PBF Energy Inc

Previous wording

•rate of inflation and its impacts on supply and demand, pricing, and supply chain disruption;

Current wording

•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;

Previous wording

•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;

Current wording

•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;

Previous wording

•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;

Current wording

•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;

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

•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

Current wording

•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;

Previous wording

•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.

Current wording

•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

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

Overview— PBF Energy net income was $2,162.0 million for the year ended December 31, 2023 compared to net income of $2,972.8 million for the year ended December 31, 2022. Net income attributable to PBF Energy stockholders was $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) compared to net income attributable to PBF Energy stockholders of $2,876.8 million, or $22.84 per diluted share, for the year ended December 31, 2022 ($22.84 per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income, or $23.36 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 attributable to PBF Energy stockholders represents PBF Energy’s equity interest in PBF LLC’s pre-tax income, less applicable income tax expense. PBF Energy’s weighted-average equity interest in PBF LLC was 99.3% for both the year ended December 31, 2023 and 2022.

Current wording

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.

Previous wording

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, related to changes in our earn-out obligation associated with the acquisition of the Martinez refinery and logistic assets (the “Martinez Contingent Consideration”), 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 Third Inventory Intermediation Agreement of $13.5 million, or $10.0 million, net of tax. Our results for the year ended December 31, 2022 were negatively impacted by special items consisting of pre-tax charges associated with the change in the Tax Receivable Agreement liability of $290.3 million, or $215.1 million net of tax, a net loss on the extinguishment of debt mainly associated with the redemption of our 2025 Senior Secured Notes of $66.1 million, or $49.0 million net of tax, and net changes in fair value of contingent consideration of $48.3 million, or $35.8 million net of tax, partially offset by a $233.8 million tax benefit associated with the remeasurement of certain deferred tax assets.

Current wording

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.

Previous wording

Excluding the impact of these special items, when comparing our results to the year ended December 31, 2022, we experienced an overall decrease in our refining margins due to unfavorable movements in crack spreads and crude oil differentials, as well as planned and unplanned maintenance, primarily at our West Coast refineries. 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. Refined product margins primarily benefited in 2022 from global supply disruptions, caused in large part by the conflict between Russia and Ukraine.

Current wording

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.

Previous wording

Revenues— Revenues totaled $38.3 billion for the year ended December 31, 2023 compared to $46.8 billion for the year ended December 31, 2022, a decrease of approximately $8.5 billion or 18.2%. Revenues per barrel sold were $100.85 and $123.26 for the years ended December 31, 2023 and 2022, respectively, a decrease of 18.2% directly related to lower hydrocarbon commodity prices. 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, 2022, the total throughput rates at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 300,300 bpd, 148,500 bpd, 180,700 bpd and 295,600 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. For the year ended December 31, 2022, the total barrels sold at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 353,800 bpd, 158,200 bpd, 190,600 bpd and 338,400 bpd, respectively.

Current wording

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.

Previous wording

Overall average throughput rates were lower in the year ended December 31, 2023 due to increased maintenance activity and lower demand compared to the same period in 2022. We plan to continue operating our refineries based on demand and current market conditions. Total refined product barrels sold were slightly higher than throughput rates, reflecting sales from inventory as well as sales and purchases of refined products outside our refineries.

Current wording

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.

Previous wording

Consolidated gross margin—Consolidated gross margin totaled $2,398.6 million for the year ended December 31, 2023, compared to $4,678.6 million for the year ended December 31, 2022, a decrease of $2,280.0 million. Gross refining margin (as described below in Non-GAAP Financial Measures) totaled $5,287.7 million, or $16.07 per barrel of throughput, for the year ended December 31, 2023 compared to $7,429.9 million, or $22.00 per barrel of throughput, for the year ended December 31, 2022, a decrease of approximately $2,142.2 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. During the years ended December 31, 2023 and December 31, 2022, our margin calculations were not impacted by special items.

Current wording

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.

Previous wording

Additionally, our results continue to be impacted by significant costs to comply with the RFS. Total RFS compliance costs were $762.3 million for the year ended December 31, 2023 compared to $1,225.5 million for the year ended December 31, 2022.

Current wording

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.

Previous wording

Average industry margins were unfavorable during the year ended December 31, 2023 compared 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.

Current wording

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.

Previous wording

On the East Coast, the Dated Brent (NYH) 2-1-1 industry crack spread was approximately $29.67 per barrel, or 26.3% lower, in the year ended December 31, 2023, as compared to $40.26 per barrel in the same period in 2022. Our margins were positively impacted from our refinery specific slate on the East Coast by strengthened WTI/Bakken differential, which increased by $2.77 per barrel, offset by weakened Dated Brent/Maya differential, which decreased by $0.24 per barrel compared to the same period in 2022. The WTI/WCS differential decreased to $18.32 per barrel in 2023 compared to $21.30 per barrel in 2022, which unfavorably impacted our cost of heavy Canadian crude.

