PBF Finance 10-K2023 FY Annual report

This Annual Report on Form 10-K is filed by PBF Holding Company LLC (“PBF Holding”) and PBF Finance Corporation (“PBF Finance”). PBF Holding is a wholly-owned subsidiary of PBF Energy Company LLC (“PBF LLC”) and is the parent company for PBF LLC's refinery operating subsidiaries. PBF Finance is a wholly-owned subsidiary of PBF Holding. PBF Holding is an indirect subsidiary of PBF Energy Inc. (“PBF Energy”), which is the sole managing member of, and owner of an equity interest representing approximately 99.3% of the outstanding economic interests in PBF LLC as of December 31, 2023. PBF Energy operates and controls all of the business and affairs and consolidates the financial results of PBF LLC and its subsidiaries. PBF Holding, together with its consolidated subsidiaries, owns and operates oil refineries and related facilities in North America.

In this Annual Report on Form 10-K, unless the context otherwise requires, references to the “Company,” “we,” “our” or “us” refer to PBF Holding, and, in each case, unless the context otherwise requires, its consolidated subsidiaries. References to “subsidiary guarantors” refer to PBF Services Company LLC (“PBF Services”), PBF Power Marketing LLC (“PBF Power”), Paulsboro Refining Company LLC (“PRC”), Toledo Refining Company LLC (“Toledo Refining”), Delaware City Refining Company LLC (“DCR”), PBF Investments LLC (“PBF Investments”), PBF International Inc., Chalmette Refining, L.L.C. (“Chalmette Refining”), PBF Energy Western Region LLC (“PBF Western Region”), Torrance Refining Company LLC (“Torrance Refining”), and Martinez Refining Company LLC (“MRC”), which are the subsidiaries of PBF Holding that guarantee PBF Holding’s 7.875% senior unsecured notes due 2030 (the “2030 Senior Notes”) and the 6.00% senior unsecured notes due 2028 (the “2028 Senior Notes”) as of December 31, 2023.

In this Annual Report on Form 10-K, we make certain forward-looking statements, including statements regarding our plans, strategies, objectives, expectations, intentions, and resources. You should read our forward-looking statements together with our disclosures under the heading: “Cautionary Statement Regarding Forward-Looking Statements.” When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in this Annual Report on Form 10-K under “Risk Factors” in Item 1A.

We are one of the largest independent petroleum refiners and suppliers of unbranded transportation fuels, heating oil, petrochemical feedstocks, lubricants and other petroleum products in the United States. We sell our products throughout the Northeast, Midwest, Gulf Coast and West Coast of the United States, as well as in other regions of the United States, Canada and Mexico and are able to ship products to other international destinations. We own and operate six domestic oil refineries and related assets. 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. The Company’s six oil refineries represent one reportable segment.

We are a Delaware limited liability company and a holding company for our operating subsidiaries. PBF Finance is a wholly-owned subsidiary of PBF Holding. We are a wholly-owned subsidiary of PBF LLC, and PBF Energy is the sole managing member of, and owner of an equity interest as of December 31, 2023 representing approximately 99.3% of the outstanding economic interests in PBF LLC.

On December 18, 2012, our indirect parent, PBF Energy completed its IPO. As a result of PBF Energy’s IPO and related organization transactions, PBF Energy became the sole managing member of PBF LLC and operates and controls all of its business and affairs and consolidates the financial results of PBF LLC and its subsidiaries, including PBF Holding and PBF Finance. As of December 31, 2023, PBF Energy held 120,461,851 PBF LLC Series C Units and its current and former executive officers and directors and certain employees and others held 862,780 PBF LLC Series A Units and the holders of PBF Energy’s issued and outstanding shares of its Class A common stock have approximately 99.3% of the voting power in PBF Energy, and the members of PBF LLC other than PBF Energy through their holdings of Class B common stock have approximately 0.7% of the voting power in PBF Energy.

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

PBF Logistics LP (“PBFX”) is an affiliate of ours. PBFX, an indirect wholly-owned subsidiary of PBF Energy and PBF LLC, owns or leases, operates, develops and acquires crude oil and refined products terminals, pipelines, storage facilities and similar logistics assets. PBFX engages in the receiving, handling, storage and transferring of crude oil, refined products, natural gas and intermediates from sources located throughout the United States and Canada for PBF Energy in support of its refineries, as well as for third-party customers. The majority of PBFX’s revenues are derived from long-term, fee-based commercial agreements with us, which include minimum volume commitments, for receiving, handling, storing and transferring crude oil, refined products, and natural gas. PBF Energy also has agreements with PBFX that establish fees for certain general and administrative services and operational and maintenance services provided by us to PBFX.

See “Agreements with PBFX” below as well as “Note 9 - Related Party Transactions” of our Notes to Consolidated Financial Statements for additional information. See “Item 1A. Risk Factors” and “Item 13. Certain Relationships and Related Transactions, and Director Independence.”

PBF Logistics GP LLC (“PBFX GP”) serves as the general partner of PBFX. PBFX GP is wholly-owned by PBF LLC. On May 14, 2014, PBFX completed its initial public offering (the “PBFX Offering”). In connection with the PBFX Offering, we distributed to PBF LLC, which in turn contributed to PBFX, the assets and liabilities of certain crude oil terminaling assets. In a series of transactions subsequent to the PBFX Offering, we distributed certain additional assets to PBF LLC, which in turn contributed those assets to PBFX. On November 30, 2022, PBF Energy acquired all of the publicly held common units in PBFX representing limited partner interests in the MLP not already owned by certain wholly-owned subsidiaries of PBF Energy and its affiliates, and PBFX became an indirect wholly-owned subsidiary of PBF Energy.

On June 27, 2023, PBF Energy and Eni Sustainable Mobility US Inc., a subsidiary of Eni SpA (“Eni”), consummated the closing of the equity method investment transaction and the capitalization of St. Bernard Renewables LLC (“SBR”), a jointly held investee designed to own, develop, and operate the renewable diesel facility co-located with our Chalmette refinery in Louisiana (the “Renewable Diesel Facility”). In connection with this transaction, we distributed to PBF LLC, which in turn contributed to SBR, certain assets. We have no interest in SBR.

See “Agreements with SBR” below as well as “Note 9 - Related Party Transactions” of our Notes to Consolidated Financial Statements for additional information. See “Item 1A. Risk Factors” and “Item 13. Certain Relationships and Related Transactions, and Director Independence.”

Our website address is www.pbfenergy.com. Information contained on our website is not part of this Annual Report on Form 10-K. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any other materials filed with (or furnished to) the SEC by us are available on our website (under “Investors”) free of charge, soon after we file or furnish such material.

We own and operate six refineries (two of which are operated as a single unit) that provide us with geographic and market diversity. We produce a variety of products at each of our refineries, including gasoline, ULSD, heating oil, jet fuel, lubricants, petrochemicals and asphalt. We sell our products throughout the Northeast, Midwest, Gulf Coast and West Coast of the United States, as well as in other regions of the United States, Canada and Mexico, and are able to ship products to other international destinations.

Our refinery assets as of December 31, 2023 are described below.

As a result of its configuration and process units, Delaware City has the capability of processing a slate of heavy crudes with a high concentration of high sulfur crudes, as well as other high sulfur feedstock when economically viable, and is one of the largest and most complex refineries on the East Coast. The Delaware City refinery is one of two heavy crude processing refineries, the other being our Paulsboro refinery, on the East Coast of the United States. The Delaware City coking capacity is equal to approximately 25% of crude capacity.

The Delaware City refinery primarily processes a variety of medium to heavy, sour crude oils, but can run light, sweet crude oils as well. The refinery has large conversion capacity with its 82,000 bpd FCC unit, 54,500 bpd fluid coking unit and 24,000 bpd hydrocracking unit.

Pursuant to the Third Inventory Intermediation Agreement, J. Aron had purchased and held title to certain inventory, including crude oil, intermediate and certain 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 our storage tanks at the Refineries (the “Storage Tanks”). Following the early termination, we purchased, and now own all of the inventory previously held by J. Aron.

Under normal operating conditions, the Paulsboro refinery currently consumes approximately 40,000 MMBTU per day of natural gas supplied via pipeline from third parties. The Paulsboro refinery is mostly self-sufficient for electrical power through a mix of gas and steam turbine generators. The Paulsboro refinery generation supplies all of the 20MW total refinery load. There are circumstances where available generation is greater than the total refinery load, and the Paulsboro refinery can export up to about 40MW of power to the utility grid if warranted. If necessary, supplemental electrical power is available on a guaranteed basis from the local utility. The Paulsboro refinery is connected to the grid via three separate 69KV aerial feeders and has the ability to run entirely on imported power. Steam is produced in three boilers and a heat recovery steam generator fed by the exhaust from the gas turbine. In addition, there are a number of waste heat boilers and furnace stack economizers throughout the refinery that supplement the steam generation capacity. The Paulsboro refinery’s hydrogen needs are met by the steam methane reformer and the catalytic reformer.

The following table approximates the Toledo refinery’s current major process unit capacities. Unit capacities are shown in barrels per stream day.

We have an agreement with Sunoco whereby Sunoco purchases gasoline and distillate products representing approximately one-third of the Toledo refinery’s gasoline and distillates production. The agreement expires in June 2025, subject to certain early termination rights. We sell the bulk of the petrochemicals produced at the Toledo refinery through short-term contracts or on the spot market and the majority of the petrochemical distribution is done via rail.

The following table approximates the Chalmette refinery’s current major process unit capacities. Unit capacities are shown in barrels per stream day.

The following table approximates the Torrance refinery’s current major process unit capacities. Unit capacities are shown in barrels per stream day.

The following table approximates the Martinez refinery’s current major process unit capacities. Unit capacities are shown in barrels per stream day.

Beginning with the completion of the PBFX Offering, we have entered into a series of agreements with PBFX, including commercial and operational agreements. Each of these agreements and their impact to our operations is outlined below.

Immediately prior to the closing of certain contribution agreements, which PBF LLC entered into with PBFX (as defined in the table below, and collectively referred to as the “Contribution Agreements”), we contributed certain assets to PBF LLC. PBF LLC in turn contributed those assets to PBFX pursuant to the Contribution Agreements. Certain proceeds received by PBF LLC from PBFX in accordance with the Contribution Agreements were subsequently contributed by PBF LLC to us. The Contribution Agreements include the following:

PBFX currently derives the majority of its revenue from long-term, fee-based agreements with us, which generally include a minimum volume commitment, as applicable, and are supported by contractual fee escalations for inflation adjustments and certain increases in operating costs. We believe the terms and conditions under these agreements, as well as the Omnibus Agreement and the Services Agreement (each as defined below), each with PBFX, are generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services.

In addition to the commercial agreements described above, PBFX entered into an omnibus agreement, which has been amended and restated in connection with the closing of certain of the Contribution Agreements with PBFX GP, PBF LLC and us (as amended, the “Omnibus Agreement”). The Omnibus Agreement addresses the payment of an annual fee for the provision of various general and administrative services and reimbursement of salary and benefit costs for certain PBF Energy employees.

The annual fee under the Omnibus Agreement for the year ended December 31, 2023 was $7.9 million, inclusive of obligations under the Omnibus Agreement to reimburse us for certain compensation and benefit costs of employees who devoted more than 50% of their time to PBFX during the year ended December 31, 2023. We currently estimate to receive $6.0 million, inclusive of estimated obligations under the Omnibus Agreement as a reimbursement for certain compensation and benefit costs of employees who devote more than 50% of their time to PBFX for the year ending December 31, 2024.

Additionally, PBFX entered into an operation and management services and secondment agreement with us and certain of our subsidiaries (as amended, the “Services Agreement”), pursuant to which we provide PBFX with the personnel necessary for PBFX to perform its obligations under its commercial agreements. PBFX reimburses us for the use of such employees and the provision of certain infrastructure-related services to the extent applicable to its operations, including storm water discharge and waste water treatment, steam, potable water, access to certain roads and grounds, sanitary sewer access, electrical power, emergency response, filter press, fuel gas, API solids treatment, fire water and compressed air. For the year ended December 31, 2023, PBFX paid us an annual fee of $8.7 million pursuant to the Services Agreement and we currently estimate to receive the same annual reimbursement pursuant to the Services Agreement for the year ending December 31, 2024.

The Services Agreement will terminate upon the termination of the Omnibus Agreement, provided that PBFX may terminate any service on 30-days’ notice.

Refer to “Note 9 - Related Party Transactions” of our Notes to Consolidated Financial Statements for further discussion regarding the above agreements with PBFX and SBR.

Our refineries make various grades of gasoline, distillates (including diesel fuel, jet fuel, and ULSD) and other products from crude oil, other feedstocks, and blending components. We sell these products through our commercial accounts, and sales with major oil companies. For the years ended December 31, 2023, 2022 and 2021, gasoline and distillates accounted for 88.8%, 88.6% and 86.4% of our revenues, respectively.

We sell a variety of refined products to a diverse customer base. The majority of our refined products are primarily sold through short-term contracts or on the spot market. In addition, we have product offtake arrangements for a portion of our clean products. For the years ended December 31, 2023 and December 31, 2022 only one customer, Shell plc (“Shell”), accounted for 10% or more of our revenues (approximately 14% and 14%, respectively). As of December 31, 2023 and December 31, 2022, only one customer, Shell, accounted for 10% or more of our total trade accounts receivable (approximately 19% and 19%, respectively).

