UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark one)


☒			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended: December 31, ~~2022~~2023


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-35764

PBF HOLDING COMPANY LLC

PBF FINANCE CORPORATION

(Exact name of registrant as specified in its charter)


Delaware		27-2198168
Delaware		45-2685067
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

One Sylvan Way, Second Floor
Parsippany	New Jersey	07054
(Address of principal executive offices)		(Zip Code)

(973) 455-7500

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act.


Title of each class	Trading Symbol	Name of each exchange on which registered
N/A	N/A	N/A

Securities registered pursuant to Section 12(g) of the Act: None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

PBF Holding Company LLC ¨ Yes x No

PBF Finance Corporation ¨ Yes x No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

PBF Holding Company LLC x Yes ¨ No

PBF Finance Corporation x Yes ¨ No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

PBF Holding Company LLC ¨ Yes x No

PBF Finance Corporation ¨ Yes x No

(Note: The registrant is a voluntary filer of reports under Section 13 or 15(d) of the Securities Exchange Act of 1934 and has filed during the preceding 12 months all reports it would have been required to file by Section 13 or 15(d) of the Securities Exchange Act of 1934 if the registrant had been subject to one of such Sections.)

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

PBF Holding Company LLC x Yes ¨ No

PBF Finance Corporation x Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

PBF Holding Company LLC

Large accelerated
filer

☐

Accelerated filer

☐

Non-accelerated filer

☒

Smaller reporting
company

☐

Emerging growth company

☐

PBF Finance Corporation

Large accelerated
filer

☐

Accelerated filer

☐

Non-accelerated filer

☒

Smaller reporting
company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

PBF Holding Company LLC ¨

PBF Finance Corporation ¨

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.

PBF Holding Company LLC ¨

PBF Finance Corporation ¨

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.

PBF Holding Company LLC ¨

PBF Finance Corporation ¨

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b).

PBF Holding Company LLC ¨

PBF Finance Corporation ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

PBF Holding Company LLC ¨ Yes x No

PBF Finance Corporation ¨ Yes x No

There is no trading in the membership interests of PBF Holding LLC or the common stock of PBF Finance Corporation and therefore an aggregate market value based on such is not determinable.

PBF Holding Company LLC has no common stock outstanding. As of February 2423, ~~2023~~2024, 100% of the membership interests of PBF Holding Company LLC were owned by PBF Energy Company LLC, and PBF Finance Corporation had 100 shares of common stock outstanding, all of which were held by PBF Holding Company LLC.

PBF Finance Corporation meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this Form with the reduced disclosure format.

DOCUMENTS INCORPORATED BY REFERENCE

PBF Energy Inc., the managing member of our direct parent PBF Energy Company LLC, will file with the Securities and Exchange Commission a definitive Proxy Statement for its ~~2023~~2024 Annual Meeting of Stockholders within 120 days after December 31, ~~2022~~2023. Portions of the Proxy Statement of PBF Energy Inc. are incorporated by reference in Part III of this Form 10-K to the extent stated herein.

PBF HOLDING COMPANY LLC

TABLE OF CONTENTS

PART I
	Item 1.	Business	7
	Item 1A.	Risk Factors	2625
	Item 1B.	Unresolved Staff Comments	47
	Item 2.	Properties	47
	Item 1C.	Cybersecurity	48
	Item 3.	Legal Proceedings	48
	Item 2.	Properties	49
	Item 4.	Mine Safety Disclosures	50
	Item 3.	Legal Proceedings	50
	Item 4.	Mine Safety Disclosures	53
PART II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	5154
	Item 6.	[RESERVED]	5154
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	5255
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	8886
	Item 8.	Financial Statements and Supplementary Data	8987
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	8987
	Item 9A.	Controls and Procedures	9088
	Item 9B.	Other Information	9088
	Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	9088
PART III
	Item 10.	Directors, Executive Officers and Corporate Governance	9189
	Item 11.	Executive Compensation	9492
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	9492
	Item 13.	Certain Relationships and Related Transactions, and Director Independence	9492
	Item 14.	Principal Accountant Fees and Services	9492
PART IV
	Item 15.	Exhibits and Financial Statement Schedules	9593
	Item 16.	Form 10-K Summary
SIGNATURES

GLOSSARY OF SELECTED TERMS

Unless otherwise noted or indicated by context, the following terms used in this Annual Report on Form 10-K have the following meanings:

“AB 32” refers to the greenhouse gas emission control regulations in the state of California to comply with Assembly Bill 32.

“ANS” refers to Alaskan North Slope crude oil reflective of West Coast economics, characterized by API gravity between 28° and 35°.

“ASCI” refers to the Argus Sour Crude Index, a pricing index used to approximate market prices for sour, heavy crude oil.

“Bakken” refers to both a crude oil production region generally covering North Dakota, Montana and Western Canada, and the crude oil that is produced in that region.

“barrel” refers to a common unit of measure in the oil industry, which equates to 42 gallons.

“blendstocks” refers to various compounds that are combined with gasoline or diesel from the crude oil refining process to make finished gasoline and diesel; these may include natural gasoline, FCC unit gasoline, ethanol, reformate or butane, among others.

“bpd” is an abbreviation for barrels per day.

“CAM Pipeline” or “CAM Connection Pipeline” refers to the Clovelly-Alliance-Meraux pipeline in Louisiana.

“CARB” refers to the California Air Resources Board; gasoline and diesel fuel sold in the state of California are regulated by CARB and require stricter quality and emissions reduction performance than required by other states.

“catalyst” refers to a substance that alters, accelerates, or instigates chemical changes, but is not produced as a product of the refining process.

“coke” refers to a coal-like substance that is produced from heavier crude oil fractions during the refining process.

“complexity” refers to the number, type and capacity of processing units at a refinery, measured by the Nelson Complexity Index, which is often used as a measure of a refinery’s ability to process lower quality crude in an economic manner.

“COVID-19” refers to the 2019 outbreak of the novel coronavirus pandemic.

“crack spread” refers to a simplified calculation that measures the difference between the price for light products and crude oil. For example, we reference (a) the 2-1-1 crack spread, which is a general industry standard utilized by our Delaware City, Paulsboro and Chalmette refineries that approximates the per barrel refining margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of heating oil or ULSD, (b) the 4-3-1 crack spread, which is a benchmark utilized by our Toledo and Torrance refineries that approximates the per barrel refining margin resulting from processing four barrels of crude oil to produce three barrels of gasoline and one-half barrel of jet fuel and one-half barrel of ULSD and (c) the 3-2-1 crack spread, which is a benchmark utilized by our Martinez refinery that approximates the per barrel refining margin resulting from processing three barrels of crude oil to produce two barrels of gasoline and three-quarters of a barrel jet fuel and one-quarter of a barrel ULSD.

“Dated Brent” refers to Brent blend oil, a light, sweet North Sea crude oil, characterized by an American Petroleum Institute (“API”) gravity of 38° and a sulfur content of approximately 0.4 weight percent, that is used as a benchmark for other crude oils.

“distillates” refers primarily to diesel, heating oil, kerosene and jet fuel.

“downstream” refers to the downstream sector of the energy industry generally describing oil refineries, marketing and distribution companies that refine crude oil and sell and distribute refined products. The opposite of the downstream sector is the upstream sector, which refers to exploration and production companies that search for and/or produce crude oil and natural gas underground or through drilling or exploratory wells.

“EPA” refers to the United States Environmental Protection Agency.

“ESG” refers to environmental, social, and governance matters.

“ethanol” refers to a clear, colorless, flammable oxygenated liquid. Ethanol is typically produced chemically from ethylene, or biologically from fermentation of various sugars from carbohydrates found in agricultural crops. It is used in the United States as a gasoline octane enhancer and oxygenate.

“ExxonMobil” refers to Exxon Mobil Corporation.

“FCC” refers to fluid catalytic cracking.

“feedstocks” refers to crude oil and partially refined products that are processed and blended into refined products.

“GAAP” refers to U.S. generally accepted accounting principles developed by the Financial Accounting Standards Board for nongovernmental entities.

“GHG” refers to greenhouse gas.

“Group I base oils or lubricants” refers to conventionally refined products characterized by sulfur content less than 0.03% with a viscosity index between 80 and 120. Typically, these products are used in a variety of automotive and industrial applications.

“heavy crude oil” refers to a relatively inexpensive crude oil with a low API gravity characterized by high relative density and viscosity. Heavy crude oils require greater levels of processing to produce high value products such as gasoline and diesel.

“IPO” refers to the initial public offering of PBF Energy Class A common stock which closed on December 18, 2012.

“IRA” refers to the Inflation Reduction Act; a U.S. federal law enacted on August 16, 2022 that resulted in significant law changes related to tax, climate change, energy, and health care. The tax provision includes, but is not limited to, a corporate alternative minimum tax of 15%, excise tax of 1% on certain corporate stock buy-backs, energy-related tax credits and incentives, and additional Internal Revenue Service (“IRS”) funding.

“J. Aron” refers to J. Aron & Company, a subsidiary of The Goldman Sachs Group, Inc.

“KV” refers to Kilovolts.

“LCM” refers to a GAAP requirement for inventory to be valued at the lower of cost or market.

“light crude oil” refers to a relatively expensive crude oil with a high API gravity characterized by low relative density and viscosity. Light crude oils require lower levels of processing to produce high value products such as gasoline and diesel.

“light products” refers to the group of refined products with lower boiling temperatures, including gasoline and distillates.

“LLS” refers to Light Louisiana Sweet benchmark for crude oil reflective of Gulf coast economics for light sweet domestic and foreign crudes. It is characterized by an API gravity of between 35° and 40° and a sulfur content of approximately .35 weight percent.

“LPG” refers to liquefied petroleum gas.

“Maya” refers to Maya crude oil, a heavy, sour crude oil characterized by an API gravity of approximately 22° and a sulfur content of approximately 3.3 weight percent that is used as a benchmark for other heavy crude oils.

“MLP” refers to the master limited partnership.

“MMBTU” refers to million British thermal units.

“MOEM Pipeline” refers to a pipeline that originates at a terminal in Empire, Louisiana approximately 30 miles north of the mouth of the Mississippi River. The MOEM Pipeline is 14 inches in diameter, 54 miles long and transports crude from South Louisiana to the Chalmette refinery and transports Heavy Louisiana Sweet (“HLS”) and South Louisiana Intermediate (“SLI”) crude.

“MW” refers to Megawatt.

“Nelson Complexity Index” refers to the complexity of an oil refinery as measured by the Nelson Complexity Index, which is calculated on an annual basis by the Oil and Gas Journal. The Nelson Complexity Index assigns a complexity factor to each major piece of refinery equipment based on its complexity and cost in comparison to crude distillation, which is assigned a complexity factor of 1.0. The complexity of each piece of refinery equipment is then calculated by multiplying its complexity factor by its throughput ratio as a percentage of crude distillation capacity. Adding up the complexity values assigned to each piece of equipment, including crude distillation, determines a refinery’s complexity on the Nelson Complexity Index. A refinery with a complexity of 10.0 on the Nelson Complexity Index is considered ten times more complex than crude distillation for the same amount of throughput.

“NYH” refers to the New York Harbor market value of petroleum products.

“OSHA” refers to the Occupational Safety and Health Administration of the U.S. Department of Labor.

“refined products” refers to petroleum products, such as gasoline, diesel and jet fuel, that are produced by a refinery.

“Renewable Fuel Standard” (or “RFS”) refers to the Renewable Fuel Standard issued pursuant to the Energy Independence and Security Act of 2007 implementing mandates to blend renewable fuels into petroleum fuels produced and sold in the United States.

“RINs” refers to renewable fuel credits required for compliance with the RFS.

“Saudi Aramco” refers to Saudi Arabian Oil Company.

“SEC” refers to the United States Securities and Exchange Commission.

“sour crude oil” refers to a crude oil that is relatively high in sulfur content, requiring additional processing to remove the sulfur. Sour crude oil is typically less expensive than sweet crude oil.

“Sunoco” refers to Sunoco, LLC.

“sweet crude oil” refers to a crude oil that is relatively low in sulfur content, requiring less processing to remove the sulfur than sour crude oil. Sweet crude oil is typically more expensive than sour crude oil.

“Syncrude” refers to a blend of Canadian synthetic oil, a light, sweet crude oil, typically characterized by API gravity between 30° and 32° and a sulfur content of approximately 0.1-0.2 weight percent.

“throughput” refers to the volume processed through a unit or refinery.

“turnaround” refers to a periodically required shutdown and comprehensive maintenance event to refurbish and maintain a refinery unit or units that involves the cleaning, repair, and inspection of such units and occurs generally on a periodic cycle.

“ULSD” refers to ultra-low-sulfur diesel.

“WCS” refers to Western Canadian Select, a heavy, sour crude oil blend typically characterized by API gravity between 20° and 22° and a sulfur content of approximately 3.5 weight percent that is used as a benchmark for heavy Western Canadian crude oil.

“WTI” refers to West Texas Intermediate crude oil, a light, sweet crude oil, typically characterized by API gravity between 38° and 40° and a sulfur content of approximately 0.3 weight percent that is used as a benchmark for other crude oils.

“WTS” refers to West Texas Sour crude oil, a sour crude oil characterized by API gravity between 30° and 33° and a sulfur content of approximately 1.28 weight percent that is used as a benchmark for other sour crude oils.

“yield” refers to the percentage of refined products that is produced from crude oil and other feedstocks.

Explanatory Note

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, ~~2022~~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.

PART I

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 7.25875% senior unsecured notes due ~~2025~~2030 (the “~~2025~~2030 Senior Notes”) and the 6.00% senior unsecured notes due 2028 (the “2028 Senior Notes”) as of December 31, ~~2022~~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.

ITEM. 1. BUSINESS

Overview and Corporate Structure

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.

Ownership Structure

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, ~~2022~~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, ~~2022~~2023, PBF Energy held ~~129~~120,~~660~~461,~~538~~851 PBF LLC Series C Units and its current and former executive officers and directors and certain employees and others held ~~910~~862,~~457~~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.

PBF Holding Refineries

Our six refineries are located in Delaware City, Delaware, Paulsboro, New Jersey, Toledo, Ohio, Chalmette, Louisiana, Torrance, California and Martinez, California. In 2020, we reconfigured our Delaware City and Paulsboro refineries (the “East Coast Refining Reconfiguration”), temporarily idling certain of our major processing units at the Paulsboro refinery, in order to operate the two refineries as one functional unit that we refer to as the “East Coast Refining System”. Each refinery is briefly described in the table below:

Refinery

Region

Nelson Complexity Index (1)

Throughput Capacity (in barrels per day) (1)

PADD

Crude Processed (2)

Source (2)

Delaware City

East Coast

13.6

180,000

light sweet through heavy sour

water, rail

Paulsboro

East Coast

8.8 (3)

155,000(3)

light sweet through heavy sour

water

Toledo

Mid-Continent

11.0

180,000

light sweet

pipeline, truck, rail

Chalmette

Gulf Coast

13.0

185,000

light sweet through heavy sour

water, pipeline

Torrance

West Coast

13.8

166,000

medium and heavy

pipeline, water, truck

Martinez

West Coast

16.1

157,000

medium and heavy

pipeline and water

________

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

(1) Reflects operating conditions at each refinery as of the date of this filing. Changes in complexity and throughput capacity reflect the result of current market conditions, in addition to investments made to improve our facilities and maintain compliance with environmental and governmental regulations. Configurations at each of our refineries are regularly evaluated and accordingly updated, which resulted in the restart of several idled processing units at the Paulsboro refinery in 2022.

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

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

PBF Logistics LP Transactions

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. ~~PBF~~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 ~~July~~November 2730, 2022, PBF Energy ~~and~~acquired ~~PBF~~all ~~LLC~~of ~~entered~~the ~~into~~publicly ~~the~~held ~~Merger~~common ~~Agreement~~units ~~with~~in PBFX ~~announcing~~representing ~~the~~limited ~~Merger~~partner ~~Transaction,~~interests ~~which~~in ~~closed~~the onMLP ~~November~~not ~~30,~~already ~~2022~~owned ~~(all~~by ~~terms~~certain aswholly-owned ~~defined~~subsidiaries inof ~~the~~PBF ~~“Recent~~Energy ~~Developments”~~and ~~section~~its ~~below).~~affiliates, ~~See~~and ~~“Agreements with~~ PBFX” ~~below~~became asan ~~well~~indirect ~~as “Note 10~~ wholly-owned ~~Related~~subsidiary ~~Party Transactions”~~ of ~~our~~PBF ~~Notes to Consolidated Financial Statements for additional information~~Energy.

~~See “Item 1A~~St. ~~Risk~~Bernard ~~Factors”~~Renewables ~~and~~LLC ~~“Item 13. Certain Relationships and Related~~ Transactions, ~~and Director Independence.”~~

~~Recent~~On ~~Developments~~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.

~~Merger~~See ~~Transaction~~“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.”

On July 27, 2022, PBF Energy, PBF LLC, PBFX Holdings Inc., a Delaware corporation and wholly owned subsidiary of PBF LLC (“PBFX Holdings”), Riverlands Merger Sub LLC, a Delaware limited liability company and wholly owned subsidiary of PBF LLC, PBFX, and PBFX GP entered into a definitive agreement (the “Merger Agreement”) pursuant to which PBF Energy and PBF LLC announced their intention to acquire 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 on the closing date of the transaction (the “Merger Transaction”).

The Merger Transaction closed on November 30, 2022 and PBFX became an indirect wholly-owned subsidiary of PBF Energy and PBF LLC.

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

Renewable Diesel Project

We are currently progressing on our renewable diesel project that will be located at our Chalmette refinery (the “Renewable Diesel Project”). The Renewable Diesel Project will incorporate certain existing idled assets at the refinery, including an idle hydrocracker, along with a newly-constructed pre-treatment unit to establish a 20,000 bpd renewable diesel production facility. We continue to invest capital costs for the facility and related project infrastructure with a plan of commencing operations in the first half of 2023.

Additionally, as disclosed in “Note 20, Subsequent Events”, on February 16, 2023 we announced that we entered into a definitive agreement with Eni Sustainable Mobility, a subsidiary of Eni SpA (“Eni”), to partner in a 50-50 joint venture, St. Bernard Renewables LLC, (“SBR”) which will own the renewable diesel facility that is currently under construction at our Chalmette refinery. Upon consummation of the transaction, which is subject to customary closing conditions, including regulatory approvals, Eni will contribute capital and expertise in renewable diesel operations, supply and marketing while we will continue to manage project execution and will serve as the operator of the facility once construction is complete.

Available Information

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.

The diagram below depicts our organizational structure as of December 31, 2023:

The diagram below depicts our organizational structure as of December 31, 2022:

Refining Operations

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, ~~2022~~2023 are described below.

East Coast Refining System (Delaware City Refinery and Paulsboro Refinery)

Overview. The Delaware City refinery is located on an approximately 5,000-acre site, with access to waterborne cargoes and an extensive distribution network of pipelines, barges and tankers, truck and rail. The Delaware City refinery is a fully integrated operation that receives crude via rail at our crude unloading facilities, or via ship or barge at the docks owned by the Delaware City refinery located on the Delaware River. The crude and other feedstocks are stored in an extensive tank farm prior to processing. In addition, there is a 15-lane, 76,000 bpd capacity truck loading rack located adjacent to the refinery and a 23-mile interstate pipeline that are used to distribute clean products. The Paulsboro refinery is located on approximately 950-acres on the Delaware River in Paulsboro, New Jersey, near Philadelphia and approximately 30 miles away from Delaware City. Paulsboro receives crude and feedstocks via its marine terminal on the Delaware River.

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.

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The following table approximates the East Coast Refining System’s current major process unit capacities. Unit capacities are shown in barrels per stream day.


Delaware City Refinery Units			Nameplate Capacity
Crude Distillation Unit			180,000
Vacuum Distillation Unit			105,000
Fluid Catalytic Cracking Unit			82,000
Hydrotreating Units			180,000
Hydrocracking Unit			24,000
Catalytic Reforming Unit			43,000
Benzene / Toluene Extraction Unit			15,000
Butane Isomerization Unit			6,000
Alkylation Unit			12,500
Polymerization Unit			16,000
Fluid Coking Unit			54,500


Paulsboro Refinery Units						Nameplate Capacity
Crude Distillation Units (1)						155,000
Vacuum Distillation Units (1)						50,000
Fluid Catalytic Cracking Unit (1)						Idled
Hydrotreating Units (1)						102,000
Catalytic Reforming Unit (1)						29,000
Alkylation Unit (1)						Idled
Lube Oil Processing Unit						12,000
Delayed Coking Unit (1)						Idled
Propane Deasphalting Unit						11,000

~~(1)~~—————————— ~~Current nameplate capacity was fully or partially reduced as part of the East Coast Refining Reconfiguration.~~

~~Feedstocks~~(1) ~~and~~Current ~~Supply~~nameplate ~~Arrangements.~~capacity Wewas ~~source~~fully ~~our~~or ~~crude~~partially ~~oil~~reduced ~~needs~~as ~~for~~part ~~Delaware~~of ~~City~~the ~~primarily~~2020 ~~through~~reconfiguration ~~short-term and spot market agreements. We have a contract with Saudi Aramco pursuant to which we have purchased up to approximately 100,000 bpd~~ of ~~crude~~our ~~oil~~Delaware ~~from~~City ~~Saudi~~and ~~Aramco~~Paulsboro ~~that~~refineries ~~is processed at~~ (the ~~Paulsboro~~“East ~~refinery.~~Coast ~~The~~Refining ~~crude purchased under this contract is priced off the ASCI~~Reconfiguration”).

~~Refined~~Feedstocks ~~Product Yield~~ and ~~Distribution~~Supply Arrangements. ~~The~~We ~~Delaware~~source ~~City~~our ~~refinery~~crude ~~predominantly~~oil ~~produces gasoline, jet fuel, ULSD~~ and ~~ultra-low~~feedstock ~~sulfur~~needs ~~heating~~for ~~oil as well as certain other products. Products produced at~~ the ~~Delaware~~East ~~City~~Coast ~~refinery~~Refining ~~are~~System ~~transferred to customers~~ through ~~pipelines~~waterborne deliveries, ~~barges~~primarily orthrough atshort-term ~~its truck rack. We market~~ and ~~sell all of our refined products independently to a variety of customers on the~~ spot market ~~or through term~~ agreements. ~~The~~We ~~Paulsboro~~also ~~refinery~~have ~~predominantly~~a ~~manufactures~~crude ~~Group~~supply Icontract ~~base~~with ~~oils~~Saudi orAramco, ~~lubricants~~the ~~and~~term ~~asphalt~~of ~~and~~which ~~jet~~is ~~fuel.~~currently ~~Products~~year ~~produced~~to atyear, ~~the~~for ~~Paulsboro~~up ~~refinery are transferred~~ to ~~customers~~approximately ~~primarily~~100,000 ~~through~~bpd ~~pipelines,~~that ~~barges,~~is orprocessed at ~~its truck rack. We market and sell all of our refined products independently to a variety of customers on~~ the ~~spot~~Paulsboro ~~market or through term agreements~~refinery.

13Refined Product Yield and Distribution. The Delaware City refinery predominantly produces gasoline, jet fuel, ULSD and ultra-low sulfur heating oil as well as certain other products. Products produced at the Delaware City refinery are transferred to customers through pipelines, barges or at its truck rack. We market and sell all of our refined products independently to a variety of customers on the spot market or through term agreements. The Paulsboro refinery predominantly manufactures Group I base oils or lubricants and asphalt, jet fuel and ULSD. Products produced at the Paulsboro refinery are transferred to customers primarily through pipelines, barges, or at its truck rack. We market and sell all of our refined products independently to a variety of customers on the spot market or through term agreements.

Inventory Intermediation Agreement. On October 25, 2021, we entered into a third amended and restated inventory intermediation agreement with J. Aron, (the “Third Inventory Intermediation Agreement”), to support the operations of the Delaware City, Paulsboro and Chalmette refineries (collectively, the “PBF Entities”). The Third Inventory Intermediation Agreement expires on December 31, 2024, which term may be further extended by mutual consent of the parties to December 31, 2025. 12

~~Pursuant to the Third~~ Inventory Intermediation Agreement~~, J~~. ~~Aron~~On ~~purchases~~July ~~and~~31, ~~holds~~2023, ~~title~~we toearly ~~certain~~terminated ~~inventory,~~the ~~including~~third ~~crude~~amended ~~oil, intermediate~~ and ~~certain~~restated ~~finished~~inventory ~~products~~intermediation agreement (the “J.Third ~~Aron~~Inventory ~~Products~~Intermediation Agreement”), ~~purchased~~previously orentered ~~produced~~into by ~~the Paulsboro~~ and ~~Delaware~~among ~~City~~PBF ~~refineries~~Holding (and, atits ~~the~~subsidiaries, ~~election of the PBF Entities~~DCR, ~~the~~PRC and Chalmette ~~refinery)~~Refining (~~the~~collectively, ~~"Refineries") and delivered into our storage tanks at~~ the ~~Refineries (the~~ “~~Storage~~PBF ~~Tanks~~Entities”). ~~The~~and J. Aron ~~Products are sold back~~ to ussupport as the J.operations ~~Aron Products are discharged out~~ of ~~our Storage Tanks. At expiration or termination of~~ the ~~Third~~PBF ~~Inventory Intermediation Agreement, we will have to repurchase the inventories outstanding under the Third Inventory Intermediation Agreement at that time~~Entities.

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.

Tankage Capacity. The Delaware City refinery has total storage capacity of approximately 10.0 million barrels. Of the total, approximately 3.6 million barrels of storage capacity are dedicated to crude oil and other feedstock storage with the remaining 6.4 million barrels allocated to finished products, intermediates and other products. The Paulsboro refinery has total storage capacity of approximately 7.5 million barrels. Of the total, approximately 2.1 million barrels are dedicated to crude oil storage with the remaining 5.4 million barrels allocated to finished products, intermediates and other products.

Energy and Other Utilities. Under normal operating conditions, the Delaware City refinery consumes approximately 75,000 MMBTU per day of natural gas supplied via pipeline from third parties. The Delaware City refinery has a 280 MW power plant located on site that consists of two natural gas-fueled turbines with combined capacity of approximately 140 MW and four turbo generators with combined nameplate capacity of approximately 140 MW. Collectively, this power plant produces electricity in excess of Delaware City’s refinery load of approximately 90 MW. Excess electricity is sold into the Pennsylvania-New Jersey-Maryland, or PJM, grid. Steam is primarily produced by a combination of three dedicated boilers, two heat recovery steam generators on the gas turbines, and is supplemented by secondary boilers at the FCC and Coker. Hydrogen is currently provided via the refinery’s steam methane reformer and continuous catalytic reformer.

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.

Toledo Refinery

Overview. The Toledo refinery primarily processes a slate of light, sweet crudes from Canada, the Mid-Continent, the Bakken region and the U.S. Gulf Coast. The Toledo refinery is located on a 282-acre site near Toledo, Ohio, approximately 60 miles from Detroit. Crude is delivered to the Toledo refinery through three primary pipelines: (1) Enbridge from the north, (2) Patoka from the west and (3) Mid-Valley from the south. Crude is also delivered to a nearby terminal by rail and from local sources by truck to a truck unloading facility within the refinery.

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


Toledo Refinery Units			Nameplate Capacity
Crude Distillation Unit			180,000
Fluid Catalytic Cracking Unit			82,000
Hydrotreating Units			95,000
Hydrocracking Unit			52,000
Catalytic Reforming Units			52,000
Alkylation Unit			11,000
Polymerization Unit			7,000
UDEX Unit			16,300

Feedstocks and Supply Arrangements. We source our crude oil and feedstock needs for the Toledo refinery through connections to the Marysville Pipeline and Maumee Pipeline, and via truck rack, primarily through short-term and spot market agreements.

Refined Product Yield and Distribution. The Toledo refinery produces finished products, including gasoline, jet and ULSD, in addition to a variety of high-value petrochemicals including benzene, toluene, xylene, nonene and tetramer. The Toledo refinery is connected, via pipelines, to an extensive distribution network throughout Ohio, Illinois, Indiana, Kentucky, Michigan, Pennsylvania and West Virginia. The finished products are transported on pipelines owned by Sunoco Logistics Partners L.P. and Buckeye Partners L.P. In addition, we have proprietary connections to a variety of smaller pipelines and spurs that help us optimize our clean products distribution. A significant portion of the Toledo refinery’s gasoline and ULSD are distributed through various terminals in this network.

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.

Tankage Capacity. The Toledo refinery has total storage capacity of approximately 4.5 million barrels. The Toledo refinery receives its crude through pipeline connections and a truck rack. Of the total, approximately 1.3 million barrels are dedicated to crude oil storage with the remaining 3.2 million barrels allocated to intermediates and products.

Energy and Other Utilities. Under normal operating conditions, the Toledo refinery consumes approximately 25,000 MMBTU per day of natural gas supplied via pipeline from third parties. The Toledo refinery purchases its electricity from the PJM grid and has a long-term contract to purchase hydrogen and steam from a local third-party supplier. In addition to the third-party steam supplier, the Toledo refinery consumes a portion of the steam that is generated by its various process units.

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Chalmette Refinery

Overview. The Chalmette refinery is located on a 400-acre site near New Orleans, Louisiana. It is a dual-train coking refinery and is capable of processing both light and heavy crude oil through its 185,000 bpd crude units and downstream units. Chalmette Refining owns 100% of the MOEM Pipeline, providing access to the Empire Terminal, as well as the CAM Connection Pipeline, providing access to the Louisiana Offshore Oil Port facility through a third-party pipeline. Chalmette Refining also owns 80% of each of the Collins Pipeline Company (“Collins”) and T&M Terminal Company (“T&M”), both located in Collins, Mississippi, which provide a clean products outlet for the refinery to the Plantation and Colonial Pipelines. In addition, there is also a marine terminal capable of importing waterborne feedstocks and loading or unloading finished products. There is also a clean products truck rack that provides access to local markets and crude storage. WeThe ~~are~~Renewable ~~currently~~Diesel ~~progressing~~Facility onis ~~our~~also ~~renewable diesel project that will be~~ located at our Chalmette refinery. The ~~project~~facility ~~will~~incorporates ~~incorporate~~a ~~certain~~repurposed ~~existing idled assets at the refinery, including an idle~~ hydrocracker, along with a newly-constructed pre-treatment unit to establish a capacity to produce 20,000 bpd renewable diesel ~~production facility which is set to be started in the first half of 2023~~.

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


Chalmette Refinery Units			Nameplate Capacity
Crude Distillation Units			185,000
Vacuum Distillation Unit			114,000
Fluid Catalytic Cracking Unit			75,000
Hydrotreating Units			189,000
Delayed Coking Unit			42,000
Catalytic Reforming Unit			42,000
Alkylation Unit			17,000
Aromatics Extraction Unit			17,000

Feedstocks and Supply Arrangements. We source our crude oil and feedstock needs for the Chalmette refinery through connections to the CAM Pipeline and MOEM Pipeline, asand ~~well~~via aswaterborne ~~our marine terminal~~deliveries, ~~and~~primarily through short-term and spot market agreements.

Refined Product Yield and Distribution. The Chalmette refinery predominantly produces gasoline and diesel fuels and also manufactures high-value petrochemicals including benzene and xylene. Products produced at the Chalmette refinery are transferred to customers through pipelines, the marine terminal and truck rack. The majority of our clean products are delivered to customers via pipelines. Our ownership of the Collins pipeline and T&M terminal provides the Chalmette refinery with strategic access to Southeast and East Coast markets through third-party logistics.

Inventory Intermediation Agreement. AtOn ~~the~~July ~~election~~31, ~~of the PBF Entities~~2023, ~~certain~~we ~~inventory~~early atterminated the ~~Chalmette refinery may be held by J. Aron pursuant to the~~ Third Inventory Intermediation Agreement. Refer to East Coast Refining System (Delaware City refinery and Paulsboro refinery), above, for further details.

Tankage Capacity. The Chalmette refinery has a total tankage capacity of approximately 8.1 million barrels. Of this total, approximately 2.6 million barrels are allocated to crude oil storage with the remaining 5.5 million barrels allocated to intermediates and products.

Energy and Other Utilities. Under normal operating conditions, the Chalmette refinery consumes approximately 25,000 MMBTU per day of natural gas supplied via pipeline from third parties. The Chalmette refinery purchases its electricity from a local utility and has a long-term contract to purchase hydrogen from a third-party supplier.

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Torrance Refinery

Overview. The Torrance refinery is located on 750-acres in Torrance, California. It is a high-conversion crude, delayed-coking refinery capable of processing both heavy and medium crude oils through its crude unit and downstream units. In addition to refining assets, the Torrance refinery acquisition included a number of high-quality logistics assets including a sophisticated network of crude and products pipelines, product distribution terminals and refinery crude and product storage facilities. The most significant logistics asset is a crude gathering and transportation system which delivers San Joaquin Valley crude oils directly from the field to the refinery, which is now owned by PBFX. Additionally, there are several pipelines serving the refinery that provide access to sources of waterborne crude oils including the Ports of Long Beach and Los Angeles, as well as clean product outlets with a direct pipeline that supplies jet fuel to the Los Angeles airport that are held by affiliates of the refinery.

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


Torrance Refinery Units			Nameplate Capacity
Crude Distillation Unit			166,000
Vacuum Distillation Unit			102,000
Fluid Catalytic Cracking Unit			90,000
Hydrotreating Units			155,500
Hydrocracking Unit			25,000
Alkylation Unit			25,500
Delayed Coking Unit			58,000

Feedstocks and Supply Arrangements. ~~The Torrance refinery primarily processes a variety of medium and heavy crude oils.~~ We ~~have~~source aour crude ~~supply~~oil ~~agreement~~and ~~with~~feedstock ~~ExxonMobil~~needs for ~~approximately~~the ~~60,000 bpd of crude oil that can be processed at our~~ Torrance refinery. ~~This~~mainly ~~crude~~through ~~supply~~connections ~~agreement~~to ~~has~~our anown ~~automatic renewal feature~~pipeline, ~~unless~~and ~~either~~via ~~party~~waterborne ~~gives~~deliveries ~~thirty-six~~and ~~months~~truck ~~written termination notice. Additionally~~racks, weprimarily ~~obtain crude and feedstocks from other sources~~ through ~~connections to third~~short-~~party~~term ~~pipelines as well as ship docks~~ and ~~truck~~spot ~~racks~~market agreements.

Refined Product Yield and Distribution. The Torrance refinery predominantly produces gasoline, jet fuel and diesel fuels. Products produced at the Torrance refinery are transferred to customers through pipelines, the marine terminal and truck rack. The majority of clean products are delivered to customers via pipelines. We currently market and sell all of our refined products independently to a variety of customers either on the spot market or through term agreements.