Current wording

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.

Previous wording

Across the Mid-Continent, the WTI (Chicago) 4-3-1 industry crack spread was $23.71 per barrel, or 24.9% lower, in the year ended December 31, 2023, as compared to $31.56 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 premium of $1.28 per barrel in the year ended December 31, 2023, as compared to a premium of $4.05 per barrel in the prior year. Additionally, the WTI/Syncrude differential averaged a premium of $0.91 per barrel for the year ended December 31, 2023 as compared to a premium of $3.04 per barrel in the prior year.

Current wording

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.

Previous wording

On the Gulf Coast, the LLS (Gulf Coast) 2-1-1 industry crack spread was $29.13 per barrel, or 22.4% lower, in the year ended December 31, 2023 as compared to $37.56 per barrel in the prior year. Margins on the Gulf Coast were negatively impacted from our refinery specific slate by a weakening WTI/LLS differential, which averaged a premium of $2.48 per barrel for the year ended December 31, 2023 as compared to a premium of $2.22 per barrel in the prior year.

Current wording

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.

Previous wording

On the West Coast, the ANS (West Coast) 4-3-1 industry crack spread was $36.88 per barrel, or 11.4% lower, in the year ended December 31, 2023 as compared to $41.64 per barrel in the prior year. Additionally, the ANS (West Coast) 3-2-1 industry crack spread was $36.89 per barrel, or 11.9% lower, in the year ended December 31, 2023 as compared to $41.89 per barrel in the prior year. Our margins on the West Coast were negatively impacted from our refinery specific slate by a weakening WTI/ANS differential, which averaged a premium of $4.70 per barrel for the year ended December 31, 2023 as compared to a premium of $4.17 per barrel in the prior year.

Current wording

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.

Previous wording

Operating expenses— Operating expenses totaled $2,694.9 million for the year ended December 31, 2023 compared to $2,599.0 million for the year ended December 31, 2022, an increase of approximately $95.9 million, or 3.7%. Of the total $2,694.9 million in operating expenses, $2,581.3 million, or $7.85 per barrel of throughput, related to expenses incurred by the Refining segment, while the remaining $113.6 million related to expenses incurred by the Logistics segment ($2,495.6 million or $7.39 per barrel of throughput, and $103.4 million of operating expenses for the year ended December 31, 2022 related to the Refining and Logistics segments, respectively). The increase in operating expenses was mainly attributable to higher maintenance and operational costs primarily due to unplanned downtime, partially offset by lower energy expenses driven by lower natural gas prices.

Current wording

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.

Previous wording

General and administrative expenses— General and administrative expenses totaled $362.5 million for the year ended December 31, 2023, compared to $468.7 million for the year ended December 31, 2022, a decrease of $106.2 million or 22.7%. Our general and administrative expenses were lower in comparison to the prior year due to lower employee-related expenses, including lower incentive compensation. General and administrative costs are comprised of personnel, facilities and other infrastructure costs necessary to support our refineries and related logistics assets.

Current wording

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.

Previous wording

Gain on formation of 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.

Current wording

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.

Previous wording

(Gain) loss on sale of 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. There was a loss of $0.9 million for the year ended December 31, 2022 related primarily to the sale of non-operating refinery assets.

Current wording

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.

Previous wording

Depreciation and amortization expense— Depreciation and amortization expense totaled $571.5 million for the year ended December 31, 2023 (including $560.0 million recorded within Cost of sales) compared to $511.1 million for the year ended December 31, 2022 (including $503.6 million recorded within Cost of sales), an increase of $60.4 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.

Current wording

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.

Previous wording

Change in fair value of contingent consideration, net— Change in fair value of contingent consideration represented a gain of $45.8 million and a loss of $48.3 million for the years ended December 31, 2023 and December 31, 2022, respectively. These gains and losses were primarily related to changes in the estimated fair value of the Martinez Contingent Consideration.

Current wording

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.

Previous wording

Change in Tax Receivable Agreement liability— The change in the Tax Receivable Agreement liability for the year ended December 31, 2023, represented a benefit of $2.0 million. Changes in the Tax Receivable Agreement liability for the year ended December 31, 2022 represented a charge of $290.3 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.

Current wording

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.

Previous wording

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, compared to a loss of $2.0 million for the year ended December 31, 2022. These gains and losses relate 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.

Current wording

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.