.

Material Cash Requirements

Our material cash requirements include the following known contractual and other obligations as of December 31, 2024 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.

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(a)    Credit facilities and debt

Credit facilities and debt represent the repayment of indebtedness incurred in connection with the 2030 Senior Notes, 2028 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.

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(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.

(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, 2024. Refer to “Note 11 - Commitments and Contingencies” and “Note 18 - Income Taxes” of our Notes to the Consolidated Financial statements for further discussion of the Tax Receivable Agreement. The short-term portion of our Tax Receivable Agreement obligation at December 31, 2024 was paid in January 2025.

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.

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Critical Accounting Policies

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

Environmental Matters

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

Impairment of Long-Lived Assets

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

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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 $165.0 million as of December 31, 2024.

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.

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Recent Accounting Pronouncements

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

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, 2023 and 2022 and comparisons of the results for the years ended December 31, 2023 and 2022. Discussions of results for the year ended December 31, 2021 and comparisons of the results for the years ended December 31, 2022 and 2021 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, 2022.

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 and its impacts 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, the outbreak of armed hostilities in the middle east and disruptions in international shipping resulting from recent attacks by armed groups on cargo ships in the Red Sea, 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 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;

•our ability to manage our costs and expenses;

•political pressure and influence of environmental groups and other stakeholders on decisions and policies related to the refining and processing 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, or from actions taken by environmental interest groups;

•the risk of cyber-attacks;

•our increased dependence on technology;

• the effects of competition in our markets;

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

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

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

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

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

•our expectations and timing with respect to our acquisition and investment activity 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;

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•restrictive covenants in our indebtedness that may adversely affect our operational flexibility;

•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 12.7 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.

Debt and Credit Facilities

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 no outstanding borrowings under the revolving credit facilities as of December 31, 2023 or December 31, 2022.

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.

There were no outstanding borrowings on the PBFX Revolving Credit Facility as of December 31, 2022.

Senior Notes

On August 21, 2023, we issued $500.0 million in aggregate principal amount of the 2030 Senior Notes. The net proceeds from this 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.

On September 13, 2023, we exercised our rights under the indenture governing the 2025 Senior Notes to redeem all of the outstanding 2025 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 all 2025 Senior Notes approximated $664.5 million plus accrued and unpaid interest.

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.

During the year ended December 31, 2022, we exercised our rights under the indenture governing the 9.25% senior secured notes due 2025 (the “2025 Senior Secured Notes”) to redeem all of the outstanding 2025 Senior Secured Notes at a price of 104.625% of the aggregate principal amount thereof plus accrued and unpaid interest. The aggregate redemption price for all 2025 Senior Secured Notes approximated $1.3 billion plus accrued and unpaid interest. The difference between the carrying value of the 2025 Senior Secured Notes on the date they were redeemed and the amount for which they were redeemed was $69.9 million and was recorded as a Loss on extinguishment of debt in the Consolidated Statements of Operations.

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During the year ended December 31, 2022, we made a number of open market repurchases of our 2028 Senior Notes and our 2025 Senior Notes that resulted in the extinguishment of $24.9 million in principal of the 2028 Senior Notes and $5.0 million in principal of the 2025 Senior Notes. Total cash consideration paid to repurchase the principal amount outstanding of the 2028 Senior Notes and the 2025 Senior Notes, excluding accrued interest, totaled $25.9 million and we recognized a $3.8 million gain on the extinguishment of this debt during the year ended December 31, 2022.

During the year ended December 31, 2021, we made a number of open market repurchases of our 2028 Senior Notes and our 2025 Senior Notes that resulted in the extinguishment of $173.5 million in principal of the 2028 Senior Notes and $55.5 million in principal of the 2025 Senior Notes. Total cash consideration paid to repurchase the principal amount outstanding of the 2028 Senior Notes and the 2025 Senior Notes, excluding accrued interest, totaled $146.8 million and we recognized a $79.9 million gain on the extinguishment of debt during the year ended December 31, 2021.

Catalyst Financing Obligations

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

During the years ended December 31, 2022, we settled certain of our precious metals financing arrangements, resulting in reductions of debt of approximately $56.2 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, the PBF Entities, entered into the Third Inventory Intermediation Agreement with J. Aron. Pursuant to the Third Inventory Intermediation Agreement, J. Aron purchased and held title to the J. Aron Products purchased or produced by the Refineries and delivered into 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 a second amendment to the Third Inventory Intermediation Agreement to amend certain provisions in order to allow for the early termination of the Third 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.

Renewable Diesel Facility

On June 27, 2023, we closed on the jointly held investment in SBR. In connection with this investment, we contributed the SBR business, with an estimated fair value of $1.69 billion, excluding working capital. Eni contributed $845.6 million in cash, 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. 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.

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Share Repurchase Program

On December 12, 2022, our Board of Directors authorized the Repurchase Program. On May 3, 2023, our Board of Directors approved an increase in the repurchase authorization amount under the Repurchase Program from $500.0 million to $1.0 billion and extended the program expiration date to December 2025. On February 13, 2024, our Board of Directors approved an increase in the repurchase authorization amount under the Repurchase Program from $1.0 billion to $1.75 billion. During the year ended December 31, 2023, we purchased 12,367,073 shares of PBF Energy's Class A common stock for $532.5 million, inclusive of commissions paid, through open market transactions. During the year ended December 31, 2022, we purchased 4,192,555 shares of PBF Energy's Class A common stock for $156.4 million, inclusive of commissions paid, through open market transactions.

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.