Tankage Capacity. The Torrance refinery has a total tankage capacity of approximately 8.6 million barrels. Of this total, approximately 2.1 million barrels are allocated to crude oil storage with the remaining 6.5 million barrels allocated to intermediates and products.

Energy and Other Utilities. Under normal operating conditions, the Torrance refinery consumes approximately 47,000 MMBTU per day of natural gas supplied via pipeline from third parties. The Torrance refinery generates some power internally using a combination of steam and gas turbines and purchases any additional needed power from the local utility. The Torrance refinery has a long-term contract to purchase hydrogen from a third-party supplier.

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Martinez Refinery

Overview. The Martinez refinery is located on an 860-acre site in the City of Martinez, 30 miles northeast of San Francisco, California. The refinery is a high-conversion, dual-coking facility ~~with~~and ~~a Nelson Complexity Index of 16.1, making it~~ one of the most complex refineries in the United States. The facility is strategically positioned in Northern California and provides for operating and commercial synergies with the Torrance refinery located in Southern California. In addition to refining assets, the Martinez refinery includes a number of high-quality onsite logistics assets including a deep-water marine facility, product distribution terminals and refinery crude and product storage facilities with approximately 8.8 million barrels of shell capacity.

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


Martinez Refinery Units						Nameplate Capacity
Crude Distillation Unit						157,000
Vacuum Distillation Unit						102,000
Fluid Catalytic Cracking Unit						72,000
Hydrotreating Units						268,000
Hydrocracking Unit						42,900
Alkylation Unit						12,500
Delayed Coking Unit						25,500
Flexi Coking Unit						22,500
Isomerization Unit						15,000

Feedstocks and Supply Arrangements. We ~~have~~source ~~entered~~our ~~into~~crude ~~various~~oil ~~five~~and feedstock needs for the Martinez refinery through connections to the Crimson San Pablo Bay Pipeline, and via waterborne deliveries, primarily through short-~~year~~term and spot market agreements. We also have crude supply agreements with Shell ~~Oil~~Trading ~~Products~~(US) ~~for~~Company ~~approximately~~(primarily ~~150,000~~serving ~~bpd, in~~ the ~~aggregate,~~Martinez torefinery) ~~support~~for ~~our~~up ~~West~~to ~~Coast~~95,000 ~~and~~bpd, ~~Mid-Continent~~which, ~~refinery~~upon ~~operations.~~expiration ~~Additionally,~~of weone ~~obtain~~of ~~crude~~the ~~and~~agreements ~~feedstocks~~in ~~from~~early ~~other~~2024, ~~sources~~will ~~through~~be ~~connections~~reduced to ~~third-party~~up ~~pipelines~~to asapproximately ~~well~~65,000 asbpd, ~~ship~~through ~~docks~~early 2025.

Refined Product Yield and Distribution. We entered into certain offtake agreements for our West Coast system with Shell Oil Products for clean products with varying terms up to 15 years. We currently market and sell all of our refined products independently to a variety of customers either on the spot market or through term agreements.

Tankage Capacity. Martinez has a total tankage capacity of approximately 8.8 million barrels. Of this total, approximately 2.5 million barrels are allocated to crude oil storage with the remaining 6.3 million barrels allocated to intermediates and products.

Energy and Other Utilities. Under normal operating conditions, the Martinez refinery consumes approximately 80,000 MMBTU per day of natural gas (including natural gas consumed in hydrogen production) supplied via pipeline from third parties. The Martinez refinery generates some power internally using a combination of steam and gas turbines and purchases any additional needed power from the local utility. The Martinez refinery has a long-term contract to purchase hydrogen from a third-party supplier.

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Agreements with PBFX

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.

Contribution Agreements

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:


Contribution Agreement	Effective Date	Assets Contributed	Total Consideration
Contribution Agreement I	5/8/2014	DCR Rail Terminal and the Toledo Truck Terminal	74,053 PBFX common units and 15,886,553 PBFX subordinated units
Contribution Agreement II	9/16/2014	DCR West Rack	$135.0 million in cash and $15.0 million through the issuance of 589,536 PBFX common units
Contribution Agreement III	12/2/2014	Toledo Storage Facility	$135.0 million in cash and $15.0 million through the issuance of 620,935 PBFX common units
Contribution Agreement IV	5/5/2015	DCR Products Pipeline and DCR Truck Rack	$112.5 million in cash and $30.5 million through the issuance of 1,288,420 PBFX common units
Contribution Agreement V	8/31/2016	Torrance Valley Pipeline (50% equity interest in TVPC)	$175.0 million in cash
Contribution Agreement VI	2/15/2017	Paulsboro Natural Gas Pipeline	$11.6 million affiliate promissory note
Contribution Agreements VII-X	7/16/2018	Development Assets	$31.6 million through the issuance of 1,494,134 PBFX common units
Contribution Agreement XI	4/24/2019	Remaining 50% equity interest in TVPC	$200.0 million in cash

Commercial Agreements

PBFX currently derives the majority of its revenue from long-term, fee-based agreements with us, which generally include a minimum volume commitment ~~(“MVC”)~~, 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.

Refer to “Note 10 - Related Party Transactions” of our Notes to Consolidated Financial Statements for further discussion regarding the commercial agreements with PBFX.

Omnibus Agreement

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 ~~PBF~~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, 2022 was $8.3 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, 2022. We currently estimate to receive $8.3 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, 2023.18

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.

Services Agreement

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, ~~2022~~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, ~~2023~~2024.

On February 13, 2019, we amended the existing Amended and Restated Delaware City Rail Terminaling Services Agreement, by and between Delaware City Terminaling Company LLC (“DCTC”) and us (as amended effective January 1, 2019, the “Amended and Restated Delaware City Rail Terminaling Services Agreement”) for the inclusion of services through certain rail infrastructure (the “East Coast Rail Assets”) at the assets acquired in connection with the PBFX acquisition of CPI Operations LLC (the “East Coast Storage Assets”). We also entered into a new Terminaling Services Agreement, by and between DCTC and us, with a four-year term starting on January 1, 2022, subsequent to the expiration of the Amended and Restated Delaware City Rail Terminaling Services Agreement, related to the DCR Rail Facilities and the East Coast Rail Assets, which reduced the MVC to 95,000 bpd and includes additional services to be provided by PBFX as operator of facilities owned by our subsidiaries.

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

Agreements with SBR

The Company has entered into agreements with SBR for the sale of RINs and Low Carbon Fuel Standard (“LCFS”) credits.

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.

Principal Products

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, ~~2022~~2023, ~~2021~~2022 and ~~2020~~2021, gasoline and distillates accounted for 88.68%, 8688.46% and 8586.14% of our revenues, respectively.

Customers

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, ~~2022~~2023 and December 31, ~~2021~~2022 only one customer, Shell plc (“Shell”), accounted for 10% or more of our revenues (approximately 14% and 1514%, respectively). As of December 31, ~~2022~~2023 and December 31, ~~2021~~2022, only one customer, Shell, accounted for 10% or more of our total trade accounts receivable (approximately 19% and 2619%, respectively).

Seasonality

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 ~~2022~~recent ~~and 2021~~years.

Competition

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. ~~However,~~Because ~~unlike certain of our competitors,~~ we ~~currently~~ do not directly produce renewable fuels, ~~and~~ increasing the volume of renewable fuels that must be blended into our products ~~displaces~~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.

Corporate Offices

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.

Employees and Human Capital

Safety

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.

Development and Retention

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.

2221

Headcount

As of December 31, ~~2022~~2023, we had approximately 3,~~526~~686 employees, of which 1,~~864~~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.

Location

Number of employees

Employees covered by collective bargaining agreements

Collective bargaining agreements

Expiration date

Headquarters

~~414~~470

—

N/A

Delaware City refinery

~~525~~535

~~372~~374

USW

January 2026

Paulsboro refinery

~~270~~301

~~174~~189

IOW

March 2026

Toledo refinery

~~490~~524

~~2975~~327

~~USWUSW~~USW

February ~~2026February~~ 2026

Chalmette refinery

~~582~~587

~~323~~335

USW

January 2026

Torrance refinery

~~588~~592

~~31911~~30415

USWIBEW

January 2026January 2026

Torrance logistics

9697

~~414~~102813

~~USWUSW~~USWUSWUSW

April 2024January ~~2026~~2026March 2028

Martinez refinery

~~561~~580

~~30414~~30715

USWIBEW

February 2026February 2026

Total employees

3,~~526~~686

1,~~864~~917

2322

Environmental, Health and Safety Matters

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:

•Item 1A. “Risk Factors”

◦Our results of operations continue to be impacted by significant costs to comply with renewable fuels mandates. The market prices for RINs have been volatile and may harm our profitability;

◦We may have capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate;

◦We may incur significant liability under, or costs and capital expenditures to comply with, environmental and health and safety regulations, which are complex and change frequently;

◦Potential further laws and regulations related to climate change could have a material adverse impact on our operations and adversely affect our facilities;

◦Regulation of emissions of greenhouse gases could force us to incur increased capital expenditures and operating costs that could have a material adverse effect on our results of operations and financial condition;

◦Environmental clean-up and remediation costs of our sites and environmental litigation could decrease our net cash flow, reduce our results of operations and impair our financial condition;

◦Our pipelines are subject to federal and/or state regulations, which could reduce profitability and the amount of cash we generate;

◦We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with health, safety, environmental and other laws and regulations;

◦Enhanced scrutiny on ESG matters and developments related to climate change may negatively impact our business and our access to capital markets;

◦We are subject to strict laws and regulations regarding employee and process safety, and failure to comply with these laws and regulations could have a material adverse effect on our results of operations, financial condition and profitability.

•Item 3. “Legal Proceedings”

•Item 8. “Financial Statements and Supplementary Data”

◦ Note 7 - Accrued Expenses,

◦ Note 910 - ~~Other~~Commitments ~~Long-Term Liabilities~~ and Contingencies

~~◦ Note 11 - Commitments and Contingencies~~23

Applicable Federal and State Regulatory Requirements

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:

•Item 8. “Financial Statements and Supplementary Data”

◦ Note 1110 - Commitments and Contingencies

2524

ITEM 1A. RISK FACTORS

Summary of Risk Factors

Operating in our industry involves a degree of risk. These risks are discussed more fully below and include, but are not limited to, the following, any of which could have a material adverse effect on our financial condition, results of operations and cash flows:

Risks Relating to Our Business and Industry

•The price volatility of crude oil, other feedstocks, blendstocks, refined products and fuel and utility services;

•Volatility in commodity prices and refined product demand;

•Crude oil differentials and related factors, which fluctuate substantially;

•Significant interruptions or casualty losses at any of our refineries and related assets ~~or logistics terminals, pipelines or other facilities~~;

•Interruptions of supply and distribution at our refineries;

•Renewable fuels mandates and the cost of RINs;

•Existence of capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate;

•Regulation ofrelated to climate change and emissions of greenhouse gases and other regulatory environmental and health and safety regulations;

•Completion and successful commencement of commercial operation of the renewable diesel project and consummation of the proposed joint venture transaction;

•Enhanced scrutiny on ESG matters;

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

•Actions taken by our competitors, including adjustments to refining capacity or renewable fuels production in response to regulations and market conditions;

•Volatility and uncertainty in the credit and capital markets, including as a result of higher interest rates;

•Any political instability, including as a result of Russia’s military action in Ukraine, the outbreak of armed hostilities in the middle east, disruption in international shipping resulting from recent attacks by armed groups on cargo ships in the Red Sea, military strikes, sustained military campaigns, terrorist activity, changes in foreign policy, or other catastrophic events;

•A cyber-attack on, or other failure of, our technology infrastructure;

•Competition from other companies in the refining industry;

•Delays or cost increases related to capital spending programs;

•Product liability claims, operational liability claims and other material litigation;

•Acquisition or integration of new assets into our business;

•Labor disruptions that would interfere with our operations;

•Discontinuation of employment of any of our senior executives or other key employees;

•Our activity in commodity derivatives markets.

Risks Related to Our Indebtedness

•Our levels of indebtedness;

•Our ability to secure necessary financing on acceptable terms;

•Changes in our credit ratings;

•Limitations on our operations or ability to make distributions arising out of restrictive covenants in our debt instruments;

•Anti-takeover provisions in our indentures.

2625

Risk Factors

You should carefully read the risks and uncertainties described below. The risks and uncertainties described below are not the only ones facing our ~~company~~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.

Risks Relating to Our Business and Industry

Demand for our refined products can significantly decline due to changes in global and regional economic conditions.

Business closings and layoffs in the markets we operate may adversely affect demand for our refined products. Deterioration of general economic conditions or weak demand levels could require additional actions on our part to lower our operating costs, including temporarily or permanently ceasing to operate units at our facilities~~, as experienced in 2020 when certain assets were temporarily idled as part of the East Coast Refining Reconfiguration~~. There may be significant incremental costs associated with such actions. Deterioration of global and regional economic conditions may harm our liquidity and ability to repay our outstanding debt.

The price volatility of crude oil, other feedstocks, blendstocks, refined products and fuel and utility services may have a material adverse effect on our revenues, profitability, cash flows and liquidity.

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 ~~lower~~LCM ~~of cost or market~~ value under the last-in-first-out (“LIFO”) inventory valuation methodology. At December 31, ~~2022~~2023 and December 31, ~~2021~~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. For example, during the year ended December 31, 2020, we recorded an adjustment to value our inventories to the lower of cost or market which decreased income from operations and net income by $268.0 million.

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.

2726

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.

Our working capital, cash flows and liquidity can be significantly impacted by volatility in commodity prices and refined product demand.

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.

Our profitability is affected by crude oil differentials and related factors, which fluctuate substantially.

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, ~~efforts~~imbalances inbetween ~~Canada to control~~ the ~~imbalance between its~~ 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.

2827

A significant interruption or casualty loss at any of our refineries and related assets could reduce our production, particularly if not fully covered by our insurance. Failure by one or more insurers to honor its coverage commitments for an insured event could materially and adversely affect our future cash flows, operating results and financial condition.

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 wedesired ~~desire~~ 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 ~~for~~that ~~which~~was ~~we were~~ 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 refineries are subject to interruptions of supply and distribution, including due to severe weather events, as a result of our reliance on pipelines and railroads for transportation of crude oil and refined products.

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.

2928

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.

Our results of operations continue to be impacted by significant costs to comply with renewable fuels mandates. The market prices for RINs have been volatile and may harm our profitability.

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 ~~currently~~directly produce renewable fuels, increasing the volume of renewable fuels that must be blended into our products ~~displaces~~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. ~~The~~Our ~~price~~results ofcontinue ~~RINS~~to ~~was~~be ~~significant~~impacted inby ~~2022~~significant ~~and~~costs ~~could~~to ~~increase~~comply ~~further~~with inthe ~~2023~~RFS. WeWhile we have entered into agreements with SBR that allow us to purchase RINs at our election, we incurred approximately $~~1,225~~762.53 million in RINs costs during the year ended December 31, ~~2022~~2023 as compared to $~~726~~1,225.05 million and $~~326~~726.40 million during the years ended December 31, ~~2021~~2022 and ~~2020~~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 321, ~~2022~~2023, EPA finalized the volumes of renewable fuels that obligated refineries must blend into their final petroleum fuels for years ~~2020~~2023, ~~2021~~2024, and ~~2022. On December 1~~2025, ~~2022,~~and ~~EPA~~finalized ~~proposed~~ 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.

3029

We may have capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate.

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 ~~not covered by our various supply agreements and the Third Inventory Intermediation Agreement~~.

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. ~~Termination~~Following our early termination of ~~our~~the Third Inventory Intermediation Agreement ~~with J. Aron~~, ~~which~~we iswill ~~currently~~fund ~~scheduled~~all tofuture ~~expire~~inventory inpurchases ~~2024,~~with ~~would~~existing ~~require~~working uscapital toor ~~finance~~other ~~the J. Aron Products covered by the agreement, which financing may not be~~ available atsources ~~terms that are as favorable or at all. We are obligated to repurchase from J. Aron all volumes~~ of ~~the J. Aron Products upon expiration or earlier termination of this agreement, which may have a material adverse impact on our~~ liquidity~~, working capital and financial condition~~. 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.

We may incur significant liability under, or costs and capital expenditures to comply with, regulatory, environmental and health and safety regulations, which are complex and change frequently.

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.

3130

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, onMRC ~~July~~is ~~21,~~subject ~~2021, the board of Bay Area Air Quality Management District (“BAAQMD”) voted~~ to ~~adopt~~ 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. ~~The~~Although ~~regulation~~MRC ~~does~~believes ~~not~~that ~~require~~it ~~that~~will ~~any~~achieve ~~specific~~compliance ~~technology~~through bethe ~~utilized~~alternative toemissions ~~meet~~monitoring ~~the~~system ~~new~~(“AEMS”) ~~standards.~~approved ~~The~~by ~~costs~~the ~~incurred~~Bay byArea usAir toQuality ~~achieve~~Management ~~the~~District ~~new~~(“BAAQMD”) ~~emissions~~and ~~standards~~subject atto ~~our~~validation ~~Martinez~~as ~~refinery~~part ~~within~~of the ~~required~~settlement ~~timeframe~~agreement ~~may~~entered beinto ~~significant~~on February 12, ~~and~~2024, there can be no assurance that the ~~measures~~AEMS wewill ~~implement~~be ~~will~~validated or achieve the required emissions reductions. ~~Additionally,~~or onthat ~~September~~we ~~16, 2022, the state of California enacted SB 1322, The California Oil Refinery Cost Disclosure Act. Effective in 2023, this bill~~ will ~~require~~not ~~operators~~incur ofsignificant ~~refineries~~additional incosts ~~the state that produce gasoline meeting California specifications, within 30 days of the end of each calendar month,~~ to ~~submit~~comply towith the ~~State~~Rule ~~Energy~~6-5 ~~Resources Conservation and Development Commission certain information regarding petroleum sales volumes and prices~~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.

See also “Recent record refining industry profits have raised the concern of public policy experts and federal and state policymakers, who have questioned whether these profits are justified, or whether they constituted a “windfall” to the industry and have enacted, or could enact legislation that could adversely affect our operations and our profitability” risk factor below for additional regulatory risks that are not environmental, health or safety-related.

Potential further laws and regulations related to climate change could have a material adverse impact on our operations and adversely affect our facilities.

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.

Regulation of emissions of greenhouse gases could force us to incur increased capital expenditures and operating costs and could have a material adverse effect on our results of operations and financial condition.

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 ~~already~~ 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.

~~incur~~As ~~costs~~noted above, on September 23, 2020, the California Governor issued Executive Order N-79-20 (“N-79-20 Order”) intended to ~~monitor~~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 ~~report~~pickup ~~GHG~~trucks ~~emissions~~within orCalifornia, ~~reduce~~and ~~emissions~~a 2045 goal of ~~GHGs~~no ~~associated~~sale ~~with~~of ~~our~~internal ~~operations.~~combustion Inengine ~~addition~~medium- and heavy-duty trucks, ~~various~~and ~~states~~off-road vehicles and equipment. However, ~~individually~~the asN-79-20 ~~well~~Order aswould instill ~~some~~allow ~~cases~~used internal combustion engine vehicles to be used and sold after these dates. In an effort to accomplish the 2035 goal, on aAugust ~~regional~~25, ~~basis~~2022, ~~have~~CARB ~~taken~~voted ~~steps~~unanimously to ~~control~~adopt ~~GHG~~the ~~emissions~~Advanced Clean Cars II (“ACCII”) regulations. According to CARB, ~~including~~the ~~adoption~~ACCII ofregulations ~~GHG~~will ~~reporting~~rapidly ~~requirements~~scale down light-duty passenger car, ~~cap~~truck, and ~~trade~~SUV ~~systems~~emissions ~~and~~starting ~~renewable~~with ~~portfolio~~the ~~standards~~2026 ~~(such~~model asyear ABthrough ~~32)~~2035. OnThe ~~September~~regulations 23are two-pronged. First, ~~2020~~they amend the ~~Governor~~California ofZero-emission ~~California~~Vehicle ~~issued~~Regulation to require an ~~executive~~increasing ~~order~~number ~~effectively~~of ~~banning~~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 ~~sale~~regulations ofamend ~~new~~the ~~gasoline~~California Low-~~powered~~emission ~~passenger~~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. ~~and~~Similar ~~requiring~~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 ~~medium~~truck toand ~~heavy~~bus ~~duty~~fleet ~~vehicles~~ by 2045 everywhere feasible., ~~The~~and ~~executive~~significantly ~~order~~earlier ~~requires~~for ~~state~~certain ~~agencies~~market tosegments ~~build~~such ~~out~~as ~~sufficient~~last ~~electric~~mile ~~vehicle~~delivery ~~charging~~and ~~infrastructure~~drayage applications. ItThe initial focus of ACF is ~~not~~on ~~possible~~high-priority atfleets ~~this~~with ~~time~~vehicles tothat ~~predict~~are suitable for early electrification, their subhaulers, and entities that hire them. As to the ~~ultimate~~2045 ~~form~~goal, ~~timing~~it oris ~~extent~~currently ofuncertain ~~federal~~how orthe ~~state~~N-79-20 ~~regulation~~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 ~~on any of~~ these costs to our customers. ~~Regulatory~~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.

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 Low Carbon Fuel Standard (“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. 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.

Environmental clean-up and remediation costs of our sites and environmental litigation, including related to climate change, could decrease our net cash flow, reduce our results of operations and impair our financial condition.

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.

34We 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.

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 may 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 pipelines are subject to federal and/or state regulations, which could reduce profitability and the amount of cash we generate.

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.

Record refining industry profits have raised the concern of public policy experts and federal and state policymakers, who have questioned whether these profits are justified, or whether they constituted a “windfall” to the industry and have proposed legislation that if enacted could adversely affect our profitability. 34

InRecent ~~2022,~~ record refining industry profits have raised the concern of ~~many~~ public policy experts and federal and state policymakers, who have questioned whether these profits ~~were~~are justified, or whether they constituted a “windfall” to the industry and have ~~proposed~~enacted ~~legislation~~or ~~that~~could ifenact ~~enacted~~legislation that could adversely affect our profitability. In particular, on December 5, 2022, the Governor of the State of California proposed a bill that would impose a penalty on oil refiners in the State of California based on what the State determines to be excessive profits. To the extent that such legislation is enacted in California or similar legislation is enacted in any of the other jurisdictions in which we operate our refineries, our business, results of operations, ~~profitability~~ and ~~cash~~our ~~flows could be adversely impacted~~profitability.

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.

We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with health, safety, environmental and other laws and regulations.

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.

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.

Our pending renewable diesel project may not commence operations when we expect, or at all, and, if completed, we may not be able to successfully integrate the renewable diesel project into our business, consummate the proposed joint venture transaction or realize the anticipated benefits of this investment.

The completion of the renewable business project is subject to the successful incorporation of certain existing idled assets at the Chalmette refinery, along with a newly-constructed pre-treatment unit to establish a 20,000 bpd renewable diesel production facility, with the goal of being in production in the first half of 2023. Concurrent with our activities to progress the project, we entered into a definitive agreement with Eni, to partner in a 50-50 joint venture, SBR, which will own the renewable diesel facility upon consummation of the transaction, and which is subject to customary closing conditions, including regulatory approvals. There can be no assurance that we will close the transaction or complete the renewable diesel project on the timeframe that we anticipate, or at all. Failure to complete the renewable diesel project or any delays in completing it could have an adverse impact on our future business and operations. In addition, we will have incurred significant capital and investment-related expenses without realizing the expected benefits.

Additionally, if the renewable diesel project is completed and/or the proposed joint venture transaction closes, we will have certain obligations and liabilities to the joint venture as the construction manager, operator and provider of services. Further, if the proposed joint venture transaction closes, SBR will be operated as a separate entity and we will not fully control its operations. There can be no assurance that we will realize the anticipated benefits and operating synergies of the renewable diesel facility or the joint venture. Our estimates regarding the earnings, operating cash flow, capital expenditures and liabilities resulting from this investment may prove to be incorrect. This project involves risks, including:

•diversion of management time and attention from our existing business;

•reliance on our joint venture partner and their financial condition;

•risk that our joint venture partner does not always share our goals and objectives; and

•certain obligations that we have to fund capital expenditures relating to this project.

Enhanced scrutiny on ESG matters and developments related to climate change may negatively impact our business and our access to capital markets.

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.

Some of our competitors may have a competitive advantage by providing alternative energy sources or by owning their own retail sites.

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.

We may be negatively affected by the rate of inflation and its impact on the global economy.

Current inflation within the economy has resulted in increased interest rates and capital costs, contributed to supply shortages, increased the cost of living and labor, and other related items. As a result of inflation, which may continue, we expect to continue to encounter higher increases in the cost of feedstocks, labor, materials, and other inputs necessary in the refining of crude oil and other feedstocks. Although we may take actions to counteract the impacts of inflation, if these actions are not effective it could have a material adverse effect on our business, results of operations and financial condition. Additionally, higher future inflation or concerns of a recession could impact the demand for our products and services.

We may not be able to obtain funding on acceptable terms or at all, including because of volatility and uncertainty in the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.

In the past, global financial markets and economic conditions have been, and may again be, subject to disruption and volatile due to a variety of factors, including uncertainty in the financial services sector, low consumer confidence, falling commodity prices, geopolitical issues and generally weak economic conditions. In addition, the fixed income and bank markets could experience periods of extreme volatility that may negatively impact market liquidity conditions. As a result, the cost of raising money in the debt and equity capital markets could increase substantially at times while the availability of funds from those markets diminishes significantly. In particular, as a result of concerns about the stability of financial markets generally, which may be subject to unforeseen disruptions, the cost of obtaining money from the credit markets may increase as many lenders and institutional investors increase interest rates, enact tighter lending standards, refuse to refinance existing debt on similar terms or at all and reduce or, in some cases, cease to provide funding to borrowers. Due to these factors, we cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due. Moreover, without adequate funding, we may be unable to execute our ~~growth~~business strategy, complete future acquisitions or growth projects, take advantage of other business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.

Any political instability, military strikes, sustained military campaigns, terrorist activity, changes in foreign policy, or other catastrophic events could have a material adverse effect on our business, results of operations and financial condition.

U.S. and global markets are experiencing volatility and disruption following the escalation of geopolitical tensions and Russia’s military action in Ukraine starting in February 2022, the outbreak of armed hostilities in the middle east and disruptions in international shipping resulting from recent attacks by armed groups on cargo ships in the Red Sea. Although the length and impact of ~~the~~these ongoing military ~~conflict~~conflicts is highly unpredictable, ~~the~~these ~~war~~wars inhave ~~Ukraine has~~ led to market disruptions, including significant volatility in the financial markets and the global macroeconomic and geopolitical environment. Furthermore, a protracted conflict between Ukraine and Russia, or any escalation of ~~that~~this conflict, may result in additional financial and economic sanctions and import and/or export controls imposed on Russia by the United States, the UK, the EU, Canada and others, such as the ~~recent~~United States ban on import of Russian oil effective March 8, 2022 and the EU ban on oil products from Russia effective February 5, 2023, which may have adverse impacts on the wider global economy and market conditions and could, in turn, have a material adverse impact on our business, financial condition, cash flows and results of operations.

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.

A cyber-attack on, or other failure of, our technology infrastructure could affect our business and assets, and have a material adverse effect on our financial condition, results of operations and cash flows.

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.

Competition from companies that produce their own supply of feedstocks, have extensive retail outlets, make alternative fuels or have greater financial and other resources than we do could materially and adversely affect our business and results of operations.

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 ~~supply~~provide ~~their~~means ~~own~~to ~~renewable~~satisfy ~~fuels~~the ~~or alternative forms of~~ energy and ~~fuels~~fuel ~~to satisfy the~~ 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.

We must make substantial capital expenditures on our operating facilities to maintain their reliability and efficiency. If we are unable to complete capital projects at their expected costs and/or in a timely manner, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations or cash flows could be materially and adversely affected.

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:

•denial or delay in obtaining regulatory approvals and/or permits;

•unplanned increases in the cost of construction materials or labor;

•disruptions in transportation of modular components and/or construction materials;

•severe adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors and suppliers;

•shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;

•market-related increases in a project’s debt or equity financing costs; and/or

•non-performance or force majeure by, or disputes with, vendors, suppliers, contractors or sub-contractors involved with a project.

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 strict laws and regulations regarding employee and process safety, and failure to comply with these laws and regulations could have a material adverse effect on our results of operations, financial condition and profitability.

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 operational liability claims and litigation could adversely affect our business and results of operations.

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.

Compliance with and changes in tax laws could adversely affect our performance.

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.

Acquisitions or other investments that we may undertake in the future involve a number of risks, any of which could cause us not to realize the anticipated benefits.

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, ~~and~~ mid-stream ~~sector~~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 doacquire soadditional assets or invest in new businesses will be dependent upon a number of factors, including our ability to identify acceptable acquisition ~~candidates~~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.

A portion of our workforce is unionized, and we may face labor disruptions that would interfere with our operations.

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 business may suffer if any of our senior executives or other key employees discontinues employment with us. Furthermore, a shortage of skilled labor or disruptions in our labor force may make it difficult for us to maintain labor productivity.

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.

Our hedging activities may limit our potential gains, exacerbate potential losses and involve other risks.

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:

•the volumes of our actual use of crude oil or natural gas or production of the applicable refined products is less than the volumes subject to the hedging arrangement;

•accidents, interruptions in feedstock transportation, inclement weather or other events cause unscheduled shutdowns or otherwise adversely affect our refineries, or those of our suppliers or customers;

•changes in commodity prices have a material impact on collateral and margin requirements under our hedging arrangements, resulting in us being subject to margin calls;

•the counterparties to our derivative contracts fail to perform under the contracts; or

•a sudden, unexpected event materially impacts the commodity or crack spread subject to the hedging arrangement.

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.

Our commodity derivative activities could result in period-to-period earnings volatility.

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 ~~settlement~~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.

Risks Related to Our Indebtedness

Our indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under our indebtedness.

Our indebtedness may significantly affect our financial flexibility in the future. As of December 31, ~~2022~~2023, we have total debt of $1,~~470~~298.14 million, excluding unamortized deferred debt issuance costs of $3552.25 million, and we could incur additional borrowings under our asset-based revolving credit facility (the “Revolving Credit Facility”). We may incur additional indebtedness in the future including additional 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, 2022 to the extent that any of our activities triggered these covenants, there are no assurances that conditions could not change significantly, and that such changes could adversely impact our ability to meet some of 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 new investments or incur new liens.

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

•a portion of our cash flow from operations will be dedicated to the payment of principal of, and interest on, our indebtedness and will not be available for other purposes;

•under certain circumstances, covenants contained in our existing debt arrangements limit our ability to borrow additional funds, dispose of assets and make certain investments;

•in certain circumstances these covenants also require us to meet or maintain certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our industry, such as being able to take advantage of acquisition opportunities when they arise;

•our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited; and

•we may be at a competitive disadvantage to those of our competitors that are less leveraged; and we may be more vulnerable to adverse economic and industry conditions.

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 may not be able to secure necessary financing on acceptable terms, or at all.

We currently have notes outstanding with ~~varying~~ maturity dates ~~beginning~~ in ~~2025~~2028 and ~~ending in 2028~~2030. Additionally, our Revolving Credit Facility ~~has~~matures ~~a maturity date~~ in ~~2025~~2028. We can make no assurance that we will be able to refinance ~~this~~these ~~agreement~~agreements on acceptable terms prior to ~~its~~their maturity ~~date~~dates. Market disruptions or other credit factors, such as rising inflation and higher interest rates, ~~are~~may ~~expected to~~ 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.

Despite our level of indebtedness, we and our subsidiaries may be able to incur substantially more debt, which could exacerbate the risks described above.

We and our subsidiaries ~~may~~are be 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.

Our future credit ratings could adversely affect our business, the cost of our borrowing, and our ability to obtain credit in the future.

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 ~~2025~~2030 Senior Notes are rated B1Ba3 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, ~~increase~~maintain ~~our~~adequate levels of liquidity and make cash distributions to our members.

Restrictive covenants in our debt instruments, including the indentures governing our notes, may limit our ability to undertake certain types of transactions, which could adversely affect our business, financial condition, results of operations and our ability to service our indebtedness.

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.

Provisions in our indentures and other agreements could discourage an acquisition of us by a third-party.

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 ~~2025~~2028 Senior Notes and the ~~2028~~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”) ~~and the Third Intermediation Agreement with J. Aron~~ also contain provisions related to a change in control that could make it more difficult or expensive for a third-party to acquire us.

Risks Related to Our Organizational Structure

Under a tax receivable agreement, PBF Energy is required to pay the pre-IPO owners of PBF LLC for certain realized or assumed tax benefits it may claim arising in connection with its initial public offering and future exchanges of PBF LLC Series A Units, or other permitted assignees, for shares of its Class A common stock and related transactions (the “Tax Receivable Agreement”). The indentures governing the senior notes allow us, under certain circumstances, to make distributions sufficient for PBF Energy to pay its obligations arising from the Tax Receivable Agreement.

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, ~~2022~~2023, a total liability for the Tax Receivable Agreement of $~~338~~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 ~~or decrease~~ 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.

Risks Related to Our Affiliation with PBFX

We depend upon PBFX for a substantial portion of our refineries’ logistics needs and have obligations for minimum volume commitments in our commercial agreements with PBFX.

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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 1C. CYBERSECURITY

Cybersecurity risk management and strategy

Our cybersecurity risk management program is managed by our Chief Information Officer (“CIO”) who reports to our Chief Financial Officer and provides regular updates to the Board. Our CIO establishes our overall Information Technology (“IT”) security strategy, oversees our information, cyber, and technology security and manages our IT department, which includes our Cybersecurity team. His responsibilities include developing, implementing, and enforcing security policies to protect critical data. The head of our Cybersecurity team, our Director of Information Security, who reports to our CIO, runs the day-to-day management of our cybersecurity risks. Our IT department overall assists in implementing cybersecurity strategies and policies under the direction of the Cybersecurity team, as applicable.

