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, 20192022
or
| ☐ | 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
Commission File Number: 333-206728-02
PBF ENERGY INC.
PBF ENERGY COMPANY LLC
(Exact name of registrant as specified in its charter)
| Delaware | 45-3763855 | ||||||||||
| Delaware | 61-1622166 | ||||||||||
| (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) | ||||||||||
(Registrants’ 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 | |||||||||
| Class A Common Stock, par value $.001 | PBF | New York Stock Exchange | |||||||||
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 Energy Inc. x Yes o No
PBF Energy Company LLC o 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 Energy Inc. o Yes x No
PBF Energy Company LLC o Yes x 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 Energy Inc. x Yes o No
PBF Energy Company LLC x Yes o No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted and posted 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 and post such files).
PBF Energy Inc. x Yes o No
PBF Energy Company LLC x Yes o 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 Energy Inc. | Large accelerated filer | ☒ | Accelerated filer | ☐ | Non-accelerated filer | ☐ | Smaller reporting company | ☐ | Emerging growth company | ☐ | ||||||||||||||||||||||
| PBF Energy Company LLC | 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 Energy Inc. o
PBF Energy Company LLC o
PBF Energy Inc. ☒
PBF Energy Company LLC ☒
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 Energy Inc. o
PBF Energy Company LLC o
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 Energy Inc. o
PBF Energy Company LLC o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
PBF Energy Inc. ☐ Yes x☒ No
PBF Energy Company LLC ☐ Yes x☒ No
The aggregate market value of the Common Stock of PBF Energy Inc. held by non-affiliates as of June 30, 20192022, the last business day of the registrant’s most recently completed second fiscal quarter, was $3,719,104,999approximately $3.5 billion based upon the New York Stock Exchange Composite Transaction closing price.
As of February 18, 2020,9, 2023, PBF Energy Inc. had outstanding 119,784,833128,975,077 shares of Class A common stock and 2013 shares of Class B common stock. PBF Energy Inc. is the sole managing member of, and owner of an equity interest representing approximately 99.0%99.3% of the outstanding economic interest in PBF Energy Company LLC as of December 31, 2019.2022. There is no trading in the membership interest of PBF Energy Company LLC and therefore an aggregate market value based on such is not determinable. PBF Energy Company LLC has 0no common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
PBF Energy Inc. intends to file with the Securities and Exchange Commission a definitive Proxy Statement for its Annual Meeting of Stockholders within 120 days after December 31, 2019.2022. Portions of the Proxy Statement are incorporated by reference in Part III of this Form 10-K to the extent stated herein.
PBF ENERGY INC. AND PBF ENERGY COMPANY LLC
TABLE OF CONTENTS
| PART I | |||||||||||||
| PART II | |||||||||||||
| PART III | |||||||||||||
| PART IV | |||||||||||||
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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:
“AB32”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” refers tois 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, and (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.
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“Dated Brent” refers to Brent blend oil, a light, sweet North Sea crude oil, characterized by an APIAmerican 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.
“Ethanol Permit” refers to the Coastal Zone Act permit for ethanol issued to our Delaware City refinery.
“FCC” refers to fluid catalytic cracking.
“feedstocks” refers to crude oil and partially refined petroleum products that are processed and blended into refined products.
“GAAP” refers to U.S. generally accepted accounting principles developed by the Financial Accounting StandardsStandard 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.
“IDRs” refers to incentive distribution rights.
“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.
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“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.
“NYMEX”OSHA” refers to the New York Mercantile Exchange.Occupational Safety and Health Administration of the U.S. Department of Labor.
“PADD” refers to Petroleum Administration for Defense Districts.
“refined products” refers to petroleum products, such as gasoline, diesel and jet fuel, that are produced by a refinery.
“RINS”Renewable Fuel Standard” (“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 Renewable Fuel Standard.RFS.
“Saudi Aramco” refers to Saudi Arabian Oil Company.
“SEC” refers to the United States Securities and Exchange Commission.
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“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.
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Explanatory Note
This Annual Report on Form 10-K is filed by PBF Energy Inc. (“PBF Energy”) and PBF Energy Company LLC (“PBF LLC”). Each Registrant hereto is filing on its own behalf all of the information contained in this report that relates to such Registrant. Each Registrant hereto is not filing any information that does not relate to such Registrant, and therefore makes no representation as to any such information. PBF Energy is a holding company whose primary asset is an equity interest in PBF LLC. PBF Energy is the sole managing member of, and owner of an equity interest representing approximately 99.0%99.3% of the outstanding economic interests in PBF LLC as of December 31, 2019.2022. PBF Energy operates and controls all of the business and affairs and consolidates the financial results of PBF LLC and its subsidiaries. PBF LLC is a holding company for the companies that directly and indirectly own and operate the business. As of December 31, 2019, PBF LLC also holds a 48.2% limited partner interest and a non-economic general partner interest in PBF Logistics LP (“PBFX”), a publicly-traded MLP.
PART I
This Annual Report on Form 10-K is filed by PBF Energy and PBF LLC. Discussions or areas of this report that either apply only to PBF Energy or PBF LLC are clearly noted in such sections. Unless the context indicates otherwise, the terms “Company”, “we,” “us,” and “our” refer to both PBF Energy and PBF LLC and its consolidated subsidiaries, including PBF Holding Company LLC (“PBF Holding”), PBF Investments LLC, (“PBF Investments”), Toledo Refining Company LLC, (“Toledo Refining” or “TRC”), Paulsboro Refining Company LLC (“Paulsboro Refining” or “PRC”PRC”), Delaware City Refining Company LLC (“Delaware City Refining” or “DCR”DCR”), Chalmette Refining, L.L.C. (“Chalmette Refining”), PBF Energy Western Region LLC (“PBF Western Region”), Torrance Refining Company LLC (“Torrance Refining”), Torrance Logistics Company LLC, Martinez Refining Company LLC (“Torrance Logistics”MRC”), PBF Logistics GP LLC (“PBFPBFX GP”) and PBFX.PBF Logistics LP (“PBFX”) and its subsidiaries.
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, under the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 to the extent such statements relate to the operations of an entity that is not a limited liability company or a partnership. You should read our forward-looking statements together with our disclosures under the heading: “Cautionary Statement for the Purpose of Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995.” 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.
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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 were formed in 2008 to pursue acquisitions of crude oil refineries and downstream assets in North America. As of December 31, 2019, we own and operate fivesix domestic oil refineries and related assets, which we acquired in 2010, 2011, 2015 and 2016.assets. Our refineries have a combined processing capacity, known as throughput, of approximately 900,0001,000,000 bpd, and a weighted-average Nelson Complexity Index of 12.2.12.7 based on current operating conditions. The complexity and throughput capacity of our refineries are subject to change dependent upon configuration changes we make to respond to market conditions, as well as a result of investments made to improve our facilities and maintain compliance with environmental and governmental regulations. We operate in two reportable business segments: Refining and Logistics.
PBF Energy was formed on November 7, 2011 and is a holding company whose primary asset is a controlling equity interest in PBF LLC. We are the sole managing member of PBF LLC and operate and control all of the business and affairs of PBF LLC. We consolidate the financial results of PBF LLC and its subsidiaries and record a noncontrolling interest in our consolidated financial statements representing the economic interests of the members of PBF LLC other than PBF Energy. PBF LLC is a holding company for the companies that directly or indirectly own and operate our business. PBF Holding is a wholly-owned subsidiary of PBF LLC and is the parent company for our refining operations. PBF Energy, through its ownershipPBFX is an indirect wholly-owned subsidiary of PBF LLC also consolidates the financial results of PBFXthat owns and records a noncontrolling interest for the economic interests in PBFX held by the public common unitholders of PBFX.operates logistics assets that support our refining operations.
As of December 31, 2019,2022, PBF Energy held 119,826,202129,660,538 PBF LLC Series C Units and our current and former executive officers and directors and certain employees and others held 1,215,317910,457 PBF LLC Series A Units (we refer to all of the holders of the PBF LLC Series A Units as “the members of PBF LLC other than PBF Energy”). As a result, the holders of PBF Energy’s issued and outstanding shares of its Class A common stock have approximately 99.0%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 1.0%0.7% of the voting power in PBF Energy.
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The following map details the locations of our refineries and the location of PBFX’s assets as of December 31, 2019 (each as defined below):
9
Refining
| Refinery | Region | Nelson Complexity Index | Throughput Capacity (in barrels per day) | PADD | Crude Processed (1) | Source (1) | Refinery | Region | Nelson Complexity Index (1) | Throughput Capacity (in barrels per day) (1) | PADD | Crude Processed (2) | Source (2) | |||||||||||||
| Delaware City | East Coast | 11.3 | 190,000 | 1 | light sweet through heavy sour | water, rail | Delaware City | East Coast | 13.6 | 180,000 | 1 | light sweet through heavy sour | water, rail | |||||||||||||
| Paulsboro | East Coast | 13.2 | 180,000 | 1 | light sweet through heavy sour | water | Paulsboro | East Coast | 8.8(3) | 155,000(3) | 1 | light sweet through heavy sour | water | |||||||||||||
| Toledo | Mid-Continent | 9.2 | 170,000 | 2 | light sweet | pipeline, truck, rail | Toledo | Mid-Continent | 11.0 | 180,000 | 2 | light sweet | pipeline, truck, rail | |||||||||||||
| Chalmette | Gulf Coast | 12.7 | 189,000 | 3 | light sweet through heavy sour | water, pipeline | Chalmette | Gulf Coast | 13.0 | 185,000 | 3 | light sweet through heavy sour | water, pipeline | |||||||||||||
| Torrance | West Coast | 14.9 | 155,000 | 5 | medium and heavy | pipeline, water, truck | Torrance | West Coast | 13.8 | 166,000 | 5 | medium and heavy | pipeline, water, truck | |||||||||||||
| Martinez | Martinez | West Coast | 16.1 | 157,000 | 5 | 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 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 East Coast Refining Reconfiguration and subsequent restart of several idled processing units at the Paulsboro refinery, our Nelson Complexity Index and throughput capacity were reduced.
Logistics
PBFX, is a fee-based, growth-oriented, publicly-traded Delaware MLP formed byan indirect wholly-owned subsidiary of PBF Energy to ownand PBF LLC, owns or lease, operate, developleases, operates, develops and acquireacquires 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 PBF Energy in support of its refineries, as well as for third-party customers. As of December 31, 2019, a substantialThe majority of PBFX’s revenues are derived from long-term, fee-based commercial agreements with PBF Holding, 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 PBF Holding to PBFX. These transactions, other than those with third parties, are eliminated by us in consolidation.
See “Item 1A. Risk Factors” and “Item 13. Certain Relationships and Related Transactions, and Director Independence.”
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Recent Developments
On February 1, 2020, we acquired from Equilon EnterprisesJuly 27, 2022, PBF Energy, PBF LLC, d/b/PBFX Holdings Inc., a Shell Oil Products US (the "Seller"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 (“Merger Sub”), 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 Martinez refinerypublicly held common units in PBFX representing limited partner interests in the MLP not already owned by certain wholly-owned subsidiaries of PBF Energy and related logistics assets (collectively,its affiliates on the “Martinez Acquisition”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 saleshare of Class A Common Stock, par value $0.001 per share, of PBF Energy (the “PBF Energy Common Stock,” and purchase agreement dated June 11, 2019 (the “Salesuch consideration, the “Stock Consideration”), (ii) $9.25 in cash, without interest (together with the Stock Consideration, the “Merger Consideration”), and Purchase Agreement”). The Martinez refinery is located on an 860-acre site(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 Cityissuance of Martinez, 30 miles northeast8,864,684 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 San Francisco, California.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 project will incorporate certain existing idled assets at the refinery, is a high-conversion 157,000 bpd, dual-coking facilityincluding an idle hydrocracker, along with a Nelson Complexity Indexnewly-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 16.1, making it onecommencing operations in the first half of 2023.
Additionally, as disclosed in “Note 24, Subsequent Events”, on February 15, 2023 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 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. The Martinez Acquisition further increases our total throughput capacity to over 1,000,000 bpd.
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 reportsAnnual Reports on Form 10-K, quarterly reportsQuarterly Reports on Form 10-Q, current reportsCurrent Reports on Form 8-K, and any other materials filed with (or furnished to) the U.S. Securities and Exchange Commission (“SEC”)SEC by us are available on our website (under “Investors”) free of charge, soon after we file or furnish such material. In this same location, we also post our corporate governance guidelines, code of business conduct and ethics, and the charters of the committees of our boardBoard of directors.Directors. These documents are available free of charge in print to any stockholder that makes a written request to the Secretary, PBF Energy Inc., One Sylvan Way, Second Floor, Parsippany, New Jersey 07054.
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The diagram below depicts our organizational structure as of December 31, 2019:2022:
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Operating Segments
We operate in two reportable business segments: Refining and Logistics. Our fivesix oil refineries, including certain related logistics assets that are not owned by PBFX, are engaged in the refining of crude oil and other feedstocks into petroleum products, and are aggregated intorepresent the Refining segment. PBFX operates certain logistics assets such as crude oil and refined petroleum products terminals, pipelines and storage facilities. Certain of PBFX’s assets were previously operated and owned by various subsidiaries of PBF Holding and were acquired by PBFX in a series of transactions since its inception. PBFX is reported in the Logistics segment. A substantial majority of PBFX’s revenues are derived from long-term, fee-based commercial agreements with PBF Holding and its subsidiaries and these intersegment related revenues are eliminated in consolidation. See “Note 2120 - Segment Information” of our Notes to Consolidated Financial Statements, for detailed information on our operating results by business segment.
Refining Segment
Our refinery assets as of December 31, 20192022 are described below.
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 itsour crude unloading facilities, or via ship or barge at itsthe 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 (the “Truck Rack”) located adjacent to the refinery and a 23-mile interstate pipeline (the “DCR Products Pipeline”) that are used to distribute clean products. The DCR Products PipelinePaulsboro refinery is located on approximately 950-acres on the Delaware River in Paulsboro, New Jersey, near Philadelphia and Truck Rack were sold to PBFX in May 2015.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 cokingprocessing refineries, the other being our Paulsboro refinery, on the East Coast of the United States withStates. 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 fluid catalytic crackingFCC unit, (“FCC unit”), 52,00054,500 bpd fluid coking unit and 21,00024,000 bpd hydrocracking unit.
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The following table approximates the Delaware City refinery’sEast Coast Refining System’s current major process unit capacities. Unit capacities are shown in barrels per stream day.
Nameplate Capacity | |||||||||
| Crude Distillation Unit | |||||||||
| Vacuum Distillation Unit | |||||||||
| Fluid Catalytic Cracking Unit | 82,000 | ||||||||
| Hydrotreating Units | |||||||||
| Hydrocracking Unit | |||||||||
| Catalytic Reforming Unit | 43,000 | ||||||||
| Benzene / Toluene Extraction Unit | 15,000 | ||||||||
| Butane Isomerization Unit | 6,000 | ||||||||
| Alkylation Unit | |||||||||
| Polymerization Unit | 16,000 | ||||||||
| Fluid Coking Unit | |||||||||
| 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 and Supply Arrangements. We source our crude oil needs for Delaware City primarily through 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 oil from Saudi Aramco that is processed at the Paulsboro refinery. The crude purchased under this contract is priced off the ASCI.
Refined 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 and jet fuel. 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.
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Inventory Intermediation Agreement. On August 29, 2019,October 25, 2021, we entered into a third amended and restated inventory intermediation agreementsagreement with J. Aron, (as amended from time to time, the “Inventory(the “Third Inventory Intermediation Agreements”Agreement”), to support the operations of the Delaware City, Paulsboro and PaulsboroChalmette refineries (the “East Coast Refineries”(collectively, the “PBF Entities”). The Third Inventory Intermediation Agreement by and among J. Aron, PBF Holding and DCR expires on June 30, 2021,December 31, 2024, which term may be further extended by mutual consent of the parties to June 30, 2022.December 31, 2025.
Pursuant to eachthe Third Inventory Intermediation Agreement, J. Aron purchases and holds title to certain inventory, including crude oil, intermediate and certain finished products (the “J. Aron Products”), purchased or produced by the East Coast RefineriesPaulsboro and Delaware City refineries (and, at the election of the PBF Entities, the Chalmette refinery) (the "Refineries") and delivered into the Company’sour storage tanks at the Delaware City and Paulsboro refineries and at PBFX’s East Coast Storage Assets (collectively the “J. Aron StorageRefineries (the “Storage Tanks”). Furthermore, J. Aron agrees to sell theThe J. Aron Products are sold back to the East Coast Refineriesus as the J. Aron Products are discharged out of our J. Aron Storage Tanks. At expiration or termination of the Third Inventory Intermediation Agreement, we will have to repurchase the inventories outstanding under the Third Inventory Intermediation Agreement at that time.
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.
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.
| Refinery Units | Nameplate Capacity | ||||||||
| Crude Distillation Unit | |||||||||
| Fluid Catalytic Cracking Unit | |||||||||
| Hydrotreating Units | 95,000 | ||||||||
| Hydrocracking Unit | |||||||||
| Catalytic Reforming Units | |||||||||
| Alkylation Unit | |||||||||
| Polymerization Unit | 7,000 | ||||||||
| UDEX Unit | 16,300 | ||||||||
Feedstocks and Supply Arrangements. We source our crude oil needs for the Toledo refinery 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.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 Toledo’sthe 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 had an initial three-year term,expires in June 2025, subject to certain early termination rights. In March 2019, the agreement was renewed and extended for a three-year term. 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. A portion of storage capacity dedicated to crude oil and finished products was sold to PBFX in conjunction with its acquisition of the Toledo Storage Facility (as defined below) in December 2014.
Energy and Other Utilities. Under normal operating conditions, the Toledo refinery consumes approximately 20,00025,000 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 189,000185,000 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 and T&M Terminal Company, 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;products. There is also a clean products truck rack whichthat provides access to local markets;markets and crude storage. We are currently progressing on our renewable diesel project that will be located at our Chalmette refinery. The project will incorporate certain existing idled assets at the refinery, including an idle hydrocracker, along with a crude and product storage facility.newly-constructed pre-treatment unit to establish a 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.
| Refinery Units | Nameplate Capacity | ||||||||
| Crude Distillation Units | |||||||||
| Vacuum Distillation Unit | 114,000 | ||||||||
| Fluid Catalytic Cracking Unit | |||||||||
| Hydrotreating Units | |||||||||
| Delayed Coking Unit | |||||||||
| Catalytic Reforming Unit | |||||||||
| Alkylation Unit | |||||||||
| 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, as well as our marine terminal. On November 1, 2015, we entered into a market-based crude supply agreement with Petróleos de Venezuela S.A. (“PDVSA”) that has a ten-year term with a renewal option for an additional five years, subject to certain early termination rights. The pricing for the crude supply isterminal, and through short-term and spot market based and is agreed upon on a quarterly basis by both parties. We have not sourced crude oil under this agreement since 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.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 Pipelinepipeline and T&M Terminalterminal provides the Chalmette refinery with strategic access to Southeast and East Coast markets through third-party logistics.
Inventory Intermediation Agreement. At the election of the PBF Entities, certain inventory at 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 19,00025,000 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 acres750-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 includesacquisition 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. Additionally, included in the refinerythere are several pipelines whichserving 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.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.
| Refinery Units | Nameplate Capacity | ||||||||
| Crude Distillation Unit | |||||||||
| Vacuum Distillation Unit | 102,000 | ||||||||
| Fluid Catalytic Cracking Unit | |||||||||
| Hydrotreating Units | |||||||||
| Hydrocracking Unit | |||||||||
| Alkylation Unit | |||||||||
| Delayed Coking Unit | |||||||||
Feedstocks and Supply Arrangements. The Torrance refinery primarily processes a variety of medium and heavy crude oils. On July 1, 2016, we entered intoWe have a crude supply agreement with Exxon Mobil Oil Corporation (“ExxonMobil”)ExxonMobil for approximately 60,000 bpd of crude oil that can be processed at our Torrance refinery. This crude supply agreement has a five-year term with an automatic renewal feature, unless either party gives thirty-six months written notice of its intent to terminate the agreement.termination notice. Additionally, we obtain crude and feedstocks from other sources through connections to third-party pipelines as well as ship docks and truck racks.
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. On July 1, 2016, we entered into an offtake agreement with ExxonMobil pursuant to which ExxonMobil purchased up to 50% of our gasoline production. This offtake agreement had an initial term of three years and was not renewed upon expiration on July 1, 2019. 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 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.
| 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 entered into various five-year crude supply agreements with Shell Oil Products for approximately 150,000 bpd, in the aggregate, to support our West Coast and Mid-Continent refinery operations. Additionally, we obtain crude and feedstocks from other sources through connections to third-party pipelines as well as ship docks.
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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Logistics Segment
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, 2019, 20182022, 2021 and 2017,2020, gasoline and distillates accounted for 86.8%88.5%, 84.7%86.2% and 84.1%84.7% 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. However,In addition, we do have product offtake arrangements for a portion of our clean products. For the years ended December 31, 2019, 20182022 and 2017, no singleDecember 31, 2021 only one customer, Shell plc (“Shell”), accounted for 10% or more of our revenues respectively.(approximately 14% and 15% respectively). As of December 31, 20192022 and December 31, 2018, no single2021, only one customer, Shell, accounted for 10% or more of our total trade accounts receivable.receivable (approximately 19% and 26%, respectively).
Seasonality
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.
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The refining industry is 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.
Corporate Offices
We currently lease approximately 58,00063,000 square feet for our principal corporate offices in Parsippany, New Jersey. The lease for our principal corporate offices expires in 2022.2026. Functions performed in the Parsippany office include overall corporate management, refinery and HSEhealth, 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 4,0008,800 square feet for our regional corporate office in Long Beach, California. The lease for our Long Beach office expires in 2021.2026. Functions performed in the Long Beach office include overall regional corporate management, planning and strategy, commercial operations, logistics, contract administration, marketing and governmental affairs.
We lease approximately 5,000 square feet for our regional corporate office in The Woodlands, Texas. The lease for The Woodlands office expires in 2022.2032. Functions performed in The Woodlands include pipeline control center operations and logistics operations, engineering and regulatory support functions.
Employees and Human Capital
Safety
We believe our responsibility to our employees, neighbors, shareholders, 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.
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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.
Headcount
As of December 31, 2019,2022, we had approximately 3,4423,616 employees, of which 1,7131,912 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 | — | N/A | N/A | |||||||||||||||||||||||||
| Delaware City refinery | 525 | 372 | USW | January 2026 | |||||||||||||||||||||||||
| Paulsboro refinery | 270 | 174 | IOW | March 2026 | |||||||||||||||||||||||||
| Toledo refinery | 490 | 297 5 | USW USW | February 2026 February 2026 | |||||||||||||||||||||||||
| Chalmette refinery | 582 | 323 | USW | January 2026 | |||||||||||||||||||||||||
| Torrance refinery | 588 | 319 11 | USW IBEW | January 2026 January 2026 | |||||||||||||||||||||||||
| Torrance logistics | 96 | 41 4 | USW USW | April 2024 January 2026 | |||||||||||||||||||||||||
| Martinez refinery | 561 | 304 14 | USW IBEW | February 2026 February 2026 | |||||||||||||||||||||||||
| Other Logistics assets | 90 | 23 10 15 | USW-East Coast Storage Assets USW- East Coast Terminals USW- East Coast Terminals | January 2026 April 2024 March 2028 | |||||||||||||||||||||||||
| Total employees | 3,616 | 1,912 | |||||||||||||||||||||||||||
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| Location | Number of employees | Employees covered by collective bargaining agreements | Collective bargaining agreements | Expiration date | ||||
| Headquarters | 414 | — | N/A | N/A | ||||
| Delaware City refinery | 558 | 377 | USW | January 2022 | ||||
| Paulsboro refinery | 486 | 294 | IOW | March 2022 | ||||
| Toledo refinery | 550 | 333 | USW | February 2022 | ||||
| Chalmette refinery | 612 | 301 | USW | January 2022 | ||||
| Torrance refinery | 616 | 311 12 | USW IBEW | January 2022 January 2022 | ||||
| Torrance logistics | 114 | 47 4 | USW USW | April 2021 January 2022 | ||||
| PBFX | 92 | 24 10 | USW-East Coast Storage Assets USW- East Coast Terminals | January 2022 April 2024 | ||||
| Total employees | 3,442 | 1,713 | ||||||
Information About Our Executive Officers
The following is a list of our executive officers as of February 20, 2020:
16, 2023:
| Name | Age (as of December 31, | Position | ||||||||||||
| Thomas | Chief Executive Officer and Chairman of the Board of Directors | |||||||||||||
| Matthew | President | |||||||||||||
| Interim Chief Financial Officer | ||||||||||||||
| Paul Davis | 60 | Senior Vice President, | ||||||||||||
| Senior Vice President, | ||||||||||||||
| Trecia Canty | Senior Vice President, General Counsel & Corporate Secretary | |||||||||||||
| Steven Steach | 66 | Senior Vice President, Refining | ||||||||||||
| Wendy Ho Tai | 56 | Senior Vice President, Human Resources | ||||||||||||
| Jim Fedena | 58 | Senior Vice President, Logistics, Renewable Fuels, and Strategic Assets | ||||||||||||
Thomas J. Nimbley has served as our Chief Executive Officer since June 2010 and on our Board of Directors since October 2014. He has served as the Chairman of our Board since July 2016. He was our Executive Vice President, Chief Operating Officer from March 2010 through June 2010. In his capacity as our Chief Executive Officer, Mr. Nimbley also serves as a director and the Chief Executive Officer of certain of our subsidiaries, and our affiliates, including Chairman of the Board of PBFPBFX 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.
Matthew C. Lucey has served as our President since January 2015 and was our Executive Vice President from April 2014 to December 2014. Mr. 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 our subsidiaries, including PBFPBFX 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.
Paul Davis has served as our Senior Vice President, Supply, Trading and Optimization since April 2022. He previously served as President, PBF Western Region sincefrom September 2017.2017 to April 2022. Mr. Davis joined us in April of 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
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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 Corporation in various operational and commercial positions, including sourcing refinery feedstocks and crude oil and the disposition of refined petroleum products, as well as optimization roles within refineries.
Thomas L. O’Connor has served as our Senior Vice President, Commodity Risk and Strategy since April 2022. He previously served as Senior Vice President, Commercial sincefrom September 2015.2015 to April 2022. Mr. O’Connor joined us 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 our 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.
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 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.
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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 may have capital needs for whichcould incur substantial costs or disruptions in our internally generated cash flowsbusiness if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with health, safety, environmental and other sources of liquiditylaws and regulations;
◦Enhanced scrutiny on ESG matters and developments related to climate change may not be adequate;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”, and;
•Item 8. “Financial Statements and Supplementary Data”
◦Note 87 - Accrued Expenses,
◦Note 1110 - Other Long-Term Liabilities and
◦Note 1312 - Commitments and Contingencies
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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 1312 - Commitments and Contingencies
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ITEM 1A. RISK FACTORS
Summary of Risk Factors
Investing in our common stock 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 may have a material adverse effect on our revenues, profitability, cash flows and liquidity.services;
•Completion and Analysissuccessful commencement of Financial Conditioncommercial operation of the renewable diesel project;
•Enhanced scrutiny on ESG matters;
•Ability to realize the anticipated benefits of the Merger Transaction;
•Rate of inflation and Results of Operations.” Our liquidity condition will affectits impacts on supply and demand, pricing, and supply chain disruption;
•Actions taken by our abilitycompetitors, including adjustments to satisfy anyrefining capacity or renewable fuels production in response to regulations and all of these needs or obligations.market conditions;
•Any political instability, including as a result of Russia’s military action in Ukraine, military strikes, sustained military campaigns, terrorist activity, changes in foreign policy, or other catastrophic events could have a material adverse effectevents;
•A cyber-attack on, our business, results of operations and financial condition.
•Delays or cost increases related to capital spending programs involving engineering, procurementprograms;
•Product liability claims, operational liability claims and constructionother material litigation;
•Acquisition or integration of new facilities (or improvements and repairs toassets into our existing facilities and equipment, including turnarounds) could adversely affectbusiness;
•Labor disruptions that would interfere with our ability to achieve targeted internal ratesoperations;
•Discontinuation of return and operating results. Such delays or cost increases may arise as a resultemployment of unpredictable factors in the marketplace, many of which are beyond our control, including:
•Our activity in our labor force may make it difficult for us to maintain labor productivity.
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 arising out of restrictive covenants in our debt instruments;
•Anti-takeover provisions in our indentures.
Risks Related to Our Organizational Structure and PBF Energy Class A Common Stock
•PBF Energy’s dependence upon distributions from PBF LLC and its subsidiaries to pay taxes and meet its other obligations;
•The rights of other members of PBF LLC may conflict with the interests of PBF Energy Class A common stockholders;
•Obligations under the Tax Receivable Agreement, as defined below;
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•Prospect that dividend payments may not be declared in the future;
•Anti-takeover provisions in our certificate of incorporation and bylaws and under Delaware law;
•Volatility of our stock price;
•Potential dilution of our current stockholders.
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. 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. In that case, the trading price of PBF Energy Class A common stock could fall.
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 and the trading price of PBF Energy’s Class A common stock.
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 of cost or market value under the last-in-first-out (“LIFO”) inventory valuation methodology. At December 31, 2022 and December 31, 2021, 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 and $196.7 million, respectively.
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Prices of crude oil, other feedstocks, blendstocks, and refined products depend on numerous factors beyond our control, including the supply of and demand for crude oil, other feedstocks, gasoline, diesel, ethanol, asphalt and other refined products. Such supply and demand are affected by a variety of economic, market, environmental and political conditions.
Our direct operating expense structure also impacts our profitability. Our major direct operating expenses include employee and contract labor, maintenance and energy. Our predominant variable direct operating cost is energy, which is comprised primarily of fuel and other utility services. The volatility in costs of fuel, principally natural gas, and other utility services, principally electricity, used by our refineries and other operations affect our operating costs. Fuel and utility prices have been, and will continue to be, affected by factors outside our control, such as supply and demand for fuel and utility services in both local and regional markets. Natural gas prices have historically been volatile and, typically, electricity prices fluctuate with natural gas prices. Future increases in fuel and utility prices may have a negative effect on our refining margins, profitability and cash flows.
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 in Canada to control the imbalance between its production and capacity to export crude 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.
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A significant interruption or casualty loss at any of our refineries and related assets or logistics terminals, pipelines or other facilities 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 well as logistics terminals, pipelines and other facilities. As a result, our operations could be subject to significant interruption if any of our refineries or other facilities 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 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 we 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 which 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 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 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.
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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 produce renewable fuels, increasing the volume of renewable fuels that must be blended into our products displaces 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 price of RINS was significant in 2022 and could increase further in 2023. We incurred approximately $1,225.5 million in RINs costs during the year ended December 31, 2022 as compared to $726.0 million and $326.4 million during the years ended December 31, 2021 and 2020, 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 3, 2022, EPA finalized the volumes of renewable fuels that obligated refineries must blend into their final petroleum fuels for years 2020, 2021, and 2022.On December 1, 2022, EPA 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.
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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 of our Third Inventory Intermediation Agreement with J. Aron, which is currently scheduled to expire in 2024, would require us to finance the J. Aron Products covered by the agreement, which financing may not be available at 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.
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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, on July 21, 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 regulation does not require that any specific technology be utilized to meet the new standards. The costs incurred by us to achieve the new emissions standards at our Martinez refinery within the required timeframe may be significant, and there can be no assurance that the measures we implement will achieve the required emissions reductions. Additionally, On September 16, 2022, the state of California enacted SB 1322, The California Oil Refinery Cost Disclosure Act. Effective in 2023, this bill will require operators of refineries in the state that produce gasoline meeting California specifications, within 30 days of the end of each calendar month, to submit to the State Energy Resources Conservation and Development Commission certain information regarding petroleum sales volumes and prices.
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.
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, 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
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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 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, the 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.
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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.
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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.
In 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 justified, or whether they constituted a “windfall” to the industry and have proposed legislation that if enacted 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 flows could be adversely impacted.
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.
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We may incur significant liabilities under, or costs and capital expenditures to comply with, health, safety, environmental and other laws and regulations, which are complex and change frequently. Our operations are subject to federal, state and local laws regulating, among other things, the handling of petroleum and other regulated materials, the emission and discharge of materials into the environment, waste management, and remediation of discharges of petroleum and petroleum products, characteristics and composition of gasoline and distillates and other matters otherwise relating to the protection of the environment. Our operations are also subject to extensive laws and regulations relating to occupational health and safety, in addition to laws and regulations affecting the transportation of crude oil by rail in North America.
We cannot predict what additional environmental, health and safety legislation or regulations may be adopted in the future, or how existing or future laws or regulations may be administered or interpreted with respect to our operations. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time.
Certain environmental laws impose strict, and in certain circumstances joint and several liability for, costs of investigation and cleanup of such spills, discharges or releases on owners and operators of, as well as persons who arrange for treatment or disposal of regulated materials at contaminated sites. Under these laws, we may incur liability or be required to pay penalties for past contamination, and third parties may assert claims against us for damages allegedly arising out of any past or future contamination. The potential penalties and clean-up costs for past or future releases or spills, the failure of prior owners of our facilities to complete their clean-up obligations, the liability to third parties for damage to their property, or the need to address newly-discovered information or conditions that may require a response could be significant, and the payment of these amounts could have a material adverse effect on our business, financial condition and results of operations.
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 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 Sustainable Mobility, a subsidiary of Eni SpA (“Eni”) to partner in a 50-50 joint venture, SBR which will own the renewable diesel facility upon consummation of the transaction, 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 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 transaction closes, the joint venture 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.
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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 stock price and 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 stock price and 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 vehicles and renewable power supplies. These developments may also lead to reduced demand for our products, a reduction in our revenue, higher costs and an overall decrease in our profitability.
Additionally, increased attention and scrutiny regarding climate change has resulted in increased investor attention and an increased risk of public and private litigation, which could increase our costs and/or otherwise negatively affect our operations and overall profitability, and cause the market price of our Class A common stock to decline.
We may fail to realize the anticipated benefits of the Merger Transaction.
On November 30, 2022, we completed the Merger Transaction, pursuant to which PBF Energy and PBF LLC acquired all of the publicly held common units in PBFX representing limited partner interests in the MLP not already owned by certain wholly-owned subsidiaries of PBF Energy and its affiliates. As a result of the Merger Transaction, PBFX became an indirect wholly-owned subsidiary of PBF Energy and PBF LLC. The Merger Transaction involves a number of significant risks and uncertainties that may adversely affect us, including: our inability to realize anticipated synergies or other expected benefits or cost savings; failure to successfully integrate systems, business processes, policies and procedures; exposure to unforeseen costs; higher than anticipated transaction costs; potential loss of key employees, suppliers or customers; and other challenges associated with managing the larger, more complex and integrated businesses. Many of these factors will be outside of our control and any one of these factors could materially impact our business, financial condition and results of operations. These benefits may not be achieved within the anticipated time frame, or at all. Additional unanticipated costs may be incurred in the integration of the businesses. All of these factors could negatively impact the price of our Class A common stock. As a result, we cannot assure you that the Merger Transaction will result in the realization of the benefits anticipated from the transaction.
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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 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 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 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 strategy, complete future acquisitions, 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. Although the length and impact of the ongoing military conflict is highly unpredictable, the war in 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 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 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 and could cause the market value of PBF Energy’s Class A common stock to decline.
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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.
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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 their own renewable fuels or alternative forms of energy and fuels 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.
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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.
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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 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, and any acquisitions 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 in the future within the refining and mid-stream sector based on performance through the cycle, advantageous access to crude oil supplies, attractive refined products market fundamentals and access to distribution and logistics infrastructure. Our ability to do so will be dependent upon a number of factors, including our ability to identify acceptable acquisition candidates, consummate acquisitions 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 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. 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 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 on our financial performance until we have operated the acquired refineries for a substantial period of time.
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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.”
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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 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, 2019,2022, we have total debt of $2,097.3$1,995.3 million, excluding unamortized deferred debt issuance costs of $32.4$36.2 million and our PBF LLC Affiliate note payable with PBF Energy that eliminates in consolidation at the PBF Energy level, and we could incur an additional $1,673.5 millionborrowings under our credit facilities. As disclosed in “Note 25 - Subsequent Events” of our Notes to Consolidated Financial Statements, we incurred additional debt in conjunction with the
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.
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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 and ending in 2028. Additionally, the PBF Holding’s asset-based revolving credit facility (the “Revolving Credit Facility”) and the PBFX amended and restated revolving credit facility (the “PBFX Revolving Credit Facility”) have maturity dates in 2025 and 2023, respectively. We can make no assurance that we will be able to refinance these agreements on acceptable terms prior to their maturity dates. Market disruptions or other credit factors, such as rising inflation and higher interest rates, are 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 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 currently anticipatedcurrent 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 cause us to be unable to operate one or more of our refineries at full capacity.
The 6.0% senior unsecured notes due 2028 (the “2028 Senior Notes”) and the 7.25% senior unsecured notes due 2025 (the “2025 Senior Notes”) are rated B1 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 our liquidity and make cash distributions to our shareholders.
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Restrictive covenants in our debt instruments, including the indentures governing our notes, may limit our ability to undertake certain types of transactions.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 subjectsand 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, pay dividends 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 theseour debt instruments also require our subsidiaries to satisfy or maintain certain financial condition tests in certain circumstances. Our subsidiaries’ ability to meet these financial condition tests can be affected by events beyond our control and theywe may not meet such teststests. 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 future.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 Senior Notes (as defined below),and the 2028 Senior Notes, and the PBFX 2023 Senior Notes (as defined below and in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results
Risks Related to Our Organizational Structure and PBF Energy Class A Common Stock
PBF Energy is the managing member of PBF LLC and its only material asset is its interest in PBF LLC. Accordingly, PBF Energy depends upon distributions from PBF LLC and its subsidiaries to pay its taxes, meet its other obligations and/or pay dividends in the future.
PBF Energy is a holding company and all of its operations are conducted through subsidiaries of PBF LLC. PBF Energy has no independent means of generating revenue and no material assets other than its ownership interest in PBF LLC. We depend on the earnings and cash flow of our subsidiaries to meet our obligations, including our indebtedness, tax liabilities and obligations to make payments under a tax receivable agreement entered into with PBF LLC Series A and PBF LLC Series B unitholders (the “Tax Receivable Agreement”). If we do not receive such cash distributions, dividends or other payments from our subsidiaries, we may be unable to meet our obligations and/or pay dividends.
PBF Energy, as the sole managing partner of PBF LLC, may cause PBF LLC to make distributions to its members in an amount sufficient to enable PBF Energy to cover all applicable taxes at assumed tax rates, to make payments owed by PBF Energy under the Tax Receivable Agreement, and to pay other obligations and dividends, if any, declared by PBF Energy. To the extent we need funds and any of our subsidiaries is restricted from making such distributions under applicable law or regulation or under the terms of our financing or other contractual arrangements, or is otherwise unable to provide such funds, such restrictions could materially adversely affect our liquidity and financial condition.
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The Revolving Credit Facility, the 2028 Senior Notes, the 2025 Senior Notes, and certain of our other outstanding debt arrangements include a restricted payment covenant, which restricts the ability of PBF Holding to make distributions to us, and we anticipate our future debt will contain a similar restriction. The PBFX Revolving Credit Facility and PBFX’s indenture governing its PBFX 2023 Senior Notes also containcontains covenants that limit or restrict PBFX’s ability and the ability of its restricted subsidiaries to make distributions and other restricted payments and restrict PBFX’s ability to incur liens and enter into burdensome agreements. In addition, there may be restrictions on payments by our subsidiaries under applicable laws, including laws that require companies to maintain minimum amounts of capital and to make payments to stockholders only from profits. For example, PBF Holding is 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, and PBFX is subject to a similar prohibition. As a result, we may be unable to obtain that cash to satisfy our obligations and make payments to PBF Energy stockholders, if any.
The rights of other members of PBF LLC may conflict with the interests of PBF Energy Class A common stockholders.
The interests of the other members of PBF LLC, which include current and former directors and officers, may not in all cases be aligned with PBF Energy Class A common stockholders’ interests. For example, these members may have different tax positions which could influence their positions, including regarding whether and when we dispose of assets and whether and when we incur new or refinance existing indebtedness, especially in light of the existence of the Tax Receivable Agreement. In addition, the structuring of future transactions may take into consideration these tax or other considerations even where no similar benefit would accrue to PBF Energy Class A common stockholders or us. See “Certain Relationships and Related Transactions—IPO Related Agreements” in our 20202023 Proxy Statement incorporated herein by reference.
Under the Tax Receivable Agreement, PBF Energy is required to pay the former and current holders of PBF LLC Series A Units and PBF LLC Series B Units for certain realized or assumed tax benefits PBF Energy may claim arising in connection with prior offerings and future exchanges of PBF LLC Series A Units for shares of its Class A common stock and related transactions. The indentures governing the senior notes allow PBF LLC, under certain circumstances, to make distributions sufficient for PBF Energy to pay its obligation under the Tax Receivable Agreement, and such amounts are expected to be substantial.Agreement.
PBF Energy is party to a Tax Receivable Agreement that provides for the payment from time to time by PBF Energy to the current and former holders of PBF LLC Series A Units and PBF LLC Series B Units of 85% of the benefits, if any, that PBF Energy is deemed to realize as a result of (i) the increases in tax basis resulting from its acquisitions of PBF LLC Series A Units, including such acquisitions in connection with its prior offerings or in the future and (ii) certain other tax benefits related to its entering into the Tax Receivable Agreement, including tax benefits attributable to payments under the Tax Receivable Agreement. See “Item 13. Certain Relationships and Related Transactions, and Director Independence.”
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PBF Energy may make under the Tax Receivable Agreement will be substantial. Ashas recognized, as of December 31, 2019, PBF Energy has recognized2022, a liability for the Tax Receivable Agreement of $373.5$338.6 million, reflecting PBF Energy’s estimate of the estimated undiscounted amounts that itPBF Energy expects to pay under the agreement due to exchanges that occurred prior to that date, and to range overagreement. As future taxable income is recorded, increases in our Tax Receivable Agreement liability may be necessary in conjunction with the next five years from approximately $13.0 million to $86.0 million per year and decline thereafter. Future payments by PBF Energy in respectrevaluation of subsequent exchanges of PBF LLC Series A Units would be in addition to these amounts and are expected to be material as well.deferred tax assets. If PBF Energy does not have taxable income, PBF Energy generally is not required (absent a change of control or circumstances requiring an early termination payment) to make payments under the Tax Receivable Agreement for that taxable year because no benefit will have been actually realized. However, any tax benefits that do not result in realized benefits in a given tax year will likely generate tax attributes that may be utilized to generate benefits in previous or future tax years. The utilization of such tax attributes will result in payments under the Tax Receivable Agreement. The foregoing numbers are merely estimates based on assumptions that are subject to change due to various factors, including, among other factors, the timing of exchanges of PBF LLC Series A Units for shares of PBF Energy Class A common stock as contemplated by the Tax Receivable
Agreement, the price of PBF Energy Class A common stock at the time of such exchanges, the extent to which such exchanges are taxable, and the amount and timing of PBF Energy’s income. The actual payments under the Tax Receivable Agreement could differ materially. It is possible that future transactions or events could increase or decrease the actual tax benefits realized and the corresponding Tax Receivable Agreement payments. There may be a material negative effect on our liquidity if, as a result of timing discrepancies or otherwise, (i) the payments under the Tax Receivable Agreement exceed the actual benefits PBF Energy realizes in respect of the tax attributes subject to the Tax Receivable Agreement, and/or (ii) distributions to PBF Energy by PBF LLC are not sufficient to permit PBF Energy, after it has paid its taxes and other obligations, to make payments under the Tax Receivable Agreement. The payments under the Tax Receivable Agreement are not conditioned upon any recipient’s continued ownership of us.
In certain cases, payments by PBF Energy under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits it realizes in respect of the tax attributes subject to the Tax Receivable Agreement. These provisions may deter a change in control of the Company.
The Tax Receivable Agreement provides that upon certain changes of control, or if, at any time, PBF Energy elects an early termination of the Tax Receivable Agreement, PBF Energy’s (or its successor’s) obligations with respect to exchanged or acquired PBF LLC Series A Units (whether exchanged or acquired before or after such transaction) would be based on certain assumptions, including (i) that PBF Energy would have sufficient taxable income to fully utilize the deductions arising from the increased tax deductions and tax basis and other benefits related to entering into the Tax Receivable Agreement and (ii) that the subsidiaries of PBF LLC will sell certain nonamortizable assets (and realize certain related tax benefits) no later than a specified date. Moreover, in each of these instances, PBF Energy would be required to make an immediate payment equal to the present value (at a discount rate equal to LIBORthe London Interbank Offering Rate (“LIBOR”) plus 100 basis points) of the anticipated future tax benefits (based on the foregoing assumptions). Accordingly, payments under the Tax Receivable Agreement may be made years in advance of the actual realization, if any, of the anticipated future tax benefits and may be significantly greater than the actual benefits PBF Energy realizes in respect of the tax attributes subject to the Tax Receivable Agreement. Assuming that the market value of a share of PBF Energy Class A common stock equals $31.37 per share (the closing price on December 31, 2019) and that LIBOR were to be 1.85%, we estimate that, as of December 31, 2019 the aggregate amount of these accelerated payments would have been approximately $326.9 million if triggered immediately on such date. In these situations, PBF Energy’s obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity. PBF Energy may not be able to finance its obligations under the Tax Receivable Agreement and its existing indebtedness may limit its subsidiaries’ ability to make distributions to PBF Energy to pay these obligations. These provisions may deter a potential sale of our Company to a third-party and may otherwise make it less likely that a third-party would enter into a change of control transaction with us.
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Moreover, 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. PBF Energy will not be reimbursed for any payments previously made under the Tax Receivable Agreement if the Internal Revenue ServiceIRS subsequently disallows part or all of the tax benefits that gave rise to such prior payments. As a result, in certain circumstances, payments could be made under the Tax Receivable Agreement that are significantly in excess of the benefits that PBF Energy actually realized in respect of (i) the increases in tax basis resulting from our purchases or exchanges of PBF LLC Series A Units and (ii) certain other tax benefits related to PBF Energy entering into the Tax Receivable Agreement, including tax benefits attributable to payments under the Tax Receivable Agreement.
PBF Energy cannot assure you that it will continue to declare dividends or have the available cash to make dividend payments.
Although PBF Energy currently intends to continue to pay quarterly cash dividends on its Class A common stock, the declaration, amount and payment of any dividends will be at the sole discretion of our boardBoard of directors.Directors. PBF Energy is not obligated under any applicable laws, its governing documents or any contractual agreements with its existing and prior 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). Our boardBoard of directorsDirectors may take into account, among other things, general economic conditions, our financial condition and operating results, our available cash
and current and anticipated cash needs, capital requirements, plans for expansion, including acquisitions, tax, legal, regulatory and contractual restrictions and implications, including under our subsidiaries’ outstanding debt documents, and such other factors as our boardBoard of directorsDirectors may deem relevant in determining whether to declare or pay any dividend. Because PBF Energy is a holding company with no material assets (other than the equity interests of its direct subsidiary), its cash flow and ability to pay dividends is dependent upon the financial results and cash flows of its indirect subsidiaries PBF Holding and PBFX and their respective operating subsidiaries and the distribution or other payment of cash to it in the form of dividends or otherwise. The direct and indirect subsidiaries of PBF Energy are separate and distinct legal entities and have no obligation to make any funds available to it other than in the case of certain intercompany transactions. As a result, if PBF Energy does not declare or pay dividends you may not receive any return on an investment in PBF Energy Class A common stock unless you sell PBF Energy Class A common stock for a price greater than that which you paid for it.
