PBF Energy Inc.

Previous 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;

Current wording

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

Previous 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;

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

Previous wording

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

Current wording

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

Previous wording

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

Current wording

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

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 for approximately $664.5 million.

Current wording

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

Previous wording

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.

Current wording

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

Previous 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.

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.

Previous 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.

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 & Company, a subsidiary of The Goldman Sachs Group, Inc. (“J. Aron”). Pursuant to the Inventory Intermediation Agreement, J. Aron purchased and held title to certain crude oil, intermediates, and finished products (the “J. Aron Products”) purchased or produced by the Paulsboro and Delaware City refineries (and at the election of the PBF Entities, the Chalmette refinery) (collectively, the “Refineries”) and delivered into the storage tanks at the Refineries (the “Storage Tanks”). The J. Aron Products were sold back to us as the J. Aron Products were discharged out of the Storage Tanks.

Previous 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.

Current wording

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

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. 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.

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, 2025, a liability for the Tax Receivable Agreement of $168.2 million was recorded ($293.6 million and $336.6 million as of December 31, 2024 and December 31, 2023, respectively) reflecting our estimate of the undiscounted amounts that we expect to pay under the agreement. As future taxable income is recognized, increases in our Tax Receivable Agreement liability may be necessary in conjunction with the revaluation of deferred tax assets. Refer to “Note 11 - Commitments and Contingencies” and “Note 18 - Income Taxes” of our Notes to Consolidated Financial Statements for more details.

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 $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.

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 $680.1 million in RINs costs during the year ended December 31, 2025 as compared to $515.3 million and $762.3 million during the years ended December 31, 2024 and 2023, respectively. The fluctuations in RINs costs are due primarily to volatility in prices for ethanol-linked RINs and changes in our production of on-road transportation fuels. Our RINs purchase obligation is dependent on our actual shipment of on-road transportation fuels domestically and the amount of blending achieved.

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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

Current wording

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

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 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.

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 39% distillate, 37% gasoline, 2% high-value Group I lubricants, 1% high-value petrochemicals, with the remaining portion of the product slate comprised of lower-value products (14% black oil, 3% LPGs, and 4% other). For this reason, we believe the Dated Brent (NYH) 2-1-1 is an appropriate benchmark industry refining margin. The majority of East Coast refining revenues are generated off NYH-based market prices.

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; and

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

Previous wording

•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.

Current wording

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

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 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.

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 52% gasoline, 38% distillate, 3% high-value petrochemicals (including nonene, tetramer, benzene, xylene and toluene) with the remaining portion of the product slate comprised of lower-value products (4% LPGs and 3% black oil). For this reason, we believe the WTI (Chicago) 4-3-1 is an appropriate benchmark industry refining margin. The majority of Toledo revenues are generated off Chicago-based market prices.

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 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.

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 46% gasoline and 31% distillate, 1% high-value petrochemicals with the remaining portion of the product slate comprised of lower-value products (9% black oil, 5% LPGs, and 8% other). For this reason, we believe the LLS (Gulf Coast) 2-1-1 is an appropriate benchmark industry refining margin. The majority of Chalmette revenues are generated off Gulf Coast-based market prices.

Previous wording

•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

Current wording

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

Previous wording

•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.

Current wording

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

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 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.

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 57% gasoline and 29% distillate with the remaining portion of the product slate comprised of lower-value products (3% LPG, 2% black oil and 9% other). For this reason, we believe the ANS (West Coast) 4-3-1 is an appropriate benchmark industry refining margin. The majority of Torrance revenues are generated off West Coast Los Angeles-based market prices.

Previous wording

•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

Current wording

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

Previous wording

•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.

Current wording

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

Previous wording

•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.

Current wording

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

Previous 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.

Current wording

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

Previous 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.

Current wording

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

Previous 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.

Current wording

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

Previous 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.

Current wording

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

Previous 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.

Current wording

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

Previous wording

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.

Current wording

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

Previous 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.

Current wording

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

Previous 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.

Current wording

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

Previous 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.

Current wording

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

Previous 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.

Current wording

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

Previous 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.

Current wording

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

Previous 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.

Current wording

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

Previous 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.

Current wording

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

Previous 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.

Current wording

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

Previous 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.

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 no such gain or loss during the year ended December 31, 2025.