Our cybersecurity risk management program aligns with the National Institute of Standards and Technology Cyber Security Framework, which establishes five areas of focus: identify, protect, detect, respond and recover. Our cybersecurity risk management program is designed to manage industry-specific threats, as well as threats arising from the overall evolving cybersecurity landscape and consists of two principal areas of focus: (i) enterprise systems, which consists of all business systems used in our daily operations and (ii) operational technology, which consists of all process control, supervisory control and data acquisition systems. Key elements of our cybersecurity management program include:

•identifying, monitoring and mitigating the cybersecurity risks to our systems, assets, data and capabilities;

•a critical response process for cybersecurity incidents, including the process for detection, investigation, containment and remediation of any such incidents;

•establishment of disaster recovery plans;

•testing, at least bi-annually, of select critical systems for disaster recovery and periodic walk-throughs of procedures for disaster recovery;

•identity access policies that aim to identify and monitor for potential cyber intrusions;

•periodic security tests, including monthly internal vulnerability scans, weekly external vulnerability scans, monthly phishing campaigns and recurring penetration testing by third-party cybersecurity firms;

•table-top exercises, at least quarterly, for incident response preparedness for the Cybersecurity team and Information Technology department; and

•annual drills for potential threats on various aspects of our technology assets based on the then-existing IT threat landscape for our industry.

Pursuant to our incident response plan, the Cybersecurity team has defined roles in responding to all cybersecurity incidents to provide an efficient and organized approach to handling cybersecurity threats, with the CIO receiving all reports and status updates regarding cybersecurity threats. The incident response plan provides a documented framework for when and how the CIO informs and updates our Board, the executive officers and other internal parties and when external parties are notified or consulted about a cybersecurity threat and the status thereof.

We also utilize third-party cybersecurity vendors to assist us with various aspects of our cybersecurity risk management program. For example, in order to support our cybersecurity incident response procedures, we have retained several third-party cybersecurity firms to monitor the IT threat landscape for our industry. As part of our efforts to manage the risk of cybersecurity threats associated with the use of third parties, we monitor and evaluate the cybersecurity risk profiles of third-party technology providers and consider such risk profiles when selecting third-party technology providers. Any third-party service provider that is granted access to our network is required to comply with our policies regarding information technology and cybersecurity. We also engage several third-party cybersecurity firms to perform independent assessments of the effectiveness of our cybersecurity risk management program and assist us in the continued review of our cybersecurity risk management program in order to reflect the evolving landscape of cybersecurity.

To date, there have been no significant risks from cybersecurity threats, including as a result of any significant cybersecurity breaches or attacks that have materially affected our business, results of operations or financial condition. However, if we were to be subject to a material successful cyber intrusion, it could result in remediation or service restoration costs, increased cybersecurity 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. See “Item 1A. Risk Factors−Risks Relating to Our Business and Industry−A cyber-attack on, or other failure of, our technology infrastructure could affect our business and assets, and have a material adverse effect on our financial condition, results of operations and cash flows.”

Cybersecurity governance

Our CIO has 30 years of experience in highly regulated industries managing information security in complex, matrixed environments, seven of which are in his current role with the Company. He has created and maintained enterprise-level information security programs for our Company and other US and international companies in the refining industry.

The CIO, along with the head of our Cybersecurity team, periodically reports, no less than quarterly, to our Board and our executive officers regarding the state of our cybersecurity risk management program, including information on the status of ongoing efforts to manage and mitigate cybersecurity risks, as well as recent cybersecurity trends and events and any updates to cybersecurity matters.

The Audit Committee reviews our disclosures with respect to cybersecurity and information technology risks. The Audit Committee also reviews with management guidelines and policies to govern the process by which risk assessment and risk management is undertaken, including but not limited to cybersecurity and information technology risks. As part of the Company’s enterprise-wide risk management program, our Internal Audit team also reports to our Audit Committee regarding assessments of our cybersecurity and information technology risks, at least annually, based on regular updates by our CIO regarding such risks. Our Internal Audit team periodically reports to our executive officers and the Audit Committee regarding such risks.

ITEM 2. PROPERTIES

See “Item 1. Business”.

4749

ITEM 3. LEGAL PROCEEDINGS

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.

OnWe ~~April~~currently 17have 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, ~~2019~~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 ~~received~~reasonably abelieve ~~Notice~~that such proceedings will result in monetary sanctions of ~~Violation~~$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 (“~~NOV~~CCC”), ~~from~~the Department of Justice and EPA, and the ~~South~~California ~~Coast~~Department ~~Air~~of ~~Quality~~Fish ~~Management~~and ~~District~~Game (“~~SCAQMD~~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 ~~Title~~the Vspent ~~deviations~~catalyst ~~alleged~~incident to ~~have~~date. ~~occurred~~The inCCC ~~second~~has ~~half~~issued oftwo ~~2018~~NOVs related to the spent catalyst incident. InThe ~~May~~BAAQMD ~~2022~~also issued an NOV relating to the July 11, 2023 coke dust incident and an NOV relating to the ~~SCAQMD~~October ~~requested~~6, ~~that~~2023 wecoke ~~present~~dust aincident. ~~settlement~~For ~~proposal~~the spent catalyst incident, the DFG, CCC, and the BAAQMD have referred their findings and/or NOVs issued to ~~resolve~~date to the ~~NOV~~CCC District Attorney. On ~~June~~November 16, ~~2022~~2023, wethe ~~presented~~CCC District Attorney and BAAQMD announced a ~~settlement~~joint ~~offer~~civil enforcement action against us that will include enforcement of ~~$456~~claims from the November 24,~~820~~ to2022 ~~settle~~spent ~~the~~catalyst ~~NOV~~release, as well as additional enforcement claims. On ~~July~~December 2215, ~~2022~~2023, the ~~SCAQMD~~BAAQMD ~~presented~~issued a ~~counter~~NOV ~~proposal~~related ofto ~~$1.2~~odors ~~million~~from flaring that occurred on the same date. On ~~August~~December 2518, ~~2022~~2023, wethe ~~presented~~BAAQMD issued four NOVs related to a ~~counter~~fire ~~proposal~~incident ofthat ~~$736~~occurred on December 17,~~845~~ 2023. OnFor ~~December~~both 15the spent catalyst, ~~2022~~coke dust, ~~the~~flaring ~~SCAQMD~~and ~~accepted~~fire ~~our~~incidents, ~~counter~~no ~~proposal.~~penalties ~~The~~have ~~parties~~been ~~are~~assessed ~~currently~~but ~~drafting~~it is reasonable to expect that, individually or in the ~~settlement~~aggregate, ~~agreement.~~the amount of such penalties may exceed $300,000.

On ~~February~~September 1727, ~~2017~~2023, inMRC ~~Arnold~~received ~~Goldstein,~~from etthe ~~al.~~San v.Francisco ~~Exxon~~Bay ~~Mobil~~Regional ~~Corporation,~~Water etQuality ~~al.,~~Control weBoard ~~and~~(“RWQCB”) ~~PBF~~an ~~LLC,~~Administrative ~~and~~Civil ~~our~~Liability ~~subsidiaries,~~(“ACL”) ~~PBF~~assessment ~~Western~~in ~~Region and Torrance Refining and~~ the ~~manager~~amount of ~~our~~$13.8 ~~Torrance~~million ~~refinery~~for ~~along~~allegedly: ~~with~~(1) ~~ExxonMobil~~exceeding ~~were~~its ~~named~~effluent aslimitations ~~defendants in a class action~~ and ~~representative~~discharging ~~action~~to ~~complaint~~the ~~filed~~Carquinez onStrait ~~behalf~~without ofauthorization ~~Arnold~~in ~~Goldstein,~~October ~~John Covas~~2022, ~~Gisela~~January ~~Janette La Bella and others similarly situated. The complaint was filed in the Superior Court of the State of California~~2023, ~~County of Los Angeles~~ and ~~alleges~~June ~~negligence,~~2023; ~~strict liability, ultra-hazardous activity, a continuing private nuisance, a permanent private nuisance, a continuing public nuisance, a permanent public nuisance~~ and ~~trespass resulting from the February 18, 2015 electrostatic precipitator~~ (~~“ESP”~~2) ~~explosion~~failing ~~at the Torrance refinery which was then owned and operated by ExxonMobil. The operation of the Torrance refinery by the PBF entities subsequent~~ to ~~our~~submit ~~acquisition~~Climate inChange ~~July~~Adaptation ~~2016 is also referenced in the complaint~~information. ToOn ~~the~~January ~~extent~~12, ~~that plaintiffs’ claims relate to the ESP explosion~~2024, ~~ExxonMobil~~MRC ~~retained~~met ~~responsibility~~with ~~for any liabilities that would arise from~~ the ~~lawsuit~~RWQCB ~~pursuant~~ to ~~the~~discuss ~~agreement~~its ~~relating~~response to ~~the~~their ~~acquisition~~ACL ~~of the Torrance refinery~~assessment. OnBased ~~July~~on ~~2, 2018,~~ the ~~Court~~discussions ~~granted~~and ~~leave to plaintiffs to file a Second Amended Complaint alleging groundwater contamination. With~~ the ~~filing~~information ofprovided ~~the~~by ~~Second Amended Complaint~~MRC, ~~plaintiffs added an additional plaintiff, Hany Youssef. On October 15, 2019,~~ the ~~judge~~RWQCB ~~granted~~proposed ~~certification~~reducing ~~to two limited classes of property owners with Youssef as~~ the ~~sole~~ACL ~~class~~assessment ~~representative and named plaintiff, rejecting two other proposed subclasses based on negligence and on strict liability for ultrahazardous activities. The certified subclasses relate~~ to ~~trespass~~approximately ~~claims for ground contamination and nuisance for air emissions~~$4. ~~On February~~ 5, ~~2021,~~million ~~our motion for Limited Extension of Discovery Cut-Off~~ and anoted ~~Motion~~that ~~by plaintiffs~~ for ~~Leave~~any tosettlement ~~File~~50% ~~Third~~of ~~Amended Complaint were heard by~~ the ~~Court.~~penalty Oncould ~~May~~be 5,in ~~2021,~~ the ~~Court~~form ~~granted~~of ~~plaintiffs~~an ~~leave~~Enhanced toCompliance ~~amend~~Actions ~~their~~(“ECA”) ~~complaint for the third time to substitute Navarro for Youssef. On May 12~~settlement, ~~2021,~~Supplemental ~~plaintiffs~~Environmental ~~filed~~Project ~~their Third Amended Complaint~~ (“~~TAC~~SEP”) ~~that contained significant changes and new claims~~, ~~including~~or ~~individual claims, that were not included in the motion for leave to amend plaintiffs presented to the Court. On June 9, 2021, we filed~~ a ~~Motion~~combination toof ~~Dismiss/Strike~~ the ~~TAC~~two. On ~~June~~January 2319, ~~2021~~2024, ~~plaintiffs~~MRC ~~filed~~agreed ~~their opposition~~ to ~~our~~accept ~~Motion to Dismiss/Strike, to which we filed our reply on July 2, 2021. A hearing on~~ the ~~Motion~~reduced ~~to Dismiss/Strike the TAC was held on August 2~~ACL, ~~2021 and the Court ordered that the TAC be struck and that the parties meet and confer~~ with ~~respect~~50% toof the ~~complaint~~approximately $4.5 ~~After~~million ~~meeting~~dedicated ~~and conferring, plaintiffs agreed~~ to ~~submit~~an aECA ~~corrected TAC with changes reflecting the removal of Youssef~~ and ~~the substitution of Navarro as the named Plaintiff~~SEP. OnOnce ~~August 23, 2021,~~ the ~~Court approved the~~ parties’ ~~stipulation~~finalize ~~to take Navarro’s deposition on September 23, 2021. Also, on August 23, 2021,~~ the ~~Court~~settlement ~~approved~~agreement ~~the~~and ~~parties’~~ stipulation tofor ~~continue~~entry ~~the~~of ~~pretrial~~administrative ~~dates~~civil ~~with~~liability ~~the new deadlines. On October 8~~order, ~~2021,~~it ~~plaintiffs~~will ~~filed~~be ~~their~~presented ~~Motion~~ to ~~Appoint Navarro as Class Representative. On October 29, 2021, we filed our opposition to this motion. On November 15, 2021, plaintiffs filed their reply. On February 8, 2022,~~ the ~~Court held a hearing on plaintiff~~RWQCB’s ~~Motion~~Board ~~to Appoint Navarro as Class Representative but did not act on the motion. Instead, the Court ordered the parties to submit draft orders~~ for ~~the Court’s consideration. After considering the parties’ proposed orders, on July 5, 2022, the Court issued a~~ final ~~order ruling that Plaintiffs’ Motion to Substitute Navarro as Class Representative was denied and decertifying both of Plaintiffs’ proposed Air and Ground Subclasses~~approval. ~~The order provided that the~~

4850

~~case~~On ~~will~~February ~~proceed~~17, ~~with~~2017, ~~Navarro~~in asArnold ~~the~~Goldstein, ~~sole~~et ~~plaintiff~~al. v. Exxon Mobil Corporation, et al., we and ~~required~~PBF ~~the~~LLC, ~~parties~~and toour ~~meet~~subsidiaries, PBF Western Region and ~~confer~~Torrance Refining and ~~propose~~the manager of our Torrance refinery along with ExxonMobil were named as defendants in a ~~schedule~~class ~~for~~action and representative action complaint. The complaint was filed in the ~~remaining~~Superior ~~pretrial~~Court ~~dates~~of the State of California, County of Los Angeles and aalleges ~~trial~~negligence, ~~date.~~strict Onliability, ~~July~~ultra-hazardous 19activity, ~~2022~~a continuing private nuisance, ~~Plaintiff~~a ~~filed~~permanent private nuisance, a ~~petition~~continuing ~~with~~public nuisance, a permanent public nuisance and trespass resulting from the ~~Ninth~~February ~~Circuit~~18, ~~Court~~2015 electrostatic precipitator (“ESP”) explosion at the Torrance refinery, which was then owned and operated by ExxonMobil. The operation of ~~Appeals~~the ~~seeking~~Torrance ~~permission~~refinery by the PBF entities subsequent to ~~appeal~~our acquisition in July 2016 is also referenced in the ~~District~~complaint. ~~Court~~To the extent that plaintiffs’s ~~decertification~~claims ~~order~~relate ~~finding~~to ~~that~~the ~~Navarro~~ESP isexplosion, anExxonMobil ~~inadequate~~retained ~~class~~responsibility ~~representative.~~for ~~Our~~any ~~answer~~liabilities that would arise from the lawsuit pursuant to the ~~petition~~agreement ~~was~~relating ~~filed~~to onthe ~~July~~acquisition ~~29,~~of ~~2022~~the Torrance refinery. On ~~September~~July 222, ~~2022~~2018, the ~~Ninth~~Court ~~Circuit~~granted ~~issued~~leave anto ~~order~~plaintiffs ~~denying~~to ~~Plaintiffs’~~file ~~petition~~a ~~for~~Second ~~permission~~Amended toComplaint ~~file~~alleging groundwater contamination. With the filing of the Second Amended Complaint, plaintiffs added an ~~interlocutory~~additional ~~appeal~~plaintiff, ~~confirming~~Hany ~~that~~Youssef. On October 15, 2019, the ~~case~~judge ~~will~~granted ~~proceed~~certification to two limited classes of property owners with ~~Navarro~~Youssef as the sole ~~plaintiff.~~class Onrepresentative ~~September~~and ~~27,~~named ~~2022~~plaintiff, ~~the~~rejecting ~~Plaintiff~~two ~~filed~~other aproposed ~~schedule~~subclasses ofbased ~~pretrial~~on negligence and ~~trial~~on ~~dates~~strict ~~with~~liability afor ~~trial~~ultrahazardous ~~date~~activities. ofThe ~~July~~certified ~~18,~~subclasses ~~2023,~~relate ~~which~~to ~~was~~trespass ~~approved~~claims byfor ~~the~~ground ~~Court~~contamination and nuisance for air emissions. On ~~January~~May 135, ~~2023~~2021, the ~~Defendants~~Court ~~filed~~granted aplaintiffs ~~motion~~leave ~~for~~to ~~judgment~~amend ontheir complaint for the ~~pleadings~~third time to substitute Navarro for Youssef. On ~~January~~July 235, ~~2023~~2022, the ~~Plaintiff~~Court ~~filed~~issued ~~its~~a ~~opposition~~final toorder ~~the~~ruling ~~Defendants’~~that ~~motion. Defendants~~Plaintiffs’ ~~reply~~Motion to ~~Plaintiff’s~~Substitute ~~opposition~~Navarro as Class Representative was ~~filed~~denied onand ~~January~~decertifying ~~30,~~both ~~2023.~~of ~~Defendants~~Plaintiffs’ ~~motion~~proposed ~~was~~Air ~~scheduled~~and toGround beSubclasses. ~~heard~~The byorder provided that the ~~Court~~case onwill ~~February~~proceed 13with Navarro as the sole plaintiff. On September 22, ~~2023~~2022, the Ninth Circuit Court of Appeals affirmed. On February 27, 2023, the Court issued an order granting our motion for judgment on the pleadings and dismissed Plaintiff’s trespass claim with prejudice and granted Plaintiff leave to amend his nuisance claims in conformity with the order if he can do so consistent with Rule 11 of the Federal Rules of Civil Procedures. On March 27, 2023, Plaintiff ~~can~~filed ~~file~~a ~~and~~Fourth ~~serve~~Amended anComplaint ~~amended~~relating ~~complaint~~to nothe ~~later~~remaining ~~than~~nuisance ~~March~~claims. 25On May 23, 2023, the Court denied our motion to dismiss on the pleadings for Plaintiff’s failure to establish standing to bring the nuisance claims. ~~Per~~After completing further discovery, on August 28, 2023, we filed a Motion for Summary Judgment. On October 18, 2023, the Court issued an order granting our motion, ~~failure~~adjudged that Plaintiff take nothing, and that the action be dismissed with prejudice. The order also allows us to ~~file~~recover the costs of suit pursuant to a ~~complaint~~bill byof ~~that~~costs. ~~date~~On ~~will~~October ~~waive~~30, 2023, Plaintiff filed a notice of appeal to the Ninth Circuit regarding the Court’s ~~right~~order togranting dosummary sojudgment. Plaintiff’s opening brief is due March 22, 2024 and ~~the~~our ~~complaint~~answering ~~will~~brief beis ~~dismissed~~due ~~with~~April ~~prejudice~~22, 2024. We presently believe the outcome of this litigation will not have a material impact on our financial position, results of operations, or cash flows.

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 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 that 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, we filed a Motion To Augment/Correct The Administrative Record regarding various documents that the BAAQMD is currently withholding and do not plan to include in the administrative record. On December 30, 2022, the BAAQMD filed its opposition to our motion. On January 12, 2023, we filed our reply to the BAAQMD’s opposition. The hearing on our motion was held on February 2, 2023. At the hearing, 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 will jointly identify approximately 50 of the withheld/redacted documents for the Court to review, and the Court will rule on those documents. The parties will then apply the Court’s ruling to the remainder of the withheld documents. If there is still a dispute, the parties will bring the dispute back before the Court. The Court set the writ hearing for September 20, 2023. It is currently expected that the non-disputed portion of the Administrative Record will be lodged with the Court in early February 2023. If the Court ultimately grants our motion on the deliberative privilege, the Administrative Record will be augmented. We expect another mandatory settlement conference to be held in first quarter of 2023. We presently believe the outcome will not have a material impact on our financial position, results of operations, or cash flows.51

49On 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.

On August 16, 2023, in Joseph Piscitelli and Lara Zanzucchi v. Martinez Refining Company LLC, our subsidiary MRC was named as a defendant in a class action and representative action complaint which contains allegations of public and private nuisance, trespass, and negligence arising from MRC’s operations. MRC filed its answer to the complaint on October 31,2023. The initial Court hearing to discuss discovery issues was held on January 2, 2024. At the hearing, the Court raised the issue of mediation and directed the parties to meet and confer and agree to stipulate to a mediation deadline. On January 9, 2024, the parties filed a stipulation agreeing to consider private mediation by September 20, 2024. On January 17, 2024, the Court issued a scheduling order setting the class certification hearing for April 10, 2025. The parties are currently engaged in discovery. We presently believe the outcome will not have a material impact on our financial position, results of operations, or cash flows.

On December 15, 2023, in Alena Cruz and Shannon Payne vs. PBF Energy Inc., et. al, we and our subsidiaries PBF Energy Western Region and MRC were named as defendants in a class action and representative action complaint filed by Alena Cruz and Shannon Payne, and on behalf of all others similarly situated. The complaint contains allegations of Clean Air Act violations, claims for medical and environmental monitoring, liability for ultrahazardous activities, negligence, and public and private nuisance from MRC’s operations. The proposed class is all individuals who reside and/or work in the City of Martinez, including the surrounding communities of Alhambra Valley and Franklin Canyon, as well as El Sobrante, Hercules, Benicia, and Richmond, who have allegedly been exposed to elevated levels of spent catalyst discharged from MRC’s operations during the period November 24, 2022 to the present. On December 21, 2023, Plaintiffs granted an extension until February 5, 2024 for MRC to respond to the initial complaint. On February 5, 2024, MRC filed a motion to dismiss on the pleadings. In response, on February 16, 2024, Plaintiffs’ filed a First Amendment Complaint (“FAC”). On February 29, 2024, MRC filed a motion to dismiss the FAC on the pleadings. Plaintiff’s opposition to the motion is due March 14, 2024. MRC’s reply to Plaintiffs’ opposition is due March 21, 2024. The motion hearing date is currently scheduled for April 4, 2024. We presently believe the outcome 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.

ITEM 4. MINE SAFETY DISCLOSURES

None.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

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

Holders

At February 2423, ~~2023~~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 ~~2022~~2023.

Dividend and Distribution Policy

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 ~~2025~~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 $~~571~~1,582.48 million in distributions to PBF LLC during the year ended December 31, ~~2022~~2023. In addition, during the year ended December 31, ~~2022~~2023 PBF LLC used $25106.06 million to make non-tax distributions ~~of $0.20 per unit~~ to its members, of which $24105.8 million was distributed to PBF Energy and the balance was distributed to PBF LLC’s other members. PBF Energy used this $24105.8 million to pay cash dividends of $0.20 per share of its Class A common stock on ~~November~~March 2916, ~~2022.~~2023, ~~PBF~~May ~~LLC~~31, ~~also~~2023 ~~made~~and ~~aggregate~~August ~~tax~~31, ~~distributions~~2023, toand ~~its~~cash ~~members~~dividends of $~~1,130~~0.~~1 million,~~25 ofper ~~which~~share ~~$1,121.8 million~~on ~~was~~November ~~made~~30, ~~to PBF Energy~~2023. ~~See “Item 1A. Risk Factors”.~~

ITEM 6. [RESERVED]

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

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

In this Item 7, we discuss results for the years ended December 31, ~~2022~~2023 and ~~2021~~2022 and comparisons of the results for the years ended December 31, ~~2022~~2023 and ~~2021~~2022. Discussions of results for the year ended December 31, ~~2020~~2021 and comparisons of the results for the years ended December 31, ~~2021~~2022 and ~~2020~~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, ~~2021~~2022.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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:

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

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

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

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

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

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

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

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

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

•our ability to ~~target~~manage ~~and execute expense reduction measures and achieve opportunities to improve~~ our ~~liquidity,~~costs ~~including continued repurchases of our outstanding debt securities or otherwise further reducing our debt,~~ and~~/or~~ ~~potential sales of non-operating assets or other real property~~expenses;

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

•the risk of cyber-attacks;

•our increased dependence on technology;

•the effects of competition in our markets;

•our ability to make acquisitions or investments, including in renewable diesel production, ~~such as our proposed joint venture transaction with Eni, on any announced time frame or at all,~~ and to realize the benefits from such acquisitions or investments;

•if our proposed joint venture transaction is consummated, our ability to successfully manage SBR's operations together with our joint venture partner;

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

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

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

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

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

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

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

•termination of our Third Inventory Intermediation Agreement with J. Aron, which is scheduled to expire in December 2024 and could have a material adverse effect on our liquidity, as we would be required to finance our crude oil, intermediate and refined products inventory covered by the agreement. Additionally, we are obligated to repurchase from J. Aron certain J. Aron Products upon termination of the agreement;

•our assumptions regarding payments arising under PBF Energy’s Tax Receivable Agreement and other arrangements relating to PBF Energy;

•the impact of disruptions to crude or feedstock supply to any of our refineries, including disruptions related to PBFX, SBR, or with third-party logistics infrastructure or operations, including pipeline, marine and rail transportation; and

•any decisions we continue to make with respect to our energy-related logistics assets that may be transferred to PBFX.

5356

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

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

Executive Summary

Our business operations are conducted by our subsidiaries. We own and operate six domestic oil refineries and related assets located in Delaware City, Delaware, Paulsboro, New Jersey, Toledo, Ohio, Chalmette, Louisiana, Torrance, California and Martinez, California. 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.

Factors Affecting Comparability

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

Debt and Credit Facilities

Revolving Credit Facility

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

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

Senior Notes

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

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

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.

On December 21, 2020, we issued an additional $250.0 million in aggregate principal amount of the 2025 Senior Secured Notes. The net proceeds from this offering were approximately $245.7 million after deducting the initial purchasers’ discount and offering expenses. We used the net proceeds for general corporate purposes.

On May 13, 2020, we issued $1.0 billion in aggregate principal amount of the 2025 Senior Secured Notes. The net proceeds from this offering were approximately $982.9 million after deducting the initial purchasers’ discount and offering expenses. We used the net proceeds for general corporate purposes.

On February 14, 2020, we exercised our rights under the indenture governing the 7.00% senior notes due 2023 (the “2023 Senior Notes”) to redeem all of the outstanding 2023 Senior Notes at a price of 103.5% of the aggregate principal amount thereof plus accrued and unpaid interest. The aggregate redemption price for all 2023 Senior Notes approximated $517.5 million plus accrued and unpaid interest. The difference between the carrying value of the 2023 Senior Notes on the date they were redeemed and the amount for which they were redeemed was $22.2 million and has been classified as Loss on extinguishment of debt in the Consolidated Statements of Operations for the year ending December 31, 2020.

On January 24, 2020, we issued $1.0 billion in aggregate principal amount of the 2028 Senior Notes. The net proceeds from this offering were approximately $987.0 million after deducting the initial purchasers’ discount and offering expenses. We used $517.5 million of the proceeds to fully redeem our 2023 Senior Notes and the balance to fund a portion of the cash consideration for Martinez Acquisition (as defined below).

PBF Holding Revolving Credit Facility

On May 25, 2022, we entered into an amendment of our existing Revolving Credit Agreement. Among other things, the Revolving Credit Agreement amended and extended the Revolving Credit Facility through January 2025 and increased the maximum commitment to $4.3 billion through May 2023 (currently set to adjust to $2.75 billion in May 2023 through January 2025). The amendments also redefine certain components of the Borrowing Base (as defined in the Revolving Credit Agreement) to reflect the existence of the two tranches, tranche A which is comprised of existing lenders who have not elected to extend and whose commitments retain the existing maturity date under the existing revolving credit agreement of May 2, 2023 (the “Tranche A Commitments”) and tranche B, which is comprised of existing and new lenders whose commitments have an extended maturity date of January 31, 2025 (the “Tranche B Commitments”). The Tranche A Commitments total $1.55 billion and the Tranche B Commitments total $2.75 billion. The amendments also include changes to incorporate the adoption of Secured Overnight Financing Rate (“SOFR”) as a replacement of the London Interbank Offering Rate (“LIBOR”), changes to joint lead arrangers, bookrunners, syndication agents and other titles, and other changes related to the foregoing. In addition, an accordion feature allows for additional Tranche B Commitments of up to an additional $500.0 million plus an amount equal to the Tranche A Commitments for existing Tranche A lenders.

During the year ended December 31, 2022 we made net repayments of $900.0 million on the Revolving Credit Facility, resulting in no outstanding borrowings as of December 31, 2022. There was $900.0 million of outstanding borrowings under the Revolving Credit Facility as of December 31, 2021 and December 31, 2020.

Catalyst Financing Obligations

During the year ended December 31, ~~2022 and December 31~~2023, ~~2021,~~ we settled ~~certain~~our ofremaining ~~our~~outstanding precious ~~metals~~metal financing ~~arrangements~~arrangement, ~~resulting~~which inrepresented ~~reductions~~a reduction of debt of approximately $563.21 million ~~and $31~~.~~7 million,~~ ~~respectively.~~

~~The~~During ~~volumes of~~ the ~~precious~~year ~~metal~~ended ~~catalyst~~December 31, ~~and~~2022, ~~the~~we ~~interest~~settled ~~rates~~certain ~~are fixed over the term~~ of ~~each~~our ~~financing arrangement. We are obligated to repurchase the~~ precious metals ~~catalyst~~financing atarrangements, ~~fair~~resulting ~~market~~in ~~value~~reductions ~~upon expiration~~ of ~~these leases. For all leases not renewed at maturity, we have the ability and intent to finance such~~ debt ~~through~~of ~~availability~~approximately ~~under our revolving credit facilities~~$56.2 million.

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

Market Developments

The impact of the unprecedented global health and economic crisis sparked by the COVID-19 pandemic at the end of the quarter ended March 31, 2020, created a shock in oil demand resulting in an economic challenge to our industry which has not occurred since our formation. This resulted in significant demand reduction for our refined products and atypical volatility in oil commodity prices. The demand for these products started to recover in 2021 and continued to improve in 2022. Additionally, refining margins improved significantly in 2022 as a result of high demand and global supply disruption.

Torrance Land Sales

On December 30, 2020, we closed on a third-party sale of parcels 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 $8.1 million in the fourth quarter of 2020, included within Gain on sale of assets in the Consolidated Statements of Operations.

East Coast Refining Reconfiguration

On December 31, 2020, we completed the East Coast Refining Reconfiguration. As part of the reconfiguration process, we temporarily idled certain of our major processing units at the Paulsboro refinery, resulting in lower overall throughput and inventory levels in addition to decreases in capital and operating costs. In 2022, we restarted several of these idled processing units. Based on this reconfiguration and subsequent restart of several processing units, our East Coast throughput capacity currently approximates 335,000 barrels per day.

Turnaround Costs and Assets under Construction

In 2020, we accelerated the recognition of approximately $56.2 million of unamortized deferred turnaround amortization costs associated with these idled units. Additionally, we abandoned certain projects related to assets under construction related to these idled assets, resulting in an impairment charge of approximately $11.9 million in 2020.

Capital Project Abandonments

During 2020, in connection with our strategic initiative to address the COVID-19 pandemic, including our East Coast Refining Reconfiguration, we reassessed our refinery wide slate of capital projects that were either in process or not yet placed into service as of December 31, 2020. Based on this reassessment and our strategic plan to reduce capital expenditures, we decided to abandon various capital projects across the refining system, resulting in an impairment charge of approximately $79.9 million in 2020.

Severance Costs

Following the onset of the COVID-19 pandemic, in 2020 we implemented a number of cost reduction initiatives to strengthen our financial flexibility and rationalize overhead expenses, including workforce reduction. During the second quarter of 2020, we reduced headcount across our refineries, which resulted in approximately $12.9 million of severance related costs. Additionally, as a result of the East Coast Refining Reconfiguration, we incurred charges in the fourth quarter of 2020 of approximately $11.8 million of severance related expenses. These severance costs were included in general and administrative expenses.

Early Return of Railcars

In the fourth quarter of 2020 we agreed to voluntarily return a portion of railcars under an operating lease in order to rationalize certain components of our railcar fleet. Under the terms of the lease amendment, we agreed to pay amounts in lieu of satisfaction of return conditions (the “early termination penalty”). As a result, we recognized an expense of $12.5 million within Cost of sales, consisting of charges for the early termination penalty and charges related to the remaining lease payments associated with the railcars identified within the amended lease, all of which were idled and out of service as of December 31, 2020.

Sale of Hydrogen Plants

On April 17, 2020, we closed on the sale of five hydrogen plants to Air Products and Chemicals, Inc. (“Air Products”) in a sale-leaseback transaction for gross cash proceeds of $530.0 million and recognized a gain of $471.1 million. In connection with the sale, we entered into a transition services agreement, which was followed by the execution of long-term supply agreements in August 2020, through which Air Products will exclusively supply hydrogen, steam, carbon dioxide and other products to the Martinez, Torrance and Delaware City refineries for a term of fifteen years.

Martinez Acquisition

We acquired the Martinez refinery and related logistics assets from Shell Oil Products on February 1, 2020 for an aggregate purchase price of $1,253.4 million (the “Martinez Acquisition”), including final working capital of $216.1 million and the obligation to make certain post-closing earn-out payments to Shell Oil Products based on certain earnings thresholds of the Martinez refinery for a period of up to four years (the “Martinez Contingent Consideration”). The transaction was financed through a combination of cash on hand, including proceeds from the 2028 Senior Notes, and borrowings under the Revolving Credit Facility.

The Martinez refinery is located on an 860-acre site in the City of Martinez, 30 miles northeast of San Francisco, California. The refinery is a high-conversion 157,000 bpd, dual-coking facility with a Nelson Complexity Index of 16.1, making it one of the most complex refineries in the United States. The facility is strategically positioned in Northern California and provides for operating and commercial synergies with the Torrance refinery located in Southern California. In addition to refining assets, the Martinez Acquisition includes a number of high-quality onsite logistics assets including a deep-water marine facility, product distribution terminals and refinery crude and product storage facilities with approximately 8.8 million barrels of shell capacity.

Inventory Intermediation Agreement

OnPrior ~~October~~to 252023, ~~2021,~~ PBF Holding and its subsidiaries, the PBF Entities, entered into the Third Inventory Intermediation Agreement with J. Aron,. ~~pursuant~~Pursuant to ~~which~~ the ~~terms of the existing inventory intermediation agreements were amended and restated in their entirety, including, among other things, pricing and an extension of the terms. The~~ Third Inventory Intermediation Agreement ~~extends the term to December 31~~, ~~2024,~~J. ~~which~~Aron ~~term~~purchased ~~may~~and beheld ~~further~~title ~~extended~~to ~~by mutual consent of~~ the ~~parties~~J. toAron ~~December~~Products ~~31,~~purchased ~~2025.~~or Onproduced ~~May~~by ~~25, 2022,~~ the ~~PBF~~Refineries ~~Entities~~and ~~entered~~delivered into ~~an amendment of~~ the ~~Third~~Storage ~~Inventory~~Tanks. ~~Intermediation~~The ~~Agreement~~J. toAron ~~amend~~Products ~~certain~~were ~~provisions~~sold ~~thereof~~back ~~that related~~ to ~~and~~us ~~were~~as ~~impacted~~the byJ. ~~amendments~~Aron ~~made~~Products onwere ~~May~~discharged ~~25,~~out ~~2022~~of to the ~~Revolving~~Storage ~~Credit Agreement~~Tanks.

57On 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.