Traditionally, demand for gasoline and diesel is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and construction work. Decreased demand during the winter months can lower gasoline and diesel prices. However, due to global supply disruptions, the effects of seasonality on our operating results have been less impactful in recent years.

The refining business is very competitive. We compete directly with various other refining companies on the East, Gulf and West Coasts and in the Mid-Continent, with integrated oil companies, with foreign refiners that import products into the United States and with producers and marketers in other industries supplying alternative forms of energy and fuels to satisfy the requirements of industrial, commercial and individual consumers. Some of our competitors have expanded the capacity of their refineries and internationally new refineries are coming on line which could also affect our competitive position.

Profitability in the refining industry depends largely on refined product margins, which can fluctuate significantly, as well as crude oil prices and differentials between the prices of different grades of crude oil, operating efficiency and reliability, product mix and costs of product distribution and transportation. Certain of our competitors that have larger and more complex refineries may be able to realize lower per-barrel costs or higher margins per barrel of throughput. Several of our principal competitors are integrated national or international oil companies that are larger and have substantially greater resources. Because of their integrated operations and larger capitalization, these companies may be more flexible in responding to volatile industry or market conditions, such as shortages of feedstocks or intense price fluctuations. Refining margins are frequently impacted by sharp changes in crude oil costs, which may not be immediately reflected in product prices.

The refining industry is also highly competitive with respect to feedstock supply. Unlike certain of our competitors that have access to proprietary controlled sources of crude oil production available for use at their own refineries, we obtain all of our crude oil and substantially all other feedstocks from unaffiliated sources. The availability and cost of crude oil and feedstock are affected by global supply and demand. We have no crude oil reserves and are not engaged in the exploration or production of crude oil. We believe, however, that we will be able to obtain adequate crude oil and other feedstocks at generally competitive prices for the foreseeable future.

Pursuant to its RFS, EPA has implemented mandates to blend renewable fuels into the petroleum fuels produced and sold in the United States. Because we do not directly produce renewable fuels, increasing the volume of renewable fuels that must be blended into our products could displace an increasing volume of our refineries’ product pool, potentially resulting in lower earnings and profitability. In addition, in order to meet certain of these and future EPA requirements, we may be required to continue to purchase RINs, which historically had, and we expect to have, fluctuating costs based on market conditions.

We currently lease approximately 63,000 square feet for our principal corporate offices in Parsippany, New Jersey. The lease for our principal corporate offices expires in 2026. Functions performed in the Parsippany office include overall corporate management, refinery and health, safety and environmental management, planning and strategy, corporate finance, commercial operations, logistics, contract administration, marketing, investor relations, governmental affairs, accounting, tax, treasury, information technology, legal and human resources support functions.

We lease approximately 8,800 square feet for our regional corporate office in Long Beach, California. The lease for our Long Beach office expires in 2026. Functions performed in the Long Beach office include overall regional corporate management, planning and strategy, commercial operations, logistics, contract administration, marketing and governmental affairs.

We believe our responsibility to our employees, neighbors, members, other stakeholders and the environment is only fulfilled through our commitment to safety and reliability. Through rigorous training, sharing of expertise across our sites, continuous monitoring and through promoting a culture of excellence in operations, we continuously strive to keep our people, the communities in which we operate in and the environment safe.

We are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA Hazard Communication Standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances.

The development, attraction and retention of employees is a critical success factor for our Company. To support the advancement of our employees, we offer rigorous training and development programs and encourage the sharing of expertise across our sites. We actively promote inclusion and diversity in our workforce at each of our locations and provide our employees with opportunities to give back through engagement in our local communities through supportive educational programs, philanthropic and volunteer activities.

We believe that a combination of competitive compensation and career growth and development opportunities help increase employee morale and reduce voluntary turnover. Our comprehensive benefit packages are competitive in the marketplace and we believe in recognizing and rewarding talent through our various cash and equity compensation programs.

As of December 31, 2023, we had approximately 3,686 employees, of which 1,917 are covered by collective bargaining agreements. Our hourly employees are covered by collective bargaining agreements through the United Steel Workers (“USW”), the Independent Oil Workers (“IOW”) and the International Brotherhood of Electrical Workers (“IBEW”). We consider our relations with the represented employees to be satisfactory.

Our refineries, pipelines and related operations are subject to extensive and frequently changing federal, state and local laws and regulations, including, but not limited to, those relating to the discharge of materials into the environment or that otherwise relate to the protection of the environment, waste management and the characteristics and the compositions of fuels. Compliance with existing and anticipated laws and regulations can increase the overall cost of operating the refineries, including remediation, operating costs and capital costs to construct, maintain and upgrade equipment and facilities. Permits are also required under these laws for the operation of our refineries, pipelines and related operations and these permits are subject to revocation, modification and renewal. Compliance with applicable environmental laws, regulations and permits will continue to have an impact on our operations, results of operations and capital requirements. We believe that our current operations are in substantial compliance with existing environmental laws, regulations and permits.

We incorporate by reference into this Item the environmental disclosures contained in the following sections of this report:

As is the case with all companies engaged in industries similar to ours, we face potential exposure to future claims and lawsuits involving environmental and safety matters. These matters include soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances which we manufactured, handled, used, released or disposed of.

Current and future environmental regulations are expected to require additional expenditures, including expenditures for investigation and remediation, which may be significant, at our refineries and at our other facilities. To the extent that future expenditures for these purposes are material and can be reasonably determined, these costs are disclosed and accrued.

Our operations are also subject to various laws and regulations relating to occupational health and safety. We maintain safety training and maintenance programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations. Compliance with applicable health and safety laws and regulations has required and continues to require substantial expenditures.

We cannot predict what additional health, safety and environmental legislation or regulations will be enacted or become effective in the future or how existing or future laws or regulations will be administered or interpreted with respect to our operations. Compliance with more stringent laws or regulations or adverse changes in the interpretation of existing requirements or discovery of new information such as unknown contamination could have an adverse effect on the financial position and the results of our operations and could require substantial expenditures for the installation and operation of systems and equipment that we do not currently possess.

We incorporate by reference into this Item the federal and state regulatory requirements disclosures contained in the following sections of this report:

You should carefully read the risks and uncertainties described below. The risks and uncertainties described below are not the only ones facing our Company. Additional risks and uncertainties may also impair our business operations. If any of the following risks actually occur, our business, financial condition, results of operations or cash flows would likely suffer.

Our profitability, cash flows and liquidity from operations depend primarily on the margin above operating expenses (including the cost of refinery feedstocks, such as crude oil, intermediate partially refined products, and natural gas liquids that are processed and blended into refined products) at which we are able to sell refined products. Refining is primarily a margin-based business and, to increase profitability, it is important to maximize the yields of high value finished products while minimizing the costs of feedstock and operating expenses. When the margin between refined product prices and crude oil and other feedstock costs contracts, our earnings, profitability and cash flows are negatively affected. Historically, refining margins have been volatile, and are likely to continue to be volatile, as a result of a variety of factors, including fluctuations in the prices of crude oil, other feedstocks, refined products and fuel and utility services. An increase or decrease in the price of crude oil will likely result in a similar increase or decrease in prices for refined products; however, there may be a time lag in the realization, or no such realization, of the similar increase or decrease in prices for refined products. The effect of changes in crude oil prices on our refining margins therefore depends in part on how quickly and how fully refined product prices adjust to reflect these changes.

The nature of our business has required us to maintain substantial crude oil, feedstock and refined product inventories. Because crude oil, feedstock and refined products are commodities, we have no control over the changing market value of these inventories. Our crude oil, feedstock and refined product inventories are valued at the LCM value under the last-in-first-out (“LIFO”) inventory valuation methodology. At December 31, 2023 and December 31, 2022, the replacement value of inventories exceeded the LIFO carrying value, therefore no LCM inventory reserve was recorded. If the market value of our crude oil, feedstock and refined product inventory declines to an amount less than our LIFO cost, we would record a write-down of inventory and a non-cash impact to cost of products and other.

Prices of crude oil, other feedstocks, blendstocks, and refined products depend on numerous factors beyond our control, including the supply of and demand for crude oil, other feedstocks, gasoline, diesel, ethanol, asphalt and other refined products. Such supply and demand are affected by a variety of economic, market, environmental and political conditions.

Our direct operating expense structure also impacts our profitability. Our major direct operating expenses include employee and contract labor, maintenance and energy. Our predominant variable direct operating cost is energy, which is comprised primarily of fuel and other utility services. The volatility in costs of fuel, principally natural gas, and other utility services, principally electricity, used by our refineries and other operations affect our operating costs. Fuel and utility prices have been, and will continue to be, affected by factors outside our control, such as supply and demand for fuel and utility services in both local and regional markets. Natural gas prices have historically been volatile and, typically, electricity prices fluctuate with natural gas prices. Future increases in fuel and utility prices may have a negative effect on our refining margins, profitability and cash flows.

Payment terms for our crude oil purchases are typically longer than those terms we extend to our customers for sales of refined products. Additionally, reductions in crude oil purchases tend to lag demand decreases for our refined products. As a result of this timing differential, the payables for our crude oil purchases are generally proportionally larger than the receivables for our refined product sales. As we are normally in a net payables position, a decrease in commodity prices generally results in a use of working capital. Given we process a significant volume of crude oil, the impact can materially affect our working capital, cash flows and liquidity.

A significant portion of our profitability is derived from the ability to purchase and process crude oil feedstocks that historically have been less expensive than benchmark crude oils, such as the heavy, sour crude oils processed at our Delaware City, Paulsboro, Chalmette, Torrance and Martinez refineries. For our Toledo refinery, aside from recent crude differential volatility, purchased crude prices have historically been above the WTI benchmark, however, such crude slate typically results in favorable refinery production yield. For all locations, these crude oil differentials can vary significantly from quarter to quarter depending on overall economic conditions and trends and conditions within the markets for crude oil and refined products. Any change in these crude oil differentials may have an impact on our earnings. Our rail investment and strategy to acquire cost advantaged Mid-Continent and Canadian crude, which are priced based on WTI, could be adversely affected when the WTI/Dated Brent or related differentials narrow. A narrowing of the WTI/Dated Brent differential may result in our Toledo refinery losing a portion of its crude oil price advantage over certain of our competitors, which negatively impacts our profitability. In addition, imbalances between the production and capacity to export crude in Canada may continue to result in price volatility and the narrowing of the WTI/WCS differential, which is a proxy for the difference between light U.S. and heavy Canadian crude oil, and may reduce our refining margins and adversely affect our profitability and earnings. Divergent views have been expressed as to the expected magnitude of changes to these crude differentials in future periods. Any continued or further narrowing of these differentials could have a material adverse effect on our business and profitability.

Additionally, governmental and regulatory actions, including continued resolutions by the Organization of the Petroleum Exporting Countries to restrict crude oil production levels and executive actions by the current U.S. presidential administration to restrict the advancement of certain energy infrastructure projects such as the Keystone XL pipeline or Enbridge’s Line 5 pipeline, may continue to impact crude oil prices and crude oil differentials. Any increase in crude oil prices or unfavorable movements in crude oil differentials due to such actions or changing regulatory environment may negatively impact our ability to acquire crude oil at economical prices and could have a material adverse effect on our business and profitability.

Our business currently consists of owning and operating six refineries and related assets. As a result, our operations could be subject to significant interruption if any of our refineries were to experience a major accident, be damaged by severe weather or other natural disaster, or otherwise be forced to shut down or curtail production due to unforeseen events, such as acts of God, nature, orders of governmental authorities, supply chain disruptions impacting our crude rail facilities or other logistics assets, power outages, acts of terrorism, fires, toxic emissions and maritime hazards. Any such shutdown or disruption would reduce the production from that refinery. There is also risk of mechanical failure and equipment shutdowns both in general and following unforeseen events. Further, in such situations, undamaged refinery processing units may be dependent on or interact with damaged sections of our refineries and, accordingly, are also subject to being shut down. In the event any of our refineries is forced to shut down for a significant period of time, it would have a material adverse effect on our earnings, our other results of operations and our financial condition as a whole.

As protection against these hazards, we maintain insurance coverage for our refineries against some, but not all, such potential losses and liabilities, including claims against us by third parties relating to our operations and products. We may not be able to maintain or obtain insurance of the type and amount desired at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may increase substantially. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, coverage for hurricane damage can be limited, and coverage for terrorism risks can include broad exclusions. If we were to incur a significant liability that was not fully insured, it could have a material adverse effect on our financial position.

Our insurance program includes a number of insurance carriers. Significant disruptions in financial markets could lead to a deterioration in the financial condition of many financial institutions, including insurance companies and, therefore, we may not be able to obtain the full amount of our insurance coverage for insured events. Even where we have insurance in place, there can be no assurance that the carriers will honor their obligations under the policies.

