See “Item 1A. Risk Factors” and “Item 13. Certain Relationships and Related Transactions, and Director Independence.”
Our website address is www.pbfenergy.com. Information contained on our website is not part of this Annual Report on Form 10-K. Our annual 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.
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 into 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 revenue isrevenues are derived from long-term, fee basedfee-based commercial agreements with PBF Holding and its subsidiaries and these intersegment related revenues are eliminated in consolidation. See “Note 2022 - Segment Information” of our Notes to Consolidated Financial Statements, for detailed information on our operating results by business segment.
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”), 47,00054,500 bpd fluid coking unit and 18,00024,000 bpd hydrocracking unit with vacuum distillation.unit.
steam methane reformer and continuous catalytic reformer. During 2018, we signed an agreement with a third-party for the construction and subsequent lease of a new 25 million cubic feet per day hydrogen facility (the “Hydrogen Facility”) which is expected to be completed in the first quarter of 2020. Upon completion, the Hydrogen Facility will provide us with additional complex crude processing capabilities.
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 March 2022, subject to certain early termination rights. In March 2017, the agreement was renewed and extended for a two-year term. We are currently in the process of negotiating aactive negotiations with Sunoco on renewal of this agreement.contract. 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.
We formed PBFX, a publicly-traded MLP, to own or lease, operate, develop and acquire crude oil and refined petroleum products terminals, pipelines, storage facilities and similar logistics assets. PBFX’s operations are aggregated into the Logistics segment. 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. A substantial majority of PBFX’s revenues isare 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. PBFX’s third-party revenue is primarily derived from its third-party acquisitions. 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 PBF Energy and PBF LLC in consolidation.
| | | | | | | | | | | | | | |
(a)Name | These assets represent the assets that PBFX acquired from PBF LLC. |
| Age (as of December 31, 2021) | | Position |
(b)Thomas Nimbley | These assets are collectively referred to as the “DCR Rail Facility”. |
| 70 | | Chief Executive Officer and Chairman of the Board of Directors |
(c)Matthew Lucey | These assets are collectively referred to as the “Development Assets”. |
| 48 | | President |
(d)C. Erik Young | Of the approximately 3.9 million barrel aggregate shell capacity, approximately 1.3 million barrels are dedicated to crude and approximately 2.6 million barrels are allocated to refined products and intermediates. |
| 44 | | Senior Vice President, Chief Financial Officer |
(e)Paul Davis | Of the approximately 4.0 million barrel aggregate shell capacity, approximately 3.0 million barrels are dedicated to crude and feedstock and approximately 1.0 million barrels are allocated to asphalt. | 59 | | President, Western Region |
| Thomas O’Connor | | 49 | | Senior Vice President, Commercial |
| Trecia Canty | | 52 | | Senior Vice President, General Counsel & Corporate Secretary |
| Steven Steach | | 65 | | Senior Vice President, Refining |
Thomas 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 PBF 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 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 PBF 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.
C. Erik Young has served as our Senior Vice President and Chief Financial Officer since April 2014 after joining us in December 2010 as Director, Strategic Planning where he was responsible for both corporate development and capital markets initiatives. Mr. Young is also a director of certain of our subsidiaries, including PBF GP. Prior to joining the Company, Mr. Young spent eleven years in corporate finance, strategic planning and mergers and acquisitions roles across a variety of industries. He began his career in investment banking before joining J.F. Lehman & Company, a private equity investment firm, in 2001.
Paul Davis has served as our President, PBF Western Region since September 2017. 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 products commercial operations for Hess Energy Trading Company from 2006 to 2012. Prior to that, Mr. Davis was responsible for Premcor’s U.S. Midwest clean products disposition group. Mr. Davis has over 29 years of experience in commercial operations in crude oil and refined products, including 16 years with the ExxonMobil in various operational and commercial positions, including sourcing refinery feedstocks and crude oil and the disposition of refined products, as well as optimization roles within refineries.
Thomas O’Connor has served as our Senior Vice President, Commercial since September 2015. 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.
Environmental, Health and Safety Matters
Our refineries, pipelines and related operations are subject to extensive and frequently changing federal, state and local laws and regulations, including, but not limited to, those relating to the discharge of materials into the environment or that otherwise relate to the protection of the environment, waste management and the characteristics and the compositions of fuels. Compliance with existing and anticipated laws and regulations can increase the overall cost of operating the refineries, including remediation, operating costs and capital costs to construct, maintain and upgrade equipment and facilities. Permits are also required under these laws for the operation of our refineries, pipelines and related operations and these permits are subject to revocation, modification and renewal. Compliance with applicable environmental laws, regulations and permits will continue to have an impact on our operations, results of operations and capital requirements. We believe that our current operations are in substantial compliance with existing environmental laws, regulations and permits.
We incorporate by reference into this Item the environmental disclosures contained in the following sections of this report:
•Item 1A. “Risk Factors”
◦ Our results of operations continue to be impacted by significant costs to comply with renewable fuels mandates. The market prices for RINs have been volatile and may harm our profitability;
◦ We may have capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate;
◦ We may incur significant liability under, or costs and capital expenditures to comply with, environmental and health and safety regulations, which are complex and change frequently;
◦ Potential further laws and regulations related to climate change could have a material adverse impact on our operations and adversely affect our facilities;
◦ Regulation of emissions of greenhouse gases could force us to incur increased capital expenditures and operating costs that could have a material adverse effect on our results of operations and financial condition;
◦ Environmental clean-up and remediation costs of our sites and environmental litigation could decrease our net cash flow, reduce our results of operations and impair our financial condition;
◦ Our pipelines are subject to federal and/or state regulations, which could reduce profitability and the amount of cash we generate;
◦ We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with health, safety, environmental and other laws and regulations;
◦ We are subject to strict laws and regulations regarding employee and process safety, and failure to comply with these laws and regulations could have a material adverse effect on our results of operations, financial condition and profitability.
•Item 3. “Legal Proceedings”,
•Item 8. “Financial Statements and Supplementary Data”
◦ Note 9 - Accrued Expenses,
◦ Note 12 - Other Long-Term Liabilities and
◦ Note 14 - Commitments and Contingencies
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 14 - Commitments and Contingencies
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 Related to the COVID-19 Pandemic
•The COVID-19 pandemic and its effects on our liquidity, business, financial condition and results of operations;
•Decline in demand for our refined products;
•Worsening of market conditions related to the COVID-19 pandemic.
Risks Relating to Our Business and Industry
•The price volatility of crude oil, other feedstocks, blendstocks, refined products and fuel and utility services;
•Volatility in commodity prices and refined product demand;
•Crude oil differentials and related factors, which fluctuate substantially;
•Significant interruptions or casualty losses at any of our refineries and related assets or logistics terminals, pipelines or other facilities;
•Interruptions of supply and distribution at our refineries;
•Renewable fuels mandates and the cost of RINs;
•Existence of capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate;
•Regulation of emissions of greenhouse gases and other environmental and health and safety regulations;
•Enhanced scrutiny on ESG matters;
•Volatility and uncertainty in the credit and capital markets;
•Any political instability, military strikes, sustained military campaigns, terrorist activity, changes in foreign policy, or other catastrophic events;
•A cyber-attack on, or other failure of, our technology infrastructure;
•Competition from companies who have not been adversely impacted as much as we have been by the COVID-19 pandemic;
•Delays or cost increases related to capital spending programs;
•Product liability and operational liability claims and litigation;
•Prospect that dividend payments may not be reinstated;
•Acquisition or integration of new assets into our business;
•Labor disruptions that would interfere with our operations;
•Discontinuation of employment of any of our senior executives or other key employees;
•Our activity in commodity derivatives markets.
Risks Related to Our Indebtedness
•Our substantial 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;
•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.
Risks Related to Our Ownership of PBFX
•Obligations for minimum volume commitments in our commercial agreements with PBFX;
•Potential tax consequences related to our involvement in PBFX.
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 Related to the COVID-19 Pandemic
The outbreak of the COVID-19 pandemic significantly and adversely affected our liquidity, business, financial condition and results of operations starting in the first quarter of 2020. While we have seen the demand for our products return in 2021, there can be no assurance that our liquidity, business, financial condition and results of operations will revert to pre-COVID-19 pandemic levels going forward.
The outbreak of the COVID-19 pandemic starting in the first quarter of 2020, negatively impacted, and may continue to impact, worldwide economic and commercial activity and financial markets. The COVID-19 pandemic, and variants thereof, and the related governmental responses resulted in significant business and operational disruptions, including business and school closures, supply chain disruptions, travel restrictions, stay-at-home orders and limitations on the availability of workforces, inclusive of mandatory quarantine periods, and has resulted in significantly lower global demand for refined petroleum and petrochemical products. Although demand for these products started to recover throughout the year ended December 31, 2021 following the lifting or easing of certain restrictions and the distribution of COVID-19 vaccines and other protective measures, there can be no assurance that future periods will not be negatively impacted by the continuing effect of the COVID-19 pandemic, including resurgences and variants of the virus.
In addition, the impact of the COVID-19 pandemic has created simultaneous shocks in oil supply and demand resulting in an economic challenge to our industry which has not occurred since our formation. It is impossible to estimate the duration or significance of the financial impact that will result from the COVID-19 pandemic. However, the extent of the impact of the COVID-19 pandemic on our business, financial condition, results of operations and liquidity will depend largely on future developments, including the duration and severity of the pandemic and variants thereof, particularly within the geographic areas where we operate, the effectiveness of vaccine programs, and the related impact on overall economic activity, all of which cannot be predicted with certainty at this time.
We continue to work with federal, state and local health authorities to respond to COVID-19 cases in the regions we operate and are taking or supporting measures to try to limit the spread of the virus and to mitigate the burden on the healthcare system. Many of these measures will continue to have an adverse impact on our business and financial results that we are not currently able to fully quantify. For example, we are carefully
evaluating projects and non-essential work at our refineries. Based on market conditions, our refineries have been operating at reduced rates, while constantly monitoring and adjusting our production to correlate to increases in product demand. We lowered our capital program for 2021 and will continue to plan to do so in 2022 as compared to historic levels. We have planned a level of capital expenditures we believe will allow us to satisfy and comply with all required safety, environmental and planned regulatory capital commitments and other regulatory requirements, although there are no assurances that we will be able to continue to do so. Non-compliance with applicable environmental and safety requirements, including as a result of reduced staff due to an outbreak at one of our refineries, may impair our operations, may subject us to fines or penalties assessed by governmental authorities and/or may result in an environmental or safety incident. We may also be subject to liability as a result of claims against us by impacted workers or third parties.
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 have adversely affected 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 in the case of the East Coast Refining Reconfiguration. There may be significant incremental costs associated with such actions. Further 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 persistence or worsening or market conditions related to the COVID-19 pandemic may require us to raise additional capital to meet our obligations and operate our business.
Our borrowing base under PBF Holding’s asset-based revolving credit facility (the “Revolving Credit Facility”) could be reduced if market conditions deteriorate or crude prices decrease significantly. Our borrowing base availability under the Revolving Credit Facility was $3,400.0 million as of December 31, 2021. If current market conditions return to levels experienced during the height of the COVID-19 pandemic, or worsen, we may require additional capital to meet our obligations as well as to operate our business, and additional financing and/or assets sales may not be possible on favorable terms or at all. Potential economic factors resulting from the COVID-19 pandemic, which could lead to increasing unemployment rates, substantially reduced travel and reduced business and consumer spending, could also affect our business.
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.
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, as we experienced in 2020, 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. Although we reduced our crude oil, feedstock and refined product inventories in 2020 to strengthen our financial position in response to the COVID-19 pandemic, inventory has slowly returned to normalized levels in 2021. 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. 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, reflecting the net change in the LCM inventory reserve from $401.6 million at December 31, 2019 to $669.6 million at December 31, 2020. At December 31, 2021, the replacement value of inventories exceeded the LIFO carrying value, therefore no LCM inventory reserve was recorded.