Anti-takeover and certain other provisions in our certificate of incorporation and bylaws and Delaware law may discourage or delay a change in control.
Our certificate of incorporation and bylaws contain provisions which could make it more difficult for stockholders to effect certain corporate actions. Among other things, these provisions:
•authorize the issuance of undesignated preferred stock, the terms of which may be established and the shares of which may be issued without stockholder approval;
•prohibit stockholder action by written consent;
•restrict certain business combinations with stockholders who obtain beneficial ownership of a certain percentage of our outstanding common stock;
•provide that special meetings of stockholders may be called only by the chairman of the boardBoard of directors,Directors, the chief executive officer or the boardBoard of directors,Directors, and establish advance notice procedures for the nomination of candidates for election as directors or for proposing matters that can be acted upon at stockholder meetings; and
•provide that our stockholders may only amend our bylaws with the approval of 75% or more of all of the outstanding shares of our capital stock entitled to vote.
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These anti-takeover provisions and other provisions of Delaware law may have the effect of delaying or deterring a change of control of our company. Certain provisions could also discourage proxy contests and make it more difficult for you and other stockholders to elect directors of your choosing and to cause us to take other corporate actions you desire. These provisions could limit the price that certain investors might be willing to pay in the future for shares of PBF Energy Class A common stock.
The market price of PBF Energy Class A common stock may be volatile, whichand you could cause the valuelose all or part of your investment to decline.investment..
The market price of PBF Energy Class A common stock has in the past been and may continue to be highly volatile and could be subject to wide fluctuations due to a number of factors including:
•market conditions in the oil refining industry and volatility in commodity prices;
•changes in, or failure to meet, earnings estimates of securities analysts;
•variations in actual or anticipated operating results or dividends, if any, to stockholders;
•the impact of disruptions to crude or feedstock supply to any of our refineries, including disruptions due to problems with third-party logistics infrastructure;
•litigation and government investigations;
•the timing and announcement of any potential acquisitions or divestitures and subsequent impact of any future acquisitions or divestitures on our capital structure, financial condition or results of operations;
•changes or proposed changes in laws or regulations or differing interpretations or enforcement thereof;
•general economic and stock market conditions; and
•the availability for sale, or sales by PBF Energy or its senior management, of a significant number of shares of its Class A common stock in the public market.
In recent years, the stock market in general, and the market for energy companies in particular, has experienced significant price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of those companies. This volatility has had a significant impact on the market price of securities issued by many companies, including companies in our industry. In addition, the stock markets generally may experience significant volatility, often unrelated to the operating performance of the individual companies whose securities are publicly-traded. These and other factors may cause the market price of PBF Energy Class A common stock to decrease significantly, which in turn would adversely affect the value of your investment.
In the past, following periods of volatility in the market price of a company’s securities, stockholders have often instituted class action securities litigation against those companies. Such litigation, if instituted, could result in substantial costs and a diversion of management’s attention and resources, which could significantly harm our profitability and reputation.
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Our Ownershipcurrent stockholders could experience dilution, which could further depress the price of PBFXour Class A common stock.
We depend upon PBFX for acontinue to require substantial portionworking capital to fund our business. We may sell equity securities or convertible securities or other derivative securities in the public or private markets if we continue to need capital, and even when conditions or terms are not otherwise favorable, including at prices at or below the then current market price of our refineries’ logistics needsshares of Class A common stock. As a result, stockholders may experience substantial dilution, and have obligationsthe market price of our Class A common stock could decline as a result of the introduction of a large number of shares of our Class A common stock, or securities convertible into or exchangeable or exercisable for minimum volume commitments in our commercial agreements with PBFX.
PBF Energy will be required to pay taxes on its share of taxable income from PBF LLC and its other subsidiary flow-through entities, (including PBFX), regardless of the amount of cash distributions PBF Energy receives from PBF LLC.
The holders of limited liability company interests in PBF LLC, including PBF Energy, generally have to include for purposes of calculating their U.S. federal, state and local income taxes their share of any taxable income of PBF LLC, regardless of whether such holders receive cash distributions from PBF LLC. PBF Energy ultimately may not receive cash distributions from PBF LLC equal to its share of the taxable income of PBF LLC or even equal to the actual tax due with respect to that income. For example, PBF LLC is required to include in taxable income PBF LLC’s allocable share of PBFX’s taxable income and gains (such share to be determined pursuant to the partnership agreement of PBFX), regardless of the amount of cash distributions received by PBF LLC from PBFX, and such taxable income and gains will flow-through to PBF Energy to the extent of its allocable share of the taxable income of PBF LLC. As a result, at certain times, the amount of cash otherwise ultimately available
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
See “Item 1. Business”.
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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,ten-year, $100.0 million environmental insurance policy to insure against unknown environmental liabilities. Furthermore, in connection with
On April 17, 2019, we received a Notice of Violation (“NOV”) from the acquisition, we assumed responsibility for certain specified environmental matters that occurred prior to our ownership of the refinery and logistics assets, including specified incidents and/or NOVs issued by regulatory agencies in various years before our ownership, including the Southern CaliforniaSouth Coast Air Quality Management District (“SCAQMD”) and the Division of Occupational Safety and Health of the State of California (“Cal/OSHA”).
$736,845. On December 5, 1990, prior to15, 2022, the SCAQMD accepted our ownership of the Chalmette refinery, the plaintiff in Adam Thomas, et al. v. Exxon Mobil Corporation and Chalmette Refining, L.L.C., filed an action on behalf of himself and potentially thousands of other individuals in St. Bernard Parish and Orleans Parish who were allegedly exposed to hydrogen sulfide and sulfur dioxide as a result of more than 100 separate flaring events that occurred between 1989 and 2010. This litigation is proceeding as a mass action with individually named plaintiffs as a result of a 2008 trial court decision, affirmed by the court of appeals that denied class certification.counter proposal. The plaintiffs claim to have suffered physical injuries, property damage, and other damages as a result of the releases. Plaintiffs seek to recover unspecified compensatory and punitive damages, interest, and costs. The Court had scheduled an October 2019 mini-trial of up to 10 plaintiffs, relating to as many as 5 separate flaring events that occurred between 2002 and 2007. However, on October 9, 2019, the parties reached an agreement in principle to settle this matter, which is expected to result in the dismissal with prejudice of all outstanding claims. Althoughare currently drafting the settlement resolution has not been finalized, we presently believe the outcome will not have a material impact on our financial position, results of operations, or cash flows.agreement.
On February 17, 2017, in Arnold Goldstein, et al. v. Exxon Mobil Corporation, et al., we and PBF LLC, and our subsidiaries, PBF Western Region and Torrance Refining and the manager of our Torrance refinery along with ExxonMobil were named as defendants in a class action and representative action complaint filed on behalf of Arnold Goldstein, John Covas, Gisela Janette La Bella and others similarly situated. The complaint was filed in the Superior Court of the State of California, County of Los Angeles (the “Court”) and alleges negligence, strict liability, ultrahazardousultra-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”) explosion 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 acquisition in July 2016 is also referenced in the complaint. To the extent that plaintiffs’ claims relate to the ESP explosion, ExxonMobil has retained responsibility for any liabilities that would arise from the lawsuit pursuant to the agreement relating to the acquisition of the Torrance refinery. On July 2, 2018, the Court granted leave to plaintiffs’plaintiffs to file a Second Amended Complaint alleging groundwater contamination. With the filing of the Second Amended Complaint, Plaintiffs’plaintiffs added an additional plaintiff. On March 18, 2019, the class certification hearing was held and the judge took the matter under submission. On April 1, 2019, the judge issued an order denying class certification. On April 15, 2019, Plaintiffs filed a Petition with the Ninth Circuit for Permission to Appeal the Order Denying Motion for Class Certification. The appeal is currently pending with the Ninth Circuit. On May 3, 2019, Plaintiffs filed a Motion with the Central District Court for Leave to File a Renewed Motion for Class Certification. On May 22, 2019, the judge granted Plaintiffs’ motion. We filed our opposition to the motion on July 29, 2019. The Plaintiffs’ motion was heard on September 23, 2019.plaintiff, Hany Youssef. On October 15, 2019, the judge granted certification to two limited classes of property owners with Youssef as the sole class 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 claims for ground contamination and nuisance for air emissions. On February 5, 2021, our motion for Limited Extension of Discovery Cut-Off and a Motion by plaintiffs for Leave to File Third Amended Complaint were heard by the Court. On May 5, 2021, the Court granted plaintiffs leave to amend their complaint for the third time to substitute Navarro for Youssef. On May 12, 2021, plaintiffs filed their Third Amended Complaint (“TAC”) that contained significant changes and new claims, including 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 to Dismiss/Strike the TAC. On June 23, 2021, plaintiffs filed their opposition to our Motion to Dismiss/Strike, to which we filed our reply on July 2, 2021. A hearing on the Motion to Dismiss/Strike the TAC was held on August 2, 2021 and the Court ordered that the TAC be struck and that the parties meet and confer with respect to the complaint. After meeting and conferring, plaintiffs agreed to submit a corrected TAC with changes reflecting the removal of Youssef and the substitution of Navarro as the named Plaintiff. On August 23, 2021, the Court approved the parties’ stipulation to take Navarro’s deposition on September 23, 2021. Also, on August 23, 2021, the Court approved the parties’ stipulation to continue the pretrial dates with the new deadlines. On October 8, 2021, plaintiffs filed their 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’s Motion 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. The order provided that the
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case will proceed with Navarro as the sole plaintiff and required the parties to meet and confer and propose a schedule for the remaining pretrial dates and a trial date. On July 19, 2022, Plaintiff filed a petition with the Ninth Circuit Court of Appeals seeking permission to appeal the District Court’s decertification order finding that Navarro is an inadequate class representative. Our answer to the petition was filed on July 29, 2022. On September 22, 2022, the Ninth Circuit issued an order denying Plaintiffs’ petition for permission to file an interlocutory appeal, confirming that the case will proceed with Navarro as the sole plaintiff. On September 27, 2022, the Plaintiff filed a schedule of pretrial and trial dates with a trial date of July 18, 2023, which was approved by the Court. On January 13, 2023, the Defendants filed a motion for judgment on the pleadings. On January 23, 2023, the Plaintiff filed its opposition to the Defendants’ motion. Defendants’ reply to Plaintiff’s opposition was filed on January 30, 2023. Defendants’ motion was scheduled to be heard by the Court on February 13, 2023. On February 13, 2023, the Court issued a minute order taking the February 13th hearing off the calendar and under submission. A new hearing date will be scheduled if the Court decides oral argument would be helpful. 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.
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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 DISCLOSUREDISCLOSURES
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
PBF Energy Class A common stock trades on the New York Stock Exchange under the symbol “PBF.”“PBF”. PBF Energy Class B common stock is not publicly-traded.
As of February 18, 20209, 2023 there were 165253 holders of record of PBF Energy Class A common stock and 2013 holders of record of PBF Energy Class B common stock.
Dividend and Distribution Policy
Subject to the following paragraphs, PBF Energy currently intends to continue to pay quarterly cash dividends of approximately $0.30$0.20 per share on its Class A common stock. The declaration, amount and payment of this and any other future dividends on shares of Class A common stock will be at the sole discretion of PBF Energy’s board of directors.
PBF Energy is a holding company and has no material assets other than its ownership interests of PBF LLC. In order for PBF Energy to pay any dividends, it needs to cause PBF LLC to make distributions to it and the holders of PBF LLC Series A Units, and PBF LLC needs to cause PBF Holding and/or PBFX to make distributions to it, in at least an amount sufficient to cover cash dividends, if any, declared by PBF Energy. Each of PBF Holding and PBFX is 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, PBF LLC may be unable to obtain cash from PBF Holding and/or PBFX to satisfy its obligations and make distributions to PBF Energy for dividends, if any, to PBF Energy’s stockholders. If PBF LLC makes such distributions to PBF Energy, the holders of PBF LLC Series A Units will also be entitled to receive pro rata distributions.
The ability of PBF Holding to pay dividends and make distributions to PBF LLC is, and in the future may be, limited by covenants in its Revolving Credit Facility, the 20252028 Senior Notes, the 20282025 Senior Notes and other debt instruments. Subject to certain exceptions, the Revolving Credit Facility and the indentures governing the senior notes prohibit PBF Holding from making distributions to PBF LLC if certain defaults exist. In addition, both the indentures and the Revolving Credit Facility contain additional restrictions limiting PBF Holding’s ability to make distributions to PBF LLC.
PBFX intendsmade aggregate quarterly distributions of $75.3 million ($1.20 per unit) during the year ended December 31, 2022 to make a minimum quarterly distribution to the holders of its common units, includingof which $35.9 million was paid to PBF LLC. After the Merger Transaction PBF Energy and PBF LLC acquired all of at least $0.30 per unit, or $1.20 per unit onthe publicly held common units in PBFX representing limited partner interests in the partnership not already owned by certain wholly-owned subsidiaries of PBF Energy and its affiliate. Therefore, PBFX became an annualized basis, to the extent PBFX has sufficient cash from operations after the establishmentindirect wholly-owned subsidiary of cash reservesPBF Energy and the payment of costs and expenses, including reimbursements of expenses to PBFX’s general partner. However, there isPBF LLC that may no guarantee that PBFX willlonger pay the minimum quarterly distribution or any amount on the units we own in any quarter. Even if PBFX’s cash distribution policy is not modified or revoked, the amount of distributions paid under the policy and the decision to make any distribution is determined by its general partner, taking into consideration the terms of PBFX’s partnership agreement and debt facilities.
dividends. PBF Holding made $121.6$571.4 million in distributions to PBF LLC during the year ended December 31, 2019.2022. In addition, during the year ended December 31, 2022 PBF LLC used $145.3$25.0 million which included $115.4 million distributed from PBF Holding, to make four separate non-tax distributions of $0.30$0.20 per unit ($1.20 per unit in total) to its members, of which $143.8$24.8 million was distributed to PBF Energy and the balance was distributed to PBF LLC’s other members. PBF Energy used this $143.8$24.8 million to pay four separate equivalent cash dividends of $0.30$0.20 per share of its Class A common stock on March 14, 2019, May 30, 2019, August 30, 2019 and November 26, 2019.29, 2022. PBF LLC also made aggregate tax distributions to its members of $55.1$1,130.1 million, of which $53.4$1,121.8 million was made to PBF Energy. In addition, PBFX made aggregate quarterly distributions of $125.5 million ($2.05 per unit) during the year ended December 31, 2019 to holders of its common units, of which $61.4 million was paid to PBF LLC.
PBF LLC expects to continue to make tax distributions to its members in accordance with its amended and restated limited liability company agreement.
The declaration, amount and payment of any future dividends on shares of PBF Energy Class A common stock will be at the sole discretion of PBF Energy’s Board of Directors, and we are not obligated under any applicable laws, our governing documents or any contractual agreements with our 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).
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Stock Performance Graph
In accordance with SEC rules, the information contained in the Stock Performance Graph below shall not be deemed to be “soliciting material,” or to be “filed” with the SEC, or subject to the SEC’s Regulation 14A or 14C, other than as provided under Item 201(e) of Regulation S-K, or to the liabilities of Section 18 of the Securities Exchange Act of 1934, as amended, except to the extent that we specifically request that the information be treated as soliciting material or specifically incorporate it by reference into a document filed under the Securities Act of 1933, as amended.amended.
| 12/31/2017 | 12/31/2018 | 12/31/2019 | 12/31/2020 | 12/31/2021 | 12/31/2022 | ||||||||||||||||||||||||||||||
| PBF Energy Class A common stock | $ | 100.00 | $ | 95.06 | $ | 95.22 | $ | 21.81 | $ | 39.84 | $ | 125.81 | |||||||||||||||||||||||
| S&P 500 | 100.00 | 95.62 | 125.72 | 148.85 | 191.58 | 156.89 | |||||||||||||||||||||||||||||
| Peer Group | 100.00 | 89.00 | 107.83 | 71.05 | 95.61 | 164.63 | |||||||||||||||||||||||||||||
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| 12/31/2014 | 12/31/2015 | 12/31/2016 | 12/31/2017 | 12/31/2018 | 12/31/2019 | ||||||||||||||||||
| PBF Energy Class A common stock | $ | 100.00 | $ | 143.62 | $ | 114.10 | $ | 152.40 | $ | 144.87 | $ | 145.11 | |||||||||||
| S&P 500 | 100.00 | 101.38 | 113.51 | 138.29 | 132.23 | 173.86 | |||||||||||||||||
| Peer Group | 100.00 | 123.39 | 125.95 | 167.27 | 148.91 | 180.37 | |||||||||||||||||
Recent Sales of Unregistered Securities—Exchange of PBF LLC Series A Units for PBF Energy Class A Common Stock
In the fourth quarter of 2019,2022, there were no exchanges of PBF LLC Series A Units for shares of PBF Energy Class A common stock in transactions exempt from registration under Section 4(2)4(a)(2) of the Securities Act. No exchanges
Share Repurchase Program
The following table summarizes PBF Energy’s Class A common stock share repurchase activity during the fourth quarter of 2022:
| Period | Total Number of Shares Purchased (1) | Average Price Paid per Share (2) | Total Number of Shares Purchased as Part of Publicly Announced Plan (3) | Approximately Dollar Value of Shares that May Yet Be Purchased Under Plan (in millions) | ||||||||||||||||||||||
| December | 4,192,555 | $ | 37.30 | 4,192,555 | $ | 343.60 | ||||||||||||||||||||
(1) The shares purchased include only those shares that have settled as of the period end date.
(2) Average price per share excludes transaction commissions.
(3) On December 12, 2022, our Board of Directors authorized the repurchase of up to $500.0 million of PBF Energy’s Class A common stock (as amended from time to time, the "Repurchase Program"). The Repurchase Program will expire in December 2024. These repurchases may be made from time to time through various methods, including open market transactions, block trades, accelerated share repurchases, privately negotiated transactions or otherwise, certain of which have been effected through Rule 10b5-1 plans. The timing and number of shares repurchased depended on a variety of factors, including price, capital availability, legal requirements and economic and market conditions. We were made bynot obligated to purchase any of our directorsshares under the Repurchase Program, and repurchases could be suspended or executive officers.discontinued at any time without prior notice.
ITEM 6. SELECTED FINANCIAL DATA
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| Year Ended December 31, | ||||||||||||||||||||
| PBF Energy | 2019 | 2018 | 2017 | 2016 | 2015 | |||||||||||||||
| (in millions, except share and per share data) | ||||||||||||||||||||
| Revenues | $ | 24,508.2 | $ | 27,186.1 | $ | 21,786.6 | $ | 15,920.4 | $ | 13,123.9 | ||||||||||
| Cost and expenses: | ||||||||||||||||||||
| Cost of products and other | 21,387.5 | 24,503.4 | 18,863.6 | 13,598.3 | 11,481.6 | |||||||||||||||
| Operating expenses (excluding depreciation and amortization expense as reflected below) | 1,782.3 | 1,721.0 | 1,684.4 | 1,422.8 | 902.9 | |||||||||||||||
| Depreciation and amortization expense | 425.3 | 359.1 | 278.0 | 216.3 | 187.7 | |||||||||||||||
| Cost of sales | 23,595.1 | 26,583.5 | 20,826.0 | 15,237.4 | 12,572.2 | |||||||||||||||
General and administrative expenses (excluding depreciation and amortization expense as reflected below) (1) | 284.0 | 277.0 | 214.5 | 166.3 | 181.3 | |||||||||||||||
| Depreciation and amortization expense | 10.8 | 10.6 | 13.0 | 5.8 | 9.7 | |||||||||||||||
| Change in contingent consideration | (0.8 | ) | — | — | — | — | ||||||||||||||
| (Gain) loss on sale of asset | (29.9 | ) | (43.1 | ) | 1.5 | 11.4 | (1.0 | ) | ||||||||||||
| Total cost and expenses | 23,859.2 | 26,828.0 | 21,055.0 | 15,420.9 | 12,762.2 | |||||||||||||||
| Income from operations | 649.0 | 358.1 | 731.6 | 499.5 | 361.7 | |||||||||||||||
| Other income (expense): | ||||||||||||||||||||
| Interest expense, net | (159.6 | ) | (169.9 | ) | (154.4 | ) | (150.0 | ) | (106.2 | ) | ||||||||||
| Change in Tax Receivable Agreement liability | — | 13.9 | 250.9 | 12.9 | 18.2 | |||||||||||||||
| Change in fair value of catalyst obligations | (9.7 | ) | 5.6 | (2.2 | ) | 1.4 | 10.2 | |||||||||||||
| Debt extinguishment costs | — | — | (25.5 | ) | — | — | ||||||||||||||
| Other non-service components of net periodic benefit cost | (0.2 | ) | 1.1 | (1.4 | ) | (0.6 | ) | (1.7 | ) | |||||||||||
| Income before income taxes | 479.5 | 208.8 | 799.0 | 363.2 | 282.2 | |||||||||||||||
| Income tax expense | 104.3 | 33.5 | 315.6 | 137.7 | 86.7 | |||||||||||||||
| Net income | 375.2 | 175.3 | 483.4 | 225.5 | 195.5 | |||||||||||||||
| Less: net income attributable to noncontrolling interests | 55.8 | 47.0 | 67.8 | 54.7 | 49.1 | |||||||||||||||
| Net income attributable to PBF Energy Inc. stockholders | $ | 319.4 | $ | 128.3 | $ | 415.6 | $ | 170.8 | $ | 146.4 | ||||||||||
| Weighted-average shares of Class A common stock outstanding: | ||||||||||||||||||||
| Basic | 119,887,646 | 115,190,262 | 109,779,407 | 98,334,302 | 88,106,999 | |||||||||||||||
| Diluted | 121,853,299 | 118,773,606 | 113,898,845 | 103,606,709 | 94,138,850 | |||||||||||||||
| Net income available to Class A common stock per share: | ||||||||||||||||||||
| Basic | $ | 2.66 | $ | 1.11 | $ | 3.78 | $ | 1.74 | $ | 1.66 | ||||||||||
| Diluted | $ | 2.64 | $ | 1.10 | $ | 3.73 | $ | 1.74 | $ | 1.65 | ||||||||||
| Dividends per common share | $ | 1.20 | $ | 1.20 | $ | 1.20 | $ | 1.20 | $ | 1.20 | ||||||||||
| Balance sheet data (at end of period) : | ||||||||||||||||||||
| Total assets | $ | 9,132.4 | $ | 8,005.4 | $ | 8,118.0 | $ | 7,621.9 | $ | 6,105.1 | ||||||||||
Total debt (2) | 2,097.3 | 1,974.7 | 2,226.1 | 2,180.7 | 1,881.6 | |||||||||||||||
| Total equity | 3,585.5 | 3,248.5 | 2,902.9 | 2,570.7 | 2,095.9 | |||||||||||||||
| Other financial data : | ||||||||||||||||||||
Capital expenditures (3) | $ | 748.9 | $ | 733.9 | $ | 727.1 | $ | 1,612.9 | $ | 981.1 | ||||||||||
| Year Ended December 31, | ||||||||||||||||||||
| PBF LLC | 2019 | 2018 | 2017 | 2016 | 2015 | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Revenues | $ | 24,508.2 | $ | 27,186.1 | $ | 21,786.6 | $ | 15,920.4 | $ | 13,123.9 | ||||||||||
| Cost and expenses: | ||||||||||||||||||||
| Cost of products and other | 21,387.5 | 24,503.4 | 18,863.6 | 13,598.3 | 11,481.6 | |||||||||||||||
| Operating expenses (excluding depreciation and amortization expense as reflected below) | 1,782.3 | 1,721.0 | 1,684.4 | 1,422.8 | 902.9 | |||||||||||||||
| Depreciation and amortization expense | 425.3 | 359.1 | 278.0 | 216.3 | 187.7 | |||||||||||||||
| Cost of sales | 23,595.1 | 26,583.5 | 20,826.0 | 15,237.4 | 12,572.2 | |||||||||||||||
General and administrative expenses (excluding depreciation and amortization expense as reflected below) (1) | 282.3 | 275.2 | 214.2 | 166.1 | 180.3 | |||||||||||||||
| Depreciation and amortization expense | 10.8 | 10.6 | 13.0 | 5.8 | 9.7 | |||||||||||||||
| Change in contingent consideration | (0.8 | ) | — | — | — | — | ||||||||||||||
| (Gain) loss on sale of assets | (29.9 | ) | (43.1 | ) | 1.5 | 11.4 | (1.0 | ) | ||||||||||||
| Total cost and expenses | 23,857.5 | 26,826.2 | 21,054.7 | 15,420.7 | 12,761.2 | |||||||||||||||
| Income from operations | 650.7 | 359.9 | 731.9 | 499.7 | 362.7 | |||||||||||||||
| Other income (expense): | ||||||||||||||||||||
| Interest expense, net | (169.1 | ) | (178.5 | ) | (162.3 | ) | (155.8 | ) | (109.4 | ) | ||||||||||
| Change in fair value of catalyst obligations | (9.7 | ) | 5.6 | (2.2 | ) | 1.4 | 10.2 | |||||||||||||
| Debt extinguishment costs | — | — | (25.5 | ) | — | — | ||||||||||||||
| Other non-service components of net periodic benefit cost | (0.2 | ) | 1.1 | (1.4 | ) | (0.6 | ) | (1.7 | ) | |||||||||||
| Income before income taxes | 471.7 | 188.1 | 540.5 | 344.7 | 261.8 | |||||||||||||||
| Income tax (benefit) expense | (8.3 | ) | 8.0 | (10.8 | ) | 23.7 | 0.6 | |||||||||||||
| Net income | 480.0 | 180.1 | 551.3 | 321.0 | 261.2 | |||||||||||||||
| Less: net income attributable to noncontrolling interests | 51.5 | 42.3 | 51.2 | 40.1 | 34.9 | |||||||||||||||
| Net income attributable to PBF Energy Company LLC | $ | 428.5 | $ | 137.8 | $ | 500.1 | $ | 280.9 | $ | 226.3 | ||||||||||
| Balance sheet data (at end of period) : | ||||||||||||||||||||
| Total assets | $ | 9,129.1 | $ | 7,953.1 | $ | 8,039.0 | $ | 7,133.5 | $ | 5,501.2 | ||||||||||
Total debt (2) | 2,473.7 | 2,300.8 | 2,519.0 | 2,370.8 | 2,096.3 | |||||||||||||||
| Total equity | 3,609.1 | 3,219.4 | 2,878.5 | 2,487.7 | 1,909.4 | |||||||||||||||
| Other financial data : | ||||||||||||||||||||
Capital expenditures (3) | $ | 748.9 | $ | 733.9 | $ | 727.0 | $ | 1,612.9 | $ | 981.1 | ||||||||||
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”, “Item 6. Selected Financial Data,” 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 and 2021 and comparisons of the results for the years ended December 31, 2022 and 2021. Discussions of results for the year ended December 31, 2020 and comparisons of the results for the years ended December 31, 2021 and 2020 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.
CAUTIONARY STATEMENT FOR THE PURPOSE OF SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This Annual Report on Form 10-K contains certain “forward-looking statements,” as defined in the Private Securities Litigation Reform Act of 1995 (“PSLRA”), of expected future developments that involve risks and uncertainties. You can identify forward-looking statements because they contain words such as “believes,” “expects,” “may,” “should,”�� “seeks,” “approximately,” “intends,” “plans,” “estimates,” “anticipates” or similar expressions that relate to our strategy, plans or intentions. All statements we make relating to our estimated and projected earnings, margins, costs, expenditures, cash flows, growth rates and financial results or to our strategies, objectives, intentions, resources and expectations regarding future industry trends are forward-looking statements made under the safe harbor provisions of the PSLRA except to the extent such statements relate to the operations of a partnership or limited liability company. In addition, we, through our senior management, from time to time make forward-looking public statements concerning our expected future operations and performance and other developments. These forward-looking statements are subject to risks and uncertainties that may change at any time, and, therefore, our actual results may differ materially from those that we expected. We derive many of our forward-looking statements from our operating budgets and forecasts, which are based uponon 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;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;
•the effectsrate of competition in our markets;inflation and its impacts on supply and demand, pricing, and supply chain disruption;
•changes in currency exchange rates, interest ratesthe possibility that the expected synergies and capital costs;value creation from the Merger Transaction will not be realized, or will not be realized within the expected time period;
•the risk that unexpected costs will be incurred in connection with the Merger Transaction;
•adverse developmentsthe effects related to, or resulting from, Russia's military action in Ukraine, including the imposition of additional sanctions and export controls, as well as the broader impacts to financial markets and the global macroeconomic and geopolitical environment;
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•the effectiveness of our relationshipcrude 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 both our key employeesthe RFS and unionized employees;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 indebtedness;
•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;
•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 and execute expense reduction measures and achieve opportunities to improve our liquidity, 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;
•political pressure and influence of environmental groups and other stakeholders on decisions and policies related to the refining and processing of crude oil and refined products, and the related adverse impacts from changes in our regulatory environment, such as the effects of compliance with AB 32, or from actions taken by environmental interest groups;
•the risk of cyber-attacks;
•our increased dependence on technology;
•the effects of competition in our markets;
•the possibility that we might reduce or not pay further dividends in the future;
•the inability of our subsidiaries to freely pay dividends or make distributions to us;
•our ability to make acquisitions or investments, including in renewable diesel production, on any announced time frame or at all, and to realize the benefits from such acquisitions or investments;
•liabilities arising from recent acquisitions or investments, that are unforeseen or exceed our expectations;
•our expectations and timing with respect to our acquisition activity and whether such acquisitions are accretive or dilutive to shareholders;
•adverse developments in our relationship with both our key employees and unionized employees;
•our indebtedness, including the impact of potential downgrades to our corporate credit rating and unsecured notes;
•changes in currency exchange rates, interest rates and capital costs;
•restrictive covenants in our indebtedness that may adversely affect our operational flexibility;
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•counterparty credit and performance risk exposure related to our supply and inventory intermediation arrangements expose us to counterparty credit and performance risk;arrangements;
•termination of our Third Inventory Intermediation AgreementsAgreement 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 agreements.agreement. Additionally, we are obligated to repurchase from J. Aron certain products located at our J. Aron Storage TanksProducts upon termination of these agreements;
•payments by PBF Energy to the current and former holders of PBF LLC Series A Units and PBF LLC Series B Units under PBF Energy’s Tax Receivable Agreement for certain tax benefits we may claim;
•our assumptions regarding payments arising under PBF Energy’s Tax Receivable Agreement and other arrangements relating to our organizational structure are subject to change due to various factors, including, among other factors, the timing of exchanges of PBF LLC Series A Units for shares of PBF Energy Class A common stock as contemplated by the Tax Receivable Agreement, the price of PBF Energy Class A common stock at the time of such exchanges, the extent to which such exchanges are taxable, and the amount and timing of our income;
•the impact of disruptions to crude or feedstock supply to any of our refineries, including disruptions due to problems at PBFX or with third-party logistics infrastructure or operations, including pipeline, marine and rail transportation;
We caution you that the foregoing list of important factors may not contain all of the material factors that are important to you. In addition, in light of these risks and uncertainties, the matters referred to in the forward-looking statements contained in this Annual Report on Form 10-K may not in fact occur. Accordingly, investors should not place undue reliance on those statements.
Our forward-looking statements speak only as of the date of this Annual Report on Form 10-K. Except as required by applicable law, including the securities laws of the United States, we do not intend to update or revise any forward-looking statements. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the foregoing.
Executive Summary
Our business operations are conducted by PBF LLC and itsour subsidiaries. We were formed in March 2008 to pursue the acquisitions of crude oil refineriesown and downstream assets in North America. As of December 31, 2019, we owned and operated fiveoperate six domestic oil refineries and related assets located in Delaware City, Delaware, Paulsboro, New Jersey, Toledo, Ohio, Chalmette, Louisiana, Torrance, California, and Torrance,Martinez, California. Our refineries have a combined processing capacity, known as throughput, of approximately 900,0001,000,000 bpd, and a weighted averageweighted-average Nelson Complexity Index of 12.2.12.7 based on current operating conditions. The complexity and throughput capacity of our refineries are subject to change dependent upon configuration changes we make to respond to market conditions, as well as a result of investments made to improve our facilities and maintain compliance with environmental and governmental regulations. We operate in two reportable business segments: Refining and Logistics. Our five oilsix refineries are all engaged in the refining of crude oil and other feedstocks into petroleum products, and are aggregated intorepresent the Refining segment. PBFX operates certain logistical assets such as crude oil and refined petroleum products terminals, pipelines, and storage facilities, which are aggregated intorepresent the Logistics 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.
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Share Repurchase Program
On August 1, 2019December 12, 2022, our Board of Directors authorized the repurchase of up to $500.0 million of PBF Energy's Class A common stock. The Repurchase Program will expire in December 2024. For the period of time from the inception of the Repurchase Program through December 31, 2022, we purchased 4,192,555 shares for $156.4 million, inclusive of commissions paid. We may make additional share repurchases in the future.
These repurchases were made from time to time through various methods, including open market transactions, block trades, accelerated share repurchases, privately negotiated transactions or otherwise, certain of which may be effected through Rule 10b5-1 plans. The timing and August 7, 2018, wenumber of shares repurchased depended on a variety of factors, including price, capital availability, legal requirements and economic and market conditions. We were not obligated to purchase any shares under the Repurchase Program, and repurchases might have been suspended or discontinued at any time without prior notice.
Merger Transaction
On July 27, 2022, PBF Energy, PBF LLC, PBFX Holdings, Merger Sub, PBFX, and PBFX GP entered into 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 Merger Transaction. The Merger Transaction closed on third-party salesNovember 30, 2022 and PBFX became an indirect wholly-owned subsidiary of parcels of real property acquired as partPBF Energy and PBF LLC.
At the Effective Time, pursuant to the terms of the Torrance refinery, but not partMerger Agreement, each PBFX Public Common Unit was converted into the right to receive: (i) the Merger Consideration and (ii) any cash in lieu of fractional shares of PBF Energy Common Stock to which the holder thereof became entitled upon surrender of such PBFX Public Common Units in accordance with the Merger Agreement. Such Merger Agreement consideration totaled $303.7 million in cash and resulted in the issuance of 8,864,684 shares of PBF Energy Class A common stock. The PBFX Common Units owned by PBF LLC and PBFX Holdings and the non-economic general partner interest remain outstanding and were unaffected by the Merger. There was no change in ownership of the refinery itself.non-economic general partner interest.
Debt and Credit Facilities
Senior Notes
PBFX’s 6.875% senior notes (the “PBFX 2023 Senior Notes”) were redeemed on February 2, 2023 and are classified as Current debt as of December 31, 2022 within our Consolidated Balance Sheet.
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 sales resulted in gainsaggregate redemption price for all 2025 Senior Secured Notes approximated $1.3 billion plus accrued and unpaid interest. The difference between the carrying value of approximately $33.1the 2025 Senior Secured Notes on the date they were redeemed and the amount for which they were redeemed was $69.9 million and $43.8 million in the third quarterwas recorded as a Loss on extinguishment of 2019 and 2018, respectively, included within Gain on sale of assetsdebt in the Consolidated Statements of Operations.
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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 early termination penaltyyear 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 (ii)offering expenses. We used $517.5 million of the proceeds to fully redeem our 2023 Senior Notes and the balance to fund a $12.0 million chargeportion 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 LIBOR, changes to joint lead arrangers, bookrunners, syndication agents and other titles, and other changes related to the remaining lease payments associated withforegoing. 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 railcars identified withinTranche A Commitments for existing Tranche A lenders.
During the amended lease, allyear ended December 31, 2022, we made net repayments of which were idled and out of service$900.0 million on the Revolving Credit Facility, resulting in no outstanding borrowings as of December 31, 2018.
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PBFX Revolving Credit Facility
December 31, 2022. The outstanding borrowings under the PBFX Revolving Credit Facility were $283.0 million, $156.0$100.0 million and $29.7$200.0 million as of December 31, 2019, 2018 and 2017, respectively.
Catalyst Financing Obligations
During the year ended December 31, 2017, there was $350.02022 and December 31, 2021, we settled certain of our precious metals financing arrangements, resulting in reductions of debt of approximately $56.2 million outstanding under the August 2014 Revolving Credit Agreement.and $31.7 million, respectively.
Refer to pay the related redemption price and accrued and unpaid interest for any 2020 Senior Secured Notes that remained outstanding after the completion of the Tender Offer, and for general corporate purposes. As described in “Note 98 - Credit Facilities and Debt” of our Notes to Consolidated Financial Statements, upon the satisfaction and dischargefor 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, Senior Secured Notescreated 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.
Land Sales
On December 20, 2021, PBFX closed on a third-party sale of real property at the refined products terminals in the greater Philadelphia area (“East Coast Terminals”). The sale resulted in a gain of approximately $2.8 million in the fourth quarter of 2021, included within Gain on sale of assets in the Consolidated Statements of Operations.
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.
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Capital Project Abandonments
During 2020, in connection with our strategic initiative to address the closingCOVID-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 Tender OfferCOVID-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.
Tax Receivable Agreement
In connection with PBF Energy’s IPO, PBF Energy entered into a Tax Receivable Agreement pursuant to which PBF Energy is required to pay the members of PBF LLC, who exchange their units for PBF Energy Class A common stock or whose units PBF Energy purchases, approximately 85% of the cash savings in income taxes that PBF Energy realizes as a result of the increase in the tax basis of its interest in PBF LLC, including tax benefits attributable to payments made under the Tax Receivable Agreement. PBF Energy has recognized, as of December 31, 2022, a liability for the Tax Receivable Agreement of $338.6 million ($48.3 million as of December 31, 2021) reflecting the estimate of the undiscounted amounts that PBF Energy expects to pay under the agreement. As of December 31, 2020, there was zero liability recognized related to the Tax Receivable Agreement. As future taxable income is recognized, increases in our Tax Receivable Agreement liability may be necessary in conjunction with the revaluation of deferred tax assets. Refer to “Note 12 - Commitments and Contingencies” and “Note 19 - Income Taxes” of our Notes to Consolidated Financial Statements for more details.
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.
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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 redemption,obligation to make certain post-closing earn-out payments to Shell Oil Products based on certain earnings thresholds of the 2023 Senior Notes became unsecured and certain covenants were modified, as providedMartinez refinery for ina 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 indenture governing the 20232028 Senior Notes, and related documents.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
On October 6, 2017, PBFX issued an additional $175.0 million in aggregate principal amount of 6.875% Senior Notes due 2023 (together25, 2021, PBF Holding and its subsidiaries, the PBF Entities, entered into the Third Inventory Intermediation Agreement with J. Aron, pursuant to which the initially issued notes, the “PBFX 2023 Senior Notes”). The additional amountterms of the PBFX 2023 Senior Notesexisting inventory intermediation agreements were issued at 102%amended and restated in their entirety, including, among other things, pricing and an extension of face value withthe terms. The Third Inventory Intermediation Agreement extends the term to December 31, 2024, which term may be further extended by mutual consent of the parties to December 31, 2025. On May 25, 2022, the PBF Entities entered into an effective rateamendment of 6.442%the Third Inventory Intermediation Agreement to amend certain provisions thereof that related to and were issuedimpacted by amendments made on May 25, 2022 to the Revolving Credit 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 indenture governingThird Inventory Intermediation Agreement in November 2021. J. Aron has the initial PBFX 2023 Senior Notes dated May 12, 2015. PBFX usedright to store the net proceeds fromJ. Aron Products purchased in tanks under the offeringThird Inventory Intermediation Agreement and will retain these storage rights for the term of the additional amount ofagreement. We intend to utilize the PBFX 2023 Senior Notescrude oil and will market and sell the refined products independently to repay a portion of the PBFX Revolving Credit Facility and for general capital purposes.third parties.
Renewable FuelsFuel Standard
We are subject to obligations to purchase RINs required to comply with the Renewable FuelsFuel Standard. 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 $122.7$1,225.5 million in RINs costs during the year ended December 31, 20192022 as compared to $143.9$726.0 million and $293.7$326.4 million during the years ended December 31, 20182021 and 2017,2020, respectively. The fluctuationsincreases in 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.fuels. Our RINs purchase obligation is dependent on our actual shipment of on-road transportation fuels domestically and the amount of blending achieved.
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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 petroleum products ultimately sold depends on numerous factors beyond our control, including the supply of, and demand for, crude oil, gasoline, diesel and other refined petroleum 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 petroleum 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 petroleum 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 petroleum 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 petroleum 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.
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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 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 Paulsboro and Delaware CityEast 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 PDVSAPetróleos 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.
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 FuelsFuel Standard. 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.
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Refinery-Specific Information
The following section includes refinery-specific information related to our operations, crude oil differentials, ancillary costs, and local premiums and discounts.
The Delaware City refinery’sEast Coast Refining System’s realized gross margin on a per barrel basis has historically differedis projected to differ from the Dated Brent (NYH) 2-1-1 benchmark refining margin due to the following factors:
•the Delaware City refinerysystem processes a slate of primarily medium and heavy sour crude oils, which has constituted approximately 55%60% to 65%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 Delaware City,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.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 conventional blendstock for oxygenate blendingCBOB 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 55%51% gasoline, 34%36% distillate, 5% high-value petrochemicals (including nonene, tetramer, benzene, xylene and toluene) with the remaining portion of the product slate comprised of lower-value products (4%(5% LPGs and 2% other)3% black oil). For this reason, we believe the WTI (Chicago) 4-3-1 is an appropriate benchmark industry refining margin. The majority of Toledo revenues are generated off Chicago-based market prices.
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.
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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 50%44% gasoline and 33%36% distillate, 1% high-value petrochemicals with the remaining portion of the product slate comprised of lower-value products (8%(7% black oil, 4%5% LPGs, 3% petroleum coke, 3% LPGs, and 2% petrochemical feedstocks)4% 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 processed a slate of primarily medium and heavy sour crude oils, which has historically constituted approximately 55%50% to 65% 75%of total throughput. The remaining throughput consists of sweet crude oil 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 Alaskan North Slope (“ANS”)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)(“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 62%56% gasoline and 26%27% distillate with the remaining portion of the product slate comprised of lower-value products (8% petroleum coke, 2%(3% LPG, 3% black oil and 2% black oil)11% 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 80%70% to 90% of total throughput. The Torrance crude slate has the lowest API gravity (typically an American Petroleum Institute (“API”)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.
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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 70% to 90% 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.
Results of Operations
The tables below reflect our consolidated financial and operating highlights for the years ended December 31, 2019, 20182022, 2021 and 20172020 (amounts in millions, except per share data). Differences between the results of operations of PBF Energy and PBF LLC primarily pertain to income taxes, interest expense and noncontrolling interest as shown below. Earnings per share information applies only to the financial results of PBF Energy. We operate in two reportable business segments: Refining and Logistics. Our oil refineries, excluding the assets ownedoperated by PBFX, are all engaged in the refining of crude oil and other feedstocks into petroleum products, and are aggregated intorepresent the Refining segment. PBFX is a publicly-traded MLPan indirect wholly-owned subsidiary of PBF Energy and PBF LLC that operates certain logistics assets such as crude oil and refined petroleum products terminals, pipelines and storage facilities. PBFX’s operations are aggregated intorepresent the Logistics segment. We do not separately discuss our results by individual segments as, apart from PBFX’s third-party acquisitions, our Logistics segment did not have any significant third-party revenues and a significant portion of its operating results eliminateare eliminated in consolidation.
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| PBF Energy | Year Ended December 31, | PBF Energy | Year Ended December 31, | |||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | 2022 | 2021 | 2020 | |||||||||||||||||||||||||||
| Revenues | $ | 24,508.2 | $ | 27,186.1 | $ | 21,786.6 | Revenues | $ | 46,830.3 | $ | 27,253.4 | $ | 15,115.9 | |||||||||||||||||||
| Cost and expenses: | Cost and expenses: | |||||||||||||||||||||||||||||||
| Cost of products and other | 21,387.5 | 24,503.4 | 18,863.6 | Cost of products and other | 39,049.1 | 23,826.8 | 14,275.6 | |||||||||||||||||||||||||
| Operating expenses (excluding depreciation and amortization expense as reflected below) | 1,782.3 | 1,721.0 | 1,684.4 | Operating expenses (excluding depreciation and amortization expense as reflected below) | 2,599.0 | 2,085.9 | 1,918.3 | |||||||||||||||||||||||||
| Depreciation and amortization expense | 425.3 | 359.1 | 278.0 | Depreciation and amortization expense | 503.6 | 453.5 | 551.7 | |||||||||||||||||||||||||
| Cost of sales | 23,595.1 | 26,583.5 | 20,826.0 | Cost of sales | 42,151.7 | 26,366.2 | 16,745.6 | |||||||||||||||||||||||||
| General and administrative expenses (excluding depreciation and amortization expense as reflected below) | 284.0 | 277.0 | 214.5 | General and administrative expenses (excluding depreciation and amortization expense as reflected below) | 468.7 | 247.3 | 248.5 | |||||||||||||||||||||||||
| Depreciation and amortization expense | 10.8 | 10.6 | 13.0 | Depreciation and amortization expense | 7.5 | 13.3 | 11.3 | |||||||||||||||||||||||||
| Change in contingent consideration | (0.8 | ) | — | — | ||||||||||||||||||||||||||||
| (Gain) loss on sale of assets | (29.9 | ) | (43.1 | ) | 1.5 | |||||||||||||||||||||||||||
| Change in fair value of contingent consideration, net | Change in fair value of contingent consideration, net | 48.3 | 32.4 | (93.7) | ||||||||||||||||||||||||||||
| Impairment expense | Impairment expense | — | — | 98.8 | ||||||||||||||||||||||||||||
| Loss (gain) on sale of assets | Loss (gain) on sale of assets | 0.9 | (3.0) | (477.8) | ||||||||||||||||||||||||||||
| Total cost and expenses | 23,859.2 | 26,828.0 | 21,055.0 | Total cost and expenses | 42,677.1 | 26,656.2 | 16,532.7 | |||||||||||||||||||||||||
| Income from operations | 649.0 | 358.1 | 731.6 | |||||||||||||||||||||||||||||
| Income (loss) from operations | Income (loss) from operations | 4,153.2 | 597.2 | (1,416.8) | ||||||||||||||||||||||||||||
| Other income (expense): | Other income (expense): | |||||||||||||||||||||||||||||||
| Interest expense, net | (159.6 | ) | (169.9 | ) | (154.4 | ) | Interest expense, net | (246.0) | (317.5) | (258.2) | ||||||||||||||||||||||
| Change in Tax Receivable Agreement liability | — | 13.9 | 250.9 | Change in Tax Receivable Agreement liability | (290.3) | (48.3) | 373.5 | |||||||||||||||||||||||||
| Change in fair value of catalyst obligations | (9.7 | ) | 5.6 | (2.2 | ) | Change in fair value of catalyst obligations | (2.0) | 8.5 | (11.8) | |||||||||||||||||||||||
| Debt extinguishment costs | — | — | (25.5 | ) | ||||||||||||||||||||||||||||
| (Loss) gain on extinguishment of debt | (Loss) gain on extinguishment of debt | (66.1) | 79.9 | (22.2) | ||||||||||||||||||||||||||||
| Other non-service components of net periodic benefit cost | (0.2 | ) | 1.1 | (1.4 | ) | Other non-service components of net periodic benefit cost | 8.8 | 7.8 | 4.3 | |||||||||||||||||||||||
| Income before income taxes | 479.5 | 208.8 | 799.0 | |||||||||||||||||||||||||||||
| Income (loss) before income taxes | Income (loss) before income taxes | 3,557.6 | 327.6 | (1,331.2) | ||||||||||||||||||||||||||||
| Income tax expense | 104.3 | 33.5 | 315.6 | Income tax expense | 584.8 | 12.1 | 2.1 | |||||||||||||||||||||||||
| Net income | 375.2 | 175.3 | 483.4 | |||||||||||||||||||||||||||||
| Net income (loss) | Net income (loss) | 2,972.8 | 315.5 | (1,333.3) | ||||||||||||||||||||||||||||
| Less: net income attributable to noncontrolling interests | 55.8 | 47.0 | 67.8 | Less: net income attributable to noncontrolling interests | 96.0 | 84.5 | 59.1 | |||||||||||||||||||||||||
| Net income attributable to PBF Energy Inc. stockholders | $ | 319.4 | $ | 128.3 | $ | 415.6 | ||||||||||||||||||||||||||
| Net income (loss) attributable to PBF Energy Inc. stockholders | Net income (loss) attributable to PBF Energy Inc. stockholders | $ | 2,876.8 | $ | 231.0 | $ | (1,392.4) | |||||||||||||||||||||||||
| Consolidated gross margin | $ | 913.1 | $ | 602.6 | $ | 960.6 | Consolidated gross margin | $ | 4,678.6 | $ | 887.2 | $ | (1,629.7) | |||||||||||||||||||
Gross refining margin (1) | $ | 2,801.2 | $ | 2,419.4 | $ | 2,676.6 | Gross refining margin (1) | $ | 7,429.9 | $ | 3,087.7 | $ | 496.8 | |||||||||||||||||||
| Net income available to Class A common stock per share: | Net income available to Class A common stock per share: | |||||||||||||||||||||||||||||||
| Basic | $ | 2.66 | $ | 1.11 | $ | 3.78 | Basic | $ | 23.47 | $ | 1.92 | $ | (11.64) | |||||||||||||||||||
| Diluted | $ | 2.64 | $ | 1.10 | $ | 3.73 | Diluted | $ | 22.84 | $ | 1.90 | $ | (11.64) | |||||||||||||||||||
——————————
(1) See Non-GAAP Financial Measures.