Our Toledo, Chalmette, Torrance and Martinez refineries receive a significant portion of their crude oil through our owned, as well as third party, pipelines. These pipelines include the Enbridge system, Capline and Mid-Valley pipelines for supplying crude to our Toledo refinery, the MOEM Pipeline (which is owned by PBFX) and CAM Pipeline for supplying crude to our Chalmette refinery and the San Joaquin Pipeline, San Pablo Bay Pipeline, San Ardo and Coastal Pipeline systems for supplying crude to our Torrance and Martinez refineries. Additionally, our Toledo, Chalmette, Torrance and Martinez refineries deliver a significant portion of the refined products through pipelines. These pipelines include pipelines such as the Sunoco Logistics Partners L.P. and Buckeye Partners L.P. pipelines at the Toledo refinery, the Collins pipeline (which is owned by PBFX) at our Chalmette refinery, the Jet Pipeline to the Los Angeles International Airport, the Product Pipeline to Vernon and the Product Pipeline to Atwood at our Torrance refinery and the KinderMorgan SFPP North Pipeline at our Martinez refinery. We could experience an interruption of supply or delivery, or an increased cost of receiving crude oil and delivering refined products to market, if the ability of these pipelines to transport crude oil or refined products is disrupted because of accidents, weather interruptions, governmental regulation, terrorism, other third-party action or casualty or other events.

The Delaware City rail unloading facilities and the assets acquired in connection with the acquisition of CPI Operations LLC (the “East Coast Storage Assets”), allow our East Coast Refining System to source WTI-based crudes from Western Canada and the Mid-Continent, which may provide significant cost advantages versus traditional Brent-based international crudes in certain market environments. Any disruptions or restrictions to our supply of crude by rail due to problems with third-party logistics infrastructure or operations or as a result of increased regulations, could increase our crude costs and negatively impact our results of operations and cash flows.

Due to the common carrier regulatory obligation applicable to interstate oil pipelines, capacity allocation among shippers can become contentious in the event demand is in excess of capacity. Therefore, nominations by new shippers or increased nominations by existing shippers may reduce the capacity available to us. Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that we rely upon for transportation of crude oil and refined products could have a further material adverse effect on our business, financial condition, results of operations and cash flows.

In addition, substantial weather-related conditions could impact our relationships and arrangements with our major customers and suppliers by materially affecting the normal flow of crude oil and refined products, especially seaborne transactions. For example, severe weather events could damage transportation infrastructures and lead to interruptions of our operations, including our ability to deliver our products, or increases in costs to receive crude oil.

Pursuant to the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007, EPA has issued the RFS, implementing mandates to blend renewable fuels into the petroleum fuels produced and sold in the United States. Under the RFS, the volume of renewable fuels that obligated refineries must blend into their finished petroleum fuels historically has increased on an annual basis. In addition, certain states have passed legislation that requires minimum biodiesel blending in finished distillates. On October 13, 2010, EPA raised the maximum amount of ethanol allowed under federal law from 10% to 15% for cars and light trucks manufactured since 2007. The maximum amount allowed under federal law currently remains at 10% ethanol for all other vehicles. Existing laws and regulations could change, and the minimum volumes of renewable fuels that must be blended with refined petroleum fuels may increase. Because we do not directly produce renewable fuels, increasing the volume of renewable fuels that must be blended into our products could displace an increasing volume of our refinery’s product pool, potentially resulting in lower earnings and profitability. In addition, in order to meet certain of these and future EPA requirements, we may be required to purchase RINs, which may have fluctuating costs based on market conditions. Our results continue to be impacted by significant costs to comply with the RFS. While we have entered into agreements with SBR that allow us to purchase RINs at our election, we incurred approximately $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 our RINs costs are due primarily to volatility in prices for ethanol-linked RINs and increases in our production of on-road transportation fuels since 2012. Our RINs purchase obligation is dependent on our actual shipment of on-road transportation fuels domestically and the amount of blending achieved which can cause variability in our profitability. On June 21, 2023, EPA finalized the volumes of renewable fuels that obligated refineries must blend into their final petroleum fuels for years 2023, 2024, and 2025, and finalized volume requirements and percentage standards under the RFS program for 2023, 2024, and 2025, as well as making a series of important modifications to strengthen and expand the RFS program. As a result, we could also experience fluctuating compliance costs in the future if the volumes finalized by EPA differ from what has been proposed.

If we cannot generate sufficient cash flows or otherwise secure sufficient liquidity to support our short-term and long-term capital requirements, we may not be able to meet our payment obligations or our future debt obligations, comply with certain deadlines related to environmental regulations and standards, or pursue our business strategies, including acquisitions, in which case our operations may not perform as we currently expect. We have substantial short-term capital needs and may have substantial long-term capital needs. Our short-term working capital needs are primarily related to financing certain of our crude oil and refined products inventory.

If we cannot adequately handle our crude oil and feedstock requirements or if we are required to obtain our crude oil supply at our other refineries without the benefit of the existing supply arrangements or the applicable counterparty defaults in its obligations, our crude oil pricing costs may increase as the number of days between when we pay for the crude oil and when the crude oil is delivered to us increases. Following our early termination of the Third Inventory Intermediation Agreement, we will fund all future inventory purchases with existing working capital or other available sources of liquidity. Further, if we are not able to market and sell our finished products to credit worthy customers, we may be subject to delays in the collection of our accounts receivable and exposure to additional credit risk. Such increased exposure could negatively impact our liquidity due to our increased working capital needs as a result of the increase in the amount of crude oil inventory and accounts receivable we would have to carry on our balance sheet. Our long-term needs for cash include those to repay our indebtedness and other contractual obligations, support ongoing capital expenditures for equipment maintenance and upgrades, including during turnarounds at our refineries, and to complete our routine and normally scheduled maintenance, regulatory and security expenditures.

In addition, from time to time, we are required to spend significant amounts for repairs when one or more processing units experiences temporary shutdowns. We continue to utilize significant capital to upgrade equipment, improve facilities, and reduce operational, safety and environmental risks. In connection with the Paulsboro, Torrance and Martinez acquisitions, we assumed certain significant environmental obligations, and we have assumed a portion of certain environmental liabilities that may arise in connection with the Martinez acquisition and may similarly do so in future acquisitions. We will likely incur substantial compliance costs in connection with new or changing environmental, health and safety regulations. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Our liquidity and financial condition will affect our ability to satisfy any and all of these needs or obligations.

Our operations are subject to federal, state and local laws regulating, among other things, the use and/or handling of petroleum and other regulated materials, the emission and discharge of materials into the environment, waste management, and remediation of discharges of petroleum and petroleum products, characteristics and composition of gasoline and distillates and other matters otherwise relating to the protection of the environment and the health and safety of the surrounding community. Our operations are also subject to extensive laws and regulations relating to occupational health and safety.

We cannot predict what additional environmental, health and safety legislation or regulations may be adopted in the future, or how existing or future laws or regulations may be administered or interpreted with respect to our operations. Many of these laws and regulations have become increasingly stringent over time, and the cost of compliance with these requirements can be expected to increase over time. In addition, a failure to comply with these laws and regulations could adversely impact our ability to operate. For example, MRC is subject to amendments to “Regulation 6-5: Particulate Emissions from Refinery Fluidized Catalytic Cracking Units - 2021 Amendment” (“Rule 6-5 Amendment”) requiring compliance with more stringent standards for particulate emissions from FCC units at refineries in the Bay Area that will be effective in 2026. Although MRC believes that it will achieve compliance through the alternative emissions monitoring system (“AEMS”) approved by the Bay Area Air Quality Management District (“BAAQMD”) and subject to validation as part of the settlement agreement entered into on February 12, 2024, there can be no assurance that the AEMS will be validated or achieve the required emissions reductions or that we will not incur significant additional costs to comply with the Rule 6-5 Amendment.

Certain environmental laws impose strict, and in certain circumstances, joint and several, liability for costs of investigation and cleanup of spills, discharges or releases on owners and operators of, as well as persons who arrange for treatment or disposal of regulated materials at, contaminated sites. Under these laws, we may incur liability or be required to pay penalties for past contamination, and third parties may assert claims against us for damages allegedly arising out of any past or future contamination. The potential penalties and clean-up costs for past or future spills, discharges or releases, the failure of prior owners of our facilities to complete their clean-up obligations, the liability to third parties for damage to their property, or the need to address newly-discovered information or conditions that may require a response could be significant, and the payment of these amounts could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. We believe the issue of climate change will likely continue to receive scientific and political attention, with the potential for further laws and regulations that could materially adversely affect our ongoing operations.

In addition, as many of our facilities are located near coastal areas, rising sea levels may disrupt our ability to operate those facilities or transport crude oil and refined products. Extended periods of such disruption could have an adverse effect on our results of operation. We could also incur substantial costs to protect or repair these facilities.

Both houses of Congress have actively considered legislation to reduce emissions of GHGs, such as carbon dioxide and methane, including proposals to: (i) establish a cap and trade system, (ii) create a federal renewable energy or “clean” energy standard requiring electric utilities to provide a certain percentage of power from such sources, and (iii) create enhanced incentives for use of renewable energy and increased efficiency in energy supply and use. In addition, EPA is taking steps to regulate GHGs under the existing federal Clean Air Act. EPA has adopted regulations limiting emissions of GHGs from motor vehicles, and is currently proposing new mobile source regulations further limiting GHG emissions for light- and medium- duty vehicles and heavy-duty highway vehicles. EPA has also adopted regulations addressing the permitting of GHG emissions from stationary sources, and requiring the reporting of GHG emissions from specified large GHG emission sources, including refineries. These and similar regulations could require us to incur costs to monitor and report GHG emissions or reduce emissions of GHGs associated with our operations. In addition, various states, individually as well as in some cases on a regional basis, have taken steps to control GHG emissions, including adoption of GHG reporting requirements, cap and trade systems and renewable portfolio standards (such as AB 32). On September 23, 2020 the Governor of California issued an executive order effectively banning the sale of new gasoline-powered passenger cars and trucks by 2035 and requiring zero-emission medium to heavy duty vehicles by 2045 everywhere feasible. The executive order requires state agencies to build out sufficient electric vehicle charging infrastructure. It is not possible at this time to predict the ultimate form, timing or extent of federal or state regulation. In the event we do incur increased costs as a result of increased efforts to control GHG emissions, we may not be able to pass on any of these costs to our customers. Regulatory requirements also could adversely affect demand for the refined products that we produce. Any increased costs or reduced demand could materially and adversely affect our business and results of operations.

Requirements to reduce emissions could result in increased costs to operate and maintain our facilities as well as implement and manage new emission controls and programs put in place. For example, in September 2016, the state of California enacted Senate Bill 32 which further reduces greenhouse gas emissions targets to 40 percent below 1990 levels by 2030. Two regulations implemented to achieve these goals are Cap-and-Trade and the LCFS. In 2012, CARB implemented Cap-and-Trade. This program currently places a cap on GHGs and we are required to acquire a sufficient number of credits to cover emissions from our refineries and our in-state sales of gasoline and diesel. In 2009, CARB adopted the LCFS, which required a 10% reduction in the carbon intensity of gasoline and diesel by 2020. In 2018, CARB amended the LCFS to require a 20% reduction by 2030. Compliance is achieved through blending lower carbon intensity biofuels into gasoline and diesel or by purchasing credits. Compliance with each of these programs is facilitated through a market-based credit system. If sufficient credits are unavailable for purchase or we are unable to pass through costs to our customers, we have to pay a higher price for credits or if we are otherwise unable to meet our compliance obligations, our financial condition and results of operations could be adversely affected.

As noted above, on September 23, 2020, the California Governor issued Executive Order N-79-20 (“N-79-20 Order”) intended to further reduce GHGs within the state. The N-79-20 Order sets a 2035 goal of no sale of internal combustion engines for passenger cars and pickup trucks within California, and a 2045 goal of no sale of internal combustion engine medium- and heavy-duty trucks, and off-road vehicles and equipment. However, the N-79-20 Order would still allow used internal combustion engine vehicles to be used and sold after these dates. In an effort to accomplish the 2035 goal, on August 25, 2022, CARB voted unanimously to adopt the Advanced Clean Cars II (“ACCII”) regulations. According to CARB, the ACCII regulations will rapidly scale down light-duty passenger car, truck, and SUV emissions starting with the 2026 model year through 2035. The regulations are two-pronged. First, they amend the California Zero-emission Vehicle Regulation to require an increasing number of zero-emission vehicles, and rely on advanced vehicle technologies, including battery-electric, hydrogen fuel cell electric, and plug-in hybrid electric vehicles, to meet air quality and climate change emissions standards. Second, the regulations amend the California Low-emission Vehicle Regulations to include increasingly stringent standards for gasoline cars and heavier passenger trucks to continue to reduce smog-forming emissions while the sector transitions toward 100% electrification by 2035. Similar to the ACCII, on April 28, 2023, CARB voted unanimously to adopt the Advanced Clean Fleet (“ACF”) regulations with the goal of achieving a zero-emission truck and bus fleet by 2045 everywhere feasible, and significantly earlier for certain market segments such as last mile delivery and drayage applications. The initial focus of ACF is on high-priority fleets with vehicles that are suitable for early electrification, their subhaulers, and entities that hire them. As to the 2045 goal, it is currently uncertain how the N-79-20 Order may be ultimately implemented by various California regulatory agencies. In the event we do incur increased costs as a result of increased efforts to control GHG emissions through future adopted regulatory requirements, we may not be able to pass these costs to our customers. These future regulatory requirements also could adversely affect demand for the refined products that we produce. Any increased costs or reduced demand could materially and adversely affect our business and results of operations.