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 slightly 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.
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 as a result of our reliance on pipelines and railroads for transportation of crude oil and refined products.
Our Toledo, Chalmette, Torrance and Martinez refineries receive a significant portion of their crude oil through our owned, as well as third-party, pipelines. These pipelines include the Enbridge system, Capline and Mid-Valley pipelines for supplying crude to our Toledo refinery, the MOEM Pipeline (which is owned by our subsidiary) and CAM Pipeline for supplying crude to our Chalmette refinery and the San Joaquin Pipeline, San Pablo Bay Pipeline, San Ardo and Coastal Pipeline systems for supplying crude to our Torrance and Martinez refineries. Additionally, our Toledo, Chalmette, Torrance and Martinez refineries deliver a significant portion of the refined products through pipelines. These pipelines include pipelines such as the Sunoco Logistics Partners L.P. and Buckeye Partners L.P. pipelines at the Toledo refinery, the Collins pipeline (which is owned by our subsidiary) at our Chalmette refinery, the Jet Pipeline to the Los Angeles International Airport, the Product Pipeline to Vernon and the Product Pipeline to Atwood at our Torrance refinery and the KinderMorgan SFPP North Pipeline at our Martinez refinery. We could experience an interruption of supply or delivery, or an increased cost of receiving crude oil and delivering refined products to market, if the ability of these pipelines to transport crude oil or refined products is disrupted because of accidents, weather interruptions, governmental regulation, terrorism, other third-party action or casualty or other events.
The Delaware City rail unloading facilities and the assets acquired in connection with the PBFX 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.
In addition, 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.
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 Renewable Fuel Standard, implementing mandates to blend renewable fuels into the petroleum fuels produced and sold in the United States. Under the Renewable Fuel Standard, 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 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 2021 and could increase further in 2022. We incurred approximately $726.0 million in RINs costs during the year ended December 31, 2021 as compared to $326.4 million and $122.7 million during the years ended December 31, 2020 and 2019, 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. EPA’s proposed volumes of renewable fuels that obligated refineries must blend into their final petroleum fuels are expected to be finalized by the end of the first quarter of 2022. 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.
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, 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.
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. For example, on July 21, 2021, the board of Bay Area Air Quality Management District (“BAAQMD”) voted to adopt proposed 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 by 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.
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 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.
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. The N-79-20 Order encourages zero emissions technologies such as electric vehicles, and accelerated deployment of affordable fueling and charging options. It is currently uncertain how the N-79-20 Order may be ultimately implemented by various California regulatory agencies. In the event we do incur increased costs as a result of increased efforts to control GHG emissions through future adopted regulatory requirements, we may not be able to pass these costs to our customers. These future regulatory requirements also could adversely
affect demand for the refined products that we produce. Any increased costs or reduced demand could materially and adversely affect our business and results of operations.
Environmental clean-up and remediation costs of our sites and environmental litigation 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—Contractual Obligations and Commitments”.
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.
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.
We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with health, safety, environmental and other laws and regulations.
Our operations require numerous permits and authorizations under various laws and regulations. These authorizations and permits are subject to revocation, renewal or modification and can require operational changes to limit impacts or potential impacts on the environment and/or health and safety. A violation of authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions, and/or facility shutdowns. In addition, major modifications of our operations could require modifications to our existing permits or upgrades to our existing pollution control equipment. Any or all of these matters could have a negative effect on our business, results of operations and cash flows.
We may incur significant liabilities under, or costs and capital expenditures to comply with, health, safety, environmental and other laws and regulations, which are complex and change frequently. Our operations are subject to federal, state and local laws regulating, among other things, the handling of petroleum and other regulated materials, the emission and discharge of materials into the environment, waste management, and remediation of discharges of petroleum and petroleum products, characteristics and composition of gasoline and distillates and other matters otherwise relating to the protection of the environment. Our operations are also subject to extensive laws and regulations relating to occupational health and safety, in addition to laws and regulations affecting the transportation of crude oil by rail in North America.
We cannot predict what additional environmental, health and safety legislation or regulations may be adopted in the future, or how existing or future laws or regulations may be administered or interpreted with respect to our operations. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time.
Certain environmental laws impose strict, and in certain circumstances joint and several liability for, costs of investigation and cleanup of such spills, discharges or releases on owners and operators of, as well as persons who arrange for treatment or disposal of regulated materials at contaminated sites. Under these laws, we may incur liability or be required to pay penalties for past contamination, and third parties may assert claims against us for damages allegedly arising out of any past or future contamination. The potential penalties and clean-up costs for past or future releases or spills, the failure of prior owners of our facilities to complete their clean-up obligations, the liability to third parties for damage to their property, or the need to address newly-discovered information or conditions that may require a response could be significant, and the payment of these amounts could have a material adverse effect on our business, financial condition and results of operations.
Enhanced scrutiny on ESG matters may 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.
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 have experienced periods of extreme volatility that have negatively impacted market liquidity conditions, including as a result of the impact of the COVID-19 pandemic. As a result, the cost of raising money in the debt and equity capital markets has increased substantially at times while the availability of funds from those markets diminished 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.
Any political instability, military strikes, sustained military campaigns, terrorist activity, changes in foreign policy in areas or regions of the world where we acquire crude oil and other raw materials or sell our refined products may affect our business in unpredictable ways, including forcing us to increase security measures and causing disruptions of supplies and distribution markets. We may also be subject to United States trade and economic sanctions laws, which change frequently as a result of foreign policy developments, and which may necessitate changes to our crude oil acquisition activities. Further, like other industrial companies, our facilities may be the target of terrorist activities or subject to catastrophic events such as natural disasters and pandemic illness. Any act of war, terrorism, or other catastrophic events that resulted in damage to, or otherwise disrupts the operating activities of, any of our refineries or third-party facilities upon which we are dependent for our business operations could have a material adverse effect on our business, results of operations and financial condition.
A cyber-attack on, or other failure of, our technology infrastructure could affect our business and assets, and have a material adverse effect on our financial condition, results of operations and cash flows.
We are becoming increasingly dependent on our technology infrastructure and certain critical information systems which process, transmit and store electronic information, including information we use to safely and effectively operate our respective assets and businesses. These information systems include data network and telecommunications, internet access, our websites, and various computer hardware equipment and software applications, including those that are critical to the safe operation of our refineries and logistics assets. We have invested, and expect to continue to invest, significant time, manpower and capital in our technology infrastructure and information systems. These information systems are subject to damage or interruption from a number of potential sources including natural disasters, software viruses or other malware, power failures, cybersecurity threats to gain unauthorized access to sensitive information, cyber-attacks, which may render data systems unusable, and physical threats to the security of our facilities and infrastructure. Additionally, our business is highly dependent on financial, accounting and other data processing systems and other communications and information systems, including our enterprise resource planning tools. We process a large number of transactions on a daily basis and rely upon the proper functioning of computer systems. Furthermore, we rely on information systems across our respective operations, including the management of supply chain and various other processes and transactions. As a result, a disruption on any information systems at our refineries or logistics assets, may cause disruptions to our collective operations.
The potential for such security threats or system failures has subjected our operations to increased risks that could have a material adverse effect on our business. To the extent that these information systems are under our control, we have implemented measures such as virus protection software, emergency recovery processes and a formal disaster recovery plan to address the outlined risks. However, security measures for information systems cannot be guaranteed to be failsafe, and our formal disaster recovery plan and other implemented measures may not prevent delays or other complications that could arise from an information systems failure. If a key system were hacked or otherwise interfered with by an unauthorized user, or were to fail or experience unscheduled downtime for any reason, even if only for a short period, or any compromise of our data security or our inability to use or access these information systems at critical points in time, it could unfavorably impact the timely and efficient operation of our business, damage our reputation and subject us to additional costs and liabilities. The increase in companies and individuals working remotely has increased the frequency and scope of cyber-attacks and the risk of potential cybersecurity incidents, both deliberate attacks and unintentional events. While, to date, we have not had a significant cybersecurity breach or attack that had a material impact on our business or results of operations, if we were to be subject to a material successful cyber intrusion, it could result in remediation or service restoration costs, increased cyber protection costs, lost revenues, litigation or regulatory actions by governmental authorities, increased insurance premiums, reputational damage and damage to our competitiveness, financial condition, results of operations and cash flows.
Cyber-attacks against us or others in our industry could result in additional regulations, and U.S. government warnings have indicated that infrastructure assets, including pipelines, may be specifically targeted by certain groups. These attacks include, without limitation, malicious software, ransomware, attempts to gain unauthorized access to data, and other electronic security breaches. These attacks may be perpetrated by state-sponsored groups, “hacktivists”, criminal organizations or private individuals (including employee malfeasance). Current efforts by the federal government, including the Strengthening the Cybersecurity of Federal Networks and Critical Infrastructure executive order, the issuance of new cybersecurity requirements for critical pipeline owners and operators issued by the Department of Homeland Security’s Transportation Security Administration following a cyber-attack on a major petroleum pipeline in 2021, and any potential future regulations could lead to increased regulatory compliance costs, insurance coverage cost or capital expenditures. We cannot predict the potential impact to our business or the energy industry resulting from additional regulations.
Further, our business interruption insurance may not compensate us adequately for losses that may occur. We do not carry insurance specifically for cybersecurity events; however, certain of our insurance policies may allow for coverage for a cyber-event resulting in ensuing property damage from an otherwise insured peril. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, results of operations and cash flows. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.
Competition from companies who have not been adversely impacted as much as we have been by the COVID-19 pandemic, 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. Many of our competitors have not been adversely impacted by the COVID-19 pandemic as much as we have been impacted. Certain of our competitors have larger and more complex refineries, and may be able to realize lower per-barrel costs or higher margins per barrel of throughput. Several of our principal competitors are integrated national or international oil companies that are larger and have substantially greater resources than we do and access to proprietary sources of controlled crude oil production. Unlike these competitors, we obtain substantially all of our feedstocks from unaffiliated sources. We are not engaged in the petroleum exploration and production business and therefore do not produce any of our crude oil feedstocks. We do not have a retail business and therefore are dependent upon others for outlets for our refined products. Because of their integrated operations and larger capitalization, these companies may be more flexible in responding to volatile industry or market conditions, such as shortages of crude oil supply and other feedstocks or intense price fluctuations and they may also be able to obtain more favorable trade credit terms.
Newer or upgraded refineries will often be more efficient than our refineries, which may put us at a competitive disadvantage. We have taken significant measures to maintain our refineries including the installation of new equipment and redesigning older equipment to improve our operations. However, these actions involve significant uncertainties, since upgraded equipment may not perform at expected throughput levels, the yield and product quality of new equipment may differ from design specifications and modifications may be needed to correct equipment that does not perform as expected. Any of these risks associated with new equipment, redesigned older equipment or repaired equipment could lead to lower revenues or higher costs or otherwise have an adverse effect on future results of operations and financial condition. Over time, our refineries or certain refinery units may become obsolete, or be unable to compete, because of the construction of new, more efficient facilities by our competitors.
We must make substantial capital expenditures on our operating facilities to maintain their reliability and efficiency. If we are unable to complete capital projects at their expected costs and/or in a timely manner, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations or cash flows could be materially and adversely affected.