Pursuant to the Third Inventory Intermediation Agreement, J. Aron will continue to purchase and hold title to the J. Aron Products purchased or produced by the Refineries and delivered into the Storage Tanks. Furthermore, J. Aron agrees to sell the J. Aron Products back to PRC and DCR (and, at the election of the PBF Entities, Chalmette Refining) as the J. Aron Products are discharged out of the Storage Tanks. We exercised our right to include the Chalmette refinery under the Third Inventory Intermediation Agreement in November 2021. J. Aron has the right to store the J. Aron Products purchased in tanks under the Third Inventory Intermediation Agreement and will retain these storage rights for the term of the agreement. We intend to utilize the crude oil and will market and sell the refined products independently to third parties. 58

Distribution of assets

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.

Land Sales

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

East Coast Refining Reconfiguration

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

Renewable Fuel Standard

We are subject to obligations to purchase RINs required to comply with ~~the Renewable Fuel Standard~~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 $~~1,225~~762.53 million in RINs costs during the year ended December 31, ~~2022~~2023 as compared to $~~726~~1,225.05 million and $~~326~~726.40 million during the years ended December 31, ~~2021~~2022 and ~~2020~~2021, respectively. The ~~increases~~fluctuations in RINs costs are due primarily to volatility in prices for ethanol-linked RINs and ~~increases~~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.

Agreements with PBFX

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 109 - Related Party Transactions” of our Notes to Consolidated Financial Statements.

A summary of our affiliate transactions with PBFX is as follows (in millions):

	Year Ended December 31,
	2022		2021		2020
	2023		2022		2021
Reimbursements under affiliate agreements:
Services Agreement	$	8.7	$	8.7	$	8.7
Omnibus Agreement	87.39		78.3		7.63
Total expenses under affiliate agreements	~~319~~347.68		~~304~~319.16		~~289~~304.41

Factors Affecting Operating Results

Overview

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

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

Benchmark Refining Margins

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

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

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

Credit Risk Management

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

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

Other Factors

We currently source our crude oil for our refineries on a global basis through a combination of market purchases and short-term purchase contracts, and through our crude oil supply agreements. We believe purchases based on market pricing has given us flexibility in obtaining crude oil at lower prices and on a more accurate “as needed” basis. Since our East Coast refineries access their crude slates from the Delaware River via ship or barge and through our rail facilities at Delaware City, these refineries have the flexibility to purchase crude oils from the Mid-Continent and Western Canada, as well as a number of different countries. We have not sourced crude oil under our crude supply arrangement with Petróleos de Venezuela S.A. (“PDVSA”) since 2017 as PDVSA has suspended deliveries due to our inability to agree to mutually acceptable payment terms and because of U.S. government sanctions against PDVSA.

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. ~~Certain of these railcars were subsequently sold to a third-party, which has leased the railcars back to us for periods of between four and seven years.~~ In subsequent periods, we have sold or returned railcars to optimize our railcar portfolio. Our railcar fleet, ~~at times,~~ 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 ~~the Renewable Fuel Standard~~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.

6061

Refinery-Specific Information

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

East Coast Refining System (Delaware City and Paulsboro Refineries). The benchmark refining margin for the East Coast Refining System is calculated by assuming that two barrels of Dated Brent crude oil are converted into one barrel of gasoline and one barrel of diesel. We calculate this benchmark using the NYH market value of reformulated blendstock for oxygenate blending (“RBOB”) and ULSD against the market value of Dated Brent and refer to the benchmark as the Dated Brent (NYH) 2-1-1 benchmark refining margin. The East Coast Refining System has a product slate of approximately 39% gasoline, 3735% distillate, 2% high-value Group I lubricants, 1% high-value petrochemicals, with the remaining portion of the product slate comprised of lower-value products (34% LPGs, 1215% black oil and 64% other). For this reason, we believe the Dated Brent (NYH) 2-1-1 is an appropriate benchmark industry refining margin. The majority of East Coast refining revenues are generated off NYH-based market prices.

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

•the system processes a slate of primarily medium and heavy sour crude oils, which has constituted approximately 6050% to 75% of total throughput. The remaining throughput consists of sweet crude oil and other feedstocks and blendstocks. In addition, we have the capability to process a significant volume of light, sweet crude oil depending on market conditions. Our total throughput costs have historically priced at a discount to Dated Brent; and

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

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

Toledo Refinery. The benchmark refining margin for the Toledo refinery is calculated by assuming that four barrels of WTI crude oil are converted into three barrels of gasoline, one-half barrel of ULSD and one-half barrel of jet fuel. We calculate this refining margin using the Chicago market values of CBOB and ULSD and the United States Gulf Coast value of jet fuel against the market value of WTI and refer to this benchmark as the WTI (Chicago) 4-3-1 benchmark refining margin. Our Toledo refinery has a product slate of approximately 5150% gasoline, 3637% distillate, 54% high-value petrochemicals (including nonene, tetramer, benzene, xylene and toluene) with the remaining portion of the product slate comprised of lower-value products (54% LPGs, and 35% black oil). For this reason, we believe the WTI (Chicago) 4-3-1 is an appropriate benchmark industry refining margin. The majority of Toledo revenues are generated off Chicago-based market prices.

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

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

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

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

6162

Chalmette Refinery. The benchmark refining margin for the Chalmette refinery is calculated by assuming two barrels of LLS crude oil are converted into one barrel of gasoline and one barrel of diesel. We calculate this benchmark using the US Gulf Coast market value of 87 conventional gasoline and ULSD against the market value of LLS and refer to this benchmark as the LLS (Gulf Coast) 2-1-1 benchmark refining margin. Our Chalmette refinery has a product slate of approximately 4447% gasoline and 3634% distillate, 1% high-value petrochemicals with the remaining portion of the product slate comprised of lower-value products (76% black oil, 5% LPGs, 32% petroleum coke, and 45% other). For this reason, we believe the LLS (Gulf Coast) 2-1-1 is an appropriate benchmark industry refining margin. The majority of Chalmette revenues are generated off Gulf Coast-based market prices.

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

•the Chalmette refinery has ~~generally~~recently processed a slate of primarily ~~medium~~light and ~~heavy~~medium ~~sour~~ crude oils, which ~~has~~represents ~~historically constituted~~ approximately 5060% to 75% of total throughput. The remaining throughput consists of ~~sweet~~heavy crude ~~oil~~oils and other feedstocks and blendstocks; and

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

Torrance Refinery. The benchmark refining margin for the Torrance refinery is calculated by assuming that four barrels of ANS crude oil are converted into three barrels of gasoline, one-half barrel of diesel and one-half barrel of jet fuel. We calculate this benchmark using the West Coast Los Angeles market value of California reformulated blendstock for oxygenate blending (“CARBOB”), CARB diesel and jet fuel and refer to the benchmark as the ANS (West Coast) 4-3-1 benchmark refining margin. Our Torrance refinery has a product slate of approximately 5654% gasoline and 2729% distillate with the remaining portion of the product slate comprised of lower-value products (35% ~~LPG~~black oil, 32% ~~black~~LPG ~~oil~~ and 1110% other). For this reason, we believe the ANS (West Coast) 4-3-1 is an appropriate benchmark industry refining margin. The majority of Torrance revenues are generated off West Coast Los Angeles-based market prices.

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

•the Torrance refinery has generally processed a slate of primarily heavy sour crude oils, which has historically constituted approximately 7065% to 9080% of total throughput. The Torrance crude slate has the lowest API gravity (typically an API gravity of less than 20 degrees) of all of our refineries. The remaining throughput consists of other feedstocks and blendstocks; and

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

6263

Martinez Refinery. The benchmark refining margin for the Martinez refinery is calculated by assuming that three barrels of ANS crude oil are converted into two barrels of gasoline, one-quarter barrel of diesel and three-quarter barrel of jet fuel. We calculate this benchmark using the West Coast San Francisco market value of CARBOB, CARB diesel and jet fuel and refer to the benchmark as the ANS (West Coast) 3-2-1 benchmark refining margin. Our Martinez refinery has a product slate of approximately 5457% gasoline and 3531% distillate with the remaining portion of the product slate comprised of lower-value products (24% black oil petroleum coke, 4% LPG and 54% other). For this reason, we believe the ANS (West Coast) 3-2-1 is an appropriate benchmark industry refining margin. The majority of Martinez revenues are generated off West Coast San Francisco-based market prices.

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

•the Martinez refinery has generally processed a slate of primarily heavy sour crude oils, which has historically constituted approximately 7045% to 9070% of total throughput. The remaining throughput consists of other feedstocks and blendstocks; and

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

6364

Results of Operations

The following tables reflect our consolidated financial and operating highlights for the years ended December 31, ~~2022~~2023, ~~2021~~2022 and ~~2020~~2021 (amounts in millions, unless otherwise noted).

	Year Ended December 31,
	2022		2021		2020
	2023		2022		2021
Revenues	$	4638,~~780~~288.65	$	2746,~~202~~780.06	$	1527,~~045~~202.0
Cost and expenses:
Cost of products and other	3933,~~350~~000.78		2439,~~114~~350.37		1424,~~548~~114.23
Operating expenses (excluding depreciation and amortization expense as reflected below)	2,~~495~~581.63		12,~~999~~495.16		1,~~835~~999.21
Depreciation and amortization expense	~~466~~523.9		~~415~~466.79		~~498~~415.07
Cost of sales	4236,~~313~~106.20		2642,~~529~~313.12		1626,~~881~~529.41
General and administrative expenses (excluding depreciation and amortization expense as reflected below)	~~438~~350.52		~~226~~438.45		~~229~~226.04
Depreciation and amortization expense	78.5		137.35		1113.3
Change in fair value of contingent consideration, net	48(45.18)		2948.41		~~(79~~29.3)4
Impairment expense	—		—		91.8
(Gain) loss on sale of assets	(1.3)		0.9		(0.2)
Loss (gain) on sale of assets	0.9		(0.2)		(477.8)
Total cost and expenses	36,417.6		42,808.2		26,798.0
Total cost and expenses	42,808.2		26,798.0		16,656.4
Income from operations	1,870.9		3,972.4		404.0
Income (loss) from operations	3,972.4		404.0		(1,611.4)
Other income (expense):
Interest expense, net	(~~206~~61.93)		(~~275~~206.19)		(~~210~~275.31)
Change in fair value of catalyst obligations	(21.0)1		8(2.50)		~~(11.~~8).5
(Loss) gain on extinguishment of debt	(665.17)		79(66.91)		~~(22~~79.2)9
Other non-service components of net periodic benefit cost	80.87		78.8		47.38
Income (loss) before income taxes	3,706.2		225.1		(1,851.4)
Income before income taxes	1,805.7		3,706.2		225.1
Income tax (benefit) expense	(2.7)		(14.0)		6.1
Income tax expense (benefit)	1.9		(2.7)		(14.0)
Net income (loss)	3,708.9		239.1		(1,857.5)
Net income	1,803.8		3,708.9		239.1
Less: net income (loss) attributable to noncontrolling interests	(10.4)9		2(1.34)		(02.3)
Net income (loss) attributable to PBF Holding Company LLC	$	3,710.3	$	236.8	$	(1,857.2)
Net income attributable to PBF Holding Company LLC	$	1,802.9	$	3,710.3	$	236.8
Consolidated gross margin	$	42,~~467~~182.45	$	~~672~~4,467.94	$	~~(1,836~~672.4)9
Gross refining margin (1)	$	75,~~429~~287.97	$	37,~~087~~429.79	$	~~496~~3,087.87

——————————

(1)See Non-GAAP Financial Measures.

Operating Highlights

	Year Ended December 31,
	2022			2021			2020
Key Operating Information
Production (bpd in thousands)	937.1			852.2			737.1
Crude oil and feedstocks throughput (bpd in thousands)	925.1			834.5			727.7
Total crude oil and feedstocks throughput (millions of barrels)	337.7			304.6			266.3
Consolidated gross margin per barrel of throughput	$	13.23		$	2.22		$	(6.90)
Gross refining margin, excluding special items, per barrel of throughput (1)	$	22.00		$	7.94		$	3.23
Refinery operating expense, per barrel of throughput	$	7.39		$	6.56		$	6.89
Crude and feedstocks (% of total throughput) (2)
Heavy	32		%	34		%	42		%
Medium	36		%	31		%	26		%
Light	18		%	18		%	17		%
Other feedstocks and blends	14		%	17		%	15		%
Total throughput	100		%	100		%	100		%
Yield (% of total throughput)
Gasoline and gasoline blendstocks	47		%	53		%	51		%
Distillates and distillate blendstocks	35		%	30		%	30		%
Lubes	1		%	1		%	1		%
Chemicals	1		%	2		%	1		%
Other	17		%	16		%	18		%
Total yield	101		%	102		%	101		%
_________________
(1) See Non-GAAP Financial Measures.
(2) We define heavy crude oil as crude oil with an API gravity of less than 24 degrees. We define medium crude oil as crude oil with an API gravity between 24 and 35 degrees. We define light crude oil as crude oil with an API gravity higher than 35 degrees.

~~The~~Operating ~~table below summarizes certain market indicators relating to our operating results as reported by Platts, a division of The McGraw-Hill Companies.~~Highlights

	Year Ended December 31,
	2022			2021			2020
	2023			2022			2021
	(dollars per barrel, except as noted)
Key Operating Information
Dated Brent crude oil	$	101.27		$	70.89		$	41.62
Production (bpd in thousands)	918.3			937.1			852.2
West Texas Intermediate (WTI) crude oil	$	94.58		$	68.10		$	39.25
Crude oil and feedstocks throughput (bpd in thousands)	909.4			925.1			834.5
Light Louisiana Sweet (LLS) crude oil	$	96.81		$	69.59		$	41.13
Total crude oil and feedstocks throughput (millions of barrels)	329.0			337.7			304.6
Alaska North Slope (ANS) crude oil	$	98.76		$	70.56		$	42.20
Consolidated gross margin per barrel of throughput	$	6.63		$	13.23		$	2.22
Crack Spreads
Gross refining margin, excluding special items, per barrel of throughput (1)	$	16.07		$	22.00		$	7.94
Dated Brent (NYH) 2-1-1	$	40.26		$	16.84		$	9.11
Refinery operating expense, per barrel of throughput	$	7.85		$	7.39		$	6.56
WTI (Chicago) 4-3-1	$	31.56		$	16.34		$	6.30
Crude and feedstocks (% of total throughput) (2)
LLS (Gulf Coast) 2-1-1	$	37.56		$	16.03		$	7.59
Heavy	27		%	32		%	34		%
ANS (West Coast-LA) 4-3-1	$	41.64		$	20.10		$	11.30
Medium	35		%	36		%	31		%
ANS (West Coast-SF) 3-2-1	$	41.89		$	20.55		$	9.99
Light	20		%	18		%	18		%
Crude Oil Differentials
Other feedstocks and blends	18		%	14		%	17		%
Dated Brent (foreign) less WTI	$	6.68		$	2.80		$	2.37
Total throughput	100		%	100		%	100		%
Dated Brent less Maya (heavy, sour)	$	13.95		$	6.47		$	5.37
Yield (% of total throughput)
Dated Brent less WTS (sour)	$	6.98		$	2.63		$	2.33
Gasoline and gasoline blendstocks	47		%	47		%	53		%
Dated Brent less ASCI (sour)	$	9.68		$	3.90		$	1.81
Distillates and distillate blendstocks	34		%	35		%	30		%
WTI less WCS (heavy, sour)	$	21.30		$	14.19		$	10.72
Lubes	1		%	1		%	1		%
WTI less Bakken (light, sweet)	$	(4.05)		$	(0.14)		$	2.41
Chemicals	1		%	1		%	2		%
WTI less Syncrude (light, sweet)	$	(3.04)		$	2.25		$	2.13
Other	18		%	17		%	16		%
WTI less LLS (light, sweet)	$	(2.22)		$	(1.50)		$	(1.88)
Total yield	101		%	101		%	102		%
WTI less ANS (light, sweet)	$	(4.17)		$	(2.46)		$	(2.95)
_________________
Natural gas (dollars per MMBTU)	$	6.54		$	3.73		$	2.13
(1) See Non-GAAP Financial Measures.
(2) We define heavy crude oil as crude oil with an API gravity of less than 24 degrees. We define medium crude oil as crude oil with an API gravity between 24 and 35 degrees. We define light crude oil as crude oil with an API gravity higher than 35 degrees.

2022 Compared to 2021

Overview— Our net income was $3,708.9 million for the year ended December 31, 2022 compared to net income of $239.1 million for the year ended December 31, 2021.

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. Our results for the year ended December 31, 2021 were positively impacted by special items consisting of a non-cash LCM inventory adjustment of approximately $669.6 million and a gain on the extinguishment of debt associated with the repurchase of a portion of our 2028 Senior Notes and 2025 Senior Notes of $79.9 million, offset by charges associated with the change in the fair value of the Martinez Contingent Consideration of $29.4 million.

~~Excluding~~The ~~the~~table ~~impact~~below ofsummarizes ~~these~~certain ~~special~~market ~~items,~~indicators ~~when~~relating ~~comparing~~to our operating results toas ~~the~~reported ~~year~~by ~~ended December 31~~Platts, ~~2021,~~a wedivision ~~experienced an increase in the demand for our refined products, evidenced by higher throughput volumes and barrels sold at all~~ of ~~our~~The ~~refineries,~~McGraw-Hill ~~as well as overall stronger refining margins due to favorable movements in crack spreads and crude oil differentials~~Companies. ~~These~~Effective ~~improving~~RIN ~~metrics~~basket ~~have~~price ~~positively~~is ~~impacted~~recalculated ~~our~~based ~~revenues,~~on ~~gross~~information ~~margin~~as ~~and~~reported ~~operating~~by ~~income~~Argus.

Revenues— Revenues totaled $46.8 billion for the year ended December 31, 2022 compared to $27.2 billion for the year ended December 31, 2021, an increase of approximately $19.6 billion or 72.1%. Revenues per barrel sold were $123.12 and $80.64 for the years ended December 31, 2022 and 2021, respectively, an increase of 52.7% directly related to higher hydrocarbon commodity prices. For the year ended December 31, 2022, the total throughput rates at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 300,300 bpd, 148,500 bpd, 180,700 bpd and 295,600 bpd, respectively. For the year ended December 31, 2021, the total throughput rates at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 250,900 bpd, 134,100 bpd, 163,300 bpd and 286,200 bpd, respectively. For the year ended December 31, 2022, the total barrels sold at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 353,800 bpd, 158,200 bpd, 190,600 bpd and 338,400 bpd, respectively. For the year ended December 31, 2021, the total barrels sold at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 292,500 bpd, 142,600 bpd, 170,400 bpd and 318,700 bpd, respectively.


	Year Ended December 31,
	2023		2022		2021
	(dollars per barrel, except as noted)
Dated Brent crude oil	$	82.64	$	101.27	$	70.89
West Texas Intermediate (WTI) crude oil	$	77.67	$	94.58	$	68.10
Light Louisiana Sweet (LLS) crude oil	$	80.14	$	96.81	$	69.59
Alaska North Slope (ANS) crude oil	$	82.36	$	98.76	$	70.56
Crack Spreads
Dated Brent (NYH) 2-1-1	$	29.67	$	40.26	$	16.84
WTI (Chicago) 4-3-1	$	23.71	$	31.56	$	16.34
LLS (Gulf Coast) 2-1-1	$	29.13	$	37.56	$	16.03
ANS (West Coast-LA) 4-3-1	$	36.88	$	41.64	$	20.10
ANS (West Coast-SF) 3-2-1	$	36.89	$	41.89	$	20.55
Crude Oil Differentials
Dated Brent (foreign) less WTI	$	4.97	$	6.68	$	2.80
Dated Brent less Maya (heavy, sour)	$	13.71	$	13.95	$	6.47
Dated Brent less WTS (sour)	$	4.99	$	6.98	$	2.63
Dated Brent less ASCI (sour)	$	5.73	$	9.68	$	3.90
WTI less WCS (heavy, sour)	$	18.32	$	21.30	$	14.19
WTI less Bakken (light, sweet)	$	(1.28)	$	(4.05)	$	(0.14)
WTI less Syncrude (light, sweet)	$	(0.91)	$	(3.04)	$	2.25
WTI less LLS (light, sweet)	$	(2.48)	$	(2.22)	$	(1.50)
WTI less ANS (light, sweet)	$	(4.70)	$	(4.17)	$	(2.46)
Effective RIN basket price	$	7.02	$	7.66	$	6.75
Natural gas (dollars per MMBTU)	$	2.66	$	6.54	$	3.73

~~Overall~~2023 ~~average~~Compared ~~throughput rates were higher for the year ended December 31, 2022 compared~~ to 2021. During the year ended December 31, 2021, we operated our refineries at reduced rates and periodically increased the throughput rates across our entire refining system to correlate with the gradual increases in demand experienced throughout the year. Overall average throughput in 2022 remained high as a result of sustained increases in demand and favorable market conditions. Total refined product barrels sold were higher than throughput rates, reflecting sales from inventory as well as sales and purchases of refined products outside our refineries.

~~Consolidated Gross Margin~~Overview— ~~Consolidated~~Our ~~gross~~net ~~margin~~income ~~totaled~~was $41,~~467~~803.48 million for the year ended December 31, ~~2022,~~2023 compared to ~~$672.9~~net ~~million~~income ~~for the year ended December 31, 2021, an increase~~ of $3,~~794~~708.~~5 million. Gross refining margin (as described below in Non-GAAP Financial Measures) totaled $7,429.~~9 million, ~~or $22.00 per barrel of throughput,~~ for the year ended December 31, 2022 ~~compared to $3,087~~.7 million, or $10.14 per barrel of throughput, for the year ended December 31, 2021, an increase of approximately $4,342.2 million. Gross refining margin excluding special items totaled $7,429.9 million, or $22.00 per barrel of throughput, for the year ended December 31, 2022 compared to $2,418.1 million, or $7.94 per barrel of throughput, for the year ended December 31, 2021, an increase of $5,011.8 million.

~~During~~Our results for the year ended December 31, ~~2022,~~2023 ~~our margin calculations~~ were ~~not~~positively impacted by special items. ~~Consolidated~~consisting ~~gross~~of ~~margin~~a ~~and~~change ~~gross~~in ~~refining~~fair ~~margin~~value ~~increased~~of ~~due~~contingent toconsideration ~~favorable~~related ~~movements~~to changes in ~~certain~~our ~~crack~~earn-out ~~spreads~~obligation ~~and~~associated ~~crude~~with ~~oil~~the ~~differentials~~acquisition ~~and~~of ~~higher~~the ~~throughput~~Martinez ~~volumes~~refinery and ~~barrels~~logistic ~~sold~~assets at(the ~~all~~“Martinez ofContingent ~~our~~Consideration”) ~~refineries~~of $45.8 ~~For~~million ~~the~~and ~~year~~a ~~ended~~gain ~~December 31,~~on ~~2021,~~the ~~our~~sale ~~margin~~of ~~calculations included~~ a ~~favorable~~parcel ~~special~~of ~~item~~land ~~related~~at toour aTorrance ~~non-cash~~refinery ~~LCM~~of ~~inventory~~$1.7 million, ~~adjustment~~partially ofoffset ~~approximately~~by a $~~669~~5.67 million loss on aextinguishment ~~net~~of ~~basis~~debt ~~resulting~~related ~~from~~to the ~~increase~~redemption inof ~~crude~~the ~~oil~~2025 Senior Notes and ~~refined~~the ~~product~~amendment ~~prices~~and ~~from~~restatement of the ~~year~~Revolving ~~ended~~Credit ~~December 31~~Facility, ~~2020~~and toexit costs associated with the early termination of the Third Inventory Intermediation Agreement of $13.5 million. Our results for the year ended December 31, ~~2021~~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.

Additionally, our results continue to be impacted by significant costs to comply with the RFS. Total RFS costs were $1,225.5 million for the year ended December 31, 2022 compared to $726.0 million for the year ended December 31, 2021.

Average industry margins were favorable during the year ended December 31, 2022 compared to the prior year, primarily due to increased refining margins as a result of sustained demand and global supply disruptions.

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.

Revenues— Revenues totaled $38.3 billion for the year ended December 31, 2023 compared to $46.8 billion for the year ended December 31, 2022, a decrease of approximately $8.5 billion or 18.2%. Revenues per barrel sold were $100.75 and $123.12 for the years ended December 31, 2023 and 2022, respectively, a decrease of 18.2% directly related to lower hydrocarbon commodity prices. For the year ended December 31, 2023, the total throughput rates at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 327,600 bpd, 136,400 bpd, 174,200 bpd and 271,200 bpd, respectively. For the year ended December 31, 2022, the total throughput rates at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 300,300 bpd, 148,500 bpd, 180,700 bpd and 295,600 bpd, respectively. For the year ended December 31, 2023, the total barrels sold at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 373,700 bpd, 148,700 bpd, 187,300 bpd and 340,800 bpd, respectively. For the year ended December 31, 2022, the total barrels sold at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 353,800 bpd, 158,200 bpd, 190,600 bpd and 338,400 bpd, respectively.

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.

Consolidated gross margin— Consolidated gross margin totaled $2,182.5 million for the year ended December 31, 2023, compared to $4,467.4 million for the year ended December 31, 2022, a decrease of $2,284.9 million. Gross refining margin (as described below in Non-GAAP Financial Measures) totaled $5,287.7 million, or $16.07 per barrel of throughput, for the year ended December 31, 2023 compared to $7,429.9 million, or $22.00 per barrel of throughput, for the year ended December 31, 2022, a decrease of approximately $2,142.2 million. Consolidated gross margin and gross refining margin decreased due to unfavorable movements in crack spreads and crude oil differentials at the majority of our refineries. During the years ended December 31, 2023 and 2022, our margin calculations were not impacted by special items.

Additionally, our results continue to be impacted by significant costs to comply with the RFS. Total RFS compliance costs were $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 $40.26 per barrel, or 139.1% higher, in the year ended December 31, 2022, as compared to $16.84 per barrel in the same period in 2021. Our margins were positively impacted from our refinery specific slate on the East Coast by strengthened Dated Brent/Maya differential, which increased by $7.48 per barrel, offset by weakened WTI/Bakken differential, which decreased by $3.91 per barrel compared to the same period in 2021. The WTI/WCS differential increased to $21.30 per barrel in 2022 compared to $14.19 per barrel in 2021, which favorably impacted our cost of heavy Canadian crude.

Across the Mid-Continent, the WTI (Chicago) 4-3-1 industry crack spread was $31.56 per barrel, or 93.1% higher, in the year ended December 31, 2022, as compared to $16.34 per barrel in the prior year. Our margins were negatively impacted from our refinery specific slate in the Mid-Continent by a decreasing WTI/Bakken differential, which averaged a premium of $4.05 per barrel in the year ended December 31, 2022, as compared to a premium of $0.14 per barrel in the prior year. Additionally, the WTI/Syncrude differential averaged a premium of $3.04 per barrel for the year ended December 31, 2022 as compared to a discount of $2.25 per barrel in the prior year.

On the Gulf Coast, the LLS (Gulf Coast) 2-1-1 industry crack spread was $37.56 per barrel, or 134.3% higher, in the year ended December 31, 2022 as compared to $16.03 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 $2.22 per barrel for the year ended December 31, 2022 as compared to a premium of $1.50 per barrel in the prior year.

On the West Coast, the ANS (West Coast) 4-3-1 industry crack spread was $41.64 per barrel, or 107.2% higher, in the year ended December 31, 2022 as compared to $20.10 per barrel in the prior year. Additionally, the ANS (West Coast) 3-2-1 industry crack spread was $41.89 per barrel, or 103.8% higher, in the year ended December 31, 2022 as compared to $20.55 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 $4.17 per barrel for the year ended December 31, 2022 as compared to a premium of $2.46 per barrel in the prior year.

Operating Expenses— Operating expenses totaled $2,495.6 million, or $7.39 per barrel of throughput, for the year ended December 31, 2022 compared to $1,999.1 million, or $6.56 per barrel of throughput, for the year ended December 31, 2021, an increase of $496.5 million, or 24.8%. The increase in operating expenses was mainly attributable to increases in natural gas volumes and price across our refineries when compared to the prior year. Additionally, we experienced higher outside services, maintenance and operational costs due to increased production.

General and Administrative Expenses— General and administrative expenses totaled $438.5 million for the year ended December 31, 2022, compared to $226.4 million for the year ended December 31, 2021, an increase of $212.1 million or 93.7%. The increase in general and administrative expenses is primarily related to higher employee-related expenses, certain of which includes the recognition of incentive compensation. Our general and administrative expenses are comprised of personnel, facilities and other infrastructure costs necessary to support our refineries and related logistics assets.

Depreciation and Amortization Expense— Depreciation and amortization expense totaled $474.4 million for the year ended December 31, 2022 (including $466.9 million recorded within Cost of sales) compared to $429.0 million for the year ended December 31, 2021 (including $415.7 million recorded within Cost of sales), an increase of $45.4 million. The increase was a result of a general increase in our fixed asset base due to capital projects and turnarounds completed since the end of the prior year.

~~Change~~On inthe ~~Fair~~East ~~Value~~Coast, ofthe ~~Contingent~~Dated ~~Consideration~~Brent (NYH) 2-1-1 industry crack spread was approximately $29.67 per barrel, ~~net—~~or ~~Change~~26.3% lower, in ~~fair~~the ~~value~~year ofended ~~contingent~~December 31, ~~consideration~~2023, ~~represented~~as acompared ~~loss~~to of $4840.126 ~~million~~per ~~and~~barrel ain ~~loss~~the ofsame ~~$29~~period in 2022.4 ~~million~~Our ~~for~~margins were positively impacted from our refinery specific slate on the ~~years~~East ~~ended~~Coast ~~December 31~~by strengthened WTI/Bakken differential, ~~2022~~which ~~and~~increased ~~December 31~~by $2.77 per barrel, ~~2021~~offset by weakened Dated Brent/Maya differential, ~~respectively.~~which ~~These~~decreased by ~~losses~~$0.24 ~~were~~per ~~primarily~~barrel ~~related~~compared to the ~~changes~~same period in ~~estimated~~2022. ~~fair~~The ~~value~~WTI/WCS ofdifferential ~~the~~decreased ~~earn-out~~to ~~liability~~$18.32 ~~associated~~per ~~with~~barrel ~~the~~in ~~acquisition~~2023 ofcompared ~~the~~to ~~Martinez~~$21.30 ~~refinery,~~per ~~offset~~barrel byin ~~the~~2022, ~~recognition~~which ofunfavorably ~~contingent~~impacted ~~assets~~our ~~associated~~cost ~~with~~of ~~the~~heavy ~~acquisition~~Canadian crude.

~~Loss~~Across the Mid-Continent, the WTI (~~Gain~~Chicago) on4-3-1 ~~Sale~~industry ofcrack ~~Assets—~~spread ~~There~~ was a$23.71 ~~loss~~per ofbarrel, $0or 24.9% ~~million~~lower, ~~and~~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 ~~gain~~premium of $01.228 ~~million~~per ~~for~~barrel in the year ended December 31, ~~2022~~2023, ~~and~~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, ~~2021,~~2023 ~~respectively,~~as ~~related~~compared ~~primarily~~ to ~~the~~a ~~sale~~premium of ~~non-operating~~$3.04 ~~refinery~~per ~~assets~~barrel in the prior year.

~~Change~~On inthe ~~Fair~~Gulf ~~Value~~Coast, ofthe ~~Catalyst~~LLS ~~Obligations—~~(Gulf ~~Change~~Coast) in2-1-1 ~~fair~~industry ~~value~~crack ofspread ~~catalyst~~was ~~obligations~~$29.13 ~~represented~~per abarrel, ~~loss~~or ~~of $2~~22.04% ~~million~~lower, ~~for~~in the year ended December 31, ~~2022,~~2023 as compared to ~~a gain of~~ $837.556 ~~million~~per ~~for~~barrel in the prior year. ~~ended~~Margins ~~December 31,~~on ~~2021.~~the ~~These~~Gulf ~~losses~~Coast ~~and~~were ~~gains~~negatively ~~relate~~impacted tofrom ~~the~~our ~~change~~refinery inspecific ~~fair~~slate ~~value~~by ofa ~~the~~weakening ~~precious~~WTI/LLS ~~metals~~differential, ~~underlying~~which ~~the~~averaged ~~sale~~a ~~and~~premium ~~leaseback~~ of ~~our~~$2.48 ~~refineries’~~per ~~precious~~barrel ~~metal~~for ~~catalysts,~~the ~~which~~year weended ~~are~~December 31, ~~obligated~~2023 as compared to ~~repurchase~~a atpremium ~~fair~~of ~~market~~$2.22 ~~value~~per ~~upon~~barrel ~~lease~~in ~~termination~~the prior year.

~~(Loss)~~On ~~Gain~~the onWest ~~Extinguishment~~Coast, ofthe ~~Debt—~~ANS We(West ~~incurred~~Coast) a4-3-1 ~~loss~~industry oncrack ~~extinguishment~~spread ofwas ~~debt~~$36.88 ofper ~~$66~~barrel, or 11.14% ~~million~~lower, in the year ended December 31, ~~2022~~2023 ~~related~~as compared to ~~the~~$41.64 ~~redemption~~per ofbarrel ~~all~~in ofthe prior year. Additionally, the ~~outstanding~~ANS ~~2025~~(West ~~Senior~~Coast) ~~Secured~~3-2-1 ~~Notes~~industry crack spread was $36.89 per barrel, ~~slightly~~or ~~offset~~11.9% bylower, ain ~~gain~~the ~~related~~year ended December 31, 2023 as compared to $41.89 per barrel in the ~~repurchase~~prior ofyear. aOur ~~portion~~margins ofon ~~our~~the ~~2028~~West ~~Senior~~Coast ~~Notes~~were ~~and~~negatively ~~2025~~impacted ~~Senior~~from ~~Notes.~~our Werefinery ~~incurred~~specific slate by a ~~gain~~weakening onWTI/ANS ~~extinguishment~~differential, ofwhich ~~debt~~averaged a premium of $794.970 ~~million~~per inbarrel for the year ended December 31, ~~2021~~2023 ~~related~~as compared to ~~the repurchase of~~ a ~~portion~~premium of ~~our~~$4.17 ~~2028~~per ~~Senior~~barrel ~~Notes~~in ~~and~~the ~~2025~~prior ~~Senior Notes~~year.