We may be subject to liability for the investigation and clean-up of environmental contamination at each of the properties that we own, lease, occupy or operate and at off-site locations where we arrange for the treatment or disposal of regulated materials. We may become involved in litigation or other proceedings related to the foregoing. If we were to be held responsible for damages in any such litigation or proceedings, such costs may not be covered by insurance and may be material. Historical soil and groundwater contamination has been identified at our refineries. Currently, remediation projects for such contamination are underway in accordance with regulatory requirements at our refineries. In connection with the acquisitions of certain of our refineries and logistics assets, the prior owners have retained certain liabilities or indemnified us for certain liabilities, including those relating to pre-acquisition soil and groundwater conditions, and in some instances, we have assumed certain liabilities and environmental obligations, including certain existing and potential remediation obligations. If the prior owners fail to satisfy their obligations for any reason, or if significant liabilities arise in the areas in which we assumed liability, we may become responsible for remediation expenses and other environmental liabilities, which could have a material adverse effect on our business, financial condition, results of operations and cash flow. As a result, in addition to making capital expenditures or incurring other costs to comply with environmental laws, we also may be liable for significant environmental litigation or for investigation and remediation costs and other liabilities arising from the ownership or operation of these assets by prior owners, which could materially adversely affect our business, financial condition, results of operations and cash flow. See “Item 1. Business—Environmental, Health and Safety Matters” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations���Material Cash Requirements”.

We may also face liability arising from current or future claims alleging personal injury or property damage due to exposure to chemicals or other regulated materials, such as various perfluorinated compounds, including perfluorooctanoate, perfluorooctane sulfonate, perfluorohexane sulfonate, or other per-and polyfluoroalkyl substances (collectively, “PFAS”), asbestos, benzene, silica dust and petroleum hydrocarbons, at or from our facilities. We may also face liability for personal injury, property damage, natural resource damage or clean-up costs for the alleged migration of contamination from our properties. A significant increase in the number or success of these claims could materially adversely affect our business, financial condition, results of operations and cash flow. Recently, we have been voluntarily cooperating with various local, state and federal agencies in their review of the environmental and health effects of PFAS and additional PFAS-related laws may be developed at the local, state and federal level that could lead to our incurring liability for damages or other costs, civil or criminal proceedings, the imposition of fines and penalties, or other remedies or otherwise affect our business. Governmental inquiries or lawsuits involving PFAS could lead to our incurring liability for damages or other costs, civil or criminal proceedings, the imposition of fines and penalties, or other remedies, as well as restrictions on or added costs for our business operations going forward, including in the form of restrictions on discharges at our manufacturing facilities or otherwise. We may be subject to asserted or unasserted claims and governmental regulatory proceedings and inquiries related to the use of PFAS in a variety of jurisdictions.

Changes in law or interpretation of settled law and changes in policy, including with respect to climate change, other environmental regulations or regulations mandating efficiency standards or the use of alternative fuels or uncompetitive fuel components, could adversely affect our operations and results by increasing our cost of compliance, delaying or eliminating available business opportunities and/or preventing or limiting existing operations. Our operations also may give rise to federal, state or local government enforcement proceedings alleging non-compliance with applicable laws or regulations.

We operate in jurisdictions where very large and unpredictable punitive damage awards may occur in the context of litigation. Private plaintiffs may also initiate legal action against us for alleged environmental impacts. These parties may attempt to use the legal system to promote public policy agendas (including seeking to reduce the production and sale of hydrocarbon products through litigation targeting the company or other industry participants), gain political notoriety, or obtain monetary awards from the company. For example, in recent years, private litigation has been increasingly initiated against oil and gas companies by local and state agencies and private parties alleging climate change impacts arising from their operations and seeking damages and equitable relief. We have not had any climate change litigation initiated against us to date and we cannot reasonably predict whether any such litigation will be initiated against us or, if initiated, what the outcome would be. If any such litigation were to be initiated against us, at a minimum, we would incur legal and other expenses to defend such lawsuits, which amounts could be significant. If we failed to prevail in any such litigation and were required to pay significant damages and/or materially alter the manner in which we conduct our business, there could be a material adverse impact on our operations, financial condition or results of operations.

Our transportation activities are subject to regulation by multiple governmental agencies. The regulatory burden on the industry increases the cost of doing business and affects profitability. Additional proposals and proceedings that affect the oil industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission, the United States Department of Transportation, and the courts. We cannot predict when or whether any such proposals may become effective or what impact such proposals may have. Projected operating costs related to our pipelines reflect the recurring costs resulting from compliance with these regulations, and these costs may increase due to future acquisitions, changes in regulation, changes in use, or discovery of existing but unknown compliance issues.

Beginning in 2022, record refining industry profits raised the concern of many public policy experts and federal and state policymakers, who have questioned whether these profits were justified, or whether they constituted a “windfall” to the industry and have proposed legislation that if enacted could adversely affect our profitability. In September 2022, California adopted Senate Bill No. 1322 (“SB 1322”), which requires refineries in California to report monthly on the volume and cost of the crude oil they buy, the quantity and price of the wholesale gasoline they sell, and the gross gasoline margin per barrel, among other information. The provisions of SB 1322 were effective January 2023. In March 2023, California adopted Senate Bill No. 2 (such statute, together with any regulations contemplated or issued thereunder, “SBx 1-2”), which, among other things, (i) authorized the establishment of a maximum gross gasoline refining margin and the imposition of a financial penalty for profits above a maximum gross gasoline refining margin, (ii) significantly expanded the reporting obligations under SB 1322 and the Petroleum Industry Information Reporting Act of 1980, which include reporting requirements to the California Energy Commission (“CEC”) for all participants in the petroleum industry supply chain in California (e.g., refiners, marketers, importers, transporters, terminals, producers, renewables producers, pipelines, and ports), (iii) created the Division of Petroleum Market Oversight within the CEC to analyze the data provided under SBx 1-2, and (iv) authorized the CEC to regulate the timing and other aspects of refinery turnaround and maintenance activities in certain instances. SBx 1-2 imposes increased and substantial reporting requirements, which include daily, weekly, monthly, and annual reporting of detailed operational and financial data on all aspects of our operations in California. The operational data includes any plans for turnaround and maintenance activities at our two California refineries and the way we expect to address the potential impacts on feedstock and product inventories in California as a result of such turnaround and maintenance activities. The provisions of SBx 1-2 became effective June 26, 2023.

In September 2023, the Governor of the State of California directed the CEC to begin the regulatory processes concerning (i) potential penalties for exceeding a maximum gross gasoline refining margin and (ii) the timing of refinery turnarounds and maintenance. Consequently, the CEC adopted an order requiring an informational proceeding on a maximum gross gasoline refining margin and penalty under SBx 1-2. It also adopted an order initiating rulemaking activity under SBx 1-2 that will be focused on refinery maintenance and turnarounds.

To the extent that the CEC establishes a maximum gross gasoline refining margin and imposes a financial penalty for profits above such maximum gross gasoline refining margin, our financial results and profitability could be adversely affected. Our results of operations and our financial performance could also be adversely impacted to the extent that restrictions on turnaround and maintenance activities are imposed by the CEC. We cannot reasonably predict the impact that the full implementation of SBx1-2 will have on our California operations or our Company nor can we predict the impact that similarly focused legislation or actions in other jurisdictions in which we operate our refineries may have. The recently adopted legislation in California, and the future enactment of similar legislation in any of the other jurisdictions could adversely impact our business, results of operations, profitability and cash.

Our operations require numerous permits and authorizations under various laws and regulations. These authorizations and permits are subject to revocation, renewal or modification and can require operational changes to limit impacts or potential impacts on the environment and/or health and safety. A violation of authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions, and/or facility shutdowns. In addition, major modifications of our operations could require modifications to our existing permits or upgrades to our existing pollution control equipment. Any or all of these matters could have a negative effect on our business, results of operations and cash flows.

We may incur significant liabilities under, or costs and capital expenditures to comply with, health, safety, environmental and other laws and regulations, which are complex and change frequently. Our operations are subject to federal, state and local laws regulating, among other things, the handling of petroleum and other regulated materials, the emission and discharge of materials into the environment, waste management, and remediation of discharges of petroleum and petroleum products, characteristics and composition of gasoline and distillates and other matters otherwise relating to the protection of the environment. Our operations are also subject to extensive laws and regulations relating to occupational health and safety, in addition to laws and regulations affecting the transportation of crude oil by rail in North America.

We cannot predict what additional environmental, health and safety legislation or regulations may be adopted in the future, or how existing or future laws or regulations may be administered or interpreted with respect to our operations. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time.

Certain environmental laws impose strict, and in certain circumstances joint and several liability for, costs of investigation and cleanup of such spills, discharges or releases on owners and operators of, as well as persons who arrange for treatment or disposal of regulated materials at contaminated sites. Under these laws, we may incur liability or be required to pay penalties for past contamination, and third parties may assert claims against us for damages allegedly arising out of any past or future contamination. The potential penalties and clean-up costs for past or future releases or spills, the failure of prior owners of our facilities to complete their clean-up obligations, the liability to third parties for damage to their property, or the need to address newly-discovered information or conditions that may require a response could be significant, and the payment of these amounts could have a material adverse effect on our business, financial condition and results of operations.

Enhanced scrutiny on ESG matters may impact our business as it relates to the use of refined products, climate change, increasing public expectations on companies to address climate change, and potential use of substitutes or replacements to our products may result in increased costs, reduced demand for our products, reduced profits, increased regulations and litigation, and adverse impacts on our access to capital markets. In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform and advise their investment and voting decisions. Also, some stakeholders may advocate for divestment of fossil fuel investments and encourage lenders to limit funding to companies engaged in the manufacturing of refined products. Unfavorable ESG ratings and investment community divestment initiatives may lead to negative investor and public sentiment toward the Company and to the diversion of capital from our industry, which could have a negative impact on our access to, and costs of, capital. This scrutiny, coupled with changes in consumer behavior, attitudes and preferences with respect to the generation and consumption of energy and the use of fossil fuels, may continue to result in (a) the enactment of climate change related regulations, policies and initiatives, including alternative energy requirements, (b) further technological advances related to the generation, storage and consumption of energy through alternative methods such as wind and solar and (c) increased demand for and/or availability of non-fossil fuel energy sources and related consumer products such as electric and hybrid vehicles and renewable power supplies. These developments may also lead to reduced demand for our products, a reduction in our revenue, higher costs and an overall decrease in our profitability.

Additionally, increased attention and scrutiny regarding climate change has resulted in increased investor attention and an increased risk of public and private litigation, which could increase our costs and/or otherwise negatively affect our operations and overall profitability, and cause the market price of our Class A common stock to decline.

We compete with other companies and industries that may provide alternative means to satisfy fuel and energy requirements to their customers or own their own retail network. The refining industry is highly competitive with respect to petroleum product capacity and feedstock supply. We compete with many companies for available supplies of crude oil and other feedstocks, and for third-party retail outlets for our refined petroleum products. Such companies that produce alternative energy sources or own their own retail sites may be better positioned to deal with changes in refining capacity, depressed refining margins or feedstock shortages.

Any further political instability, military strikes, sustained military campaigns, terrorist activity, changes in foreign policy in areas or regions of the world where we acquire crude oil and other raw materials or sell our refined products may affect our business in unpredictable ways, including forcing us to increase security measures and causing disruptions of supplies and distribution markets. We may also be subject to United States trade and economic sanctions laws, which change frequently as a result of foreign policy developments, and which may necessitate changes to our crude oil acquisition activities. Further, like other industrial companies, our facilities may be the target of terrorist activities or subject to catastrophic events such as natural disasters and pandemic illness. Any act of war, terrorism, or other catastrophic events that resulted in damage to, or otherwise disrupts the operating activities of, any of our refineries or third-party facilities upon which we are dependent for our business operations could have a material adverse effect on our business, results of operations and financial condition.

We are becoming increasingly dependent on our technology infrastructure and certain critical information systems which process, transmit and store electronic information, including information we use to safely and effectively operate our respective assets and businesses. These information systems include data network and telecommunications, internet access, our websites, and various computer hardware equipment and software applications, including those that are critical to the safe operation of our refineries and logistics assets. We have invested, and expect to continue to invest, significant time, manpower and capital in our technology infrastructure and information systems. These information systems are subject to damage or interruption from a number of potential sources including natural disasters, software viruses or other malware, power failures, cybersecurity threats to gain unauthorized access to sensitive information, cyber-attacks, which may render data systems unusable, and physical threats to the security of our facilities and infrastructure. Additionally, our business is highly dependent on financial, accounting and other data processing systems and other communications and information systems, including our enterprise resource planning tools. We process a large number of transactions on a daily basis and rely upon the proper functioning of computer systems. Furthermore, we rely on information systems across our respective operations, including the management of supply chain and various other processes and transactions. As a result, a disruption on any information systems at our refineries or logistics assets, may cause disruptions to our collective operations.

The potential for such security threats or system failures has subjected our operations to increased risks that could have a material adverse effect on our business. To the extent that these information systems are under our control, we have implemented measures such as virus protection software, emergency recovery processes and a formal disaster recovery plan to address the outlined risks. However, security measures for information systems cannot be guaranteed to be failsafe, and our formal disaster recovery plan and other implemented measures may not prevent delays or other complications that could arise from an information systems failure. If a key system were hacked or otherwise interfered with by an unauthorized user, or were to fail or experience unscheduled downtime for any reason, even if only for a short period, or any compromise of our data security or our inability to use or access these information systems at critical points in time, it could unfavorably impact the timely and efficient operation of our business, damage our reputation and subject us to additional costs and liabilities. The increase in companies and individuals working remotely has increased the frequency and scope of cyber-attacks and the risk of potential cybersecurity incidents, both deliberate attacks and unintentional events. While, to date, we have not had a significant cybersecurity breach or attack that had a material impact on our business or results of operations, if we were to be subject to a material successful cyber intrusion, it could result in remediation or service restoration costs, increased cyber protection costs, lost revenues, litigation or regulatory actions by governmental authorities, increased insurance premiums, reputational damage and damage to our competitiveness, financial condition, results of operations and cash flows.