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| PBF LLC | Year Ended December 31, | |||||||||||||||||||
| 2022 | 2021 | 2020 | ||||||||||||||||||
| Revenues | $ | 46,830.3 | $ | 27,253.4 | $ | 15,115.9 | ||||||||||||||
| Cost and expenses: | ||||||||||||||||||||
| Cost of products and other | 39,049.1 | 23,826.8 | 14,275.6 | |||||||||||||||||
| Operating expenses (excluding depreciation and amortization expense as reflected below) | 2,599.0 | 2,085.9 | 1,918.3 | |||||||||||||||||
| Depreciation and amortization expense | 503.6 | 453.5 | 551.7 | |||||||||||||||||
| Cost of sales | 42,151.7 | 26,366.2 | 16,745.6 | |||||||||||||||||
| General and administrative expenses (excluding depreciation and amortization expense as reflected below) | 466.6 | 245.2 | 247.7 | |||||||||||||||||
| Depreciation and amortization expense | 7.5 | 13.3 | 11.3 | |||||||||||||||||
| Change in fair value of contingent consideration, net | 48.3 | 32.4 | (93.7) | |||||||||||||||||
| Impairment expense | — | — | 98.8 | |||||||||||||||||
| Loss (gain) on sale of assets | 0.9 | (3.0) | (477.8) | |||||||||||||||||
| Total cost and expenses | 42,675.0 | 26,654.1 | 16,531.9 | |||||||||||||||||
| Income (loss) from operations | 4,155.3 | 599.3 | (1,416.0) | |||||||||||||||||
| Other income (expense): | ||||||||||||||||||||
| Interest expense, net | (257.2) | (327.8) | (268.5) | |||||||||||||||||
| Change in fair value of catalyst obligations | (2.0) | 8.5 | (11.8) | |||||||||||||||||
| (Loss) gain on extinguishment of debt | (66.1) | 79.9 | (22.2) | |||||||||||||||||
| Other non-service components of net periodic benefit cost | 8.8 | 7.8 | 4.3 | |||||||||||||||||
| Income (loss) before income taxes | 3,838.8 | 367.7 | (1,714.2) | |||||||||||||||||
| Income tax expense (benefit) | 4.6 | (14.0) | 6.1 | |||||||||||||||||
| Net income (loss) | 3,834.2 | 381.7 | (1,720.3) | |||||||||||||||||
| Less: net income attributable to noncontrolling interests | 68.1 | 82.1 | 76.2 | |||||||||||||||||
| Net income (loss) attributable to PBF Energy Company LLC | $ | 3,766.1 | $ | 299.6 | $ | (1,796.5) | ||||||||||||||
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| PBF LLC | Year Ended December 31, | |||||||||||
| 2019 | 2018 | 2017 | ||||||||||
| Revenues | $ | 24,508.2 | $ | 27,186.1 | $ | 21,786.6 | ||||||
| Cost and expenses: | ||||||||||||
| Cost of products and other | 21,387.5 | 24,503.4 | 18,863.6 | |||||||||
| Operating expenses (excluding depreciation and amortization expense as reflected below) | 1,782.3 | 1,721.0 | 1,684.4 | |||||||||
| Depreciation and amortization expense | 425.3 | 359.1 | 278.0 | |||||||||
| Cost of sales | 23,595.1 | 26,583.5 | 20,826.0 | |||||||||
| General and administrative expenses (excluding depreciation and amortization expense as reflected below) | 282.3 | 275.2 | 214.2 | |||||||||
| Depreciation and amortization expense | 10.8 | 10.6 | 13.0 | |||||||||
| Change in contingent consideration | (0.8 | ) | — | — | ||||||||
| (Gain) loss on sale of assets | (29.9 | ) | (43.1 | ) | 1.5 | |||||||
| Total cost and expenses | 23,857.5 | 26,826.2 | 21,054.7 | |||||||||
| Income from operations | 650.7 | 359.9 | 731.9 | |||||||||
| Other income (expense): | ||||||||||||
| Interest expense, net | (169.1 | ) | (178.5 | ) | (162.3 | ) | ||||||
| Change in fair value of catalyst obligations | (9.7 | ) | 5.6 | (2.2 | ) | |||||||
| Debt extinguishment costs | — | — | (25.5 | ) | ||||||||
| Other non-service components of net periodic benefit cost | (0.2 | ) | 1.1 | (1.4 | ) | |||||||
| Income before income taxes | 471.7 | 188.1 | 540.5 | |||||||||
| Income tax (benefit) expense | (8.3 | ) | 8.0 | (10.8 | ) | |||||||
| Net income | 480.0 | 180.1 | 551.3 | |||||||||
| Less: net income attributable to noncontrolling interests | 51.5 | 42.3 | 51.2 | |||||||||
| Net income attributable to PBF Energy Company LLC | $ | 428.5 | $ | 137.8 | $ | 500.1 | ||||||
Operating Highlights
| Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | 2022 | 2021 | 2020 | |||||||||||||||||||||||||||||||||
| Key Operating Information | Key Operating Information | |||||||||||||||||||||||||||||||||||||
| Production (bpd in thousands) | 825.2 | 854.5 | 802.9 | Production (bpd in thousands) | 937.1 | 852.2 | 737.1 | |||||||||||||||||||||||||||||||
| Crude oil and feedstocks throughput (bpd in thousands) | 823.1 | 849.7 | 807.4 | Crude oil and feedstocks throughput (bpd in thousands) | 925.1 | 834.5 | 727.7 | |||||||||||||||||||||||||||||||
| Total crude oil and feedstocks throughput (millions of barrels) | 300.4 | 310.0 | 294.7 | Total crude oil and feedstocks throughput (millions of barrels) | 337.7 | 304.6 | 266.3 | |||||||||||||||||||||||||||||||
| Consolidated gross margin per barrel of throughput | $ | 3.04 | $ | 1.94 | $ | 3.25 | Consolidated gross margin per barrel of throughput | $ | 13.85 | $ | 2.91 | $ | (6.12) | |||||||||||||||||||||||||
Gross refining margin, excluding special items, per barrel of throughput (1) | $ | 8.51 | $ | 9.09 | $ | 8.08 | Gross refining margin, excluding special items, per barrel of throughput (1) | $ | 22.00 | $ | 7.94 | $ | 3.23 | |||||||||||||||||||||||||
| Refinery operating expense, per barrel of throughput | $ | 5.61 | $ | 5.34 | $ | 5.52 | Refinery operating expense, per barrel of throughput | $ | 7.39 | $ | 6.56 | $ | 6.89 | |||||||||||||||||||||||||
Crude and feedstocks (% of total throughput) (2) | Crude and feedstocks (% of total throughput) (2) | |||||||||||||||||||||||||||||||||||||
| Heavy | 32 | % | 36 | % | 34 | % | Heavy | 32 | % | 34 | % | 42 | % | |||||||||||||||||||||||||
| Medium | 28 | % | 30 | % | 30 | % | Medium | 36 | % | 31 | % | 26 | % | |||||||||||||||||||||||||
| Light | 26 | % | 21 | % | 21 | % | Light | 18 | % | 18 | % | 17 | % | |||||||||||||||||||||||||
| Other feedstocks and blends | 14 | % | 13 | % | 15 | % | Other feedstocks and blends | 14 | % | 17 | % | 15 | % | |||||||||||||||||||||||||
| Total throughput | 100 | % | 100 | % | 100 | % | Total throughput | 100 | % | 100 | % | 100 | % | |||||||||||||||||||||||||
| Yield (% of total throughput) | Yield (% of total throughput) | |||||||||||||||||||||||||||||||||||||
| Gasoline and gasoline blendstocks | 49 | % | 50 | % | 50 | % | Gasoline and gasoline blendstocks | 47 | % | 53 | % | 51 | % | |||||||||||||||||||||||||
| Distillates and distillate blendstocks | 32 | % | 32 | % | 30 | % | Distillates and distillate blendstocks | 35 | % | 30 | % | 30 | % | |||||||||||||||||||||||||
| Lubes | 1 | % | 1 | % | 1 | % | Lubes | 1 | % | 1 | % | 1 | % | |||||||||||||||||||||||||
| Chemicals | 2 | % | 2 | % | 2 | % | Chemicals | 1 | % | 2 | % | 1 | % | |||||||||||||||||||||||||
| Other | 16 | % | 16 | % | 16 | % | Other | 17 | % | 16 | % | 18 | % | |||||||||||||||||||||||||
| Total yield | 100 | % | 101 | % | 99 | % | Total yield | 101 | % | 102 | % | 101 | % | |||||||||||||||||||||||||
——————————
(1) See Non-GAAP Financial Measures.
(2) We define heavy crude oil as crude oil with American Petroleum Institute (API)an API gravity of less than 24 degrees. We define medium crude oil as crude oil with an API gravity between 24 and 35 degrees. We define light crude oil as crude oil with an API gravity higher than 35 degrees.
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The table below summarizes certain market indicators relating to our operating results as reported by Platts.
| Year Ended December 31, | ||||||||||||
| 2019 | 2018 | 2017 | ||||||||||
| (dollars per barrel, except as noted) | ||||||||||||
| Dated Brent crude oil | $ | 64.34 | $ | 71.34 | $ | 54.18 | ||||||
| West Texas Intermediate (WTI) crude oil | $ | 57.03 | $ | 65.20 | $ | 50.79 | ||||||
| Light Louisiana Sweet (LLS) crude oil | $ | 62.67 | $ | 70.23 | $ | 54.02 | ||||||
| Alaska North Slope (ANS) crude oil | $ | 65.00 | $ | 71.54 | $ | 54.43 | ||||||
| Crack Spreads | ||||||||||||
| Dated Brent (NYH) 2-1-1 | $ | 12.68 | $ | 13.17 | $ | 14.74 | ||||||
| WTI (Chicago) 4-3-1 | $ | 15.25 | $ | 14.84 | $ | 15.88 | ||||||
| LLS (Gulf Coast) 2-1-1 | $ | 12.43 | $ | 12.30 | $ | 13.57 | ||||||
| ANS (West Coast) 4-3-1 | $ | 18.46 | $ | 15.48 | $ | 17.43 | ||||||
| Crude Oil Differentials | ||||||||||||
| Dated Brent (foreign) less WTI | $ | 7.31 | $ | 6.14 | $ | 3.39 | ||||||
| Dated Brent less Maya (heavy, sour) | $ | 6.76 | $ | 8.70 | $ | 7.16 | ||||||
| Dated Brent less WTS (sour) | $ | 8.09 | $ | 13.90 | $ | 4.37 | ||||||
| Dated Brent less ASCI (sour) | $ | 3.73 | $ | 4.64 | $ | 3.66 | ||||||
| WTI less WCS (heavy, sour) | $ | 13.61 | $ | 26.93 | $ | 12.24 | ||||||
| WTI less Bakken (light, sweet) | $ | 0.66 | $ | 2.86 | $ | (0.26 | ) | |||||
| WTI less Syncrude (light, sweet) | $ | 0.18 | $ | 6.84 | $ | (1.74 | ) | |||||
| WTI less LLS (light, sweet) | $ | (5.64 | ) | $ | (5.03 | ) | $ | (3.23 | ) | |||
| WTI less ANS (light, sweet) | $ | (7.97 | ) | $ | (6.34 | ) | $ | (3.63 | ) | |||
| Natural gas (dollars per MMBTU) | $ | 2.53 | $ | 3.07 | $ | 3.02 | ||||||
| Year Ended December 31, | ||||||||||||||||||||
| 2022 | 2021 | 2020 | ||||||||||||||||||
| (dollars per barrel, except as noted) | ||||||||||||||||||||
| Dated Brent crude oil | $ | 101.27 | $ | 70.89 | $ | 41.62 | ||||||||||||||
| West Texas Intermediate (WTI) crude oil | $ | 94.58 | $ | 68.10 | $ | 39.25 | ||||||||||||||
| Light Louisiana Sweet (LLS) crude oil | $ | 96.81 | $ | 69.59 | $ | 41.13 | ||||||||||||||
| Alaska North Slope (ANS) crude oil | $ | 98.76 | $ | 70.56 | $ | 42.20 | ||||||||||||||
| Crack Spreads | ||||||||||||||||||||
| Dated Brent (NYH) 2-1-1 | $ | 40.26 | $ | 16.84 | $ | 9.11 | ||||||||||||||
| WTI (Chicago) 4-3-1 | $ | 31.56 | $ | 16.34 | $ | 6.30 | ||||||||||||||
| LLS (Gulf Coast) 2-1-1 | $ | 37.56 | $ | 16.03 | $ | 7.59 | ||||||||||||||
| ANS (West Coast-LA) 4-3-1 | $ | 41.64 | $ | 20.10 | $ | 11.30 | ||||||||||||||
| ANS (West Coast-SF) 3-2-1 | $ | 41.89 | $ | 20.55 | $ | 9.99 | ||||||||||||||
| Crude Oil Differentials | ||||||||||||||||||||
| Dated Brent (foreign) less WTI | $ | 6.68 | $ | 2.80 | $ | 2.37 | ||||||||||||||
| Dated Brent less Maya (heavy, sour) | $ | 13.95 | $ | 6.47 | $ | 5.37 | ||||||||||||||
| Dated Brent less WTS (sour) | $ | 6.98 | $ | 2.63 | $ | 2.33 | ||||||||||||||
| Dated Brent less ASCI (sour) | $ | 9.68 | $ | 3.90 | $ | 1.81 | ||||||||||||||
| WTI less WCS (heavy, sour) | $ | 21.30 | $ | 14.19 | $ | 10.72 | ||||||||||||||
| WTI less Bakken (light, sweet) | $ | (4.05) | $ | (0.14) | $ | 2.41 | ||||||||||||||
| WTI less Syncrude (light, sweet) | $ | (3.04) | $ | 2.25 | $ | 2.13 | ||||||||||||||
| WTI less LLS (light, sweet) | $ | (2.22) | $ | (1.50) | $ | (1.88) | ||||||||||||||
| WTI less ANS (light, sweet) | $ | (4.17) | $ | (2.46) | $ | (2.95) | ||||||||||||||
| Natural gas (dollars per MMBTU) | $ | 6.54 | $ | 3.73 | $ | 2.13 | ||||||||||||||
2022 Compared to 20182021
Overview— PBF Energy net income was $375.2$2,972.8 million for the year ended December 31, 20192022 compared to net income of $175.3$315.5 million for the year ended December 31, 2018.2021. PBF LLC net income was $480.0$3,834.2 million for the year ended December 31, 20192022 compared to net income of $180.1$381.7 million for the year ended December 31, 2018.2021. Net income attributable to PBF Energy stockholders was $319.4$2,876.8 million, or $2.64$22.84 per diluted share, for the year ended December 31, 20192022 ($2.6422.84 per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income, or $0.90$23.36 per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income excluding special items, as described below in Non-GAAP Financial Measures) compared to net income attributable to PBF Energy stockholders of $128.3$231.0 million, or $1.10$1.90 per diluted share, for the year ended December 31, 20182021 ($1.101.90 per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income, or $3.26$(2.50) per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net incomeloss excluding special items, as described below in Non-GAAP Financial Measures). The net income attributable to PBF Energy stockholders represents PBF Energy’s equity interest in PBF LLC’s pre-tax income, less applicable income tax expense. PBF Energy’s weighted-average equity interest in PBF LLC was 99.0%99.3% and 98.3%99.2% for the years ended December 31, 20192022 and 2018,2021, respectively.
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Our results for the year ended December 31, 2019 were positively impacted by special items comprised of a non-cash, pre-tax LCM inventory adjustment of approximately $250.2 million, or $188.0 million net of tax and a pre-tax gain on the sale of land at our Torrance refinery of $33.1 million, or $24.9 million net of tax. Our results for the year ended December 31, 20182022 were negatively impacted by special items consisting of a non-cash, pre-
Excluding the impact of these special items, when comparing our results were negatively impactedto the year ended December 31, 2021, we experienced an increase in the demand for our refined products, evidenced by unfavorable movements in crude differentials and overall lowerhigher throughput volumes and barrels sold acrossat all of our refineries, partially offset by higheras well as overall stronger refining margins due to favorable movements in crack spreads realized atand crude oil differentials. These improving metrics have positively impacted our West Coast refinery. Refining margins for the current year compared to the prior year were weaker at our East Coast, Mid-Continentrevenues, gross margin, and Gulf Coast refineries, offset by significantly stronger margins realized on the West Coast. Our results for the year ended December 31, 2019 were also negatively impacted by increased operating expenses and depreciation and amortization expense associated with our continued investment in our refining assets and the effect of significant turnaround and maintenance activity during 2019.income.
Revenues— Revenues totaled $24.5$46.8 billion for the year ended December 31, 20192022 compared to $27.2$27.3 billion for the year ended December 31, 2018, a decrease2021, an increase of approximately $2.7$19.5 billion or 9.9%71.4%. Revenues per barrel sold were $69.93$123.26 and $77.08$80.79 for the years ended December 31, 20192022 and 2018,2021, respectively, a decreasean increase of 9.3%52.6% directly related to lowerhigher hydrocarbon commodity prices. For the year ended December 31, 2019,2022, the total throughput rates at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 336,400300,300 bpd, 153,000148,500 bpd, 177,900180,700 bpd and 155,800295,600 bpd, respectively. For the year ended December 31, 2018,2021, the total throughput rates at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 344,700250,900 bpd, 149,600134,100 bpd, 185,600163,300 bpd and 169,800286,200 bpd, respectively. The throughput rates at our East Coast and West Coast refineries were lower in the year ended December 31, 2019 compared to the same period in 2018 due to planned downtime associated with turnarounds of the coker and associated units at our Delaware City and Torrance refineries and the crude unit at our Paulsboro refinery, all of which were completed in the first half of 2019, and unplanned downtime at our Delaware City refinery in the first quarter of 2019. Throughput rates at our Mid-Continent refinery were higher in the current year compared to the prior year due to a planned turnaround at our Toledo refinery in the first half of the prior year. Throughput rates at our Gulf Coast refinery were lower in the year ended December 31, 2019 compared to the same period in 2018 due to unplanned downtime in the fourth quarter of 2019. For the year ended December 31, 2019,2022, the total barrels sold at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 382,500353,800 bpd, 163,900158,200 bpd, 225,300190,600 bpd and 188,600338,400 bpd, respectively. For the year ended December 31, 2018,2021, the total barrels sold at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 372,700292,500 bpd, 161,800142,600 bpd, 233,700170,400 bpd and 198,100318,700 bpd, respectively.
Overall average 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 theour refineries.
Consolidated Gross Margin— Consolidated gross margin totaled $913.1$4,678.6 million for the year ended December 31, 2019,2022, compared to $602.6$887.2 million for the year ended December 31, 2018,2021, an increase of $310.5$3,791.4 million. Gross refining margin (as described below in Non-GAAP Financial Measures) totaled $2,801.2$7,429.9 million, or $9.34$22.00 per barrel of throughput, for the year ended December 31, 20192022 compared to $2,419.4$3,087.7 million, or $7.79$10.14 per barrel of throughput, for the year ended December 31, 2018,2021, an increase of approximately $381.8$4,342.2 million. Gross refining margin excluding special items totaled $2,551.0$7,429.9 million, or $8.51$22.00 per barrel of throughput, for the year ended December 31, 20192022 compared to $2,823.0$2,418.1 million, or $9.09$7.94 per barrel of throughput, for the year ended December 31, 2018, a decrease2021, an increase of $272.0$5,011.8 million.
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During the year ended December 31, 2022, our margin calculations were not impacted by special items. Consolidated gross margin and gross refining margin were positively impactedincreased due to favorable movements in certain crack spreads and crude oil differentials and higher throughput volumes and barrels sold at all our refineries. For the current year byended December 31, 2021, our margin calculations included a favorable special item related to a non-cash LCM inventory adjustment of approximately $250.2$669.6 million on a net basis resulting from the increase in crude oil and refined product prices from the year ended 2018. Gross refining margin excluding the impact of special items decreased dueDecember 31, 2020 to unfavorable movements in certain crude differentials and refining margins and reduced throughput rates at the majority of our refineries, partially offset by higher throughput rates in the Mid-Continent and stronger crack spreads on the West Coast. For the year ended December 31, 2018, special items impacting our margin calculations included a non-cash LCM inventory adjustment of approximately $351.3 million
Additionally, our results continue to be impacted by significant costs to comply with the RFS, although at a reduced level from the prior year.RFS. Total RFS costs were $122.7$1,225.5 million for the year ended December 31, 20192022 compared with $143.9to $726.0 million for the year ended December 31, 2018.2021.
Average industry margins were mixedfavorable during the year ended December 31, 20192022 compared withto the prior year, primarily due to increased refining margins as a result of varying regional product inventory levelssustained demand and seasonal and unplanned refining downtime issues impacting product margins. Crude oil differentials were generally unfavorable compared with the prior year, with notable light-heavy crude differential compression negatively impacting our gross refining margin and moving our overall crude slate lighter.
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.
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Operating Expenses— Operating expenses totaled $1,782.3$2,599.0 million for the year ended December 31, 20192022 compared to $1,721.0$2,085.9 million for the year ended December 31, 2018,2021, an increase of approximately $61.3$513.1 million, or 3.6%24.6%. Of the total $1,782.3$2,599.0 million ofin operating expenses, for the year ended December 31, 2019, $1,684.3$2,495.6 million, or $5.617.39 per barrel of throughput, related to expenses incurred by the Refining segment, while the remaining $98.0$103.4 million related to expenses incurred by the Logistics segment ($1,654.81,999.1 million or $5.346.56 per barrel of throughput, and $66.2$86.8 million of operating expenses for the year ended December 31, 20182021 related to the Refining and Logistics segments, respectively). IncreasesThe increase in operating expenses werewas mainly attributedattributable to higher outside service costs related to turnaroundincreases in natural gas volumes and maintenance activity. Operating expenses related toprice across our Logistics segment increasedrefineries when compared to 2018the prior year. Additionally, we experienced higher outside services, maintenance and operational costs due to expenses related to the operations of PBFX’s recently acquired assets and higher environmental clean-up remediation costs and product contamination remediation costs.increased production.
General and Administrative Expenses— General and administrative expenses totaled $284.0$468.7 million for the year ended December 31, 2019,2022, compared to $277.0$247.3 million for the year ended December 31, 2018,2021, an increase of $7.0$221.4 million or 2.5%89.5%. The increase in general and administrative expenses for the year ended December 31, 2019 compared with the year ended December 31, 2018is primarily related to higher outside services, including legal settlement charges, and transaction costs related toemployee-related expenses, certain of which includes the Martinez Acquisition, partially offset by a reduction inrecognition 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 $436.1$511.1 million for the year ended December 31, 20192022 (including $425.3$503.6 million recorded within Cost of sales) compared to $369.7$466.8 million for the year ended December 31, 20182021 (including $359.1$453.5 million recorded within Cost of sales), an increase of $66.4$44.3 million. The increase was a result of additional depreciation expense associated with a general increase in our fixed asset base due to capital projects and turnarounds completed during 2019since the end of the prior year.
Change in Fair Value of Contingent Consideration, net— Change in fair value of contingent consideration represented a loss of $48.3 million and 2018, as well as accelerated amortizationa loss of $32.4 million for the years ended December 31, 2022 and December 31, 2021, respectively. These losses were primarily related to the Delaware City and Torrancechanges in estimated fair value of the earn-out liability associated with the acquisition of the Martinez refinery, turnarounds, which were completed inoffset by the first halfrecognition of 2019.contingent assets associated with the acquisition.
Loss (Gain) on Sale of Assets— 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. There was a gain of $3.0 million for the year ended December 31, 2021 related primarily to a third-party sale of PBFX real property.
Change in Tax Receivable Agreement Liability—There was no change in the Tax Receivable Agreement liability for the year ended December 31, 2019. Change in the Tax Receivable Agreement liability for the year ended December 31, 20182022 and December 31, 2021, represented a gaincharge of $13.9 million.$290.3 million and a charge of $48.3 million, respectively. These charges were primarily the result of changes in the deferred tax asset valuation allowance recorded in accordance with Accounting Standards Codification (“ASC”) 740 Income Taxes (“ASC 740”), related to the reduction of deferred tax assets associated with the payments made or expected to be made in connection with the Tax Receivable Agreement liability.
Change in Fair Value of Catalyst Obligations— Change in the fair value of catalyst obligations represented a loss of $9.7$2.0 million for the year ended December 31, 2019,2022, compared to a gain of $5.6$8.5 million for the year ended December 31, 2018.2021. These gainslosses and lossesgains relate to the change in fair value of the precious metals underlying the sale and leaseback of our refineries’ precious metal catalysts, which we are obligated to repurchase at fair market value upon lease termination.
(Loss) Gain on Extinguishment of Debt— We incurred a loss on extinguishment of debt of $66.1 million in the catalyst financing arrangement termination dates.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 our 2028 Senior Notes and 2025 Senior Notes. We incurred a gain on extinguishment of debt of $79.9 million in the year ended December 31, 2021 related to the repurchase of a portion of our 2028 Senior Notes and 2025 Senior Notes.
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Interest Expense, net— PBF Energy interest expense totaled $159.6$246.0 million for the year ended December 31, 2019,2022, compared to $169.9$317.5 million for the year ended December 31, 2018,2021, a decrease of $10.3$71.5 million. This net decrease is mainly attributable to the redemption of the 2025 Senior Secured Notes during the third quarter of 2022, as well as lower outstanding revolver borrowings for the year ended December 31, 2019.balances on our revolving credit facilities. Interest expense includes interest on long-term debt including the PBFX credit facilities, costs related to the sale and leaseback of our precious metal catalysts, financing costs associated with the Third Inventory Intermediation AgreementsAgreement with J. Aron, letter of credit fees associated with the purchase of certain crude oils and the amortization of deferred financing costs. PBF LLC interest expense totaled $169.1$257.2 million and $178.5$327.8 million for the year ended December 31, 20192022 and December 31, 2018,2021, respectively (inclusive of $9.5$11.2 million and $8.6$10.3 million, respectively, of incremental interest expense on the affiliate note payable with PBF Energy that eliminates in consolidation atin the PBF Energy level)consolidated financial statements).
Income Tax Expense— PBF LLC is organized as a limited liability company and PBFX is an MLP,a partnership, both of which are treated as “flow-through” entities for federal income tax purposes and therefore are not subject to income tax. However, two subsidiaries of Chalmette Refining and our Canadian subsidiary, PBF Energy Limited, (“PBF Ltd.”), are treated as C-Corporations for income tax purposes and may incur income taxes with respect to their earnings, as applicable. The members of PBF LLC are required to include their proportionate share of PBF LLC’s taxable income or loss, which includes PBF LLC’s allocable share of PBFX’s pre-tax income or loss, on their respective tax returns. PBF LLC generally makes distributions to its members, per the terms of PBF LLC’s amended and restated limited liability company agreement, related to such taxes on a pro-rata basis. PBF Energy recognizes an income tax expense or benefit in our consolidated financial statements based on PBF Energy’s allocable share of PBF LLC’s pre-tax income or loss, which was approximately 99.0%99.3% and 98.3%99.2%, on a weighted-average basis for the years ended December 31, 20192022 and 2018,2021, respectively. PBF Energy’s Consolidated Financial Statements do not reflect any benefit or provision for income taxes on the pre-tax income or loss attributable to the noncontrolling interests in PBF LLC or PBFX (although, as described above, PBF LLC must make tax distributions
to all its members on a pro-rata basis). PBF Energy’s effective tax rate, excludingincluding the impact of noncontrolling interest,interests, for the years ended December 31, 20192022 and 20182021 was 21.8%16.4% and 16.0%3.7%, respectively, reflectingrespectively. The effective tax adjustmentsrate for discrete items andboth years was significantly impacted by changes in the impactdeferred tax valuation allowance. In 2022, the full valuation allowance was released, resulting in a tax benefit of $308.5 million for the year ended December 31, 2022, compared to a tax return to income tax provision adjustments.benefit of $49.9 million for the year ended December 31, 2021.
Noncontrolling Interest— PBF Energy is the sole managing member of, and has a controlling interest in, PBF LLC. As the sole managing member of PBF LLC, PBF Energy operates and controls all of the business and affairs of PBF LLC and its subsidiaries. PBF Energy consolidates the financial results of PBF LLC and its subsidiaries, including PBFX. With respect to the consolidation of PBF LLC, the Company recordswe record a noncontrolling interest for the economic interest in PBF LLC held by members other than PBF Energy, and with respect to the consolidation of PBFX, the Company recordswe recorded a noncontrolling interest for the economic interests in PBFX held by the public unitholders of PBFX prior to the close of the PBFX Merger Transaction, and with respect to the consolidation of PBF Holding, the Company recordswe record a 20% noncontrolling interest for the ownership interests in two subsidiaries of Chalmette Refining held by a third party.third-party. The total noncontrolling interest on the Consolidated Statements of Operations represents the portion of the Company’s earnings or loss attributable to the economic interests held by members of PBF LLC other than PBF Energy, by the public common unitholders of PBFX prior to the close of the PBFX Merger Transaction and by the third-party stockholders of certain of Chalmette Refining’s subsidiaries. The total noncontrolling interest on the Consolidated Balance Sheets represents the portion of the Company’s net assets attributable to the economic interests held by the members of PBF LLC other than PBF Energy, by the public common unitholders of PBFX and by the third-party stockholders of the two Chalmette Refining subsidiaries. PBF Energy’s weighted-average equity noncontrolling interest ownership percentage in PBF LLC for the years ended December 31, 20192022 and 20182021 was approximately 1.0%0.7% and 1.7%0.8%, respectively. The carrying amount of the noncontrolling interest on our Consolidated Balance Sheets attributable to the noncontrolling interest is not equal to the noncontrolling interest ownership percentage due to the effect of income taxes and related agreements that pertain solely to PBF Energy.
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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. Such Non-GAAP financial measures are presented only in the context of PBF Energy’s results and are not presented or discussed in respect to PBF LLC.
Special Items
The Non-GAAP measures presented include Adjusted Fully-Converted Net Income (Loss) excluding special items, gross refining margin excluding special items, EBITDA excluding special items, and gross refining marginnet debt to capitalization excluding special items. Special items for the periods presented relate to LCM inventory adjustments, gains on salenet changes in fair value of assets at our Torrance refinery,contingent consideration, changes in the Tax Receivable Agreement liability, loss (gain) on extinguishment of debt, gain on sale of hydrogen plants, severance and reconfiguration costs, impairment expense, net tax (benefit) expense on remeasurement of deferred tax assets, gains on land sales, charges associated with the early return of certain leased railcars, debt extinguishmentturnaround acceleration costs, a net tax benefit related to the TCJA enactment and a net tax expense associated with the remeasurement of Tax Receivable Agreement associated deferred tax assets.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.
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Adjusted Fully-Converted Net Income (Loss) and Adjusted Fully-Converted Net Income (Loss) Excluding Special Items
PBF Energy utilizes results presented on an Adjusted Fully-Converted basis that reflects an assumed exchange of all PBF LLC Series A Units for shares of PBF Energy Class A common stock. In addition, we present results on an Adjusted Fully-Converted basis excluding special items as described above. We believe that these Adjusted Fully-Converted measures, when presented in conjunction with comparable GAAP measures, are useful to investors to compare PBF Energy results across different periods and to facilitate an understanding of our operating results.
Neither Adjusted Fully-Converted Net Income (Loss) nor Adjusted Fully-Converted Net Income (Loss) excluding special items should be considered an alternative to net income (loss) presented in accordance with GAAP. Adjusted Fully-Converted Net Income (Loss) and Adjusted Fully-Converted Net Income (Loss) excluding special items presented by other companies may not be comparable to our presentation, since each company may define these terms differently. The differences between Adjusted Fully-Converted and GAAP results are as follows:
1.Assumed exchange of all PBF LLC Series A Units for shares of PBF Energy Class A common stock. As a result of the assumed exchange of all PBF LLC Series A Units, the noncontrolling interest related to these units is converted to controlling interest. Management believes that it is useful to provide the per-share effect associated with the assumed exchange of all PBF LLC Series A Units. 2.Income Taxes. Prior to PBF Energy’s IPO, PBF Energy was organized as a limited liability company treated as a “flow-through” entity for income tax purposes, and even after PBF Energy’s IPO, not all of its earnings are subject to corporate-level income taxes. Adjustments have been made to the Adjusted Fully-Converted tax provisions and earnings to assume that PBF Energy had adopted its post-IPO corporate tax structure for all periods presented and is taxed as a C-corporation in the U.S. at the prevailing corporate rates. These assumptions are consistent with the assumption in clause 1 above that all PBF LLC Series A Units are exchanged for shares of PBF Energy Class A common stock, as the assumed exchange would change the amount of PBF Energy’s earnings that are subject to corporate income tax. 81 | |
The following table reconciles PBF Energy’s Adjusted Fully-Converted results with its results presented in accordance with GAAP for the years ended December 31, 2019, 20182022, 2021 and 20172020 (in millions, except share and per share amounts):
| Year Ended December 31, | ||||||||||||
| 2019 | 2018 | 2017 | ||||||||||
| Net income attributable to PBF Energy Inc. stockholders | $ | 319.4 | $ | 128.3 | $ | 415.6 | ||||||
| Less: Income allocated to participating securities | 0.5 | 0.7 | 1.0 | |||||||||
| Income available to PBF Energy Inc. stockholders - basic | 318.9 | 127.6 | 414.6 | |||||||||
Add: Net income attributable to noncontrolling interests(1) | 4.3 | 4.6 | 16.7 | |||||||||
Less: Income tax expense(2) | (1.0 | ) | (1.2 | ) | (6.6 | ) | ||||||
| Adjusted fully-converted net income | $ | 322.2 | $ | 131.0 | $ | 424.7 | ||||||
Special Items:(3) | ||||||||||||
| Add: Non-cash LCM inventory adjustment | (250.2 | ) | 351.3 | (295.5 | ) | |||||||
| Add: Change in Tax Receivable Agreement liability | — | (13.9 | ) | (250.9 | ) | |||||||
| Add: Debt extinguishment costs | — | — | 25.5 | |||||||||
Add: Net tax benefit related to the TCJA | — | — | (173.3 | ) | ||||||||
| Add: Net tax expense on remeasurement of Tax Receivable Agreement associated deferred tax assets | — | — | 193.4 | |||||||||
| Add: Gain on Torrance land sale | (33.1 | ) | (43.8 | ) | — | |||||||
| Add: Early railcar return expense | — | 52.3 | — | |||||||||
| Less: Recomputed income taxes on special items | 70.4 | (89.9 | ) | 206.3 | ||||||||
| Adjusted fully-converted net income excluding special items | $ | 109.3 | $ | 387.0 | $ | 130.2 | ||||||
| Weighted-average shares outstanding of PBF Energy Inc. | 119,887,646 | 115,190,262 | 109,779,407 | |||||||||
Conversion of PBF LLC Series A Units (4) | 1,207,581 | 1,938,089 | 3,823,783 | |||||||||
Common stock equivalents (5) | 758,072 | 1,645,255 | 295,655 | |||||||||
| Fully-converted shares outstanding—diluted | 121,853,299 | 118,773,606 | 113,898,845 | |||||||||
| Diluted net income per share | $ | 2.64 | $ | 1.10 | $ | 3.73 | ||||||
| Adjusted fully-converted net income per fully exchanged, fully diluted shares outstanding | $ | 2.64 | $ | 1.10 | $ | 3.73 | ||||||
| Adjusted fully-converted net income excluding special items per fully exchanged, fully diluted shares outstanding | $ | 0.90 | $ | 3.26 | $ | 1.14 | ||||||
| Year Ended December 31, | ||||||||||||||||||||
| 2022 | 2021 | 2020 | ||||||||||||||||||
| Net income (loss) attributable to PBF Energy Inc. stockholders | $ | 2,876.8 | $ | 231.0 | $ | (1,392.4) | ||||||||||||||
| Less: Income allocated to participating securities | — | — | 0.1 | |||||||||||||||||
| Income (loss) available to PBF Energy Inc. stockholders - basic | 2,876.8 | 231.0 | (1,392.5) | |||||||||||||||||
Add: Net income (loss) attributable to noncontrolling interests(1) | 27.9 | 2.4 | (17.1) | |||||||||||||||||
Less: Income tax (expense) benefit (2) | (7.2) | (0.6) | 4.6 | |||||||||||||||||
| Adjusted fully-converted net income (loss) | $ | 2,897.5 | $ | 232.8 | $ | (1,405.0) | ||||||||||||||
Special Items:(3) | ||||||||||||||||||||
| Add: Non-cash LCM inventory adjustment | — | (669.6) | 268.0 | |||||||||||||||||
| Add: Change in fair value of contingent consideration, net | 48.3 | 32.4 | (93.7) | |||||||||||||||||
| Add: Gain on sale of hydrogen plants | — | — | (471.1) | |||||||||||||||||
| Add: Gain on land sales | — | (2.8) | (8.1) | |||||||||||||||||
| Add: Impairment expense | — | — | 98.8 | |||||||||||||||||
| Add: LIFO inventory decrement | — | — | 83.0 | |||||||||||||||||
| Add: Turnaround acceleration costs | — | — | 56.2 | |||||||||||||||||
| 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 | |||||||||||||||||
| Add: Change in Tax Receivable Agreement liability | 290.3 | 48.3 | (373.5) | |||||||||||||||||
| Add: Net tax (benefit) expense on remeasurement of deferred tax assets | (233.8) | (37.4) | 259.1 | |||||||||||||||||
| Less: Recomputed income tax on special items | (104.9) | 173.9 | 99.9 | |||||||||||||||||
| Adjusted fully-converted net income (loss) excluding special items | $ | 2,963.5 | $ | (302.3) | $ | (1,421.7) | ||||||||||||||
| Weighted-average shares outstanding of PBF Energy Inc. | 122,598,076 | 120,240,009 | 119,617,998 | |||||||||||||||||
Conversion of PBF LLC Series A Units (4) | 917,991 | 988,730 | 1,042,667 | |||||||||||||||||
Common stock equivalents (5) | 3,344,039 | 1,409,415 | — | |||||||||||||||||
| Fully-converted shares outstanding—diluted | 126,860,106 | 122,638,154 | 120,660,665 | |||||||||||||||||
| Diluted net income (loss) per share | $ | 22.84 | $ | 1.90 | $ | (11.64) | ||||||||||||||
Adjusted fully-converted net income (loss) per fully exchanged, fully diluted shares outstanding (5) | $ | 22.84 | $ | 1.90 | $ | (11.64) | ||||||||||||||
| Adjusted fully-converted net income (loss) excluding special items per fully exchanged, fully diluted shares outstanding | $ | 23.36 | $ | (2.50) | $ | (11.78) | ||||||||||||||
——————————
See Notes to Non-GAAP Financial Measures.
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Gross Refining Margin and Gross Refining Margin Excluding Special Items
Gross refining margin is defined as consolidated gross margin excluding refinery depreciation, refinery operating expense,expenses, and gross margin of PBFX. 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 refinery 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 | |||||||||||||||||||||||||||
| $ | per barrel of throughput | $ | per barrel of throughput | $ | per barrel of throughput | ||||||||||||||||||||||||
| Calculation of consolidated gross margin: | |||||||||||||||||||||||||||||
| Revenues | $ | 46,830.3 | $ | 138.69 | $ | 27,253.4 | $ | 89.46 | $ | 15,115.9 | $ | 56.76 | |||||||||||||||||
| Less: Cost of sales | 42,151.7 | 124.84 | 26,366.2 | 86.55 | 16,745.6 | 62.88 | |||||||||||||||||||||||
| Consolidated gross margin | $ | 4,678.6 | $ | 13.85 | $ | 887.2 | $ | 2.91 | $ | (1,629.7) | $ | (6.12) | |||||||||||||||||
| Reconciliation of consolidated gross margin to gross refining margin: | |||||||||||||||||||||||||||||
| Consolidated gross margin | $ | 4,678.6 | $ | 13.85 | $ | 887.2 | $ | 2.91 | $ | (1,629.7) | $ | (6.12) | |||||||||||||||||
| Add: PBFX operating expense | 121.4 | 0.36 | 103.4 | 0.35 | 99.9 | 0.38 | |||||||||||||||||||||||
| Add: PBFX depreciation expense | 36.7 | 0.11 | 37.8 | 0.13 | 53.7 | 0.19 | |||||||||||||||||||||||
| Less: Revenues of PBFX | (369.3) | (1.09) | (355.5) | (1.17) | (360.3) | (1.35) | |||||||||||||||||||||||
| Add: Refinery operating expenses | 2,495.6 | 7.39 | 1,999.1 | 6.56 | 1,835.2 | 6.89 | |||||||||||||||||||||||
| Add: Refinery depreciation expense | 466.9 | 1.38 | 415.7 | 1.36 | 498.0 | 1.87 | |||||||||||||||||||||||
| Gross refining margin | $ | 7,429.9 | $ | 22.00 | $ | 3,087.7 | $ | 10.14 | $ | 496.8 | $ | 1.86 | |||||||||||||||||
Special Items: (3) | |||||||||||||||||||||||||||||
| Add: Non-cash LCM inventory adjustment | — | — | (669.6) | (2.20) | 268.0 | 1.01 | |||||||||||||||||||||||
| Add: LIFO inventory decrement | — | — | — | — | 83.0 | 0.31 | |||||||||||||||||||||||
| 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 | |||||||||||||||||
| Year Ended December 31, | |||||||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||||||
| $ | per barrel of throughput | $ | per barrel of throughput | $ | per barrel of throughput | ||||||||||||||||
| Calculation of consolidated gross margin: | |||||||||||||||||||||
| Revenues | $ | 24,508.2 | $ | 81.58 | $ | 27,186.1 | $ | 87.67 | $ | 21,786.6 | $ | 73.92 | |||||||||
| Less: Cost of sales | 23,595.1 | 78.54 | 26,583.5 | 85.73 | 20,826.0 | 70.67 | |||||||||||||||
| Consolidated gross margin | $ | 913.1 | $ | 3.04 | $ | 602.6 | $ | 1.94 | $ | 960.6 | $ | 3.25 | |||||||||
| Reconciliation of consolidated gross margin to gross refining margin: | |||||||||||||||||||||
| Consolidated gross margin | $ | 913.1 | $ | 3.04 | $ | 602.6 | $ | 1.94 | $ | 960.6 | $ | 3.25 | |||||||||
| Add: PBFX operating expense | 118.7 | 0.40 | 84.4 | 0.27 | 66.4 | 0.23 | |||||||||||||||
| Add: PBFX depreciation expense | 38.6 | 0.13 | 29.4 | 0.09 | 23.7 | 0.08 | |||||||||||||||
| Less: Revenues of PBFX | (340.2 | ) | (1.13 | ) | (281.5 | ) | (0.91 | ) | (254.8 | ) | (0.86 | ) | |||||||||
| Add: Refinery operating expense | 1,684.3 | 5.61 | 1,654.8 | 5.34 | 1,626.4 | 5.52 | |||||||||||||||
| Add: Refinery depreciation expense | 386.7 | 1.29 | 329.7 | 1.06 | 254.3 | 0.86 | |||||||||||||||
| Gross refining margin | $ | 2,801.2 | $ | 9.34 | $ | 2,419.4 | $ | 7.79 | $ | 2,676.6 | $ | 9.08 | |||||||||
Special Items: (3) | |||||||||||||||||||||
| Add: Non-cash LCM inventory adjustment | (250.2 | ) | (0.83 | ) | 351.3 | 1.13 | (295.5 | ) | (1.00 | ) | |||||||||||
| Add: Early railcar return expense | — | — | 52.3 | 0.17 | — | — | |||||||||||||||
| Gross refining margin excluding special items | $ | 2,551.0 | $ | 8.51 | $ | 2,823.0 | $ | 9.09 | $ | 2,381.1 | $ | 8.08 | |||||||||
——————————
See Notes to Non-GAAP Financial Measures.
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EBITDA, EBITDA Excluding Special Items and Adjusted EBITDA
Our management uses EBITDA (earnings before interest, income taxes, depreciation and amortization), 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 boardBoard of directors,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, the non-cash change in the fair value of catalyst obligations, gain on sale of hydrogen plants, the write down of inventory to the LCM, changes in the liability for Tax Receivable Agreement liability due to factors out of PBF Energy’s control such as changes in tax rates, loss (gain) on extinguishment of debt, extinguishment costs related to refinancing activitieschange in the fair value of contingent 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.