Delays or cost increases related to capital spending programs involving engineering, procurement and construction of new facilities (or improvements and repairs to our existing facilities and equipment, including turnarounds) could adversely affect our ability to achieve targeted internal rates of return and operating results. Such delays or cost increases may arise as a result of unpredictable factors in the marketplace, many of which are beyond our control, including:
•denial or delay in obtaining regulatory approvals and/or permits;
•unplanned increases in the cost of construction materials or labor;
•disruptions in transportation of modular components and/or construction materials;
•severe adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors and suppliers;
•shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
•market-related increases in a project’s debt or equity financing costs; and/or
•non-performance or force majeure by, or disputes with, vendors, suppliers, contractors or sub-contractors involved with a project.
Our refineries contain many processing units, a number of which have been in operation for many years. Equipment, even if properly maintained, may require significant capital expenditures and expenses to keep it operating at optimum efficiency. One or more of the units may require unscheduled downtime for unanticipated maintenance or repairs that are more frequent than our scheduled turnarounds for such units. Scheduled and unscheduled maintenance could reduce our revenues during the period of time that the units are not operating.
Our forecasted internal rates of return are also based upon our projections of future market fundamentals, which are not within our control, including changes in general economic conditions, 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.
PBF Energy has suspended its quarterly dividend and does not anticipate that it will declare dividends in the foreseeable future.
On March 30, 2020, PBF Energy announced that it has suspended its quarterly cash dividend of $0.30 per share on its Class A common stock, as part of its strategic plan to respond to the impact of the COVID-19 outbreak and related market activity. 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). Any future declaration, amount and payment of any dividends will be at the sole discretion of our Board of Directors, however, because the impact of the COVID-19 outbreak and related market activity is difficult to predict, we do not anticipate that our Board of Directors will determine to declare a dividend in the foreseeable future. Our Board of Directors 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 Board of Directors 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.
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 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 are continuously being enacted or proposed that 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.
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. Certain of these agreements have expired while others are scheduled to expire on various dates in 2022 through 2024 (See “Item 1. Business” - Employees). For the agreements that expired, terms related to new collective bargaining agreements have been agreed to on local bargaining issues and are pending settlement of the National Oil Bargaining Program which will set contract term, wages, health care contributions and any other agreed upon issues prior to being executed.During this interim period, the terms of the expired agreements will remain in place under rolling 24-hour extensions until new agreements are finalized. Future negotiations prior to the expiration of our collective agreements may result in labor unrest for which a strike or work stoppage is possible. Strikes and/or work stoppages could negatively affect our operational and financial results and may increase operating expenses at the refineries.
Our business may suffer if any of our senior executives or other key employees discontinues employment with us. Furthermore, a shortage of skilled labor or disruptions in our labor force may make it difficult for us to maintain labor productivity.
Our future success depends to a large extent on the services of our senior executives and other key employees. Our business depends on our continuing ability to recruit, train and retain highly qualified employees in all areas of our operations, including engineering, accounting, business operations, finance and other key back-office and mid-office personnel. Furthermore, our operations require skilled and experienced employees with proficiency in multiple tasks. The competition for these employees is intense, and the loss of these executives or employees could harm our business. If any of these executives or other key personnel resigns or becomes unable to continue in his or her present role and is not adequately replaced, our business operations could be materially adversely affected.
Our hedging activities may limit our potential gains, exacerbate potential losses and involve other risks.
We may enter into commodity derivatives contracts to hedge our crude price risk or crack spread risk with respect to a portion of our expected gasoline and distillate production on a rolling basis or to hedge our exposure to the price of natural gas, which is a significant component of our refinery operating expenses. Consistent with that policy we may hedge some percentage of our future crude and natural gas supply. We may enter into hedging arrangements with the intent to secure a minimum fixed cash flow stream on the volume of products hedged during the hedge term and to protect against volatility in commodity prices. Our hedging arrangements may fail to fully achieve these objectives for a variety of reasons, including our failure to have adequate hedging arrangements, if any, in effect at any particular time and the failure of our hedging arrangements to produce the anticipated results. We may not be able to procure adequate hedging arrangements due to a variety of factors. Moreover, such transactions may limit our ability to benefit from favorable changes in crude oil, refined product and natural gas prices.
In addition, our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which:
•the volumes of our actual use of crude oil or natural gas or production of the applicable refined products is less than the volumes subject to the hedging arrangement;
•accidents, interruptions in feedstock transportation, inclement weather or other events cause unscheduled shutdowns or otherwise adversely affect our refineries, or those of our suppliers or customers;
•changes in commodity prices have a material impact on collateral and margin requirements under our hedging arrangements, resulting in us being subject to margin calls;
•the counterparties to our derivative contracts fail to perform under the contracts; or
•a sudden, unexpected event materially impacts the commodity or crack spread subject to the hedging arrangement.
As a result, the effectiveness of our hedging strategy could have a material impact on our financial results. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”
In addition, these hedging activities involve basis risk. Basis risk in a hedging arrangement occurs when the price of the commodity we hedge is more or less variable than the index upon which the hedged commodity is based, thereby making the hedge less effective. For example, a New York Mercantile Exchange index used for hedging certain volumes of our crude oil or refined products may have more or less variability than the actual cost or price we realize for such crude oil or refined products. We may not hedge all the basis risk inherent in our hedging arrangements and derivative contracts.
Our commodity derivative activities could result in period-to-period earnings volatility.
We do not currently apply hedge accounting to any of our commodity derivative contracts and, as a result, unrealized gains and losses will be charged to our earnings based on the increase or decrease in the market value of such unsettled positions. These gains and losses may be reflected in our income statement in periods that differ from when the settlement 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 substantial 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, 2021, we have total debt of $4,330.8 million, excluding unamortized deferred debt issuance costs of $35.0 million and our PBF LLC Affiliate note payable with PBF Energy that eliminates in consolidation at the PBF Energy level, and we could incur additional borrowings under our credit facilities. We may incur additional indebtedness in the future including additional secured indebtedness, subject to the satisfaction of any debt incurrence and, if applicable, lien incurrence limitation covenants in our existing financing agreements. Although we were in compliance with incurrence covenants during the year ended December 31, 2021, 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 stock or incur new liens.
The level of our indebtedness has several important consequences for our future operations, including that:
•a portion of our cash flow from operations will be dedicated to the payment of principal of, and interest on, our indebtedness and will not be available for other purposes;
•under certain circumstances, covenants contained in our existing debt arrangements limit our ability to borrow additional funds, dispose of assets and make certain investments;
•in certain circumstances these covenants also require us to meet or maintain certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our industry, such as being able to take advantage of acquisition opportunities when they arise;
•our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited; and
•we may be at a competitive disadvantage to those of our competitors that are less leveraged; and we may be more vulnerable to adverse economic and industry conditions.
Our indebtedness increases the risk that we may default on our debt obligations, certain of which contain cross-default and/or cross-acceleration provisions. Our, and our subsidiaries’, ability to meet future principal obligations will be dependent upon our future performance, which in turn will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our business may not continue to generate sufficient cash flow from operations to repay our indebtedness. If we are unable to generate sufficient cash flow from operations, we may be required to sell assets, to refinance all or a portion of our indebtedness or to obtain additional financing. Refinancing may not be possible and additional financing may not be available on commercially acceptable terms, or at all.
We may not be able to secure necessary financing on acceptable terms, or at all.
We currently have notes outstanding with varying maturity dates beginning in 2023 and ending in 2028. Additionally, our most significant credit facilities - the Revolving Credit Facility and the PBFX amended and restated revolving credit facility (the “PBFX Revolving Credit Facility”) - both have maturity dates in 2023. We can make no assurance that we will be able to refinance our outstanding indebtedness on acceptable terms prior to their maturity dates. Market disruptions, such as those experienced in relation to the COVID-19 pandemic, may increase our cost of borrowing or adversely affect our ability to refinance our obligations as they become due. Further, ESG concerns and other pressures on the oil and gas industry could lead to increased costs of financing or limit our access to the capital markets. If we are unable to refinance our indebtedness or access additional credit, or if short-term or long-term borrowing costs significantly increase, our ability to finance current operations and meet our short-term and long-term obligations could be adversely affected.
Despite our substantial 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 current debt levels, the leverage risks described above would increase. Also, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness.
Our future credit ratings could adversely affect our business, the cost of our borrowing, and our ability to obtain credit in the future.
Changes in our credit profile could affect the way crude oil and other suppliers view our ability to make payments and induce them to shorten the payment terms for our purchases or require us to post security or letters of credit prior to payment. Due to the large dollar amounts and volume of our crude oil and other feedstock purchases, any imposition by these suppliers of more burdensome payment terms on us may have a material adverse effect on our liquidity and our ability to make payments to our suppliers. This, in turn, could 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 Caa1 by Moody’s, B by S&P, and B- by Fitch. The 9.25% senior secured notes due 2025 (the “2025 Senior Secured Notes”) are rated B2 by Moody’s, BB- by S&P, and BB by Fitch. The 6.875% PBFX senior notes due 2023 (the “PBFX 2023 Senior Notes”) are rated B3 by Moody’s, B by S&P, and B+ by Fitch. During 2021, Moody’s and S&P downgraded our corporate family rating as well as our unsecured and secured notes ratings, with all ratings on negative outlook. If the current market conditions persist or deteriorate, we expect that the credit rating agencies will continue to re-evaluate our corporate credit rating and the ratings of our unsecured and secured notes. Adverse changes in our credit ratings may also negatively impact the terms of credit we receive from our suppliers and require us to prepay or post collateral. Further adverse actions taken by the rating agencies on our corporate credit rating or the rating of our notes may further 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.
Restrictive covenants in our debt instruments, including the indentures governing our notes, may limit our ability to undertake certain types of transactions, which could adversely affect our business, financial condition, results of operations and our ability to service our indebtedness.
Various covenants in our current and future debt instruments and other financing arrangements, including the indentures governing our notes, may restrict our and our subsidiaries’ financial flexibility in a number of ways. Our current indebtedness and the indentures that govern our notes subject us to significant financial and other restrictive covenants, including restrictions on our ability to incur additional indebtedness, place liens upon assets, 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 our debt instruments also require our subsidiaries to satisfy or maintain certain financial condition tests in certain circumstances. Our ability to meet these financial condition tests can be affected by events beyond our control and we may not meet such tests. In addition, a failure to comply with the provisions of our existing debt could result in an event of default that could enable our lenders, subject to the terms and conditions of such debt, to declare the outstanding principal, together with accrued interest, to be immediately due and payable. Events beyond our control, including the impact of the COVID-19 pandemic and related governmental responses and developments in the global oil markets, 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, the 2025 Senior Secured Notes, the 2028 Senior Notes and the PBFX 2023 Senior Notes, holders of our notes could require us to repurchase all outstanding notes at 101% of the principal amount thereof, plus accrued and unpaid interest, if any, at the date of repurchase. Certain other significant agreements of ours such as our agreement governing the Revolving Credit Facility (the “Revolving Credit Agreement”), Tax Receivable Agreement (as defined below) and the Third Intermediation Agreement with J. Aron also contain provisions related to a change in control that could make it more difficult or expensive for a third-party to acquire us.
Risks Related to Our Organizational Structure 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.
The Revolving Credit Facility, the 2028 Senior Notes, the 2025 Senior Notes, the 2025 Senior Secured 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. PBFX Revolving Credit Facility and PBFX’s indenture governing its PBFX 2023 Senior Notes also contain 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 2022 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.
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.”
PBF Energy has recognized, as of December 31, 2021, a liability for the Tax Receivable Agreement of $48.3 million, reflecting the estimated undiscounted amounts that PBF Energy expects to pay under the agreement, net of a deferred tax asset valuation allowance recognized in accordance with FASB Accounting Standards Codification (“ASC”) 740, Income Taxes (“ASC 740”). As future taxable income is recorded, increases in our Tax Receivable Agreement liability may be necessary in conjunction with the revaluation of 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 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 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 the 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. 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.
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 Service 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.
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 Board of Directors, the chief executive officer or the Board of 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.