Cyber-attacks against us or others in our industry could result in additional regulations, and U.S. government warnings have indicated that infrastructure assets, including pipelines, may be specifically targeted by certain groups. These attacks include, without limitation, malicious software, ransomware, attempts to gain unauthorized access to data, and other electronic security breaches. These attacks may be perpetrated by state-sponsored groups, “hacktivists”, criminal organizations or private individuals (including employee malfeasance). Current efforts by the federal government, including the Strengthening the Cybersecurity of Federal Networks and Critical Infrastructure executive order, the issuance of new cybersecurity requirements for critical pipeline owners and operators issued by the Department of Homeland Security’s Transportation Security Administration following a cyber-attack on a major petroleum pipeline in 2021, and any potential future regulations could lead to increased regulatory compliance costs, insurance coverage cost or capital expenditures. We cannot predict the potential impact to our business or the energy industry resulting from additional regulations.

Further, our business interruption insurance may not compensate us adequately for losses that may occur. We do not carry insurance specifically for cybersecurity events; however, certain of our insurance policies may allow for coverage for a cyber-event resulting in ensuing property damage from an otherwise insured peril. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, results of operations and cash flows. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

Our refining operations compete with domestic refiners and marketers in regions of the United States in which we operate, as well as with domestic refiners in other regions and foreign refiners that import products into the United States. In addition, we compete with other refiners, producers and marketers in other industries that provide means to satisfy the energy and fuel requirements of our industrial, commercial and individual consumers. Certain of our competitors have larger and more complex refineries, and may be able to realize lower per-barrel costs or higher margins per barrel of throughput. Several of our principal competitors are integrated national or international oil companies that are larger and have substantially greater resources than we do and access to proprietary sources of controlled crude oil production. Unlike these competitors, we obtain substantially all of our feedstocks from unaffiliated sources. We are not engaged in the petroleum exploration and production business and therefore do not produce any of our crude oil feedstocks. We do not have a retail business and therefore are dependent upon others for outlets for our refined products. Because of their integrated operations and larger capitalization, these companies may be more flexible in responding to volatile industry or market conditions, such as shortages of crude oil supply and other feedstocks or intense price fluctuations and they may also be able to obtain more favorable trade credit terms.

Newer or upgraded refineries will often be more efficient than our refineries, which may put us at a competitive disadvantage. We have taken significant measures to maintain our refineries including the installation of new equipment and redesigning older equipment to improve our operations. However, these actions involve significant uncertainties, since upgraded equipment may not perform at expected throughput levels, the yield and product quality of new equipment may differ from design specifications and modifications may be needed to correct equipment that does not perform as expected. Any of these risks associated with new equipment, redesigned older equipment or repaired equipment could lead to lower revenues or higher costs or otherwise have an adverse effect on future results of operations and financial condition. Over time, our refineries or certain refinery units may become obsolete, or be unable to compete, because of the construction of new, more efficient facilities by our competitors.

Delays or cost increases related to capital spending programs involving engineering, procurement and construction of new facilities (or improvements and repairs to our existing facilities and equipment, including turnarounds) could adversely affect our ability to achieve targeted internal rates of return and operating results. Such delays or cost increases may arise as a result of unpredictable factors in the marketplace, many of which are beyond our control, including:

Our refineries contain many processing units, a number of which have been in operation for many years. Equipment, even if properly maintained, may require significant capital expenditures and expenses to keep it operating at optimum efficiency. One or more of the units may require unscheduled downtime for unanticipated maintenance or repairs that are more frequent than our scheduled turnarounds for such units. Scheduled and unscheduled maintenance could reduce our revenues during the period of time that the units are not operating.

Our forecasted internal rates of return are also based upon our projections of future market fundamentals, which are not within our control, including changes in general economic conditions, inflation, slow growth, recession, impact of new regulations, available alternative supply and customer demand. Any one or more of these factors could have a significant impact on our business. If we were unable to make up the delays associated with such factors or to recover the related costs, or if market conditions change, it could materially and adversely affect our financial position, results of operations or cash flows.

We are subject to the requirements of the OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, OSHA requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees, state and local governmental authorities, and local residents. Failure to comply with OSHA requirements, including general industry standards, process safety standards and control of occupational exposure to regulated substances, could result in claims against us that could have a material adverse effect on our results of operations, financial condition and the cash flows of the business if we are subjected to significant fines or compliance costs.

Product liability and liability arising from our operations are significant risks. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers of petroleum products based upon claims for injuries and property damage caused by the use of or exposure to various products. Failure of our products to meet required specifications or claims that a product is inherently defective could result in product liability claims from third parties, including our shippers and customers, and also arise from contaminated or off-specification product in commingled pipelines and storage tanks and/or defective fuels. We may also be subject to personal injury claims arising from incidents that occur in connection with or relating to our operations. Product liability and personal injury claims against us could have a material adverse effect on our business, financial condition or results of operations.

We are subject to extensive tax liabilities, including federal, state, local and foreign taxes such as income, excise, sales/use, payroll, franchise, property, gross receipts, withholding and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations, such as the IRA, are continuously being enacted or proposed and could result in increased expenditures for tax liabilities in the future. These liabilities are subject to periodic audits by the respective taxing authorities, which could increase our tax liabilities. Subsequent changes to our tax liabilities as a result of these audits may also subject us to interest and penalties. There can be no certainty that our federal, state, local or foreign taxes could be passed on to our customers.

We may not be successful in acquiring additional assets or making investments in new business, and any acquisitions or other investments that we do consummate may not produce the anticipated benefits or may have adverse effects on our business and operating results. We may selectively consider strategic acquisitions and other investments in the future within the refining, mid-stream and renewable diesel or alternative energy sectors based on performance through the cycle, advantageous access to crude oil supplies, attractive refined products market fundamentals and access to distribution and logistics infrastructure. For example, we are part of Mid-Atlantic Clean Hydrogen Hub (“MACH2”), a broad consortium exploring the development of a clean energy and logistics hub on 2,500 acres adjacent to our Delaware City refinery, that was selected by the Department of Energy to receive up to $750.0 million to advance the development of a clean hydrogen production and distribution hub. In connection with MACH2, we are considering investments in renewable electricity, green hydrogen production, development of 10 million square feet of distribution warehouses and office space, and hydrogen fueling facilities for a large fleet of medium duty trucks. Our ability to acquire additional assets or invest in new businesses will be dependent upon a number of factors, including our ability to identify acceptable acquisition or investment opportunities, consummate acquisitions or other investments on acceptable terms, successfully integrate acquired assets and obtain financing to fund acquisitions and to support our growth and many other factors beyond our control. Risks associated with acquisitions and other investments include those relating to the diversion of management time and attention from our existing business, liability for known or unknown environmental conditions or other contingent liabilities and greater than anticipated expenditures required for compliance with environmental, safety or other regulatory standards or for investments to improve operating results, and the incurrence of additional indebtedness to finance acquisitions or capital expenditures relating to acquired assets. We may also enter into transition services agreements in the future with sellers of any additional refineries we acquire or otherwise invest in. Such services may not be performed timely and effectively, and any significant disruption in such transition services or unanticipated costs related to such services could adversely affect our business and results of operations. In addition, it is likely that, when we acquire or otherwise invest in refineries, we will not have access to the type of historical financial information that we will require regarding the prior operation of the refineries. As a result, it may be difficult for investors to evaluate the probable impact of significant acquisitions or other investments on our financial performance until we have operated the acquired refineries for a substantial period of time.

Most hourly employees at our refineries are covered by collective bargaining agreements through the USW, the IOW and the IBEW. These agreements are scheduled to expire on various dates in 2024 through 2028 (See “Item 1. Business” - Employees). Future negotiations prior to the expiration of our collective agreements may result in labor unrest for which a strike or work stoppage is possible. Strikes and/or work stoppages could negatively affect our operational and financial results and may increase operating expenses at the refineries.

Our future success depends to a large extent on the services of our senior executives and other key employees. Our business depends on our continuing ability to recruit, train and retain highly qualified employees in all areas of our operations, including engineering, accounting, business operations, finance and other key back-office and mid-office personnel. Furthermore, our operations require skilled and experienced employees with proficiency in multiple tasks. The competition for these employees is intense, and the loss of these executives or employees could harm our business. If any of these executives or other key personnel resigns or becomes unable to continue in his or her present role and is not adequately replaced, our business operations could be materially adversely affected.

We may enter into commodity derivatives contracts to hedge our crude price risk or crack spread risk with respect to a portion of our expected gasoline and distillate production on a rolling basis or to hedge our exposure to the price of natural gas, which is a significant component of our refinery operating expenses. Consistent with that policy we may hedge some percentage of our future crude and natural gas supply. We may enter into hedging arrangements with the intent to secure a minimum fixed cash flow stream on the volume of products hedged during the hedge term and to protect against volatility in commodity prices. Our hedging arrangements may fail to fully achieve these objectives for a variety of reasons, including our failure to have adequate hedging arrangements, if any, in effect at any particular time and the failure of our hedging arrangements to produce the anticipated results. We may not be able to procure adequate hedging arrangements due to a variety of factors. Moreover, such transactions may limit our ability to benefit from favorable changes in crude oil, refined product and natural gas prices.

In addition, our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which:

As a result, the effectiveness of our hedging strategy could have a material impact on our financial results. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

In addition, these hedging activities involve basis risk. Basis risk in a hedging arrangement occurs when the price of the commodity we hedge is more or less variable than the index upon which the hedged commodity is based, thereby making the hedge less effective. For example, a New York Mercantile Exchange index used for hedging certain volumes of our crude oil or refined products may have more or less variability than the actual cost or price we realize for such crude oil or refined products. We may not hedge all the basis risk inherent in our hedging arrangements and derivative contracts.

We do not currently apply hedge accounting to any of our commodity derivative contracts and, as a result, unrealized gains and losses will be charged to our earnings based on the increase or decrease in the market value of such unsettled positions. These gains and losses may be reflected in our income statement in periods that differ from when the settlements of the underlying hedged items are reflected in our income statement. Such derivative gains or losses in earnings may produce significant period-to-period earnings volatility that is not necessarily reflective of our underlying operational performance.

The level of our indebtedness has several important consequences for our future operations, including that:

Our indebtedness increases the risk that we may default on our debt obligations, certain of which contain cross-default and/or cross-acceleration provisions. Our, and our subsidiaries’, ability to meet future principal obligations will be dependent upon our future performance, which in turn will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our business may not continue to generate sufficient cash flow from operations to repay our indebtedness. If we are unable to generate sufficient cash flow from operations, we may be required to sell assets, to refinance all or a portion of our indebtedness or to obtain additional financing. Refinancing may not be possible and additional financing may not be available on commercially acceptable terms, or at all.

We currently have notes outstanding with maturity dates in 2028 and 2030. Additionally, our Revolving Credit Facility matures in 2028. We can make no assurance that we will be able to refinance these agreements on acceptable terms prior to their maturity dates. Market disruptions or other credit factors, such as rising inflation and higher interest rates, may increase our cost of borrowing or adversely affect our ability to refinance our obligations as they become due. Further, ESG concerns and other pressures on the oil and gas industry could lead to increased costs of financing or limit our access to the capital markets. If we are unable to refinance our indebtedness or access additional credit, or if short-term or long-term borrowing costs significantly increase, our ability to finance current operations and meet our short-term and long-term obligations could be adversely affected.

We and our subsidiaries are able to incur additional indebtedness in the future including additional secured or unsecured debt. Although our debt instruments and financing arrangements contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions, and the indebtedness incurred in compliance with these restrictions could be substantial. To the extent new debt is added to our current debt levels, the leverage risks described above would increase. Also, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness.

Changes in our credit profile could affect the way crude oil and other suppliers view our ability to make payments and induce them to shorten the payment terms for our purchases or require us to post security or letters of credit prior to payment. Due to the large dollar amounts and volume of our crude oil and other feedstock purchases, any imposition by these suppliers of more burdensome payment terms on us may have a material adverse effect on our liquidity and our ability to make payments to our suppliers. This, in turn, could reduce our access to supply and cause us to be unable to operate one or more of our refineries at full capacity.

Our 2028 Senior Notes and 2030 Senior Notes are rated Ba3 by Moody’s, BB by S&P, and BB- by Fitch. Any adverse changes in our credit ratings may negatively impact the terms of credit we receive from our suppliers and require us to prepay or post collateral. Additionally, adverse actions taken by the rating agencies on our corporate credit rating or the rating of our notes may increase our cost of borrowings or hinder our ability to raise financing in the capital markets or have an unfavorable impact on the credit terms we have with our suppliers, which could impair our ability to grow our business, maintain adequate levels of liquidity and make cash distributions to our members.