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The following tables reconcile net income (loss) as reflected in PBF Energy’s results of operations to EBITDA, EBITDA excluding special items and Adjusted EBITDA for the periods presented (in millions):
| Year Ended December 31, | ||||||||||||||||||||||||||||||||||||
| Year Ended December 31, | 2022 | 2021 | 2020 | |||||||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | ||||||||||||||||||||||||||||||||||
| Reconciliation of net income to EBITDA and EBITDA excluding special items: | ||||||||||||||||||||||||||||||||||||
| Net income | $ | 375.2 | $ | 175.3 | $ | 483.4 | ||||||||||||||||||||||||||||||
| Reconciliation of net income (loss) to EBITDA and EBITDA excluding special items: | Reconciliation of net income (loss) to EBITDA and EBITDA excluding special items: | |||||||||||||||||||||||||||||||||||
| Net income (loss) | Net income (loss) | $ | 2,972.8 | $ | 315.5 | $ | (1,333.3) | |||||||||||||||||||||||||||||
| Add: Depreciation and amortization expense | Add: Depreciation and amortization expense | 436.1 | 369.7 | 291.0 | Add: Depreciation and amortization expense | 511.1 | 466.8 | 563.0 | ||||||||||||||||||||||||||||
| Add: Interest expense, net | Add: Interest expense, net | 159.6 | 169.9 | 154.4 | Add: Interest expense, net | 246.0 | 317.5 | 258.2 | ||||||||||||||||||||||||||||
| Add: Income tax expense | Add: Income tax expense | 104.3 | 33.5 | 315.6 | Add: Income tax expense | 584.8 | 12.1 | 2.1 | ||||||||||||||||||||||||||||
| EBITDA | EBITDA | $ | 1,075.2 | $ | 748.4 | $ | 1,244.4 | EBITDA | $ | 4,314.7 | $ | 1,111.9 | $ | (510.0) | ||||||||||||||||||||||
Special Items: (3) | Special Items: (3) | Special Items: (3) | ||||||||||||||||||||||||||||||||||
| Add: Non-cash LCM inventory adjustment | Add: Non-cash LCM inventory adjustment | (250.2 | ) | 351.3 | (295.5 | ) | Add: Non-cash LCM inventory adjustment | — | (669.6) | 268.0 | ||||||||||||||||||||||||||
| Add: Change in fair value of contingent consideration, net | Add: Change in fair value of contingent consideration, net | 48.3 | 32.4 | (93.7) | ||||||||||||||||||||||||||||||||
| Add: Gain on sale of hydrogen plants | Add: Gain on sale of hydrogen plants | — | — | (471.1) | ||||||||||||||||||||||||||||||||
| Add: Gain on land sales | Add: Gain on land sales | — | (2.8) | (8.1) | ||||||||||||||||||||||||||||||||
| Add: Impairment expense | Add: Impairment expense | — | — | 98.8 | ||||||||||||||||||||||||||||||||
| Add: LIFO inventory decrement | Add: LIFO inventory decrement | — | — | 83.0 | ||||||||||||||||||||||||||||||||
| Add: Severance and reconfiguration costs | Add: Severance and reconfiguration costs | — | — | 30.0 | ||||||||||||||||||||||||||||||||
| Add: Early railcar return expense | Add: Early railcar return expense | — | — | 12.5 | ||||||||||||||||||||||||||||||||
| Add: Loss (gain) on extinguishment of debt | Add: Loss (gain) on extinguishment of debt | 66.1 | (79.9) | 22.2 | ||||||||||||||||||||||||||||||||
| Add: Change in Tax Receivable Agreement liability | Add: Change in Tax Receivable Agreement liability | — | (13.9 | ) | (250.9 | ) | Add: Change in Tax Receivable Agreement liability | 290.3 | 48.3 | (373.5) | ||||||||||||||||||||||||||
| Add: Debt extinguishment costs | — | — | 25.5 | |||||||||||||||||||||||||||||||||
| Add: Gain on Torrance land sale | (33.1 | ) | (43.8 | ) | — | |||||||||||||||||||||||||||||||
| Add: Early railcar return expense | — | 52.3 | — | |||||||||||||||||||||||||||||||||
| EBITDA excluding special items | EBITDA excluding special items | $ | 791.9 | $ | 1,094.3 | $ | 723.5 | EBITDA excluding special items | $ | 4,719.4 | $ | 440.3 | $ | (941.9) | ||||||||||||||||||||||
| Reconciliation of EBITDA to Adjusted EBITDA: | Reconciliation of EBITDA to Adjusted EBITDA: | Reconciliation of EBITDA to Adjusted EBITDA: | ||||||||||||||||||||||||||||||||||
| EBITDA | EBITDA | $ | 1,075.2 | $ | 748.4 | $ | 1,244.4 | EBITDA | $ | 4,314.7 | $ | 1,111.9 | $ | (510.0) | ||||||||||||||||||||||
| Add: Stock based compensation | Add: Stock based compensation | 37.3 | 26.0 | 26.8 | Add: Stock based compensation | 54.3 | 35.6 | 34.2 | ||||||||||||||||||||||||||||
| Add: Net non-cash change in fair value of catalyst obligations | 9.7 | (5.6 | ) | 2.2 | ||||||||||||||||||||||||||||||||
| Add: Change in fair value of catalyst obligations | Add: Change in fair value of catalyst obligations | 2.0 | (8.5) | 11.8 | ||||||||||||||||||||||||||||||||
Add: Non-cash LCM inventory adjustment (3) | Add: Non-cash LCM inventory adjustment (3) | (250.2 | ) | 351.3 | (295.5 | ) | Add: Non-cash LCM inventory adjustment (3) | — | (669.6) | 268.0 | ||||||||||||||||||||||||||
Add: Change in fair value of contingent consideration, net (3) | Add: Change in fair value of contingent consideration, net (3) | 48.3 | 32.4 | (93.7) | ||||||||||||||||||||||||||||||||
Add: Gain on sale of hydrogen plants (3) | Add: Gain on sale of hydrogen plants (3) | — | — | (471.1) | ||||||||||||||||||||||||||||||||
Add: Gain on land sales (3) | Add: Gain on land sales (3) | — | (2.8) | (8.1) | ||||||||||||||||||||||||||||||||
Add: Impairment expense (3) | Add: Impairment expense (3) | — | — | 98.8 | ||||||||||||||||||||||||||||||||
Add: LIFO inventory decrement (3) | Add: LIFO inventory decrement (3) | — | — | 83.0 | ||||||||||||||||||||||||||||||||
Add: Severance and reconfiguration costs (3) | Add: Severance and reconfiguration costs (3) | — | — | 30.0 | ||||||||||||||||||||||||||||||||
Add: Early railcar return expense (3) | Add: Early railcar return expense (3) | — | — | 12.5 | ||||||||||||||||||||||||||||||||
Add: Loss (gain) on extinguishment of debt (3) | Add: Loss (gain) on extinguishment of debt (3) | 66.1 | (79.9) | 22.2 | ||||||||||||||||||||||||||||||||
Add: Change in Tax Receivable Agreement liability (3) | Add: Change in Tax Receivable Agreement liability (3) | — | (13.9 | ) | (250.9 | ) | Add: Change in Tax Receivable Agreement liability (3) | 290.3 | 48.3 | (373.5) | ||||||||||||||||||||||||||
Add: Debt extinguishment costs (3) | — | — | 25.5 | |||||||||||||||||||||||||||||||||
| Adjusted EBITDA | Adjusted EBITDA | $ | 872.0 | $ | 1,106.2 | $ | 752.5 | Adjusted EBITDA | $ | 4,775.7 | $ | 467.4 | $ | (895.9) | ||||||||||||||||||||||
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See Notes to Non-GAAP Financial Measures.
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Net Debt to Capitalization Ratio and Net Debt to Capitalization Ratio Excluding Special Items
The total debt to capitalization ratio is calculated by dividing total debt by the sum of total debt and total equity. This ratio is a measurement that management believes is useful to investors in analyzing our leverage. Net debt and the net debt to capitalization ratio are Non-GAAP measures. Net debt is calculated by subtracting cash and cash equivalents from total debt. We believe these measurements are also useful to investors since we have the ability to and may decide to use a portion of our cash and cash equivalents to retire or pay down our debt. Additionally, we have also presented the total debt to capitalization and net debt to capitalization ratios excluding the cumulative effects of special items on equity.
| December 31, | December 31, | ||||||||||||||||||||||
| 2022 | 2021 | ||||||||||||||||||||||
| Balance Sheet Data: | |||||||||||||||||||||||
| Cash and cash equivalents | $ | 2,203.6 | $ | 1,341.5 | |||||||||||||||||||
| Inventories | 2,763.6 | 2,505.1 | |||||||||||||||||||||
| Total assets | 13,549.1 | 11,641.4 | |||||||||||||||||||||
| Total debt | 1,959.1 | 4,295.8 | |||||||||||||||||||||
| Total equity | 5,056.0 | 2,532.8 | |||||||||||||||||||||
Total equity excluding special items (6) | $ | 4,660.5 | $ | 2,071.3 | |||||||||||||||||||
| Total debt to capitalization ratio | 28 | % | 63 | % | |||||||||||||||||||
Total debt to capitalization ratio, excluding special items (6) | 30 | % | 67 | % | |||||||||||||||||||
| Net debt to capitalization ratio* | (5) | % | 54 | % | |||||||||||||||||||
Net debt to capitalization ratio, excluding special items* (6) | (6) | % | 59 | % | |||||||||||||||||||
| * Negative ratio exists at 12/31/2022 as cash is in excess of debt. | |||||||||||||||||||||||
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See Notes to Non-GAAP Financial Measures.
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Notes to Non-GAAP Financial Measures
The following notes are applicable to the Non-GAAP Financial Measures above:
(1) Represents the elimination of the noncontrolling interest associated with the ownership by the members of PBF LLC other than PBF Energy, as if such members had fully exchanged their PBF LLC Series A Units for shares of PBF Energy Class A common stock.
(2) Represents an adjustment to reflect PBF Energy’s annualized statutory corporate tax rate of approximately 25.9% for 2022 and 2021, and 26.6% for 2020, applied to the net income (loss) attributable to noncontrolling interest for all periods presented. The adjustment assumes the full exchange of existing PBF LLC Series A Units as described in (1) above.
(3) Special items:
LCM inventory adjustmentInventory 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 included in the Refining segment’s 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):
| 2019 | 2018 | 2017 | 2022 | 2021 | 2020 | |||||||||||||||||||||||
| January 1, | $ | 651.8 | $ | 300.5 | $ | 596.0 | January 1, | $ | — | $ | 669.6 | $ | 401.6 | |||||||||||||||
| December 31, | 401.6 | 651.8 | 300.5 | 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 | |||||||||||||||
| Net LCM inventory adjustment benefit (charge) in income (loss) from operations | $ | — | $ | 669.6 | $ | (268.0) | |||||||||||
| Net LCM inventory adjustment benefit (charge) in net income (loss) | — | 496.2 | (196.7) | ||||||||||||||
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| Year Ended December 31, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| Net LCM inventory adjustment (charge) benefit in income from operations | $ | 250.2 | $ | (351.3 | ) | $ | 295.5 | ||||
| Net LCM inventory adjustment (charge) benefit in net income | 188.0 | (260.0 | ) | 178.5 | |||||||
Gain on Torrance land saleSale of Hydrogen Plants - During the yearsyear ended December 31, 2019 and 2018, respectively,2020, we recorded a gain on the sale of twofive hydrogen plants. The gain increased income from operations and net income by $471.1 million and $345.8 million, respectively. There were no such gains in the years ended December 31, 2022 and December 31, 2021.
Gain on Land Sales - During the year ended December 31, 2021, we recorded a gain on sale of PBFXreal-property at the East Coast Terminals, which increased income from operations and net income by $2.8 million and $2.1 million, respectively. During the years ended December 31, 2020, we recorded a gain on sale of one separate parcels of real property acquired as part of the Torrance refinery, but not part of the refinery itself. The gainitself, which increased income from operations and net income by $33.1$8.1 million and $24.9$5.9 million, respectively, during the year ended December 31, 2019. The gain increased2020. There were no such gains in the year ended December 31, 2022.
Impairment Expense - During the year ended December 31, 2020, we recorded an impairment charge which decreased income from operations and net income by $43.8$98.8 million and $32.4$72.5 million, respectively, resulting from the write-down of certain assets as a result of the East Coast Refining Reconfiguration, project abandonments and the write-down of certain PBFX long-lived assets. 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 pre-tax charge to cost of products and other related to a LIFO inventory layer decrement. The majority of the decrement related to our East Coast 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 and $60.9 million, respectively, for the year ended December 31, 2018. There was no such gain2020. 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, 2017.2020, 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 and $41.3 million, respectively. There were no such costs in the years ended December 31, 2022 and December 31, 2021.
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Early Return of Railcars - During the year ended December 31, 20182020, we recognized certain expenses within Cost of sales associated with the voluntary early return of certain leased railcars. These chargesrailcars, which decreased income from operations and net income by $52.3$12.5 million and $38.7$9.2 million, respectively. There were no such expenses recorded in the years ended December 31, 20192022 and December 31, 2017.2021.
Change in Tax Receivable Agreement liability - During the year ended December 31, 2018,2022, we recorded a change in the Tax Receivable Agreement liability that decreased income before income taxes and net income by $290.3 million and $215.1 million, respectively. During the year ended December 31, 2021, PBF Energy recorded a change in the Tax Receivable Agreement liability that decreased income before income taxes and net income by $48.3 million and $35.8 million, respectively. During the year ended December 31, 2020, PBF Energy recorded a change in the Tax Receivable Agreement liability that increased income before taxes and net income by $13.9$373.5 million and $10.3$274.1 million, respectively. During the year ended December 31, 2017 PBF Energy recorded a change in Tax Receivable Agreement liability that increased income before income taxes and net income by $250.9 million and $151.5 million, respectively. There was no such change in the liability for the year ended December 31, 2019. The changes in the Tax Receivable Agreement liability reflect charges or benefits attributable to changes in PBF Energy’s obligation under the Tax Receivable Agreement due to factors out of our control such as changes in tax rates.
Recomputed Income taxesTax on special itemsSpecial Items - The income tax impact of theon these special items, other than TCJA related items, werethe net tax expense special item discussed below, is calculated using the tax rates shown in (2) above.
Net Tax (Benefit) Expense on Remeasurement of Deferred Tax Assets - During the year ended December 31, 2022, we recorded a decrease to our deferred tax valuation allowance of $308.5 million (reducing our deferred tax valuation allowance to zero), in accordance with ASC 740, of which $233.8 million related to a tax benefit with respect to the remeasurement of deferred tax assets and the balance related to our net changes in the Tax Receivable Agreement liability. During the year ended December 31, 2021, we recorded a deferred tax valuation allowance of $308.5 million in accordance with ASC 740(a decrease of$49.9 million when compared to December 31, 2020, which includes a tax benefit of approximately $12.5 million related to our net change in the Tax Receivable Agreement liability and a net tax benefit of $37.4 million related primarily to the remeasurement of deferred tax assets). During the year ended December 31, 2020, we recorded a deferred tax valuation allowance of $358.4 million. This amount includes tax expense of approximately $99.3 million related to our net change in the Tax Receivable Agreement liability or a net tax expense of $259.1 million related primarily to the remeasurement of deferred tax assets.
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(4) Represents an adjustment to weighted-average diluted shares outstanding to assume the full exchange of existing PBF LLC Series A Units as described in (1) above.
(5) Represents weighted-average diluted shares outstanding assuming the conversion of all common stock equivalents, including options and warrants for PBF LLC Series A Units and performance share units and options for shares of PBF Energy Class A common stock as calculated under the treasury stock method (to the extent the impact of such exchange would not be anti-dilutive) for the years ended December 31, 2022, 2021 and 2020, respectively. Common stock equivalents exclude the effects of performance share units and options and warrants to purchase 3,877,035, 12,568,275 and 14,446,894 shares of PBF Energy Class A common stock and PBF LLC Series A Units because they are anti-dilutive for the years ended December 31, 2022, 2021 and 2020, respectively. For periods showing a net loss, all common stock equivalents and unvested restricted stock are considered anti-dilutive.
(6) Total Equity excluding special items is calculated in the table below:
| December 31, | December 31, | |||||||||||||||||||
| 2022 | 2021 | |||||||||||||||||||
| (in millions) | ||||||||||||||||||||
| Total equity | $ | 5,056.0 | $ | 2,532.8 | ||||||||||||||||
| Special Items (Note 4) | ||||||||||||||||||||
| Add: Change in fair value of contingent consideration, net | (13.0) | (61.3) | ||||||||||||||||||
| Add: Gain on sale of hydrogen plants | (471.1) | (471.1) | ||||||||||||||||||
| Add: Gain on land sales | (87.8) | (87.8) | ||||||||||||||||||
| Add: Impairment expense | 98.8 | 98.8 | ||||||||||||||||||
| Add: LIFO inventory decrement | 83.0 | 83.0 | ||||||||||||||||||
| Add: Turnaround acceleration costs | 56.2 | 56.2 | ||||||||||||||||||
| Add: Severance and reconfiguration costs | 30.0 | 30.0 | ||||||||||||||||||
| Add: Early railcar return expense | 64.8 | 64.8 | ||||||||||||||||||
| Add: Loss (gain) on extinguishment of debt | 33.9 | (32.2) | ||||||||||||||||||
| Add: Change in Tax Receivable Agreement liability | (325.3) | (615.6) | ||||||||||||||||||
| Less: Recomputed income tax on special items | 126.9 | 231.8 | ||||||||||||||||||
| Add: Net tax (benefit) expense on remeasurement of deferred tax assets | (12.1) | 221.7 | ||||||||||||||||||
| Add: Net tax expense on Tax Cuts and Jobs Act related special items | 20.2 | 20.2 | ||||||||||||||||||
| Net impact of special items to equity | (395.5) | (461.5) | ||||||||||||||||||
| Total equity excluding special items | $ | 4,660.5 | $ | 2,071.3 | ||||||||||||||||
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Liquidity and Capital Resources
Overview
Our primary sources of liquidity are our cash flows from operations, cash and cash equivalents and borrowing availability under our credit facilities, as described below. We believe that our cash flows from operations and available capital resources will be sufficient to meet our and our subsidiaries’ capital expenditures, working capital needs, dividend payments, debt service and share repurchase program requirements, as well as ourPBF Energy’s obligations under the Tax Receivable Agreement, for the next twelve months. However, our ability to generate sufficient cash flow from operations depends, in part, on petroleum oil market pricing and general economic, political and other factors beyond our control. WeAs of December 31, 2022, we are in compliance as of December 31, 2019 with all of the covenants, including financial covenants, in all of our debt agreements.
Cash Flow Analysis
Cash Flows from Operating Activities
Net cash provided by operating activities was $933.5$4,772.0 million for the year ended December 31, 20192022 compared to net cash provided by operating activities of $838.0$477.3 million for the year ended December 31, 2018.2021. Our operating cash flows for the year ended December 31, 20192022 included our net income of $375.2$2,972.8 million, and net changes in operating assets and liabilities reflecting cash proceeds of $341.0 million, primarily driven by timing of payments for accrued expense. Change in accrued expenses is due primarily to an increase in renewable energy and emissions obligations, as a result of an increase in our unfunded RINs obligation as of December 31, 2022. Our overall increase in cash provided by operating activities also included depreciation and amortization of $533.9 million, deferred income taxes of $420.2 million, change in the Tax Receivable Agreement liability of $290.3 million, net loss on extinguishment of debt primarily related to the redemption of our 2025 Senior Secured Notes of $66.1 million, stock-based compensation of $54.3 million, net change in the fair value of contingent consideration of $48.3 million, pension and other post-retirement benefit costs of $47.6 million, change in the fair value of our catalyst obligations of $2.0 million, and loss on sale of assets of $0.9 million, partially offset by net non-cash charges related to the change in the fair value of our inventory repurchase obligations of $5.4 million.
Our operating cash flows for the year ended December 31, 2021 included our net income of $315.5 million, depreciation and amortization of $447.5$483.8 million, deferred income tax expensenet changes in operating assets and liabilities reflecting cash proceeds of $103.7$268.6 million primarily driven by accrued expenses due 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, pension and other post-retirement benefitsbenefit costs of $44.8$50.8 million, change in the Tax Receivable Agreement liability of $48.3 million, stock-based compensation of $37.3$35.6 million, change in the fair value of contingent consideration of $32.4 million, and deferred income taxes of $11.7 million, partially offset by a net non-cash benefit of $669.6 million related to an LCM inventory adjustment, gain on extinguishment of debt related to the repurchase of a portion of our 2028 Senior Notes and 2025 Senior Notes of $79.9 million, changes in the fair value of our catalyst obligations of $8.5 million, net non-cash charges related to the change in the fair value of our inventory repurchase obligations of $8.4 million, and gain on sale of assets of $3.0 million.
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Net cash provided by operating activities was $477.3 million for the year ended December 31, 2021 compared to net cash used in operating activities of $631.6 million for the year ended December 31, 2020. Our operating cash flows for the year ended December 31, 2020 included our net loss of $1,333.3 million, gain on sale of assets of $477.8 million mainly related to the sale of the hydrogen plants and the sale of land at our Torrance refinery, change in the Tax Receivable Agreement liability of $373.5 million, net non-cash charges relating to the change in the fair value of our inventory repurchase obligations of $25.4$12.6 million and changeschange in the fair value of the contingent consideration of $93.7 million, partially offset by depreciation and amortization of $581.1 million, net non-cash charge of $268.0 million related to an LCM inventory adjustment, impairment expense of $98.8 million, pension and other post-retirement benefits costs of $55.7 million, stock-based compensation of $34.2 million, debt extinguishment costs related to the early redemption of our 2023 Senior Notes of $22.2 million, change in the fair value of our catalyst obligations of $9.7 million, partially offset by a net non-cash benefit of $250.2 million relating to an LCM inventory adjustment, a gain on sale of assets of $29.9$11.8 million and change in fair valuedeferred income taxes of contingent consideration of $0.8$1.6 million. In addition, net changes in operating assets and liabilities reflected cash inflows of approximately $170.8 million driven by the timing of inventory purchases, payments for accrued expenses and accounts payable and collections of accounts receivables. Our operating cash flows for the year ended December 31, 2018 included our net income of $175.3 million, depreciation and amortization of $378.6 million, deferred income tax expense of $32.7 million, pension and other post-retirement benefits costs of $47.4 million, a net non-cash charge of $351.3 million relating to an LCM inventory adjustment, stock-based compensation of $26.0 million, partially offset by a gain on sale of assets of $43.1 million, net non-cash charges relating to the change in the fair value of our inventory repurchase obligations of $31.8 million, change in the Tax Receivable Agreement liability of $13.9 million and changes in the fair value of our catalyst obligations of $5.6 million. In addition, net changes in operating assets and liabilities reflected uses of cash of approximately $78.9 million driven by the timing of inventory purchases, payments for accrued expenses and accounts payable and collections of accounts receivables.
Cash Flows from Investing Activities
Net cash used in investing activities was $712.6$1,010.9 million for the year ended December 31, 20192022 compared to $685.6$388.5 million for the year ended December 31, 2018.2021. The net cash flows used in investing activities for the year ended December 31, 20192022 was comprised of cash outflows of $404.9 million for capital expenditures totaling $633.3 million, expenditures for refinery turnarounds of $299.3$311.6 million, and expenditures for other assets of $44.7 million, partially offset by proceeds of $36.3 million related to the sale of land at our Torrance refinery.$66.0 million. Net cash used in investing activities for the year ended December 31, 20182021 was comprised of cash outflows of $317.5 million for capital expenditures totaling $249.1 million, expenditures for refinery turnarounds of $266.0$117.7 million, and expenditures for other assets of $17.0 million, expenditures for the acquisition of the East Coast Storage Assets by PBFX of $75.0 million and expenditures for the acquisition of the Knoxville Terminals by PBFX of $58.4$28.9 million, partially offset by proceeds of $48.3 million related tofrom the sale of land at our Torrance refinery.
Net cash used in investing activities was $685.6$388.5 million for the year ended December 31, 20182021 compared to $687.0$1,026.5 million for the year ended December 31, 2017.2020. Net cash used in investing activities for the year ended December 31, 20172020 was comprised of cash outflows of $306.7$1,176.2 million forused to fund the Martinez Acquisition, capital expenditures totaling $196.2 million, expenditures for refinery turnarounds of $379.1$188.1 million and expenditures for other assets of $31.2 million and expenditures for the acquisition of the Toledo Products Terminal by PBFX of $10.1$9.1 million, partially offset by $40.1 millionproceeds from sale of net maturitiesassets of marketable securities.$543.1 million.
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Cash Flows from Financing Activities
Net cash used in financing activities was $3.3$2,899.0 million for the year ended December 31, 20192022 compared to net cash used in financing activities of $128.1$356.8 million for the year ended December 31, 2018.2021. For the year ended December 31, 2019,2022, net cash used in financing activities consisted primarily of the redemption of our 2025 Senior Secured Notes of $1,307.4 million, net repayments on the Revolving Credit Facility of $900.0 million, the purchase of PBFX publicly held shares in connection with the Merger Transaction of $303.7 million, the share repurchase of PBF Energy’s Class A common stock of $156.4 million, net repayments on the PBFX Revolving Credit Facility of $100.0 million, dividends and distributions of $73.6 million, settlements of precious metal catalyst obligations of $56.2 million, deferred financing costs and other costs of $31.3 million, $25.9 million related to the repurchase of the principal amount outstanding of the 2028 Senior Notes and the 2025 Senior Notes, excluding accrued interest, payments on finance leases of $11.3 million, and PBFX Contingent Consideration payments of $3.1 million, partially offset by transactions made in connection with stock-based compensation plans of $67.8 million, and proceeds from insurance premium financing of $2.1 million. For the year ended December 31, 2021, net cash used in financing activities consisted of $146.8 million related to the repurchase of the principal amount outstanding of the 2028 Senior Notes and the 2025 Senior Notes, excluding accrued interest, net repayments on the PBFX Revolving Credit Facility of $100.0 million, distributions and dividends of $209.2$39.7 million, net settlements of precious metal catalyst obligations of $31.7 million, payments on finance leases of $17.8 million, PBFX Contingent Consideration payments of $12.2 million, principal amortization payments on the PBF Rail Term Loan of $7.4 million, and deferred financing costs and other of $1.2 million.
Net cash used in financing activities was $356.8 million for the year ended December 31, 2021 compared to net cash provided by financing activities of $2,452.7 million for the year ended December 31, 2020. For the year ended December 31, 2020, net cash provided by financing activities consisted of cash proceeds of $1,228.7 million from the issuance of the 2025 Senior Secured Notes net of related issuance costs, cash proceeds of $469.9 million from the issuance of the 2028 Senior Notes net of cash paid to redeem the 2023 Senior Notes and related issuance costs, net borrowings under our Revolving Credit Facility of $900.0 million, and proceeds from catalyst financing arrangements of $51.9 million, partially offset by net repayments on the PBFX Revolving Credit Facility of $83.0 million, net settlements of precious metal catalyst obligations of $8.8 million, distributions and dividends of $82.2 million, principal amortization payments of the PBF Rail Term Loan (as defined in “Note 9 - Credit Facilities and Debt” of our Notes to Consolidated Financial Statements)$7.2 million, payments on finance leases of $7.0 million, settlements of catalyst obligations of $6.5$12.4 million, taxes paid for net settlement of equity-based compensation of $4.8$2.1 million, repurchases of our common stock in connection with tax withholding obligations upon the vesting of certain restricted stock awards of $4.9 million and deferred payment for the East Coast Storage Assets Acquisition of $32.0 million, partially offset by $132.5 million in net proceeds from the issuance of PBFX common units, net borrowings from the PBFX Revolving Credit Facility of $127.0$1.6 million and deferred financing costs and other of $1.6$0.5 million. Additionally, during the year ended December 31, 2019, we borrowed and repaid 1,350.0 million under our Revolving Credit Facility resulting in no net change to amounts outstanding for the year ended December 31, 2019. For the year ended December 31, 2018, net cash used in financing activities consisted primarily of distributions and dividends of $189.3 million, principal amortization payments of the PBF Rail Term Loan of $6.8 million, repayment of the note payable of $5.6 million, settlements of catalyst obligations of $9.1 million, taxes paid for net settlement of equity-based compensation of $5.4 million, deferred financing costs of $16.2 million, repurchases of our common stock in connection with tax withholding obligations upon the vesting of certain restricted stock awards of $8.2 million and net repayments of our Revolving Credit Facility of $350.0 million, partially offset by $287.3 million in net proceeds from the August 2018 Equity Offering, $34.9 million in net proceeds from the issuance of PBFX common units, net borrowings from the PBFX Revolving Credit Facility of $126.3 million and proceeds from stock options exercised of $14.0 million.
The cash flow activity of PBF LLC for the years ended December 31, 2019, December 31, 20182022, 2021 and December 31, 20172020 is materially consistent with that of PBF Energy discussed above, other than changes in deferred income taxes and certain working capital items, which are different from PBF Energy due to certain tax related items not applicable to PBF LLC. Additionally, PBF LLC reflects net borrowings of $3.1 million and net proceeds of $44.1 million and $102.5$1,070.5 million for the years ended December 31, 2019, 2018,2022 and 2017,net repayments of $1.1 million and $0.1 million for 2021 and 2020, respectively, related to an affiliate loan with PBF Energy, included in cash flows from financing activities, which eliminates in consolidation at PBF Energy.
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Capitalization
Our capital structure was comprised of the following as of December 31, 20192022 (in millions):
| December 31, 2019 | |||
Debt, including current maturities (1): | |||
| PBF LLC debt | |||
| Affiliate note payable | $ | 376.4 | |
| PBF Holding debt | |||
| 2025 Senior Notes | 725.0 | ||
2023 Senior Notes | 500.0 | ||
| PBF Rail Term Loan | 14.5 | ||
| Catalyst financing arrangements | 47.6 | ||
| PBF Holding debt | 1,287.1 | ||
| PBFX debt | |||
| PBFX 2023 Senior Notes | 525.0 | ||
| PBFX Revolving Credit Facility | 283.0 | ||
| PBFX debt | 808.0 | ||
| Unamortized deferred financing costs | (32.4 | ) | |
| Unamortized premium on PBFX 2023 Senior Notes | 2.2 | ||
| Total PBF LLC debt, net of unamortized deferred financing costs and premium | 2,441.3 | ||
| Less: Affiliate note payable | (376.4 | ) | |
Total PBF Energy debt, net of unamortized deferred financing costs and premium (2) | $ | 2,064.9 | |
| Total PBF Energy Equity | $ | 3,585.5 | |
Total PBF Energy Capitalization (3) | $ | 5,650.4 | |
| Total PBF Energy Debt to Capitalization Ratio | 37 | % | |
| December 31, 2022 | |||||
Debt: (1) | |||||
| PBF LLC debt | |||||
| Affiliate note payable | $ | 1,445.7 | |||
| PBF Holding debt | |||||
| 2028 Senior Notes | 801.6 | ||||
| 2025 Senior Notes | 664.5 | ||||
| Revolving Credit Facility | — | ||||
| Catalyst financing arrangements | 4.0 | ||||
| PBF Holding debt | 1,470.1 | ||||
| PBFX debt | |||||
PBFX 2023 Senior Notes (2) | 525.0 | ||||
| PBFX Revolving Credit Facility | — | ||||
| PBFX debt | 525.0 | ||||
| Unamortized deferred financing costs | (36.2) | ||||
| Unamortized premium | 0.2 | ||||
| Total PBF LLC debt, net of unamortized deferred financing costs and premium | 3,404.8 | ||||
| Less: Affiliate note payable | (1,445.7) | ||||
Total PBF Energy debt, net of unamortized deferred financing costs and premium(3) | $ | 1,959.1 | |||
| Total PBF Energy Equity | $ | 5,056.0 | |||
Total PBF Energy Capitalization (4) | $ | 7,015.1 | |||
(1) Refer to “Note 98 - Credit Facilities and Debt” and “Note 109 - Affiliate Note Payable - PBF LLC” of our Notes to Consolidated Financial Statements for further discussiondisclosure related to debt.
(2) The PBFX 2023 Senior Notes were redeemed on February 2, 2023.
(3) Excludes the PBF LLC affiliate note payable that is eliminated atin the PBF Energy level.consolidated financial statements.
During the initial purchasers’ discount and estimated offering expenses. We used the proceeds to redeem our outstanding 2023 Senior Notes, to pay a portion of the cash consideration for the Martinez Acquisition and for general corporate purposes.
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In addition, we made a number of open market repurchases of our 2028 Senior Notes and 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 this extinguishment of debt during the year ended December 31, 2022.
On May 25, 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.
During 2022, we also settled certain of our precious metals financing arrangements, resulting in a reduction of debt of approximately $56.2 million.
Revolving Credit Facilities Overview
We had available capacity under revolving credit facilities as follows at December 31, 20192022 (in millions):
| Total Commitment | Amount Borrowed as of December 31, 2019 | Outstanding Letters of Credit | Available Capacity | Expiration date | Total Commitment | Amount Borrowed as of December 31, 2022 | Outstanding Letters of Credit | Borrowing Base Availability | Expiration Date | |||||||||||||||||||||||||||||||||||||||||
| Revolving Credit Facility (a) | $ | 3,400.0 | $ | — | $ | 221.4 | $ | 1,461.3 | May 2023 | Revolving Credit Facility (a) | $ | 4,300.0 | $ | — | $ | 576.1 | $ | 4,300.0 | January 2025 | |||||||||||||||||||||||||||||||
| PBFX Revolving Credit Facility | 500.0 | 283.0 | 4.8 | 212.2 | July 2023 | PBFX Revolving Credit Facility | 500.0 | — | 3.5 | 496.5 | July 2023 | |||||||||||||||||||||||||||||||||||||||
| Total Credit Facilities | $ | 3,900.0 | $ | 283.0 | $ | 226.2 | $ | 1,673.5 | Total Credit Facilities | $ | 4,800.0 | $ | — | $ | 579.6 | $ | 4,796.5 | |||||||||||||||||||||||||||||||||
(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 billion. 95 |
We acquired the Martinez refinery and related logistics assets from Shell Oil Products on Indebtedness
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
On October 25, 2021, PBF Holding and its subsidiaries, the PBF Entities, entered into the Third Inventory Intermediation Agreement with J. Aron, pursuant to which includes PBF Energy cash balance atthe 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, 2019. In addition, as2024, which term may be further extended by mutual consent of the parties to December 31, 2019, PBFX had approximately $212.2 million2025. On May 25, 2022, the PBF Entities entered into an amendment of borrowing capacitythe Third Inventory Intermediation Agreement to amend certain provisions thereof that related to and were impacted by amendments made on May 25, 2022 to the Revolving Credit 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 PBFX Revolving Credit Facility comparedThird 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.
Renewable Fuel Standard
We are subject to obligations to purchase RINs required to comply with $340.0 millionthe Renewable Fuel Standard. 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 December 31, 2018. The PBFX Revolving
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Factors Affecting Operating Results
Overview
Our earnings and cash flows from operations are primarily affected by the changerelationship 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 LCM inventory adjustment, partially offsetmaterials 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 capital expenditures, including turnaroundhow the prices of refined products adjust to reflect such changes.
Crude oil and other feedstock costs and dividendsthe prices of refined products have historically been subject to wide fluctuation. Expansion and distributions.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.
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 under our agreements with foreign national oil companies require that we post letters ofthroughput, 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 arrange for shipment. We pay for the crude when invoiced, at which time the letters of credit are lifted. We have a contract with Saudi Aramco pursuant to which we have been purchasing up to approximately 100,000 bpdany product premiums or discounts, as well as inventory fluctuations, timing of crude oil from Saudi Aramcoand 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.
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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 processed atreflected in the carrying amount of the receivables that are presented in our Paulsboro refinery.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 connection withaddition, receivable balances are monitored on an ongoing basis. We also limit the Chalmette Acquisition we entered into a contract with PDVSArisk of bad debts by obtaining security such as guarantees or letters of credit.
We continually monitor our market risk exposure for market developments which could introduce significant volatility in the supply of 40,000 to 60,000 bpd offinancial markets.
Other Factors
We currently source our crude oil that can be processedfor 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 any oflower 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 Gulf Coast refineries.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 this agreementour crude supply arrangement with Petróleos de Venezuela S.A. (“PDVSA”) since 2017 whenas PDVSA has suspended deliveries due to the parties’our inability to agree to mutually acceptable payment terms and because of U.S. government sanctions against PDVSA. Notwithstanding the suspension, the recent U.S. government sanctions imposed against PDVSA and Venezuela would prevent us from purchasing
Currently, crude oil under this agreement. In connection with the closing of the Torrance Acquisition, we entered into a crude supply agreement with ExxonMobil for approximately 60,000 bpd of crude oil that can be processeddelivered by rail is consumed 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 agreements for ourEast Coast refineries. The Delaware City rail unloading facilities, and Toledo refineries.
| Payments due by period | ||||||||||||||||||||
| Total | Less than 1 year | 1-3 Years | 3-5 Years | More than 5 years | ||||||||||||||||
| PBF Energy: | ||||||||||||||||||||
Long-term debt (a) | $ | 2,095.1 | $ | 21.4 | $ | 40.7 | $ | 1,308.0 | $ | 725.0 | ||||||||||
Interest payments on debt facilities (a) | 607.5 | 138.3 | 276.5 | 166.4 | 26.3 | |||||||||||||||
Leases and other rental-related commitments (b) | 641.3 | 193.9 | 128.1 | 71.1 | 248.2 | |||||||||||||||
Purchase obligations: (c) | ||||||||||||||||||||
| Crude and Feedstock Supply and Inventory Intermediation Agreements | 6,494.9 | 3,331.7 | 3,149.1 | 14.1 | — | |||||||||||||||
| Other Supply and Capacity Agreements | 544.1 | 138.5 | 109.3 | 97.1 | 199.2 | |||||||||||||||
| Construction obligations | 37.2 | 37.2 | — | — | — | |||||||||||||||
Environmental obligations (d) | 141.2 | 12.8 | 35.3 | 17.2 | 75.9 | |||||||||||||||
Pension and post-retirement obligations (e) | 274.9 | 15.8 | 33.4 | 27.0 | 198.7 | |||||||||||||||
Tax Receivable Agreement obligation (f) | 373.5 | — | 75.6 | 107.8 | 190.1 | |||||||||||||||
East Coast Storage Assets Contingent Consideration (g) | 30.6 | 10.7 | 19.9 | — | — | |||||||||||||||
| Total contractual cash obligations for PBF Energy | $ | 11,240.3 | $ | 3,900.3 | $ | 3,867.9 | $ | 1,808.7 | $ | 1,663.4 | ||||||||||
| Adjustments for PBF LLC: | ||||||||||||||||||||
Less: Tax Receivable Agreement obligation (h) | (373.5 | ) | — | (75.6 | ) | (107.8 | ) | (190.1 | ) | |||||||||||
Add: Affiliate Note Payable (h) | 376.4 | — | — | — | 376.4 | |||||||||||||||
| Total contractual cash obligations for PBF LLC | $ | 11,243.2 | $ | 3,900.3 | $ | 3,792.3 | $ | 1,700.9 | $ | 1,849.7 | ||||||||||
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. 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.
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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, 37% distillate, 2% high-value Group I lubricants, 1% high-value petrochemicals, with the remaining portion of railcars underthe product slate comprised of lower-value products (3% LPGs, 12% black oil and 6% other). For this reason, we believe the Dated Brent (NYH) 2-1-1 is an operating lease in orderappropriate 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 rationalize certain componentsdiffer 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 60% 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 51% gasoline, 36% distillate, 5% high-value petrochemicals (including nonene, tetramer, benzene, xylene and toluene) with the remaining portion of the product slate comprised of lower-value products (5% LPGs and 3% black oil). For this reason, we believe the WTI (Chicago) 4-3-1 is an appropriate benchmark industry refining margin. The majority of Toledo revenues are generated off Chicago-based market prices.
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.
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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 44% gasoline and 36% distillate, 1% high-value petrochemicals with the remaining portion of the product slate comprised of lower-value products (7% black oil, 5% LPGs, 3% petroleum coke, and 4% 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 processed a slate of primarily medium and heavy sour crude oils, which has historically constituted approximately 50% to 75%of total throughput. The remaining throughput consists of sweet crude oil 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 56% gasoline and 27% distillate with the remaining portion of the product slate comprised of lower-value products (3% LPG, 3% black oil and 11% 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 70% to 90% 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 railcar fleet basedrefineries. 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.
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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 54% gasoline and 35% distillate with the remaining portion of the product slate comprised of lower-value products (2% black oil petroleum coke, 4% LPG and 5% 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 prevailing market conditionsa 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 70% to 90% 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.
Results of Operations
The tables below reflect our consolidated financial and operating highlights for the years ended December 31, 2022, 2021 and 2020 (amounts in millions, except per share data). Differences between the results of operations of PBF Energy and PBF LLC primarily pertain to income taxes, interest expense and noncontrolling interest as shown below. Earnings per share information applies only to the financial results of PBF Energy. We operate in two reportable business segments: Refining and Logistics. Our oil refineries, excluding the assets operated by PBFX, are all engaged in the crude oil by rail market. Under the terms of the lease amendment, we agreed to pay the early termination penalty and will pay a reduced rental fee over the remaining term of the lease. As of December 31, 2019, $16.1 million of our total $52.3 million charge recognized in 2018 has not yet been paid and is included within the table above.
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| PBF Energy | Year Ended December 31, | |||||||||||||||||||
| 2022 | 2021 | 2020 | ||||||||||||||||||
| Revenues | $ | 46,830.3 | $ | 27,253.4 | $ | 15,115.9 | ||||||||||||||
| Cost and expenses: | ||||||||||||||||||||
| Cost of products and other | 39,049.1 | 23,826.8 | 14,275.6 | |||||||||||||||||
| Operating expenses (excluding depreciation and amortization expense as reflected below) | 2,599.0 | 2,085.9 | 1,918.3 | |||||||||||||||||
| Depreciation and amortization expense | 503.6 | 453.5 | 551.7 | |||||||||||||||||
| Cost of sales | 42,151.7 | 26,366.2 | 16,745.6 | |||||||||||||||||
| General and administrative expenses (excluding depreciation and amortization expense as reflected below) | 468.7 | 247.3 | 248.5 | |||||||||||||||||
| Depreciation and amortization expense | 7.5 | 13.3 | 11.3 | |||||||||||||||||
| Change in fair value of contingent consideration, net | 48.3 | 32.4 | (93.7) | |||||||||||||||||
| Impairment expense | — | — | 98.8 | |||||||||||||||||
| Loss (gain) on sale of assets | 0.9 | (3.0) | (477.8) | |||||||||||||||||
| Total cost and expenses | 42,677.1 | 26,656.2 | 16,532.7 | |||||||||||||||||
| Income (loss) from operations | 4,153.2 | 597.2 | (1,416.8) | |||||||||||||||||
| Other income (expense): | ||||||||||||||||||||
| Interest expense, net | (246.0) | (317.5) | (258.2) | |||||||||||||||||
| Change in Tax Receivable Agreement liability | (290.3) | (48.3) | 373.5 | |||||||||||||||||
| Change in fair value of catalyst obligations | (2.0) | 8.5 | (11.8) | |||||||||||||||||
| (Loss) gain on extinguishment of debt | (66.1) | 79.9 | (22.2) | |||||||||||||||||
| Other non-service components of net periodic benefit cost | 8.8 | 7.8 | 4.3 | |||||||||||||||||
| Income (loss) before income taxes | 3,557.6 | 327.6 | (1,331.2) | |||||||||||||||||
| Income tax expense | 584.8 | 12.1 | 2.1 | |||||||||||||||||
| Net income (loss) | 2,972.8 | 315.5 | (1,333.3) | |||||||||||||||||
| Less: net income attributable to noncontrolling interests | 96.0 | 84.5 | 59.1 | |||||||||||||||||
| Net income (loss) attributable to PBF Energy Inc. stockholders | $ | 2,876.8 | $ | 231.0 | $ | (1,392.4) | ||||||||||||||
| Consolidated gross margin | $ | 4,678.6 | $ | 887.2 | $ | (1,629.7) | ||||||||||||||
Gross refining margin (1) | $ | 7,429.9 | $ | 3,087.7 | $ | 496.8 | ||||||||||||||
| Net income available to Class A common stock per share: | ||||||||||||||||||||
| Basic | $ | 23.47 | $ | 1.92 | $ | (11.64) | ||||||||||||||
| Diluted | $ | 22.84 | $ | 1.90 | $ | (11.64) | ||||||||||||||
——————————
(1) See Non-GAAP Financial Measures.
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| PBF LLC | Year Ended December 31, | |||||||||||||||||||
| 2022 | 2021 | 2020 | ||||||||||||||||||
| Revenues | $ | 46,830.3 | $ | 27,253.4 | $ | 15,115.9 | ||||||||||||||
| Cost and expenses: | ||||||||||||||||||||
| Cost of products and other | 39,049.1 | 23,826.8 | 14,275.6 | |||||||||||||||||
| Operating expenses (excluding depreciation and amortization expense as reflected below) | 2,599.0 | 2,085.9 | 1,918.3 | |||||||||||||||||
| Depreciation and amortization expense | 503.6 | 453.5 | 551.7 | |||||||||||||||||
| Cost of sales | 42,151.7 | 26,366.2 | 16,745.6 | |||||||||||||||||
| General and administrative expenses (excluding depreciation and amortization expense as reflected below) | 466.6 | 245.2 | 247.7 | |||||||||||||||||
| Depreciation and amortization expense | 7.5 | 13.3 | 11.3 | |||||||||||||||||
| Change in fair value of contingent consideration, net | 48.3 | 32.4 | (93.7) | |||||||||||||||||
| Impairment expense | — | — | 98.8 | |||||||||||||||||
| Loss (gain) on sale of assets | 0.9 | (3.0) | (477.8) | |||||||||||||||||
| Total cost and expenses | 42,675.0 | 26,654.1 | 16,531.9 | |||||||||||||||||
| Income (loss) from operations | 4,155.3 | 599.3 | (1,416.0) | |||||||||||||||||
| Other income (expense): | ||||||||||||||||||||
| Interest expense, net | (257.2) | (327.8) | (268.5) | |||||||||||||||||
| Change in fair value of catalyst obligations | (2.0) | 8.5 | (11.8) | |||||||||||||||||
| (Loss) gain on extinguishment of debt | (66.1) | 79.9 | (22.2) | |||||||||||||||||
| Other non-service components of net periodic benefit cost | 8.8 | 7.8 | 4.3 | |||||||||||||||||
| Income (loss) before income taxes | 3,838.8 | 367.7 | (1,714.2) | |||||||||||||||||
| Income tax expense (benefit) | 4.6 | (14.0) | 6.1 | |||||||||||||||||
| Net income (loss) | 3,834.2 | 381.7 | (1,720.3) | |||||||||||||||||
| Less: net income attributable to noncontrolling interests | 68.1 | 82.1 | 76.2 | |||||||||||||||||
| Net income (loss) attributable to PBF Energy Company LLC | $ | 3,766.1 | $ | 299.6 | $ | (1,796.5) | ||||||||||||||
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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 | $ | 13.85 | $ | 2.91 | $ | (6.12) | ||||||||||||||||||||
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.
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The table below summarizes certain market indicators relating to our operating results as reported by Platts, a division of The McGraw-Hill Companies.
| Year Ended December 31, | ||||||||||||||||||||
| 2022 | 2021 | 2020 | ||||||||||||||||||
| (dollars per barrel, except as noted) | ||||||||||||||||||||
| Dated Brent crude oil | $ | 101.27 | $ | 70.89 | $ | 41.62 | ||||||||||||||
| West Texas Intermediate (WTI) crude oil | $ | 94.58 | $ | 68.10 | $ | 39.25 | ||||||||||||||
| Light Louisiana Sweet (LLS) crude oil | $ | 96.81 | $ | 69.59 | $ | 41.13 | ||||||||||||||
| Alaska North Slope (ANS) crude oil | $ | 98.76 | $ | 70.56 | $ | 42.20 | ||||||||||||||
| Crack Spreads | ||||||||||||||||||||
| Dated Brent (NYH) 2-1-1 | $ | 40.26 | $ | 16.84 | $ | 9.11 | ||||||||||||||
| WTI (Chicago) 4-3-1 | $ | 31.56 | $ | 16.34 | $ | 6.30 | ||||||||||||||
| LLS (Gulf Coast) 2-1-1 | $ | 37.56 | $ | 16.03 | $ | 7.59 | ||||||||||||||
| ANS (West Coast-LA) 4-3-1 | $ | 41.64 | $ | 20.10 | $ | 11.30 | ||||||||||||||
| ANS (West Coast-SF) 3-2-1 | $ | 41.89 | $ | 20.55 | $ | 9.99 | ||||||||||||||
| Crude Oil Differentials | ||||||||||||||||||||
| Dated Brent (foreign) less WTI | $ | 6.68 | $ | 2.80 | $ | 2.37 | ||||||||||||||
| Dated Brent less Maya (heavy, sour) | $ | 13.95 | $ | 6.47 | $ | 5.37 | ||||||||||||||
| Dated Brent less WTS (sour) | $ | 6.98 | $ | 2.63 | $ | 2.33 | ||||||||||||||
| Dated Brent less ASCI (sour) | $ | 9.68 | $ | 3.90 | $ | 1.81 | ||||||||||||||
| WTI less WCS (heavy, sour) | $ | 21.30 | $ | 14.19 | $ | 10.72 | ||||||||||||||
| WTI less Bakken (light, sweet) | $ | (4.05) | $ | (0.14) | $ | 2.41 | ||||||||||||||
| WTI less Syncrude (light, sweet) | $ | (3.04) | $ | 2.25 | $ | 2.13 | ||||||||||||||
| WTI less LLS (light, sweet) | $ | (2.22) | $ | (1.50) | $ | (1.88) | ||||||||||||||
| WTI less ANS (light, sweet) | $ | (4.17) | $ | (2.46) | $ | (2.95) | ||||||||||||||
| Natural gas (dollars per MMBTU) | $ | 6.54 | $ | 3.73 | $ | 2.13 | ||||||||||||||
2022 Compared to 2021
Overview— PBF Energy net income was $2,972.8 million for the year ended December 31, 2022 compared to net income of $315.5 million for the year ended December 31, 2021. PBF LLC net income was $3,834.2 million for the year ended December 31, 2022 compared to net income of $381.7 million for the year ended December 31, 2021. Net income attributable to PBF Energy stockholders was $2,876.8 million, or natural gas$22.84 per diluted share, for the year ended December 31, 2022 ($22.84 per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income, or $23.36 per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income excluding special items, as described below in Non-GAAP Financial Measures) compared to net income attributable to PBF Energy stockholders of $231.0 million, or $1.90 per diluted share, for the year ended December 31, 2021 ($1.90 per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income, or $(2.50) per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net loss excluding special items, as described below in Non-GAAP Financial Measures). The net income attributable to PBF Energy stockholders represents PBF Energy’s equity interest in PBF LLC’s pre-tax income, less applicable income tax expense. PBF Energy’s weighted-average equity interest in PBF LLC was 99.3% and 99.2% for the years ended December 31, 2022 and 2021, respectively.