On December 20, 2021, PBFX closed on a third-party sale of real property at the refined products terminals in the greater Philadelphia area (“East Coast Terminals”). The sale resulted in a gain of approximately $2.8 million in the fourth quarter of 2021, included within Gain on sale of assets in the Consolidated Statements of Operations.

Merger Transaction

On November 30, 2022, PBF Energy, PBF LLC, PBFX Holdings Inc., a Delaware corporation and wholly-owned subsidiary of PBF LLC (“PBFX Holdings”), Riverlands Merger Sub LLC, a Delaware limited liability company and wholly owned subsidiary of PBF LLC, PBFX, and PBF Logistics GP LLC closed on a definitive agreement (the “Merger Agreement”) pursuant to which PBF Energy and PBF LLC acquired all of the publicly held common units in PBFX representing limited partner interests in the master limited partnership not already owned by certain wholly-owned subsidiaries of PBF Energy and its affiliates (the “Merger Transaction”). Subsequent to closing on the Merger Transaction, PBFX became an indirect wholly-owned subsidiary of PBF Energy and PBF LLC.

At the effective time of the closing of the Merger Transaction, pursuant to the terms of the Merger Agreement, each PBFX Public Common Unit was converted into the right to receive: (i) 0.270 of a share of Class A Common Stock, par value $0.001 per share, of PBF Energy, (ii) $9.25 in cash, without interest and (iii) any cash in lieu of fractional shares of PBF Energy Common Stock to which the holder thereof became entitled upon surrender of such PBFX Public Common Units in accordance with the Merger Agreement. Such Merger Agreement consideration totaled $303.7 million in cash and resulted in the issuance of 8,864,684 shares of PBF Energy Class A common stock. The PBFX Common Units owned by PBF LLC and PBFX Holdings and the non-economic general partner interest remain outstanding and were unaffected by the Merger Transaction. There was no change in ownership of the non-economic general partner interest.

East Coast Refining Reconfiguration

In 2022, we restarted several processing units at the Paulsboro refinery, that were temporarily idled in 2020 as part of the East Coast Refining Reconfiguration. Based on this reconfiguration and subsequent restart of several processing units, our East Coast throughput capacity currently approximates 335,000 barrels per day.

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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. We have recognized, as of December 31, 2023, a liability for the Tax Receivable Agreement of $336.6 million ($338.6 million and $48.3 million as of December 31, 2022 and December 31, 2021, respectively) reflecting our estimate of the undiscounted amounts that we expect to pay under the agreement. As of December 31, 2023, $43.0 million of the Tax Receivable Agreement obligation was recorded as a Current liability and represents the amount paid in January 2024 related to the 2022 tax year. As future taxable income is recognized, increases in our Tax Receivable Agreement liability may be necessary in conjunction with the revaluation of deferred tax assets. Refer to “Note 11 - Commitments and Contingencies” and “Note 18 - Income Taxes” of our Notes to Consolidated Financial Statements for more details.

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 $762.3 million in RINs costs during the year ended December 31, 2023 as compared to $1,225.5 million and $726.0 million during the years ended December 31, 2022 and 2021, 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.

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

Benchmark Refining Margins

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

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

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

Credit Risk Management

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

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

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

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

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

Refinery-Specific Information

The following section includes refinery-specific information related to our operations, 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% gasoline, 35% distillate, 2% high-value Group I lubricants, 1% high-value petrochemicals, with the remaining portion of the product slate comprised of lower-value products (4% LPGs, 15% black oil 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; and

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•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 priced at a significant discount to RBOB and ULSD.

•the Paulsboro refinery produces Group I lubricants, which 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 50% gasoline, 37% distillate, 4% 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 5% black oil). For this reason, we believe the WTI (Chicago) 4-3-1 is an appropriate benchmark industry refining margin. The majority of Toledo revenues are generated off Chicago-based market prices.

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

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

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

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

Chalmette Refinery. The benchmark refining margin for the Chalmette refinery is calculated by assuming two barrels of LLS crude oil are converted into one barrel of gasoline and one barrel of diesel. We calculate this benchmark using the US Gulf Coast market value of 87 conventional gasoline and ULSD against the market value of LLS and refer to this benchmark as the LLS (Gulf Coast) 2-1-1 benchmark refining margin. Our Chalmette refinery has a product slate of approximately 47% gasoline and 34% distillate, 1% high-value petrochemicals with the remaining portion of the product slate comprised of lower-value products (6% black oil, 5% LPGs, 2% petroleum coke, and 5% 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 has recently 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 heavy, sour crude slate processed at Chalmette, we produce lower-value products including sulfur and petroleum coke. These products are priced at a significant discount to 87 conventional gasoline and ULSD.

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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 54% gasoline and 29% distillate with the remaining portion of the product slate comprised of lower-value products (5% black oil, 2% LPG and 10% 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 65% 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 priced at a significant discount to gasoline and diesel.

Martinez Refinery. The benchmark refining margin for the Martinez refinery is calculated by assuming that three barrels of ANS crude oil are converted into two barrels of gasoline, one-quarter barrel of diesel and three-quarter barrel of jet fuel. We calculate this benchmark using the West Coast San Francisco market value of CARBOB, CARB diesel and jet fuel and refer to the benchmark as the ANS (West Coast) 3-2-1 benchmark refining margin. Our Martinez refinery has a product slate of approximately 57% gasoline and 31% distillate with the remaining portion of the product slate comprised of lower-value products (4% black oil petroleum coke, 4% LPG 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 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, 2023, 2022 and 2021 (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.