Various covenants in our current and future debt instruments and other financing arrangements, including the indentures governing our notes, may restrict our and our subsidiaries’ financial flexibility in a number of ways. Our current indebtedness and the indentures that govern our notes subject us to significant financial and other restrictive covenants, including restrictions on our ability to incur additional indebtedness, place liens upon assets, make distributions, or make certain other restricted payments and investments, consummate certain asset sales or asset swaps, conduct businesses other than our current businesses, or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of our assets. Some of our debt instruments also require our subsidiaries to satisfy or maintain certain financial condition tests in certain circumstances. Our ability to meet these financial condition tests can be affected by events beyond our control and we may not meet such tests. In addition, a failure to comply with the provisions of our existing debt could result in an event of default that could enable our lenders, subject to the terms and conditions of such debt, to declare the outstanding principal, together with accrued interest, to be immediately due and payable. Events beyond our control may affect our ability to comply with our covenants. If we were unable to repay the accelerated amounts, our lenders could proceed against the collateral granted to them to secure such debt. If the payment of our debt is accelerated, defaults under our other debt instruments, if any, may be triggered, and our assets may be insufficient to repay such debt in full.

Certain provisions of our indentures could make it more difficult or more expensive for a third-party to acquire us. Upon the occurrence of certain transactions constituting a “change of control” as described in the indentures governing the 2028 Senior Notes and the 2030 Senior Notes, holders of our notes could require us to repurchase all outstanding notes at 101% of the principal amount thereof, plus accrued and unpaid interest, if any, at the date of repurchase. Certain other significant agreements of ours such as our agreement governing the Revolving Credit Facility (the “Revolving Credit Agreement”) also contain provisions related to a change in control that could make it more difficult or expensive for a third-party to acquire us.

PBF Energy entered into a Tax Receivable Agreement that provides for the payment from time to time (“On-Going Payments”) by PBF Energy to the holders of PBF LLC Series A Units and PBF LLC Series B Units, or other permitted assignees, for certain tax benefits it may claim arising in connection with its prior offerings and future exchanges of PBF LLC Series A Units for shares of its Class A common stock and related transactions, and the amounts it may pay could be significant.

PBF Energy’s payment obligations under the Tax Receivable Agreement are PBF Energy’s obligations and not obligations of PBF Holding, PBF Finance, or any of PBF Holding’s other subsidiaries. However, because PBF Energy is primarily a holding company with limited operations of its own, its ability to make payments under the Tax Receivable Agreement is dependent on our ability to make future distributions to it. The indentures governing the senior notes allow us to make tax distributions (as defined in the applicable indentures), and it is expected that PBF Energy’s share of these tax distributions will be in amounts sufficient to allow PBF Energy to make On-Going Payments. The indentures governing the senior notes also allow us to make a distribution sufficient to allow PBF Energy to make any payments required under the Tax Receivable Agreement upon a change in control, so long as we offer to purchase all of the senior notes outstanding at a price in cash equal to 101% of the aggregate principal amount thereof, plus accrued and unpaid interest thereon, if any. If PBF Energy’s share of the distributions it receives under these specific provisions of the indentures is insufficient to satisfy its obligations under the Tax Receivable Agreement, PBF Energy may cause us to make distributions in accordance with other provisions of the indentures in order to satisfy such obligations.

Our existing indebtedness may limit our ability to make distributions to PBF LLC, and in turn for PBF Energy to pay these obligations. These provisions may deter a potential sale of us to a third-party and may otherwise make it less likely that a third-party would enter into a change of control transaction with PBF Energy or us.

PBF Energy has recognized, as of December 31, 2023, a total liability for the Tax Receivable Agreement of $336.6 million, of which $43.0 million was recorded as a current liability and was paid in January 2024 related to the 2022 tax year. As PBF Energy records future taxable income, increases in its Tax Receivable Agreement liability may be necessary. It is possible that future transactions or events could increase the actual tax benefits realized and the corresponding payments. Moreover, future payments under the Tax Receivable Agreement will be based on the tax reporting positions that PBF Energy determines in accordance with the Tax Receivable Agreement. Neither PBF Energy nor any of its subsidiaries will be reimbursed for any payments previously made under the Tax Receivable Agreement if the IRS subsequently disallows part or all of the tax benefits that gave rise to such prior payments.

We depend on PBFX to receive, handle, store and transfer crude oil, petroleum products and natural gas for us from our operations and sources located throughout the United States and Canada in support of certain of our refineries under long-term, fee-based commercial agreements with us. These commercial agreements have an initial term ranging from one to fifteen years and generally include minimum quarterly commitments and inflation escalators. If we fail to meet the minimum commitments during any calendar quarter, we will be required to make a shortfall payment quarterly to PBFX equal to the volume of the shortfall multiplied by the applicable fee.

PBFX’s operations are subject to all of the risks and operational hazards inherent in receiving, handling, storing and transferring crude oil, petroleum products and natural gas, including: damages to its facilities, related equipment and surrounding properties caused by floods, fires, severe weather, explosions and other natural disasters and acts of terrorism; mechanical or structural failures at PBFX’s facilities or at third-party facilities on which its operations are dependent; curtailments of operations relative to severe seasonal weather; inadvertent damage to our facilities from construction, farm and utility equipment; and other hazards. Any of these events or factors could result in severe damage or destruction to PBFX’s assets or the temporary or permanent shut-down of PBFX’s facilities. If PBFX is unable to serve our logistics needs, our ability to operate our refineries and receive crude oil and distribute products could be adversely impacted, which could adversely affect our business, financial condition and results of operations.

None.

In connection with the acquisition of the Torrance refinery and related logistics assets, we assumed certain pre-existing environmental liabilities related to certain environmental remediation obligations to address existing soil and groundwater contamination and monitoring activities, which reflect the estimated cost of the remediation obligations. In addition, in connection with the acquisition of the Torrance refinery and related logistics assets, we purchased a ten-year, $100.0 million environmental insurance policy to insure against unknown environmental liabilities.

We currently have multiple outstanding notices of violation (“NOVs”) issued by regulatory authorities for various alleged regulation and permit violations at our refineries. It is not possible to predict the outcome of any of these NOVs or the amount of the penalties that will be assessed in connection with any NOV. If any one or more of them were decided against us, we believe that there would be no material effect on our financial position, results of operations, or liquidity. SEC regulations require us to disclose certain information about proceedings arising under federal, state, or local provisions regulating the discharge of materials into the environment or protecting the environment if we reasonably believe that such proceedings will result in monetary sanctions of $300,000 or more. On November 24, 2022, the Martinez refinery experienced a spent catalyst release that is currently being investigated by the BAAQMD, Contra Costa County (“CCC”), the Department of Justice and EPA, and the California Department of Fish and Game (“DFG”). On July 11, 2023 and October 6, 2023, the Martinez refinery experienced unintentional releases of petroleum coke dust and has received inquiries or notices of investigation from the BAAQMD, the California Department of Industrial Relations, Division of Occupational Safety and Health, the CCC, and the EPA. The BAAQMD has issued 35 NOVs relating to the spent catalyst incident to date. The CCC has issued two NOVs related to the spent catalyst incident. The BAAQMD also issued an NOV relating to the July 11, 2023 coke dust incident and an NOV relating to the October 6, 2023 coke dust incident. For the spent catalyst incident, the DFG, CCC, and the BAAQMD have referred their findings and/or NOVs issued to date to the CCC District Attorney. On November 16, 2023, the CCC District Attorney and BAAQMD announced a joint civil enforcement action against us that will include enforcement of claims from the November 24, 2022 spent catalyst release, as well as additional enforcement claims. On December 15, 2023, the BAAQMD issued a NOV related to odors from flaring that occurred on the same date. On December 18, 2023, the BAAQMD issued four NOVs related to a fire incident that occurred on December 17, 2023. For both the spent catalyst, coke dust, flaring and fire incidents, no penalties have been assessed but it is reasonable to expect that, individually or in the aggregate, the amount of such penalties may exceed $300,000.

On September 27, 2023, MRC received from the San Francisco Bay Regional Water Quality Control Board (“RWQCB”) an Administrative Civil Liability (“ACL”) assessment in the amount of $13.8 million for allegedly: (1) exceeding its effluent limitations and discharging to the Carquinez Strait without authorization in October 2022, January 2023, and June 2023; and (2) failing to submit Climate Change Adaptation information. On January 12, 2024, MRC met with the RWQCB to discuss its response to their ACL assessment. Based on the discussions and the information provided by MRC, the RWQCB proposed reducing the ACL assessment to approximately $4.5 million and noted that for any settlement 50% of the penalty could be in the form of an Enhanced Compliance Actions (“ECA”) settlement, Supplemental Environmental Project (“SEP”), or a combination of the two. On January 19, 2024, MRC agreed to accept the reduced ACL, with 50% of the approximately $4.5 million dedicated to an ECA and SEP. Once the parties finalize the settlement agreement and stipulation for entry of administrative civil liability order, it will be presented to the RWQCB’s Board for final approval.

On September 7, 2021, MRC filed a Verified Petition for Writ of Mandate and Complaint for Declaratory and Injunctive Relief against the BAAQMD requesting the Court to declare as invalid, unenforceable, and ultra vires the BAAMQD’s July 21, 2021, adoption of amendments to Rule 6-5 Amendment. MRC is also seeking a writ of mandate ordering the BAAQMD to vacate and rescind the adoption of the Rule 6-5 Amendment, as well as appropriate declaratory relief, injunctive relief, and reasonable costs incurred by MRC to bring this Petition/Complaint. In the Petition/Complaint MRC alleges that: its feasible alternative Particulate Matter (“PM”) reduction proposal, which would achieve significant PM reductions while avoiding the significant costs and environmental impacts of the BAAQMD’s adopted PM limit, was improperly removed from consideration and not presented to the BAAQMD Board when the Rule 6-5 Amendment was adopted with the current PM standard; when adopting the Rule 6-5 Amendment, the BAAQMD flagrantly ignored numerous mandatory requirements of the California Environmental Quality Act (“CEQA”) and the California Health and Safety Code; the BAAQMD’s adoption of the Rule 6-5 Amendment also violated California common law; and these failings render the Rule 6-5 Amendment ultra vires, illegal, and unenforceable. We held mandatory settlement conferences with the BAAQMD on October 27, 2021 and December 15, 2021. On December 9, 2022, MRC filed a Motion to Augment/Correct the Administrative Record regarding various documents that the BAAQMD is currently withholding and does not plan to include in the administrative record. On February 2, 2023, although the Court partially denied our motion concerning documents where the BAAQMD asserted the attorney client privilege, the Court held that CEQA places a heavy burden on the BAAQMD in justifying withholding documents based on the deliberative privilege. At the Court’s request, the parties agreed to a process whereby they jointly identified approximately 50 of the withheld/redacted documents for the Court to review. The Court ruled on those documents on February 22, 2023, ordering full disclosure of two types of documents related to the BAAQMD’s cost-estimates for the rule. In compliance with the Court’s order, in March 2023, the BAAQMD produced additional or less-redacted versions of previously produced documents. On May 26, 2023, MRC filed its opening brief. The BAAQMD’s opposition brief was filed on July 21, 2023. MRC filed its reply brief on August 18, 2023. The bench trial scheduled for December 21, 2023, was rescheduled to February 29, 2024. On February 12, 2024, the parties entered a settlement agreement pursuant to which MRC is dismissing its Petition/Complaint and the BAAQMD has approved MRC’s AEMS, to be validated within the first year after the effective date of the rule. We presently believe the settlement will not have a material impact on our financial position, results of operations, or cash flows.

The federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances. Under CERCLA, such persons may be subject to joint and several liability for investigation and the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. As discussed more fully above, certain of our sites are subject to these laws and we may be held liable for investigation and remediation costs or claims for natural resource damages. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Analogous state laws impose similar responsibilities and liabilities on responsible parties. In our current normal operations, we have generated waste, some of which falls within the statutory definition of a “hazardous substance” and some of which may have been disposed of at sites that may require cleanup under Superfund.

As the ultimate outcomes of the pending matters discussed above are uncertain, we cannot currently estimate the final amount or timing of their resolution, but any such amount is not expected to have a material impact on our financial position, results of operations, or cash flows, individually or in the aggregate.

We are a privately-owned company with no established public trading market for our membership units.

At February 23, 2024, 100% of our outstanding membership interests were held by PBF LLC. PBF Finance had 100 shares of common stock outstanding, all of which were held by us. None of the membership interests are publicly-traded, and none were issued or sold in 2023.

In cases when there is sufficient cash and cash equivalents and borrowing capacity, we are permitted under our debt agreements to make distributions; however, our ability to make distributions to PBF LLC is, and in the future may be, limited by covenants in our Revolving Credit Facility, the 2028 Senior Notes, the 2030 Senior Notes and other debt instruments. Subject to certain exceptions, the Revolving Credit Facility and the indentures governing the senior notes prohibit us from making distributions to PBF LLC if certain defaults exist. Our ability to continue to comply with our debt covenants is, to a significant degree, subject to our operating results, which are dependent on a number of factors outside of our control.

We are a holding company and all of our operations are conducted through our subsidiaries. We have no independent means of generating revenue other than through assets owned by our subsidiaries. In order for us to make any distributions, we will need to cause our subsidiaries to make distributions to us. We and our subsidiaries are generally prohibited under Delaware law from making a distribution to a member to the extent that, at the time of the distribution, after giving effect to the distribution, liabilities of the limited liability company (with certain exceptions) exceed the fair value of its assets. As a result, we may be unable to obtain cash from our subsidiaries to satisfy our obligations and make distributions to PBF LLC, when necessary.