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, which could cause the value of your investment to decline.
The market price of PBF Energy Class A common stock may be highly volatile and subject to wide fluctuations due to a number of factors including:
•market conditions in the oil refining industry and volatility in commodity prices and the ongoing impact of COVID-19;
•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 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.
Our current stockholders could experience dilution, which could further depress the price of our Class A common stock.
We continue to require substantial working 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 shares of Class A common stock. As a result, stockholders may experience substantial dilution, and the 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 our Class A common stock, into the market or the perception that these sales could occur. Sales of a large number of shares of our Class A common stock, or securities convertible into or exchangeable or exercisable for our Class A common stock, or the possibility that these sales may occur, also might make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. In addition, any equity securities we issue may have rights, preferences or privileges senior to those of our Class A common stock, and our current debt agreements contain, and any agreements for future debt or preferred equity financings, if available, are likely to contain, covenants limiting or restricting our ability to take specific actions, such as incurring additional debt. Holders of Class A common stock are not entitled to preemptive rights or other protections against dilution. Because our decision to issue securities in any future offering will depend on our capital needs as well as market conditions and other factors beyond om control, we cannot predict or estimate the amount, timing, nature or impact of future issuances, if any. Our Class A common stockholders bear the risk of our future offerings reducing the per share market price of our Class A common stock.
Risks Related to Our Ownership of PBFX
We depend upon PBFX for a substantial portion of our refineries’ logistics needs and have obligations for minimum volume commitments in our commercial agreements with PBFX.
We depend on PBFX to receive, handle, store and transfer crude oil, petroleum products and natural gas for us from our operations and sources located throughout the United States and Canada in support of certain of our refineries under long-term, fee-based commercial agreements with our subsidiaries. These commercial agreements have an initial term ranging from one to fifteen years and generally include minimum quarterly commitments and inflation escalators. If we fail to meet the minimum commitments during any calendar quarter, we will be required to make a shortfall payment quarterly to PBFX equal to the volume of the shortfall multiplied by the applicable fee.
PBFX’s operations are subject to all of the risks and operational hazards inherent in receiving, handling, storing and transferring crude oil, petroleum products and natural gas, including: damages to its facilities, related equipment and surrounding properties caused by floods, fires, severe weather, explosions and other natural disasters and acts of terrorism; mechanical or structural failures at PBFX’s facilities or at third-party facilities on which its operations are dependent; curtailments of operations relative to severe seasonal weather; inadvertent damage to our facilities from construction, farm and utility equipment; and other hazards. Any of these events or factors could result in severe damage or destruction to PBFX’s assets or the temporary or permanent shut-down of PBFX’s facilities. If PBFX is unable to serve our logistics needs, our ability to operate our refineries and receive crude oil and distribute products could be adversely impacted, which could adversely affect our business, financial condition and results of operations.
In addition, as of December 31, 2021, PBF LLC owns 29,953,631 common units representing 47.9% limited partner interest in PBFX. The inability of PBFX to continue operations, perform under its commercial arrangements with our subsidiaries or the occurrence of any of these risks or operational hazards, could also adversely impact the value of our investment in PBFX and, because PBFX is a consolidated entity, our business, financial condition and results of operations.
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 to PBF Energy on account of its indirect interest in PBFX may not be sufficient for PBF Energy to pay the amount of taxes it will owe on account of its indirect interests in PBFX.
If PBFX was to be treated as a corporation, rather than as a partnership, for U.S. federal income tax purposes or if PBFX was otherwise subject to entity-level taxation, PBFX’s cash available for distribution to its unitholders, including to us, would be reduced, likely causing a substantial reduction in the value of units, including the units held by us.
The present U.S. federal income tax treatment of publicly-traded partnerships, including PBFX, or an investment in its common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time the U.S. Congress considers substantive changes to the existing federal income tax laws that would affect publicly-traded partnerships. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for PBFX to meet the exception to be treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in PBFX common units.
If PBFX were treated as a corporation for U.S. federal income tax purposes, it would pay U.S. federal income tax on income at the corporate tax rate, which is currently a maximum of 21% under the TCJA, and would likely be liable for state income tax at varying rates. Distributions to PBFX unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to PBFX unitholders. Because taxes would be imposed upon PBFX as a corporation, the cash available for distribution to PBFX unitholders would be substantially reduced. Therefore, PBFX’s treatment as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to PBFX unitholders, likely causing a substantial reduction in the value of the units.
All of the executive officers and a majority of the directors of PBF GP are also current or former officers or directors of PBF Energy. Conflicts of interest could arise as a result of this arrangement.
PBF Energy indirectly owns and controls PBF GP, and appoints all of its officers and directors. All of the executive officers and a majority of the directors of PBF GP are also current or former officers or directors of PBF Energy. These individuals will devote significant time to the business of PBFX. Although the directors and officers of PBF GP have a fiduciary duty to manage PBF GP in a manner that is beneficial to PBF Energy, as directors and officers of PBF GP they also have certain duties to PBFX and its unitholders. Conflicts of interest may arise between PBF Energy and its affiliates, including PBF GP, on the one hand, and PBFX and its unitholders, on the other hand. In resolving these conflicts of interest, PBF GP may favor its own interests and the interests of PBFX over the interests of PBF Energy. In certain circumstances, PBF GP may refer any conflicts of interest or potential conflicts of interest between PBFX, on the one hand, and PBF Energy, on the other hand, to its conflicts committee (which must consist entirely of independent directors) for resolution, which conflicts committee must act in the best interests of the public unitholders of PBFX. As a result, PBF GP may manage the business of PBFX in a way that may differ from the best interests of PBF Energy or its stockholders.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
See “Item 1. Business”.
ITEM 3. LEGAL PROCEEDINGS
On December 28, 2016, DNREC issued the Ethanol Permit to DCR allowing the utilization of existing tanks and existing marine loading equipment at their existing facilities to enable denatured ethanol to be loaded from storage tanks to marine vessels and shipped to offsite facilities. On January 13, 2017, the issuance of the Ethanol Permit was appealed by two environmental groups. On February 27, 2017, the Coastal Zone Industrial Control Board (the “Coastal Zone Board”) held a public hearing and dismissed the appeal, determining that the appellants did not have standing. The appellants filed an appeal of the Coastal Zone Board’s decision with the Delaware Superior Court (the “Superior Court”) on March 30, 2017. On January 19, 2018, the Superior Court rendered an Opinion regarding the decision of the Coastal Zone Board to dismiss the appeal of the Ethanol Permit for the ethanol project. The judge determined that the record created by the Coastal Zone Board was insufficient for the Superior Court to make a decision, and therefore remanded the case back to the Coastal Zone Board to address the deficiency in the record. Specifically, the Superior Court directed the Coastal Zone Board to address any evidence concerning whether the appellants’ claimed injuries would be affected by the increased quantity of ethanol shipments. On remand, the Coastal Zone Board met on January 28, 2019 and reversed its previous decision on standing ruling that the appellants have standing to appeal the issuance of the Ethanol Permit. The parties to the action filed a joint motion with the Coastal Zone Board, requesting that the Coastal Zone Board concur with the parties’ proposal to secure from the Superior Court confirmation that all rights and claims are preserved for any subsequent appeal to the Superior Court, and that the matter then be scheduled for a hearing on the merits before the Coastal Zone Board. The Coastal Zone Board notified the parties in January of 2020 that it concurred with the parties’ proposed course of action. The appellants and DCR subsequently filed a motion with the Superior Court requesting relief consistent with what was described to the Coastal Zone Board. In March of 2020, the Superior Court issued a letter relinquishing jurisdiction over the matter, and concurring with the parties’ proposal to allow the case to proceed to a hearing on the merits before the Coastal Zone Board. The parties must now jointly propose to the Coastal Zone Board a schedule for prehearing activity and a merits hearing to resolve the matter. The parties must, therefore, submit to the Coastal Zone Board a joint proposed schedule to govern future proceedings related to the merits hearing to resolve the matter.
On September 11, 2020, DCR received two Citations and Notification of Penalties, with sub-parts, from OSHA related to a combustion incident occurring on March 11, 2020. The citation seeks to impose penalties in the amount of $401,923 related to alleged violations of the Occupation Safety and Health Act of 1970. An informal conference with OSHA on October 2, 2020 was unsuccessful in resolving the matter, and, as a result, DCR filed a Notice of Contest with OSHA contesting the citations in their entirety at the end of the informal conference. OSHA filed its Complaint on December 13, 2020, and DCR filed its response on January 4, 2021. OSHA and DCR participated in mandatory meditation on February 2, 2021, which was unsuccessful. On February 25, 2021, the Occupational Safety and Health Review Commission granted the parties’ Joint Motion for Additional Time for the Parties to Discuss Settlement. The Court has since granted multiple additional extensions. On May 27, 2021, the parties notified the court that settlement negotiations are continuing and have continued to provide updates on the settlement negotiations. Subsequently, OSHA and DCR reached a settlement agreement with an assessed penalty of $401,923 and DCR agreed to undertake certain abatement measures. On January 24, 2022, DCR and the United Steelworkers signed the settlement agreement, and on January 25, 2022, OSHA executed the agreement.
On September 27, 2021, DCR received a Notice of Administrative Penalty Assessment and Secretary’s Order from DNREC, seeking to impose penalties in the amount of $285,000 related to alleged Title V permit violations occurring in 2019 and 2020. On October 15, 2021, DCR filed a Notice of Appeal before Delaware’s Environmental Appeals Board, contesting the Secretary’s findings and requesting a hearing. On November 2, 2021, the Environmental Appeals Board scheduled a Pre-Hearing Conference for April 8, 2022 and Hearing Date for April 26, 2022. On November 30, 2021, settlement negotiations commenced, which are continuing to date.
In connection with the acquisition of the Torrance refinery and related logistics assets, we assumed certain pre-existing environmental liabilities related to certain environmental remediation obligations to address existing soil and groundwater contamination and monitoring activities, which reflect the estimated cost of the remediation obligations. In addition, in connection with the acquisition of the Torrance refinery and related logistics assets, we purchased a ten-year, $100.0 million environmental insurance policy to insure against unknown environmental liabilities.
Subsequent to the acquisition, Notices of Violations (“NOVs”) were issued by the South Coast Air Quality Management District (“SCAQMD”), Division of Occupational Safety and Health of the State of California, the City of Torrance, the City of Torrance Fire Department, and the Los Angeles County Sanitation District related to alleged operational violations, emission discharges and/or flaring incidents at the refinery and the logistics assets both before and after our acquisition. EPA in November 2016 conducted a Risk Management Plan (“RMP”) inspection following the acquisition related to Torrance operations and issued preliminary findings in March 2017 concerning RMP potential operational violations. Effective January 9, 2020, we and EPA entered into a Consent Agreement and Final Order (“CAFO”), which contains no admission by us for any alleged violations in the CAFO, includes a release from all alleged violations in the CAFO, requires the payment of a penalty of $125,000 in January 2020 and also requires the implementation of a supplemental environmental project (“SEP”) of at least $219,000 that must be completed by December 15, 2021. The SEP consisted of configuring the northeast fire water monitor to automatically deploy water upon detection of a release. We completed this reconfiguration on December 15, 2021 and expended at least $219,000 as required by the CAFO. On February 11, 2022, we submitted the final SEP Completion Report to EPA, which should fully resolve this matter.