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Our results for the year ended December 31, 2022 were negatively impacted by special items consisting of pre-tax charges associated with the change in the Tax Receivable Agreement liability of $290.3 million, or $215.1 million net of tax, a net loss on the extinguishment of debt mainly associated with the redemption of our 2025 Senior Secured Notes of $66.1 million, or $49.0 million net of tax, and net changes in fair value of contingent consideration of $48.3 million, or $35.8 million net of tax, partially offset by a $233.8 million tax benefit associated with the remeasurement of certain deferred tax assets. Our results for the year ended December 31, 2021 were positively impacted by special items consisting of a non-cash, pre-tax LCM inventory adjustment of approximately $669.6 million, or $496.2 million net of tax, a pre-tax 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, or $59.2 million net of tax, a gain on the sale of certain PBFX land of $2.8 million, or $2.1 million net of tax, and a $37.4 million tax benefit associated with the remeasurement of certain deferred tax assets, offset by pre-tax charges associated with the change in the Tax Receivable Agreement liability of $48.3 million, or $35.8 million net of tax and a change in fair value of the Martinez Contingent Consideration and the earn-out obligation associated with the acquisition of CPI Operations LLC (the “PBFX Contingent Consideration”) of $32.4 million, or $24.0 million net of tax.
Excluding the impact of these special items, when comparing our results to the year ended December 31, 2021, we experienced an increase in the demand for our refined products, evidenced by higher throughput volumes and barrels sold at all of our refineries, contractsas well as overall stronger refining margins due to favorable movements in crack spreads and crude oil differentials. These improving metrics have positively impacted our revenues, gross margin, and operating income.
Revenues— Revenues totaled $46.8 billion for the treatmentyear ended December 31, 2022 compared to $27.3 billion for the year ended December 31, 2021, an increase of wastewater,approximately $19.5 billion or 71.4%. Revenues per barrel sold were $123.26 and contracts$80.79 for pipeline capacity. We enter into these contractsthe years ended December 31, 2022 and 2021, respectively, an increase of 52.6% directly related to facilitatehigher 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.
Overall average 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— Consolidated gross margin totaled $4,678.6 million for the year ended December 31, 2022, compared to $887.2 million for the year ended December 31, 2021, an increase of $3,791.4 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.
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During the year ended December 31, 2022, our margin calculations were not impacted by special items. Consolidated gross margin and gross refining margin increased due to favorable movements in certain crack spreads and crude oil deliveriesdifferentials and higher throughput volumes and barrels sold at all our refineries. For the year ended December 31, 2021, our margin calculations included a favorable special item related to ensurea non-cash LCM inventory adjustment of approximately $669.6 million on a net basis resulting from the increase in crude oil and refined product prices from the year ended December 31, 2020 to the year ended December 31, 2021.
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.
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.
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Operating Expenses— Operating expenses totaled $2,599.0 million for the year ended December 31, 2022 compared to $2,085.9 million for the year ended December 31, 2021, an adequate supplyincrease of energyapproximately $513.1 million, or essential24.6%. Of the total $2,599.0 million in operating expenses, $2,495.6 million, or 7.39 per barrel of throughput, related to expenses incurred by the Refining segment, while the remaining $103.4 million related to expenses incurred by the Logistics segment ($1,999.1 million or 6.56 per barrel of throughput, and $86.8 million of operating expenses for the year ended December 31, 2021 related to the Refining and Logistics segments, respectively). 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 $468.7 million for the year ended December 31, 2022, compared to $247.3 million for the year ended December 31, 2021, an increase of $221.4 million or 89.5%. 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 $511.1 million for the year ended December 31, 2022 (including $503.6 million recorded within Cost of sales) compared to $466.8 million for the year ended December 31, 2021 (including $453.5 million recorded within Cost of sales), an increase of $44.3 million. The increase was a result of a general increase in our fixed asset base due to capital projects and turnarounds completed since the end of the prior year.
Change in Fair Value of Contingent Consideration, net— Change in fair value of contingent consideration represented a loss of $48.3 million and a loss of $32.4 million for the years ended December 31, 2022 and December 31, 2021, respectively. These losses were primarily related to the changes in estimated fair value of the earn-out liability associated with the acquisition of the Martinez refinery, operations. Substantiallyoffset by the recognition of contingent assets associated with the acquisition.
Loss (Gain) on Sale of Assets— 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. There was a gain of $3.0 million for the year ended December 31, 2021 related primarily to a third-party sale of PBFX real property.
Change in Tax Receivable Agreement Liability— Change in the Tax Receivable Agreement liability for the year ended December 31, 2022 and December 31, 2021, represented a charge of $290.3 million and a charge of $48.3 million, respectively. These charges were primarily the result of changes in the deferred tax asset valuation allowance recorded in accordance with Accounting Standards Codification (“ASC”) 740 Income Taxes (“ASC 740”), related to the reduction of deferred tax assets associated with the payments made or expected to be made in connection with the Tax Receivable Agreement liability.
Change in Fair Value of Catalyst Obligations— Change in fair value of catalyst obligations represented a loss of $2.0 million for the year ended December 31, 2022, compared to a gain of $8.5 million for the year ended December 31, 2021. These losses and gains relate to the change in fair value of the precious metals underlying the sale and leaseback of our refineries’ precious metal catalysts, which we are obligated to repurchase at fair market value upon lease termination.
(Loss) Gain on Extinguishment of Debt— We incurred a loss on extinguishment of debt of $66.1 million in the year ended December 31, 2022 related to the redemption of all of these obligationsthe outstanding 2025 Senior Secured Notes, slightly offset by a gain related to the repurchase of a portion of our 2028 Senior Notes and 2025 Senior Notes. We incurred a gain on extinguishment of debt of $79.9 million in the year ended December 31, 2021 related to the repurchase of a portion of our 2028 Senior Notes and 2025 Senior Notes.
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Interest Expense, net— PBF Energy interest expense totaled $246.0 million for the year ended December 31, 2022, compared to $317.5 million for the year ended December 31, 2021, a decrease of $71.5 million. This net decrease is mainly attributable to the redemption of the 2025 Senior Secured Notes during the third quarter of 2022, as well as lower outstanding balances on our revolving credit facilities. Interest expense includes interest on long-term debt including the PBFX credit facilities, costs related to the sale and leaseback of our precious metal catalysts, financing costs associated with the Third Inventory Intermediation Agreement with J. Aron, letter of credit fees associated with the purchase of certain crude oils and the amortization of deferred financing costs. PBF LLC interest expense totaled $257.2 million and $327.8 million for the year ended December 31, 2022 and December 31, 2021, respectively (inclusive of $11.2 million and $10.3 million, respectively, of incremental interest expense on the affiliate note payable with PBF Energy that eliminates in consolidation in the PBF Energy consolidated financial statements).
Income Tax Expense— PBF LLC is organized as a limited liability company and PBFX is a partnership, both of which are treated as “flow-through” entities for federal income tax purposes and therefore are not subject to income tax. However, two subsidiaries of Chalmette Refining and our Canadian subsidiary, PBF Energy Limited, are treated as C-Corporations for income tax purposes and may incur income taxes with respect to their earnings, as applicable. The members of PBF LLC are required to include their proportionate share of PBF LLC’s taxable income or loss, on their respective tax returns. PBF LLC generally makes distributions to its members, per the terms of PBF LLC’s amended and restated limited liability company agreement, related to such taxes on a pro-rata basis. PBF Energy recognizes an income tax expense or benefit in our consolidated financial statements based on fixed prices. CertainPBF Energy’s allocable share of PBF LLC’s pre-tax income or loss, which was approximately 99.3% and 99.2%, on a weighted-average basis for the years ended December 31, 2022 and 2021, respectively. PBF Energy’s Consolidated Financial Statements do not reflect any benefit or provision for income taxes on the pre-tax income or loss attributable to the noncontrolling interests in PBF LLC (although, as described above, PBF LLC must make tax distributions to all its members on a pro-rata basis). PBF Energy’s effective tax rate, including the impact of noncontrolling interests, for the years ended December 31, 2022 and 2021 was 16.4% and 3.7%, respectively. The effective tax rate for both years was significantly impacted by changes in the deferred tax valuation allowance. In 2022, the full valuation allowance was released, resulting in a tax benefit of $308.5 million for the year ended December 31, 2022, compared to a tax benefit of $49.9 million for the year ended December 31, 2021.
Noncontrolling Interest— PBF Energy is the sole managing member of, and has a controlling interest in, PBF LLC. As the sole managing member of PBF LLC, PBF Energy operates and controls all of the business and affairs of PBF LLC and its subsidiaries. PBF Energy consolidates the financial results of PBF LLC and its subsidiaries, including PBFX. With respect to the consolidation of PBF LLC, we record a noncontrolling interest for the economic interest in PBF LLC held by members other than PBF Energy, with respect to the consolidation of PBFX, we recorded a noncontrolling interest for the economic interests in PBFX held by the public unitholders of PBFX prior to the close of the PBFX Merger Transaction, and with respect to the consolidation of PBF Holding, we record a 20% noncontrolling interest for the ownership interests in two subsidiaries of Chalmette Refining held by a third-party. The total noncontrolling interest on the Consolidated Statements of Operations represents the portion of the Company’s earnings or loss attributable to the economic interests held by members of PBF LLC other than PBF Energy, by the public common unitholders of PBFX prior to the close of the PBFX Merger Transaction and by the third-party stockholders of certain of Chalmette Refining’s subsidiaries. The total noncontrolling interest on the Consolidated Balance Sheets represents the portion of the Company’s net assets attributable to the economic interests held by the members of PBF LLC other than PBF Energy, and by the third-party stockholders of the two Chalmette Refining subsidiaries. PBF Energy’s weighted-average equity noncontrolling interest ownership percentage in PBF LLC for the years ended December 31, 2022 and 2021 was approximately 0.7% and 0.8%, respectively. The carrying amount of the noncontrolling interest on our Consolidated Balance Sheets attributable to the noncontrolling interest is not equal to the noncontrolling interest ownership percentage due to the effect of income taxes and related agreements that pertain solely to PBF Energy.
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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. Such Non-GAAP financial measures are presented only in the context of PBF Energy’s results and are not presented or discussed in respect to PBF LLC.
Special Items
The Non-GAAP measures presented include fixedAdjusted Fully-Converted Net Income (Loss) excluding special items, gross refining margin excluding special items, EBITDA excluding special items, and net debt to capitalization excluding special items. Special items for the periods presented relate to LCM inventory adjustments, net changes in fair value of contingent consideration, changes in the Tax Receivable Agreement liability, loss (gain) on extinguishment of debt, gain on sale of hydrogen plants, severance and reconfiguration costs, impairment expense, net tax (benefit) expense on remeasurement of deferred tax assets, 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 minimum volumesuperior to, the financial measures prepared in accordance with GAAP.
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Adjusted Fully-Converted Net Income (Loss) and Adjusted Fully-Converted Net Income (Loss) Excluding Special Items
PBF Energy utilizes results presented on an Adjusted Fully-Converted basis that reflects an assumed exchange of all PBF LLC Series A Units for shares of PBF Energy Class A common stock. In addition, we present results on an Adjusted Fully-Converted basis excluding special items as described above. We believe that these Adjusted Fully-Converted measures, when presented in conjunction with comparable GAAP measures, are useful to investors to compare PBF Energy results across different periods and to facilitate an understanding of our operating results.
Neither Adjusted Fully-Converted Net Income (Loss) nor Adjusted Fully-Converted Net Income (Loss) excluding special items should be considered an alternative to net income (loss) presented in accordance with GAAP. Adjusted Fully-Converted Net Income (Loss) and Adjusted Fully-Converted Net Income (Loss) excluding special items presented by other companies may not be comparable to our presentation, since each company may define these terms differently. The differences between Adjusted Fully-Converted and GAAP results are as follows:
1.Assumed exchange of all PBF LLC Series A Units for shares of PBF Energy Class A common stock. As a result of the assumed exchange of all PBF LLC Series A Units, the noncontrolling interest related to these units is converted to controlling interest. Management believes that it is useful to provide the per-share effect associated with the assumed exchange of all PBF LLC Series A Units.
2.Income Taxes. Prior to PBF Energy’s IPO, PBF Energy was organized as a limited liability company treated as a “flow-through” entity for income tax purposes, and even after PBF Energy’s IPO, not all of its earnings are subject to corporate-level income taxes. Adjustments have been made to the Adjusted Fully-Converted tax provisions and earnings to assume that PBF Energy had adopted its post-IPO corporate tax structure for all periods presented and is taxed as a C-corporation in the U.S. at the prevailing corporate rates. These assumptions are consistent with the assumption in clause 1 above that all PBF LLC Series A Units are exchanged for shares of PBF Energy Class A common stock, as the assumed exchange would change the amount of PBF Energy’s earnings that are subject to corporate income tax.
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The following table reconciles PBF Energy’s Adjusted Fully-Converted results with its results presented in accordance with GAAP for the years ended December 31, 2022, 2021 and 2020 (in millions, except share and per share amounts):
| Year Ended December 31, | ||||||||||||||||||||
| 2022 | 2021 | 2020 | ||||||||||||||||||
| Net income (loss) attributable to PBF Energy Inc. stockholders | $ | 2,876.8 | $ | 231.0 | $ | (1,392.4) | ||||||||||||||
| Less: Income allocated to participating securities | — | — | 0.1 | |||||||||||||||||
| Income (loss) available to PBF Energy Inc. stockholders - basic | 2,876.8 | 231.0 | (1,392.5) | |||||||||||||||||
Add: Net income (loss) attributable to noncontrolling interests(1) | 27.9 | 2.4 | (17.1) | |||||||||||||||||
Less: Income tax (expense) benefit (2) | (7.2) | (0.6) | 4.6 | |||||||||||||||||
| Adjusted fully-converted net income (loss) | $ | 2,897.5 | $ | 232.8 | $ | (1,405.0) | ||||||||||||||
Special Items:(3) | ||||||||||||||||||||
| Add: Non-cash LCM inventory adjustment | — | (669.6) | 268.0 | |||||||||||||||||
| Add: Change in fair value of contingent consideration, net | 48.3 | 32.4 | (93.7) | |||||||||||||||||
| Add: Gain on sale of hydrogen plants | — | — | (471.1) | |||||||||||||||||
| Add: Gain on land sales | — | (2.8) | (8.1) | |||||||||||||||||
| Add: Impairment expense | — | — | 98.8 | |||||||||||||||||
| Add: LIFO inventory decrement | — | — | 83.0 | |||||||||||||||||
| Add: Turnaround acceleration costs | — | — | 56.2 | |||||||||||||||||
| 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 | |||||||||||||||||
| Add: Change in Tax Receivable Agreement liability | 290.3 | 48.3 | (373.5) | |||||||||||||||||
| Add: Net tax (benefit) expense on remeasurement of deferred tax assets | (233.8) | (37.4) | 259.1 | |||||||||||||||||
| Less: Recomputed income tax on special items | (104.9) | 173.9 | 99.9 | |||||||||||||||||
| Adjusted fully-converted net income (loss) excluding special items | $ | 2,963.5 | $ | (302.3) | $ | (1,421.7) | ||||||||||||||
| Weighted-average shares outstanding of PBF Energy Inc. | 122,598,076 | 120,240,009 | 119,617,998 | |||||||||||||||||
Conversion of PBF LLC Series A Units (4) | 917,991 | 988,730 | 1,042,667 | |||||||||||||||||
Common stock equivalents (5) | 3,344,039 | 1,409,415 | — | |||||||||||||||||
| Fully-converted shares outstanding—diluted | 126,860,106 | 122,638,154 | 120,660,665 | |||||||||||||||||
| Diluted net income (loss) per share | $ | 22.84 | $ | 1.90 | $ | (11.64) | ||||||||||||||
Adjusted fully-converted net income (loss) per fully exchanged, fully diluted shares outstanding (5) | $ | 22.84 | $ | 1.90 | $ | (11.64) | ||||||||||||||
| Adjusted fully-converted net income (loss) excluding special items per fully exchanged, fully diluted shares outstanding | $ | 23.36 | $ | (2.50) | $ | (11.78) | ||||||||||||||
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See Notes to Non-GAAP Financial Measures.
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Gross Refining Margin and Gross Refining Margin Excluding Special Items
Gross refining margin is defined as consolidated gross margin excluding refinery depreciation, refinery operating expenses, and gross margin of PBFX. 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 operating expenses and refinery 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 | |||||||||||||||||||||||||||
| $ | per barrel of throughput | $ | per barrel of throughput | $ | per barrel of throughput | ||||||||||||||||||||||||
| Calculation of consolidated gross margin: | |||||||||||||||||||||||||||||
| Revenues | $ | 46,830.3 | $ | 138.69 | $ | 27,253.4 | $ | 89.46 | $ | 15,115.9 | $ | 56.76 | |||||||||||||||||
| Less: Cost of sales | 42,151.7 | 124.84 | 26,366.2 | 86.55 | 16,745.6 | 62.88 | |||||||||||||||||||||||
| Consolidated gross margin | $ | 4,678.6 | $ | 13.85 | $ | 887.2 | $ | 2.91 | $ | (1,629.7) | $ | (6.12) | |||||||||||||||||
| Reconciliation of consolidated gross margin to gross refining margin: | |||||||||||||||||||||||||||||
| Consolidated gross margin | $ | 4,678.6 | $ | 13.85 | $ | 887.2 | $ | 2.91 | $ | (1,629.7) | $ | (6.12) | |||||||||||||||||
| Add: PBFX operating expense | 121.4 | 0.36 | 103.4 | 0.35 | 99.9 | 0.38 | |||||||||||||||||||||||
| Add: PBFX depreciation expense | 36.7 | 0.11 | 37.8 | 0.13 | 53.7 | 0.19 | |||||||||||||||||||||||
| Less: Revenues of PBFX | (369.3) | (1.09) | (355.5) | (1.17) | (360.3) | (1.35) | |||||||||||||||||||||||
| Add: Refinery operating expenses | 2,495.6 | 7.39 | 1,999.1 | 6.56 | 1,835.2 | 6.89 | |||||||||||||||||||||||
| Add: Refinery depreciation expense | 466.9 | 1.38 | 415.7 | 1.36 | 498.0 | 1.87 | |||||||||||||||||||||||
| Gross refining margin | $ | 7,429.9 | $ | 22.00 | $ | 3,087.7 | $ | 10.14 | $ | 496.8 | $ | 1.86 | |||||||||||||||||
Special Items: (3) | |||||||||||||||||||||||||||||
| Add: Non-cash LCM inventory adjustment | — | — | (669.6) | (2.20) | 268.0 | 1.01 | |||||||||||||||||||||||
| Add: LIFO inventory decrement | — | — | — | — | 83.0 | 0.31 | |||||||||||||||||||||||
| 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 | |||||||||||||||||
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See Notes to Non-GAAP Financial Measures.
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EBITDA, EBITDA Excluding Special Items and Adjusted EBITDA
Our management uses EBITDA (earnings before interest, income taxes, depreciation and amortization), 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, changes in the Tax Receivable Agreement liability due to factors out of PBF Energy’s control such as changes in tax rates, loss (gain) on extinguishment of debt, change in the fair value of contingent 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, while othersfor capital expenditures or contractual commitments;
•do not reflect changes in, or cash requirements for, our working capital needs;
•do not reflect our interest expense, or the cash requirements necessary to service interest or principal payments, on our debt;
•do not reflect realized and unrealized gains and losses from certain hedging activities, which may have a substantial impact on our cash flow;
•do not reflect certain other non-cash income and expenses; and
•exclude income taxes that may represent a reduction in available cash.
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The following tables reconcile net income (loss) as reflected in PBF Energy’s results of operations to EBITDA, EBITDA excluding special items and Adjusted EBITDA for the periods presented (in millions):
| Year Ended December 31, | |||||||||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||||||||
| Reconciliation of net income (loss) to EBITDA and EBITDA excluding special items: | |||||||||||||||||||||||
| Net income (loss) | $ | 2,972.8 | $ | 315.5 | $ | (1,333.3) | |||||||||||||||||
| Add: Depreciation and amortization expense | 511.1 | 466.8 | 563.0 | ||||||||||||||||||||
| Add: Interest expense, net | 246.0 | 317.5 | 258.2 | ||||||||||||||||||||
| Add: Income tax expense | 584.8 | 12.1 | 2.1 | ||||||||||||||||||||
| EBITDA | $ | 4,314.7 | $ | 1,111.9 | $ | (510.0) | |||||||||||||||||
Special Items: (3) | |||||||||||||||||||||||
| Add: Non-cash LCM inventory adjustment | — | (669.6) | 268.0 | ||||||||||||||||||||
| Add: Change in fair value of contingent consideration, net | 48.3 | 32.4 | (93.7) | ||||||||||||||||||||
| Add: Gain on sale of hydrogen plants | — | — | (471.1) | ||||||||||||||||||||
| Add: Gain on land sales | — | (2.8) | (8.1) | ||||||||||||||||||||
| Add: Impairment expense | — | — | 98.8 | ||||||||||||||||||||
| 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 | ||||||||||||||||||||
| Add: Change in Tax Receivable Agreement liability | 290.3 | 48.3 | (373.5) | ||||||||||||||||||||
| EBITDA excluding special items | $ | 4,719.4 | $ | 440.3 | $ | (941.9) | |||||||||||||||||
| Reconciliation of EBITDA to Adjusted EBITDA: | |||||||||||||||||||||||
| EBITDA | $ | 4,314.7 | $ | 1,111.9 | $ | (510.0) | |||||||||||||||||
| Add: Stock based compensation | 54.3 | 35.6 | 34.2 | ||||||||||||||||||||
| Add: Change in fair value of catalyst obligations | 2.0 | (8.5) | 11.8 | ||||||||||||||||||||
Add: Non-cash LCM inventory adjustment (3) | — | (669.6) | 268.0 | ||||||||||||||||||||
Add: Change in fair value of contingent consideration, net (3) | 48.3 | 32.4 | (93.7) | ||||||||||||||||||||
Add: Gain on sale of hydrogen plants (3) | — | — | (471.1) | ||||||||||||||||||||
Add: Gain on land sales (3) | — | (2.8) | (8.1) | ||||||||||||||||||||
Add: Impairment expense (3) | — | — | 98.8 | ||||||||||||||||||||
Add: LIFO inventory decrement (3) | — | — | 83.0 | ||||||||||||||||||||
Add: Severance and reconfiguration costs (3) | — | — | 30.0 | ||||||||||||||||||||
Add: Early railcar return expense (3) | — | — | 12.5 | ||||||||||||||||||||
Add: Loss (gain) on extinguishment of debt (3) | 66.1 | (79.9) | 22.2 | ||||||||||||||||||||
Add: Change in Tax Receivable Agreement liability (3) | 290.3 | 48.3 | (373.5) | ||||||||||||||||||||
| Adjusted EBITDA | $ | 4,775.7 | $ | 467.4 | $ | (895.9) | |||||||||||||||||
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See Notes to Non-GAAP Financial Measures.
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Net Debt to Capitalization Ratio and Net Debt to Capitalization Ratio Excluding Special Items
The total debt to capitalization ratio is calculated by dividing total debt by the sum of total debt and total equity. This ratio is a measurement that management believes is useful to investors in analyzing our leverage. Net debt and the net debt to capitalization ratio are Non-GAAP measures. Net debt is calculated by subtracting cash and cash equivalents from total debt. We believe these measurements are also useful to investors since we have the ability to and may decide to use a portion of our cash and cash equivalents to retire or pay down our debt. Additionally, we have also presented the total debt to capitalization and net debt to capitalization ratios excluding the cumulative effects of special items on equity.
| December 31, | December 31, | ||||||||||||||||||||||
| 2022 | 2021 | ||||||||||||||||||||||
| Balance Sheet Data: | |||||||||||||||||||||||
| Cash and cash equivalents | $ | 2,203.6 | $ | 1,341.5 | |||||||||||||||||||
| Inventories | 2,763.6 | 2,505.1 | |||||||||||||||||||||
| Total assets | 13,549.1 | 11,641.4 | |||||||||||||||||||||
| Total debt | 1,959.1 | 4,295.8 | |||||||||||||||||||||
| Total equity | 5,056.0 | 2,532.8 | |||||||||||||||||||||
Total equity excluding special items (6) | $ | 4,660.5 | $ | 2,071.3 | |||||||||||||||||||
| Total debt to capitalization ratio | 28 | % | 63 | % | |||||||||||||||||||
Total debt to capitalization ratio, excluding special items (6) | 30 | % | 67 | % | |||||||||||||||||||
| Net debt to capitalization ratio* | (5) | % | 54 | % | |||||||||||||||||||
Net debt to capitalization ratio, excluding special items* (6) | (6) | % | 59 | % | |||||||||||||||||||
| * Negative ratio exists at 12/31/2022 as cash is in excess of debt. | |||||||||||||||||||||||
——————————
See Notes to Non-GAAP Financial Measures.
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Notes to Non-GAAP Financial Measures
The following notes are applicable to the Non-GAAP Financial Measures above:
(1)Represents the elimination of the noncontrolling interest associated with the ownership by the members of PBF LLC other than PBF Energy, as if such members had fully exchanged their PBF LLC Series A Units for shares of PBF Energy Class A common stock.
(2) Represents an adjustment to reflect PBF Energy’s annualized statutory corporate tax rate of approximately 25.9% for 2022 and 2021, and 26.6% for 2020, applied to the net income (loss) attributable to noncontrolling interest for all periods presented. The adjustment assumes the full exchange of existing PBF LLC Series A Units as described in (1) above.
(3) Special items:
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 actual usage.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 amountsnet impact of these LCM inventory adjustments are included in thisthe Refining segment’s 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 are basedincludes the LCM inventory reserve as of each date presented (in millions):
| 2022 | 2021 | 2020 | |||||||||||||||
| January 1, | $ | — | $ | 669.6 | $ | 401.6 | |||||||||||
| December 31, | — | — | 669.6 | ||||||||||||||
The following table includes the corresponding impact of changes in the LCM inventory reserve on fixed or minimum quantitiesincome (loss) from operations and net income (loss) for the periods presented (in millions):
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| Net LCM inventory adjustment benefit (charge) in income (loss) from operations | $ | — | $ | 669.6 | $ | (268.0) | |||||||||||
| Net LCM inventory adjustment benefit (charge) in net income (loss) | — | 496.2 | (196.7) | ||||||||||||||
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Change in Fair Value of Contingent Consideration, net - During the year ended December 31, 2022, we recorded a net change in fair value of contingent consideration related to be purchasedchanges in the estimated fair value of the earn-out liability associated with the acquisition of the Martinez refinery, offset by the recognition of contingent assets associated with the acquisition. These changes resulted in decreases to income from operations and net income by $48.3 million and $35.8 million, respectively. During the year ended December 31, 2021, we recorded a change in fair value of the contingent consideration related to both the Martinez Contingent Consideration and the fixed or estimated costs basedPBFX Contingent Consideration, which decreased income from operations and net income by $32.4 million and $24.0 million, respectively. During the year ended December 31, 2020 we recorded a change in fair value of the contingent consideration related to both the Martinez Contingent Consideration and the PBFX Contingent Consideration, which increased income from operations and net income by $93.7 million and $68.8 million, respectively.
Gain on market conditionsSale of Hydrogen Plants - During the year ended December 31, 2020, we recorded a gain on the sale of five hydrogen plants. The gain increased income from operations and net income by $471.1 million and $345.8 million, respectively. There were no such gains in the years ended December 31, 2022 and December 31, 2021.
Gain on Land Sales - During the year ended December 31, 2021, we recorded a gain on sale of PBFXreal-property at the East Coast Terminals, which increased income from operations and net income by $2.8 million and $2.1 million, respectively. During the years ended December 31, 2020, we recorded a gain on sale of one separate parcels 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 and $5.9 million, respectively, during the year ended December 31, 2020. There were no such gains in the year ended December 31, 2022.
Impairment Expense - During the year ended December 31, 2020, we recorded an impairment charge which decreased income from operations and net income by $98.8 million and $72.5 million, respectively, resulting from the write-down of certain assets as a result of the East Coast Refining Reconfiguration, project abandonments and the write-down of certain PBFX long-lived assets. 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, 2019.2020, the Company recorded a pre-tax charge to cost of products and other related to a LIFO inventory layer decrement. The majority of the decrement related to our East Coast 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 and $60.9 million, respectively, for the year ended December 31, 2020. Decrements recorded in the years ended December 31, 2022 and December 31, 2021 were not significant.
Severance and Reconfiguration Costs - During the year ended December 31, 2020, we recorded severance charges related to reductions in our crude supply agreement with PDVSA. We have not sourced crude oil under this agreement sinceworkforce, which decreased income from operations and net income by $24.7 million and $18.1 million, respectively. During the third quarter of 2017 as PDVSA has suspended deliveries dueyear ended December 31, 2020, we recorded reconfiguration charges related to the parties inability to agree to mutually acceptable payment terms and becausetemporary idling of U.S. government sanctions against PDVSA.
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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 and $9.2 million, respectively. There were no such expenses recorded in costthe years ended December 31, 2022 and tenureDecember 31, 2021.
Loss (Gain) on Extinguishment of Debt - During the year ended December 31, 2022, we recorded a pre-tax net loss on extinguishment of debt which decreased income before income taxes and net income by $66.1 million and $49.0 million, respectively, primarily related to remediate our outstanding obligations and are further discussed in “Note 13 - Commitments and Contingencies”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 pre-tax gain on extinguishment of debt related to Consolidated Financial Statements.the repurchase of a portion of the 2028 Senior Notes and the 2025 Senior Notes, which increased income before income taxes and net income by $79.9 million and $59.2 million, respectively. During the year ended December 31, 2020, we recorded pre-tax debt extinguishment costs related to the redemption of the 2023 Senior Notes which decreased income before income taxes and net income by $22.2 million and $16.3 million, respectively.
liability - During the year ended December 31, 2022, we recorded a change in the Tax Receivable Agreement liability that decreased income before income taxes and net income by $290.3 million and $215.1 million, respectively. During the year ended December 31, 2021, PBF Energy recorded a change in the Tax Receivable Agreement liability that decreased income before income taxes and net income by $48.3 million and $35.8 million, respectively. During the year ended December 31, 2020, PBF Energy recorded a change in the Tax Receivable Agreement liability that increased income before taxes and net income by $373.5 million and $274.1 million, respectively. The table above reflectschanges in the Tax Receivable Agreement liability reflect charges or benefits attributable to changes in PBF Energy’s estimated timing of paymentsobligation under the Tax Receivable Agreement including the impactdue to factors out of our control such as changes in tax rates, as well as periodic adjustments to our liability based, in part, on an updated estimate of the TCJA, assumingamounts that we earn sufficient taxableexpect to pay, using assumptions consistent with those used in our concurrent estimate of the deferred tax asset valuation allowance.
Recomputed Income Tax on Special Items - The income tax impact on these special items, other than the net tax expense special item discussed below, is calculated using the tax rates shown in (2) above.
Net Tax (Benefit) Expense on Remeasurement of Deferred Tax Assets - During the year ended December 31, 2022, we recorded a decrease to realize allour deferred tax benefits that are subjectvaluation allowance of $308.5 million (reducing our deferred tax valuation allowance to zero), in accordance with ASC 740, of which $233.8 million related to a tax benefit with respect to the remeasurement of deferred tax assets and the balance related to our net changes in the Tax Receivable Agreement liability. During the year ended December 31, 2021, we recorded a deferred tax valuation allowance of $308.5 million in accordance with ASC 740(a decrease of$49.9 million when compared to December 31, 2020, which includes a tax benefit of approximately $12.5 million related to our net change in the Tax Receivable Agreement liability and a net tax benefit of $37.4 million related primarily to the remeasurement of deferred tax assets). During the year ended December 31, 2020, we recorded a deferred tax valuation allowance of $358.4 million. This amount includes tax expense of approximately $99.3 million related to our net change in the Tax Receivable Agreement liability or a net tax expense of $259.1 million related primarily to the remeasurement of deferred tax assets.
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(4) Represents an adjustment to weighted-average diluted shares outstanding to assume the full exchange of existing PBF LLC Series A Units as described in (1) above.
(5) Represents weighted-average diluted shares outstanding assuming the conversion of all common stock equivalents, including options and warrants for PBF LLC Series A Units and performance share units and options for shares of PBF Energy Class A common stock as calculated under the treasury stock method (to the extent the impact of such exchange would not be anti-dilutive) for the years ended December 31, 2022, 2021 and 2020, respectively. Common stock equivalents exclude the effects of performance share units and options and warrants to purchase 3,877,035, 12,568,275 and 14,446,894 shares of PBF Energy Class A common stock and PBF LLC Series A Units because they are anti-dilutive for the years ended December 31, 2022, 2021 and 2020, respectively. For periods showing a net loss, all common stock equivalents and unvested restricted stock are considered anti-dilutive.
(6) Total Equity excluding special items is calculated in the table below:
| December 31, | December 31, | |||||||||||||||||||
| 2022 | 2021 | |||||||||||||||||||
| (in millions) | ||||||||||||||||||||
| Total equity | $ | 5,056.0 | $ | 2,532.8 | ||||||||||||||||
| Special Items (Note 4) | ||||||||||||||||||||
| Add: Change in fair value of contingent consideration, net | (13.0) | (61.3) | ||||||||||||||||||
| Add: Gain on sale of hydrogen plants | (471.1) | (471.1) | ||||||||||||||||||
| Add: Gain on land sales | (87.8) | (87.8) | ||||||||||||||||||
| Add: Impairment expense | 98.8 | 98.8 | ||||||||||||||||||
| Add: LIFO inventory decrement | 83.0 | 83.0 | ||||||||||||||||||
| Add: Turnaround acceleration costs | 56.2 | 56.2 | ||||||||||||||||||
| Add: Severance and reconfiguration costs | 30.0 | 30.0 | ||||||||||||||||||
| Add: Early railcar return expense | 64.8 | 64.8 | ||||||||||||||||||
| Add: Loss (gain) on extinguishment of debt | 33.9 | (32.2) | ||||||||||||||||||
| Add: Change in Tax Receivable Agreement liability | (325.3) | (615.6) | ||||||||||||||||||
| Less: Recomputed income tax on special items | 126.9 | 231.8 | ||||||||||||||||||
| Add: Net tax (benefit) expense on remeasurement of deferred tax assets | (12.1) | 221.7 | ||||||||||||||||||
| Add: Net tax expense on Tax Cuts and Jobs Act related special items | 20.2 | 20.2 | ||||||||||||||||||
| Net impact of special items to equity | (395.5) | (461.5) | ||||||||||||||||||
| Total equity excluding special items | $ | 4,660.5 | $ | 2,071.3 | ||||||||||||||||
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Liquidity and Capital Resources
Overview
Our primary sources of liquidity are our cash flows from operations, cash and cash equivalents and borrowing availability under our credit facilities, as described below. We believe that our cash flows from operations and available capital resources will be sufficient to meet our and our subsidiaries’ capital expenditures, working capital needs, dividend payments, debt service and share repurchase program requirements, as well as PBF Energy’s obligations under the Tax Receivable Agreement, for the next twelve months. However, our ability to generate sufficient cash flow from operations depends, in part, on petroleum oil market pricing and general economic, political and other factors beyond our control. As of December 31, 2022, 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 $4,772.0 million for the year ended December 31, 2022 compared to net cash provided by operating activities of $477.3 million for the year ended December 31, 2021. Our operating cash flows for the year ended December 31, 2022 included our net income of $2,972.8 million, and net changes in operating assets and liabilities reflecting cash proceeds of $341.0 million, primarily driven by timing of payments for accrued expense. Change in accrued expenses is due primarily to an increase in renewable energy and emissions obligations, as a result of an increase in our unfunded RINs obligation as of December 31, 2019.2022. Our overall increase in cash provided by operating activities also included depreciation and amortization of $533.9 million, deferred income taxes of $420.2 million, change in the Tax Receivable Agreement liability of $290.3 million, net loss on extinguishment of debt primarily related to the redemption of our 2025 Senior Secured Notes of $66.1 million, stock-based compensation of $54.3 million, net change in the fair value of contingent consideration of $48.3 million, pension and other post-retirement benefit costs of $47.6 million, change in the fair value of our catalyst obligations of $2.0 million, and loss on sale of assets of $0.9 million, partially offset by net non-cash charges related to the change in the fair value of our inventory repurchase obligations of $5.4 million.
Our operating cash flows for the year ended December 31, 2021 included our net income of $315.5 million, depreciation and amortization of $483.8 million, net changes in operating assets and liabilities reflecting cash proceeds of $268.6 million primarily driven by accrued expenses due 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, pension and other post-retirement benefit costs of $50.8 million, change in the Tax Receivable Agreement liability of $48.3 million, stock-based compensation of $35.6 million, change in the fair value of contingent consideration of $32.4 million, and deferred income taxes of $11.7 million, partially offset by a net non-cash benefit of $669.6 million related to an LCM inventory adjustment, gain on extinguishment of debt related to the repurchase of a portion of our 2028 Senior Notes and 2025 Senior Notes of $79.9 million, changes in the fair value of our catalyst obligations of $8.5 million, net non-cash charges related to the change in the fair value of our inventory repurchase obligations of $8.4 million, and gain on sale of assets of $3.0 million.
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Net cash provided by operating activities was $477.3 million for the year ended December 31, 2021 compared to net cash used in operating activities of $631.6 million for the year ended December 31, 2020. Our operating cash flows for the year ended December 31, 2020 included our net loss of $1,333.3 million, gain on sale of assets of $477.8 million mainly related to the sale of the hydrogen plants and the sale of land at our Torrance refinery, change in the Tax Receivable Agreement liability of $373.5 million, net non-cash charges relating to the change in the fair value of our inventory repurchase obligations of $12.6 million and change in the fair value of the contingent consideration of $93.7 million, partially offset by depreciation and amortization of $581.1 million, net non-cash charge of $268.0 million related to an LCM inventory adjustment, impairment expense of $98.8 million, pension and other post-retirement benefits costs of $55.7 million, stock-based compensation of $34.2 million, debt extinguishment costs related to the early redemption of our 2023 Senior Notes of $22.2 million, change in the fair value of our catalyst obligations of $11.8 million and deferred income taxes of $1.6 million. In addition, net changes in operating assets and liabilities reflected cash inflows of $585.9 million driven by the timing of inventory purchases, payments for accrued expenses and accounts payable and collections of accounts receivable.
Cash Flows from Investing Activities
Net cash used in investing activities was $1,010.9 million for the year ended December 31, 2022 compared to $388.5 million for the year ended December 31, 2021. The net cash flows used in investing activities for the year ended December 31, 2022 was comprised of cash outflows of capital expenditures totaling $633.3 million, expenditures for refinery turnarounds of $311.6 million, and expenditures for other assets of $66.0 million. Net cash used in investing activities for the year ended December 31, 2021 was comprised of cash outflows of capital expenditures totaling $249.1 million, expenditures for refinery turnarounds of $117.7 million, and expenditures for other assets of $28.9 million, partially offset by proceeds from the sale of assets of $7.2 million.
Net cash used in investing activities was $388.5 million for the year ended December 31, 2021 compared to $1,026.5 million for the year ended December 31, 2020. Net cash used in investing activities for the year ended December 31, 2020 was comprised of cash outflows of $1,176.2 million used to fund the Martinez Acquisition, capital expenditures totaling $196.2 million, expenditures for refinery turnarounds of $188.1 million and expenditures for other assets of $9.1 million, partially offset by proceeds from sale of assets of $543.1 million.
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Cash Flows from Financing Activities
Net cash used in financing activities was $2,899.0 million for the year ended December 31, 2022 compared to net cash used in financing activities of $356.8 million for the year ended December 31, 2021. For the year ended December 31, 2022, net cash used in financing activities consisted of the redemption of our 2025 Senior Secured Notes of $1,307.4 million, net repayments on the Revolving Credit Facility of $900.0 million, the purchase of PBFX publicly held shares in connection with the Merger Transaction of $303.7 million, the share repurchase of PBF Energy’s Class A common stock of $156.4 million, net repayments on the PBFX Revolving Credit Facility of $100.0 million, dividends and distributions of $73.6 million, settlements of precious metal catalyst obligations of $56.2 million, deferred financing costs and other costs of $31.3 million, $25.9 million related to the repurchase of the principal amount outstanding of the 2028 Senior Notes and the 2025 Senior Notes, excluding accrued interest, payments on finance leases of $11.3 million, and PBFX Contingent Consideration payments of $3.1 million, partially offset by transactions made in connection with stock-based compensation plans of $67.8 million, and proceeds from insurance premium financing of $2.1 million. For the year ended December 31, 2021, net cash used in financing activities consisted of $146.8 million related to the repurchase of the principal amount outstanding of the 2028 Senior Notes and the 2025 Senior Notes, excluding accrued interest, net repayments on the PBFX Revolving Credit Facility of $100.0 million, distributions and dividends of $39.7 million, net settlements of precious metal catalyst obligations of $31.7 million, payments on finance leases of $17.8 million, PBFX Contingent Consideration payments of $12.2 million, principal amortization payments on the PBF Rail Term Loan of $7.4 million, and deferred financing costs and other of $1.2 million.
Net cash used in financing activities was $356.8 million for the year ended December 31, 2021 compared to net cash provided by financing activities of $2,452.7 million for the year ended December 31, 2020. For the year ended December 31, 2020, net cash provided by financing activities consisted of cash proceeds of $1,228.7 million from the issuance of the 2025 Senior Secured Notes net of related issuance costs, cash proceeds of $469.9 million from the issuance of the 2028 Senior Notes net of cash paid to redeem the 2023 Senior Notes and related issuance costs, net borrowings under our Revolving Credit Facility of $900.0 million, and proceeds from catalyst financing arrangements of $51.9 million, partially offset by net repayments on the PBFX Revolving Credit Facility of $83.0 million, net settlements of precious metal catalyst obligations of $8.8 million, distributions and dividends of $82.2 million, principal amortization payments of the PBF Rail Term Loan of $7.2 million, payments on finance leases of $12.4 million, taxes paid for net settlement of equity-based compensation of $2.1 million, repurchases of our common stock in connection with tax withholding obligations upon the vesting of certain restricted stock awards of $1.6 million and deferred financing costs and other of $0.5 million.
The cash flow activity of PBF LLC for the years ended December 31, 2022, 2021 and 2020 is materially consistent with that of PBF Energy discussed above, other than changes in deferred income taxes and certain working capital items, which are different from PBF Energy due to certain tax related items not applicable to PBF LLC. Additionally, PBF LLC reflects net borrowings of $1,070.5 million for the years ended December 31, 2022 and net repayments of $1.1 million and $0.1 million for 2021 and 2020, respectively, related to an affiliate loan with PBF Energy, included in cash flows from financing activities, which eliminates in consolidation at PBF Energy.
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Capitalization
Our capital structure was comprised of the following as of December 31, 2022 (in millions):
| December 31, 2022 | |||||
Debt: (1) | |||||
| PBF LLC debt | |||||
| Affiliate note payable | $ | 1,445.7 | |||
| PBF Holding debt | |||||
| 2028 Senior Notes | 801.6 | ||||
| 2025 Senior Notes | 664.5 | ||||
| Revolving Credit Facility | — | ||||
| Catalyst financing arrangements | 4.0 | ||||
| PBF Holding debt | 1,470.1 | ||||
| PBFX debt | |||||
PBFX 2023 Senior Notes (2) | 525.0 | ||||
| PBFX Revolving Credit Facility | — | ||||
| PBFX debt | 525.0 | ||||
| Unamortized deferred financing costs | (36.2) | ||||
| Unamortized premium | 0.2 | ||||
| Total PBF LLC debt, net of unamortized deferred financing costs and premium | 3,404.8 | ||||
| Less: Affiliate note payable | (1,445.7) | ||||
Total PBF Energy debt, net of unamortized deferred financing costs and premium(3) | $ | 1,959.1 | |||
| Total PBF Energy Equity | $ | 5,056.0 | |||
Total PBF Energy Capitalization (4) | $ | 7,015.1 | |||
(1) Refer to “Note 138 - CommitmentsCredit Facilities and Contingencies” of our Notes to Consolidated Financial Statement for further discussion of the Tax Receivable Agreement.
(2) The PBFX 2023 Senior Notes were redeemed on February 2, 2023.
(3) Excludes the PBF LLC affiliate note payable that is eliminated in the PBF Energy consolidated financial statements.
(4) Total Capitalization refers to the sum of debt, excluding intercompany debt, plus total equity.
2022 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.
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In addition, we made a number of open market repurchases of our 2028 Senior Notes and 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 this extinguishment of debt during the year ended December 31, 2022.
On May 25, 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.
During 2022, we also settled certain of our precious metals financing arrangements, resulting in a reduction of debt of approximately $56.2 million.
Revolving Credit Facilities Overview
One of our primary sources of liquidity are borrowings available under our revolving credit facilities. As of December 31, 2022, PBF Energy had $2,203.6 million of cash and cash equivalents and no outstanding balances under the Revolving Credit Facility or the PBFX Revolving Credit Facility. PBF LLC cash and cash equivalents totaled $2,201.8 million as of December 31, 2019, PBF LLC2022.
We had an outstanding note payableavailable capacity under revolving credit facilities as follows at December 31, 2022 (in millions):
| 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 | |||||||||||||||||||||||
| PBFX Revolving Credit Facility | 500.0 | — | 3.5 | 496.5 | July 2023 | |||||||||||||||||||||||||||
| Total Credit Facilities | $ | 4,800.0 | $ | — | $ | 579.6 | $ | 4,796.5 | ||||||||||||||||||||||||
(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 PBF Energy for an aggregate principal amountrespect to investment grade obligors plus (ii) 85% of $376.4 million.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 note has an interest rate of 2.5%borrowing base is subject to customary reserves and matureseligibility criteria and in April 2030, but may be prepaid in whole or in part at any time, at the option of PBF LLC without penalty or premium. This affiliate note payable is a cash obligation of PBF LLC only and eliminates in consolidation for PBF Energy.event cannot exceed $4.3 billion.