We make, from time to time, cash distributions in amounts sufficient for PBF LLC to make tax distributions to its members and may make additional distributions to the extent necessary for PBF Energy to declare and pay any quarterly cash dividends. The declaration, amount and payment of this and any other future distributions by us will be at the sole discretion of our board of directors and the board of directors of PBF Energy, which is the sole managing member of our sole member (PBF LLC), and we are not obligated under any applicable laws, governing documents or any contractual agreements with PBF LLC’s existing owners or otherwise to declare or pay any dividends or other distributions (other than the obligations of PBF LLC to make tax distributions to its members).

We made $1,582.8 million in distributions to PBF LLC during the year ended December 31, 2023. In addition, during the year ended December 31, 2023 PBF LLC used $106.6 million to make non-tax distributions to its members, of which $105.8 million was distributed to PBF Energy and the balance was distributed to PBF LLC’s other members. PBF Energy used this $105.8 million to pay cash dividends of $0.20 per share of its Class A common stock on March 16, 2023, May 31, 2023 and August 31, 2023, and cash dividends of $0.25 per share on November 30, 2023.

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

In this Item 7, we discuss results for the years ended December 31, 2023 and 2022 and comparisons of the results for the years ended December 31, 2023 and 2022. Discussions of results for the year ended December 31, 2021 and comparisons of the results for the years ended December 31, 2022 and 2021 can be found in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of the Company's annual report on Form 10-K for the year ended December 31, 2022.

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

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

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

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

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. 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. Our six refineries are all engaged in the refining of crude oil and other feedstocks into petroleum products, and represent one reportable segment.

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

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

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

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

On September 13, 2023, we exercised our rights under the indenture governing the 2025 Senior Notes to redeem all of the outstanding 2025 Senior Notes at a price of 100% of the aggregate principal amount thereof, plus accrued and unpaid interest through the date of redemption. The aggregate redemption price for all 2025 Senior Notes approximated $664.5 million plus accrued and unpaid interest.

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

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

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

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

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

Refer to “Note 8 - Credit Facilities and Debt” of our Notes to Consolidated Financial Statements, for further information.

Prior to 2023, PBF Holding and its subsidiaries, the PBF Entities, entered into the Third Inventory Intermediation Agreement with J. Aron. Pursuant to the Third Inventory Intermediation Agreement, J. Aron purchased and held title to the J. Aron Products purchased or produced by the Refineries and delivered into the Storage Tanks. The J. Aron Products were sold back to us as the J. Aron Products were discharged out of the Storage Tanks.

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

On June 27, 2023, we distributed to PBF LLC, which in turn contributed to St. Bernard Renewables LLC (“SBR”), approximately $748.3 million in assets related to the renewable diesel facility co-located with the Company’s Chalmette refinery in Louisiana (the “Renewable Diesel Facility”). We have no interest in SBR, which is jointly owned by a subsidiary of PBF LLC and its partner, Eni Sustainable Mobility US Inc., a subsidiary of Eni SpA. Additionally, we distributed to PBF LLC, which in turn contributed to one of its subsidiaries, Chalmette Refining Service Company LLC (“CRSC”), approximately $103.8 million in assets. The Company has no interest in CRSC, which is owned by PBF LLC.

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

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

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.

PBFX, an indirect wholly-owned subsidiary of PBF Energy and PBF LLC, is a partnership that owns or leases, operates, develops and acquires crude oil, and refined petroleum products terminals, pipelines, storage facilities and similar logistics assets. PBFX engages in the receiving, handling, storage and transferring of crude oil, refined products, natural gas and intermediates from sources located throughout the United States and Canada for us in support of certain of our refineries, as well as for third-party customers.

We have entered into a series of agreements with PBFX, including contribution, commercial and operational agreements. Each of these agreements and their impact to our operations is described in “Item 1. Business” and “Note 9 - Related Party Transactions” of our Notes to Consolidated Financial Statements.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Our results for the year ended December 31, 2023 were positively impacted by special items consisting of a change in fair value of contingent consideration related to changes in our earn-out obligation associated with the acquisition of the Martinez refinery and logistic assets (the “Martinez Contingent Consideration”) of $45.8 million and a gain on the sale of a parcel of land at our Torrance refinery of $1.7 million, partially offset by a $5.7 million loss on extinguishment of debt related to the redemption of the 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. Our results for the year ended December 31, 2022 were negatively impacted by special items consisting of a net loss on the extinguishment of debt mainly associated with the redemption of our 2025 Senior Secured Notes of $66.1 million and a net change in the fair value of the Martinez Contingent Consideration of $48.1 million.

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.

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.

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.

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.

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

On the East Coast, the Dated Brent (NYH) 2-1-1 industry crack spread was approximately $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.

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.

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.

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.

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

The Non-GAAP measures presented include gross refining margin excluding special items, and EBITDA excluding special items. Special items for the periods presented relate to LCM inventory adjustment, net changes in fair value of contingent consideration, loss (gain) on extinguishment of debt, and gain on land sales. See “Notes to Non-GAAP Financial Measures” below for more details on all special items disclosed. Although we believe that Non-GAAP financial measures, excluding the impact of special items, provide useful supplemental information to investors regarding the results and performance of our business and allow for helpful period-over-period comparisons, such Non-GAAP measures should only be considered as a supplement to, and not as a substitute for, or superior to, the financial measures prepared in accordance with GAAP.

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

Neither gross refining margin nor gross refining margin excluding special items should be considered an alternative to consolidated gross margin, income from operations, net cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Gross refining margin and gross refining margin excluding special items presented by other companies may not be comparable to our presentation, since each company may define these terms differently.

The following table presents our GAAP calculation of gross margin and a reconciliation of gross refining margin to the most directly comparable GAAP financial measure, consolidated gross margin, on a historical basis, as applicable, for each of the periods indicated (in millions, except per barrel amounts):

Our primary sources of liquidity are our cash flows from operations, cash and cash equivalents and borrowing availability under our credit facility, as described below. We believe that our cash flows from operations and available capital resources will be sufficient to meet our and our subsidiaries’ capital expenditures, working capital needs, future distributions and debt service requirements for the next twelve months. However, our ability to generate sufficient cash flow from operations depends, in part, on petroleum oil market pricing and general economic, political and other factors beyond our control. As of December 31, 2023, we are in compliance with all covenants, including financial covenants, in all our debt agreements.

Cash Flows from Operating Activities

Net cash provided by operating activities was $1,478.0 million for the year ended December 31, 2023 compared to net cash provided by operating activities of $4,696.2 million for the year ended December 31, 2022. Our operating cash flows for the year ended December 31, 2023 included our net income of $1,803.8 million, depreciation and amortization of $551.6 million, stock-based compensation of $51.5 million, pension and other post-retirement benefit costs of $47.9 million, loss on extinguishment of debt primarily related to the redemption of our 2025 Senior Notes and the amendment and restatement of the Revolving Credit Facility of $5.7 million, and deferred income tax benefit of $3.7 million, partially offset by net change in the fair value of contingent consideration of $45.8 million, gain on sale of assets of $1.3 million and a change in the fair value of our catalyst obligations of $1.1 million. In addition, net changes in operating assets and liabilities reflected uses of cash of $938.0 million, driven by inventory purchases and payments for accrued expenses. The change in accrued expenses was due primarily to a decrease in renewable energy and emissions obligations, as a result of a decrease in our unfunded RINs obligation.

Our operating cash flows for the year ended December 31, 2022 included our net income of $3,708.9 million and net changes in operating assets and liabilities reflecting cash proceeds of $291.5 million, primarily driven by timing of payments for accrued expenses. Change in accrued expenses was due primarily to an increase in renewable energy credit and emissions obligations, as a result of an increase in our unfunded RINs obligation as of December 31, 2022. Our overall increase in cash provided by operating activities also included depreciation and amortization of $495.6 million, loss on extinguishment of debt primarily related to the redemption of our 2025 Senior Secured Notes of $66.1 million, net change in the fair value of contingent consideration of $48.1 million, pension and other post-retirement benefit costs of $47.6 million, stock-based compensation of $44.1 million, change in the fair value of our catalyst obligations of $2.0 million, and loss on sale of assets of $0.9 million, partially offset by a non-cash charges related to the change in the fair value of our inventory repurchase obligations of $5.4 million and deferred income taxes of $3.2 million.

Net cash provided by operating activities was $4,696.2 million for the year ended December 31, 2022 compared to net cash provided by operating activities of $292.3 million for the year ended December 31, 2021. Our operating cash flows for the year ended December 31, 2021 included our net income of $239.1 million, depreciation and amortization of $444.3 million, net changes in operating assets and liabilities reflected cash proceeds of $279.5 million driven by accrued expenses due to an increase in renewable energy credit and emissions obligations, as a result of an increase in our unfunded RIN’s obligations as of December 31, 2021, pension and other post-retirement benefits costs of $50.8 million, stock-based compensation of $30.3 million, and change in the fair value of contingent consideration of $29.4 million, partially offset by a non-cash benefit of $669.6 million related to an LCM inventory adjustment, gain on extinguishment of debt related to the repurchase of a portion of our 2028 Senior Notes and 2025 Senior Notes of $79.9 million, deferred income taxes of $14.5 million, change in the fair value of our catalyst obligations of $8.5 million, net non-cash charges related to the change in the fair value of our inventory repurchase obligations of $8.4 million, and gain on sale of assets of $0.2 million.

Cash Flows from Investing Activities

Net cash used in investing activities was $1,157.3 million for the year ended December 31, 2023 compared to $1,003.0 million for the year ended December 31, 2022. The net cash flows used in investing activities for the year ended December 31, 2023 was comprised of capital expenditures totaling $647.7 million, expenditures for refinery turnarounds of $473.5 million, and expenditures for other assets of $40.5 million, partially offset by proceeds from the sale of assets of $4.4 million. Net cash used in investing activities for the year ended December 31, 2022 was comprised of capital expenditures totaling $625.4 million, expenditures for refinery turnarounds of $311.6 million and expenditures for other assets of $66.0 million.

Net cash used in investing activities was $1,003.0 million for the year ended December 31, 2022 compared to $387.1 million for the year ended December 31, 2021. Net cash used in investing activities for the year ended December 31, 2021 was comprised of capital expenditures totaling $240.5 million, expenditures for refinery turnarounds of $117.7 million, and expenditures for other assets of $28.9 million.

Net cash used in financing activities was $2,845.0 million for the year ended December 31, 2022 compared to net cash used in financing activities of $169.6 million for the year ended December 31, 2021. For the year ended December 31, 2021, net cash used in financing activities consisted of $146.8 million related to the repurchase of the principal amount outstanding of the 2028 Senior Notes and the 2025 Senior Notes, excluding accrued interest, net settlements of precious metal catalyst obligations of $31.7 million, payments on finance leases of $17.8 million, principal amortization payments of the PBF Rail Term Loan of $7.4 million, distributions to members of $3.4 million, partially offset by proceeds from contributions from PBF LLC of $37.0 million, and deferred financing costs and other of $0.5 million.

On September 13, 2023, we exercised our rights under the indenture governing the 2025 Senior Notes to redeem all of the outstanding 2025 Senior Notes at a price of 100% of the aggregate principal amount thereof, plus accrued and unpaid interest through the date of redemption. The aggregate redemption price for all 2025 Senior Notes approximated $664.5 million plus accrued and unpaid interest.

On 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 2025 Senior Notes, as described above.

Revolving Credit Facility

On August 23, 2023, we entered into the Revolving Credit Agreement. The Revolving Credit Agreement amended and restated the Prior Credit Agreement. Among other things, the Revolving Credit Agreement extended the Revolving Credit Facility through August 2028 and increased the maximum commitment amount under the facility to $3.5 billion from $2.85 billion. The commitment fees on the unused portion, the interest rate on advances and the fees for letters of credit are generally consistent with the Prior Credit Agreement.

Precious metal catalyst obligations

During 2023, we also settled our remaining outstanding precious metals financing arrangement, resulting in a reduction of debt of approximately $3.1 million.

Refer to “Note 8 – Credit Facilities and Debt” of our Notes to Consolidated Financial Statements, for further information.

One of our primary sources of liquidity is available borrowings capacity under our Revolving Credit Facility, which had the following available capacity at December 31, 2023 (in millions):

Our debt, including our Revolving Credit Facility and senior notes, include certain typical financial covenants and restrictions on our subsidiaries’ ability to, among other things, incur or guarantee new debt, engage in certain business activities including transactions with affiliates and asset sales, make investments or distributions, engage in mergers or pay dividends in certain circumstances. These covenants are subject to a number of important exceptions and qualifications. We are in compliance as of December 31, 2023 with all covenants, including financial covenants, in all of our debt agreements. For further discussion of our indebtedness and these covenants and restrictions, see “Note 8 - Credit Facilities and Debt” of our Notes to Consolidated Financial Statements.

As of December 31, 2023, our operational liquidity was more than $4.6 billion (more than $4.9 billion as of December 31, 2022), which consists of $1.8 billion of cash and more than $2.8 billion of borrowing availability under our Revolving Credit Facility, which includes our cash on hand.