EPA and the California Department of Toxic Substances Control (“DTSC”) in December 2016 conducted a Resource Conservation and Recovery Act (“RCRA”) inspection following the acquisition related to Torrance operations and also issued in March 2017 preliminary findings concerning RCRA potential operational violations. On June 14, 2018, the Torrance refinery and DTSC reached settlement regarding the oil bearing materials. Following this settlement, in June 2018, DTSC referred the remaining alleged RCRA violations from EPA’s and DTSC’s December 2016 inspection to the California Attorney General. On April 7, 2021, we were notified that these alleged remaining six federal RCRA violations had been referred to EPA for resolution. On June 2, 2021, EPA conducted a further inspection to the December 2016 RCRA inspection. On August 13, 2021, we received EPA’s additional report indicating that the six federal RCRA findings were closed with no further enforcement action. The remaining alleged state RCRA violation is still pending with the California Attorney General.
On February 4, 2021, we received a letter from the SCAQMD proposing to settle a NOV relating to 15 Title V deviations alleged to have occurred in the second half of 2017 for $1.3 million. On October 8, 2021, we reached settlement in principle with the SCAQMD to pay a penalty of $250,000 for 14 of the Title V deviations and a penalty of $1.3 million for the remaining deviation, which covers the period of 2017 through 2021 and settlement agreements are in process.
On December 4, 2020, the Pennsylvania Department of Environmental Protection ("PaDEP") issued a draft Consent Order and Agreement (“CAO”) to PBF Logistics Products Terminals LLC (“PLPT”) with respect to two alleged violations at the Philadelphia terminal for failure to: 1) test and inspect regulated piping as required in accordance with industry standards; and 2) have a professional engineering certification that all above ground storage tanks meet the applicable performance standards and requirements as a result of an alleged release of oil on January 10, 2020 into the Schuylkill River resulting from a pipe leak that was not contained by emergency containment structure. The draft order included a proposed penalty of $800,000. On December 15, 2021, we entered into a final CAO and agreed to pay the $800,000 penalty. Under the final CAO, we capped our future liability at $250,000 if PaDEP brought a subsequent enforcement action under the Pennsylvania Clean Streams Law (“CSL”) for environmental damage allegedly caused by the release of oil from PLPT’s operational violations. Under the final CAO, we also reserved our rights to challenge any subsequent enforcement action brought by PaDEP under the CSL. On January 13, 2022, we received from
PaDEP, a Consent Assessment of Civil Penalty alleging violations under the CSL of over $1.0 million. However, because of the CAO cap, the PaDEP’s penalty demand to settle these alleged violations is $250,000. We are currently reviewing the alleged violations and settlement offer.
In connection with self-reported flaring events that occurred at the Paulsboro Refinery between 2016 and 2020, in October 2021, the New Jersey Department of Environmental Protection (“NJDEP”) initiated discussions with PRC regarding potential penalties for alleged violations related to the self-reported flaring events. Although a formal NOV has not been issued, NJDEP provided a calculation sheet of potential penalties totaling approximately $1.6 million. We are currently challenging certain of those potential penalties and are in discussions with NJDEP regarding a potential settlement.
As the ultimate outcomes of the 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.
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 and alleges negligence, strict liability, ultra-hazardous activity, a continuing private nuisance, a permanent private nuisance, a continuing public nuisance, a permanent public nuisance and trespass resulting from the February 18, 2015 electrostatic precipitator (“ESP”) 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 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 to file a Second Amended Complaint alleging groundwater contamination. With the filing of the Second Amended Complaint, plaintiffs added an additional 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. All other dates are stayed pending the Court issuing its order. 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, 2018, in Jeprece Roussell, et al. v. PBF Consultants, LLC, et al., the plaintiff filed an action in the 19th Judicial District Court for the Parish of East Baton Rouge, alleging numerous causes of action, including wrongful death, premises liability, negligence, and gross negligence against PBF Holding, PBFX Operating Company LLC, Chalmette Refining, two individual employees of the Chalmette refinery (the defendants), two entities, PBF Consultants, LLC and PBF Investments that are Louisiana companies that are not associated with our companies, as well as Clean Harbors, Inc. and Clean Harbors Environmental Services, Inc. (collectively, “Clean Harbors”), Mr. Roussell’s employer. Mr. Roussell was fatally injured on March 31, 2018 while employed by Clean Harbors and performing clay removal work activities inside a clay treating vessel located at the Chalmette refinery. Plaintiff sought unspecified compensatory damages for pain and suffering, past and future mental anguish, impairment, past and future economic loss, attorney’s fees and court costs. On October 8, 2021, we and our insurers reached an agreement in principle to settle this litigation and the related matters. Our portion of the settlement was accrued as of September 30, 2021 and did not have a material impact on our financial position, results of operations, or cash flows. Settlement documents have been executed and payments have been made. A Motion to Dismiss with Prejudice was filed by the parties on February 3, 2022.
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 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. We presently believe the outcome will not have a material impact on our financial position, results of operations, or cash flows.
We are subject to obligations to purchase RINs. On February 15, 2017, we received notification that EPA records indicated that PBF Holding used potentially invalid RINs that were in fact verified under EPA’s RIN Quality Assurance Program (“QAP”) by an independent auditor as QAP A RINs. Under the regulations use of potentially invalid QAP A RINs provides the user with an affirmative defense from civil penalties provided certain conditions are met. We have asserted the affirmative defense and if accepted by EPA will not be required to replace these RINs and will not be subject to civil penalties under the program. It is reasonably possible that EPA will not accept our defense and may assess penalties in these matters, but any such amount is not expected to have a material impact on our financial position, results of operations, or cash flows.
The federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances. Under CERCLA, such persons may be subject to joint and several liability for investigation and the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. As discussed more fully above, certain of our sites are subject to these laws and we may be held liable for investigation and remediation costs or claims for natural resource damages. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Analogous state laws impose similar responsibilities and liabilities on responsible parties. In our current normal operations, we have generated waste, some of which falls within the statutory definition of a “hazardous substance” and some of which may have been disposed of at sites that may require cleanup under Superfund.
ITEM 4. MINE SAFETY DISCLOSURES
None.
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 Energy Class B common stock is not publicly-traded.
As of February 10, 2022 there were 31 holders of record of PBF Energy Class A common stock and 15 holders of record of PBF Energy Class B common stock.
Dividend and Distribution Policy
PBF Energy
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 2025 Senior Secured Notes, the 2028 Senior Notes, the 2025 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.
While it is impossible to estimate the duration or ultimate financial impact of the COVID-19 pandemic on our business, our results have been adversely impacted. As part of our strategic plan to navigate these current extraordinary and volatile markets, we have suspended PBF Energy’s quarterly dividend on its Class A common stock. We will continue to monitor and evaluate our dividend policy as market conditions develop and our business outlook becomes clearer, however, we do not anticipate that our Board of Directors will declare a dividend in the foreseeable future.
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).
PBF Logistics LP
Due to the uncertainty of the full impact of the COVID-19 pandemic will have on its business, PBFX has decided to reduce their quarterly distribution to its minimum quarterly distribution of $0.30 per unit, which represents a shift in its distribution strategy to build cash flow coverage, de-lever the business and strengthen its financial resources as they continue to pursue potential organic growth projects or strategic acquisition opportunities. PBFX intends to continue to pay at least the minimum quarterly distribution to the holders of its common units, including PBF LLC, of at least $0.30 per unit per quarter, or $1.20 per unit on an annualized basis, to the extent PBFX has sufficient cash from operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to PBFX’s general partner. However, there is no guarantee that PBFX will pay the minimum quarterly distribution or any amount on the units they 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.
During 2020, PBF Energy announced that it had suspended its quarterly dividend of $0.30 per share on its Class A common stock as part of its strategic plan to respond to the impact of the COVID-19 outbreak. As a result, there were no dividends or distributions for the year ended December 31, 2021. There were no tax distributions to PBF LLC’s other members in 2021. PBF Holding made $2.7 million in distributions to PBF LLC during the year ended December 31, 2021. In addition, PBFX made aggregate quarterly distributions of $76.0 million ($1.20 per unit) during the year ended December 31, 2021 to holders of its common units, of which $35.9 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.
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.
This performance graph and the related textual information are based on historical data and are not indicative of future performance. The following line graph compares the cumulative total return on an investment in our common stock against the cumulative total return of the S&P 500 Composite Index and an index of peer companies (that we selected) for the periods commencing December 31, 2016 through December 31, 2021. Our peer group consists of the following companies that are engaged in refining operations in the U.S.: CVR Energy Inc., Delek US Holdings Inc., HollyFrontier Corp, Marathon Petroleum Corp, Phillips 66 and Valero Energy Corp.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 12/31/2016 | | 12/31/2017 | | 12/31/2018 | | 12/31/2019 | | 12/31/2020 | | 12/31/2021 |
| PBF Energy Class A common stock | $ | 100.00 | | | $ | 133.57 | | | $ | 126.97 | | | $ | 127.18 | | | $ | 29.13 | | | $ | 53.22 | |
| S&P 500 | 100.00 | | | 121.83 | | | 116.49 | | | 153.17 | | | 181.35 | | | 233.41 | |
| Peer Group | 100.00 | | | 132.54 | | | 117.97 | | | 142.91 | | | 94.07 | | | 126.35 | |
Recent Sales of Unregistered Securities—Exchange of PBF LLC Series A Units for PBF Energy Class A Common Stock
In the fourth quarter of 2021, there were 66,202 PBF LLC Series A Units exchanged for 66,202 shares of PBF Energy Class A common stock in transactions exempt from registration under Section 4(a)(2) of the Securities Act. We received no other consideration in connection with any exchanges. No exchanges were made by any of our directors or executive officers.
ITEM 6. [RESERVED]
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following review of our results of operations and financial condition should be read in conjunction with “Item 1. Business”, “Item 1A. Risk Factors”, “Item 2. Properties”, and “Item 8. Financial Statements and Supplementary Data,” respectively, included in this Annual Report on Form 10-K.
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 upon 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:
•the effect of the COVID-19 pandemic, including resurgences and variants of the virus, as well as related governmental and consumer responses on our business, financial condition and results of operations;
•supply, demand, prices and other market conditions for our products or crude oil, including volatility in commodity prices or constraints arising from federal, state or local governmental actions or environmental and/or social activists that reduce crude oil production or availability in the regions in which we operate our pipelines and facilities;
•the effectiveness of our crude oil sourcing strategies, including our crude by rail strategy and related commitments;
•our obligation to buy RINs and market risks related to the volatility in the price of RINs required to comply with the Renewable Fuel Standard and GHG emission credits required to comply with various GHG emission programs, such as AB 32;
•our ability to operate our businesses efficiently, manage capital expenditures and costs (including general and administrative expenses) and generate earnings and cash flow;
•our expectations with respect to our capital improvement and turnaround projects;
•the impact of current and future laws, rulings and governmental regulations, including restrictions on the exploration and/or production of crude oil in the state of California, the implementation of rules and regulations regarding transportation of crude oil by rail or in response to the potential impacts of climate change, decarbonization and future energy transition;
•adverse impacts related to legislation by the federal government lifting the restrictions on exporting U.S. crude oil;
•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 may not reinstate dividend payments;
•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, 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 substantial indebtedness, including the impact of potential downgrades to our corporate credit rating, secured notes 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;
•counterparty credit and performance risk exposure related to our supply and inventory intermediation arrangement;
•termination of our Third Inventory Intermediation Agreement with J. Aron, which is scheduled to expire in December 2024 and could have a material adverse effect on our liquidity, as we would be required to finance our crude oil, intermediate and refined products inventory covered by the agreement. Additionally, we are obligated to repurchase from J. Aron certain J. Aron Products upon termination of the agreement;
•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 related to PBFX or with third-party logistics infrastructure or operations, including pipeline, marine and rail transportation;
•risks associated with the operation of PBFX as a separate, publicly-traded entity;
•potential tax consequences related to our investment in PBFX; and
•any decisions we continue to make with respect to our energy-related logistics assets that may be transferred to PBFX.