~~Interest~~Operating ~~Expense, net~~expenses— ~~Interest~~Operating ~~expense~~expenses totaled $~~206~~2,581.93 million, ~~for~~or ~~the~~$7.85 ~~year~~per ~~ended~~barrel ~~December 31,~~of ~~2022~~throughput, ~~compared to $275.1 million~~ for the year ended December 31, ~~2021,~~2023 acompared ~~decrease~~to of $~~68.~~2,495.6 million., ~~This~~or ~~net~~$7.39 ~~decrease~~per isbarrel ~~mainly attributable to the redemption~~ of ~~the~~throughput, ~~2025~~for ~~Senior Secured Notes during~~ the ~~third~~year ~~quarter~~ended ofDecember 31, 2022, asan ~~well~~increase asof ~~lower~~$85.7 ~~outstanding~~million, ~~balances~~or ~~on our Revolving Credit Facility~~3.4%. ~~Interest~~The ~~expense~~increase ~~includes~~in ~~interest~~operating onexpenses ~~long-term~~was ~~debt,~~mainly ~~costs~~attributable ~~related~~ to ~~the~~higher ~~sale~~maintenance and ~~leaseback~~operational ~~of our precious metal catalysts, financing~~ costs ~~associated~~primarily ~~with~~due ~~the~~to ~~Third~~unplanned ~~Inventory Intermediation Agreement with J. Aron~~downtime, ~~letter~~partially ofoffset ~~credit~~by ~~fees~~lower ~~associated~~energy ~~with~~expenses ~~the~~driven ~~purchase~~by oflower ~~certain~~natural ~~crude~~gas ~~oils and the amortization of deferred financing costs~~prices.

~~Income~~General ~~Tax~~and ~~Expense~~administrative expenses— AsGeneral weand ~~are~~administrative aexpenses ~~limited~~totaled ~~liability~~$350.2 ~~company~~million ~~treated~~for asthe ayear ~~“flow-through”~~ended ~~entity~~December 31, ~~for income tax purposes~~2023, ~~our~~compared ~~consolidated~~to ~~financial~~$438.5 ~~statements~~million ~~generally do not include a benefit or expense~~ for ~~income taxes for~~ the ~~years~~year ended December 31, 2022, ~~and~~a ~~2021,~~decrease ~~respectively,~~of ~~apart~~$88.3 ~~from~~million ~~the~~or ~~income~~20.1%. ~~tax~~Our ~~attributable~~general toand ~~two~~administrative ~~subsidiaries~~expenses ~~acquired~~were lower in ~~connection~~comparison ~~with~~to the ~~acquisition~~prior ofyear ~~our~~due ~~Chalmette~~to ~~refinery~~lower ~~and our wholly~~employee-~~owned~~related ~~Canadian subsidiary~~expenses, ~~PBF~~including ~~Energy~~lower ~~Limited~~incentive ~~(“PBF Ltd~~compensation.~~”).~~ ~~These~~General ~~subsidiaries~~and ~~are~~administrative ~~treated~~costs asare ~~C-Corporations~~comprised ~~for income tax purposes. An income tax benefit~~ of ~~$2.7~~personnel, ~~million~~facilities ~~was~~and ~~recorded~~other ~~for~~infrastructure ~~the~~costs ~~year~~necessary ~~ended December 31, 2022 in comparison~~ to ~~income~~support ~~tax~~our ~~benefit~~refineries ofand ~~$14.0~~related ~~million~~logistics ~~recorded for the year ended December 31, 2021, primarily attributable to the results of PBF Ltd~~assets.

(Gain) loss on sale of assets— There was a net gain of $1.3 million for the year ended December 31, 2023 related primarily to the sale of a parcel of land at our Torrance refinery. There was a loss of $0.9 million for the year ended December 31, 2022 related primarily to the sale of non-operating refinery assets.

Depreciation and amortization expense— Depreciation and amortization expense totaled $532.4 million for the year ended December 31, 2023 (including $523.9 million recorded within Cost of sales) compared to $474.4 million for the year ended December 31, 2022 (including $466.9 million recorded within Cost of sales), an increase of $58.0 million. The increase was a result of a general increase in our fixed asset base due to capital projects and turnarounds completed since the end of the prior year.

Change in fair value of contingent consideration, net— Change in fair value of contingent consideration represented a gain of $45.8 million and a loss of $48.1 million for the years ended December 31, 2023 and December 31, 2022, respectively. These gains and losses were related to changes in the estimated fair value of the Martinez Contingent Consideration.

Change in fair value of catalyst obligations— Change in fair value of catalyst obligations represented a gain of $1.1 million for the year ended December 31, 2023, compared to a loss of $2.0 million for the year ended December 31, 2022. These gains and losses relate to the change in fair value of the precious metals underlying the sale and leaseback of our refineries’ precious metal catalysts, which we were obligated to repurchase at fair market value upon lease termination.

(Loss) gain on extinguishment of debt— There was a loss on extinguishment of debt of $5.7 million in the year ended December 31, 2023, related to the redemption of the 2025 Senior Notes and the amendment and restatement of the Revolving Credit Agreement. There was a loss on extinguishment of debt of $66.1 million incurred in the year ended December 31, 2022 related to the redemption of all of the outstanding 2025 Senior Secured Notes, slightly offset by a gain related to the repurchase of a portion of each of the 2028 Senior Notes and 2025 Senior Notes.

Interest expense, net— Interest expense totaled $61.3 million for the year ended December 31, 2023, compared to $206.9 million for the year ended December 31, 2022, a decrease of $145.6 million. The net decrease is mainly attributable to the redemption of the 2025 Senior Secured Notes during the third quarter of 2022, and the redemption of the 2025 Senior Notes in the third quarter of 2023, and the offering of our 2030 Senior Notes during the third quarter of 2023 at a reduced principal amount, as well as no outstanding balance on our Revolving Credit Facility. Additionally, the early termination of the Third Inventory Intermediation Agreement in 2023 further reduced our interest expense. There was also a $51.8 million increase in interest income earned during the year ended December 31, 2023 driven by higher interest rates in comparison to the prior year. Interest expense includes interest on long-term debt, costs related to the sale and leaseback of our precious metal catalysts, financing costs and subsequent one-time exit costs of $13.5 million associated with the Third Inventory Intermediation Agreement with J. Aron, which was terminated effective as of July 31, 2023, letter of credit fees associated with the purchase of certain crude oils and the amortization of deferred financing costs.

Income tax expense (benefit)— As we are a limited liability company treated as a “flow-through” entity for income tax purposes, our consolidated financial statements generally do not include a benefit or expense for income taxes for the years ended December 31, 2023 and 2022, respectively, apart from the income tax attributable to two subsidiaries acquired in connection with the acquisition of our Chalmette refinery and our wholly-owned Canadian subsidiary, PBF Energy Limited (“PBF Ltd.”). These subsidiaries are treated as C-Corporations for income tax purposes. Income tax expense of $1.9 million was recorded for the year ended December 31, 2023 in comparison to an income tax benefit of $2.7 million recorded for the year ended December 31, 2022, primarily attributable to the results of PBF Ltd.

Non-GAAP Financial Measures

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

Special Items

The Non-GAAP measures presented include gross refining margin excluding special items, and EBITDA excluding special items. Special items for the periods presented relate to LCM inventory ~~adjustments~~adjustment, net changes in fair value of contingent consideration, loss (gain) on extinguishment of debt, ~~gain on sale of hydrogen plants, severance~~ and ~~reconfiguration~~gain ~~costs, impairment expense, gains~~ on land sales~~, charges associated with the early return of certain leased railcars, turnaround acceleration costs, and a LIFO inventory decrement~~. 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.

7071

Gross Refining Margin and Gross Refining Margin Excluding Special Items

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):

	Year Ended December 31,
	2022				2021				2020
	2023				2022				2021
	$		per barrel of throughput		$		per barrel of throughput		$		per barrel of throughput
Calculation of consolidated gross margin:
Revenues	$	4638,~~780~~288.65	$	~~138~~116.5537	$	2746,~~202~~780.06	$	89138.3055	$	1527,~~045~~202.0	$	5689.4930
Less: Cost of sales	4236,~~313~~106.20		~~125~~109.3274		2642,~~529~~313.12		87125.0832		1626,~~881~~529.41		6387.3908
Consolidated gross margin	$	42,~~467~~182.45	$	136.2363	$	~~672~~4,467.94	$	213.2223	$	~~(1,836~~672.4)9	$	(62.~~90)~~22
Reconciliation of consolidated gross margin to gross refining margin:
Consolidated gross margin	$	42,~~467~~182.45	$	136.2363	$	~~672~~4,467.94	$	213.2223	$	~~(1,836~~672.4)9	$	(62.~~90)~~22
Add: Refinery operating expense	2,~~495~~581.63		7.3985		12,~~999~~495.16		67.5639		1,~~835~~999.21		6.8956
Add: Refinery depreciation expense	~~466~~523.9		1.3859		~~415~~466.79		1.3638		~~498~~415.07		1.8736
Gross refining margin	$	75,~~429~~287.97	$	2216.0007	$	37,~~087~~429.79	$	1022.1400	$	~~496~~3,087.87	$	110.8614
Special Items: (1)
Add: Non-cash LCM inventory adjustment	—		—		(669.6)		(2.20)		268.0		1.01
Add: LCM inventory adjustment	—		—		—		—		(669.6)		(2.20)
Add: LIFO inventory decrement	—		—		—		—		83.0		0.31
Gross refining margin excluding special items	$	5,287.7	$	16.07	$	7,429.9	$	22.00	$	2,418.1	$	7.94
Add: Early railcar return expense	—		—		—		—		12.5		0.05
Gross refining margin excluding special items	$	7,429.9	$	22.00	$	2,418.1	$	7.94	$	860.3	$	3.23

——————————

See Notes to Non-GAAP Financial Measures.

7172

EBITDA, EBITDA Excluding Special Items and Adjusted EBITDA

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

EBITDA, EBITDA excluding special items and Adjusted EBITDA are not presentations made in accordance with GAAP and our computation of EBITDA, EBITDA excluding special items and Adjusted EBITDA may vary from others in our industry. In addition, Adjusted EBITDA contains some, but not all, adjustments that are taken into account in the calculation of the components of various covenants in the agreements governing our senior notes and other credit facilities. EBITDA, EBITDA excluding special items and Adjusted EBITDA should not be considered as alternatives to income from operations or net income as measures of operating performance. In addition, EBITDA, EBITDA excluding special items and Adjusted EBITDA are not presented as, and should not be considered, an alternative to cash flows from operations as a measure of liquidity. Adjusted EBITDA is defined as EBITDA before adjustments for items such as stock-based compensation expense, change in the fair value of catalyst obligations, ~~gain on sale of hydrogen plants,~~ the write down of inventory to the LCM, ~~(gain)~~net ~~loss~~change onin ~~extinguishment~~the fair value of ~~debt~~contingent ~~related~~consideration, togain ~~refinancing~~on ~~activities~~land sales, ~~change~~loss in(gain) ~~the~~on ~~fair~~extinguishment ~~value~~ of ~~contingent~~debt ~~consideration~~ and certain other non-cash items.

Other companies, including other companies in our industry, may calculate EBITDA, EBITDA excluding special items and Adjusted EBITDA differently than we do, limiting their usefulness as comparative measures. EBITDA, EBITDA excluding special items and Adjusted EBITDA also have limitations as analytical tools and should not be considered in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations include that EBITDA, EBITDA excluding special items and Adjusted EBITDA:

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

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

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

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

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

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

7273

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

	Year Ended December 31,
		2022		2021		2020
		2023		2022		2021
Reconciliation of net income (loss) to EBITDA and EBITDA excluding special items:
Reconciliation of net income to EBITDA and EBITDA excluding special items:
Net income (loss)		$	3,708.9	$	239.1	$	(1,857.5)
Net income		$	1,803.8	$	3,708.9	$	239.1
Add: Depreciation and amortization expense		~~474~~532.4		~~429~~474.04		~~509~~429.30
Add: Interest expense, net		~~206~~61.93		~~275~~206.19		~~210~~275.31
Add: Income tax (benefit) expense		(2.7)		(14.0)		6.1
Add: Income tax expense (benefit)		1.9		(2.7)		(14.0)
EBITDA		$	42,~~387~~399.54	$	~~929~~4,387.25	$	~~(1,131~~929.8)2
Special Items: (1)
Add: Non-cash LCM inventory adjustment		—		(669.6)		268.0
Add: LCM inventory adjustment		—		—		(669.6)
Add: Change in fair value of contingent consideration, net		48(45.18)		2948.41		~~(79~~29.3)4
Add: Gain on sale of hydrogen plants		—		—		(471.1)
Add: Gain on land sales		(1.7)		—		—
Add: Gain on land sales		—		—		(8.1)
Add: Loss (gain) on extinguishment of debt		5.7		66.1		(79.9)
Add: Impairment expense		—		—		91.8
EBITDA excluding special items		$	2,357.6	$	4,501.7	$	209.1
Add: LIFO inventory decrement		—		—		83.0
Add: Severance and reconfiguration costs		—		—		30.0
Add: Early railcar return expense		—		—		12.5
Add: Loss (gain) on extinguishment of debt		66.1		(79.9)		22.2
EBITDA excluding special items		$	4,501.7	$	209.1	$	(1,182.8)
Reconciliation of EBITDA to Adjusted EBITDA:
EBITDA		$	42,~~387~~399.54	$	~~929~~4,387.25	$	~~(1,131~~929.8)2
Add: Stock based compensation		4451.15		3044.31		2930.3
Add: Change in fair value of catalyst obligations		2(1.01)		(82.5)0		~~11.~~(8.5)
Add: Non-cash LCM inventory adjustment (1)		—		(669.6)		268.0
Add: LCM inventory adjustment (1)		—		—		(669.6)
Add: Change in fair value of contingent consideration, net (1)		48(45.18)		2948.41		~~(79~~29.3)4
Add: Gain on sale of hydrogen plants (1)		—		—		(471.1)
Add: Gain on land sales (1)		(1.7)		—		—
Add: Gain on land sales (1)		—		—		(8.1)
Add: Loss (gain) on extinguishment of debt (1)		5.7		66.1		(79.9)
Add: Impairment expense (1)		—		—		91.8
Adjusted EBITDA		$	2,408.0	$	4,547.8	$	230.9
Add: LIFO inventory decrement (1)		—		—		83.0
Add: Severance and reconfiguration costs (1)		—		—		30.0
Add: Early railcar return expense (1)		—		—		12.5
Add: Loss (gain) on extinguishment of debt (1)		66.1		(79.9)		22.2
Adjusted EBITDA		$	4,547.8	$	230.9	$	(1,141.7)

——————————

See Notes to Non-GAAP Financial Measures.

7374

Notes to Non-GAAP Financial Measures

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

(1) Special items:

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

The following table includes the LCM inventory reserve as of each date presented (in millions):

	2022		2021		2020
	2023		2022		2021
January 1,	$	—	$	~~669.6~~—	$	~~401~~669.6
December 31,	—		—		~~669.6~~—

The following table includes the corresponding impact of changes in the LCM inventory reserve on income ~~(loss)~~ from operations and net income ~~(loss)~~ for the periods presented (in millions):

	Year Ended December 31,
	2022		2021		2020
	2023		2022		2021
Net LCM inventory adjustment benefit (charge) in both income (loss) from operations and net income (loss)	$	—	$	669.6	$	(268.0)
Net LCM inventory adjustment benefit in both income from operations and net income	$	—	$	—	$	669.6

Change in ~~Fair~~fair ~~Value~~value of ~~Contingent~~contingent ~~Consideration~~consideration, net - During the year ended December 31, ~~2022~~2023, we recorded a net change in fair value of ~~contingent consideration related to changes in~~ the ~~estimated fair value of the earn-out liability associated with the acquisition of the~~ Martinez ~~refinery~~Contingent Consideration, ~~offset~~which byincreased ~~the recognition of contingent assets associated with the acquisition. These changes resulted in decreases to~~ income from operations and net income by $4845.18 million. During the year ended December 31, ~~2021~~2022, we recorded a net change in fair value of the Martinez Contingent Consideration, offset by the recognition of contingent ~~consideration~~assets ~~related~~associated towith the ~~Martinez~~acquisition. ~~Contingent~~These ~~Consideration~~changes ~~which~~in estimate decreased income from operations and net income by $2948.41 million. During the year ended December 31, ~~2020~~2021, we recorded a change in fair value of the ~~contingent consideration related to the~~ Martinez Contingent Consideration, which ~~increased~~decreased income from operations and net income by $7929.34 million.

~~Gain~~Loss (gain) on ~~Sale~~extinguishment of ~~Hydrogen~~debt ~~Plants~~ - During the year ended December 31, ~~2020~~2023, we recorded a ~~gain~~loss on extinguishment of debt related to the ~~sale~~redemption of ~~five~~our ~~hydrogen~~2025 ~~plants.~~Senior ~~The~~Notes ~~gain~~and ~~increased~~the amendment and restatement of the Revolving Credit Facility, which decreased income ~~from~~before ~~operations~~income taxes and net income by $~~471~~5.17 million. ~~There~~During ~~were no such gains in~~ the ~~years~~year ended December 31, 2022, we recorded a loss on extinguishment of debt related to the redemption of the 2025 Senior Secured Notes, partially offset by the gain recognized on the repurchase of a portion of each of the 2028 Senior Notes and the 2025 Senior Notes, which decreased income before income taxes and net income by $66.1 million. During the year ended December 31, 2021, we recorded a gain on extinguishment of debt related to the repurchase of a portion of each of the 2028 Senior Notes and the 2025 Senior Notes, which increased net income by $79.9 million.

Gain on Land Sales - During the year ended December 31, 2020, we recorded a gain on sale of one separate parcel of real property acquired as part of the Torrance refinery, but not part of the refinery itself, which increased income from operations and net income by $8.1 million during the year ended December 31, 2020. There were no such gains in the years ended December 31, 2022 and December 31, 2021.

Impairment Expense - During the year ended December 31, 2020, we recorded an impairment charge which decreased income from operations and net income by $91.8 million, resulting from the write-down of certain assets as a result of the East Coast Refining Reconfiguration and project abandonments. There were no such impairment charges during the years ended December 31, 2022 and December 31, 2021.

LIFO Inventory Decrement - As part of our overall reduction in throughput in 2020 and our reduction in inventory volume as of December 31, 2020, the Company recorded a charge to cost of products and other related to a LIFO inventory layer decrement. The majority of the decrement related to our East Coast LIFO inventory layer and the reduction to our East Coast inventory experienced as part of the East Coast Refining Reconfiguration. These charges decreased income from operations and net income by $83.0 million for the year ended December 31, 2020. Decrements recorded in the years ended December 31, 2022 and December 31, 2021 were not significant.

Turnaround Acceleration Costs - During the year ended December 31, 2020, we accelerated the recognition of turnaround amortization associated with units that were temporarily idled as part of the East Coast Refining Reconfiguration. These costs decreased income from operations and net income by $56.2 million. There were no such costs in the years ended December 31, 2022 and December 31, 2021.

Severance and Reconfiguration Costs - During the year ended December 31, 2020, we recorded severance charges related to reductions in our workforce which decreased income from operations and net income by $24.7 million. During the year ended December 31, 2020, we recorded reconfiguration charges related to the temporary idling of certain assets as part of our East Coast Refining System which decreased income from operations and net income by $5.3 million. There were no such costs in the years ended December 31, 2022 and December 31, 2021.

Early Return of Railcars - During the year ended December 31, 2020, we recognized certain expenses within Cost of sales associated with the voluntary early return of certain leased railcars which decreased income from operations and net income by $12.5 million. There were no such expenses recorded in the years ended December 31, 2022 and December 31, 2021.

Loss (Gain) on Extinguishment of Debt - During the year ended December 31, 2022, we recorded a loss on extinguishment of debt which decreased income before income taxes and net income by $66.1 million primarily related to the redemption of our 2025 Senior Secured Notes, partially offset by the repurchase of a portion of the 2028 Senior Notes and the 2025 Senior Notes. During the year ended December 31, 2021, we recorded a gain on extinguishment of debt related to the repurchase of a portion of the 2028 Senior Notes and the 2025 Senior Notes, which increased net income by $79.9 million. During the year ended December 31, 2020, we recorded debt extinguishment costs related to the redemption of the 2023 Senior Notes which decreased net income by $22.2 million.

Gain on land sales - During the year ended December 31, 2023, we recorded a gain on the sale of a separate parcel of real property acquired as part of the Torrance refinery, but not part of the refinery itself, which increased income from operations and net income by $1.7 million. There were no such gains in the years ended December 31, 2022 and December 31, 2021.

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are our cash flows from operations, cash and cash equivalents and borrowing availability under our credit ~~facilities~~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, ~~2022~~2023, we are in compliance with all covenants, including financial covenants, in all our debt agreements.

Cash Flow Analysis

Cash Flows from Operating Activities

Net cash provided by operating activities was $41,~~696~~478.20 million for the year ended December 31, ~~2022~~2023 compared to net cash provided by operating activities of $~~292~~4,696.32 million for the year ended December 31, ~~2021~~2022. Our operating cash flows for the year ended December 31, ~~2022~~2023 included our net income of $31,~~708~~803.98 million, ~~and~~depreciation ~~net changes in operating assets~~ and ~~liabilities~~amortization ~~reflecting cash proceeds~~ of $~~291~~551.56 million, ~~primarily~~stock-based ~~driven~~compensation ~~by timing~~ of ~~payments for accrued expense~~$51.5 ~~Change~~million, inpension ~~accrued~~and ~~expenses~~other ispost-retirement ~~due~~benefit ~~primarily~~costs toof an$47.9 ~~increase in renewable energy and emissions obligations~~million, asloss aon ~~result~~extinguishment of andebt ~~increase~~primarily inrelated ~~our~~to ~~unfunded~~the ~~RINs~~redemption ~~obligation as~~ of ~~December~~our ~~31,~~2025 ~~2022.~~Senior ~~Our~~Notes ~~overall~~and ~~increase~~the inamendment ~~cash~~and ~~provided~~restatement byof ~~operating~~the ~~activities~~Revolving ~~also~~Credit ~~included~~Facility ~~depreciation and amortization~~ of $~~495~~5.67 million, ~~loss~~and ondeferred ~~extinguishment~~income oftax ~~debt~~benefit ~~primarily related to the redemption~~ of ~~our 2025 Senior Secured Notes of~~ $663.17 million, partially offset by net change in the fair value of contingent consideration of $4845.18 million, ~~pension~~gain ~~and~~on ~~other~~sale ~~post-retirement~~of ~~benefit~~assets ~~costs~~ of $471.63 million, ~~stock-based~~and ~~compensation~~a ~~of $44.1 million,~~ change in the fair value of our catalyst obligations of $21.01 million. In addition, net changes in operating assets and ~~loss~~liabilities onreflected ~~sale~~uses of ~~assets~~cash of $0938.90 million, ~~partially~~driven ~~offset~~ by ~~net~~inventory ~~non-cash~~purchases ~~charges~~and ~~related~~payments tofor ~~the~~accrued expenses. The change in ~~the~~accrued ~~fair~~expenses ~~value~~was ofdue ~~our~~primarily ~~inventory~~to ~~repurchase~~a ~~obligations~~decrease ofin ~~$5.4~~renewable ~~million~~energy and ~~deferred~~emissions ~~income~~obligations, ~~taxes~~as a result of ~~$3.2~~a ~~million~~decrease in our unfunded RINs obligation.

Our operating cash flows for the year ended December 31, ~~2021~~2022 included our net income of $~~239~~3,708.19 million, ~~depreciation~~ and ~~amortization of $444.3 million,~~ net changes in operating assets and liabilities reflecting cash proceeds of $~~279~~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, ~~2021,~~2022. ~~pension~~Our ~~and~~overall ~~other~~increase ~~post-retirement~~in ~~benefit~~cash ~~costs~~provided ofby ~~$50.8~~operating ~~million,~~activities ~~stock-based~~also ~~compensation~~included ofdepreciation ~~$30.3 million,~~ and ~~change~~amortization ~~in the fair value~~ of ~~contingent consideration of~~ $29495.46 million, ~~partially~~loss ~~offset~~on byextinguishment ~~a non-cash benefit~~ of ~~$669.6~~debt ~~million~~primarily related to anthe ~~LCM~~redemption ~~inventory~~of ~~adjustment,~~our ~~gain~~2025 onSenior ~~extinguishment~~Secured Notes of ~~debt~~$66.1 ~~related~~million, tonet change in the ~~repurchase~~fair value of acontingent ~~portion~~consideration of ~~our~~$48.1 ~~2028~~million, ~~Senior~~pension ~~Notes~~ and ~~2025~~other ~~Senior~~post-retirement ~~Notes~~benefit costs of $7947.96 million, ~~deferred~~stock-based ~~income~~compensation ~~taxes~~ of $1444.51 million, change in the fair value of our catalyst obligations of $82.50 million, ~~net~~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 $85.4 million, and ~~gain~~deferred onincome ~~sale~~taxes of ~~assets of~~ $03.2 million.

Net cash provided by operating activities was $~~292~~4,696.32 million for the year ended December 31, ~~2021~~2022 compared to net cash ~~used~~provided inby operating activities of $~~820~~292.03 million for the year ended December 31, ~~2020~~2021. Our operating cash flows for the year ended December 31, ~~2020~~2021 included our net ~~loss~~income of $239.1 million,~~857~~ depreciation and amortization of $444.53 million, ~~gain~~net onchanges ~~sale~~in ofoperating assets and liabilities reflected cash proceeds of $~~477~~279.85 million ~~mainly~~driven ~~related~~by accrued expenses due to ~~the~~an ~~sale~~increase ofin ~~the~~renewable ~~hydrogen~~energy ~~plants~~credit and ~~the~~emissions ~~sale~~obligations, as a result of ~~land~~an atincrease in our ~~Torrance~~unfunded ~~refinery,~~RIN’s ~~net~~obligations ~~non-cash~~as ~~charges~~of ~~relating~~December 31, to2021, ~~the~~pension ~~change~~and inother ~~the~~post-retirement ~~fair~~benefits ~~value~~costs of ~~our~~$50.8 ~~inventory~~million, ~~repurchase~~stock-based ~~obligations~~compensation of $1230.63 million, and change in the fair value of ~~the~~contingent ~~Martinez~~consideration ~~Contingent Consideration~~ of $7929.34 million, partially offset by ~~depreciation and amortization of $523.8 million,~~ a non-cash ~~charge~~benefit of $~~268~~669.06 million related to an LCM inventory adjustment, ~~impairment~~gain ~~expense~~on extinguishment of ~~$91.8~~debt ~~million,~~related ~~pension~~to ~~and~~the ~~other~~repurchase ~~post-retirement~~of ~~benefits~~a ~~costs~~portion of ~~$55.7~~our ~~million,~~2028 ~~stock-based~~Senior ~~compensation~~Notes and 2025 Senior Notes of $2979.39 million, ~~debt~~deferred ~~extinguishment~~income ~~costs~~taxes ~~related to the early redemption~~ of ~~our 2023 Senior Notes of~~ $2214.25 million, change in the fair value of our catalyst obligations of $~~11.~~8 ~~million and deferred income taxes of $7~~.35 million~~. In addition~~, net ~~changes~~non-cash incharges ~~operating~~related ~~assets~~to ~~and~~the ~~liabilities~~change ~~reflected~~in ~~cash~~the ~~inflows~~fair value of ~~$597.3~~our ~~million~~inventory ~~driven~~repurchase byobligations ~~the timing~~ of ~~inventory~~$8.4 ~~purchases~~million, ~~payments for accrued expenses~~ and ~~accounts~~gain ~~payable~~on ~~and~~sale ~~collections~~of assets of ~~accounts~~$0.2 ~~receivable~~million.

Cash Flows from Investing Activities

Net cash used in investing activities was $1,~~003~~157.03 million for the year ended December 31, ~~2022~~2023 compared to $~~387.~~1,003.0 million for the year ended December 31, ~~2021~~2022. The net cash flows used in investing activities for the year ended December 31, ~~2022~~2023 was comprised of ~~cash outflows of~~ capital expenditures totaling $~~625~~647.47 million, expenditures for refinery turnarounds of $~~311~~473.65 million, and expenditures for other assets of $6640.05 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, ~~2021~~2022 was comprised of ~~cash outflows of~~ capital expenditures totaling $~~240~~625.54 million, expenditures for refinery turnarounds of $~~117~~311.76 million, and expenditures for other assets of $2866.90 million.

Net cash used in investing activities was $~~387.~~1,003.0 million for the year ended December 31, ~~2021~~2022 compared to $~~1,014~~387.21 million for the year ended December 31, ~~2020~~2021. Net cash used in investing activities for the year ended December 31, ~~2020~~2021 was comprised of ~~cash outflows of $1,176.2 million used to fund the Martinez Acquisition,~~ capital expenditures totaling $~~183~~240.95 million, expenditures for refinery turnarounds of $~~188~~117.17 million, and expenditures for other assets of $928.19 million~~, partially offset by proceeds from sale of assets of $543~~.~~1 million.~~

Cash Flows from Financing Activities

Net cash used in financing activities was $~~2,845~~713.08 million for the year ended December 31, ~~2022~~2023 compared to net cash used in financing activities of $~~169~~2,845.60 million for the year ended December 31, ~~2021~~2022. For the year ended December 31, ~~2022~~2023, net cash used in financing activities consisted ofprimarily ~~the redemption~~ of ~~our~~distributions ~~2025~~to ~~Senior~~members ~~Secured Notes~~ of $1,~~307~~583.47 million, ~~net~~redemption ~~repayments on the Revolving Credit Facility~~ of ~~$900.0~~our ~~million,~~2025 ~~distributions~~Senior toNotes ~~members~~ of $~~571~~666.42 million, ~~net~~payments ~~settlements~~related ofto ~~precious~~the ~~metal~~Martinez ~~catalyst~~Contingent ~~obligations~~Consideration of $5680.21 million, deferred financing costs and other costs of $3135.38 million, ~~$25.9~~payments ~~million~~on ~~related~~finance toleases ~~the repurchase~~ of ~~the~~$14.1 ~~principal~~million, ~~amount~~and ~~outstanding~~settlement of the ~~2028~~final ~~Senior~~precious ~~Notes~~metal ~~and~~catalyst ~~the~~obligation ~~2025~~of ~~Senior~~$3.1 ~~Notes~~million, ~~excluding~~partially ~~accrued~~offset ~~interest,~~by ~~and~~contributions ~~payments~~from onPBF ~~finance~~LLC ~~leases~~ of $111,159.36 million, ~~partially~~cash ~~offset by~~ proceeds ~~from~~of ~~contributions~~$496.6 million from ~~PBF~~the ~~LLC~~issuance of ~~$56.4~~the ~~million~~2030 Senior Notes, and proceeds from insurance premium financing of $213.10 million. For the year ended December 31, ~~2021~~2022, net cash used in financing activities consisted of ~~$146.8 million related to~~ the ~~repurchase~~redemption of the ~~principal~~2025 ~~amount~~Senior ~~outstanding~~Secured Notes of ~~the~~$1,307.4 ~~2028~~million, ~~Senior~~net ~~Notes~~repayments ~~and~~on the ~~2025~~Revolving ~~Senior~~Credit ~~Notes~~Facility of $900.0 million, ~~excluding~~distributions ~~accrued~~to ~~interest~~members of $571.4 million, net settlements of precious metal catalyst obligations of $3156.72 million, ~~payments~~deferred onfinancing ~~finance~~costs ~~leases~~and other costs of $1731.83 million, ~~principal~~$25.9 ~~amortization~~million ~~payments~~related onto the ~~$35.0~~repurchase ~~million~~of ~~term~~the ~~loan~~principal (amount outstanding of the ~~“PBF~~2028 ~~Rail~~Senior ~~Term~~Notes ~~Loan”)~~and ofthe ~~$7.4~~2025 ~~million~~Senior Notes, ~~distributions~~excluding toaccrued ~~members~~interest, and payments on finance leases of $311.43 million, partially offset by proceeds from contributions from PBF LLC of $3756.04 million, and ~~deferred~~proceeds ~~financing~~from ~~costs~~insurance ~~and~~premium ~~other~~financing of $02.51 million.

Net cash used in financing activities was $~~169~~2,845.60 million for the year ended December 31, ~~2021~~2022 compared to net cash ~~provided~~used byin financing activities of $~~2,641~~169.26 million for the year ended December 31, ~~2020~~2021. For the year ended December 31, ~~2020~~2021, net cash ~~provided~~used byin financing activities consisted of ~~cash proceeds of~~ $~~1,228~~146.78 million ~~from~~related to the ~~issuance~~repurchase of the ~~2025~~principal ~~Senior~~amount ~~Secured~~outstanding ~~Notes net~~ of ~~related issuance costs, cash proceeds of $469.9 million from~~ the ~~issuance of the~~ 2028 Senior Notes ~~net~~and ~~of cash paid to redeem~~ the ~~2023~~2025 Senior Notes, ~~and~~excluding ~~related~~accrued ~~issuance costs~~interest, ~~proceeds~~net ~~from~~settlements ~~contributions~~of ~~from~~precious ~~PBF~~metal ~~LLC~~catalyst obligations of $4231.47 million, ~~net~~payments ~~borrowings~~on ~~under~~finance ~~our~~leases ~~Revolving Credit Facility~~ of $~~900~~17.08 million, ~~and~~principal ~~proceeds~~amortization ~~from~~payments ~~catalyst~~of ~~financing~~the ~~arrangements~~PBF Rail Term Loan of $517.94 million, ~~partially offset by~~ distributions to members of $233.14 million, ~~net~~partially ~~settlements~~offset ofby ~~precious~~proceeds ~~metal~~from ~~catalyst~~contributions ~~obligations~~from ~~of $8.8 million, principal amortization payments of the~~ PBF ~~Rail~~LLC ~~Term Loan~~ of $737.20 million, ~~payments on finance leases of $12.4 million~~ and deferred financing costs and other of $0.25 million.

Capitalization

Our capital structure was comprised of the following as of December 31, ~~2022~~2023 (in millions):

	December 31, 2022
	December 31, 2023
Debt: (1)
2028 Senior Notes	$	801.6
2025 Senior Notes	664.5
2030 Senior Notes	500.0
Catalyst financing arrangements	4.0
Total debt	1,301.6
Total debt	1,470.1
Unamortized deferred financing costs	(52.5)
Unamortized deferred financing costs	(35.2)
Unamortized discount	(3.2)
Total debt, net of unamortized deferred financing costs and premium	1,434.9
Total debt, net of unamortized deferred financing costs and discount	1,245.9
Total Equity	56,~~617~~161.18
Total Capitalization (2)	$	7,~~052~~407.07

____________________________

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

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

~~2022~~2023 Debt Related Transactions

~~During the year ended December 31, 2022, we exercised our rights under the indenture governing 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.