We may incur additional indebtedness in the future, including secured indebtedness, subject to the satisfaction of any debt incurrence and, if applicable, lien incurrence limitation covenants in our existing financing agreements. Although we were in compliance with incurrence covenants during the year ended December 31, 2023, there are no assurances in the future we will be able to meet these incurrence covenants at the time that we needed to. Failure to meet the incurrence covenants could impose certain incremental restrictions on, among other matters, our ability to incur new debt (including secured debt) and also may limit the extent to which we may make future distributions, make acquisitions or investments, repurchase our outstanding debt or incur new liens.

Our working capital at December 31, 2023 was approximately $2,184.0 million, consisting of $6,480.3 million in total current assets and $4,296.3 million in total current liabilities. Our working capital at December 31, 2022 was $1,715.3 million, consisting of $6,494.5 million in total current assets and $4,779.2 million in total current liabilities.

We currently purchase all of our crude and feedstock needs from various suppliers, primarily through short-term and spot market agreements. We also have a crude supply agreement with Saudi Aramco, the term of which is currently year to year, for up to approximately 100,000 bpd that is processed at the Paulsboro refinery and crude supply agreements with Shell Trading (US) Company (primarily serving our Martinez refinery) for up to approximately 95,000 bpd, which, upon expiration of one of the agreements in early 2024, will be reduced to up to approximately 65,000 bpd, through early 2025.

On July 31, 2023, we early terminated the Third Inventory Intermediation Agreement with J. Aron. In conjunction with the early termination, we made an aggregate settlement 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.

Capital spending was $1,161.7 million for the year ended December 31, 2023 and was primarily comprised of annual maintenance and turnaround costs at our Delaware City, Toledo, Chalmette, Torrance and Martinez refineries and spending related to the construction of the Renewable Diesel Facility co-located with our Chalmette refinery of approximately $312.7 million. Capital spending also included costs associated with safety related enhancements and facility improvements at our refineries. We currently expect to spend an aggregate of approximately $800.0 million to $850.0 million in 2024 for facility improvements and refinery maintenance and turnarounds, as well as expenditures to meet environmental, regulatory and safety requirements.

Our material cash requirements include the following known contractual and other obligations as of December 31, 2023 that are expected to be paid within the next year and thereafter (in millions).

Credit facilities and debt represent the repayment of indebtedness incurred in connection with the 2030 Senior Notes and 2028 Senior Notes; we have no debt maturing before 2025.

Refer to “Note 8 - Credit Facilities and Debt” of our Notes to Consolidated Financial Statements for further disclosure related to debt.

Third Party and affiliate operating and finance lease obligations include options to extend terms that are reasonably certain of being exercised. We have entered into certain agreements for the supply of hydrogen that contain both lease and non-lease components. The table above also includes such non-lease components of these agreements. See “Note 11 - Leases” of our Notes to Consolidated Financial Statements for further details and disclosures regarding our operating and finance lease obligations.

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

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

We have minimum obligations under our commercial agreements entered into with PBFX. Refer to “Note 9 - Related Party Transactions” and “Note 10 - Commitments and Contingencies” of our Notes to the Consolidated Financial Statements for a detailed explanation of each of these agreements and quantification of minimum amounts due in subsequent periods, respectively.

Included in the table above are our obligations related to the minimum volume commitments required under these commercial agreements that were determined to not be leases under GAAP. Any incremental volumes above any minimum throughput under these agreements would increase our obligations. Our obligation with respect to certain crude oil and refined product storage agreements is based on the estimated shell capacity of the storage tanks to be utilized.

In connection with certain of our refinery acquisitions, we have assumed certain environmental remediation obligations to address matters that were outstanding at the time of such acquisitions. In addition, in connection with most of these acquisitions, we have purchased environmental insurance policies to insure against unknown environmental liabilities at each site. The obligations in the table above reflect our undiscounted best estimate in cost and tenure to remediate our outstanding obligations and are further discussed in “Note 10 - Commitments and Contingencies” of our Notes to Consolidated Financial Statements.

Pension and post-retirement obligations include only those amounts we expect to pay out in benefit payments and are further explained in “Note 14 - Employee Benefit Plans” of our Notes to Consolidated Financial Statements.

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

Inventory

Inventories are carried at the lower of cost or market. The cost of crude oil, feedstocks, blendstocks and refined products is determined under the LIFO method using the dollar value LIFO method with increments valued based on average cost during the year. The cost of supplies and other inventories is determined principally on the weighted average cost method. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years that inventory volumes decline as the result of charging cost of sales with LIFO inventory costs generated in prior periods. At December 31, 2023 and December 31, 2022 the replacement value of inventories exceeded the LIFO carrying value. The LCM or market inventory valuation reserve, or a portion thereof, is subject to reversal as a reduction to cost of products sold in subsequent periods as inventories giving rise to the reserve are sold, and a new reserve is established. Such a reduction to cost of products sold could be significant if inventory values return to historical cost price levels. Additionally, further decreases in overall inventory values could result in additional charges to cost of products sold should the LCM or market inventory valuation reserve be increased.

Environmental Matters

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

Impairment of Long-Lived Assets

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

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

As of December 31, 2023, PBF Services, DCR, PBF Power, PRC, Toledo Refining, Chalmette Refining, PBF Western Region, Torrance Refining, MRC, PBF International Inc. and PBF Investments are 100% owned subsidiaries of PBF Holding and serve as guarantors of the obligations under the 2028 Senior Notes and 2030 Senior Notes. These guarantees are full and unconditional and joint and several. PBF Holding serves as the “Issuer”. The indentures dated January 24, 2020 and August 21, 2023 among PBF Holding, PBF Finance, the guarantors party thereto, Wilmington Trust, National Association, as trustee and Deutsche Bank Trust Company Americas, as Paying Agent, Registrar, Transfer Agent and Authenticating Agent, govern subsidiaries designated as “Guarantor Subsidiaries”. PBF Ltd., PBF Transportation Company LLC, PBF Rail Logistics Company LLC, MOEM Pipeline LLC, Collins, T&M, Torrance Basin Pipeline Company LLC, Torrance Logistics Company LLC, Torrance Pipeline Company LLC, Martinez Terminal Company LLC, Martinez Pipeline Company LLC and PBFWR Logistics Holdings LLC are consolidated subsidiaries of the Company that are not guarantors of the 2028 Senior Notes and 2030 Senior Notes. The 2028 Senior Notes and 2030 Senior Notes were co-issued by PBF Finance. For purposes of the following information, PBF Finance is referred to as “Co-Issuer.” The Co-Issuer has no independent assets or operations.

The following tables present summarized information for the Issuer and the Guarantor Subsidiaries on a combined basis after elimination of (i) intercompany transactions and balances among the Issuer and the Guarantor Subsidiaries and (ii) equity in earnings from and investments in any subsidiary that is a non-guarantor.

We are exposed to market risks, including changes in commodity prices and interest rates. Our primary commodity price risk is associated with the difference between the prices we sell our refined products and the prices we pay for crude oil and other feedstocks. We may use derivative instruments to manage the risks from changes in the prices of crude oil and refined products, natural gas, interest rates, or to capture market opportunities.

Our earnings, cash flow and liquidity are significantly affected by a variety of factors beyond our control, including the supply of, and demand for, crude oil, other feedstocks, refined products and natural gas. The supply of and demand for these commodities depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, planned and unplanned downtime in refineries, pipelines and production facilities, production levels, the availability of imports, the marketing of competitive and alternative fuels, and the extent of government regulation. As a result, the prices of these commodities can be volatile. Our revenues fluctuate significantly with movements in industry refined product prices, our cost of sales fluctuates significantly with movements in crude oil and feedstock prices and our operating expenses fluctuate with movements in the price of natural gas. We manage our exposure to these commodity price risks through our supply and offtake agreements as well as through the use of various commodity derivative instruments.

We may use non-trading derivative instruments to manage exposure to commodity price risks associated with the purchase or sale of crude oil and feedstocks, finished products and natural gas outside of our supply and offtake agreements. The derivative instruments we use include physical commodity contracts and exchange-traded and over-the-counter financial instruments. We mark-to-market our commodity derivative instruments and recognize the changes in their fair value in our statements of operations.

At December 31, 2023 and December 31, 2022, we had gross open commodity derivative contracts representing 29.1 million barrels and 30.1 million barrels, respectively, with an unrealized net gain of $33.2 million and $13.9 million, respectively. The open commodity derivative contracts as of December 31, 2023 expire at various times during 2024.

We carry inventories of crude oil, intermediates and refined products (“hydrocarbon inventories”) on our Consolidated Balance Sheets, the values of which are subject to fluctuations in market prices. Our hydrocarbon inventories totaled approximately 36.2 million barrels and 32.8 million barrels at December 31, 2023 and December 31, 2022, respectively. The average cost of our hydrocarbon inventories was approximately $83.64 and $80.04 per barrel on a LIFO basis at December 31, 2023 and December 31, 2022, respectively. At December 31, 2023 and December 31, 2022, the replacement value of inventory exceeded the LIFO carrying value. If market prices of our inventory decline to a level below our average cost, we may be required to write down the carrying value of our hydrocarbon inventories to market.

Our predominant variable operating cost is energy, which is comprised primarily of natural gas and electricity. We are therefore sensitive to movements in natural gas prices. Assuming normal operating conditions, we expect our annual consumption to range from 75 million to 95 million MMBTUs of natural gas amongst our six refineries. Accordingly, a $1.00 per MMBTU change in natural gas prices would increase or decrease our natural gas costs by approximately $75.0 million to $95.0 million.

We are exposed to market risks related to our obligations to buy and the volatility in the price of credits needed to comply with various governmental and regulatory compliance programs, which include RINs, required to comply with the RFS. Our overall RINs obligation is based on a percentage of our 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, we must purchase RINs on the open market. To mitigate the impact of the market risk relating to our obligations on our results of operations and cash flows, we may elect to purchase RINs or other environmental credits as part of our liability management strategy. We also have the ability to purchase RINs directly from SBR.

In addition, we are exposed to risks associated with complying with federal and state legislative and regulatory measures to address GHG and other emissions. Requirements to reduce emissions could result in increased costs to operate and maintain our facilities as well as implement and manage new emission controls and programs put in place. Compliance with such emission standards may require the purchase of emission credits or similar instruments.

The maximum commitment under our Revolving Credit Facility is $3.5 billion. Borrowings under the Revolving Credit Facility bear interest either at the Alternative Base Rate plus the Applicable Margin or at the Term SOFR plus the Applicable Margin, all as defined in the Revolving Credit Agreement. At December 31, 2023, we had no outstanding balance in variable interest debt. If this facility was fully drawn, a 1.0% change in the interest rate would increase or decrease our interest expense by approximately $23.7 million annually.

We are subject to risk of losses resulting from nonpayment or nonperformance by our counterparties. We continue to closely monitor the creditworthiness of customers to whom we grant credit and establish credit limits in accordance with our credit policy.

For the years ended December 31, 2023 and December 31, 2022, only one customer, Shell, accounted for 10% or more of our revenues (approximately 14% and 14%, respectively).

As of December 31, 2023 and December 31, 2022, only one customer, Shell, accounted for 10% or more of our total trade accounts receivable (approximately 19% and 19%, respectively).

We conducted evaluations, under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 as amended (the “Exchange Act”)) as of the end of the period covered by this report. Based upon these evaluations as required by Exchange Act Rule 13a-15(b), the principal executive officer and principal financial officer concluded that the disclosure controls and procedures are effective.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Exchange Act. Our internal control system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America. Due to its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2023, using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework (2013). Based on such assessment, management concluded that as of December 31, 2023, our internal control over financial reporting is effective.

This Annual Report on Form 10-K does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting as permitted by Item 308(b) of Regulation S-K for non-accelerated filers.

There has been no change in our internal control over financial reporting during the quarter ended December 31, 2023 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Messrs. Nimbley and Lucey and Ms. Canty serve as the sole directors of PBF Holding and PBF Finance. We believe that each of their experience as executive officers of PBF Holding make them qualified to serve as its directors.

PBF Energy, our indirect parent, has adopted a Code of Business Conduct and Ethics that applies to our principal executive officer, principal financial officer and principal accounting officer. The Code of Business Conduct and Ethics is available at www.pbfenergy.com under the heading “Investors”. Any amendments to the Code of Business Conduct and Ethics or any grant of a waiver from the provisions of the Code of Business Conduct and Ethics requiring disclosure under applicable Securities and Exchange Commission rules will be disclosed on such website.

Additional information required by this Item will be contained in PBF Energy’s 2024 Proxy Statement, incorporated herein by reference.

Directors of PBF Holding receive no separate compensation for service on the board of directors or committees thereof.

Additional information required under this Item will be contained in PBF Energy’s 2024 Proxy Statement, incorporated herein by reference.

As of December 31, 2023, 100% of the membership interests of PBF Holding were owned by PBF LLC, and PBF Finance had 100 shares of common stock outstanding, all of which were held by PBF Holding. Refer to “Note 12 - Equity Structure” of our Notes to Consolidated Financial Statements.

The stockholders of PBF Energy may be deemed to beneficially own an interest in our membership interests by virtue of their beneficial ownership of shares of Class A common stock of PBF Energy. PBF Energy reports separately on the beneficial ownership of its officers, directors and significant stockholders. For additional information, we refer you to PBF Energy’s 2024 Proxy Statement, which is incorporated herein by reference.

Refer to “Note 9 - Related Party Transactions” of our Notes to Consolidated Financial Statements.