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 its subsidiaries. We own and operate six domestic oil refineries and related assets located in Delaware City, Delaware, Paulsboro, New Jersey, Toledo, Ohio, Chalmette, Louisiana, Torrance, California, and Martinez, California. Based on current configuration (subsequent to the East Coast Refining Reconfiguration), our refineries have a combined processing capacity, known as throughput, of approximately 1,000,000 bpd, and a weighted-average Nelson Complexity Index of 13.2 based on current operating conditions. The complexity and throughput capacity of our refineries are subject to change dependent upon configuration changes we make to respond to market conditions as well as a result of investments made to improve our facilities and maintain compliance with environmental and governmental regulations. We operate in two reportable business segments: Refining and Logistics. Our six oil refineries are all engaged in the refining of crude oil and other feedstocks into petroleum products, and are aggregated into the Refining segment. PBFX operates certain logistical assets such as crude oil and refined products terminals, pipelines, and storage facilities, which are aggregated into 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.
COVID-19 and Market Developments
The impact of the unprecedented global health and economic crisis sparked by the COVID-19 pandemic was amplified late in the quarter ended March 31, 2020 due to movements made by the world’s largest oil producers to increase market share. This created simultaneous shocks in oil supply and demand resulting in an economic challenge to our industry which has not occurred since our formation. This combination resulted in significant demand reduction for our refined products and atypical volatility in oil commodity prices. In 2021, as a result of the lifting or easing of restrictions by many governmental authorities and the distribution of COVID-19 vaccines and other protective measures, the demand for refined products started to recover, consequently improving our refining margins in comparison to the prior year. While our results for the year ended December 31, 2021 were impacted by lower demand for refined products, we experienced gradual improvements when compared to the year ended December 31, 2020 and favorable impacts on our revenues, cost of products sold, operating income and liquidity. Although we currently continue to operate our refineries at reduced rates, throughput rates across our refining system have increased in the current year to correlate with the gradual increases in demand.
Debt and Credit Facilities
Senior Notes
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 May 13, 2020, we issued $1.0 billion in aggregate principal amount of the initial 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 December 21, 2020, we issued 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 January 24, 2020, we issued $1.0 billion in aggregate principal amount of the 2028 Senior Notes. The net proceeds from this offering were approximately $987.0 million after deducting the initial purchasers’ discount and offering expenses. We used $517.5 million of the proceeds to fully redeem our 7.00% senior notes due 2023 (the “2023 Senior Notes”) and the balance to fund a portion of the cash consideration for Martinez Acquisition (as defined below).
On February 14, 2020, we exercised our rights under the indenture governing the 2023 Senior Notes to redeem all of the outstanding 2023 Senior Notes at a price of 103.5% of the aggregate principal amount thereof plus accrued and unpaid interest. The aggregate redemption price for all 2023 Senior Notes approximated $517.5 million plus accrued and unpaid interest. The difference between the carrying value of the 2023 Senior Notes on the date they were redeemed and the amount for which they were redeemed was $22.2 million and has been classified as Loss on extinguishment of debt in the Consolidated Statements of Operations for the year ending December 31, 2020.
Catalyst Financing Obligations
In September and October 2021, we settled certain precious metal financing arrangements, resulting in a reduction to debt of approximately $31.7 million.
On September 25, 2020, we closed on agreements to sell a portion of our precious metals catalyst to certain major commercial banks for approximately $51.9 million and subsequently leased the catalyst back. The precious metals financing arrangements cover a portion of the catalyst used in our East Coast Refining System, Martinez and Toledo refineries.
The volumes of the precious metal catalyst and the interest rates are fixed over the term of each financing arrangement. We are obligated to repurchase the precious metals catalyst at fair market value upon expiration of these leases. For all leases not renewed at maturity, we have the ability and intent to finance such debt through availability under our revolving credit facilities.
PBF Holding Revolving Credit Facility
During the year ended December 31, 2020, we used advances under our Revolving Credit Facility to fund a portion of the Martinez Acquisition (as defined below) and for other general corporate purposes. The outstanding borrowings under the Revolving Credit Facility as of December 31, 2021 and December 31, 2020 were $900.0 million.
PBFX Revolving Credit Facility
During the year ended December 31, 2021 and December 31, 2020, PBFX made net repayments of $100.0 million and $83.0 million on the PBFX Revolving Credit Facility. The outstanding borrowings under the PBFX Revolving Credit Facility were $100.0 million as of December 31, 2021.
Refer to “Note 10 - Credit Facilities and Debt” of our Notes to Consolidated Financial Statements, for further information.
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 and August 1, 2019, we closed on third-party sales of parcels of real property acquired as part of the Torrance refinery, but not part of the refinery itself. The sales resulted in gains of approximately $8.1 million and $33.1 million in the fourth quarter of 2020 and third quarter of 2019, respectively, 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. Based on this reconfiguration, our East Coast throughput capacity currently approximates 285,000 barrels per day.
Turnaround Costs and Assets under Construction
As of December 31, 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 the fourth quarter of 2020.
Capital Project Abandonments
In connection with our ongoing strategic initiative to address the COVID-19 pandemic, including our East Coast Refining Reconfiguration, we reassessed our refinery wide slate of capital projects that were either in process or not yet placed into service as of December 31, 2020. Based on this reassessment and our strategic plan to reduce capital expenditures, we decided to abandon various capital projects across the refining system, resulting in an impairment charge of approximately $79.9 million in the fourth quarter of 2020.
Severance Costs
Following the onset of the COVID-19 pandemic, 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, 2021, a liability for the Tax Receivable Agreement of $48.3 million reflecting the estimate of the undiscounted amounts that PBF Energy expects to pay under the agreement, net of the impact of a deferred tax asset valuation allowance recognized in accordance with ASC 740. 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 14 - Commitments and Contingencies” and “Note 21 - 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.
Martinez Acquisition
We acquired the Martinez refinery and related logistics assets from Shell Oil Products on February 1, 2020 for an aggregate purchase price of $1,253.4 million (the “Martinez Acquisition”), including final working capital of $216.1 million and the obligation to make certain post-closing earn-out payments to Shell Oil Products based on certain earnings thresholds of the Martinez refinery for a period of up to four years (the “Martinez Contingent Consideration”). The transaction was financed through a combination of cash on hand, including proceeds from the 2028 Senior Notes, and borrowings under the Revolving Credit Facility.
The Martinez refinery is located on an 860-acre site in the City of Martinez, 30 miles northeast of San Francisco, California. The refinery is a high-conversion 157,000 bpd, dual-coking facility with a Nelson Complexity Index of 16.1, making it one of the most complex refineries in the United States. The facility is strategically positioned in Northern California and provides for operating and commercial synergies with the Torrance refinery located in Southern California. In addition to refining assets, the Martinez Acquisition includes a number of high-quality onsite logistics assets including a deep-water marine facility, product distribution terminals and refinery crude and product storage facilities with approximately 8.8 million barrels of shell capacity.
Inventory Intermediation Agreement
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.
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.
PBFX Equity Offerings
On April 24, 2019, PBFX entered into subscription agreements to sell an aggregate of 6,585,500 common units to certain institutional investors in a registered direct offering (the “2019 Registered Direct Offering”) for gross proceeds of approximately $135.0 million. The 2019 Registered Direct Offering closed on April 29, 2019.
As of December 31, 2021, PBF LLC held a 47.9% limited partner interest in PBFX with the remaining 52.1% limited partner interest owned by public common unitholders.
PBFX Assets and Transactions
PBFX’s assets consist of various logistics assets (as described in “Item 1. Business”). Apart from business associated with certain third-party acquisitions, PBFX’s revenues are derived from long-term, fee-based commercial agreements with subsidiaries of PBF Holding, which include minimum volume commitments, for receiving, handling, transferring and storing crude oil, refined products and natural gas. These transactions are eliminated by PBF Energy and PBF LLC in consolidation.
Since the inception of PBFX in 2014, PBF LLC and PBFX have entered into a series of drop-down transactions. Such transactions and third-party acquisitions made by PBFX occurring in the three years ended December 31, 20182021 are discussed below.
TVPC Acquisition
On August 31, 2016,April 24, 2019, PBFX entered into a contribution agreement (the “TVPC Contribution Agreement”) between PBFX and PBF LLC. Pursuant to the TVPC Contribution Agreement, PBFX acquired fromwith PBF LLC, 50% of the issued and outstanding limited liability company interests of TVPC, whose assets consist of the San Joaquin Valley Pipeline system (which was acquired as a part of the Torrance Acquisition). The total consideration paidpursuant to PBF LLC was $175.0 million, which was funded by PBFX with $20.0 million of cash on hand, $76.2 million in proceeds from the sale of marketable securities, and $78.8 million in net proceeds from the PBFX equity offering in August 2016.
On February 15, 2017, PBFX entered into the PNGPC Contribution Agreement between PBFX and PBF LLC. Pursuant to the PNGPC Contribution Agreement, PBF LLC contributed to PBFX’s wholly-owned subsidiary, PBFX Operating Company LLC (“PBFX Op Co”), all of the issued and outstanding limited liability company interests of PNGPC. PNGPC owns and operates an existing interstate natural gas pipeline that originates in Delaware County, Pennsylvania, at an interconnection with Texas Eastern pipeline that runs under the Delaware River and terminates at the delivery point to PBF Holding’s Paulsboro refinery, and is subject to regulation by the FERC. In connection with the PNGPC Contribution Agreement, PBFX constructed a new 24” pipeline to replace the existing pipeline, which commenced services in August 2017. In consideration for the PNGPC limited liability company interests, PBFX delivered to PBF LLC (i) an $11.6 million intercompany promissory note in favor of Paulsboro RefiningTVP Holding Company LLC a wholly-owned subsidiary of PBF Holding, (ii) an expansion rights and right of first refusal agreement in favor of PBF LLC with respect to the Paulsboro Natural Gas Pipeline and (iii) an assignment and assumption agreement with respect to certain outstanding litigation involving PNGPC and the existing pipeline.
Effective February 2017, PBF Holding and PBFX Op Co entered into a ten-year storage services agreement under which PBFX, through PBFX Op Co, began providing storage services to PBF Holding commencing on November 1, 2017 upon the completion of the construction of a new crude tank with a shell capacity of 625,000 barrels at PBF Holding’s Chalmette Refinery. PBFX Op Co and Chalmette Refining have entered into a twenty-year lease(“TVP Holding”) for the premises upon which the tank is located and a project management agreement pursuant to which Chalmette Refining managed the construction of the tank.
On July 16, 2018, PBFX entered into the Development Assets Contribution Agreements with PBF LLC. Pursuant to the Development Asset Contribution Agreements, PBF LLC contributed all of the issued and outstanding limited liability company interests of the Development Assets to PBFX effective July 31, 2018. In consideration for the Development Assets limited liability company interests, PBFX delivered to PBF LLC total consideration of $31.6$200.0 million consisting of 1,494,134 common units of PBFX.
In connection with(the “TVPC Acquisition”). Prior to the foregoing transactions, PBFTVPC Acquisition, TVP Holding entered into commercial agreements with PBFX entities for the provision of services which require minimum monthly throughput volumes.owned a 50% membership interest in Torrance Valley Pipeline Company LLC (“TVPC”). Subsequent to the transactions described above, asclosing of Decemberthe TVPC Acquisition on May 31, 2018, PBF LLC holds2019, PBFX owns 100% of the membership interests in TVPC. The transaction was financed through a 44.0% limited partner interest incombination of proceeds from the 2019 Registered Direct Offering and borrowings under the PBFX consisting of 19,953,631 common units.Revolving Credit Facility.