InOn ~~addition~~September 13, 2023, we ~~made~~exercised ~~a number of open market repurchases of~~ our ~~2028~~rights ~~Senior~~under ~~Notes and 2025 Senior Notes that resulted in~~ the ~~extinguishment~~indenture ofgoverning ~~$24.9 million in principal of~~ the ~~2028~~2025 Senior Notes ~~and~~to ~~$5.0 million~~redeem inall ~~principal~~ of the outstanding 2025 Senior Notes. ~~Total~~at ~~cash~~a ~~consideration~~price ~~paid~~of to100% ~~repurchase~~of the aggregate principal amount ~~outstanding~~thereof, ofplus ~~the~~accrued ~~2028~~and ~~Senior~~unpaid ~~Notes~~interest ~~and~~through the ~~2025~~date ~~Senior~~of ~~Notes,~~redemption. ~~excluding~~The ~~accrued~~aggregate ~~interest,~~redemption ~~totaled~~price ~~$25.9 million~~for ~~and~~all we2025 ~~recognized~~Senior aNotes approximated $3664.85 million ~~gain~~plus onaccrued ~~this~~and ~~extinguishment~~unpaid ~~of debt during the year ended December 31, 2022~~interest.

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.

OnPrecious ~~May~~metal ~~25,~~catalyst 2022, we entered into an amendment of our Revolving Credit Agreement. Among other things, the Revolving Credit Agreement amended and extended the Revolving Credit Facility through January 2025 and increased the maximum commitment to $4.3 billion through May 2023 (currently set to adjust to $2.75 billion in May 2023 through January 2025). The amendments also redefine certain components of the Borrowing Base (as defined in the Revolving credit Agreement) to reflect the existence of the two tranches, Tranche A Commitments and Tranche B Commitments. The Tranche A Commitments total $1.55 billion and the Tranche B Commitments total $2.75 billion. The amendments also include changes to incorporate the adoption of SOFR as a replacement of LIBOR, changes to joint lead arrangers, bookrunners, syndication agents and other titles, and other changes related to the foregoing. In addition, an accordion feature allows for additional Tranche B Commitments of up to an additional $500.0 million plus an amount equal to the Tranche A Commitments for existing Tranche A lenders.obligations

During ~~2022~~2023, we also settled ~~certain~~our ofremaining ~~our~~outstanding precious metals financing ~~arrangements~~arrangement, resulting in a reduction of debt of approximately $563.21 million.

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

~~One of our primary sources of liquidity are borrowings available under our~~ Revolving Credit Facility, ~~which had the following available capacity at December 31, 2022 (in millions):~~Overview

						Total Commitment						Amount Borrowed as of December 31, 2022						Outstanding Letters of Credit						Borrowing Base Availability						Expiration Date
Revolving Credit Facility (a)						$	4,300.0					$	—					$	576.1					$	4,300.0					January 2025

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):


	Total Commitment		Amount Borrowed as of December 31, 2023		Outstanding Letters of Credit		Borrowing Base Availability		Expiration Date
Revolving Credit Facility (a)	$	3,500.0	$	—	$	55.0	$	3,445.0	August 2028

___________________________

(a) The amount available for borrowings and letters of credit under the Revolving Credit Facility is calculated according to a “borrowing base” formula based on (i) 90% of the book value of Eligible Accounts with respect to investment grade obligors plus (ii) 85% of the book value of Eligible Accounts with respect to non-investment grade obligors plus (iii) 80% of the cost of Eligible Hydrocarbon Inventory plus (iv) 100% of Cash and Cash Equivalents in deposit accounts subject to a control agreement, in each case as defined in the Revolving Credit Agreement. The borrowing base is subject to customary reserves and eligibility criteria and in any event cannot exceed $4.3.5 billion.

Additional Information on Indebtedness

Our debt, including our Revolving Credit Facility and senior notes, include certain typical financial covenants and restrictions on our subsidiaries’ ability to, among other things, incur or guarantee new debt, engage in certain business activities including transactions with affiliates and asset sales, make investments or distributions, engage in mergers or pay dividends in certain circumstances. These covenants are subject to a number of important exceptions and qualifications. We are in compliance as of December 31, ~~2022~~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.

Liquidity

As of December 31, ~~2022~~2023, our operational liquidity was more than $4.96 billion (more than $2.4.9 billion as of December 31, ~~2021~~2022), which consists of $2.1.8 billion of cash and more than $2.8 billion of borrowing availability under our Revolving Credit Facility, which includes our cash on hand.

We ~~are~~may ~~actively~~incur ~~monitoring~~additional indebtedness in the ~~ongoing~~future, ~~volatility~~including insecured indebtedness, subject to the ~~global~~satisfaction ~~oil~~of ~~markets~~any debt incurrence and, if applicable, lien incurrence limitation covenants in our existing financing agreements. Although we ~~continue~~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 ~~adjust~~meet ~~our~~these ~~operational~~incurrence ~~plans~~covenants at the time that we needed to. Failure to meet the ~~evolving~~incurrence ~~market~~covenants ~~conditions~~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.

We may, at any time and from time to time, seek to continue to repurchase or retire our outstanding debt securities through cash purchases (and/or exchanges for equity or debt), in open-market purchases, block trades, privately negotiated transactions or otherwise, upon such terms and at such prices as we may determine. We will evaluate any such transactions in light of then-existing market conditions, taking into account our current liquidity and prospects for future access to capital, the trading prices of our debt securities, legal requirements and contractual restrictions and economic and market conditions. The amounts involved in any such transactions, individually or in the aggregate, may be material. We are not obligated to repurchase any of our debt securities other than as set forth in the applicable indentures, and repurchases may be made or suspended or discontinued at any time without prior notice.

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, 2022, to the extent that any of our activities triggered these covenants, there are no assurances that conditions could not change significantly, and that such changes could adversely impact our ability to meet some of 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 make new investments, repurchase our outstanding debt or incur new liens.

Working Capital

~~Working~~Our working capital at December 31, ~~2022~~2023 was approximately $12,~~715~~184.30 million, consisting of $6,~~494~~480.53 million in total current assets and $4,~~779~~296.23 million in total current liabilities. ~~Working~~Our working capital at December 31, ~~2021~~2022 was $1,~~266~~715.53 million, consisting of $56,~~158~~494.65 million in total current assets and $34,~~892~~779.12 million in total current liabilities.

Crude and Feedstock Supply Agreements

~~Certain~~We ofcurrently ~~our~~purchase ~~purchases~~all of ~~crude oil under~~ our ~~agreements~~crude ~~with~~and ~~foreign~~feedstock ~~national~~needs ~~oil~~from ~~companies~~various ~~require that we post letters of credit~~suppliers, ifprimarily ~~open~~through ~~terms~~short-term ~~are exceeded,~~ and ~~arrange~~spot ~~for~~market ~~shipment~~agreements. We ~~pay~~also ~~for~~have ~~the~~a crude ~~when~~supply ~~invoiced,~~agreement atwith ~~which~~Saudi ~~time~~Aramco, ~~any~~the ~~applicable~~term ~~letters~~ of ~~credit~~which ~~are~~is ~~lifted.~~currently Weyear ~~have a contract with Saudi Aramco pursuant~~ to ~~which~~year, wefor ~~have been purchasing~~ up to approximately 100,000 bpd ~~of crude oil from Saudi Aramco~~ that is processed at ~~our~~the Paulsboro refinery. Inand ~~connection~~crude ~~with~~supply ~~the~~agreements ~~acquisition~~with ofShell ~~the~~Trading ~~Chalmette~~(US) ~~refinery~~Company we(primarily ~~entered~~serving ~~into~~our aMartinez ~~contract~~refinery) ~~with PDVSA~~ for ~~the~~up ~~supply~~to ofapproximately 4095,000 tobpd, 60which,~~000~~ ~~bpd~~upon ofexpiration ~~crude oil that can be processed at any~~ of ~~our~~one East or Gulf Coast refineries. We have not sourced crude oil under this agreement since 2017 when PDVSA suspended deliveries due to the parties’ inability to agree to mutually acceptable payment terms and because of ~~U.S. government sanctions against PDVSA. Notwithstanding~~ the ~~suspension,~~agreements ~~the~~in U.early ~~S. government sanctions imposed against PDVSA and Venezuela prevented us from purchasing crude oil under this agreement. In connection with the closing of the acquisition of the Torrance refinery~~2024, wewill ~~entered~~be ~~into~~reduced ato ~~crude~~up ~~supply~~to ~~agreement with ExxonMobil for~~ approximately 6065,000 bpd, ~~of crude oil that can be processed at our Torrance refinery. We currently purchase all of our crude and feedstock needs independently from a variety of suppliers on the spot market or~~ through ~~term~~early ~~agreements for our Delaware City and Toledo refineries~~2025.

We currently have various crude supply agreements with terms through 2025 with Shell Oil Products for approximately 145,000 bpd, in the aggregate, to support our West Coast and Mid-Continent refinery operations. In addition, we have certain offtake agreements for our West Coast system with the same counterparty for clean products with varying terms up to 15 years.

Inventory Intermediation Agreement

On ~~October~~July 2531, ~~2021~~2023, we ~~and~~early ~~the~~terminated ~~PBF Entities, entered into~~ the Third Inventory Intermediation Agreement with J. Aron,. ~~pursuant~~In toconjunction ~~which~~with the ~~terms~~early ~~of the previous inventory intermediation agreements were amended and restated in their entirety~~termination, ~~including,~~we ~~among~~made ~~other~~an ~~things~~aggregate ~~pricing~~settlement ~~and~~payment ~~an extension~~ of ~~terms~~$268.0 ~~The~~million ~~Third~~for ~~Inventory Intermediation Agreement extends~~ the ~~term~~inventory topreviously ~~December~~held ~~31, 2024, which term may be further extended~~ by ~~mutual consent of the parties to December 31, 2025~~J. ~~If not extended or replaced~~Aron, atinclusive ~~expiration,~~of ~~we will be required to repurchase the inventories outstanding under the Third Inventory Intermediation Agreement at that time~~$13.5 Onmillion ~~May 25, 2022, the PBF Entities entered into an amendment~~ of ~~the Third Inventory Intermediation Agreement to amend certain provisions thereof that~~ related tocosts ~~and~~associated ~~were~~with ~~impacted~~exiting ~~by amendments made on May 25, 2022 to~~ the ~~Revolving Credit Agreement~~agreement. ~~We intend to either extend or replace the Third Inventory Intermediation Agreement prior to its expiration.~~

At December 31, 2022, the LIFO value of the J. Aron Products included within Inventories in our Consolidated Balance Sheets was $181.8 million. We accrue a corresponding liability for such crude oil, intermediates and finished products.

Capital Spending

Capital spending was $1,~~003~~161.07 million for the year ended December 31, ~~2022~~2023 and was primarily comprised of annual maintenance and turnaround costs at our Delaware City, Toledo, Chalmette, Torrance and Martinez refineries inand ~~addition to~~ spending related to ~~our~~the ~~Renewable~~construction ~~Diesel~~of ~~Project~~the ~~for~~Renewable aDiesel ~~renewable~~Facility ~~fuels production facility~~ co-located atwith our Chalmette refinery of approximately $312.7 million. Capital spending also included costs associated with safety related enhancements and facility improvements at our refineries. ~~Excluding~~We ~~capital expenditures related to our Renewable Diesel Project, we~~ currently expect to spend an aggregate of approximately $~~700~~800.0 million to $~~750~~850.0 million ~~during~~in ~~2023~~2024 for facility improvements and refinery maintenance and turnarounds, as well as expenditures to meet environmental, regulatory and safety requirements.

During the fourth quarter of 2022, we invested approximately $140 million in capital related to our Renewable Diesel Project. We currently anticipate remaining capital expenditures to complete the project to range from $200.0 million to $250.0 million in 2023 with the goal of commencing production in the first half of 2023.

Material Cash Requirements

Our material cash requirements include the following known contractual and other obligations as of December 31, ~~2022~~2023 that are expected to be paid within the next year and thereafter (in millions).

	Payments Due by Period
	Short-Term		Long-Term		Total
Credit facilities and debt (a)	$	~~4.0~~—	$	1,~~466~~301.16	$	1,~~470~~301.16
Interest payments on credit facilities and debt	9791.28		~~295~~409.48		~~392~~501.6
Leases and other rental-related commitments (b)	~~411~~515.14		2,~~331~~212.04		2,~~742~~727.18
Purchase obligations (c)	95,~~006~~840.38		~~8,300~~624.56		176,~~306~~465.84
Minimum volume commitments with PBFX (d)	~~100~~110.26		~~186~~102.75		~~286~~213.91
Construction obligations	~~166~~143.05		—		~~166~~143.05
Environmental obligations (e)	1315.93		149.05		~~162~~164.98
Pension and post-retirement obligations (f)	2632.50		~~300~~365.41		~~326~~397.91
Martinez Contingent Consideration (g)	100.0		73.7		173.7
Total material cash requirements	$	6,749.4	$	5,165.5	$	11,914.9
Total material cash requirements	$	9,925.2	$	13,102.8	$	23,028.0

8180

(a) Credit facilities and debt

Credit facilities and debt represent ~~(i)~~ the repayment of indebtedness incurred in connection with the ~~2025~~2030 Senior Notes and 2028 Senior Notes; ~~and (ii) the repayment of our catalyst financing obligations on their maturity dates. With the exception of our catalyst financing obligations,~~ we have no debt maturing before ~~2024~~2025.

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

(b) Leases and other rental-related commitments

~~Operating~~Third Party and ~~Finance~~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 1211 - 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. Additionally, we have obligations to repurchase the J. Aron Products under the Third Inventory Intermediation Agreement with J. Aron as further explained in “Note 2 - Summary of Significant Accounting Policies”, “Note 4 - Inventories” and “Note 7 - Accrued Expenses” of our Notes to Consolidated Financial Statements.

The amounts included in this table exclude our crude supply agreement with PDVSA. We have not sourced crude oil under this agreement since the third quarter of 2017 as PDVSA has suspended deliveries due to the parties inability to agree to mutually acceptable payment terms and because of U.S. government sanctions against PDVSA.

(d) Minimum volume commitments with PBFX

We have minimum obligations under our commercial agreements entered into with PBFX. Refer to “Note 109 - Related Party Transactions” and “Note 1110 - 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.

(e) Environmental obligations

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 1110 - Commitments and Contingencies” of our Notes to Consolidated Financial Statements.

(f) Pension and post-retirement obligations

Pension and post-retirement obligations include only those amounts we expect to pay out in benefit payments and are further explained in “Note 1514 - Employee Benefit Plans” of our Notes to Consolidated Financial Statements.

~~(g) Martinez Contingent Consideration~~ 81

Contingent consideration includes our obligations to pay certain contractual earn-outs entered into as part of the acquisition. Our earn-out obligation related to the Martinez Acquisition includes the estimated undiscounted contingent consideration amounts payable to Shell Oil Products related to annual refinery earnings in 2022 and 2023.

Critical Accounting Policies

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

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, ~~2022~~2023 and December 31, ~~2021~~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, weit ~~have had limited prior exposure to certain of these environmental obligations due to our short operating history with certain of our assets. It~~ is possible that our estimates of the costs and duration of the environmental remediation activities related to these liabilities could materially change.

~~Business Combinations~~82

We use the acquisition method of accounting for the recognition of assets acquired and liabilities assumed in business combinations at their estimated fair values as of the date of acquisition. Any excess consideration transferred over the estimated fair values of the identifiable net assets acquired is recorded as goodwill. Significant judgment is required in estimating the fair value of assets acquired. As a result, in the case of significant acquisitions, we obtain the assistance of third-party valuation specialists in estimating fair values of tangible and intangible assets based on available historical information and on expectations and assumptions about the future, considering the perspective of marketplace participants. While management believes those expectations and assumptions are reasonable, they are inherently uncertain. Unanticipated market or macroeconomic events and circumstances may occur, which could affect the accuracy or validity of the estimates and assumptions.

Certain of our acquisitions may include earn-out provisions or other forms of contingent consideration. As of the acquisition date, we record contingent consideration, as applicable, at the estimated fair value of expected future payments associated with the earn-out. Any changes to the recorded fair value of contingent consideration, subsequent to the measurement period, will be recognized as earnings in the period in which it occurs. Such contingent consideration liabilities are based on best estimates of future expected payment obligations, which are subject to change due to many factors outside of our control. Changes to the estimate of expected future contingent consideration payments may occur, from time to time, due to various reasons, including actual results differing from estimates and adjustments to the revenue or earnings assumptions used as the basis for the liability based on historical experience. While we believe that our current estimate of the fair value of our contingent consideration liability is reasonable, it is possible that the actual future settlement of our earn-out obligations could materially differ.

Deferred Turnaround Costs

Refinery turnaround costs, which are incurred in connection with planned major maintenance activities at our refineries, are capitalized when incurred and amortized on a straight-line basis over the period of time estimated until the next turnaround occurs (generally three to six years). While we believe that the estimates of time until the next turnaround are reasonable, it should be noted that factors such as competition, regulation or environmental matters could cause us to change our estimates thus impacting amortization expense in the future.

Derivative Instruments

We are exposed to market risk, primarily related to changes in commodity prices for the crude oil and feedstocks used in the refining process, as well as the prices of the refined products sold and the risk associated with the price of credits needed to comply with various governmental and regulatory environmental compliance programs. The accounting treatment for commodity and environmental compliance contracts depends on the intended use of the particular contract and on whether or not the contract meets the definition of a derivative. Non-derivative contracts are recorded at the time of delivery.

All derivative instruments that are not designated as normal purchases or sales are recorded in our Consolidated Balance Sheets as either assets or liabilities measured at their fair values. Changes in the fair value of derivative instruments that either are not designated or do not qualify for hedge accounting treatment or normal purchase or normal sale accounting are recognized in income. Contracts qualifying for the normal purchases and sales exemption are accounted for upon settlement. We elect fair value hedge accounting for certain derivatives associated with our inventory repurchase obligations.

Derivative accounting is complex and requires management judgment in the following respects: identification of derivatives and embedded derivatives; determination of the fair value of derivatives; identification of hedge relationships; assessment and measurement of hedge ineffectiveness; and election and designation of the normal purchases and sales exemption. All of these judgments, depending upon their timing and effect, can have a significant impact on earnings.

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.

Recent Accounting Pronouncements

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

8583

Supplemental Guarantor Financial Information

As of December 31, ~~2022~~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 ~~2025~~2028 Senior Notes and ~~2028~~2030 Senior Notes. These guarantees are full and unconditional and joint and several. PBF Holding serves as the “Issuer”. The indentures dated ~~May~~January 3024, ~~2017~~2020 and ~~January~~August 2421, ~~2020,~~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 ~~2025~~2028 Senior Notes and ~~2028~~2030 Senior Notes. The ~~2025~~2028 Senior Notes and ~~2028~~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.

Summarized Balance Sheets (in millions)	December 31, ~~2022~~2023		December 31, ~~2021~~2022
ASSETS
Current Assets (1)	$	6,~~252~~263.0	$	46,~~840~~252.0
Non-Current Assets	6,~~283~~074.0		56,~~754~~283.0
Due from non-guarantor subsidiaries	1921,~~487~~756.08		1619,~~211~~487.0
LIABILITIES AND EQUITY
Current liabilities (1)	$	4,~~569~~078.01	$	34,~~645~~569.0
Long-term liabilities	2,~~634~~342.08		42,~~862~~634.0
Due to non-guarantor subsidiaries	1921,~~394~~692.06		1619,~~100~~394.0
(1) Includes $6.3 million and $38.2 million of accounts receivables and accounts payables, respectively, related to transactions with PBFX as of December 31, 2022. Includes $4.1 million and $61.7 million of accounts receivables and accounts payables, respectively, related to transactions with PBFX as of December 31, 2021. Refer to “Note 10 - Related Party Transactions” of the Notes to Consolidated Financial Statements for further disclosures.
(1) Includes $27.3 million and $72.0 million of accounts receivables and accounts payables, respectively, related to transactions with PBFX as of December 31, 2023. Includes $6.3 million and $38.2 million of accounts receivables and accounts payables, respectively, related to transactions with PBFX as of December 31, 2022. Refer to “Note 9 - Related Party Transactions” of the Notes to Consolidated Financial Statements for further disclosures.

8684

Summarized Statements of Operations (in millions)

December 31, ~~2022~~2023

December 31, ~~2021~~2022

Revenues

4637,~~402~~921.41

2646,~~836~~402.94

Cost of sales

3833,~~788~~590.03

2338,~~940~~788.0

Gross margin

74,~~614~~330.48

27,~~896~~614.94

Income from operations

74,~~118~~015.79

27,~~631~~118.57

Net income

63,~~832~~952.04

26,~~400~~832.20

Net income attributable to PBF Holding Company LLC

63,~~833~~951.45

26,~~397~~833.94

Non-guarantor intercompany sales with the Issuer and Guarantor subsidiaries

32,~~218~~189.61

23,~~237~~128.86

Non-guarantor intercompany cost of sales with the Issuer and Guarantor subsidiaries

9540.7

7695.7

Affiliate revenues related to transactions with PBFX (1)

1716.06

1617.0

Affiliate expenses related to transactions with PBFX (1)

~~319~~347.68

~~304~~319.16

(1) Refer to “Note 10 - Related Party Transactions” of our Notes to Condensed Consolidated Financial Statements for further information.

(1) Refer to “Note 9 - Related Party Transactions” of our Notes to Condensed Consolidated Financial Statements for further information.

8785

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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.

Commodity Price Risk

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, ~~2022~~2023 and December 31, ~~2021~~2022, we had gross open commodity derivative contracts representing 3029.1 million barrels and 4230.1 million barrels, respectively, with an unrealized net gain of $1333.92 million and ~~unrealized net loss of~~ $1213.09 million, respectively. The open commodity derivative contracts as of December 31, ~~2022~~2023 expire at various times during ~~2023~~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 3236.82 million barrels and 3032.28 million barrels at December 31, ~~2022~~2023 and December 31, ~~2021~~2022, respectively. The average cost of our hydrocarbon inventories was approximately $8083.0464 and $7880.2904 per barrel on a LIFO basis at December 31, ~~2022~~2023 and December 31, ~~2021~~2022, respectively. At December 31, ~~2022~~2023 and December 31, ~~2021~~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 ~~annually~~expect ~~consume~~our aannual ~~total~~consumption ofto ~~between~~range from 75 million ~~and~~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.

8886

Compliance Program Price Risk

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 ~~includes~~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 ~~greenhouse~~GHG ~~gas~~ 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.

Certain of these compliance contracts or instruments qualify as derivative instruments. For certain of these contracts, we elect the normal purchase normal sale exception under Accounting Standards Codification 815, Derivatives and Hedging, for such instruments, and therefore do not record these contracts at their fair value.

Interest Rate Risk

The maximum commitment under our Revolving Credit Facility is $4.3.5 billion. Borrowings under the Revolving Credit Facility bear interest either at the Alternative Base Rate plus the Applicable Margin or at the Term SOFR ~~Rate~~ plus the Applicable Margin, all as defined in the Revolving Credit Agreement. At December 31, ~~2022~~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 $2523.67 million annually.

We also have interest rate exposure in connection with our Third Inventory Intermediation Agreement under which we pay a time value of money charge based on LIBOR.

Credit Risk

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.

Concentration Risk

For the years ended December 31, ~~2022~~2023 and December 31, ~~2021~~2022, only one customer, Shell, accounted for 10% or more of our revenues (approximately 14% and 1514%, respectively).

As of December 31, ~~2022~~2023 and December 31, ~~2021~~2022, only one customer, Shell, accounted for 10% or more of our total trade accounts receivable (approximately 19% and 2619%, respectively).

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by this item is set forth beginning on page F-1 of this Annual Report on Form 10-K.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

8987

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We conducted evaluations, under the supervision and with the participation of our management, including the principal executive officer and principal financial ~~officers~~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 ~~officers~~officer concluded that the disclosure controls and procedures are effective.

Management’s Report on Internal Control over Financial Reporting

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, ~~2022~~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, ~~2022~~2023, ~~the~~our ~~Company’s~~ 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.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the quarter ended December 31, ~~2022~~2023 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

ITEM 9C. DISCLOSURES REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

9088

PART III

Explanatory Note:

We are a limited liability company wholly-owned and controlled by PBF LLC. PBF Energy is the sole managing member of PBF LLC. Our directors and executive officers are the executive officers of PBF Energy. The compensation paid to these executive officers is for services provided to both entities (i.e., they are not separately compensated for their services as an officer or director of PBF Holding). PBF Holding does not file a proxy statement. If the information were required it would be identical (other than as expressly set forth below) to the information contained in Items 10, 11, 12, 13 and 14 of the Annual Report on Form 10-K of PBF Energy that will appear in the Proxy Statement of PBF Energy furnished to its stockholders in connection with its ~~2023~~2024 Annual Meeting. Such information is incorporated by reference in this Annual Report on Form 10-K.

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information About Our Directors and Executive Officers

The following is a list of our directors and executive officers as of March 31, ~~2023~~2024:

Name

Age (as of December 31, ~~2022~~2023)

Position

Thomas J. Nimbley

Chief Executive Officer

Thomas Nimbley

Executive Chairman, Chairman of the Board

Matthew C. Lucey

President

Matthew Lucey

President, Chief Executive Officer

Karen B. Davis

6667

Senior Vice President, Chief Financial Officer

Paul Davis

6061

Senior Vice President, Supply, Trading and Optimization

Thomas O’Connor

5051

Senior Vice President, Commodity Risk and Strategy

Trecia Canty

5354

Senior Vice President, General Counsel & Corporate Secretary

Steven Steach

6667

Senior Vice President, Refining

Wendy Ho Tai

5657

Senior Vice President, Human Resources

Jim Fedena

5859

Senior Vice President, Logistics, Renewable Fuels, and Strategic Assets

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.

Thomas J. Nimbley has served as ~~our~~Chairman of the Board since June 30, 2016 and Executive Chairman since July 2023. He served as PBF Energy’s Chief Executive Officer ~~since~~from June 2010 through June 2023 and was Executive Vice President, Chief Operating Officer from ~~March~~April 2010 through June 2010. ~~In his capacity as our Chief Executive Officer,~~ Mr. Nimbley also serves as a director and the ~~Chief~~ Executive ~~Officer~~Chairman of certain of our subsidiaries and our affiliates~~, including PBFX GP~~. Prior to joining us, Mr. Nimbley served as a Principal for Nimbley Consultants LLC from June 2005 to March 2010, where he provided consulting services and assisted on the acquisition of two refineries. He previously served as Senior Vice President and head of Refining for Phillips Petroleum Company (“Phillips”) and, subsequently, Senior Vice President and head of Refining for ConocoPhillips’ (“ConocoPhillips”) domestic refining system (13 locations) following the merger of Phillips and Conoco Inc. Before joining Phillips at the time of its acquisition of Tosco Corporation (“Tosco”) in September 2001, Mr. Nimbley served in various positions with Tosco and its subsidiaries starting in April 1993.

9189

Matthew C. Lucey has served as our and PBF Energy’s President since January 2015 and Chief Executive Officer since July 2023. Mr. Lucey is also a director and the Chief Executive Officer of certain of our subsidiaries. Mr. Lucey was our Executive Vice President from April 2014 to December 2014. ~~Mr.~~and ~~Lucey~~ served as our Senior Vice President, Chief Financial Officer from April 2010 to March 2014. Mr. Lucey joined us as our Vice President, Finance in April 2008. ~~Mr. Lucey is also a director of certain of PBF Energy’s subsidiaries, including PBFX GP.~~ Prior thereto, Mr. Lucey served as a Managing Director of M.E. Zukerman & Co., a New York-based private equity firm specializing in several sectors of the broader energy industry, from 2001 to 2008. Before joining M.E. Zukerman & Co., Mr. Lucey spent six years in the banking industry.

Karen B. Davis has served as our Senior Vice President, Chief Financial Officer since February 20, 2023 and has been serving as our Principal Accounting Officer since May 11, 2023. She served as interim Chief Financial Officer from January 1, 2023 to February 19, 2023. Ms. Davis is also a director of certain of our subsidiaries. Ms. Davis previously served as Executive Vice President and Chief Financial Officer of Western Refining, Inc. and its affiliated entities, Western Refining Logistics LP and Northern Tier Energy, LP through May 2017. During her career, she has served in various chief financial officer and financial reporting officer positions with various public and private companies throughout the United States. Ms. Davis served as an independent director of PBF Energy from January 1, 2020 to December 31, 2022 and the Chairperson of the Audit Committee from October 1, 2020 to December 31, 2022. From 2017 through 2019, she served as an independent director of PBFX GP, where she was a member of the Audit and the Conflicts Committees.

Paul Davis has served as our Senior Vice President, Supply, Trading and Optimization since April 2022. He previously served as PBF Energy’s President, PBF Western Region from September 2017 to April 2022. Mr. Davis joined us in April 2012 and held various executive roles in our commercial operations, including Co-Head of Commercial, prior to serving as Senior Vice President, Western Region Commercial Operations from September 2015 to September 2017. Previously, Mr. Davis was responsible for managing the U.S. clean products commercial operations for Hess Energy Trading Company from 2006 to 2012. Prior to that, Mr. Davis was responsible for Premcor’s U.S. Midwest clean products disposition group. Mr. Davis has over 29 years of experience in commercial operations in crude oil and refined products, including 16 years with the ExxonMobil in various operational and commercial positions, including sourcing refinery feedstocks and crude oil and the disposition of refined products, as well as optimization roles within refineries.

Thomas O’Connor has served as our and PBF Energy Senior Vice President, Commodity Risk and Strategy since April 2022. He previously served as PBF Energy Senior Vice President, Commercial from September 2015 to April 2022. Mr. O’Connor joined us and PBF Energy as Senior Vice President in September 2014 with responsibility for business development and growing the business of PBFX, and from January to September 2015, served as our Co-Head of commercial activities. Prior to joining us, Mr. O’Connor worked at Morgan Stanley since 2000 in various positions, most recently as a Managing Director and Global Head of Crude Oil Trading and Global Co-Head of Oil Flow Trading. Prior to joining Morgan Stanley, Mr. O’Connor worked for Tosco from 1995 to 2000 in the Atlantic Basin Fuel Oil and Feedstocks group.

Trecia Canty has served as our Senior Vice President, General Counsel and Corporate Secretary since September 2015. In her role, Ms. Canty is responsible for the legal department and outside counsel, which provide a broad range of support for the Company’s business activities, including corporate governance, compliance, litigations and mergers and acquisitions. Previously, Ms. Canty was named Vice President, Senior Deputy General Counsel and Assistant Secretary in October 2014 and led our commercial and finance legal operations since joining us in November 2012. Ms. Canty is also a director of certain of PBF Energy’s subsidiaries. Prior to joining us, Ms. Canty served as Associate General Counsel, Corporate and Assistant Secretary of Southwestern Energy Company, where her responsibilities included finance and mergers and acquisitions, securities and corporate compliance and corporate governance. She also provided legal support to the midstream marketing and logistics businesses. Prior to joining Southwestern Energy Company in 2004, she was an associate with Cleary, Gottlieb, Steen & Hamilton.

9290

Steven Steach has served as our Senior Vice President, Refining since February 1, 2022 and has responsibility for our refining operations. He originally joined us in November 2015 in advance of the acquisition of the Torrance refinery and served as the Vice President and Refinery Manager of the Torrance refinery from its acquisition on July 1, 2016 until January 31, 2022. Before joining PBF, Mr. Steach was Refinery Manager for ConocoPhillips in Billings, MT, for four years. Prior to Billings, Mr. Steach was Operations Manager for ConocoPhillips at their Los Angeles ~~Refinery~~refinery for a total of nine years, including Site Manager at the Carson plant.

Wendy Ho Tai has served as our Senior Vice President, Human Resources since April 2022. She previously served as Vice President, Human Resources from March 2015 to April 2022 and as Senior Director, Compensation and Benefits from October 2010 to February 2015. In her tenure, Ms. Ho Tai has established the PBF benefit plans, implemented the HR information system and assisted in the integration of the employees of all acquisitions. Previously, Ms. Ho Tai held human resources management positions with Petro, Inc. and MarketSmart Interactive.

Jim Fedena has served as our Senior Vice President, Logistics, Renewable Fuels, and Strategic Assets since April 2022. He previously served as a Senior Vice President of Health, Safety and Environment from June 2010 to January 2013. From June 2010 through February 2011, he also served as the Delaware City refinery Manager during the reactivation period and, from January 2013 to April 2022, he served as Senior Vice President – Logistics~~, including for PBFX~~. Prior to joining PBF Energy he served as managing partner for PJF Associates providing consulting services for private equity firms on refining acquisitions in North America and Europe. Mr. Fedena has over 30 years of oil industry experience in refining, pipelines, and terminal operations. He also served in various positions with Premcor, ConocoPhillips, Phillips, Tosco and Coastal with responsibility for health, safety and environmental programs.

Corporate Governance Matters

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 ~~2023~~2024 Proxy Statement, incorporated herein by reference.

9391

ITEM 11. EXECUTIVE COMPENSATION

Compensation of Directors of PBF Holding Company LLC

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 ~~2023~~2024 Proxy Statement, incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

As of December 31, ~~2022~~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 1312 - 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 ~~2023~~2024 Proxy Statement, which is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Refer to “Note 109 - Related Party Transactions” of our Notes to Consolidated Financial Statements.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Deloitte & Touche LLP (PCAOB ID No. 34) (“Deloitte”) is our independent registered public accounting firm for the years ended December 31, 2023 and 2022. Our audit fees are determined as part of the overall audit fees for PBF Energy and are approved by the audit committee of the board of directors of PBF Energy. PBF Energy reports separately on the fees and services of its principal accountants. For additional information, we refer you to PBF Energy’s ~~2023~~2024 Proxy Statement, which is incorporated herein by reference.

The following table presents fees incurred for the years ended December 31, ~~2022~~2023 and ~~2021~~2022 for professional services performed by Deloitte.

(in thousands)	~~2022~~2023		~~2021~~2022
Audit Fees (1)	$	4,~~122~~494.0	$	34,~~918~~122.10
Audit-related Fees (2)	~~115~~155.0		40115.0
Tax Fees (3)	~~110~~307.41		57110.84
Total Fees	$	4,~~347~~956.41	$	4,~~015~~347.94
(1) Represents the aggregate fees for professional services rendered by Deloitte in connection with its audits of PBF Holding and its indirect parent, PBF Energy’s consolidated financial statements, including the audits of internal control over financial reporting of PBF Energy and related accounting consultation services provided to support the performance of such audits. Fees, and related expenses, are for services performed in connection with the audit of our fiscal years ended December 31, 2022 and 2021 financial statements regardless of when incurred.
(1) Represents the aggregate fees for professional services rendered by Deloitte in connection with its audits of PBF Holding and its indirect parent, PBF Energy’s consolidated financial statements, including the audits of internal control over financial reporting of PBF Energy and related accounting consultation services provided to support the performance of such audits. Fees, and related expenses, are for services performed in connection with the audit of our fiscal years ended December 31, 2023 and 2022 financial statements regardless of when incurred.
(2) Represents fees for professional services rendered in connection with various filings for PBF Holding and its indirect parent, PBF Energy, including (i) services rendered in connection with the filing of registration statements with the SEC and (ii) attestation services performed in connection with certain regulatory filings.
(3) Represents fees associated with tax services rendered for income tax planning and sales, use and excise tax matters.