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Martinez Acquisition
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
On October 25, 2021, PBF Holding and its subsidiaries, the PBF Entities, entered into the Third Inventory Intermediation Agreement with J. Aron, 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, which term may be further extended by mutual consent of the parties to December 31, 2025. On May 25, 2022, the 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, 2022 to the Revolving Credit 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.
Renewable Fuel Standard
We are subject to obligations to purchase RINs required to comply with the Renewable Fuel Standard. 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 $1,225.5 million in RINs costs during the year ended December 31, 2022 as compared to $726.0 million and $326.4 million during the years ended December 31, 2021 and 2020, respectively. The increases in RINs costs are due primarily to volatility in prices for ethanol-linked RINs and increases 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.
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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.
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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 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 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. 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.
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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 closing.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, 37% distillate, 2% high-value Group I lubricants, 1% high-value petrochemicals, with the remaining portion of the product slate comprised of lower-value products (3% LPGs, 12% black oil and 6% 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 60% 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 51% gasoline, 36% distillate, 5% high-value petrochemicals (including nonene, tetramer, benzene, xylene and toluene) with the remaining portion of the product slate comprised of lower-value products (5% LPGs and 3% black oil). For this reason, we believe the WTI (Chicago) 4-3-1 is an appropriate benchmark industry refining margin. The majority of Toledo revenues are generated off Chicago-based market prices.
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.
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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 44% gasoline and 36% distillate, 1% high-value petrochemicals with the remaining portion of the product slate comprised of lower-value products (7% black oil, 5% LPGs, 3% petroleum coke, and 4% 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 processed a slate of primarily medium and heavy sour crude oils, which has historically constituted approximately 50% to 75%of total throughput. The remaining throughput consists of sweet crude oil 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 56% gasoline and 27% distillate with the remaining portion of the product slate comprised of lower-value products (3% LPG, 3% black oil and 11% 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 70% to 90% 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.
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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 54% gasoline and 35% distillate with the remaining portion of the product slate comprised of lower-value products (2% black oil petroleum coke, 4% LPG and 5% 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 70% to 90% 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.
Results of Operations
The tables below reflect our consolidated financial and operating highlights for the years ended December 31, 2022, 2021 and 2020 (amounts in millions, except per share data). Differences between the results of operations of PBF Energy and PBF LLC primarily pertain to income taxes, interest expense and noncontrolling interest as shown below. Earnings per share information applies only to the financial results of PBF Energy. We operate in two reportable business segments: Refining and Logistics. Our oil refineries, excluding the assets operated by PBFX, are all engaged in the refining of crude oil and other feedstocks into petroleum products, and represent the Refining segment. PBFX is an indirect wholly-owned subsidiary of PBF Energy and PBF LLC that operates certain logistics assets such as crude oil and refined products terminals, pipelines and storage facilities. PBFX’s operations represent the Logistics segment. We do not separately discuss our results by individual segments as, apart from PBFX’s third-party acquisitions, our Logistics segment did not have any significant third-party revenues and a significant portion of its operating results are eliminated in consolidation.
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| PBF Energy | Year Ended December 31, | |||||||||||||||||||
| 2022 | 2021 | 2020 | ||||||||||||||||||
| Revenues | $ | 46,830.3 | $ | 27,253.4 | $ | 15,115.9 | ||||||||||||||
| Cost and expenses: | ||||||||||||||||||||
| Cost of products and other | 39,049.1 | 23,826.8 | 14,275.6 | |||||||||||||||||
| Operating expenses (excluding depreciation and amortization expense as reflected below) | 2,599.0 | 2,085.9 | 1,918.3 | |||||||||||||||||
| Depreciation and amortization expense | 503.6 | 453.5 | 551.7 | |||||||||||||||||
| Cost of sales | 42,151.7 | 26,366.2 | 16,745.6 | |||||||||||||||||
| General and administrative expenses (excluding depreciation and amortization expense as reflected below) | 468.7 | 247.3 | 248.5 | |||||||||||||||||
| Depreciation and amortization expense | 7.5 | 13.3 | 11.3 | |||||||||||||||||
| Change in fair value of contingent consideration, net | 48.3 | 32.4 | (93.7) | |||||||||||||||||
| Impairment expense | — | — | 98.8 | |||||||||||||||||
| Loss (gain) on sale of assets | 0.9 | (3.0) | (477.8) | |||||||||||||||||
| Total cost and expenses | 42,677.1 | 26,656.2 | 16,532.7 | |||||||||||||||||
| Income (loss) from operations | 4,153.2 | 597.2 | (1,416.8) | |||||||||||||||||
| Other income (expense): | ||||||||||||||||||||
| Interest expense, net | (246.0) | (317.5) | (258.2) | |||||||||||||||||
| Change in Tax Receivable Agreement liability | (290.3) | (48.3) | 373.5 | |||||||||||||||||
| Change in fair value of catalyst obligations | (2.0) | 8.5 | (11.8) | |||||||||||||||||
| (Loss) gain on extinguishment of debt | (66.1) | 79.9 | (22.2) | |||||||||||||||||
| Other non-service components of net periodic benefit cost | 8.8 | 7.8 | 4.3 | |||||||||||||||||
| Income (loss) before income taxes | 3,557.6 | 327.6 | (1,331.2) | |||||||||||||||||
| Income tax expense | 584.8 | 12.1 | 2.1 | |||||||||||||||||
| Net income (loss) | 2,972.8 | 315.5 | (1,333.3) | |||||||||||||||||
| Less: net income attributable to noncontrolling interests | 96.0 | 84.5 | 59.1 | |||||||||||||||||
| Net income (loss) attributable to PBF Energy Inc. stockholders | $ | 2,876.8 | $ | 231.0 | $ | (1,392.4) | ||||||||||||||
| Consolidated gross margin | $ | 4,678.6 | $ | 887.2 | $ | (1,629.7) | ||||||||||||||
Gross refining margin (1) | $ | 7,429.9 | $ | 3,087.7 | $ | 496.8 | ||||||||||||||
| Net income available to Class A common stock per share: | ||||||||||||||||||||
| Basic | $ | 23.47 | $ | 1.92 | $ | (11.64) | ||||||||||||||
| Diluted | $ | 22.84 | $ | 1.90 | $ | (11.64) | ||||||||||||||
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(1) See Non-GAAP Financial Measures.
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| PBF LLC | Year Ended December 31, | |||||||||||||||||||
| 2022 | 2021 | 2020 | ||||||||||||||||||
| Revenues | $ | 46,830.3 | $ | 27,253.4 | $ | 15,115.9 | ||||||||||||||
| Cost and expenses: | ||||||||||||||||||||
| Cost of products and other | 39,049.1 | 23,826.8 | 14,275.6 | |||||||||||||||||
| Operating expenses (excluding depreciation and amortization expense as reflected below) | 2,599.0 | 2,085.9 | 1,918.3 | |||||||||||||||||
| Depreciation and amortization expense | 503.6 | 453.5 | 551.7 | |||||||||||||||||
| Cost of sales | 42,151.7 | 26,366.2 | 16,745.6 | |||||||||||||||||
| General and administrative expenses (excluding depreciation and amortization expense as reflected below) | 466.6 | 245.2 | 247.7 | |||||||||||||||||
| Depreciation and amortization expense | 7.5 | 13.3 | 11.3 | |||||||||||||||||
| Change in fair value of contingent consideration, net | 48.3 | 32.4 | (93.7) | |||||||||||||||||
| Impairment expense | — | — | 98.8 | |||||||||||||||||
| Loss (gain) on sale of assets | 0.9 | (3.0) | (477.8) | |||||||||||||||||
| Total cost and expenses | 42,675.0 | 26,654.1 | 16,531.9 | |||||||||||||||||
| Income (loss) from operations | 4,155.3 | 599.3 | (1,416.0) | |||||||||||||||||
| Other income (expense): | ||||||||||||||||||||
| Interest expense, net | (257.2) | (327.8) | (268.5) | |||||||||||||||||
| Change in fair value of catalyst obligations | (2.0) | 8.5 | (11.8) | |||||||||||||||||
| (Loss) gain on extinguishment of debt | (66.1) | 79.9 | (22.2) | |||||||||||||||||
| Other non-service components of net periodic benefit cost | 8.8 | 7.8 | 4.3 | |||||||||||||||||
| Income (loss) before income taxes | 3,838.8 | 367.7 | (1,714.2) | |||||||||||||||||
| Income tax expense (benefit) | 4.6 | (14.0) | 6.1 | |||||||||||||||||
| Net income (loss) | 3,834.2 | 381.7 | (1,720.3) | |||||||||||||||||
| Less: net income attributable to noncontrolling interests | 68.1 | 82.1 | 76.2 | |||||||||||||||||
| Net income (loss) attributable to PBF Energy Company LLC | $ | 3,766.1 | $ | 299.6 | $ | (1,796.5) | ||||||||||||||
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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 | $ | 13.85 | $ | 2.91 | $ | (6.12) | ||||||||||||||||||||
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 | % | ||||||||||||||||||||
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(1) See Non-GAAP Financial Measures.
(2) We define heavy crude oil as crude oil with an API gravity of less than 24 degrees. We define medium crude oil as crude oil with an API gravity between 24 and 35 degrees. We define light crude oil as crude oil with an API gravity higher than 35 degrees.
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The table below summarizes certain market indicators relating to our operating results as reported by Platts, a division of The McGraw-Hill Companies.
| Year Ended December 31, | ||||||||||||||||||||
| 2022 | 2021 | 2020 | ||||||||||||||||||
| (dollars per barrel, except as noted) | ||||||||||||||||||||
| Dated Brent crude oil | $ | 101.27 | $ | 70.89 | $ | 41.62 | ||||||||||||||
| West Texas Intermediate (WTI) crude oil | $ | 94.58 | $ | 68.10 | $ | 39.25 | ||||||||||||||
| Light Louisiana Sweet (LLS) crude oil | $ | 96.81 | $ | 69.59 | $ | 41.13 | ||||||||||||||
| Alaska North Slope (ANS) crude oil | $ | 98.76 | $ | 70.56 | $ | 42.20 | ||||||||||||||
| Crack Spreads | ||||||||||||||||||||
| Dated Brent (NYH) 2-1-1 | $ | 40.26 | $ | 16.84 | $ | 9.11 | ||||||||||||||
| WTI (Chicago) 4-3-1 | $ | 31.56 | $ | 16.34 | $ | 6.30 | ||||||||||||||
| LLS (Gulf Coast) 2-1-1 | $ | 37.56 | $ | 16.03 | $ | 7.59 | ||||||||||||||
| ANS (West Coast-LA) 4-3-1 | $ | 41.64 | $ | 20.10 | $ | 11.30 | ||||||||||||||
| ANS (West Coast-SF) 3-2-1 | $ | 41.89 | $ | 20.55 | $ | 9.99 | ||||||||||||||
| Crude Oil Differentials | ||||||||||||||||||||
| Dated Brent (foreign) less WTI | $ | 6.68 | $ | 2.80 | $ | 2.37 | ||||||||||||||
| Dated Brent less Maya (heavy, sour) | $ | 13.95 | $ | 6.47 | $ | 5.37 | ||||||||||||||
| Dated Brent less WTS (sour) | $ | 6.98 | $ | 2.63 | $ | 2.33 | ||||||||||||||
| Dated Brent less ASCI (sour) | $ | 9.68 | $ | 3.90 | $ | 1.81 | ||||||||||||||
| WTI less WCS (heavy, sour) | $ | 21.30 | $ | 14.19 | $ | 10.72 | ||||||||||||||
| WTI less Bakken (light, sweet) | $ | (4.05) | $ | (0.14) | $ | 2.41 | ||||||||||||||
| WTI less Syncrude (light, sweet) | $ | (3.04) | $ | 2.25 | $ | 2.13 | ||||||||||||||
| WTI less LLS (light, sweet) | $ | (2.22) | $ | (1.50) | $ | (1.88) | ||||||||||||||
| WTI less ANS (light, sweet) | $ | (4.17) | $ | (2.46) | $ | (2.95) | ||||||||||||||
| Natural gas (dollars per MMBTU) | $ | 6.54 | $ | 3.73 | $ | 2.13 | ||||||||||||||
2022 Compared to 2021
Overview— PBF Energy net income was $2,972.8 million for the year ended December 31, 2022 compared to net income of $315.5 million for the year ended December 31, 2021. PBF LLC net income was $3,834.2 million for the year ended December 31, 2022 compared to net income of $381.7 million for the year ended December 31, 2021. Net income attributable to PBF Energy stockholders was $2,876.8 million, or $22.84 per diluted share, for the year ended December 31, 2022 ($22.84 per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income, or $23.36 per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income excluding special items, as described below in Non-GAAP Financial Measures) compared to net income attributable to PBF Energy stockholders of $231.0 million, or $1.90 per diluted share, for the year ended December 31, 2021 ($1.90 per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income, or $(2.50) per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net loss excluding special items, as described below in Non-GAAP Financial Measures). The net income attributable to PBF Energy stockholders represents PBF Energy’s equity interest in PBF LLC’s pre-tax income, less applicable income tax expense. PBF Energy’s weighted-average equity interest in PBF LLC was 99.3% and 99.2% for the years ended December 31, 2022 and 2021, respectively.
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Our results for the year ended December 31, 2022 were negatively impacted by special items consisting of pre-tax charges associated with the change in the Tax Receivable Agreement liability of $290.3 million, or $215.1 million net of tax, a net loss on the extinguishment of debt mainly associated with the redemption of our 2025 Senior Secured Notes of $66.1 million, or $49.0 million net of tax, and net changes in fair value of contingent consideration of $48.3 million, or $35.8 million net of tax, partially offset by a $233.8 million tax benefit associated with the remeasurement of certain deferred tax assets. Our results for the year ended December 31, 2021 were positively impacted by special items consisting of a non-cash, pre-tax LCM inventory adjustment of approximately $669.6 million, or $496.2 million net of tax, a pre-tax 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, or $59.2 million net of tax, a gain on the sale of certain PBFX land of $2.8 million, or $2.1 million net of tax, and a $37.4 million tax benefit associated with the remeasurement of certain deferred tax assets, offset by pre-tax charges associated with the change in the Tax Receivable Agreement liability of $48.3 million, or $35.8 million net of tax and a change in fair value of the Martinez Contingent Consideration and the earn-out obligation associated with the acquisition of CPI Operations LLC (the “PBFX Contingent Consideration”) of $32.4 million, or $24.0 million net of tax.
Excluding the impact of these special items, when comparing our results to the year ended December 31, 2021, we experienced an increase in the demand for our refined products, evidenced by higher throughput volumes and barrels sold at all of our refineries, as well as overall stronger refining margins due to favorable movements in crack spreads and crude oil differentials. These improving metrics have positively impacted our revenues, gross margin, and operating income.
Revenues— Revenues totaled $46.8 billion for the year ended December 31, 2022 compared to $27.3 billion for the year ended December 31, 2021, an increase of approximately $19.5 billion or 71.4%. Revenues per barrel sold were $123.26 and $80.79 for the years ended December 31, 2022 and 2021, respectively, an increase of 52.6% 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.
Overall average 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— Consolidated gross margin totaled $4,678.6 million for the year ended December 31, 2022, compared to $887.2 million for the year ended December 31, 2021, an increase of $3,791.4 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.
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During the year ended December 31, 2022, our margin calculations were not impacted by special items. Consolidated gross margin and gross refining margin increased due to favorable movements in certain crack spreads and crude oil differentials and higher throughput volumes and barrels sold at all our refineries. For the year ended December 31, 2021, our margin calculations included a favorable special item related to a non-cash LCM inventory adjustment of approximately $669.6 million on a net basis resulting from the increase in crude oil and refined product prices from the year ended December 31, 2020 to the year ended December 31, 2021.
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.
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.
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Operating Expenses— Operating expenses totaled $2,599.0 million for the year ended December 31, 2022 compared to $2,085.9 million for the year ended December 31, 2021, an increase of approximately $513.1 million, or 24.6%. Of the total $2,599.0 million in operating expenses, $2,495.6 million, or 7.39 per barrel of throughput, related to expenses incurred by the Refining segment, while the remaining $103.4 million related to expenses incurred by the Logistics segment ($1,999.1 million or 6.56 per barrel of throughput, and $86.8 million of operating expenses for the year ended December 31, 2021 related to the Refining and Logistics segments, respectively). 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 $468.7 million for the year ended December 31, 2022, compared to $247.3 million for the year ended December 31, 2021, an increase of $221.4 million or 89.5%. 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 $511.1 million for the year ended December 31, 2022 (including $503.6 million recorded within Cost of sales) compared to $466.8 million for the year ended December 31, 2021 (including $453.5 million recorded within Cost of sales), an increase of $44.3 million. The increase was a result of a general increase in our fixed asset base due to capital projects and turnarounds completed since the end of the prior year.
Change in Fair Value of Contingent Consideration, net— Change in fair value of contingent consideration represented a loss of $48.3 million and a loss of $32.4 million for the years ended December 31, 2022 and December 31, 2021, respectively. These losses were primarily related to the changes in estimated fair value of the earn-out liability associated with the acquisition of the Martinez refinery, offset by the recognition of contingent assets associated with the acquisition.
Loss (Gain) on Sale of Assets— 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. There was a gain of $3.0 million for the year ended December 31, 2021 related primarily to a third-party sale of PBFX real property.
Change in Tax Receivable Agreement Liability— Change in the Tax Receivable Agreement liability for the year ended December 31, 2022 and December 31, 2021, represented a charge of $290.3 million and a charge of $48.3 million, respectively. These charges were primarily the result of changes in the deferred tax asset valuation allowance recorded in accordance with Accounting Standards Codification (“ASC”) 740 Income Taxes (“ASC 740”), related to the reduction of deferred tax assets associated with the payments made or expected to be made in connection with the Tax Receivable Agreement liability.
Change in Fair Value of Catalyst Obligations— Change in fair value of catalyst obligations represented a loss of $2.0 million for the year ended December 31, 2022, compared to a gain of $8.5 million for the year ended December 31, 2021. These losses and gains relate to the change in fair value of the precious metals underlying the sale and leaseback of our refineries’ precious metal catalysts, which we are obligated to repurchase at fair market value upon lease termination.
(Loss) Gain on Extinguishment of Debt— We incurred a loss on extinguishment of debt of $66.1 million 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 our 2028 Senior Notes and 2025 Senior Notes. We incurred a gain on extinguishment of debt of $79.9 million in the year ended December 31, 2021 related to the repurchase of a portion of our 2028 Senior Notes and 2025 Senior Notes.
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Interest Expense, net— PBF Energy interest expense totaled $246.0 million for the year ended December 31, 2022, compared to $317.5 million for the year ended December 31, 2021, a decrease of $71.5 million. This net decrease is mainly attributable to the redemption of the 2025 Senior Secured Notes during the third quarter of 2022, as well as lower outstanding balances on our revolving credit facilities. Interest expense includes interest on long-term debt including the PBFX credit facilities, costs related to the sale and leaseback of our precious metal catalysts, financing costs associated with the Third Inventory Intermediation Agreement with J. Aron, letter of credit fees associated with the purchase of certain crude oils and the amortization of deferred financing costs. PBF LLC interest expense totaled $257.2 million and $327.8 million for the year ended December 31, 2022 and December 31, 2021, respectively (inclusive of $11.2 million and $10.3 million, respectively, of incremental interest expense on the affiliate note payable with PBF Energy that eliminates in consolidation in the PBF Energy consolidated financial statements).
Income Tax Expense— PBF LLC is organized as a limited liability company and PBFX is a partnership, both of which are treated as “flow-through” entities for federal income tax purposes and therefore are not subject to income tax. However, two subsidiaries of Chalmette Refining and our Canadian subsidiary, PBF Energy Limited, are treated as C-Corporations for income tax purposes and may incur income taxes with respect to their earnings, as applicable. The members of PBF LLC are required to include their proportionate share of PBF LLC’s taxable income or loss, on their respective tax returns. PBF LLC generally makes distributions to its members, per the terms of PBF LLC’s amended and restated limited liability company agreement, related to such taxes on a pro-rata basis. PBF Energy recognizes an income tax expense or benefit in our consolidated financial statements based on PBF Energy’s allocable share of PBF LLC’s pre-tax income or loss, which was approximately 99.3% and 99.2%, on a weighted-average basis for the years ended December 31, 2022 and 2021, respectively. PBF Energy’s Consolidated Financial Statements do not reflect any benefit or provision for income taxes on the pre-tax income or loss attributable to the noncontrolling interests in PBF LLC (although, as described above, PBF LLC must make tax distributions to all its members on a pro-rata basis). PBF Energy’s effective tax rate, including the impact of noncontrolling interests, for the years ended December 31, 2022 and 2021 was 16.4% and 3.7%, respectively. The effective tax rate for both years was significantly impacted by changes in the deferred tax valuation allowance. In 2022, the full valuation allowance was released, resulting in a tax benefit of $308.5 million for the year ended December 31, 2022, compared to a tax benefit of $49.9 million for the year ended December 31, 2021.
Noncontrolling Interest— PBF Energy is the sole managing member of, and has a controlling interest in, PBF LLC. As the sole managing member of PBF LLC, PBF Energy operates and controls all of the business and affairs of PBF LLC and its subsidiaries. PBF Energy consolidates the financial results of PBF LLC and its subsidiaries, including PBFX. With respect to the consolidation of PBF LLC, we record a noncontrolling interest for the economic interest in PBF LLC held by members other than PBF Energy, with respect to the consolidation of PBFX, we recorded a noncontrolling interest for the economic interests in PBFX held by the public unitholders of PBFX prior to the close of the PBFX Merger Transaction, and with respect to the consolidation of PBF Holding, we record a 20% noncontrolling interest for the ownership interests in two subsidiaries of Chalmette Refining held by a third-party. The total noncontrolling interest on the Consolidated Statements of Operations represents the portion of the Company’s earnings or loss attributable to the economic interests held by members of PBF LLC other than PBF Energy, by the public common unitholders of PBFX prior to the close of the PBFX Merger Transaction and by the third-party stockholders of certain of Chalmette Refining’s subsidiaries. The total noncontrolling interest on the Consolidated Balance Sheets represents the portion of the Company’s net assets attributable to the economic interests held by the members of PBF LLC other than PBF Energy, and by the third-party stockholders of the two Chalmette Refining subsidiaries. PBF Energy’s weighted-average equity noncontrolling interest ownership percentage in PBF LLC for the years ended December 31, 2022 and 2021 was approximately 0.7% and 0.8%, respectively. The carrying amount of the noncontrolling interest on our Consolidated Balance Sheets attributable to the noncontrolling interest is not equal to the noncontrolling interest ownership percentage due to the effect of income taxes and related agreements that pertain solely to PBF Energy.
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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. Such Non-GAAP financial measures are presented only in the context of PBF Energy’s results and are not presented or discussed in respect to PBF LLC.
Special Items
The Non-GAAP measures presented include Adjusted Fully-Converted Net Income (Loss) excluding special items, gross refining margin excluding special items, EBITDA excluding special items, and net debt to capitalization excluding special items. Special items for the periods presented relate to LCM inventory adjustments, net changes in fair value of contingent consideration, changes in the Tax Receivable Agreement liability, loss (gain) on extinguishment of debt, gain on sale of hydrogen plants, severance and reconfiguration costs, impairment expense, net tax (benefit) expense on remeasurement of deferred tax assets, 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.
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Adjusted Fully-Converted Net Income (Loss) and Adjusted Fully-Converted Net Income (Loss) Excluding Special Items
PBF Energy utilizes results presented on an Adjusted Fully-Converted basis that reflects an assumed exchange of all PBF LLC Series A Units for shares of PBF Energy Class A common stock. In addition, we present results on an Adjusted Fully-Converted basis excluding special items as described above. We believe that these Adjusted Fully-Converted measures, when presented in conjunction with comparable GAAP measures, are useful to investors to compare PBF Energy results across different periods and to facilitate an understanding of our operating results.
Neither Adjusted Fully-Converted Net Income (Loss) nor Adjusted Fully-Converted Net Income (Loss) excluding special items should be considered an alternative to net income (loss) presented in accordance with GAAP. Adjusted Fully-Converted Net Income (Loss) and Adjusted Fully-Converted Net Income (Loss) excluding special items presented by other companies may not be comparable to our presentation, since each company may define these terms differently. The differences between Adjusted Fully-Converted and GAAP results are as follows:
1.Assumed exchange of all PBF LLC Series A Units for shares of PBF Energy Class A common stock. As a result of the assumed exchange of all PBF LLC Series A Units, the noncontrolling interest related to these units is converted to controlling interest. Management believes that it is useful to provide the per-share effect associated with the assumed exchange of all PBF LLC Series A Units.
2.Income Taxes. Prior to PBF Energy’s IPO, PBF Energy was organized as a limited liability company treated as a “flow-through” entity for income tax purposes, and even after PBF Energy’s IPO, not all of its earnings are subject to corporate-level income taxes. Adjustments have been made to the Adjusted Fully-Converted tax provisions and earnings to assume that PBF Energy had adopted its post-IPO corporate tax structure for all periods presented and is taxed as a C-corporation in the U.S. at the prevailing corporate rates. These assumptions are consistent with the assumption in clause 1 above that all PBF LLC Series A Units are exchanged for shares of PBF Energy Class A common stock, as the assumed exchange would change the amount of PBF Energy’s earnings that are subject to corporate income tax.
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The following table reconciles PBF Energy’s Adjusted Fully-Converted results with its results presented in accordance with GAAP for the years ended December 31, 2022, 2021 and 2020 (in millions, except share and per share amounts):
| Year Ended December 31, | ||||||||||||||||||||
| 2022 | 2021 | 2020 | ||||||||||||||||||
| Net income (loss) attributable to PBF Energy Inc. stockholders | $ | 2,876.8 | $ | 231.0 | $ | (1,392.4) | ||||||||||||||
| Less: Income allocated to participating securities | — | — | 0.1 | |||||||||||||||||
| Income (loss) available to PBF Energy Inc. stockholders - basic | 2,876.8 | 231.0 | (1,392.5) | |||||||||||||||||
Add: Net income (loss) attributable to noncontrolling interests(1) | 27.9 | 2.4 | (17.1) | |||||||||||||||||
Less: Income tax (expense) benefit (2) | (7.2) | (0.6) | 4.6 | |||||||||||||||||
| Adjusted fully-converted net income (loss) | $ | 2,897.5 | $ | 232.8 | $ | (1,405.0) | ||||||||||||||
Special Items:(3) | ||||||||||||||||||||
| Add: Non-cash LCM inventory adjustment | — | (669.6) | 268.0 | |||||||||||||||||
| Add: Change in fair value of contingent consideration, net | 48.3 | 32.4 | (93.7) | |||||||||||||||||
| Add: Gain on sale of hydrogen plants | — | — | (471.1) | |||||||||||||||||
| Add: Gain on land sales | — | (2.8) | (8.1) | |||||||||||||||||
| Add: Impairment expense | — | — | 98.8 | |||||||||||||||||
| Add: LIFO inventory decrement | — | — | 83.0 | |||||||||||||||||
| Add: Turnaround acceleration costs | — | — | 56.2 | |||||||||||||||||
| 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 | |||||||||||||||||
| Add: Change in Tax Receivable Agreement liability | 290.3 | 48.3 | (373.5) | |||||||||||||||||
| Add: Net tax (benefit) expense on remeasurement of deferred tax assets | (233.8) | (37.4) | 259.1 | |||||||||||||||||
| Less: Recomputed income tax on special items | (104.9) | 173.9 | 99.9 | |||||||||||||||||
| Adjusted fully-converted net income (loss) excluding special items | $ | 2,963.5 | $ | (302.3) | $ | (1,421.7) | ||||||||||||||
| Weighted-average shares outstanding of PBF Energy Inc. | 122,598,076 | 120,240,009 | 119,617,998 | |||||||||||||||||
Conversion of PBF LLC Series A Units (4) | 917,991 | 988,730 | 1,042,667 | |||||||||||||||||
Common stock equivalents (5) | 3,344,039 | 1,409,415 | — | |||||||||||||||||
| Fully-converted shares outstanding—diluted | 126,860,106 | 122,638,154 | 120,660,665 | |||||||||||||||||
| Diluted net income (loss) per share | $ | 22.84 | $ | 1.90 | $ | (11.64) | ||||||||||||||
Adjusted fully-converted net income (loss) per fully exchanged, fully diluted shares outstanding (5) | $ | 22.84 | $ | 1.90 | $ | (11.64) | ||||||||||||||
| Adjusted fully-converted net income (loss) excluding special items per fully exchanged, fully diluted shares outstanding | $ | 23.36 | $ | (2.50) | $ | (11.78) | ||||||||||||||
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See Notes to Non-GAAP Financial Measures.
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Gross Refining Margin and Gross Refining Margin Excluding Special Items
Gross refining margin is defined as consolidated gross margin excluding refinery depreciation, refinery operating expenses, and gross margin of PBFX. 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 operating expenses and refinery 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 | |||||||||||||||||||||||||||
| $ | per barrel of throughput | $ | per barrel of throughput | $ | per barrel of throughput | ||||||||||||||||||||||||
| Calculation of consolidated gross margin: | |||||||||||||||||||||||||||||
| Revenues | $ | 46,830.3 | $ | 138.69 | $ | 27,253.4 | $ | 89.46 | $ | 15,115.9 | $ | 56.76 | |||||||||||||||||
| Less: Cost of sales | 42,151.7 | 124.84 | 26,366.2 | 86.55 | 16,745.6 | 62.88 | |||||||||||||||||||||||
| Consolidated gross margin | $ | 4,678.6 | $ | 13.85 | $ | 887.2 | $ | 2.91 | $ | (1,629.7) | $ | (6.12) | |||||||||||||||||
| Reconciliation of consolidated gross margin to gross refining margin: | |||||||||||||||||||||||||||||
| Consolidated gross margin | $ | 4,678.6 | $ | 13.85 | $ | 887.2 | $ | 2.91 | $ | (1,629.7) | $ | (6.12) | |||||||||||||||||
| Add: PBFX operating expense | 121.4 | 0.36 | 103.4 | 0.35 | 99.9 | 0.38 | |||||||||||||||||||||||
| Add: PBFX depreciation expense | 36.7 | 0.11 | 37.8 | 0.13 | 53.7 | 0.19 | |||||||||||||||||||||||
| Less: Revenues of PBFX | (369.3) | (1.09) | (355.5) | (1.17) | (360.3) | (1.35) | |||||||||||||||||||||||
| Add: Refinery operating expenses | 2,495.6 | 7.39 | 1,999.1 | 6.56 | 1,835.2 | 6.89 | |||||||||||||||||||||||
| Add: Refinery depreciation expense | 466.9 | 1.38 | 415.7 | 1.36 | 498.0 | 1.87 | |||||||||||||||||||||||
| Gross refining margin | $ | 7,429.9 | $ | 22.00 | $ | 3,087.7 | $ | 10.14 | $ | 496.8 | $ | 1.86 | |||||||||||||||||
Special Items: (3) | |||||||||||||||||||||||||||||
| Add: Non-cash LCM inventory adjustment | — | — | (669.6) | (2.20) | 268.0 | 1.01 | |||||||||||||||||||||||
| Add: LIFO inventory decrement | — | — | — | — | 83.0 | 0.31 | |||||||||||||||||||||||
| 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 | |||||||||||||||||
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See Notes to Non-GAAP Financial Measures.
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EBITDA, EBITDA Excluding Special Items and Adjusted EBITDA
Our management uses EBITDA (earnings before interest, income taxes, depreciation and amortization), 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, changes in the Tax Receivable Agreement liability due to factors out of PBF Energy’s control such as changes in tax rates, loss (gain) on extinguishment of debt, change in the fair value of contingent 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.
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The following tables reconcile net income (loss) as reflected in PBF Energy’s results of operations to EBITDA, EBITDA excluding special items and Adjusted EBITDA for the periods presented (in millions):
| Year Ended December 31, | |||||||||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||||||||
| Reconciliation of net income (loss) to EBITDA and EBITDA excluding special items: | |||||||||||||||||||||||
| Net income (loss) | $ | 2,972.8 | $ | 315.5 | $ | (1,333.3) | |||||||||||||||||
| Add: Depreciation and amortization expense | 511.1 | 466.8 | 563.0 | ||||||||||||||||||||
| Add: Interest expense, net | 246.0 | 317.5 | 258.2 | ||||||||||||||||||||
| Add: Income tax expense | 584.8 | 12.1 | 2.1 | ||||||||||||||||||||
| EBITDA | $ | 4,314.7 | $ | 1,111.9 | $ | (510.0) | |||||||||||||||||
Special Items: (3) | |||||||||||||||||||||||
| Add: Non-cash LCM inventory adjustment | — | (669.6) | 268.0 | ||||||||||||||||||||
| Add: Change in fair value of contingent consideration, net | 48.3 | 32.4 | (93.7) | ||||||||||||||||||||
| Add: Gain on sale of hydrogen plants | — | — | (471.1) | ||||||||||||||||||||
| Add: Gain on land sales | — | (2.8) | (8.1) | ||||||||||||||||||||
| Add: Impairment expense | — | — | 98.8 | ||||||||||||||||||||
| 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 | ||||||||||||||||||||
| Add: Change in Tax Receivable Agreement liability | 290.3 | 48.3 | (373.5) | ||||||||||||||||||||
| EBITDA excluding special items | $ | 4,719.4 | $ | 440.3 | $ | (941.9) | |||||||||||||||||
| Reconciliation of EBITDA to Adjusted EBITDA: | |||||||||||||||||||||||
| EBITDA | $ | 4,314.7 | $ | 1,111.9 | $ | (510.0) | |||||||||||||||||
| Add: Stock based compensation | 54.3 | 35.6 | 34.2 | ||||||||||||||||||||
| Add: Change in fair value of catalyst obligations | 2.0 | (8.5) | 11.8 | ||||||||||||||||||||
Add: Non-cash LCM inventory adjustment (3) | — | (669.6) | 268.0 | ||||||||||||||||||||
Add: Change in fair value of contingent consideration, net (3) | 48.3 | 32.4 | (93.7) | ||||||||||||||||||||
Add: Gain on sale of hydrogen plants (3) | — | — | (471.1) | ||||||||||||||||||||
Add: Gain on land sales (3) | — | (2.8) | (8.1) | ||||||||||||||||||||
Add: Impairment expense (3) | — | — | 98.8 | ||||||||||||||||||||
Add: LIFO inventory decrement (3) | — | — | 83.0 | ||||||||||||||||||||
Add: Severance and reconfiguration costs (3) | — | — | 30.0 | ||||||||||||||||||||
Add: Early railcar return expense (3) | — | — | 12.5 | ||||||||||||||||||||
Add: Loss (gain) on extinguishment of debt (3) | 66.1 | (79.9) | 22.2 | ||||||||||||||||||||
Add: Change in Tax Receivable Agreement liability (3) | 290.3 | 48.3 | (373.5) | ||||||||||||||||||||
| Adjusted EBITDA | $ | 4,775.7 | $ | 467.4 | $ | (895.9) | |||||||||||||||||
——————————
See Notes to Non-GAAP Financial Measures.
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Net Debt to Capitalization Ratio and Net Debt to Capitalization Ratio Excluding Special Items
The total debt to capitalization ratio is calculated by dividing total debt by the sum of total debt and total equity. This ratio is a measurement that management believes is useful to investors in analyzing our leverage. Net debt and the net debt to capitalization ratio are Non-GAAP measures. Net debt is calculated by subtracting cash and cash equivalents from total debt. We believe these measurements are also useful to investors since we have the ability to and may decide to use a portion of our cash and cash equivalents to retire or pay down our debt. Additionally, we have also presented the total debt to capitalization and net debt to capitalization ratios excluding the cumulative effects of special items on equity.
| December 31, | December 31, | ||||||||||||||||||||||
| 2022 | 2021 | ||||||||||||||||||||||
| Balance Sheet Data: | |||||||||||||||||||||||
| Cash and cash equivalents | $ | 2,203.6 | $ | 1,341.5 | |||||||||||||||||||
| Inventories | 2,763.6 | 2,505.1 | |||||||||||||||||||||
| Total assets | 13,549.1 | 11,641.4 | |||||||||||||||||||||
| Total debt | 1,959.1 | 4,295.8 | |||||||||||||||||||||
| Total equity | 5,056.0 | 2,532.8 | |||||||||||||||||||||
Total equity excluding special items (6) | $ | 4,660.5 | $ | 2,071.3 | |||||||||||||||||||
| Total debt to capitalization ratio | 28 | % | 63 | % | |||||||||||||||||||
Total debt to capitalization ratio, excluding special items (6) | 30 | % | 67 | % | |||||||||||||||||||
| Net debt to capitalization ratio* | (5) | % | 54 | % | |||||||||||||||||||
Net debt to capitalization ratio, excluding special items* (6) | (6) | % | 59 | % | |||||||||||||||||||
| * Negative ratio exists at 12/31/2022 as cash is in excess of debt. | |||||||||||||||||||||||
——————————
See Notes to Non-GAAP Financial Measures.
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Notes to Non-GAAP Financial Measures
The following notes are applicable to the Non-GAAP Financial Measures above:
(1)Represents the elimination of the noncontrolling interest associated with the ownership by the members of PBF LLC other than PBF Energy, as if such members had fully exchanged their PBF LLC Series A Units for shares of PBF Energy Class A common stock.
(2) Represents an adjustment to reflect PBF Energy’s annualized statutory corporate tax rate of approximately 25.9% for 2022 and 2021, and 26.6% for 2020, applied to the net income (loss) attributable to noncontrolling interest for all periods presented. The adjustment assumes the full exchange of existing PBF LLC Series A Units as described in (1) above.
(3) Special items:
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 included in the Refining segment’s 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 | |||||||||||||||
| January 1, | $ | — | $ | 669.6 | $ | 401.6 | |||||||||||
| 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 | |||||||||||||||
| Net LCM inventory adjustment benefit (charge) in income (loss) from operations | $ | — | $ | 669.6 | $ | (268.0) | |||||||||||
| Net LCM inventory adjustment benefit (charge) in net income (loss) | — | 496.2 | (196.7) | ||||||||||||||
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Change in Fair Value of Contingent Consideration, net - During the year ended December 31, 2022, 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, offset by the recognition of contingent assets associated with the acquisition. These changes resulted in decreases to income from operations and net income by $48.3 million and $35.8 million, respectively. During the year ended December 31, 2021, we recorded a change in fair value of the contingent consideration related to both the Martinez Contingent Consideration and the PBFX Contingent Consideration, which decreased income from operations and net income by $32.4 million and $24.0 million, respectively. During the year ended December 31, 2020 we recorded a change in fair value of the contingent consideration related to both the Martinez Contingent Consideration and the PBFX Contingent Consideration, which increased income from operations and net income by $93.7 million and $68.8 million, respectively.
Gain on Sale of Hydrogen Plants - During the year ended December 31, 2020, we recorded a gain on the sale of five hydrogen plants. The gain increased income from operations and net income by $471.1 million and $345.8 million, respectively. There were no such gains in the years ended December 31, 2022 and December 31, 2021.
Gain on Land Sales - During the year ended December 31, 2021, we recorded a gain on sale of PBFXreal-property at the East Coast Terminals, which increased income from operations and net income by $2.8 million and $2.1 million, respectively. During the years ended December 31, 2020, we recorded a gain on sale of one separate parcels 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 and $5.9 million, respectively, during the year ended December 31, 2020. There were no such gains in the year ended December 31, 2022.
Impairment Expense - During the year ended December 31, 2020, we recorded an impairment charge which decreased income from operations and net income by $98.8 million and $72.5 million, respectively, resulting from the write-down of certain assets as a result of the East Coast Refining Reconfiguration, project abandonments and the write-down of certain PBFX long-lived assets. 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 pre-tax charge to cost of products and other related to a LIFO inventory layer decrement. The majority of the decrement related to our East Coast 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 and $60.9 million, respectively, 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 and $41.3 million, respectively. 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 and $18.1 million, respectively. 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 and $3.9 million, respectively. There were no such costs in the years ended December 31, 2022 and December 31, 2021.
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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 and $9.2 million, respectively. 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 pre-tax net loss on extinguishment of debt which decreased income before income taxes and net income by $66.1 million and $49.0 million, respectively, 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 pre-tax gain on extinguishment of debt related to the repurchase of a portion of the 2028 Senior Notes and the 2025 Senior Notes, which increased income before income taxes and net income by $79.9 million and $59.2 million, respectively. During the year ended December 31, 2020, we recorded pre-tax debt extinguishment costs related to the redemption of the 2023 Senior Notes which decreased income before income taxes and net income by $22.2 million and $16.3 million, respectively.
Change in Tax Receivable Agreement liability - During the year ended December 31, 2022, we recorded a change in the Tax Receivable Agreement liability that decreased income before income taxes and net income by $290.3 million and $215.1 million, respectively. During the year ended December 31, 2021, PBF Energy recorded a change in the Tax Receivable Agreement liability that decreased income before income taxes and net income by $48.3 million and $35.8 million, respectively. During the year ended December 31, 2020, PBF Energy recorded a change in the Tax Receivable Agreement liability that increased income before taxes and net income by $373.5 million and $274.1 million, respectively. The changes in the Tax Receivable Agreement liability reflect charges or benefits attributable to changes in PBF Energy’s obligation under the Tax Receivable Agreement due to factors out of our control such as changes in tax rates, as well as periodic adjustments to our liability based, in part, on an updated estimate of the amounts that we expect to pay, using assumptions consistent with those used in our concurrent estimate of the deferred tax asset valuation allowance.
Recomputed Income Tax on Special Items - The income tax impact on these special items, other than the net tax expense special item discussed below, is calculated using the tax rates shown in (2) above.
Net Tax (Benefit) Expense on Remeasurement of Deferred Tax Assets - During the year ended December 31, 2022, we recorded a decrease to our deferred tax valuation allowance of $308.5 million (reducing our deferred tax valuation allowance to zero), in accordance with ASC 740, of which $233.8 million related to a tax benefit with respect to the remeasurement of deferred tax assets and the balance related to our net changes in the Tax Receivable Agreement liability. During the year ended December 31, 2021, we recorded a deferred tax valuation allowance of $308.5 million in accordance with ASC 740(a decrease of$49.9 million when compared to December 31, 2020, which includes a tax benefit of approximately $12.5 million related to our net change in the Tax Receivable Agreement liability and a net tax benefit of $37.4 million related primarily to the remeasurement of deferred tax assets). During the year ended December 31, 2020, we recorded a deferred tax valuation allowance of $358.4 million. This amount includes tax expense of approximately $99.3 million related to our net change in the Tax Receivable Agreement liability or a net tax expense of $259.1 million related primarily to the remeasurement of deferred tax assets.
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(4) Represents an adjustment to weighted-average diluted shares outstanding to assume the full exchange of existing PBF LLC Series A Units as described in (1) above.
(5) Represents weighted-average diluted shares outstanding assuming the conversion of all common stock equivalents, including options and warrants for PBF LLC Series A Units and performance share units and options for shares of PBF Energy Class A common stock as calculated under the treasury stock method (to the extent the impact of such exchange would not be anti-dilutive) for the years ended December 31, 2022, 2021 and 2020, respectively. Common stock equivalents exclude the effects of performance share units and options and warrants to purchase 3,877,035, 12,568,275 and 14,446,894 shares of PBF Energy Class A common stock and PBF LLC Series A Units because they are anti-dilutive for the years ended December 31, 2022, 2021 and 2020, respectively. For periods showing a net loss, all common stock equivalents and unvested restricted stock are considered anti-dilutive.
(6) Total Equity excluding special items is calculated in the table below:
| December 31, | December 31, | |||||||||||||||||||
| 2022 | 2021 | |||||||||||||||||||
| (in millions) | ||||||||||||||||||||
| Total equity | $ | 5,056.0 | $ | 2,532.8 | ||||||||||||||||
| Special Items (Note 4) | ||||||||||||||||||||
| Add: Change in fair value of contingent consideration, net | (13.0) | (61.3) | ||||||||||||||||||
| Add: Gain on sale of hydrogen plants | (471.1) | (471.1) | ||||||||||||||||||
| Add: Gain on land sales | (87.8) | (87.8) | ||||||||||||||||||
| Add: Impairment expense | 98.8 | 98.8 | ||||||||||||||||||
| Add: LIFO inventory decrement | 83.0 | 83.0 | ||||||||||||||||||
| Add: Turnaround acceleration costs | 56.2 | 56.2 | ||||||||||||||||||
| Add: Severance and reconfiguration costs | 30.0 | 30.0 | ||||||||||||||||||
| Add: Early railcar return expense | 64.8 | 64.8 | ||||||||||||||||||
| Add: Loss (gain) on extinguishment of debt | 33.9 | (32.2) | ||||||||||||||||||
| Add: Change in Tax Receivable Agreement liability | (325.3) | (615.6) | ||||||||||||||||||
| Less: Recomputed income tax on special items | 126.9 | 231.8 | ||||||||||||||||||
| Add: Net tax (benefit) expense on remeasurement of deferred tax assets | (12.1) | 221.7 | ||||||||||||||||||
| Add: Net tax expense on Tax Cuts and Jobs Act related special items | 20.2 | 20.2 | ||||||||||||||||||
| Net impact of special items to equity | (395.5) | (461.5) | ||||||||||||||||||
| Total equity excluding special items | $ | 4,660.5 | $ | 2,071.3 | ||||||||||||||||
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Liquidity and Capital Resources
Overview
Our primary sources of liquidity are our cash flows from operations, cash and cash equivalents and borrowing availability under our credit facilities, as described below. We believe that our cash flows from operations and available capital resources will be sufficient to meet our and our subsidiaries’ capital expenditures, working capital needs, dividend payments, debt service and share repurchase program requirements, as well as PBF Energy’s obligations under the Tax Receivable Agreement, for the next twelve months. However, our ability to generate sufficient cash flow from operations depends, in part, on petroleum oil market pricing and general economic, political and other factors beyond our control. As of December 31, 2022, 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 $4,772.0 million for the year ended December 31, 2022 compared to net cash provided by operating activities of $477.3 million for the year ended December 31, 2021. Our operating cash flows for the year ended December 31, 2022 included our net income of $2,972.8 million, and net changes in operating assets and liabilities reflecting cash proceeds of $341.0 million, primarily driven by timing of payments for accrued expense. Change in accrued expenses is due primarily to an increase in renewable energy and emissions obligations, as a result of an increase in our unfunded RINs obligation as of December 31, 2022. Our overall increase in cash provided by operating activities also included depreciation and amortization of $533.9 million, deferred income taxes of $420.2 million, change in the Tax Receivable Agreement liability of $290.3 million, net loss on extinguishment of debt primarily related to the redemption of our 2025 Senior Secured Notes of $66.1 million, stock-based compensation of $54.3 million, net change in the fair value of contingent consideration of $48.3 million, pension and other post-retirement benefit costs of $47.6 million, change in the fair value of our catalyst obligations of $2.0 million, and loss on sale of assets of $0.9 million, partially offset by net non-cash charges related to the change in the fair value of our inventory repurchase obligations of $5.4 million.
Our operating cash flows for the year ended December 31, 2021 included our net income of $315.5 million, depreciation and amortization of $483.8 million, net changes in operating assets and liabilities reflecting cash proceeds of $268.6 million primarily driven by accrued expenses due 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, pension and other post-retirement benefit costs of $50.8 million, change in the Tax Receivable Agreement liability of $48.3 million, stock-based compensation of $35.6 million, change in the fair value of contingent consideration of $32.4 million, and deferred income taxes of $11.7 million, partially offset by a net non-cash benefit of $669.6 million related to an LCM inventory adjustment, gain on extinguishment of debt related to the repurchase of a portion of our 2028 Senior Notes and 2025 Senior Notes of $79.9 million, changes in the fair value of our catalyst obligations of $8.5 million, net non-cash charges related to the change in the fair value of our inventory repurchase obligations of $8.4 million, and gain on sale of assets of $3.0 million.