PBFX IDR Restructuring AgreementRisks Relating to Our Business and Industry
On February 13, 2019, PBFX entered into the IDR Restructuring Agreement with PBF GP, pursuant to which the IDRs held by PBF LLC will be canceled and converted into 10,000,000 newly issued common units. •The IDR Restructuring is expected to close on February 28, 2019. Subsequent to the closingprice volatility of the IDR Restructuring, no distributions will be made to PBF LLC with respect to the IDRs and the newly issued common units will be entitled to normal distributions.
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, blendstocks, refined products and blending components. We sellfuel and utility services;
•Volatility in commodity prices and refined product demand;
•Crude oil differentials and related factors, which fluctuate substantially;
•Significant interruptions or casualty losses at any of our refineries and related assets or logistics terminals, pipelines or other facilities;
•Interruptions of supply and distribution at our refineries;
•Renewable fuels mandates and the cost of RINs;
•Existence of capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate;
•Regulation of emissions of greenhouse gases and other environmental and health and safety regulations;
•Enhanced scrutiny on ESG matters;
•Volatility and uncertainty in the credit and capital markets;
•Any political instability, military strikes, sustained military campaigns, terrorist activity, changes in foreign policy, or other catastrophic events;
•A cyber-attack on, or other failure of, our technology infrastructure;
•Competition from companies who have not been adversely impacted as much as we have been by the COVID-19 pandemic;
•Delays or cost increases related to capital spending programs;
•Product liability and operational liability claims and litigation;
•Prospect that dividend payments may not be reinstated;
•Acquisition or integration of new assets into our business;
•Labor disruptions that would interfere with our operations;
•Discontinuation of employment of any of our senior executives or other key employees;
•Our activity in commodity derivatives markets.
Risks Related to Our Indebtedness
•Our substantial 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;
•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.
Risks Related to Our Ownership of PBFX
•Obligations for minimum volume commitments in our commercial agreements with PBFX;
•Potential tax consequences related to our involvement in PBFX.
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 Related to the COVID-19 Pandemic
The outbreak of the COVID-19 pandemic significantly and adversely affected our liquidity, business, financial condition and results of operations starting in the first quarter of 2020. While we have seen the demand for our products return in 2021, there can be no assurance that our liquidity, business, financial condition and results of operations will revert to pre-COVID-19 pandemic levels going forward.
The outbreak of the COVID-19 pandemic starting in the first quarter of 2020, negatively impacted, and may continue to impact, worldwide economic and commercial activity and financial markets. The COVID-19 pandemic, and variants thereof, and the related governmental responses resulted in significant business and operational disruptions, including business and school closures, supply chain disruptions, travel restrictions, stay-at-home orders and limitations on the availability of workforces, inclusive of mandatory quarantine periods, and has resulted in significantly lower global demand for refined petroleum and petrochemical products. Although demand for these products started to recover throughout the year ended December 31, 2021 following the lifting or easing of certain restrictions and the distribution of COVID-19 vaccines and other protective measures, there can be no assurance that future periods will not be negatively impacted by the continuing effect of the COVID-19 pandemic, including resurgences and variants of the virus.
In addition, the impact of the COVID-19 pandemic has created simultaneous shocks in oil supply and demand resulting in an economic challenge to our industry which has not occurred since our formation. It is impossible to estimate the duration or significance of the financial impact that will result from the COVID-19 pandemic. However, the extent of the impact of the COVID-19 pandemic on our business, financial condition, results of operations and liquidity will depend largely on future developments, including the duration and severity of the pandemic and variants thereof, particularly within the geographic areas where we operate, the effectiveness of vaccine programs, and the related impact on overall economic activity, all of which cannot be predicted with certainty at this time.
We continue to work with federal, state and local health authorities to respond to COVID-19 cases in the regions we operate and are taking or supporting measures to try to limit the spread of the virus and to mitigate the burden on the healthcare system. Many of these measures will continue to have an adverse impact on our business and financial results that we are not currently able to fully quantify. For example, we are carefully
evaluating projects and non-essential work at our refineries. Based on market conditions, our refineries have been operating at reduced rates, while constantly monitoring and adjusting our production to correlate to increases in product demand. We lowered our capital program for 2021 and will continue to plan to do so in 2022 as compared to historic levels. We have planned a level of capital expenditures we believe will allow us to satisfy and comply with all required safety, environmental and planned regulatory capital commitments and other regulatory requirements, although there are no assurances that we will be able to continue to do so. Non-compliance with applicable environmental and safety requirements, including as a result of reduced staff due to an outbreak at one of our refineries, may impair our operations, may subject us to fines or penalties assessed by governmental authorities and/or may result in an environmental or safety incident. We may also be subject to liability as a result of claims against us by impacted workers or third parties.
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 have adversely affected 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 in the case of the East Coast Refining Reconfiguration. There may be significant incremental costs associated with such actions. Further 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 persistence or worsening or market conditions related to the COVID-19 pandemic may require us to raise additional capital to meet our obligations and operate our business.
Our borrowing base under PBF Holding’s asset-based revolving credit facility (the “Revolving Credit Facility”) could be reduced if market conditions deteriorate or crude prices decrease significantly. Our borrowing base availability under the Revolving Credit Facility was $3,400.0 million as of December 31, 2021. If current market conditions return to levels experienced during the height of the COVID-19 pandemic, or worsen, we may require additional capital to meet our obligations as well as to operate our business, and additional financing and/or assets sales may not be possible on favorable terms or at all. Potential economic factors resulting from the COVID-19 pandemic, which could lead to increasing unemployment rates, substantially reduced travel and reduced business and consumer spending, could also affect our business.
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.
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, as we experienced in 2020, 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. Although we reduced our crude oil, feedstock and refined product inventories in 2020 to strengthen our financial position in response to the COVID-19 pandemic, inventory has slowly returned to normalized levels in 2021. 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. 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, reflecting the net change in the LCM inventory reserve from $401.6 million at December 31, 2019 to $669.6 million at December 31, 2020. At December 31, 2021, the replacement value of inventories exceeded the LIFO carrying value, therefore no LCM inventory reserve was recorded.
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 slightly 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.
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 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 commercial accounts,owned, as well as third-party, pipelines. These pipelines include the Enbridge system, Capline and salesMid-Valley pipelines for supplying crude to our Toledo refinery, the MOEM Pipeline (which is owned by our subsidiary) and CAM Pipeline for supplying crude to our Chalmette refinery and the San Joaquin Pipeline, San Pablo Bay Pipeline, San Ardo and Coastal Pipeline systems for supplying crude to our Torrance and Martinez refineries. Additionally, our Toledo, Chalmette, Torrance and Martinez refineries deliver a significant portion of the refined products through pipelines. These pipelines include pipelines such as the Sunoco Logistics Partners L.P. and Buckeye Partners L.P. pipelines at the Toledo refinery, the Collins pipeline (which is owned by our subsidiary) at our Chalmette refinery, the Jet Pipeline to the Los Angeles International Airport, the Product Pipeline to Vernon and the Product Pipeline to Atwood at our Torrance refinery and the KinderMorgan SFPP North Pipeline at our Martinez refinery. We could experience an interruption of supply or delivery, or an increased cost of receiving crude oil and delivering refined products to market, if the ability of these pipelines to transport crude oil or refined products is disrupted because of accidents, weather interruptions, governmental regulation, terrorism, other third-party action or casualty or other events.
The Delaware City rail unloading facilities and the assets acquired in connection with majorthe PBFX 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.
In addition, due to the common carrier regulatory obligation applicable to interstate oil companies. Forpipelines, 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.
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 Renewable Fuel Standard, implementing mandates to blend renewable fuels into the petroleum fuels produced and sold in the United States. Under the Renewable Fuel Standard, 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 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 2021 and could increase further in 2022. We incurred approximately $726.0 million in RINs costs during the year ended December 31, 2021 as compared to $326.4 million and $122.7 million during the years ended December 31, 2018, 20172020 and 2016,2019, 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. EPA’s proposed volumes of renewable fuels that obligated refineries must blend into their final petroleum fuels are expected to be finalized by the end of the first quarter of 2022. 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.
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, 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 accountedand other matters otherwise relating to the protection of the environment and the health and safety of the surrounding community. Our operations are also subject to extensive laws and regulations relating to occupational health and safety.
We cannot predict what additional environmental, health and safety legislation or regulations may be adopted in the future, or how existing or future laws or regulations may be administered or interpreted with respect to our operations. Many of these laws and regulations have become increasingly stringent over time, and the cost of compliance with these requirements can be expected to increase over time. For example, on July 21, 2021, the board of Bay Area Air Quality Management District (“BAAQMD”) voted to adopt proposed 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 84.7%, 84.1%particulate emissions from FCC units at refineries in the Bay Area by 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 88.0%there can be no assurance that the measures we implement will achieve the required emissions reductions.
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 revenues, respectively.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.
CustomersPotential 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 sell a varietybelieve the issue of refined productsclimate change will likely continue to a diverse customer base. The majorityreceive 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 are primarily sold through short-term contractsproducts. Extended periods of such disruption could have an adverse effect on our results of operation. We could also incur substantial costs to protect or on the spot market. However, we dorepair these facilities.
Regulation of emissions of greenhouse gases could force us to incur increased capital expenditures and operating costs and could have product offtake arrangements for a portion of our clean products. For the years ended December 31, 2018, 2017 and 2016, no single customer accounted for 10% or more of our revenues, respectively. As of December 31, 2018 and December 31, 2017, no single customer accounted for 10% or more of our total trade accounts receivable.
Seasonality
Demand for gasoline and diesel is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and construction work. Decreased demand during the winter months can lower gasoline and diesel prices. As a result, our operating results for the first and fourth calendar quarters may be lower than those for the second and third calendar quarters of each year. Refining margins remain volatile andmaterial 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 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 reflectbe able to pass on any of these historical seasonal trends. Additionally,costs to our customers. Regulatory requirements also could adversely affect demand for the degreerefined products that we produce. Any increased costs or reduced demand could materially and adversely affect our business and results of seasonalityoperations.
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.
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. The N-79-20 Order encourages zero emissions technologies such as electric vehicles, and accelerated deployment of affordable fueling and charging options. It is currently uncertain how the N-79-20 Order may differbe ultimately implemented by various California regulatory agencies. In the geographicevent we do incur increased costs as a result of increased efforts to control GHG emissions through future adopted regulatory requirements, we may not be able to pass these costs to our customers. These future regulatory requirements also could adversely
affect demand for the refined products that we produce. Any increased costs or reduced demand could materially and adversely affect our business and results of operations.
Environmental clean-up and remediation costs of our sites and environmental litigation 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 operate. Mostassumed 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—Contractual Obligations and Commitments”.
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 seasonalityPFAS 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 PBFX’sor 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.
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.
We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with health, safety, environmental and other laws and regulations.
Our operations require numerous permits and authorizations under various laws and regulations. These authorizations and permits are subject to revocation, renewal or modification and can require operational changes to limit impacts or potential impacts on the environment and/or health and safety. A violation of authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions, and/or facility shutdowns. In addition, major modifications of our operations could require modifications to our existing permits or upgrades to our existing pollution control equipment. Any or all of these matters could have a negative effect on our business, results of operations and cash flows.
We may incur significant liabilities under, or costs and capital expenditures to comply with, health, safety, environmental and other laws and regulations, which are mitigated through fee-based commercial agreementscomplex and change frequently. Our operations are subject to federal, state and local laws regulating, among other things, the handling of petroleum and other regulated materials, the emission and discharge of materials into the environment, waste management, and remediation of discharges of petroleum and petroleum products, characteristics and composition of gasoline and distillates and other matters otherwise relating to the protection of the environment. Our operations are also subject to extensive laws and regulations relating to occupational health and safety, in addition to laws and regulations affecting the transportation of crude oil by rail in North America.
We cannot predict what additional environmental, health and safety legislation or regulations may be adopted in the future, or how existing or future laws or regulations may be administered or interpreted with respect to our operations. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time.