9492

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

1. Financial Statements. The consolidated financial statements of PBF Holding Company LLC and subsidiaries, required by Part II, Item 8, are included in Part IV of this report. See Index to Consolidated Financial Statements beginning on page F-1.

2. Financial Statement Schedules and Other Financial Information. No financial statement schedules are submitted because either they are not applicable or because the required information is included in the consolidated financial statements or notes thereto.

3. Exhibits. Filed as part of this Annual Report on Form 10-K are the following exhibits:

Number	~~Description~~	Description
3.1	Certificate of Formation of PBF Holding Company LLC (Incorporated by reference to Exhibit 3.1 filed with PBF Holding Company LLC’s Registration Statement on Form S-4 dated January 14, 2013 (Registration No. 333-186007)).	Certificate of Formation of PBF Holding Company LLC (Incorporated by reference to Exhibit 3.1 filed with PBF Holding Company LLC’s Registration Statement on Form S-4 dated January 14, 2013 (Registration No. 333-186007)).
3.2	Limited Liability Company Agreement of PBF Holding Company LLC (Incorporated by reference to Exhibit 3.2 filed with PBF Holding Company LLC’s Registration Statement on Form S-4 (Registration No. 333-186007)).	Limited Liability Company Agreement of PBF Holding Company LLC (Incorporated by reference to Exhibit 3.2 filed with PBF Holding Company LLC’s Registration Statement on Form S-4 (Registration No. 333-186007)).
3.3	Certificate of Incorporation of PBF Finance Corporation (Incorporated by reference to Exhibit 3.3 filed with PBF Holding Company LLC’s Registration Statement on Form S-4 (Registration No. 333-186007)).	Certificate of Incorporation of PBF Finance Corporation (Incorporated by reference to Exhibit 3.3 filed with PBF Holding Company LLC’s Registration Statement on Form S-4 (Registration No. 333-186007)).
3.4	~~Bylaws of PBF Finance Corporation (Incorporated by reference to Exhibit 3.4 filed with PBF Holding Company LLC’s Registration Statement on Form S-4 (Registration No. 333-186007)).~~	Bylaws of PBF Finance Corporation (Incorporated by reference to Exhibit 3.4 filed with PBF Holding Company LLC’s Registration Statement on Form S-4 (Registration No. 333-186007)).
4.1	Indenture dated as of May 30, 2017, among PBF Holding Company LLC, PBF Finance Corporation, the Guarantors named on the signature pages thereto, Wilmington Trust, National Association, as Trustee and Deutsche Bank Trust Company Americas, as Paying Agent, Registrar, Transfer Agent and Authenticating Agent and form of 7.25% Senior Note (included as Exhibit A) (incorporated by reference to Exhibit 4.1 of PBF Energy Inc’s Current Report on Form 8-K (File No. 001-35764) filed on May 30, 2017).	Indenture dated as of January 24, 2020, among PBF Holding Company LLC, PBF Finance Corporation, the Guarantors named on the signature pages thereto, Wilmington Trust, National Association, as Trustee and Deutsche Bank Trust Company Americas, as Paying Agent, Registrar, Transfer Agent and Authenticating Agent and form of 6.00% Senior Notes due 2028 (included as Exhibit A) (incorporated by reference to Exhibit 4.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated January 24, 2020 (File No. 001-35764)).
4.2	Indenture dated as of January 24, 2020, among PBF Holding Company LLC, PBF Finance Corporation, the Guarantors named on the signature pages thereto, Wilmington Trust, National Association, as Trustee and Deutsche Bank Trust Company Americas, as Paying Agent, Registrar, Transfer Agent and Authenticating Agent and form of 6.00% Senior Notes due 2028 (included as Exhibit A) (incorporated by reference to Exhibit 4.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated January 24, 2020 (File No. 001-35764)).	Indenture dated as of August 21, 2023, among PBF Holding Company LLC, PBF Finance Corporation, the Guarantors named on the signature pages thereto, Wilmington Trust, National Association, as Trustee, and Deutsche Bank Trust Company Americas, as Paying Agent, Registrar, Transfer Agent and Authenticating Agent and form of 7.875% Senior Note due 2030 (included as Exhibit A) (incorporated by reference to Exhibit 4.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated August 21, 2023 (File No. 001-35764)).
4.3	First Supplemental Indenture dated February 3, 2020, among PBF Holding Company LLC, PBF Finance Corporation, Martinez Refining Company LLC, Martinez Terminal Company LLC, Wilmington Trust, National Association, as trustee, and Deutsche Bank Trust Company Americas, as paying agent, transfer agent, registrar and authenticating agent (6.00% Senior Notes due 2028) (incorporated by reference to Exhibit 4.3 filed with PBF Energy Inc.’s Quarterly Report on Form 10-Q dated May 15, 2020 (File No. 001-35764).	First Supplemental Indenture dated February 3, 2020, among PBF Holding Company LLC, PBF Finance Corporation, Martinez Refining Company LLC, Martinez Terminal Company LLC, Wilmington Trust, National Association, as trustee, and Deutsche Bank Trust Company Americas, as paying agent, transfer agent, registrar and authenticating agent (6.00% Senior Notes due 2028) (incorporated by reference to Exhibit 4.3 filed with PBF Energy Inc.’s Quarterly Report on Form 10-Q dated May 15, 2020 (File No. 001-35764).
4.4	First Supplemental Indenture dated February 3, 2020, among PBF Holding Company LLC, PBF Finance Corporation, Martinez Refining Company LLC, Martinez Terminal Company LLC, Wilmington Trust, National Association, as trustee, and Deutsche Bank Trust Company Americas, as paying agent, transfer agent, registrar and authenticating agent (7.25% Senior Notes due 2025) (incorporated by reference to Exhibit 4.4 filed with PBF Energy Inc.’s Quarterly Report on Form 10-Q dated May 15, 2020 (File No. 001-35764).
10.1**		Form of 2023-2025 Performance Share Unit Agreement (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated April 12, 2022 (File No. 001-35764)).
10.1**	Form of 2023-2025 Performance Share Unit Agreement (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated April 12, 2022 (File No. 001-35764)).
10.2**		Form of 2023-2025 Performance Unit Agreement (incorporated by reference to Exhibit 10.2 filed with PBF Energy Inc.’s Current Report on Form 8-K dated April 12, 2022 (File No. 001-35764)).


10.3**						Form of PBF Energy Inc. Performance Share Unit Award Agreement (2022-2024 performance period) under the Amended and Restated PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 with PBF Energy Inc.’s Current Report on Form 8-K dated November 24, 2021 (File No. 001-35764)).

10.4**						Form of PBF Energy Inc. Performance Share Unit Award Agreement (2024-2026 performance period) under the Amended and Restated PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 with PBF Energy Inc.’s Current Report on Form 8-K dated November 2, 2023 (File No. 001-35764)).

10.5**						Form of PBF Energy Inc. Performance Unit Award Agreement (2022-2024 performance period) under the Amended and Restated PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.2 with PBF Energy Inc.’s Current Report on Form 8-K dated November 24, 2021 (File No. 001-35764)).

10.6**						Form of PBF Energy Inc. Performance Unit Award Agreement (2024-2026 performance period) under the Amended and Restated PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.2 with PBF Energy Inc.’s Current Report on Form 8-K dated November 2, 2023 (File No. 001-35764)).

10.7**						PBF Energy Inc. Amended and Restated 2012 Equity Incentive Plan (incorporated by reference to Appendix A to PBF Energy Inc.’s Definitive Proxy Statement on Schedule 14A filed on March 22, 2016 (File No. 001-35764)).

10.8**						PBF Energy Inc. Amended and Restated 2017 Equity Incentive Plan (incorporated by reference to Appendix A to PBF Energy Inc.’s Definitive Proxy Statement on Schedule 14A filed on April 13, 2018 (File No. 001-35764)).

10.9**						Amendment No. 1 to PBF Energy Inc. Amended and Restated 2017 Equity Incentive Plan (incorporated by reference to Appendix A to PBF Energy Inc.’s Definitive Proxy Statement on Schedule 14A filed on April 13, 2022 (File No. 001-35764)).

10.10**						Form of PBF Energy Non-Qualified Stock Option Agreement (prior to 2020) under the Amended and Restated PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated November 2, 2018 (File No. 001-35764)).

10.11**						Form of PBF Energy Non-Qualified Stock Option Agreement (2020 and thereafter) under the Amended and Restated PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated November 13, 2020 (File No. 001-35764)).

10.12**						Form of Non-Qualified Stock Option Agreement under the PBF Energy Inc. 2012 Equity Incentive Plan (incorporated by reference to Exhibit 10.28 filed with PBF Energy Inc.’s Amendment No. 6 to Registration Statement on Form S-1 (Registration No. 333-177933)).

10.13**						Form of Amended and Restated Restricted Stock Agreement for non-employee Directors under the PBF Energy Inc. 2017 Equity Incentive Plan. (incorporated by reference to Exhibit 10.3 of PBF Energy Inc.’s Annual Report on Form 10-K (File No. 001-35764) filed on February 23, 2018).

10.14**						Form of Amended and Restated Restricted Stock Agreement for employees under PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.7 of PBF Energy Inc.’s Annual Report on Form 10-K (File No. 001-35764) filed on February 23, 2018).

10.15**						Form of Amended and Restated Restricted Stock Agreement for Employees, under PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.2 of PBF Energy Inc.’s Current Report on Form 8-K dated February 15, 2023 (File No. 001-35764)).

10.16**						Form of PBF Energy Amended and Restated 2017 Equity Incentive Plan, as Amended Restricted Stock Agreement for Employee (incorporated by reference to Exhibit 10.2 filed with PBF Energy Inc.’s Current Report on Form 8-K dated December 2, 2022 (File No. 001-35764)).


10.17**						Form of Amended and Restated 2017 Equity Incentive Plan Performance Share Unit Award Agreement for the 2023-2025 Performance Cycle (incorporated by reference to Exhibit 10.3 filed with PBF Energy Inc.’s Current Report on Form 8-K dated December 2, 2022 (File No. 001-35764)).

10.18**						Form of Amended and Restated 2017 Equity Incentive Plan Performance Unit Award Agreement for the 2023-2025 Performance Cycle (incorporated by reference to Exhibit 10.4 filed with PBF Energy Inc.’s Current Report on Form 8-K dated December 2, 2022 (File No. 001-35764)).

10.19						Amended and Restated Senior Secured Revolving Credit Agreement, dated August 23, 2023 (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated August 23, 2023 (File No. 001-35764)).

10.20**						Employment Agreement dated as of February 20, 2023 between PBF Investments LLC and Karen B. Davis (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated February 16, 2023 (File No. 001-35764)).

10.21/*						Employment Agreement dated as of September 29, 2015 between PBF Investments LLC and Trecia M. Canty (incorporated by reference to Exhibit 10.36 filed with PBF Energy Inc.’s Annual Report on Form 10-K dated February 16, 2023 (File No. 001-35764)).

10.22**						Employment Agreement dated as of September 4, 2014 between PBF Investments LLC and Thomas O’Connor (incorporated by reference to Exhibit 10.9 filed with PBF Energy Inc.’s Annual Report on Form 10-K dated February 29, 2016 (File No. 001-35764)).

10.23**						Employment Agreement dated as of April 1, 2014 between PBF Investments LLC and Timothy Paul Davis (incorporated by reference to Exhibit 10.4 filed with PBF Energy Inc.’s Quarterly Report on Form 10-Q dated May 7, 2014 (File No. 001-35764)).

10.24**						Second Amended and Restated Employment Agreement dated as of May 3, 2023 between PBF Investments LLC and Thomas J. Nimbley (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated May 4, 2023 (File No. 001-35764)).

10.25**						Third Amended and Restated Employment Agreement, dated as of May 3, 2023, between PBF Investments LLC and Matthew C. Lucey (incorporated by reference to Exhibit 10.2 filed with PBF Energy Inc.’s Current Report on Form 8-K dated May 4, 2023 (File No. 001-35764)).

21.1*						Subsidiaries of PBF Holding Company LLC.

22.1*						List of Guarantor Subsidiaries.

24.1*						Power of Attorney (included on signature page).

31.1*						Certification by Chief Executive Officer of PBF Holding Company LLC pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*						Certification by Chief Financial Officer of PBF Holding Company LLC pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*(1)						Certification by Chief Executive Officer of PBF Holding Company LLC pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2*(1)						Certification by Chief Financial Officer of PBF Holding Company LLC pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS						Inline XBRL Instance Document.

101.SCH						Inline XBRL Taxonomy Extension Schema Document.

101.CAL						Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF						Inline XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB						Inline XBRL Taxonomy Extension Label Linkbase Document.

101.PRE						Inline XBRL Taxonomy Extension Presentation Linkbase Document.

10.2**			Form of 2023-2025 Performance Unit Agreement (incorporated by reference to Exhibit 10.2 filed with PBF Energy Inc.’s Current Report on Form 8-K dated April 12, 2022 (File No. 001-35764)).
10.3**			Form of PBF Energy Inc. Performance Share Unit Award Agreement (2022-2024 performance period) under the Amended and Restated PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 with PBF Energy Inc.’s Current Report on Form 8-K dated November 24, 2021 (File No. 001-35764)).
10.4**			Form of PBF Energy Inc. Performance Unit Award Agreement (2022-2024 performance period) under the Amended and Restated PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.2 with PBF Energy Inc.’s Current Report on Form 8-K dated November 24, 2021 (File No. 001-35764)).
10.5**			PBF Energy Inc. Amended and Restated 2012 Equity Incentive Plan (incorporated by reference to Appendix A to PBF Energy Inc.’s Definitive Proxy Statement on Schedule 14A filed on March 22, 2016 (File No. 001-35764)).
10.6**			PBF Energy Inc. Amended and Restated 2017 Equity Incentive Plan (incorporated by reference to Appendix A to PBF Energy Inc.’s Definitive Proxy Statement on Schedule 14A filed on April 13, 2018 (File No. 001-35764)).
10.7**			Amendment No. 1 to PBF Energy Inc. Amended and Restated 2017 Equity Incentive Plan (incorporated by reference to Appendix A to PBF Energy Inc.’s Definitive Proxy Statement on Schedule 14A filed on April 13, 2022 (File No. 001-35764)).
10.8**			Form of PBF Energy Non-Qualified Stock Option Agreement (prior to 2020) under the Amended and Restated PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated November 2, 2018 (File No. 001-35764)).
10.9**			Form of PBF Energy Non-Qualified Stock Option Agreement (2020 and thereafter) under the Amended and Restated PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated November 13, 2020 (File No. 001-35764)).
10.10**			Form of PBF Energy Performance Share Unit Award Agreement (2021-2023) under the Amended and Restated PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.2 filed with PBF Energy Inc.’s Current Report on Form 8-K dated November 13, 2020 (File No. 001-35764)).
10.11**			Form of PBF Energy Performance Unit Award Agreement (2021-2023) under the Amended and Restated PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.3 filed with PBF Energy Inc.’s Current Report on Form 8-K dated November 13, 2020 (File No. 001-35764)).
10.12**			Form of Non-Qualified Stock Option Agreement under the PBF Energy Inc. 2012 Equity Incentive Plan (incorporated by reference to Exhibit 10.28 filed with PBF Energy Inc.’s Amendment No. 6 to Registration Statement on Form S-1 (Registration No. 333-177933)).
10.13**			Form of Amended and Restated Restricted Stock Agreement for non-employee Directors under the PBF Energy Inc. 2017 Equity Incentive Plan. (incorporated by reference to Exhibit 10.3 of PBF Energy Inc.’s Annual Report on Form 10-K (File No. 001-35764) filed on February 23, 2018).
10.14**			Form of Amended and Restated Restricted Stock Agreement for employees under PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.7 of PBF Energy Inc.’s Annual Report on Form 10-K (File No. 001-35764) filed on February 23, 2018).
10.15**			Form of PBF Energy Amended and Restated 2017 Equity Incentive Plan, as Amended Restricted Stock Agreement for Employee (incorporated by reference to Exhibit 10.2 filed with PBF Energy Inc.’s Current Report on Form 8-K dated December 2, 2022 (File No. 001-35764)).



104						Cover Page Interactive Data File (formatted as Inline XBRL and contained in exhibit 101).

10.16**			Form of Amended and Restated 2017 Equity Incentive Plan Performance Share Unit Award Agreement for the 2023-2025 Performance Cycle (incorporated by reference to Exhibit 10.3 filed with PBF Energy Inc.’s Current Report on Form 8-K dated December 2, 2022 (File No. 001-35764)).
10.17**			Form of Amended and Restated 2017 Equity Incentive Plan Performance Unit Award Agreement for the 2023-2025 Performance Cycle (incorporated by reference to Exhibit 10.4 filed with PBF Energy Inc.’s Current Report on Form 8-K dated December 2, 2022 (File No. 001-35764)).
10.18			Senior Secured Revolving Credit Agreement dated as of May 2, 2018 (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated May 7, 2018 (File No. 001-35764)).
10.19			Amendment dated as of February 18, 2020 to Senior Secured Revolving Credit Agreement dated as of May 2, 2018 (incorporated by reference to Exhibit 10.3 filed with PBF Energy Inc.’s Quarterly Report on Form 10-Q dated May 15, 2020 (File No. 001-35764)).
10.20			Second Amendment dated as of May 7, 2020 to Senior Secured Revolving Credit Agreement dated as of May 2, 2018, as amended (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated May 7, 2020 (File No. 001-35764)).
10.21†			Third Amendment to Senior Secured Revolving Credit Agreement, dated May 2, 2018 (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated May 27, 2022 (File No. 001-35764)).
10.22†			Third Amended and Restated Inventory Intermediation Agreement dated as of October 25, 2021, among J. Aron & Company, LLC, PBF Holding Company LLC, Delaware City Refining Company LLC, Paulsboro Refining Company LLC and Chalmette Refining, L.L.C. (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated October 28, 2021 (File No. 001-35764)).
10.23†			First Amendment to the Third Amended and Restated Inventory Intermediation Agreement dated as of October 25, 2021, among J. Aron & Company LLC, PBF Holding Company LLC, Delaware City Refining Company LLC, Paulsboro Refining Company LLC, and Chalmette Refining, L.L.C (incorporated by reference to Exhibit 10.2 filed with PBF Energy Inc.’s Current Report on Form 8-K dated May 27, 2022 (File No. 001-35764)).
10.24			Senior Secured Revolving Credit Agreement dated as of May 2, 2018 (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated May 7, 2018 (File No. 001-35764)).
10.25			Second Amendment dated as of May 7, 2020 to Senior Secured Revolving Credit Agreement dated as of May 2, 2018, as amended (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated May 7, 2020 (File No. 001-35764)).
10.26			Amendment dated as of February 18, 2020 to Senior Secured Revolving Credit Agreement dated as of May 2, 2018 (incorporated by reference to Exhibit 10.3 filed with PBF Energy Inc.’s Quarterly Report on Form 10-Q dated May 15, 2020 (File No. 001-35764).
10.27†			Third Amended and Restated Inventory Intermediation Agreement dated as of October 25, 2021, among J. Aron & Company, LLC, PBF Holding Company LLC, Delaware City Refining Company LLC, Paulsboro Refining Company LLC and Chalmette Refining, L.L.C. (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated October 28, 2021 (File No. 001-35764)).
10.28			Joinder Agreement to the ABL Security Agreement dated as of February 1, 2020, among Martinez Refining Company LLC, Martinez Terminal Company LLC and Bank of America, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Quarterly Report on Form 10-Q dated May 15, 2020 (File No. 001-35764).
10.29			Joinder Agreement to the Credit Agreement dated as of February 1, 2020, among PBF Holding Company LLC, the Guarantors named on the signature pages thereto including Martinez Refining Company LLC, Martinez Terminal Company LLC and Bank of America, N.A., as Administrative Agent to Senior Secured Revolving Credit Agreement dated as of May 2, 2018 (incorporated by reference to Exhibit 10.2 filed with PBF Energy Inc.’s Quarterly Report on Form 10-Q dated May 15, 2020 (File No. 001-35764).

10.30/*			Employment Agreement dated as of September 29, 2015 between PBF Investments LLC and Trecia M. Canty (incorporated by reference to Exhibit 10.36 filed with PBF Energy Inc.’s Annual Report on Form 10-K dated February 16, 2023 (File No. 001-35764)).
10.31**			Employment Agreement dated as of September 4, 2014 between PBF Investments LLC and Thomas O’Connor (incorporated by reference to Exhibit 10.9 filed with PBF Energy Inc.’s Annual Report on Form 10-K dated February 29, 2016 (File No. 001-35764)).
10.32**			Employment Agreement dated as of April 1, 2014 between PBF Investments LLC and Timothy Paul Davis (incorporated by reference to Exhibit 10.4 filed with PBF Energy Inc.’s Quarterly Report on Form 10-Q dated May 7, 2014 (File No. 001-35764)).
10.33**			Employment Agreement dated as of April 1, 2014 between PBF Investments LLC and Erik Young (incorporated by reference to Exhibit 10.2 filed with PBF Energy Inc.’s Quarterly Report on Form 10-Q dated May 7, 2014 (File No. 001-35764)).
10.34**			Letter Agreement between C. Erik Young and PBF Investments LLC dated November 29, 2022 (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated November 29, 2022 (File No. 001-35764)).
10.35**			Letter Agreement dated as of December 7, 2022 between Karen B. Davis and PBF Energy Inc. (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated December 2, 2022 (File No. 001-35764)).
10.36**			Amended and Restated Employment Agreement dated as of December 17, 2012, between PBF Investments LLC and Thomas J. Nimbley (incorporated by reference to Exhibit 10.8 filed with PBF Energy Inc.’s Current Report on Form 8-K dated December 18, 2012 (File No. 001-35764)).
10.37**			Second Amended and Restated Employment Agreement, dated as of December 17, 2012, between PBF Investments LLC and Matthew C. Lucey (incorporated by reference to Exhibit 10.9 filed with PBF Energy Inc.’s Current Report on Form 8-K dated December 18, 2012 (File No. 001-35764)).
21.1*			Subsidiaries of PBF Holding Company LLC.
22.1*			List of Guarantor Subsidiaries.
24.1*			Power of Attorney (included on signature page).
31.1*			Certification by Chief Executive Officer of PBF Holding Company LLC pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*			Certification by Chief Financial Officer of PBF Holding Company LLC pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*(1)			Certification by Chief Executive Officer of PBF Holding Company LLC pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*(1)			Certification by Chief Financial Officer of PBF Holding Company LLC pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS			XBRL Instance Document.
101.SCH			XBRL Taxonomy Extension Schema Document.
101.CAL			XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF			XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB			XBRL Taxonomy Extension Label Linkbase Document.
101.PRE			XBRL Taxonomy Extension Presentation Linkbase Document.
104			Cover Page Interactive Data File (formatted as Inline XBRL and contained in exhibit 101).

——————————


*			Filed herewith.

**			Indicates management compensatory plan or arrangement.



(1)			This exhibit should not be deemed to be “filed” for purposes of Section 18 of the Exchange Act.

*			Filed herewith.
**			Indicates management compensatory plan or arrangement.
†			Portions of the exhibits have been omitted because (i) the registrant customarily and actually treats that information as private or confidential and (ii) the omitted information is not material.
(1)			This exhibit should not be deemed to be “filed” for purposes of Section 18 of the Exchange Act.

PBF HOLDING COMPANY LLC

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm						F- 2
Consolidated Balance Sheets as of December 31, 2022 and 2021						F- 4
Consolidated Balance Sheets as of December 31, 2023 and 2022						F- 4
Consolidated Statements of Operations For the Years Ended December 31, 2022, 2021 and 2020						F- 5
Consolidated Statements of Operations For the Years Ended December 31, 2023, 2022 and 2021						F- 5
Consolidated Statements of Comprehensive Income (Loss) For the Years Ended December 31, 2022, 2021, and 2020						F- 6
Consolidated Statements of Comprehensive Income For the Years Ended December 31, 2023, 2022, and 2021						F- 6
Consolidated Statements of Changes in Equity For the Years Ended December 31, 2022, 2021, and 2020						F- 7
Consolidated Statements of Changes in Equity For the Years Ended December 31, 2023, 2022, and 2021						F- 7
Consolidated Statements of Cash Flows For the Years Ended December 31, 2022, 2021, and 2020						F- 8
Consolidated Statements of Cash Flows For the Years Ended December 31, 2023, 2022, and 2021						F- 8
Notes to Consolidated Financial Statements						F- 10

F- 1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To PBF Energy ~~Inc.~~Company LLC, the Managing Member of PBF Holding Company LLC

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of PBF Holding Company LLC and subsidiaries (the "Company") as of December 31, ~~2022~~2023 and ~~2021~~2022, the related consolidated statements of operations, comprehensive income ~~(loss)~~, changes in equity, and cash flows, for each of the three years in the period ended December 31, ~~2022~~2023, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, ~~2022~~2023 and ~~2021~~2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2022~~2023, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

F-Deferred Refinery Turnaround Costs – Amortization Period – Refer to Notes 2 and 6 to the Consolidated Financial Statements

Critical Accounting Policy and Estimate – Impairment Assessment of Long-Lived Assets and Definite-Lived Intangibles – refer to Note 2 to the Consolidated Financial Statements

Critical Audit Matter Description

The Company ~~evaluates~~routinely ~~long-lived~~performs ~~assets~~turnaround ~~for~~activities ~~impairment~~at oneach ~~a continual basis and reassesses the reasonableness~~ of ~~their~~its ~~related useful lives whenever events or changes in circumstances warrant assessment~~refineries. ~~Possible~~Refinery ~~triggering~~turnaround ~~events may include~~costs, ~~among~~which ~~other~~are ~~things,~~incurred ~~significant adverse changes~~ in ~~the~~connection ~~business~~with ~~climate,~~planned ~~market~~major ~~conditions,~~maintenance ~~environmental regulations~~activities, orare adeferred ~~determination~~when ~~that~~incurred itand isamortized ~~more~~on ~~likely~~a ~~than~~straight-line ~~not~~basis ~~that~~over the ~~carrying~~period ~~amount of an asset or an asset group may not be recoverable, will be sold or retired before its~~ estimated ~~useful~~until life. During 2022, increasing environmental regulation was assessed as a possible triggering event as it relates specifically to our refineries located in California. These possible triggering events of impairment may impact the ~~Company’s~~next ~~assumptions~~planned ~~related~~turnaround ~~to future throughput levels~~occurs, ~~future~~which ~~operating~~is ~~revenues,~~based ~~expenses and gross margin, levels of anticipated capital expenditures, asset retirement obligations and remaining useful life. Changes in these assumptions could have a significant impact~~ on ~~the~~an ~~carrying~~engineering ~~amount of long- lived assets~~assessment. ~~For the year ended December 31, 2022, no impairment loss related to long-lived assets has been recognized.~~

~~We identified the determination of possible triggering events for long~~F-~~lived~~ assets as a critical audit matter because of the significant assumptions management makes when determining whether events or changes in circumstances have occurred indicating that the carrying amounts of long-lived assets may not be recoverable. This required a high degree of auditor judgment.2

Given the amounts deferred that are subject to amortization and the judgment and technical knowledge required to estimate the amortization period of the turnarounds, performing audit procedures to evaluate the reasonableness of these estimates and assumptions required a high degree of auditor judgment and an increased extent of effort.

How the Critical Audit Matter was Addressed in the Audit

~~Our~~•Tested ~~audit~~the ~~procedures~~effectiveness ~~related~~of tocontrols ~~impairment~~over ~~indicators~~the ~~for~~Company’s ~~long-lived~~approval ~~assets~~of ~~included~~ the ~~following,~~amortization ~~among~~period ~~others:~~and the recording of amortization.

•WeInquired ~~tested the effectiveness~~ of ~~controls~~refinery ~~over~~personnel ~~the~~regarding ~~identification of possible circumstances that may indicate that~~ the ~~carrying amounts of long~~in-~~lived~~service ~~assets are no longer recoverable~~date, ~~including~~the ~~controls~~amortization ~~over~~period ~~management’s useful life~~assigned, ~~throughput~~and ~~levels,~~the ~~gross~~scope ~~margin, operating expenses,~~ and ~~future~~nature ~~levels~~ of ~~capital~~turnaround ~~expenditures assumptions~~projects.

•WeWith ~~compared~~the ~~management’s~~assistance ~~evaluation~~ of ~~potential~~fair ~~impairment~~value ~~indicators~~specialists, towe ~~our~~evaluated ~~independent~~the ~~expectation~~reasonableness of the estimated amortization period by:

◦WeTesting ~~performed~~the ~~searches~~source ~~for~~information ~~adverse~~underlying ~~general~~the ~~market~~determination ~~and~~of ~~asset-specific~~the ~~environmental~~amortization ~~conditions,~~period.

◦WeDeveloping ~~inquired~~a ofrange ~~Management about the impact~~ of ~~macro-economic~~independent ~~events,~~estimates ~~the pace of decarbonization~~ and ~~the~~comparing ~~energy~~those ~~transition,~~to ~~and new environmental regulations on~~ the ~~Company’s~~estimated ~~forecasting~~amortization ofperiod ~~future~~selected ~~cash~~by ~~flows, refining margins, future levels of capital expenditure and estimated useful lives,~~ management.

~~◦We~~•Performed ~~inspected~~a ~~minutes~~look-back ofanalysis ~~the~~for ~~board~~turnarounds ofcompleted ~~directors,~~in the ~~Company’s~~current ~~public statements~~year, ~~operating~~to ~~plans,~~determine ~~and~~when ~~market~~a ~~reports~~turnaround towas ~~identify~~last ~~any~~performed ~~evidence~~on ~~that~~the ~~may~~asset ~~contradict~~and ~~management’s~~if ~~assumptions,~~the ~~and~~amortization period assigned to it was appropriate.

◦We read relevant rules and regulations issued by federal, state, and local regulatory bodies, including staff reports, resolutions, other third-party filings, and other publicly available information to assess future levels of sustained capital expenditure and impact to future refinery throughput.

•With the assistance of Environmental Specialists, we performed a public domain search to assess the impact of environmental regulatory laws on the company’s operations.

/s/ Deloitte & Touche LLP

Morristown, New Jersey

March 31, ~~2023~~2024

We have served as the Company's auditor since 2011.

F- 3

PBF HOLDING COMPANY LLC

CONSOLIDATED BALANCE SHEETS

(in millions)

	December 31,2022		December 31,2021
	December 31,2023		December 31,2022
ASSETS
Current assets:
Cash and cash equivalents	$	21,~~153~~760.98	$	12,~~305~~153.79
Accounts receivable	1,~~451~~336.71		1,~~272~~451.07
Accounts receivable - affiliate	627.3		46.13
Inventories	23,~~763~~183.61		2,~~505~~763.16
Prepaid and other current assets	~~119~~173.0		71119.70
Total current assets	6,~~494~~480.53		56,~~158~~494.65
Property, plant and equipment, net	4,~~601~~145.85		4,~~114~~601.8
Lease right of use assets - third party	~~678~~788.32		~~717~~678.03
Lease right of use assets - affiliate	~~421~~380.68		~~485~~421.46
Deferred charges and other assets, net	~~954~~1,129.03		~~813~~954.80
Total assets	$	1312,~~150~~924.21	$	1113,~~289~~150.62
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	~~847~~952.59	$	~~906~~847.35
Accounts payable - affiliate	3872.20		6138.72
Accrued expenses	32,~~691~~968.0		23,~~728~~691.30
Deferred revenue	37.5		40.3
Current operating lease liabilities - third party	131.1		60.5
Current operating lease liabilities - third party	60.5		64.8
Current operating lease liabilities - affiliate	108.7		104.5
Current operating lease liabilities - affiliate	104.5		90.7
Deferred revenue	63.6		37.5
Total current liabilities	4,~~779~~296.23		34,~~892~~779.12
Long-term debt	1,~~434~~245.9		31,~~673~~434.39
Deferred tax liabilities	2124.08		2421.20
Long-term operating lease liabilities - third party	~~551~~607.89		~~570~~551.38
Long-term operating lease liabilities - affiliate	~~317~~272.21		~~394~~317.72
Long-term financing lease liabilities - third party	5746.91		7057.69
Other long-term liabilities	~~371~~269.12		~~251~~371.01
Total liabilities	76,~~533~~762.13		87,~~876~~533.21
Commitments and contingencies (Note 11)
Commitments and contingencies (Note 10)
Equity:
PBF Holding Company LLC equity
Member’s equity	23,~~959~~298.7		2,~~870~~959.27
Retained earnings (accumulated deficit)	2,649.6		(489.3)
Retained earnings	2,868.8		2,649.6
Accumulated other comprehensive income (loss)	(418.48)		20(4.34)
Total PBF Holding Company LLC equity	56,~~604~~148.97		25,~~401~~604.29
Noncontrolling interest	1213.21		12.2
Total equity	56,~~617~~161.18		25,~~413~~617.41
Total liabilities and equity	$	1312,~~150~~924.21	$	1113,~~289~~150.62

See notes to consolidated financial statements.