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Net cash provided by operating activities was $477.3 million for the year ended December 31, 2021 compared to net cash used in operating activities of $631.6 million for the year ended December 31, 2020. Our operating cash flows for the year ended December 31, 2020 included our net loss of $1,333.3 million, gain on sale of assets of $477.8 million mainly related to the sale of the hydrogen plants and the sale of land at our Torrance refinery, change in the Tax Receivable Agreement liability of $373.5 million, net non-cash charges relating to the change in the fair value of our inventory repurchase obligations of $12.6 million and change in the fair value of the contingent consideration of $93.7 million, partially offset by depreciation and amortization of $581.1 million, net non-cash charge of $268.0 million related to an LCM inventory adjustment, impairment expense of $98.8 million, pension and other post-retirement benefits costs of $55.7 million, stock-based compensation of $34.2 million, debt extinguishment costs related to the early redemption of our 2023 Senior Notes of $22.2 million, change in the fair value of our catalyst obligations of $11.8 million and deferred income taxes of $1.6 million. In addition, net changes in operating assets and liabilities reflected cash inflows of $585.9 million driven by the timing of inventory purchases, payments for accrued expenses and accounts payable and collections of accounts receivable.
Cash Flows from Investing Activities
Net cash used in investing activities was $1,010.9 million for the year ended December 31, 2022 compared to $388.5 million for the year ended December 31, 2021. The net cash flows used in investing activities for the year ended December 31, 2022 was comprised of cash outflows of capital expenditures totaling $633.3 million, expenditures for refinery turnarounds of $311.6 million, and expenditures for other assets of $66.0 million. Net cash used in investing activities for the year ended December 31, 2021 was comprised of cash outflows of capital expenditures totaling $249.1 million, expenditures for refinery turnarounds of $117.7 million, and expenditures for other assets of $28.9 million, partially offset by proceeds from the sale of assets of $7.2 million.
Net cash used in investing activities was $388.5 million for the year ended December 31, 2021 compared to $1,026.5 million for the year ended December 31, 2020. Net cash used in investing activities for the year ended December 31, 2020 was comprised of cash outflows of $1,176.2 million used to fund the Martinez Acquisition, capital expenditures totaling $196.2 million, expenditures for refinery turnarounds of $188.1 million and expenditures for other assets of $9.1 million, partially offset by proceeds from sale of assets of $543.1 million.
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Cash Flows from Financing Activities
Net cash used in financing activities was $2,899.0 million for the year ended December 31, 2022 compared to net cash used in financing activities of $356.8 million for the year ended December 31, 2021. For the year ended December 31, 2022, net cash used in financing activities consisted of the redemption of our 2025 Senior Secured Notes of $1,307.4 million, net repayments on the Revolving Credit Facility of $900.0 million, the purchase of PBFX publicly held shares in connection with the Merger Transaction of $303.7 million, the share repurchase of PBF Energy’s Class A common stock of $156.4 million, net repayments on the PBFX Revolving Credit Facility of $100.0 million, dividends and distributions of $73.6 million, settlements of precious metal catalyst obligations of $56.2 million, deferred financing costs and other costs of $31.3 million, $25.9 million related to the repurchase of the principal amount outstanding of the 2028 Senior Notes and the 2025 Senior Notes, excluding accrued interest, payments on finance leases of $11.3 million, and PBFX Contingent Consideration payments of $3.1 million, partially offset by transactions made in connection with stock-based compensation plans of $67.8 million, and proceeds from insurance premium financing of $2.1 million. For the year ended December 31, 2021, net cash used in financing activities consisted of $146.8 million related to the repurchase of the principal amount outstanding of the 2028 Senior Notes and the 2025 Senior Notes, excluding accrued interest, net repayments on the PBFX Revolving Credit Facility of $100.0 million, distributions and dividends of $39.7 million, net settlements of precious metal catalyst obligations of $31.7 million, payments on finance leases of $17.8 million, PBFX Contingent Consideration payments of $12.2 million, principal amortization payments on the PBF Rail Term Loan of $7.4 million, and deferred financing costs and other of $1.2 million.
Net cash used in financing activities was $356.8 million for the year ended December 31, 2021 compared to net cash provided by financing activities of $2,452.7 million for the year ended December 31, 2020. For the year ended December 31, 2020, net cash provided by financing activities consisted of cash proceeds of $1,228.7 million from the issuance of the 2025 Senior Secured Notes net of related issuance costs, cash proceeds of $469.9 million from the issuance of the 2028 Senior Notes net of cash paid to redeem the 2023 Senior Notes and related issuance costs, net borrowings under our Revolving Credit Facility of $900.0 million, and proceeds from catalyst financing arrangements of $51.9 million, partially offset by net repayments on the PBFX Revolving Credit Facility of $83.0 million, net settlements of precious metal catalyst obligations of $8.8 million, distributions and dividends of $82.2 million, principal amortization payments of the PBF Rail Term Loan of $7.2 million, payments on finance leases of $12.4 million, taxes paid for net settlement of equity-based compensation of $2.1 million, repurchases of our common stock in connection with tax withholding obligations upon the vesting of certain restricted stock awards of $1.6 million and deferred financing costs and other of $0.5 million.
The cash flow activity of PBF LLC for the years ended December 31, 2022, 2021 and 2020 is materially consistent with that of PBF Energy discussed above, other than changes in deferred income taxes and certain working capital items, which are different from PBF Energy due to certain tax related items not applicable to PBF LLC. Additionally, PBF LLC reflects net borrowings of $1,070.5 million for the years ended December 31, 2022 and net repayments of $1.1 million and $0.1 million for 2021 and 2020, respectively, related to an affiliate loan with PBF Energy, included in cash flows from financing activities, which eliminates in consolidation at PBF Energy.
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Capitalization
Our capital structure was comprised of the following as of December 31, 2022 (in millions):
| December 31, 2022 | |||||
Debt: (1) | |||||
| PBF LLC debt | |||||
| Affiliate note payable | $ | 1,445.7 | |||
| PBF Holding debt | |||||
| 2028 Senior Notes | 801.6 | ||||
| 2025 Senior Notes | 664.5 | ||||
| Revolving Credit Facility | — | ||||
| Catalyst financing arrangements | 4.0 | ||||
| PBF Holding debt | 1,470.1 | ||||
| PBFX debt | |||||
PBFX 2023 Senior Notes (2) | 525.0 | ||||
| PBFX Revolving Credit Facility | — | ||||
| PBFX debt | 525.0 | ||||
| Unamortized deferred financing costs | (36.2) | ||||
| Unamortized premium | 0.2 | ||||
| Total PBF LLC debt, net of unamortized deferred financing costs and premium | 3,404.8 | ||||
| Less: Affiliate note payable | (1,445.7) | ||||
Total PBF Energy debt, net of unamortized deferred financing costs and premium(3) | $ | 1,959.1 | |||
| Total PBF Energy Equity | $ | 5,056.0 | |||
Total PBF Energy Capitalization (4) | $ | 7,015.1 | |||
(1) Refer to “Note 8 - Credit Facilities and Debt” and “Note 9 - Affiliate Note Payable - PBF LLC” of our Notes to Consolidated Financial Statements for further disclosure related to debt.
(2) The PBFX 2023 Senior Notes were redeemed on February 2, 2023.
(3) Excludes the PBF LLC affiliate note payable that is eliminated in the PBF Energy consolidated financial statements.
(4) Total Capitalization refers to the sum of debt, excluding intercompany debt, plus total equity.
2022 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.
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In addition, we made a number of open market repurchases of our 2028 Senior Notes and 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 this extinguishment of debt during the year ended December 31, 2022.
On May 25, 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.
During 2022, we also settled certain of our precious metals financing arrangements, resulting in a reduction of debt of approximately $56.2 million.
Revolving Credit Facilities Overview
One of our primary sources of liquidity are borrowings available under our revolving credit facilities. As of December 31, 2022, PBF Energy had $2,203.6 million of cash and cash equivalents and no outstanding balances under the Revolving Credit Facility or the PBFX Revolving Credit Facility. PBF LLC cash and cash equivalents totaled $2,201.8 million as of December 31, 2022.
We had available capacity under revolving credit facilities as follows at December 31, 2022 (in millions):
| 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 | |||||||||||||||||||||||
| PBFX Revolving Credit Facility | 500.0 | — | 3.5 | 496.5 | July 2023 | |||||||||||||||||||||||||||
| Total Credit Facilities | $ | 4,800.0 | $ | — | $ | 579.6 | $ | 4,796.5 | ||||||||||||||||||||||||
(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 billion.
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Additional Information on Indebtedness
Our debt, including our revolving credit facilities 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 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, our operational liquidity was more than $4.9 billion (more than $2.4 billion as of December 31, 2021), which consists of $2.1 billion of cash, excluding cash held at PBFX, and more than $2.8 billion of borrowing availability under our Revolving Credit Facility, which includes our cash on hand. In addition, as of December 31, 2022, PBFX had approximately $530.4 million of liquidity ($430.4 million as of December 31, 2021), including approximately $47.8 million in cash, and access to approximately $496.5 million under the PBFX Revolving Credit Facility.
We are actively monitoring the ongoing volatility in the global oil markets and we continue to adjust our operational plans to the evolving market conditions. 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 may pay future dividends, make new investments, repurchase our outstanding debt or stock or incur new liens.
Pursuant to the terms of the Merger Agreement, which closed on November 30, 2022, each PBFX Public Common Unit was converted into the right to receive: (i) the Merger Consideration and (ii) 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 Merger Transaction cash consideration was funded with cash on hand.
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Share Repurchases
On December 12, 2022, our Board of Directors authorized the repurchase of up to $500.0 million of PBF Energy's Class A common stock. The Repurchase Program will expire in December 2024. As of February 16, 2023, we have purchased approximately 5,045,478 shares of PBF Energy's Class A common stock under the Repurchase Program for $188.8 million through open market transactions. We may make additional share repurchases in the future but we are not obligated to purchase any shares under the Repurchase Program, and repurchases could be suspended or discontinued at any time without prior notice.
Working Capital
PBF Energy’s working capital at December 31, 2022 was approximately $1,345.6 million, consisting of $6,546.3 million in total current assets and $5,200.7 million in total current liabilities. PBF Energy’s working capital at December 31, 2021 was $1,439.5 million, consisting of $5,199.2 million in total current assets and $3,759.7 million in total current liabilities. PBF LLC’s working capital at December 31, 2022 was approximately $1,297.5 million, consisting of $6,544.5 million in total current assets and $5,247.0 million in total current liabilities. PBF LLC’s working capital at December 31, 2021 was $1,385.6 million, consisting of $5,197.5 million in total current assets and $3,811.9 million in total current liabilities.
Crude and Feedstock Supply Agreements
Certain of our purchases of crude oil under our agreements with foreign national oil companies require that we post letters of credit, if open terms are exceeded, and arrange for shipment. We pay for the crude when invoiced, at which time any applicable letters of credit are lifted. We have a contract with Saudi Aramco pursuant to which we have been purchasing up to approximately 100,000 bpd of crude oil from Saudi Aramco that is processed at our Paulsboro refinery. In connection with the acquisition of the Chalmette refinery we entered into a contract with PDVSA for the supply of 40,000 to 60,000 bpd of crude oil that can be processed at any of our 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, the U.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, we entered into a crude supply agreement with ExxonMobil for approximately 60,000 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 agreements for our Delaware City and Toledo refineries.
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 25, 2021, PBF Holding and the PBF Entities, entered into the Third Inventory Intermediation Agreement with J. Aron, pursuant to which the terms of the previous inventory intermediation agreements were amended and restated in their entirety, including, among other things, pricing and an extension of terms. The Third Inventory Intermediation Agreement extends the term to December 31, 2024, which term may be further extended by mutual consent of the parties to December 31, 2025. If not extended or replaced, at expiration, we will be required to repurchase the inventories outstanding under the Third Inventory Intermediation Agreement at that time. On May 25, 2022, the 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, 2022 to the Revolving Credit Agreement. We intend to either extend or replace the Third Inventory Intermediation Agreement prior to its expiration.
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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 $1,010.9 million for the year ended December 31, 2022 and was primarily comprised of annual maintenance and turnaround costs at our Delaware City, Chalmette, Torrance and Martinez refineries in addition to spending related to our project for a renewable fuels production facility co-located at our Chalmette refinery (the “Renewable Diesel Project”). Capital spending also included costs associated with safety related enhancements and facility improvements at our refineries and logistics assets. Excluding capital expenditures related to our Renewable Diesel Project, we currently expect to spend an aggregate of approximately $700.0 million to $750.0 million during 2023 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 that are expected to be paid within the next year and thereafter (in millions). The table below does not include any intercompany contractual obligations with PBFX as our related party transactions are eliminated upon consolidation of our financial statements.
| Payments Due by Period | ||||||||||||||||||||
| Short-Term | Long-Term | Total | ||||||||||||||||||
| PBF Energy: | ||||||||||||||||||||
Credit facilities and debt (a) | $ | 529.0 | $ | 1,466.1 | $ | 1,995.1 | ||||||||||||||
| Interest payments on credit facilities and debt | 115.3 | 295.4 | 410.7 | |||||||||||||||||
Leases and other rental-related commitments (b) | 278.0 | 1,971.1 | 2,249.1 | |||||||||||||||||
Purchase obligations (c) | 9,006.3 | 8,300.5 | 17,306.8 | |||||||||||||||||
| Construction obligations | 166.0 | — | 166.0 | |||||||||||||||||
Environmental obligations (d) | 14.7 | 150.3 | 165.0 | |||||||||||||||||
Pension and post-retirement obligations (e) | 26.5 | 300.4 | 326.9 | |||||||||||||||||
Tax Receivable Agreement obligation (f) | — | 338.6 | 338.6 | |||||||||||||||||
Martinez Contingent Consideration (g) | 100.0 | 73.7 | 173.7 | |||||||||||||||||
| Total material cash requirements for PBF Energy | $ | 10,235.8 | $ | 12,896.1 | $ | 23,131.9 | ||||||||||||||
| Adjustments for PBF LLC: | ||||||||||||||||||||
Less: Tax Receivable Agreement obligation (f) | — | (338.6) | (338.6) | |||||||||||||||||
Add: Affiliate Note Payable (h) | — | 1,445.7 | 1,445.7 | |||||||||||||||||
| Total material cash requirements for PBF LLC | $ | 10,235.8 | $ | 14,003.2 | $ | 24,239.0 | ||||||||||||||
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(a) Credit facilities and debt
Credit facilities and debt represent (i) the repayment of indebtedness incurred in connection with the 2025 Senior Notes, 2028 Senior Notes and PBFX 2023 Senior Notes; and (ii) the repayment of our catalyst financing obligations on their maturity dates. With the exception of our PBFX 2023 Senior Notes, which were redeemed on February 2, 2023, and our catalyst financing obligations, we have no debt maturing before 2024.
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 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 13 - 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.
(c) Purchase obligations
Purchase obligations include commitments to purchase crude oil from certain counterparties under supply agreements, contracts for the transportation of crude oil and supply of hydrogen, nitrogen, oxygen, chemicals, steam, or natural gas to certain of our refineries, contracts for the treatment of wastewater, contracts for pipeline capacity, and forward purchase commitments to acquire AB 32, RINs or LCFS credits from third parties. 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) Environmental obligations
In connection with certain of our refinery and logistics acquisitions, we have assumed certain environmental remediation obligations to address matters that were outstanding at the time of such acquisitions. In addition, in connection with most of these acquisitions, we have purchased environmental insurance policies to insure against unknown environmental liabilities at each site. The obligations in the table above reflect our undiscounted best estimate in cost and tenure to remediate our outstanding obligations and are further discussed in “Note 12 - Commitments and Contingencies” of our Notes to Consolidated Financial Statements.
(e) Pension and post-retirement obligations
Pension and post-retirement obligations include only those amounts we expect to pay out in benefit payments and are further explained in “Note 17 - Employee Benefit Plans” of our Notes to Consolidated Financial Statements.
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(f) Tax Receivable Agreement obligation
The table reflects PBF Energy’s estimated timing of payments under the Tax Receivable Agreement, assuming that we earn sufficient taxable income to realize all tax benefits that are subject to the Tax Receivable Agreement as of December 31, 2022. Refer to “Note 12 - Commitments and Contingencies” and “Note 19 - Income Taxes” of our Notes to the Consolidated Financial statements for further discussion of the Tax Receivable Agreement.
(g) Martinez Contingent Consideration
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.
(h) Affiliate Note Payable
As described in “Note 9 - Affiliate Note Payable - PBF LLC” of our Notes to Consolidated Financial Statements, as of December 31, 2022, PBF LLC had an outstanding note payable with PBF Energy for an aggregate principal amount of $1,445.7 million. The note has an interest rate of 2.5% and matures in April 2030, but may be prepaid in whole or in part at any time, at the option of PBF LLC without penalty or premium. This affiliate note payable is a cash obligation of PBF LLC only and eliminates in consolidation for PBF Energy.
Tax Distributions
PBF LLC is required to make periodic tax distributions to the members of PBF LLC, including PBF Energy, pro rata in accordance with their respective percentage interests for such period (as determined under the amended and restated limited liability company agreement of PBF LLC), subject to available cash and applicable law and contractual restrictions (including pursuant to our debt instruments) and based on certain assumptions. Generally, these tax distributions will be an amount equal to our estimate of the taxable income of PBF LLC for the year multiplied by an assumed tax rate equal to the highest effective marginal combined U.S. federal, state and local income tax rate prescribed for an individual or corporate resident in New York, New York (taking into account the nondeductibility of certain expenses). If, with respect to any given calendar year, the aggregate periodic tax distributions were less than the actual taxable income of PBF LLC multiplied by the assumed tax rate, PBF LLC will make a “true up” tax distribution, no later than March 15 of the following year, equal to such difference, subject to the available cash and borrowings of PBF LLC. As these distributions are conditional they have been excluded from the table above.
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Critical Accounting Policies
The following summary provides further information about our critical accounting policies that involve critical accounting estimates and should be read in conjunction with “Note 2 - Summary of Significant Accounting Policies” of our Notes to Consolidated Financial Statements, “Item 8. Financial Statements and Supplementary Data.”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, 20192022 and 2018, market values had fallen below historicalDecember 31, 2021 the replacement value of inventories exceeded the LIFO inventory costs and, as a result, we recorded lower of cost or market inventory valuation reserves of $401.6 million and $651.8 million, respectively.carrying value. The lower of costLCM 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 lower of costLCM 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, we have had limited experience withprior 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
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.
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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 exception.exemption. All of these judgments, depending upon their timing and effect, can have a significant impact on earnings.
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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.
Income Taxes and Tax Receivable Agreement
As a result of the PBF Energy’s acquisition of PBF LLC Series A Units or exchanges of PBF LLC Series A Units for PBF Energy Class A common stock, it expects to benefit from amortization and other tax deductions reflecting the step up in tax basis in the acquired assets. Those deductions will be allocated to PBF Energy and will be taken into account in reporting its taxable income. As a result of a federal income tax election made by PBF LLC, applicable to a portion of PBF Energy’s acquisition of PBF LLC Series A Units, the income tax basis of the assets of PBF LLC, underlying a portion of the units PBF Energy acquired, has been adjusted based upon the amount that PBF Energy paid for that portion of its PBF LLC Series A Units. PBF Energy entered into the Tax Receivable Agreement (as defined in “Note 13 - Commitments and Contingencies” of the Notes to our Consolidated Financial Statements) which provides for the payment by PBF Energy equal to 85% of the amount of the benefits, if any, that it is deemed to realize as a result of (i) increases in tax basis and (ii) certain other tax benefits related to entering into the Tax Receivable Agreement, including tax benefits attributable to payments under the Tax Receivable Agreement. As a result of these transactions, PBF Energy’s tax basis in its share of PBF LLC’s assets will be higher than the book basis of these same assets. This resulted in a deferred tax asset of $278.1$191.4 million as of December 31, 2019, of which the majority is expected to be realized over 10 years as the tax basis of these assets are amortized.2022.
Deferred taxes are providedcalculated using a liability method, whereby deferred tax assets are recognized for deductible temporary differences and deferred tax liabilities are recognized for taxable temporary differences. Temporary differences represent the differences between the reported amounts of assets and liabilities and their tax bases. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and
liabilities are adjusted for the effect of changes in tax laws and rates on the date of enactment. We recognize tax benefits for uncertain tax positions only if it is more likely than not that the position is sustainable based on its technical merits. Interest and penalties on uncertain tax positions are included as a component of the provision for income taxes on the Consolidated Statements of Operations. As a result of the reductionmanagement’s assessment of the corporate federal tax rate to 21%available positive and negative evidence it was determined that the $308.5 million valuation allowance, as part of the TCJA, the liabilityDecember 31, 2021, associated with the Tax Receivable Agreement was reduced. Accordingly,deferred tax assets should be released because we believed that it had become more likely than not that the deferred tax assets associated withwould be realized. The amount of the payments madedeferred tax assets considered realizable, however, could be adjusted if estimates of future taxable income are reduced or expectedincreased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to be made related to the Tax Receivable Agreement liability were also reduced.subjective evidence such as our projections for future taxable income.
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Pursuant to the Tax Receivable Agreement PBF Energy entered into at the time of its initial public offering, it is required to pay the current and former PBF LLC Series A unitholders, who exchange their units for PBF Energy stock or whose units we purchase, approximately 85% of the cash savings in income taxes that PBF Energy is deemed to realize as a result of the increase in the tax basis of its interest in PBF LLC, including tax benefits attributable to payments made under the Tax Receivable Agreement. These payment obligations are of PBF Energy and not of PBF LLC or any of its subsidiaries. PBF Energy has recognized a liability for the Tax Receivable Agreement reflecting its estimate of the undiscounted amounts that it expects to pay under the agreement. PBF Energy’s estimate of the Tax Receivable Agreement liability is based, in part, on forecasts of future taxable income over the anticipated life of PBF Energy’s future business operations, assuming no material changes in the relevant tax law. The assumptions used in the forecasts are subject to substantial uncertainty about PBF Energy’s future business operations and the actual payments that it is required to make under the Tax Receivable Agreement could differ materially from its current estimates. PBF Energy must adjust the estimated Tax Receivable Agreement liability each time we purchase PBF LLC Series A Units or upon an exchange of PBF LLC Series A Units for PBF Energy Class A common stock. Such adjustments will be based on forecasts of future taxable income and PBF Energy’s future business operations at the time of such purchases or exchanges. Periodically, PBF Energy may adjust the liability based on an updated estimate of the amounts that it expects to pay, using assumptions consistent with those used in its concurrent estimate of the deferred tax asset valuation allowance. These periodic adjustments to the Tax Receivable Agreement liability, if any, are recorded in general and administrative expense and may result in adjustments to our income tax expense and deferred tax assets and liabilities.
Recent Accounting Pronouncements
Refer to “Note 2 - Summary of Significant Accounting Policies” of our Notes to Consolidated Financial Statements, for Recently Issued Accounting Pronouncements.
ITEM 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.
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At December 31, 20192022 and 2018,December 31, 2021, we had gross open commodity derivative contracts representing 11.330.1 million barrels and 7.442.1 million barrels, respectively, with an unrealized net gain of $0.2$13.9 million and $7.2unrealized net loss of $12.0 million, respectively. The open commodity derivative contracts as of December 31, 20192022 expire at various times during 2020.2023.
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 30.232.8 million barrels and 30.530.2 million barrels at December 31, 20192022 and December 31, 2018,2021, respectively. The average cost of our hydrocarbon inventories was approximately $79.63$80.04 and $78.78$78.29 per barrel on a LIFO basis at December 31, 20192022 and December 31, 2018, respectively, excluding2021, respectively. At December 31, 2022 and December 31, 2021, the net impactreplacement value of LCM inventory adjustments of approximately $401.6 million and $651.8 million, respectively.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 consume a total of between 6875 million and 7495 million MMBTUs of natural gas amongst our five refineries as of December 31, 2019.six refineries. Accordingly, a $1.00 per MMBTU change in natural gas prices would increase or decrease our natural gas costs by approximately $68.0$75.0 million to $74.0$95.0 million.
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 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 thisthe market risk relating to our obligations on our results of operations and cash flows, we may elect to purchase RINs or other environmental credits when the priceas part of these instruments is deemed favorable.our liability management strategy.
In addition, we are exposed to risks associated with complying with federal and state legislative and regulatory measures to address greenhouse 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. For example, AB32 in California requires the state to reduce its GHG emissions to 1990 levels by 2020. 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. We generallyFor certain of these contracts, we elect the normal purchase normal sale exception under ASC 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 $3.4$4.3 billion. Borrowings under the Revolving Credit Facility bear interest either at the Alternative Base Rate plus the Applicable Margin or at Adjusted LIBORthe Term SOFR Rate plus the Applicable Margin, all as defined in the Revolving Credit Agreement. At December 31, 2022, 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 $21.9$25.6 million annually.
The PBFX Revolving Credit Facility, with a maximum commitment of $500.0 million, bears interest either at the Alternative Base Rate plus the Applicable Margin or at Adjusted LIBOR plus the Applicable Margin, all as defined in the PBFX Revolving Credit Agreement. At December 31, 2022, PBFX 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 $4.3$3.7 million annually.
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We also have interest rate exposure in connection with our Third Inventory Intermediation AgreementsAgreement 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, 2019, 20182022 and 2017, no singleDecember 31, 2021, only one customer, Shell, accounted for 10% or more of our total sales.revenues (approximately 14% and 15%, 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.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
PBF Energy and PBF LLC conducted separate evaluations under the supervision and with the participation of each company’s management, including the principal executive officer and principal financial officer, of the effectiveness of the disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 as amended (the “Exchange Act”)) as of the end of the period covered by this report. Based upon these evaluations as required by Exchange Act Rule 13a-15(b), the principal executive officer and principal financial officer, in each case, concluded that the disclosure controls and procedures are effective.
Management’s Report on Internal Control over Financial Reporting - PBF Energy
PBF Energy’s management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Exchange Act. PBF Energy’s 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.
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Management assessed the effectiveness of PBF Energy’s internal control over financial reporting as of December 31, 2019,2022, 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, 2019,2022, PBF Energy’s internal control over financial reporting is effective.
Management’s Report on Internal Control over Financial Reporting - PBF LLC
PBF LLC’s management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Exchange Act. PBF LLC’s 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 PBF LLC’s internal control over financial reporting as of December 31, 2019,2022, 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, 2019,2022, PBF LLC’s internal control over financial reporting is effective.
Auditor Attestation Report
Our independent registered public accounting firm has issued an attestation report on the effectiveness of PBF Energy’s internal control over financial reporting, which is on page F-47 of this report.
Changes in Internal Control Over Financial Reporting
There has been no change in PBF Energy’s or PBF LLC’sour internal control over financial reporting during the quarter ended December 31, 20192022 that has materially affected, or is reasonably likely to materially affect PBF Energy’s or PBF LLC’s internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
Not applicable.
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PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required under this Item will be contained in our 20202023 Proxy Statement, incorporated herein by reference.
We have 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 on our website 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 the Company’s website.
See also Information About Our Executive Officers under “Item 1. Business” of this Annual Report on Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
The information required under this Item will be contained in our 20202023 Proxy Statement, incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information required by this Item, including Securities Authorized for Issuance Under Equity Compensation Plans, will be contained in our 20202023 Proxy Statement, incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required under this Item will be contained in our 20202023 Proxy Statement, incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
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PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) 1. Financial Statements. The consolidated financial statements of PBF Energy Inc., PBF Energy Company LLC and their 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 | |||||||||||||
| Amended and Restated Certificate of Incorporation of PBF Energy Inc. (incorporated by reference to Exhibit 3.1 filed with PBF Energy Inc.’s Amendment No. 4 to Registration Statement on Form S-1 (Registration No. 333-177933)). | ||||||||||||||
| Second Amended and Restated Bylaws of PBF Energy Inc. (incorporated by reference to Exhibit 3.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated February 15, 2017 (File No. 001-35764)). | ||||||||||||||
| 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 | ||||||||||||||
| Indenture dated | ||||||||||||||
| First Supplemental Indenture dated | ||||||||||||||
| Amended and Restated Registration Rights Agreement of PBF Energy Inc. dated as of December 12, 2012 (incorporated by reference to Exhibit 4.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated December 18, 2012 (File No. 001-35764)). | ||||||||||||||
| Description of Registrant’s | ||||||||||||||
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| 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)). | ||||||||||||||
| 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)). | ||||||||||||||
| 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)). | ||||||||||||||
| 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)). | ||||||||||||||
| PBF Energy Inc. Amended and Restated 2012 Equity Incentive Plan (incorporated by reference 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, 2018 (File No. 001-35764)). | ||||||||||||||
| 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)). | ||||||||||||||
| 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)). | ||||||||||||||
| 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)). | ||||||||||||||
| 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 | ||||||||||||||
| 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 | ||||||||||||||
| 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)). | ||||||||||||||
| Form of | ||||||||||||||
| Amended and Restated Restricted Stock Agreement for non-employee Directors under the PBF Energy Inc. 2017 Equity Incentive | ||||||||||||||
| 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). | ||||||||||||||
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| Form of PBF Energy Amended and Restated | ||||||||||||||
| 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)). | ||||||||||||||
| 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)). | ||||||||||||||
| 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)). | ||||||||||||||
| 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)). | ||||||||||||||
| First Amendment to the Third Amended and Restated Inventory Intermediation Agreement dated as of October 25, 2021, among J. Aron & Company LLC, PBF | ||||||||||||||
| Amended and Restated Guaranty of Collection, dated as of October 6, 2017 (incorporated by reference to Exhibit 10.1 of PBF Energy Inc.’s Current Report on Form 8-K (File No. 001-35764) filed on October 6, 2017). | ||||||||||||||
| Designation of Other Guaranteed Revolving Credit Obligations, dated as of December 12, 2014 with respect to the Amended and Restated Guaranty of Collection (incorporated by reference to Exhibit 10.8.2 filed with PBF Energy Inc.’s Quarterly Report on Form 10-Q dated | ||||||||||||||
| Joinder Agreement dated as of September 7, 2018, among DCR Storage and Loading LLC, Chalmette Logistics Company LLC, Toledo Rail Logistics Company LLC, Paulsboro Terminaling Company LLC and Wells Fargo Bank, National Association, as Administrative Agent (incorporated by reference to Exhibit 10.4 filed with PBF Logistics LP’s Quarterly Report on Form 10-Q dated October 31, 2018 (File No. 001-36446)). | ||||||||||||||
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| Joinder Agreement to the Credit Agreement dated as of February 1, 2020, among PBF Holding Company LLC, | ||||||||||||||
| Amended and Restated Limited Liability Company Agreement of PBF Energy Company LLC (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated December 18, 2012 (File No. 001-35764)). | ||||||||||||||
| Exchange Agreement, dated as of December 12, 2012 (incorporated by reference to Exhibit 10.3 filed with PBF Energy Inc.’s Current Report on Form 8-K dated December 18, 2012 (File No. 001-35764)). | ||||||||||||||
| Tax Receivable Agreement, dated as of December 12, 2012 (incorporated by reference to Exhibit 10.2 filed with PBF Energy Inc.’s Current Report on Form 8-K dated December 18, 2012 (File No. 001-35764)). | ||||||||||||||
| Restated Warrant and Purchase Agreement between PBF Energy Company LLC and the officers party thereto, as amended (incorporated by reference to Exhibit 10.17 filed with PBF Energy Inc.’s Amendment No. 4 to Registration Statement on Form S-1 (Registration No. 333-177933)). | ||||||||||||||
| Form of Indemnification Agreement between PBF Energy Inc. and each of the executive officers and directors of PBF Energy Inc. (incorporated by reference to Exhibit 10.5 filed with PBF Energy Inc.’s Current Report on Form 8-K dated December 18, 2012 (File No. 001-35764)). | ||||||||||||||
| 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)). | ||||||||||||||
| 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)). | ||||||||||||||
| Employment Agreement dated as of April 1, 2014 between PBF Investments LLC and Erik | ||||||||||||||
| 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)). | ||||||||||||||
| 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)). | ||||||||||||||
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| 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)). | ||||||||||||||
| 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)). | ||||||||||||||
| Subsidiaries of PBF Energy and PBF Energy Company | ||||||||||||||
| Consent of Deloitte & Touche | ||||||||||||||
| Consent of Deloitte & Touche | ||||||||||||||
| Power of Attorney (included on signature page). | ||||||||||||||
| Certification by Chief Executive Officer of PBF Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of | ||||||||||||||
| Certification by Chief Financial Officer of PBF Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of | ||||||||||||||
| Certification by Chief Executive Officer of PBF Energy Company LLC pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of | ||||||||||||||
| Certification by Chief Financial Officer of PBF Energy Company LLC pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of | ||||||||||||||
| Certification by Chief Executive Officer of PBF Energy Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of | ||||||||||||||
| Certification by Chief Financial Officer of PBF Energy Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of | ||||||||||||||
| Certification by Chief Executive Officer of PBF Energy Company LLC pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of | ||||||||||||||
| Certification by Chief Financial Officer of PBF Energy Company LLC pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of | ||||||||||||||
| 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. | |||||||||||||
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in exhibit 101). | |||||||||||||
——————————
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| * | Filed herewith. | ||||
| ** | |||||
| Indicates management compensatory plan or arrangement. | |||||
| † | Portions of the exhibits have been omitted because | ||||
| (1) | This exhibit should not be deemed to be “filed” for purposes of Section 18 of the Exchange Act. | ||||
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PBF ENERGY INC. AND PBF ENERGY COMPANY LLC
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
| PBF Energy Inc. | ||||||||
| PBF Energy Company LLC | ||||||||
F- 1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of PBF Energy Inc. and subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of PBF Energy Inc. and subsidiaries (the "Company") as of December 31, 20192022 and 2018,2021, 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, 2019,2022, 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, 20192022 and 2018,2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2022, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2019,2022, based on criteria established in Internal Control -— Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 20, 2020,16, 2023, expressed an unqualified opinion on the Company's internal control over financial reporting.
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 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. 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. 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 Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate 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 matters below, providing a separate opinion on the critical audit matters or on the accounts or disclosures to which they relate.
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 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 the carrying amount
F- 2
of an asset or an asset group may not be recoverable, will be sold or retired before its estimated useful 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 assumptions related to future throughput levels, future operating revenues, 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 carrying amount of long- lived assets. 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-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 judgement.
How the Critical Audit Matter was Addressed in the Audit
Our audit procedures related to impairment indicators for long-lived assets included the following, among others:
•We tested the effectiveness of controls over the identification of possible circumstances that may indicate that the carrying amounts of long-lived assets are no longer recoverable, including controls over management’s useful life, throughput levels, gross margin, operating expenses and future levels of capital expenditures assumptions.
•We compared management’s evaluation of potential impairment indicators to our independent expectation by:
◦We performed searches for adverse general market and asset-specific environmental conditions,
◦We inquired of Management about the impact of macro-economic events, the pace of decarbonization and the energy transition, and new environmental regulations on the Company’s forecasting of future cash flows, refining margins, future levels of capital expenditure and estimated useful lives,
◦We inspected minutes of the board of directors, the Company’s public statements, operating plans, and market reports to identify any evidence that may contradict management’s assumptions, and
◦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.
Critical Accounting Policy and Estimate – Release of Valuation Allowance Related to Deferred Tax Assets – refer to Notes 2 and 19 to the Consolidated Financial Statements
Critical Audit Matter Description
Deferred taxes are calculated using a liability method, whereby deferred tax assets are recognized for deductible temporary differences and deferred tax liabilities are recognized for taxable temporary differences. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers a number of factors in assessing the realization of a deferred tax assets associated with net operating losses, including the reversal of temporary differences, future taxable income, and ongoing prudent and feasible tax-planning strategies. Management also considers the uncertainty posed by the current economic environment and the effect of this uncertainty on the various factors that management takes into account in evaluating the need for valuation allowances.
F- 3
As a result, Management determined sufficient future taxable income will be generated to permit use of the existing deferred tax assets as of December 31, 2022. The full valuation allowance in the amount of $308.5 million was released during the year to recognize the portion of net operating losses that are more likely than not to be realized.
How the Critical Audit Matter was Addressed in the Audit
•We tested the effectiveness of controls over the release of the valuation allowance and the income tax provision,
•Reviewed and evaluated the income analysis for the twelve-month period ended December 31, 2022, scheduled reversal of deferred tax liabilities and industry trends used to determine the realizability of the deferred tax assets, and
•With the assistance of our tax specialists, we evaluated the reasonableness of the valuation allowance release by assisting in the evaluation of the positive and negative evidence available, the analysis of the realizability of the deferred tax assets and the conclusions reached.
/s/ Deloitte & Touche LLP
Morristown, New Jersey
February 16, 2023
We have served as the Company's auditor since 2011.
F- 4
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To PBF Energy Inc., the Managing Member of PBF Energy Company LLC
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of PBF Energy Company LLC and subsidiaries (the "Company") as of December 31, 2022 and 2021, 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, 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 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, 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. 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- 5
Critical Audit Matter Description
The Company routinely performs turnaround activities at each of its refineries. Refinery turnaround costs, which are incurred in connection with planned major maintenance activities, are deferred when incurred and amortizedevaluates long-lived assets for impairment on a straight-linecontinual basis over the period of time estimated until the next planned turnaround occurs. Management determines the amortization period based on an evaluation determined by the engineers at the respective refineries. The estimate is developed using the engineers’ technical knowledge and experience, as well as the future turnaround plans made by refinery leadership. Management estimates the amortization period of the deferred turnaround costs ranging primarily from three to six years; however, based upon the specific facts and circumstances, different periods of deferral occur. The total cash expenditures in the current year related to turnarounds was $299.3 million.
We identified the determination of possible triggering events for long-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 judgement and an increased extent of effort, including the need to involve specialists.judgement.
How the Critical Audit Matter Waswas Addressed in the Audit
Our audit procedures related to the determination of the amortization period of the turnaround projectsimpairment indicators for long-lived assets included the following, among others:
•We tested the effectiveness of controls over the approvalidentification of possible circumstances that may indicate that the carrying amounts of long-lived assets are no longer recoverable, including controls over management’s useful life, throughput levels, gross margin, operating expenses and future levels of capital expenditures assumptions.
•We compared management’s evaluation of potential impairment indicators to our independent expectation by:
◦We performed searches for adverse general market and asset-specific environmental conditions,
◦We inquired of Management about the impact of macro-economic events, the pace of decarbonization and the energy transition, and new environmental regulations on the Company’s forecasting of future cash flows, refining margins, future levels of capital expenditure and estimated useful lives,
◦We inspected minutes of the amortization periodboard of directors, the Company’s public statements, operating plans, and the recordingmarket reports to identify any evidence that may contradict management’s assumptions, and
◦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 amortization.sustained capital expenditure and impact to future refinery throughput.
•With the assistance of our fair value specialists,Environmental Specialists, we evaluated the reasonableness of the estimated amortization period by:
/s/ Deloitte & Touche LLP
February 20, 202016, 2023
We have served as the Company's auditor since 2011.
F- 6
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of PBF Energy Inc. and subsidiaries
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of PBF Energy Inc. and subsidiaries (the “Company”) as of December 31, 2019,2022, based on criteria established in Internal Control -— Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019,2022, based on criteria established in Internal Control -— Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2019,2022, of the Company and our report dated February 20, 2020,16, 2023, expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Deloitte & Touche LLP
February 20, 202016, 2023
F- 67
PBF ENERGY INC.
CONSOLIDATED BALANCE SHEETS
(in millions, except share and per share data)
| December 31, 2019 | December 31, 2018 | December 31, 2022 | December 31, 2021 | |||||||||||||||
| ASSETS | ASSETS | |||||||||||||||||
| Current assets: | Current assets: | |||||||||||||||||
| Cash and cash equivalents (PBFX: $35.0 and $19.9, respectively) | $ | 814.9 | $ | 597.3 | ||||||||||||||
| Cash and cash equivalents | Cash and cash equivalents | $ | 2,203.6 | $ | 1,341.5 | |||||||||||||
| Accounts receivable | 835.0 | 718.2 | Accounts receivable | 1,456.3 | 1,277.6 | |||||||||||||
| Inventories | 2,122.2 | 1,865.8 | Inventories | 2,763.6 | 2,505.1 | |||||||||||||
| Prepaid and other current assets | 51.6 | 55.6 | Prepaid and other current assets | 122.8 | 75.0 | |||||||||||||
| Total current assets | 3,823.7 | 3,236.9 | Total current assets | 6,546.3 | 5,199.2 | |||||||||||||
| Property, plant and equipment, net (PBFX: $854.6 and $862.1, respectively) | 4,023.2 | 3,820.9 | ||||||||||||||||
| Deferred tax assets | — | 48.5 | ||||||||||||||||
| Operating lease right of use assets | 306.4 | — | ||||||||||||||||
| Property, plant and equipment, net | Property, plant and equipment, net | 5,361.0 | 4,902.2 | |||||||||||||||
| Lease right of use assets | Lease right of use assets | 679.1 | 717.1 | |||||||||||||||
| Deferred charges and other assets, net | 979.1 | 899.1 | Deferred charges and other assets, net | 962.7 | 822.9 | |||||||||||||
| Total assets | $ | 9,132.4 | $ | 8,005.4 | Total assets | $ | 13,549.1 | $ | 11,641.4 | |||||||||
| LIABILITIES AND EQUITY | LIABILITIES AND EQUITY | |||||||||||||||||
| Current liabilities: | Current liabilities: | |||||||||||||||||
| Accounts payable | $ | 601.4 | $ | 488.4 | Accounts payable | $ | 854.6 | $ | 911.7 | |||||||||
| Accrued expenses | 1,815.6 | 1,623.6 | Accrued expenses | 3,720.8 | 2,740.4 | |||||||||||||
| Deferred revenue | 20.1 | 20.1 | Deferred revenue | 40.6 | 42.7 | |||||||||||||
| Current operating lease liabilities | 72.1 | — | Current operating lease liabilities | 60.5 | 64.9 | |||||||||||||
| Current debt | — | 2.4 | Current debt | 524.2 | — | |||||||||||||
| Total current liabilities | 2,509.2 | 2,134.5 | Total current liabilities | 5,200.7 | 3,759.7 | |||||||||||||
| Long-term debt (PBFX: $802.1 and $673.3, respectively) | 2,064.9 | 1,931.3 | ||||||||||||||||
| Long-term debt | Long-term debt | 1,434.9 | 4,295.8 | |||||||||||||||
| Payable to related parties pursuant to Tax Receivable Agreement | 373.5 | 373.5 | Payable to related parties pursuant to Tax Receivable Agreement | 338.6 | 48.3 | |||||||||||||
| Deferred tax liabilities | 96.9 | 40.4 | Deferred tax liabilities | 535.4 | 111.4 | |||||||||||||
| Long-term operating lease liabilities | 233.1 | — | Long-term operating lease liabilities | 552.7 | 570.4 | |||||||||||||
| Long-term financing lease liabilities | Long-term financing lease liabilities | 57.9 | 70.6 | |||||||||||||||
| Other long-term liabilities | 269.3 | 277.2 | Other long-term liabilities | 372.9 | 252.4 | |||||||||||||
| Total liabilities | 5,546.9 | 4,756.9 | Total liabilities | 8,493.1 | 9,108.6 | |||||||||||||
| Commitments and contingencies (Note 13) | ||||||||||||||||||
| Commitments and contingencies (Note 12) | Commitments and contingencies (Note 12) | |||||||||||||||||
| Equity: | Equity: | |||||||||||||||||
| PBF Energy Inc. equity | PBF Energy Inc. equity | |||||||||||||||||
| Class A common stock, $0.001 par value, 1,000,000,000 shares authorized,119,804,971 shares outstanding at December 31, 2019, 119,874,191 shares outstanding at December 31, 2018 | 0.1 | 0.1 | ||||||||||||||||
| Class B common stock, $0.001 par value, 1,000,000 shares authorized, 20 shares outstanding at December 31, 2019, 20 shares outstanding at December 31, 2018 | — | — | ||||||||||||||||
| Preferred stock, $0.001 par value, 100,000,000 shares authorized, no shares outstanding at December 31, 2019 and 2018 | — | — | ||||||||||||||||
| Treasury stock, at cost, 6,424,787 shares outstanding at December 31, 2019 and 6,274,261 shares outstanding at December 31, 2018 | (165.7 | ) | (160.8 | ) | ||||||||||||||
| Class A common stock, $0.001 par value, 1,000,000,000 shares authorized, 129,639,307 shares outstanding at December 31, 2022, 120,319,577 shares outstanding at December 31, 2021 | Class A common stock, $0.001 par value, 1,000,000,000 shares authorized, 129,639,307 shares outstanding at December 31, 2022, 120,319,577 shares outstanding at December 31, 2021 | 0.1 | 0.1 | |||||||||||||||
| Class B common stock, $0.001 par value, 1,000,000 shares authorized, 13 shares outstanding at December 31, 2022, 15 shares outstanding at December 31, 2021 | Class B common stock, $0.001 par value, 1,000,000 shares authorized, 13 shares outstanding at December 31, 2022, 15 shares outstanding at December 31, 2021 | — | — | |||||||||||||||
| Preferred stock, $0.001 par value, 100,000,000 shares authorized, no shares outstanding at December 31, 2022 and December 31, 2021 | Preferred stock, $0.001 par value, 100,000,000 shares authorized, no shares outstanding at December 31, 2022 and December 31, 2021 | — | — | |||||||||||||||
| Treasury stock, at cost, 10,937,916 shares outstanding at December 31, 2022 and 6,676,809 shares outstanding at December 31, 2021 | Treasury stock, at cost, 10,937,916 shares outstanding at December 31, 2022 and 6,676,809 shares outstanding at December 31, 2021 | (327.0) | (169.1) | |||||||||||||||
| Additional paid in capital | 2,812.3 | 2,633.8 | Additional paid in capital | 3,201.6 | 2,874.0 | |||||||||||||
| Retained earnings | 401.2 | 225.8 | ||||||||||||||||
| Accumulated other comprehensive loss | (8.3 | ) | (22.4 | ) | ||||||||||||||
| Retained earnings (accumulated deficit) | Retained earnings (accumulated deficit) | 2,056.0 | (796.1) | |||||||||||||||
| Accumulated other comprehensive income (loss) | Accumulated other comprehensive income (loss) | (1.5) | 17.3 | |||||||||||||||
| Total PBF Energy Inc. equity | 3,039.6 | 2,676.5 | Total PBF Energy Inc. equity | 4,929.2 | 1,926.2 | |||||||||||||
| Noncontrolling interest | 545.9 | 572.0 | Noncontrolling interest | 126.8 | 606.6 | |||||||||||||
| Total equity | 3,585.5 | 3,248.5 | Total equity | 5,056.0 | 2,532.8 | |||||||||||||
| Total liabilities and equity | $ | 9,132.4 | $ | 8,005.4 | Total liabilities and equity | $ | 13,549.1 | $ | 11,641.4 | |||||||||
See notes to consolidated financial statements.