F- 4

PBF HOLDING COMPANY LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions)

	Year Ended December 31,
		2022		2021		2020
		2023		2022		2021
Revenues		$	4638,~~780~~288.65	$	2746,~~202~~780.06	$	1527,~~045~~202.0
Cost and expenses:
Cost of products and other		3933,~~350~~000.78		2439,~~114~~350.37		1424,~~548~~114.23
Operating expenses (excluding depreciation and amortization expense as reflected below)		2,~~495~~581.63		12,~~999~~495.16		1,~~835~~999.21
Depreciation and amortization expense		~~466~~523.9		~~415~~466.79		~~498~~415.07
Cost of sales		4236,~~313~~106.20		2642,~~529~~313.12		1626,~~881~~529.41
General and administrative expenses (excluding depreciation and amortization expense as reflected below)		~~438~~350.52		~~226~~438.45		~~229~~226.04
Depreciation and amortization expense		78.5		137.35		1113.3
Change in fair value of contingent consideration, net		48(45.18)		2948.41		~~(79~~29.3)4
Impairment expense		—		—		91.8
(Gain) loss on sale of assets		(1.3)		0.9		(0.2)
Loss (gain) on sale of assets		0.9		(0.2)		(477.8)
Total cost and expenses		36,417.6		42,808.2		26,798.0
Total cost and expenses		42,808.2		26,798.0		16,656.4
Income from operations		1,870.9		3,972.4		404.0
Income (loss) from operations		3,972.4		404.0		(1,611.4)
Other income (expense):
Interest expense, net		(~~206~~61.93)		(~~275~~206.19)		(~~210~~275.31)
Change in fair value of catalyst obligations		(21.0)1		8(2.50)		~~(11.~~8).5
(Loss) gain on extinguishment of debt		(665.17)		79(66.91)		~~(22~~79.2)9
Other non-service components of net periodic benefit cost		80.87		78.8		47.38
Income (loss) before income taxes		3,706.2		225.1		(1,851.4)
Income before income taxes		1,805.7		3,706.2		225.1
Income tax (benefit) expense		(2.7)		(14.0)		6.1
Income tax expense (benefit)		1.9		(2.7)		(14.0)
Net income (loss)		3,708.9		239.1		(1,857.5)
Net income		1,803.8		3,708.9		239.1
Less: net income (loss) attributable to noncontrolling interests		(10.4)9		2(1.34)		(02.3)
Net income (loss) attributable to PBF Holding Company LLC		$	3,710.3	$	236.8	$	(1,857.2)
Net income attributable to PBF Holding Company LLC		$	1,802.9	$	3,710.3	$	236.8

See notes to consolidated financial statements.

F- 5

PBF HOLDING COMPANY LLC

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME ~~(LOSS)~~

(in millions)

	Year Ended December 31,
		2022		2021		2020
		2023		2022		2021
Net income (loss)		$	3,708.9	$	239.1	$	(1,857.5)
Net income		$	1,803.8	$	3,708.9	$	239.1
Other comprehensive income (loss):
Unrealized loss on available for sale securities		(20.54)		(02.75)		(0.17)
Net (loss) gain on pension and other post-retirement benefits		(2214.20)		27(22.12)		327.71
Total other comprehensive income (loss)		(2414.74)		26(24.47)		326.64
Comprehensive income (loss)		3,684.2		265.5		(1,853.9)
Comprehensive income		1,789.4		3,684.2		265.5
Less: comprehensive income (loss) attributable to noncontrolling interests		(10.4)9		2(1.34)		(02.3)
Comprehensive income (loss) attributable to PBF Holding Company LLC		$	3,685.6	$	263.2	$	(1,853.6)
Comprehensive income attributable to PBF Holding Company LLC		$	1,788.5	$	3,685.6	$	263.2

See notes to consolidated financial statements.

F- 6

PBF HOLDING COMPANY LLC

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(in millions)

	Member's Equity		Accumulated Other Comprehensive Income (Loss)		RetainedEarnings (Accumulated Deficit)		Noncontrolling Interest		TotalEquity
Balance, January 1, 2020	$	2,739.1	$	(9.7)	$	1,156.9	$	10.9	$	3,897.2
Balance, January 1, 2021	$	2,809.7	$	(6.1)	$	(723.4)	$	10.6	$	2,090.8
Member distributions	—		—		(23.1)		—		(23.1)
Capital contributions from PBF LLC	42.4		—		—		—		42.4
Stock based compensation	28.2		—		—		—		28.2
Comprehensive income (loss)	—		3.6		(1,857.2)		(0.3)		(1,853.9)
Balance, December 31, 2020	2,809.7		(6.1)		(723.4)		10.6		2,090.8
Member distributions	—		—		(2.7)		—		(2.7)
Capital contributions from PBF LLC	37.0		—		—		—		37.0
Distribution of assets to PBF LLC	(0.4)		—		—		—		(0.4)
Stock based compensation	23.9		—		—		—		23.9
Comprehensive income	—		26.4		236.8		2.3		265.5
Other	—		—		—		(0.7)		(0.7)
Balance, December 31, 2021	2,870.2		20.3		(489.3)		12.2		2,413.4
Member distributions	—		—		(571.4)		—		(571.4)
Capital contributions from PBF LLC	56.4		—		—		—		56.4
Distribution of assets to PBF LLC	(0.1)		—		—		—		(0.1)
Stock based compensation	33.2		—		—		—		33.2
Comprehensive income (loss)	—		(24.7)		3,710.3		(1.4)		3,684.2
Other	—		—		—		1.4		1.4
Balance, December 31, 2022	$2,959.7	~~2,959.7~~	$(4.4)	~~(4.4)~~	$2,649.6	~~2,649.6~~	$12.2	~~12.2~~	$5,617.1	~~5,617.1~~
Member distributions	—		—		(1,583.7)		—		(1,583.7)
Capital contributions from PBF LLC	1,159.7		—		—		—		1,159.7
Distribution of assets to PBF LLC	(853.4)		—		—		—		(853.4)
Stock based compensation	35.8		—		—		—		35.8
Comprehensive income (loss)	—		(14.4)		1,802.9		0.9		1,789.4
Other	(3.1)		—		—		—		(3.1)
Balance, December 31, 2023	$	3,298.7	$	(18.8)	$	2,868.8	$	13.1	$	6,161.8

See notes to consolidated financial statements.

F- 7

PBF HOLDING COMPANY LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year Ended December 31,
	2022		2021		2020
	2023		2022		2021
Cash flows from operating activities:
Net income (loss)	$	3,708.9	$	239.1	$	(1,857.5)
Net income	$	1,803.8	$	3,708.9	$	239.1
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	~~495~~551.6		~~444~~495.36		~~523~~444.83
Impairment expense	—		—		91.8
Stock-based compensation	51.5		44.1		30.3
Stock-based compensation	44.1		30.3		29.3
Change in fair value of catalyst obligations	(1.1)		2.0		(8.5)
Change in fair value of catalyst obligations	2.0		(8.5)		11.8
Deferred income taxes	3.7		(3.2)		(14.5)
Deferred income taxes	(3.2)		(14.5)		7.3
Non-cash change in inventory repurchase obligations	—		(5.4)		(8.4)
Non-cash change in inventory repurchase obligations	(5.4)		(8.4)		(12.6)
Non-cash lower of cost or market inventory adjustment	—		—		(669.6)
Non-cash lower of cost or market inventory adjustment	—		(669.6)		268.0
Change in fair value of contingent consideration, net	(45.8)		48.1		29.4
Change in fair value of contingent consideration, net	48.1		29.4		(79.3)
Loss (gain) on extinguishment of debt	5.7		66.1		(79.9)
Loss (gain) on extinguishment of debt	66.1		(79.9)		22.2
Pension and other post-retirement benefit costs	47.9		47.6		50.8
Pension and other post-retirement benefit costs	47.6		50.8		55.7
(Gain) loss on sale of assets	(1.3)		0.9		(0.2)
Loss (gain) on sale of assets	0.9		(0.2)		(477.8)
Changes in operating assets and liabilities:
Accounts receivable	~~(179~~115.6)5		(~~770~~179.56)		~~325~~(770.15)
Due to/from affiliates	~~(25~~12.7)		9(25.37)		69.73
Inventories	(~~258~~334.51)		(~~149~~258.35)		~~392~~(149.23)
Prepaid and other current assets	(511.02)		(155.30)		(315.03)
Accounts payable	~~(97~~125.7)9		~~480~~(97.17)		~~(200~~480.6)1
Accrued expenses	~~860~~(764.89)		~~806~~860.98		~~111~~806.59
Deferred revenue	(226.8)1		(42.8)		28(4.28)
Other assets and liabilities	—(108.0)		~~(76.9)~~—		(6276.89)
Net cash provided by (used in) operating activities	$	4,696.2	$	292.3	$	(820.0)
Net cash provided by operating activities	$	1,478.0	$	4,696.2	$	292.3
Cash flows from investing activities:
Expenditures for property, plant and equipment	(~~625~~647.47)		(~~240~~625.54)		(~~183~~240.95)
Expenditures for deferred turnaround costs	(~~311~~473.65)		(~~117~~311.76)		(~~188~~117.17)
Expenditures for other assets	(6640.05)		(2866.90)		(928.19)
Acquisition of Martinez refinery	—		—		(1,176.2)
Proceeds from sale of assets	4.4		—		—
Proceeds from sale of assets	—		—		543.1
Net cash used in investing activities	$	(1,157.3)	$	(1,003.0)	$	(387.1)
Net cash used in investing activities	$	(1,003.0)	$	(387.1)	$	(1,014.2)

See notes to consolidated financial statements.

F- 8

PBF HOLDING COMPANY LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)

(in millions)

	Year Ended December 31,
	2022		2021		2020
	2023		2022		2021
Cash flows from financing activities:
Contributions from PBF LLC	$	561,159.46	$	3756.04	$	4237.40
Distribution to T&M and Collins shareholders	—		~~(0.7)~~—		—(0.7)
Distributions to members	(~~571~~1,583.47)		(2571.74)		(232.17)
Proceeds from 2025 9.25% Senior Secured Notes	—		—		1,250.6
Proceeds from 2030 7.875% Senior Notes	496.6		—		—
Proceeds from 2028 6.00% Senior Notes	—		—		1,000.0
Redemption of 2025 7.25% Senior Notes	(666.2)		—		—
Repurchase of 2028 6.00% Senior Notes	~~(21.1)~~—		(~~109~~21.31)		—(109.3)
Repurchase of 2025 7.25% Senior Notes	~~(4.8)~~—		(374.58)		—(37.5)
Redemption of 2023 7.00% Senior Notes	—		—		(517.5)
Redemption of 2025 9.25% Senior Secured Notes	—		(1,307.4)		—
Redemption of 2025 9.25% Senior Secured Notes	(1,307.4)		—		—
Proceeds from revolver borrowings	—		400.0		—
Proceeds from revolver borrowings	400.0		—		1,450.0
Repayments of revolver borrowings	—		(1,300.0)		—
Repayments of revolver borrowings	(1,300.0)		—		(550.0)
Repayments of PBF Rail Term Loan	—		—		(7.4)
Repayments of PBF Rail Term Loan	—		(7.4)		(7.2)
Settlements of precious metal catalyst obligations	(3.1)		(56.2)		(31.7)
Settlements of precious metal catalyst obligations	(56.2)		(31.7)		(8.8)
Payments on financing leases	(14.1)		(11.3)		(17.8)
Proceeds from catalyst financing arrangements	—		—		51.9
Proceeds from insurance premium financing	13.0		2.1		—
Payments on financing leases	(11.3)		(17.8)		(12.4)
Payments of contingent consideration	(80.1)		—		—
Proceeds from insurance premium financing	2.1		—		—
Deferred financing costs and other	(35.8)		(31.3)		0.5
Deferred financing costs and other	(31.3)		0.5		(34.7)
Net cash used in financing activities	$	(713.8)	$	(2,845.0)	$	(169.6)
Net cash (used in) provided by financing activities	$	(2,845.0)	$	(169.6)	$	2,641.2
Net change in cash and cash equivalents	(393.1)		848.2		(264.4)
Net change in cash and cash equivalents	848.2		(264.4)		807.0
Cash and cash equivalents, beginning of period	2,153.9		1,305.7		1,570.1
Cash and cash equivalents, beginning of period	1,305.7		1,570.1		763.1
Cash and cash equivalents, end of period	$	1,760.8	$	2,153.9	$	1,305.7
Cash and cash equivalents, end of period	$	2,153.9	$	1,305.7	$	1,570.1

Supplemental cash flow disclosures
Non-cash activities:
Accrued and unpaid capital expenditures	$	165.2	$	103.2	$	31.1
Distribution of assets to PBF Energy Company LLC	$	(853.4)	$	—	$	—
Assets acquired or remeasured under operating and financing leases	82.8		(106.6)		702.0
Accrued and unpaid capital expenditures	143.5		165.2		103.2
Fair value of the Martinez Contingent Consideration at acquisition	—		—		77.3
Assets acquired or remeasured under operating and financing leases	335.4		82.8		(106.6)
Cash paid during the year for:
Interest (net of capitalized interest of $24.8, $8.9 and $11.9 in 2022, 2021 and 2020, respectively)	$	211.5	$	265.4	$	162.9
Interest (net of capitalized interest of $38.0, $24.8 and $8.9 in 2023, 2022 and 2021, respectively)	$	95.5	$	211.5	$	265.4
Income taxes	01.86		1.0.8		1.0

See notes to consolidated financial statements.

F- 9

PBF HOLDING COMPANY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION

Description of the Business

PBF Holding Company LLC (“PBF Holding”), together with its consolidated subsidiaries, owns and operates oil refineries and related facilities in North America. PBF Holding is a wholly-owned subsidiary of PBF Energy Company LLC (“PBF LLC”). PBF Energy Inc. (“PBF Energy”) is the sole managing member of, and owner of an equity interest representing approximately 99.3% of the outstanding economic interest in PBF LLC as of December 31, ~~2022~~2023. Collectively, PBF Holding and its consolidated subsidiaries are referred to hereinafter as the “Company”.

Substantially all of the Company’s operations are in the United States. As of December 31, ~~2022~~2023, the Company’s oil refineries are all engaged in the refining of crude oil and other feedstocks into petroleum products, and have been aggregated to form one reportable segment.

PBF Logistics GP LLC (“PBFX GP”) serves as the general partner of PBF Logistics LP (“PBFX”). ~~PBF~~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~~initial public offering, wethe Company has distributed certain ~~additional~~ assets to PBF LLC, which in turn contributed those assets to PBFX. (as described in “Note 109 - Related Party Transactions”). On November 27, 2022, PBF Energy and PBF LLC ~~enter~~entered into the Merger Agreement with PBFX announcing the Merger Transaction, which was finalized on November 30, 2022 (all terms as defined in “Note 109 - Related Party Transactions”).

On June 27, 2023, the Company 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 Company has 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, the Company 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.

F- 10

PBF HOLDING COMPANY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Presentation

These Consolidated Financial Statements include the accounts of PBF Holding and its consolidated subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.

Cost Classifications

Cost of products and other consists of the cost of crude oil, other feedstocks, blendstocks and purchased refined products and the related in-bound freight and transportation costs.

Operating expenses (excluding depreciation and amortization) consists of direct costs of labor, maintenance and services, utilities, property taxes, environmental compliance costs and other direct operating costs incurred in connection with ~~our~~the Company’s refining operations. Such expenses exclude depreciation related to refining and logistics assets that are integral to the refinery production process, which is presented separately as Depreciation and amortization expense as a component of Cost of sales on the Company’s Consolidated Statements of Operations.

Use of Estimates

The preparation of the financial statements in conformity with accounting principles generally accepted in the United States ~~(“GAAP”)~~ requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures. Actual results could differ from those estimates.

Impairment Assessment of Long-Lived Assets and Definite-Lived Intangibles

The Company evaluates long-lived assets for impairment on a continual basis and reassesses 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 the Company’s 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, early retirement or 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. The Company’s 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.

Cash and Cash Equivalents

The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The carrying amount of the cash equivalents approximates fair value due to the short-term maturity of those instruments.

F- 11

PBF HOLDING COMPANY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Business Combinations

Certain of the Company’s acquisitions may include earn-out provisions or other forms of contingent consideration. As of the acquisition date, the Company records contingent consideration, as applicable, at the estimated fair value of expected future payments associated with the earn-out. Any changes to the recorded fair value of contingent consideration, subsequent to the measurement period, will be recognized as earnings in the period in which it occurs.

Cash and Cash Equivalents

Concentrations of Credit Risk

For the years ended December 31, ~~2022~~2023 and December 31, ~~2021~~2022, only one customer, Shell plc (“Shell”), accounted for 10% or more of the Company’s revenues (approximately 14% and 1514%, respectively).

As of December 31, ~~2022~~2023 and December 31, ~~2021~~2022, only one customer, Shell, accounted for 10% or more of the Company’s total trade accounts receivable (approximately 19% and 2619%, respectively).

Revenue Recognition

The Company sells various refined products primarily through its refinery subsidiaries and recognizes revenue related to the sale of products when control of the promised goods or services is transferred to the customers, in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. Refer to “Note 1615 - Revenues” for further discussion of the Company’s revenue recognition policy.

Accounts Receivable

Accounts receivable are carried at invoiced amounts. An allowance for doubtful accounts is established, if required, to report such amounts at their estimated net realizable value. In estimating probable losses, management reviews accounts that are past due and determines if there are any known disputes.

Excise taxes on sales of refined products that are collected from customers and remitted to various governmental agencies are reported on a net basis.

Inventory

Inventories are carried at the lower of cost or market (“LCM”). The cost of crude oil, feedstocks, blendstocks and refined products are determined under the last-in first-out (“LIFO”) method using the dollar value LIFO method with increments valued based on average purchase prices during the year. The cost of supplies and other inventories is determined principally on the weighted average cost method.

F- 12

PBF HOLDING COMPANY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

RINs

The Company is subject to obligations to purchase Renewable Identification Numbers (“RINs”) required to comply with the renewable fuel standard implemented by Environmental Protection Agency (“EPA”), which sets annual quotas for the quantity of renewable fuels (such as ethanol) that must be blended into motor fuels consumed in the United States (the “RFS”). The Company’s overall RINs obligation is based on a percentage of domestic shipments of on-road fuels as established by EPA. To the degree the Company is unable to blend the required amount of biofuels to satisfy its RINs obligation, RINs must be purchased on the open market to avoid penalties and fines. The Company records its RINs obligation on a net basis in Accrued expenses when its 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.

Leases

The Company leases office space, office equipment, refinery facilities and equipment, railcars and other logistics assets primarily under non-cancelable operating leases, with terms typically ranging from one to twenty years, subject to certain renewal options as applicable. The Company considers those renewal or termination options that are reasonably certain to be exercised in the determination of the lease term and initial measurement of lease liabilities and right-of-use assets. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term. Interest expense for finance leases is incurred based on the carrying value of the lease liability. Leases with an initial term of 12 months or less are not recorded on the Company’s Consolidated Balance Sheets.

~~The~~F- Company determines whether a contract is or contains a lease at inception of the contract and whether that lease meets the classification criteria of a finance or operating lease. When available, the Company uses the rate implicit in the lease to discount lease payments to present value; however, most of the Company’s leases do not provide a readily determinable implicit rate. Therefore, the Company must discount lease payments based on an estimate of its incremental borrowing rate.12

For substantially all classes of underlying assets, the Company has elected the practical expedient not to separate lease and non-lease components, which allows for combining the components if certain criteria are met. For certain leases of refinery support facilities, the Company accounts for the non-lease service component separately.

F- 13

PBF HOLDING COMPANY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company determines whether a contract is or contains a lease at inception of the contract and whether that lease meets the classification criteria of a finance or operating lease. When available, the Company uses the rate implicit in the lease to discount lease payments to present value; however, most of the Company’s leases do not provide a readily determinable implicit rate. Therefore, the Company must discount lease payments based on an estimate of its incremental borrowing rate.

Property, Plant and Equipment

Property, plant and equipment additions are recorded at cost. The Company capitalizes costs associated with the preliminary, pre-acquisition and development/construction stages of a major construction project. The Company capitalizes the interest cost associated with major construction projects based on the effective interest rate of total borrowings. The Company also capitalizes costs incurred in the acquisition and development of software for internal use, including the costs of software, materials, consultants and payroll-related costs for employees incurred in the application development stage.

Depreciation is computed using the straight-line method over the following estimated useful lives:

Process units and equipment						5-25 years
Pipeline and equipment						5-25 years
Buildings						25 years
Computers, furniture and fixtures						3-7 years
Leasehold improvements						20 years
Processing units and equipment						5-25 years
Pipeline and equipment						5-25 years
Buildings						25 years
Railcars						50 years

Maintenance and repairs are charged to operating expenses as they are incurred. Improvements and betterments, which extend the lives of the assets, are capitalized.

Deferred Charges and Other Assets, Net

Deferred charges and other assets include refinery turnaround costs, catalyst, precious metal catalysts, linefill, deferred financing costs and intangible assets. Refinery turnaround costs, which are incurred in connection with planned major maintenance activities, are capitalized when incurred and amortized on a straight-line basis over the period of time estimated to lapse until the next turnaround occurs, which is based on an engineering assessment. The amortization period generally ranges from 3 to 6 years; however, based ~~upon~~on the specific facts and circumstances, different periods of deferral may occur.

Precious metal catalysts, linefill and certain other intangibles are considered indefinite-lived assets as they are not expected to deteriorate in their prescribed functions. Such assets are assessed for impairment in connection with the Company’s review of its long-lived assets.

Deferred financing costs are capitalized when incurred and amortized over the life of the loan ~~(generally 1 to 8 years)~~.

Intangible assets with finite lives primarily consist of emission credits and permits and are amortized over their estimated useful lives (generally 1 to 10 years).

~~Asset~~F- ~~Retirement Obligations~~13

The Company records an asset retirement obligation at fair value for the estimated cost to retire a tangible long-lived asset at the time the Company incurs that liability, which is generally when the asset is purchased, constructed, or leased. The Company records the liability when it has a legal or contractual obligation to incur costs to retire the asset and when a reasonable estimate of the fair value of the liability can be made. If a reasonable estimate cannot be made at the time the liability is incurred, the Company will record the liability when sufficient information is available to estimate the liability’s fair value. Certain of the Company’s asset retirement obligations are based on its legal obligation to perform remedial activity at its refinery sites when it permanently ceases operations of the long-lived assets. The Company therefore considers the settlement date of these obligations to be indeterminable. Accordingly, the Company cannot calculate an associated asset retirement liability for these obligations at this time. The Company will measure and recognize the fair value of these asset retirement obligations when the settlement date is determinable.

F- 14

PBF HOLDING COMPANY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Asset Retirement Obligations

Environmental Matters

Liabilities for future remediation costs are recorded when environmental assessments and/or remedial efforts are probable, and the costs can be reasonably estimated. Other than for 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 the Company’s own internal environmental policies. The measurement of environmental remediation liabilities may be discounted to reflect the time value of money if the aggregate amount and timing of cash payments of the liabilities are fixed or reliably determinable. The actual settlement of the Company’s liability for environmental matters could materially differ from its 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.

Stock-Based Compensation

Stock-based compensation includes the accounting effect of options to purchase PBF Energy Class A common stock granted by PBF Energy to certain PBF Holding employees, Series A warrants issued or granted by PBF LLC to employees in connection with their acquisition of PBF LLC Series A units, options to acquire Series A units of PBF LLC granted by PBF LLC to certain employees, Series B units of PBF LLC that were granted to certain members of management and restricted PBF LLC Series A Units and restricted PBF Energy Class A common stock granted to certain directors and officers. The estimated fair value of the options to purchase PBF Energy Class A common stock and the PBF LLC Series A warrants and options, is based on the Black-Scholes option pricing model and the fair value of the PBF LLC Series B units is estimated based on a Monte Carlo simulation model. The estimated fair value is amortized as stock-based compensation expense on a straight-line method over the vesting period and included in General and administrative expense with forfeitures recognized in the period they occur.

PBF Energy grants performance share unit awards and performance unit awards to certain key employees. Performance awards granted to employees prior to November 1, 2020 are based on a three-year performance cycle with four measurement periods and performance awards granted to employees after November 1, 2020 are based on a three-year performance cycle having a single measurement period. The payout for each, which ranges from zero to 200%, is based on the relative ranking of the total shareholder return (“TSR”) of PBF Energy’s common stock as compared to the TSR of a selected group of industry peer companies over an average of four measurement periods. The performance share unit awards and performance unit awards are each measured at fair value based on Monte Carlo simulation models. The performance share unit awards will be settled in PBF Energy Class A common stock and are accounted for as equity awards and the performance unit awards will be settled in cash and are accounted for as liability awards.

~~Income~~F- ~~Taxes~~14

As PBF Holding is a limited liability company treated as a “flow-through” entity for income tax purposes, there is no benefit or expense for federal or state income tax in the accompanying financial statements apart from the income taxes attributable to two subsidiaries acquired in connection with the acquisition of Chalmette Refining, L.L.C. (“Chalmette Refining”) and the Company’s wholly-owned Canadian subsidiary, PBF Energy Limited (“PBF Ltd.”). These subsidiaries are treated as C-corporations for tax purposes, with the tax provision calculated based on the effective tax rate for the periods presented.

The State tax returns for all years since 2018 are subject to examination by the respective tax authorities.

F- 15

PBF HOLDING COMPANY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Income Taxes

The State tax returns for all years since 2019 are subject to examination by the respective tax authorities.

Pension and Other Post-Retirement Benefits

The Company recognizes an asset for the overfunded status or a liability for the underfunded status of its pension and post-retirement benefit plans. The funded status is recorded within Other long-term liabilities or Other non-current assets. Changes in the plans’ funded status are recognized in other comprehensive income in the period the change occurs.

Fair Value Measurement

A fair value hierarchy (Level 1, Level 2, or Level 3) is used to categorize fair value amounts based on the quality of inputs used to measure fair value. Accordingly, fair values derived from Level 1 inputs utilize quoted prices in active markets for identical assets or liabilities. Fair values derived from Level 2 inputs are based on quoted prices for similar assets and liabilities in active markets, and inputs other than quoted prices that are either directly or indirectly observable for the asset or liability. Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability.

The Company uses appropriate valuation techniques based on the available inputs to measure the fair values of its applicable assets and liabilities. When available, the Company measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value. In some valuations, the inputs may fall into different levels in the hierarchy. In these cases, the asset or liability level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurements.

Financial Instruments

The estimated fair value of financial instruments has been determined based on the Company’s assessment of available market information and appropriate valuation methodologies. The Company’s non-derivative financial instruments that are included in current assets and current liabilities are recorded at cost in the Consolidated Balance Sheets. The estimated fair value of these financial instruments approximates their carrying value due to their short-term nature. Derivative instruments are recorded at fair value in the Consolidated Balance Sheets.

The Company’s commodity contracts are measured and recorded at fair value using Level 1 inputs based on quoted prices in an active market, Level 2 inputs based on quoted market prices for similar instruments, or Level 3 inputs based on third-party sources and other available market based data. The Company’s catalyst obligations and derivatives related to the Company’s crude oil and feedstocks and refined product purchase obligations are measured and recorded at fair value using Level 2 inputs on a recurring basis, based on observable market prices for similar instruments.

Derivative Instruments

The Company is exposed to market risk, primarily related to changes in commodity prices for the crude oil and feedstocks used in the refining process as well as the prices of the refined products sold, and the risk associated with the price of credits needed to comply with various governmental and regulatory environmental compliance programs. The accounting treatment for commodity and environmental compliance contracts depends on the intended use of the particular contract and on whether or not the contract meets the definition of a derivative.

~~All~~F- derivative instruments, not designated as normal purchases or sales, are recorded in the Consolidated Balance Sheets as either assets or liabilities measured at their fair values. Changes in the fair value of derivative instruments that either are not designated or do not qualify for hedge accounting treatment or normal purchase or normal sale accounting are recognized in earnings. Contracts qualifying for the normal purchase and sales exemption are accounted for upon settlement. Cash flows related to derivative instruments that are not designated or do not qualify for hedge accounting treatment are included in operating activities.15

F- 16

PBF HOLDING COMPANY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All derivative instruments, not designated as normal purchases or sales, are recorded in the Consolidated Balance Sheets as either assets or liabilities measured at their fair values. Changes in the fair value of derivative instruments that either are not designated or do not qualify for hedge accounting treatment or normal purchase or normal sale accounting are recognized in earnings. Contracts qualifying for the normal purchase and sales exemption are accounted for upon settlement. Cash flows related to derivative instruments that are not designated or do not qualify for hedge accounting treatment are included in operating activities.

The Company designates certain derivative instruments as fair value hedges of a particular risk associated with a recognized asset or liability. At the inception of the hedge designation, the Company documents the relationship between the hedging instrument and the hedged item, as well as its risk management objective and strategy for undertaking various hedge transactions. Derivative gains and losses related to these fair value hedges, including hedge ineffectiveness, are recorded in cost of sales along with the change in fair value of the hedged asset or liability attributable to the hedged risk. Cash flows related to derivative instruments that are designated as fair value hedges are included in operating activities.

Economic hedges are hedges not designated as fair value or cash flow hedges for accounting purposes that are used to (i) manage price volatility in certain refinery feedstock and refined product inventories, and (ii) manage price volatility in certain forecasted refinery feedstock purchases and refined product sales. These instruments are recorded at fair value and changes in the fair value of the derivative instruments are recognized currently in cost of sales.

Derivative accounting is complex and requires management judgment in the following respects: identification of derivatives and embedded derivatives, determination of the fair value of derivatives, documentation of hedge relationships, assessment and measurement of hedge ineffectiveness and election and designation of the normal purchases and sales exemption. All of these judgments, depending upon their timing and effect, can have a significant impact on the Company’s earnings.

Recently Issued Accounting Pronouncements

In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2020-04, “Reference Rate Reform (Topic 848): Facilitation of the effects of reference rate reform on financial reporting”. The amendments in this ASU provide optional guidance to alleviate the burden in accounting for reference rate reform, by allowing certain expedients and exceptions in applying GAAP to contracts, hedging relationship and other transactions affected by the expected market transition from London Interbank Offered Rate (“LIBOR”) and other interbank rates. The Company’s adoption of this guidance did not have, and is not anticipated to have, a material impact on its Consolidated Financial Statements and related disclosures.

3. CURRENT EXPECTED CREDIT LOSSES

Credit Losses

The Company has exposure to credit losses primarily through its sales of refined products. The Company evaluates creditworthiness on an individual customer basis. The Company utilizes a financial review model for purposes of evaluating creditworthiness which is based on information from financial statements and credit reports. The financial review model enables the Company to assess the customer’s risk profile and determine credit limits on the basis of their financial strength, including but not limited to, their liquidity, leverage, debt serviceability, longevity and how they pay their bills. The Company may require security in the form of letters of credit or cash payments in advance of product delivery for certain customers that are deemed higher risk.

The Company’s payment terms on its trade receivables are relatively short, generally 30 days or less for a substantial majority of its refined products. As a result, the Company’s collection risk is mitigated to a certain extent by the fact that sales are collected in a relatively short period of time, allowing for the ability to reduce exposure on defaults if collection issues are identified. Notwithstanding, the Company reviews each customer’s credit risk profile at least annually or more frequently if warranted.

The Company performs a quarterly allowance for doubtful accounts analysis to assess whether an allowance needs to be recorded for any outstanding trade receivables. In estimating credit losses, management reviews accounts that are past due, have known disputes or have experienced any negative credit events that may result in future collectability issues. There was no allowance for doubtful accounts recorded as of December 31, ~~2022~~2023 or December 31, ~~2021~~2022.

F- 1716

PBF HOLDING COMPANY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

4. INVENTORIES

Inventories consisted of the following:


December 31, 2023
(in millions)	Total
Crude oil and feedstocks	$	1,495.4
Refined products and blendstocks	1,536.5
Warehouse stock and other	151.2
	$	3,183.1
Lower of cost or market adjustment	—
Total inventories	$	3,183.1


December 31, 2022
(in millions)	Titled Inventory		Inventory Intermediation Agreement		Total
Crude oil and feedstocks	$	1,195.2	$	140.9	$	1,336.1
Refined products and blendstocks	1,244.7		40.9		1,285.6
Warehouse stock and other	141.9		—		141.9
	$	2,581.8	$	181.8	$	2,763.6
Lower of cost or market adjustment	—		—		—
Total inventories	$	2,581.8	$	181.8	$	2,763.6

December 31, 2021
(in millions)	Titled Inventory		Inventory Intermediation Agreement		Total
Crude oil and feedstocks	$	953.5	$	151.4	$	1,104.9
Refined products and blendstocks	964.6		293.8		1,258.4
Warehouse stock and other	141.8		—		141.8
	$	2,059.9	$	445.2	$	2,505.1
Lower of cost or market adjustment	—		—		—
Total inventories	$	2,059.9	$	445.2	$	2,505.1

As of December 31, 2023 and December 31, 2022, there was no LCM inventory adjustment recorded as the replacement value of inventories exceeded the LIFO carrying value. During the year ended December 31, 2021, the Company recorded an adjustment to value its inventories to the lower of cost or market which increased income from operations by $669.6 million, reflecting no LCM inventory reserve at December 31, 2021.

OnAn ~~October~~actual ~~25,~~valuation ~~2021,~~of ~~PBF~~inventories ~~Holding~~valued ~~and~~under ~~its subsidiaries, Delaware City Refining Company LLC, Paulsboro Refining Company LLC, and Chalmette Refining (collectively,~~ the ~~“PBF~~LIFO ~~Entities”),~~method ~~entered~~is ~~into~~made aat ~~third amended and restated inventory intermediation agreement (~~the ~~“Third~~end ~~Inventory Intermediation Agreement”) with J. Aron & Company, a subsidiary~~ of ~~The~~each ~~Goldman~~year ~~Sachs~~based ~~Group,~~on ~~Inc. (“J. Aron”), pursuant to which the terms of the existing~~ inventory ~~intermediation~~levels ~~agreements were amended~~ and ~~restated~~costs inat ~~their~~that ~~entirety, including, among other things, pricing and an extension of terms~~time. ~~The~~There ~~Third~~were ~~Inventory~~no ~~Intermediation~~significant ~~Agreement~~decrements ~~extends~~recorded during the ~~term~~years toended December 31, ~~2024~~2023, ~~which term may be further extended by mutual consent of the parties to~~ December 31, ~~2025. On May 25,~~ 2022, ~~the~~or ~~PBF Entities entered into an amendment of the Third Inventory Intermediation Agreement to amend certain provisions thereof that related to and were impacted by amendments made on May 25~~December 31, ~~2022 to the Revolving Credit Agreement (as defined in Note 8 - Credit Facilities and Debt)~~2021.

~~Pursuant~~On toJuly ~~the~~31, ~~Third Inventory Intermediation Agreement~~2023, J.the ~~Aron~~Company ~~will~~terminated ~~continue~~the tothird ~~purchase~~amended and ~~hold~~restated ~~title to certain~~ inventory, ~~including~~intermediation ~~crude~~agreement ~~oil, intermediate and certain finished products~~ (the “J.Third ~~Aron~~Inventory ~~Products~~Intermediation Agreement”) ~~purchased~~previously orentered ~~produced~~into by ~~the Paulsboro~~ and ~~Delaware~~among ~~City~~PBF ~~refineries~~Holding (and, atits ~~the~~subsidiaries, ~~election~~Delaware ofCity ~~the~~Refining ~~PBF~~Company ~~Entities~~LLC, ~~the~~Paulsboro Refining Company LLC and Chalmette ~~refinery)~~Refining (collectively, the “~~Refineries~~PBF Entities”), and ~~delivered~~J. ~~into~~Aron ~~storage~~& ~~tanks~~Company, at<

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