F- 78
PBF ENERGY INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except share and per share data)
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| Revenues | $ | 46,830.3 | $ | 27,253.4 | $ | 15,115.9 | |||||||||||
| Cost and expenses: | |||||||||||||||||
| Cost of products and other | 39,049.1 | 23,826.8 | 14,275.6 | ||||||||||||||
| Operating expenses (excluding depreciation and amortization expense as reflected below) | 2,599.0 | 2,085.9 | 1,918.3 | ||||||||||||||
| Depreciation and amortization expense | 503.6 | 453.5 | 551.7 | ||||||||||||||
| Cost of sales | 42,151.7 | 26,366.2 | 16,745.6 | ||||||||||||||
| General and administrative expenses (excluding depreciation and amortization expense as reflected below) | 468.7 | 247.3 | 248.5 | ||||||||||||||
| Depreciation and amortization expense | 7.5 | 13.3 | 11.3 | ||||||||||||||
| Change in fair value of contingent consideration, net | 48.3 | 32.4 | (93.7) | ||||||||||||||
| Impairment expense | — | — | 98.8 | ||||||||||||||
| Loss (gain) on sale of assets | 0.9 | (3.0) | (477.8) | ||||||||||||||
| Total cost and expenses | 42,677.1 | 26,656.2 | 16,532.7 | ||||||||||||||
| Income (loss) from operations | 4,153.2 | 597.2 | (1,416.8) | ||||||||||||||
| Other income (expense): | |||||||||||||||||
| Interest expense, net | (246.0) | (317.5) | (258.2) | ||||||||||||||
| Change in Tax Receivable Agreement liability | (290.3) | (48.3) | 373.5 | ||||||||||||||
| Change in fair value of catalyst obligations | (2.0) | 8.5 | (11.8) | ||||||||||||||
| (Loss) gain on extinguishment of debt | (66.1) | 79.9 | (22.2) | ||||||||||||||
| Other non-service components of net periodic benefit cost | 8.8 | 7.8 | 4.3 | ||||||||||||||
| Income (loss) before income taxes | 3,557.6 | 327.6 | (1,331.2) | ||||||||||||||
| Income tax expense | 584.8 | 12.1 | 2.1 | ||||||||||||||
| Net income (loss) | 2,972.8 | 315.5 | (1,333.3) | ||||||||||||||
| Less: net income attributable to noncontrolling interests | 96.0 | 84.5 | 59.1 | ||||||||||||||
| Net income (loss) attributable to PBF Energy Inc. stockholders | $ | 2,876.8 | $ | 231.0 | $ | (1,392.4) | |||||||||||
| Weighted-average shares of Class A common stock outstanding | |||||||||||||||||
| Basic | 122,598,076 | 120,240,009 | 119,617,998 | ||||||||||||||
| Diluted | 126,860,106 | 122,638,154 | 120,660,665 | ||||||||||||||
| Net income (loss) available to Class A common stock per share: | |||||||||||||||||
| Basic | $ | 23.47 | $ | 1.92 | $ | (11.64) | |||||||||||
| Diluted | $ | 22.84 | $ | 1.90 | $ | (11.64) | |||||||||||
| Year Ended December 31, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| Revenues | $ | 24,508.2 | $ | 27,186.1 | $ | 21,786.6 | |||||
| Cost and expenses: | |||||||||||
| Cost of products and other | 21,387.5 | 24,503.4 | 18,863.6 | ||||||||
| Operating expenses (excluding depreciation and amortization expense as reflected below) | 1,782.3 | 1,721.0 | 1,684.4 | ||||||||
| Depreciation and amortization expense | 425.3 | 359.1 | 278.0 | ||||||||
| Cost of sales | 23,595.1 | 26,583.5 | 20,826.0 | ||||||||
| General and administrative expenses (excluding depreciation and amortization expense as reflected below) | 284.0 | 277.0 | 214.5 | ||||||||
| Depreciation and amortization expense | 10.8 | 10.6 | 13.0 | ||||||||
| Change in contingent consideration | (0.8 | ) | — | — | |||||||
| (Gain) loss on sale of assets | (29.9 | ) | (43.1 | ) | 1.5 | ||||||
| Total cost and expenses | 23,859.2 | 26,828.0 | 21,055.0 | ||||||||
| Income from operations | 649.0 | 358.1 | 731.6 | ||||||||
| Other income (expense): | |||||||||||
| Interest expense, net | (159.6 | ) | (169.9 | ) | (154.4 | ) | |||||
| Change in Tax Receivable Agreement liability | — | 13.9 | 250.9 | ||||||||
| Change in fair value of catalyst obligations | (9.7 | ) | 5.6 | (2.2 | ) | ||||||
| Debt extinguishment costs | — | — | (25.5 | ) | |||||||
| Other non-service components of net periodic benefit cost | (0.2 | ) | 1.1 | (1.4 | ) | ||||||
| Income before income taxes | 479.5 | 208.8 | 799.0 | ||||||||
| Income tax expense | 104.3 | 33.5 | 315.6 | ||||||||
| Net income | 375.2 | 175.3 | 483.4 | ||||||||
| Less: net income attributable to noncontrolling interests | 55.8 | 47.0 | 67.8 | ||||||||
| Net income attributable to PBF Energy Inc. stockholders | $ | 319.4 | $ | 128.3 | $ | 415.6 | |||||
| Weighted-average shares of Class A common stock outstanding | |||||||||||
| Basic | 119,887,646 | 115,190,262 | 109,779,407 | ||||||||
| Diluted | 121,853,299 | 118,773,606 | 113,898,845 | ||||||||
| Net income available to Class A common stock per share: | |||||||||||
| Basic | $ | 2.66 | $ | 1.11 | $ | 3.78 | |||||
| Diluted | $ | 2.64 | $ | 1.10 | $ | 3.73 | |||||
| Year Ended December 31, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| Net income | $ | 375.2 | $ | 175.3 | $ | 483.4 | |||||
| Other comprehensive income (loss): | |||||||||||
| Unrealized gain (loss) on available for sale securities | 0.4 | (0.1 | ) | — | |||||||
| Net gain (loss) on pension and other post-retirement benefits | 13.8 | 3.1 | (1.0 | ) | |||||||
| Total other comprehensive income (loss) | 14.2 | 3.0 | (1.0 | ) | |||||||
| Comprehensive income | 389.4 | 178.3 | 482.4 | ||||||||
| Less: comprehensive income attributable to noncontrolling interests | 55.9 | 47.0 | 67.8 | ||||||||
| Comprehensive income attributable to PBF Energy Inc. stockholders | $ | 333.5 | $ | 131.3 | $ | 414.6 | |||||
See notes to consolidated financial statements.
F- 9
PBF ENERGY INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in millions)
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| Net income (loss) | $ | 2,972.8 | $ | 315.5 | $ | (1,333.3) | |||||||||||
| Other comprehensive income (loss): | |||||||||||||||||
| Unrealized loss on available for sale securities | (2.5) | (0.7) | (0.1) | ||||||||||||||
| Net (loss) gain on pension and other post-retirement benefits | (16.3) | 27.1 | (0.7) | ||||||||||||||
| Total other comprehensive income (loss) | (18.8) | 26.4 | (0.8) | ||||||||||||||
| Comprehensive income (loss) | 2,954.0 | 341.9 | (1,334.1) | ||||||||||||||
| Less: comprehensive income attributable to noncontrolling interests | 96.0 | 84.5 | 59.1 | ||||||||||||||
| Comprehensive income (loss) attributable to PBF Energy Inc. stockholders | $ | 2,858.0 | $ | 257.4 | $ | (1,393.2) | |||||||||||
See notes to consolidated financial statements.
F- 10
PBF ENERGY INC.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(in millions, except share and per share data)
| Class A Common Stock | Class B Common Stock | Additional Paid-in Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Treasury Stock | Noncontrolling Interest | Total Equity | ||||||||||||||||||||||||||||
| Shares | Amount | Shares | Amount | Shares | Amount | ||||||||||||||||||||||||||||||
| Balance, January 1, 2020 | 119,804,971 | $ | 0.1 | 20 | $ | — | $ | 2,812.3 | $ | 401.2 | $ | (8.3) | 6,424,787 | $ | (165.7) | $ | 545.9 | $ | 3,585.5 | ||||||||||||||||
| Comprehensive income (loss) | — | — | — | — | — | (1,392.4) | (0.8) | — | — | 59.1 | (1,334.1) | ||||||||||||||||||||||||
| Distributions to PBF Energy Company LLC members | — | — | — | — | — | — | — | — | — | (0.4) | (0.4) | ||||||||||||||||||||||||
| Distributions to PBF Logistics LP public unitholders | — | — | — | — | — | — | — | — | — | (46.8) | (46.8) | ||||||||||||||||||||||||
| Stock-based compensation | — | — | — | — | 28.2 | — | — | — | — | 4.9 | 33.1 | ||||||||||||||||||||||||
| Transactions in connection with stock-based compensation plans | 166,685 | — | — | — | (1.0) | — | — | — | — | (0.9) | (1.9) | ||||||||||||||||||||||||
| Dividends ($0.30 per common share) | — | — | — | — | — | (35.9) | — | — | — | — | (35.9) | ||||||||||||||||||||||||
| Effect of change in deferred tax assets and liabilities and tax receivable agreement obligation | — | — | — | — | (2.1) | — | — | — | — | — | (2.1) | ||||||||||||||||||||||||
| Exchange of PBF Energy Company LLC Series A Units for PBF Energy Class A common stock | 254,647 | — | (4) | — | 2.3 | — | — | — | — | (2.3) | — | ||||||||||||||||||||||||
| Treasury stock purchases | (124,662) | — | — | — | 1.6 | — | — | 124,662 | (1.6) | — | — | ||||||||||||||||||||||||
| Other | — | — | — | — | 4.9 | — | — | — | — | — | 4.9 | ||||||||||||||||||||||||
| Balance, December 31, 2020 | 120,101,641 | $ | 0.1 | 16 | $ | — | $ | 2,846.2 | $ | (1,027.1) | $ | (9.1) | 6,549,449 | $ | (167.3) | $ | 559.5 | $ | 2,202.3 | ||||||||||||||||
| Comprehensive income | — | — | — | — | — | 231.0 | 26.4 | — | — | 84.5 | 341.9 | ||||||||||||||||||||||||
| Distributions to PBF Logistics LP public unitholders | — | — | — | — | — | — | — | — | — | (40.0) | (40.0) | ||||||||||||||||||||||||
| Stock-based compensation | — | — | — | — | 23.9 | — | — | — | — | 5.3 | 29.2 | ||||||||||||||||||||||||
| Transactions in connection with stock-based compensation plans | 234,739 | — | — | — | (1.1) | — | — | — | — | (1.6) | (2.7) | ||||||||||||||||||||||||
| Exchange of PBF Energy Company LLC Series A Units for PBF Energy Class A common stock | 110,557 | — | (1) | — | 0.4 | — | — | — | — | (0.4) | — | ||||||||||||||||||||||||
| Treasury stock purchases | (127,360) | — | — | — | 1.8 | — | — | 127,360 | (1.8) | — | — | ||||||||||||||||||||||||
| Other | — | — | — | — | 2.8 | — | — | — | — | (0.7) | 2.1 | ||||||||||||||||||||||||
| Balance, December 31, 2021 | 120,319,577 | $ | 0.1 | 15 | $ | — | $ | 2,874.0 | $ | (796.1) | $ | 17.3 | 6,676,809 | $ | (169.1) | $ | 606.6 | $ | 2,532.8 | ||||||||||||||||
See notes to consolidated financial statements.
F- 11
| Class A Common Stock | Class B Common Stock | Additional Paid-in Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Treasury Stock | Noncontrolling Interest | Total Equity | |||||||||||||||||||||||
| Shares | Amount | Shares | Amount | Shares | Amount | |||||||||||||||||||||||||
| Balance, January 1, 2017 | 109,204,047 | $ | 0.1 | 28 | $ | — | $ | 2,245.8 | $ | (44.9 | ) | $ | (24.5 | ) | 6,087,963 | $ | (151.6 | ) | $ | 545.6 | $ | 2,570.5 | ||||||||
| Comprehensive income (loss) | — | — | — | — | — | 415.5 | (0.9 | ) | — | — | 67.8 | 482.4 | ||||||||||||||||||
| Exercise of warrants and options | 462,500 | — | — | — | 10.5 | — | — | — | — | (0.6 | ) | 9.9 | ||||||||||||||||||
| Distributions to PBF Energy Company LLC members | — | — | — | — | — | — | — | — | — | (4.5 | ) | (4.5 | ) | |||||||||||||||||
| Distributions to PBF Logistics LP public unitholders | — | — | — | — | — | — | — | — | — | (44.6 | ) | (44.6 | ) | |||||||||||||||||
| Stock-based compensation | 702,404 | — | — | — | 21.5 | — | — | — | — | 5.3 | 26.8 | |||||||||||||||||||
| Dividends ($1.20 per common share) | — | — | — | — | — | (131.8 | ) | — | — | — | — | (131.8 | ) | |||||||||||||||||
| Effects of equity offerings and exchanges of PBF LLC Series A Units on deferred tax assets and liabilities and tax receivable agreement obligation | — | — | — | — | (1.1 | ) | — | — | — | — | — | (1.1 | ) | |||||||||||||||||
| Exchange of PBF Energy Company LLC Series A Units for PBF Energy Class A common stock | 196,580 | — | (3 | ) | — | — | — | — | — | — | — | — | ||||||||||||||||||
| Treasury stock purchases | — | — | — | — | 1.0 | — | — | 44,921 | (1.0 | ) | — | — | ||||||||||||||||||
| Other | — | — | — | — | — | (2.0 | ) | — | — | — | (2.7 | ) | (4.7 | ) | ||||||||||||||||
| Balance, December 31, 2017 | 110,565,531 | $ | 0.1 | 25 | $ | — | $ | 2,277.7 | $ | 236.8 | $ | (25.4 | ) | 6,132,884 | $ | (152.6 | ) | $ | 566.3 | $ | 2,902.9 | |||||||||
| Comprehensive Income | — | — | — | — | — | 128.3 | 3.0 | — | — | 47.0 | 178.3 | |||||||||||||||||||
| Exercise of warrants and options | 708,091 | — | — | — | 14.0 | — | — | — | — | — | 14.0 | |||||||||||||||||||
| Taxes paid for net settlement of equity-based compensation | — | — | — | — | (4.8 | ) | — | — | — | — | (0.6 | ) | (5.4 | ) | ||||||||||||||||
| Distributions to PBF Energy Company LLC members | — | — | — | — | — | — | — | — | — | (2.1 | ) | (2.1 | ) | |||||||||||||||||
| Distributions to PBF Logistics LP public unitholders | — | — | — | — | — | — | — | — | — | (49.5 | ) | (49.5 | ) | |||||||||||||||||
| Stock-based compensation | 43,311 | — | — | — | 19.7 | — | — | — | — | 5.7 | 25.4 | |||||||||||||||||||
| Dividends ($1.20 per common share) | — | — | — | — | — | (139.3 | ) | — | — | — | — | (139.3 | ) | |||||||||||||||||
| Issuance of additional PBFX common units | — | — | — | — | 28.6 | — | — | — | — | 6.3 | 34.9 | |||||||||||||||||||
| Effects of equity offerings and exchanges of PBF LLC Series A Units on deferred tax assets and liabilities and tax receivable agreement obligation | — | — | — | — | (4.9 | ) | — | — | — | — | — | (4.9 | ) | |||||||||||||||||
| Exchange of PBF Energy Company LLC Series A Units for PBF Energy Class A common stock | 2,698,635 | — | (5 | ) | — | — | — | — | — | — | — | — | ||||||||||||||||||
| August 2018 Equity Offering | 6,000,000 | — | — | — | 287.3 | — | — | — | — | — | 287.3 | |||||||||||||||||||
| Treasury stock purchases | (141,377 | ) | — | — | — | 8.2 | — | — | 141,377 | (8.2 | ) | — | — | |||||||||||||||||
| Other | — | — | — | — | 8.0 | — | — | — | — | (1.1 | ) | 6.9 | ||||||||||||||||||
| Balance, December 31, 2018 | 119,874,191 | $ | 0.1 | 20 | $ | — | $ | 2,633.8 | $ | 225.8 | $ | (22.4 | ) | 6,274,261 | $ | (160.8 | ) | $ | 572.0 | $ | 3,248.5 | |||||||||
PBF ENERGY INC.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Continued)
(in millions, except share and per share data)
| Class A Common Stock | Class B Common Stock | Additional Paid-in Capital | Retained Earnings (Accumulated Deficit) | Accumulated Other Comprehensive Income (Loss) | Treasury Stock | Noncontrolling Interest | Total Equity | ||||||||||||||||||||||||||||
| Shares | Amount | Shares | Amount | Shares | Amount | ||||||||||||||||||||||||||||||
| Balance, December 31, 2021 | 120,319,577 | $ | 0.1 | 15 | $ | — | $ | 2,874.0 | $ | (796.1) | $ | 17.3 | 6,676,809 | $ | (169.1) | $ | 606.6 | $ | 2,532.8 | ||||||||||||||||
| Comprehensive income (loss) | — | — | — | — | — | 2,876.8 | (18.8) | — | — | 96.0 | 2,954.0 | ||||||||||||||||||||||||
| Distributions to PBF Energy Company LLC members | — | — | — | — | — | — | — | — | — | (8.6) | (8.6) | ||||||||||||||||||||||||
| Distributions to PBF Logistics LP public unitholders | — | — | — | — | — | — | — | — | — | (40.3) | (40.3) | ||||||||||||||||||||||||
| Stock-based compensation | — | — | — | — | 33.2 | — | — | — | — | 10.2 | 43.4 | ||||||||||||||||||||||||
| Transactions in connection with stock-based compensation plans | 4,680,161 | — | — | — | 86.5 | — | — | — | — | (18.7) | 67.8 | ||||||||||||||||||||||||
| Dividends ($0.20 per common share) | — | — | — | — | — | (24.7) | — | — | — | — | (24.7) | ||||||||||||||||||||||||
| Effects of changes in PBF Logistics ownership interests on deferred tax assets and liabilities | — | — | — | — | (9.7) | — | — | — | — | — | (9.7) | ||||||||||||||||||||||||
| Exchange of PBF Energy Company LLC Series A Units for PBF Energy Class A common stock | 35,992 | — | (2) | — | 0.1 | — | — | — | — | (0.1) | — | ||||||||||||||||||||||||
| PBFX Merger Transaction | 8,864,684 | — | — | — | 216.0 | — | — | — | — | (519.7) | (303.7) | ||||||||||||||||||||||||
| Treasury stock purchases | (4,261,107) | — | — | — | 1.5 | — | — | 4,261,107 | (157.9) | — | (156.4) | ||||||||||||||||||||||||
| Other | — | — | — | — | — | — | — | — | — | 1.4 | 1.4 | ||||||||||||||||||||||||
| Balance, December 31, 2022 | 129,639,307 | $ | 0.1 | 13 | $ | — | $ | 3,201.6 | $ | 2,056.0 | $ | (1.5) | 10,937,916 | $ | (327.0) | $ | 126.8 | $ | 5,056.0 | ||||||||||||||||
Class A Common Stock | Class B Common Stock | Additional Paid-in Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Treasury Stock | Noncontrolling Interest | Total Equity | |||||||||||||||||||||||
| Shares | Amount | Shares | Amount | Shares | Amount | |||||||||||||||||||||||||
| Balance, December 31, 2018 | 119,874,191 | $ | 0.1 | 20 | $ | — | $ | 2,633.8 | $ | 225.8 | $ | (22.4 | ) | 6,274,261 | $ | (160.8 | ) | $ | 572.0 | $ | 3,248.5 | |||||||||
| Comprehensive Income | — | — | — | — | — | 319.4 | 14.1 | — | — | 55.9 | 389.4 | |||||||||||||||||||
| Exercise of warrants and options | 16,831 | — | — | — | 0.3 | — | — | — | — | — | 0.3 | |||||||||||||||||||
| Taxes paid for net settlement of equity-based compensation | — | — | — | — | (4.6 | ) | — | — | — | — | (0.2 | ) | (4.8 | ) | ||||||||||||||||
| Distributions to PBF Energy Company LLC members | — | — | — | — | — | — | — | — | — | (3.2 | ) | (3.2 | ) | |||||||||||||||||
| Distributions to PBF Logistics LP public unitholders | — | — | — | — | — | — | — | — | — | (64.1 | ) | (64.1 | ) | |||||||||||||||||
| Stock-based compensation | 54,475 | — | — | — | 27.2 | — | — | — | — | 6.8 | 34.0 | |||||||||||||||||||
| Dividends ($1.20 per common share) | — | — | — | — | — | (143.8 | ) | — | — | — | — | (143.8 | ) | |||||||||||||||||
| Issuance of additional PBFX common units | — | — | — | — | 152.0 | — | — | — | — | (19.5 | ) | 132.5 | ||||||||||||||||||
| Effects of changes in PBFX ownership interest on deferred tax assets and liabilities | — | — | — | — | (1.3 | ) | — | — | — | — | — | (1.3 | ) | |||||||||||||||||
| Exchange of PBF Energy Company LLC Series A Units for PBF Energy Class A common stock | 10,000 | — | — | — | — | — | — | — | — | — | — | |||||||||||||||||||
| Treasury stock purchases | (150,526 | ) | — | — | — | 4.9 | — | — | 150,526 | (4.9 | ) | — | — | |||||||||||||||||
| Other | — | — | — | — | — | (0.2 | ) | — | — | — | (1.8 | ) | (2.0 | ) | ||||||||||||||||
| Balance, December 31, 2019 | 119,804,971 | $ | 0.1 | 20 | $ | — | $ | 2,812.3 | $ | 401.2 | $ | (8.3 | ) | 6,424,787 | $ | (165.7 | ) | $ | 545.9 | $ | 3,585.5 | |||||||||
See notes to consolidated financial statements.
F- 1112
PBF ENERGY INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| Cash flows from operating activities: | |||||||||||||||||
| Net income (loss) | $ | 2,972.8 | $ | 315.5 | $ | (1,333.3) | |||||||||||
| Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | |||||||||||||||||
| Depreciation and amortization | 533.9 | 483.8 | 581.1 | ||||||||||||||
| Impairment expense | — | — | 98.8 | ||||||||||||||
| Stock-based compensation | 54.3 | 35.6 | 34.2 | ||||||||||||||
| Change in fair value of catalyst obligations | 2.0 | (8.5) | 11.8 | ||||||||||||||
| Deferred income taxes | 420.2 | 11.7 | 1.6 | ||||||||||||||
| Change in Tax Receivable Agreement liability | 290.3 | 48.3 | (373.5) | ||||||||||||||
| Non-cash change in inventory repurchase obligations | (5.4) | (8.4) | (12.6) | ||||||||||||||
| Non-cash lower of cost or market inventory adjustment | — | (669.6) | 268.0 | ||||||||||||||
| Change in fair value of contingent consideration, net | 48.3 | 32.4 | (93.7) | ||||||||||||||
| Loss (gain) on extinguishment of debt | 66.1 | (79.9) | 22.2 | ||||||||||||||
| Pension and other post-retirement benefit costs | 47.6 | 50.8 | 55.7 | ||||||||||||||
| Loss (gain) on sale of assets | 0.9 | (3.0) | (477.8) | ||||||||||||||
| Changes in operating assets and liabilities: | |||||||||||||||||
| Accounts receivable | (178.8) | (764.7) | 322.1 | ||||||||||||||
| Inventories | (258.5) | (149.3) | 392.2 | ||||||||||||||
| Prepaid and other current assets | (5.4) | (16.2) | (1.8) | ||||||||||||||
| Accounts payable | (95.7) | 480.7 | (206.6) | ||||||||||||||
| Accrued expenses | 881.0 | 797.9 | 116.0 | ||||||||||||||
| Deferred revenue | (2.1) | (4.5) | 27.1 | ||||||||||||||
| Other assets and liabilities | 0.5 | (75.3) | (63.1) | ||||||||||||||
| Net cash provided by (used in) operating activities | $ | 4,772.0 | $ | 477.3 | $ | (631.6) | |||||||||||
| Cash flows from investing activities: | |||||||||||||||||
| Expenditures for property, plant and equipment | (633.3) | (249.1) | (196.2) | ||||||||||||||
| Expenditures for deferred turnaround costs | (311.6) | (117.7) | (188.1) | ||||||||||||||
| Expenditures for other assets | (66.0) | (28.9) | (9.1) | ||||||||||||||
| Acquisition of Martinez refinery | — | — | (1,176.2) | ||||||||||||||
| Proceeds from sale of assets | — | 7.2 | 543.1 | ||||||||||||||
| Net cash used in investing activities | $ | (1,010.9) | $ | (388.5) | $ | (1,026.5) | |||||||||||
See notes to consolidated financial statements.
F- 13
F- 13
| Year Ended December 31, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| Cash flows from operating activities: | |||||||||||
| Net income | $ | 375.2 | $ | 175.3 | $ | 483.4 | |||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||
| Depreciation and amortization | 447.5 | 378.6 | 299.9 | ||||||||
| Stock-based compensation | 37.3 | 26.0 | 26.8 | ||||||||
| Change in fair value of catalyst obligations | 9.7 | (5.6 | ) | 2.2 | |||||||
| Deferred income taxes | 103.7 | 32.7 | 313.8 | ||||||||
| Change in Tax Receivable Agreement liability | — | (13.9 | ) | (250.9 | ) | ||||||
| Non-cash change in inventory repurchase obligations | 25.4 | (31.8 | ) | 13.8 | |||||||
| Non-cash lower of cost or market inventory adjustment | (250.2 | ) | 351.3 | (295.5 | ) | ||||||
| Debt extinguishment costs | — | — | 25.5 | ||||||||
| Pension and other post-retirement benefit costs | 44.8 | 47.4 | 42.2 | ||||||||
| Change in fair value of contingent consideration | (0.8 | ) | — | — | |||||||
| (Gain) loss on sale of assets | (29.9 | ) | (43.1 | ) | 1.5 | ||||||
| Changes in operating assets and liabilities: | |||||||||||
| Accounts receivable | (116.1 | ) | 234.3 | (332.4 | ) | ||||||
| Inventories | (6.3 | ) | (3.3 | ) | (54.7 | ) | |||||
| Prepaid and other current assets | 2.7 | 10.1 | 73.5 | ||||||||
| Accounts payable | 137.5 | (111.6 | ) | 34.6 | |||||||
| Accrued expenses | 208.1 | (227.1 | ) | 359.5 | |||||||
| Deferred revenue | 0.1 | 11.2 | (4.4 | ) | |||||||
| Payable to related parties pursuant to Tax Receivable Agreement | — | — | — | ||||||||
| Other assets and liabilities | (55.2 | ) | 7.5 | (53.1 | ) | ||||||
| Net cash provided by operating activities | $ | 933.5 | $ | 838.0 | $ | 685.7 | |||||
| Cash flows from investing activities: | |||||||||||
| Expenditures for property, plant and equipment | (404.9 | ) | (317.5 | ) | (306.7 | ) | |||||
| Expenditures for deferred turnaround costs | (299.3 | ) | (266.0 | ) | (379.1 | ) | |||||
| Expenditures for other assets | (44.7 | ) | (17.0 | ) | (31.2 | ) | |||||
| Acquisition of Knoxville Terminal by PBFX | — | (58.4 | ) | — | |||||||
| Acquisition of East Coast Storage Assets by PBFX | — | (75.0 | ) | — | |||||||
| Acquisition of Toledo Products Terminal by PBFX | — | — | (10.1 | ) | |||||||
| Proceeds from sale of assets | 36.3 | 48.3 | — | ||||||||
| Purchase of marketable securities | — | — | (75.0 | ) | |||||||
| Maturities of marketable securities | — | — | 115.1 | ||||||||
| Net cash used in investing activities | $ | (712.6 | ) | $ | (685.6 | ) | $ | (687.0 | ) | ||
PBF ENERGY INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
(in millions)
| Year Ended December 31, | |||||||||||||||||
| Cash flows from financing activities: | 2022 | 2021 | 2020 | ||||||||||||||
| PBFX Merger Transaction payment | (303.7) | — | — | ||||||||||||||
| Dividend payments | (24.7) | — | (35.9) | ||||||||||||||
| Distributions to PBFX Public Unitholders | (40.3) | (39.0) | (45.9) | ||||||||||||||
| Distributions to PBF Energy Company LLC members other than PBF Energy | (8.6) | — | (0.4) | ||||||||||||||
| Distribution to T&M and Collins shareholders | — | (0.7) | — | ||||||||||||||
| Proceeds from 2025 9.25% Senior Secured Notes | — | — | 1,250.6 | ||||||||||||||
| Proceeds from 2028 6.00% Senior Notes | — | — | 1,000.0 | ||||||||||||||
| Repurchase of 2028 6.00% Senior Notes | (21.1) | (109.3) | — | ||||||||||||||
| Repurchase of 2025 7.25% Senior Notes | (4.8) | (37.5) | — | ||||||||||||||
| Redemption of 2023 7.00% Senior Notes | — | — | (517.5) | ||||||||||||||
| Redemption of 2025 9.25% Senior Secured Notes | (1,307.4) | — | — | ||||||||||||||
| Proceeds from revolver borrowings | 400.0 | — | 1,450.0 | ||||||||||||||
| Repayments of revolver borrowings | (1,300.0) | — | (550.0) | ||||||||||||||
| Proceeds from PBFX revolver borrowings | — | — | 100.0 | ||||||||||||||
| Repayments of PBFX revolver borrowings | (100.0) | (100.0) | (183.0) | ||||||||||||||
| Repayments of PBF Rail Term Loan | — | (7.4) | (7.2) | ||||||||||||||
| Settlements of precious metal catalyst obligations | (56.2) | (31.7) | (8.8) | ||||||||||||||
| Proceeds from catalyst financing arrangements | — | — | 51.9 | ||||||||||||||
| Payments on financing leases | (11.3) | (17.8) | (12.4) | ||||||||||||||
| Proceeds from insurance premium financing | 2.1 | — | — | ||||||||||||||
| Transactions in connection with stock-based compensation plans, net | 67.8 | (4.6) | (2.1) | ||||||||||||||
| Payments of contingent consideration | (3.1) | (12.2) | — | ||||||||||||||
| Share repurchase of PBF Energy’s Class A common stock | (156.4) | — | (1.6) | ||||||||||||||
| Deferred financing costs and other | (31.3) | 3.4 | (35.0) | ||||||||||||||
| Net cash (used in) provided by financing activities | $ | (2,899.0) | $ | (356.8) | $ | 2,452.7 | |||||||||||
| Net change in cash and cash equivalents | 862.1 | (268.0) | 794.6 | ||||||||||||||
| Cash and cash equivalents, beginning of period | 1,341.5 | 1,609.5 | 814.9 | ||||||||||||||
| Cash and cash equivalents, end of period | $ | 2,203.6 | $ | 1,341.5 | $ | 1,609.5 | |||||||||||
| Year Ended December 31, | |||||||||||
| Cash flows from financing activities: | 2019 | 2018 | 2017 | ||||||||
| Net proceeds from issuance of PBF Energy Class A common stock | $ | — | $ | 287.3 | $ | — | |||||
| Net proceeds from issuance of PBFX common units | 132.5 | 34.9 | — | ||||||||
| Dividend payments | (143.5 | ) | (139.0 | ) | (131.7 | ) | |||||
| Distributions to PBFX public unitholders | (62.5 | ) | (48.2 | ) | (43.5 | ) | |||||
| Distributions to PBF Energy Company LLC members other than PBF Energy | (3.2 | ) | (2.1 | ) | (4.5 | ) | |||||
| Distribution to T&M and Collins shareholders | — | — | (1.8 | ) | |||||||
| Proceeds from 2025 Senior Notes | — | — | 725.0 | ||||||||
| Cash paid to extinguish 2020 Senior Secured Notes | — | — | (690.2 | ) | |||||||
| Proceeds from revolver borrowings | 1,350.0 | — | 490.0 | ||||||||
| Repayments of revolver borrowings | (1,350.0 | ) | (350.0 | ) | (490.0 | ) | |||||
| Repayments of PBF Rail Term Loan | (7.0 | ) | (6.8 | ) | (6.6 | ) | |||||
| Proceeds from PBFX revolver borrowings | 228.0 | 170.0 | 20.0 | ||||||||
| Repayments of PBFX revolver borrowings | (101.0 | ) | (43.7 | ) | (179.5 | ) | |||||
| Repayments of PBFX Term Loan borrowings | — | — | (39.7 | ) | |||||||
| Proceeds from PBFX 2023 Senior Notes | — | — | 178.5 | ||||||||
| Repayments of note payable | — | (5.6 | ) | (1.2 | ) | ||||||
| Deferred payment for the East Coast Storage Assets Acquisition | (32.0 | ) | — | — | |||||||
| Settlements of catalyst obligations | (6.5 | ) | (9.1 | ) | 10.8 | ||||||
| Taxes paid for net settlement of equity-based compensation | (4.8 | ) | (5.4 | ) | — | ||||||
| Proceeds from stock options exercised | — | 14.0 | 10.5 | ||||||||
| Purchases of treasury stock | (4.9 | ) | (8.2 | ) | (1.0 | ) | |||||
| Deferred financing costs and other | 1.6 | (16.2 | ) | (17.1 | ) | ||||||
| Net cash used in financing activities | $ | (3.3 | ) | $ | (128.1 | ) | $ | (172.0 | ) | ||
| Net increase (decrease) in cash and cash equivalents | 217.6 | 24.3 | (173.3 | ) | |||||||
| Cash and equivalents, beginning of period | 597.3 | 573.0 | 746.3 | ||||||||
| Cash and equivalents, end of period | $ | 814.9 | $ | 597.3 | $ | 573.0 | |||||
| Supplemental cash flow disclosures | |||||||||||||||||
| Non-cash activities: | |||||||||||||||||
| Accrued and unpaid capital expenditures | $ | 166.1 | $ | 104.0 | $ | 32.1 | |||||||||||
| Assets acquired or remeasured under operating and financing leases | 54.7 | (106.6) | 702.0 | ||||||||||||||
| Fair value of the Martinez Contingent Consideration at acquisition | — | — | 77.3 | ||||||||||||||
| Cash paid during year for: | |||||||||||||||||
| Interest, net of capitalized interest of $25.0, $9.1 and $12.6 in 2022, 2021 and 2020, respectively | $ | 249.7 | $ | 307.0 | $ | 206.9 | |||||||||||
| Income taxes | 148.9 | 5.7 | 2.1 | ||||||||||||||
| Supplemental cash flow disclosures | |||||||||||
| Non-cash activities: | |||||||||||
| Accrued and unpaid capital expenditures | $ | 37.2 | $ | 90.2 | $ | 26.8 | |||||
| Assets acquired under operating leases | 408.6 | — | — | ||||||||
| Assets acquired under finance leases | 26.3 | — | — | ||||||||
| Deferred payment for PBFX East Coast Storage Assets Acquisition | — | 30.9 | — | ||||||||
| East Coast Storage Assets Acquisition contingent consideration | — | 21.1 | — | ||||||||
| Note payable issued for purchase of property, plant and equipment | — | — | 6.8 | ||||||||
| Cash paid during year for: | |||||||||||
| Interest, net of capitalized interest of $18.1, $9.5 and $7.2 in 2019, 2018 and 2017, respectively | $ | 154.0 | $ | 164.4 | $ | 166.5 | |||||
| Income taxes | 2.7 | 0.7 | — | ||||||||
See notes to consolidated financial statements.
F- 14
F- 14
PBF ENERGY COMPANY LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in millions, except unit and per unit data)
| December 31, 2022 | December 31, 2021 | ||||||||||
| ASSETS | |||||||||||
| Current assets: | |||||||||||
| Cash and cash equivalents | $ | 2,201.8 | $ | 1,339.8 | |||||||
| Accounts receivable | 1,456.3 | 1,277.6 | |||||||||
| Inventories | 2,763.6 | 2,505.1 | |||||||||
| Prepaid and other current assets | 122.8 | 75.0 | |||||||||
| Total current assets | 6,544.5 | 5,197.5 | |||||||||
| Property, plant and equipment, net | 5,361.0 | 4,902.2 | |||||||||
| Lease right of use assets | 679.1 | 717.1 | |||||||||
| Deferred charges and other assets, net | 962.7 | 822.9 | |||||||||
| Total assets | $ | 13,547.3 | $ | 11,639.7 | |||||||
| LIABILITIES AND EQUITY | |||||||||||
| Current liabilities: | |||||||||||
| Accounts payable | $ | 853.4 | $ | 911.7 | |||||||
| Accrued expenses | 3,768.3 | 2,792.6 | |||||||||
| Deferred revenue | 40.6 | 42.7 | |||||||||
| Current operating lease liabilities | 60.5 | 64.9 | |||||||||
| Current debt | 524.2 | — | |||||||||
| Total current liabilities | 5,247.0 | 3,811.9 | |||||||||
| Long-term debt | 1,434.9 | 4,295.8 | |||||||||
| Affiliate note payable | 1,445.7 | 375.2 | |||||||||
| Deferred tax liabilities | 21.0 | 24.2 | |||||||||
| Long-term operating lease liabilities | 552.7 | 570.4 | |||||||||
| Long-term financing lease liabilities | 57.9 | 70.6 | |||||||||
| Other long-term liabilities | 372.9 | 252.4 | |||||||||
| Total liabilities | 9,132.1 | 9,400.5 | |||||||||
| Commitments and contingencies (Note 12) | |||||||||||
| Equity: | |||||||||||
| Series B Units, 1,000,000 issued and outstanding, no par or stated value | 5.1 | 5.1 | |||||||||
| PBF Energy Company LLC equity: | |||||||||||
| Series A Units, 910,457 and 927,990 issued and outstanding at December 31, 2022 and 2021, no par or stated value | 17.4 | 17.6 | |||||||||
| Series C Units, 129,660,538 and 120,340,808 issued and outstanding at December 31, 2022 and 2021, no par or stated value | 2,491.9 | 2,245.0 | |||||||||
| Treasury stock, at cost | (327.0) | (169.1) | |||||||||
| Retained earnings (accumulated deficit) | 2,220.0 | (390.9) | |||||||||
| Accumulated other comprehensive income (loss) | (4.4) | 20.3 | |||||||||
| Total PBF Energy Company LLC equity | 4,397.9 | 1,722.9 | |||||||||
| Noncontrolling interest | 12.2 | 511.2 | |||||||||
| Total equity | 4,410.1 | 2,234.1 | |||||||||
| Total liabilities, Series B units and equity | $ | 13,547.3 | $ | 11,639.7 | |||||||
| December 31, 2019 | December 31, 2018 | ||||||
| ASSETS | |||||||
| Current assets: | |||||||
| Cash and cash equivalents (PBFX: $35.0 and $19.9, respectively) | $ | 813.7 | $ | 596.0 | |||
| Accounts receivable | 834.0 | 718.2 | |||||
| Inventories | 2,122.2 | 1,865.8 | |||||
| Prepaid and other current assets | 51.6 | 55.1 | |||||
| Total current assets | 3,821.5 | 3,235.1 | |||||
| Property, plant and equipment, net (PBFX: $854.6 and $862.1, respectively) | 4,023.2 | 3,820.9 | |||||
| Operating lease right of use assets | 306.4 | — | |||||
| Deferred charges and other assets, net | 978.0 | 897.1 | |||||
| Total assets | $ | 9,129.1 | $ | 7,953.1 | |||
| LIABILITIES AND EQUITY | |||||||
| Current liabilities: | |||||||
| Accounts payable | $ | 601.4 | $ | 488.4 | |||
| Accrued expenses | 1,846.2 | 1,642.7 | |||||
| Deferred revenue | 20.1 | 20.1 | |||||
| Current operating lease liabilities | 72.1 | — | |||||
| Current debt | — | 2.4 | |||||
| Total current liabilities | 2,539.8 | 2,153.6 | |||||
| Long-term debt (PBFX: $802.1 and $676.3, respectively) | 2,064.9 | 1,931.3 | |||||
| Affiliate note payable | 376.4 | 326.1 | |||||
| Deferred tax liabilities | 31.4 | 40.4 | |||||
| Long-term operating lease liabilities | 233.1 | — | |||||
| Other long-term liabilities | 269.3 | 277.2 | |||||
| Total liabilities | 5,514.9 | 4,728.6 | |||||
| Commitments and contingencies (Note 13) | |||||||
| Series B Units, 1,000,000 issued and outstanding, no par or stated value | 5.1 | 5.1 | |||||
| PBF Energy Company LLC equity: | |||||||
| Series A Units, 1,215,317 and 1,206,325 issued and outstanding at December 31, 2019 and 2018, no par or stated value | 20.0 | 20.2 | |||||
| Series C Units, 119,826,202 and 119,895,422 issued and outstanding at December 31, 2019 and 2018, no par or stated value | 2,189.4 | 2,009.8 | |||||
| Treasury stock, at cost | (165.7 | ) | (160.8 | ) | |||
| Retained Earnings | 1,142.4 | 914.3 | |||||
| Accumulated other comprehensive loss | (9.7 | ) | (23.9 | ) | |||
| Total PBF Energy Company LLC equity | 3,176.4 | 2,759.6 | |||||
| Noncontrolling interest | 432.7 | 459.8 | |||||
| Total equity | 3,609.1 | 3,219.4 | |||||
| Total liabilities, Series B units and equity | $ | 9,129.1 | $ | 7,953.1 | |||
See notes to consolidated financial statements.
F- 15
F- 15
PBF ENERGY COMPANY LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions)
| Year Ended December 31, | |||||||||||||||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||||||||||||||
| Revenues | $ | 46,830.3 | $ | 27,253.4 | $ | 15,115.9 | |||||||||||||||||||||||
| Cost and expenses: | |||||||||||||||||||||||||||||
| Cost of products and other | 39,049.1 | 23,826.8 | 14,275.6 | ||||||||||||||||||||||||||
| Operating expenses (excluding depreciation and amortization expense as reflected below) | 2,599.0 | 2,085.9 | 1,918.3 | ||||||||||||||||||||||||||
| Depreciation and amortization expense | 503.6 | 453.5 | 551.7 | ||||||||||||||||||||||||||
| Cost of sales | 42,151.7 | 26,366.2 | 16,745.6 | ||||||||||||||||||||||||||
| General and administrative expenses (excluding depreciation and amortization expense as reflected below) | 466.6 | 245.2 | 247.7 | ||||||||||||||||||||||||||
| Depreciation and amortization expense | 7.5 | 13.3 | 11.3 | ||||||||||||||||||||||||||
| Change in fair value of contingent consideration, net | 48.3 | 32.4 | (93.7) | ||||||||||||||||||||||||||
| Impairment expense | — | — | 98.8 | ||||||||||||||||||||||||||
| Loss (gain) on sale of assets | 0.9 | (3.0) | (477.8) | ||||||||||||||||||||||||||
| Total cost and expenses | 42,675.0 | 26,654.1 | 16,531.9 | ||||||||||||||||||||||||||
| Income (loss) from operations | 4,155.3 | 599.3 | (1,416.0) | ||||||||||||||||||||||||||
| Other income (expense): | |||||||||||||||||||||||||||||
| Interest expense, net | (257.2) | (327.8) | (268.5) | ||||||||||||||||||||||||||
| Change in fair value of catalyst obligations | (2.0) | 8.5 | (11.8) | ||||||||||||||||||||||||||
| (Loss) gain on extinguishment of debt | (66.1) | 79.9 | (22.2) | ||||||||||||||||||||||||||
| Other non-service components of net periodic benefit cost | 8.8 | 7.8 | 4.3 | ||||||||||||||||||||||||||
| Income (loss) before income taxes | 3,838.8 | 367.7 | (1,714.2) | ||||||||||||||||||||||||||
| Income tax expense (benefit) | 4.6 | (14.0) | 6.1 | ||||||||||||||||||||||||||
| Net income (loss) | 3,834.2 | 381.7 | (1,720.3) | ||||||||||||||||||||||||||
| Less: net income attributable to noncontrolling interests | 68.1 | 82.1 | 76.2 | ||||||||||||||||||||||||||
| Net income (loss) attributable to PBF Energy Company LLC | $ | 3,766.1 | $ | 299.6 | $ | (1,796.5) | |||||||||||||||||||||||
| Year Ended December 31, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| Revenues | $ | 24,508.2 | $ | 27,186.1 | $ | 21,786.6 | |||||
| Cost and expenses: | |||||||||||
| Cost of products and other | 21,387.5 | 24,503.4 | 18,863.6 | ||||||||
| Operating expenses (excluding depreciation and amortization expense as reflected below) | 1,782.3 | 1,721.0 | 1,684.4 | ||||||||
| Depreciation and amortization expense | 425.3 | 359.1 | 278.0 | ||||||||
| Cost of sales | 23,595.1 | 26,583.5 | 20,826.0 | ||||||||
| General and administrative expenses (excluding depreciation and amortization expense as reflected below) | 282.3 | 275.2 | 214.2 | ||||||||
| Depreciation and amortization expense | 10.8 | 10.6 | 13.0 | ||||||||
| Change in contingent consideration | (0.8 | ) | — | — | |||||||
| (Gain) loss on sale of assets | (29.9 | ) | (43.1 | ) | 1.5 | ||||||
| Total cost and expenses | 23,857.5 | 26,826.2 | 21,054.7 | ||||||||
| Income from operations | 650.7 | 359.9 | 731.9 | ||||||||
| Other income (expense): | |||||||||||
| Interest expense, net | (169.1 | ) | (178.5 | ) | (162.3 | ) | |||||
| Change in fair value of catalyst obligations | (9.7 | ) | 5.6 | (2.2 | ) | ||||||
| Debt extinguishment costs | — | — | (25.5 | ) | |||||||
| Other non-service components of net periodic benefit cost | (0.2 | ) | 1.1 | (1.4 | ) | ||||||
| Income before income taxes | 471.7 | 188.1 | 540.5 | ||||||||
| Income tax (benefit) expense | (8.3 | ) | 8.0 | (10.8 | ) | ||||||
| Net income | 480.0 | 180.1 | 551.3 | ||||||||
| Less: net income attributable to noncontrolling interests | 51.5 | 42.3 | 51.2 | ||||||||
| Net income attributable to PBF Energy Company LLC | $ | 428.5 | $ | 137.8 | $ | 500.1 | |||||
See notes to consolidated financial statements.
F- 16
F- 16
PBF ENERGY COMPANY LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in millions)
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| Net income (loss) | $ | 3,834.2 | $ | 381.7 | $ | (1,720.3) | |||||||||||
| Other comprehensive income (loss): | |||||||||||||||||
| Unrealized loss on available for sale securities | (2.5) | (0.7) | (0.1) | ||||||||||||||
| Net (loss) gain on pension and other post-retirement benefits | (22.2) | 27.1 | 3.7 | ||||||||||||||
| Total other comprehensive income (loss) | (24.7) | 26.4 | 3.6 | ||||||||||||||
| Comprehensive income (loss) | 3,809.5 | 408.1 | (1,716.7) | ||||||||||||||
| Less: comprehensive income attributable to noncontrolling interests | 68.1 | 82.1 | 76.2 | ||||||||||||||
| Comprehensive income (loss) attributable to PBF Energy Company LLC | $ | 3,741.4 | $ | 326.0 | $ | (1,792.9) | |||||||||||
| Year Ended December 31, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| Net income | $ | 480.0 | $ | 180.1 | $ | 551.3 | |||||
| Other comprehensive income (loss): | |||||||||||
| Unrealized gain (loss) on available for sale securities | 0.4 | (0.1 | ) | — | |||||||
| Net gain (loss) on pension and other post-retirement benefits | 13.8 | 3.1 | (1.0 | ) | |||||||
| Total other comprehensive income (loss) | 14.2 | 3.0 | (1.0 | ) | |||||||
| Comprehensive income | 494.2 | 183.1 | 550.3 | ||||||||
| Less: comprehensive income attributable to noncontrolling interests | 51.5 | 42.3 | 51.2 | ||||||||
| Comprehensive income attributable to PBF Energy Company LLC | $ | 442.7 | $ | 140.8 | $ | 499.1 | |||||
See notes to consolidated financial statements.
F- 17
F- 17