Certain environmental laws impose strict, and in certain circumstances joint and several liability for, costs of investigation and cleanup of such spills, discharges or releases on owners and operators of, as well as persons who arrange for treatment or disposal of regulated materials at contaminated sites. Under these laws, we may incur liability or be required to pay penalties for past contamination, and third parties may assert claims against us for damages allegedly arising out of any past or future contamination. The potential penalties and clean-up costs for past or future releases or spills, the failure of prior owners of our facilities to complete their clean-up obligations, the liability to third parties for damage to their property, or the need to address newly-discovered information or conditions that may require a response could be significant, and the payment of these amounts could have a material adverse effect on our business, financial condition and results of operations.
Enhanced scrutiny on ESG matters may 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.
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 have experienced periods of extreme volatility that have negatively impacted market liquidity conditions, including as a result of the impact of the COVID-19 pandemic. As a result, the cost of raising money in the debt and equity capital markets has increased substantially at times while the availability of funds from those markets diminished 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.
Any 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 minimum volume commitments.
Competitiondata network and telecommunications, internet access, our websites, and various computer hardware equipment and software applications, including those that are critical to the safe operation of our refineries and logistics assets. We have invested, and expect to continue to invest, significant time, manpower and capital in our technology infrastructure and information systems. These information systems are subject to damage or interruption from a number of potential sources including natural disasters, software viruses or other malware, power failures, cybersecurity threats to gain unauthorized access to sensitive information, cyber-attacks, which may render data systems unusable, and physical threats to the security of our facilities and infrastructure. Additionally, our business is highly dependent on financial, accounting and other data processing systems and other communications and information systems, including our enterprise resource planning tools. We process a large number of transactions on a daily basis and rely upon the proper functioning of computer systems. Furthermore, we rely on information systems across our respective operations, including the management of supply chain and various other processes and transactions. As a result, a disruption on any information systems at our refineries or logistics assets, may cause disruptions to our collective operations.
The potential for such security threats or system failures has subjected our operations to increased risks that could have a material adverse effect on our business. To the extent that these information systems are under our control, we have implemented measures such as virus protection software, emergency recovery processes and a formal disaster recovery plan to address the outlined risks. However, security measures for information systems cannot be guaranteed to be failsafe, and our formal disaster recovery plan and other implemented measures may not prevent delays or other complications that could arise from an information systems failure. If a key system were hacked or otherwise interfered with by an unauthorized user, or were to fail or experience unscheduled downtime for any reason, even if only for a short period, or any compromise of our data security or our inability to use or access these information systems at critical points in time, it could unfavorably impact the timely and efficient operation of our business, damage our reputation and subject us to additional costs and liabilities. The increase in companies and individuals working remotely has increased the frequency and scope of cyber-attacks and the risk of potential cybersecurity incidents, both deliberate attacks and unintentional events. While, to date, we have not had a significant cybersecurity breach or attack that had a material impact on our business or results of operations, if we were to be subject to a material successful cyber intrusion, it could result in remediation or service restoration costs, increased cyber protection costs, lost revenues, litigation or regulatory actions by governmental authorities, increased insurance premiums, reputational damage and damage to our competitiveness, financial condition, results of operations and cash flows.
Cyber-attacks against us or others in our industry could result in additional regulations, and U.S. government warnings have indicated that infrastructure assets, including pipelines, may be specifically targeted by certain groups. These attacks include, without limitation, malicious software, ransomware, attempts to gain unauthorized access to data, and other electronic security breaches. These attacks may be perpetrated by state-sponsored groups, “hacktivists”, criminal organizations or private individuals (including employee malfeasance). Current efforts by the federal government, including the Strengthening the Cybersecurity of Federal Networks and Critical Infrastructure executive order, the issuance of new cybersecurity requirements for critical pipeline owners and operators issued by the Department of Homeland Security’s Transportation Security Administration following a cyber-attack on a major petroleum pipeline in 2021, and any potential future regulations could lead to increased regulatory compliance costs, insurance coverage cost or capital expenditures. We cannot predict the potential impact to our business or the energy industry resulting from additional regulations.
Further, our business interruption insurance may not compensate us adequately for losses that may occur. We do not carry insurance specifically for cybersecurity events; however, certain of our insurance policies may allow for coverage for a cyber-event resulting in ensuing property damage from an otherwise insured peril. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, results of operations and cash flows. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.
Competition from companies who have not been adversely impacted as much as we have been by the COVID-19 pandemic, 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 business is very competitive. Weoperations compete directly with variousdomestic refiners and marketers in regions of the United States in which we operate, as well as with domestic refiners in other refining companies on the East, Gulfregions and West Coasts and in the Mid-Continent, with integrated oil companies, with foreign refiners that import products into the United States andStates. In addition, we compete with other refiners, producers and marketers in other industries supplyingthat supply their own renewable fuels or alternative forms of energy and fuels to satisfy the requirements of our industrial, commercial and individual consumers. SomeMany of our competitors have expandednot been adversely impacted by 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,COVID-19 pandemic as wellmuch 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.we have been impacted. Certain of our competitors that 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.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. Refining margins are frequently impacted by sharp changes in crude oil costs, whichfluctuations and they may not be immediately reflected in product prices.
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 willalso be able to obtain adequate crude oilmore favorable trade credit terms.
Newer or upgraded refineries will often be more efficient than our refineries, which may put us at a competitive disadvantage. We have taken significant measures to maintain our refineries including the installation of new equipment and redesigning older equipment to improve our operations. However, these actions involve significant uncertainties, since upgraded equipment may not perform at expected throughput levels, the yield and product quality of new equipment may differ from design specifications and modifications may be needed to correct equipment that does not perform as expected. Any of these risks associated with new equipment, redesigned older equipment or repaired equipment could lead to lower revenues or higher costs or otherwise have an adverse effect on future results of operations and financial condition. Over time, our refineries or certain refinery units may become obsolete, or be unable to compete, because of the construction of new, more efficient facilities by our competitors.
We must make substantial capital expenditures on our operating facilities to maintain their reliability and efficiency. If we are unable to complete capital projects at their expected costs and/or in a timely manner, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations or cash flows could be materially and adversely affected.
Delays or cost increases related to capital spending programs involving engineering, procurement and construction of new facilities (or improvements and repairs to our existing facilities and equipment, including turnarounds) could adversely affect our ability to achieve targeted internal rates of return and operating results. Such delays or cost increases may arise as a result of unpredictable factors in the marketplace, many of which are beyond our control, including:
•denial or delay in obtaining regulatory approvals and/or permits;
•unplanned increases in the cost of construction materials or labor;
•disruptions in transportation of modular components and/or construction materials;
•severe adverse weather conditions, natural disasters or other feedstocksevents (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 generally competitive pricesoptimum 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, 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.
PBF Energy has suspended its quarterly dividend and does not anticipate that it will declare dividends in the foreseeable future.
On March 30, 2020, PBF Energy announced that it has suspended its quarterly cash dividend of $0.30 per share on its Class A common stock, as part of its strategic plan to respond to the impact of the COVID-19 outbreak and related market activity. 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). Any future declaration, amount and payment of any dividends will be at the sole discretion of our Board of Directors, however, because the impact of the COVID-19 outbreak and related market activity is difficult to predict, we do not anticipate that our Board of Directors will determine to declare a dividend in the foreseeable future. Our Board of Directors 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 Board of Directors 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
Our complex refinery system
Energy are separate and sourcing optionalitydistinct 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 positionnot 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.
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 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 favorably to benefit fromcould have a material adverse effect on our business, financial condition or results of operations.
Compliance with and changes in certain market conditionstax laws could adversely affect our performance.
We are subject to extensive tax liabilities, including federal, state, local and governmental or industry regulations,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 are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the pending requirement fromfuture. These liabilities are subject to periodic audits by the International Maritime Organization (“IMO”) related to the reduction in sulfur content of marine fuels to a maximum of 0.5% effective January 1, 2020. Duerespective taxing authorities, which could increase our tax liabilities. Subsequent changes to our relative refinery complexity and ample coking capacity, we anticipate being able to favorably capture the benefit from potential product margin uplift associated with an increase in demand for low sulfur fuel or a widening of the discount on high-sulfur feedstockstax 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 new IMO regulations.
Corporate Officesfuture involve a number of risks, any of which could cause us not to realize the anticipated benefits.
We currently lease approximately 58,000 square feet formay 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 principal corporate offices in Parsippany, New Jersey. The lease for our principal corporate offices expires in 2022. Functions performedbusiness and operating results. We may selectively consider strategic acquisitions in the Parsippany officefuture 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 overall corporatethose relating to the diversion of management refinerytime and HSE management, planningattention from our existing business, liability for known or unknown environmental conditions or other contingent liabilities and strategy, corporategreater 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 commercial operations, logistics, contract administration, marketing, investor relations, governmental affairs, accounting, tax, treasury, information technology, legal and human resources support functions.
acquisitions or capital expenditures relating to acquired assets. We lease approximately 4,000 square feet for our regional corporate office in Long Beach, California. The lease for our Long Beach office expires in 2021. Functions performedmay also enter into transition services agreements in the Long Beach office include overall regional corporate management, planningfuture with sellers of any additional refineries we acquire. Such services may not be performed timely and strategy, commercial operations, logistics, contract administration, marketingeffectively, and governmental affairs.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.
We lease approximately 5,000 square feet for
A portion of our regional corporate office in The Woodlands, Texas. The lease for The Woodlands office expires in 2022. Functions performed in The Woodlands include pipeline control center operationsworkforce is unionized, and logistics operations, engineering and regulatory support functions.we may face labor disruptions that would interfere with our operations.
Employees
As of December 31, 2018, we had approximately 3,266 employees, of which 1,625 are covered by collective bargaining agreements. OurMost hourly employees at our refineries are covered by collective bargaining agreements through the United Steel Workers (“USW”)USW, the IOW and the IBEW. Certain of these agreements have expired while others are scheduled to expire on various dates in 2022 through 2024 (See “Item 1. Business” - Employees). For the agreements that expired, terms related to new collective bargaining agreements have been agreed to on local bargaining issues and are pending settlement of the National Oil Bargaining Program which will set contract term, wages, health care contributions and any other agreed upon issues prior to being executed.During this interim period, the terms of the expired agreements will remain in place under rolling 24-hour extensions until new agreements are finalized. Future negotiations prior to the expiration of our collective agreements may result in labor unrest for which a strike or work stoppage is possible. Strikes and/or work stoppages could negatively affect our operational and financial results and may increase operating expenses at the refineries.
Our business may suffer if any of our senior executives or other key employees discontinues employment with us. Furthermore, a shortage of skilled labor or disruptions in our labor force may make it difficult for us to maintain labor productivity.
Our future success depends to a large extent on the services of our senior executives and other key employees. Our business depends on our continuing ability to recruit, train and retain highly qualified employees in all areas of our operations, including engineering, accounting, business operations, finance and other key back-office and mid-office personnel. Furthermore, our operations require skilled and experienced employees with proficiency in multiple tasks. The competition for these employees is intense, and the loss of these executives or employees could harm our business. If any of these executives or other key personnel resigns or becomes unable to continue in his or her present role and is not adequately replaced, our business operations could be materially adversely affected.
Our hedging activities may limit our potential gains, exacerbate potential losses and involve other risks.
We may enter into commodity derivatives contracts to hedge our crude price risk or crack spread risk with respect to a portion of our expected gasoline and distillate production on a rolling basis or to hedge our exposure to the price of natural gas, which is a significant component of our refinery operating expenses. Consistent with that policy we may hedge some percentage of our future crude and natural gas supply. We may enter into hedging arrangements with the intent to secure a minimum fixed cash flow stream on the volume of products hedged during the hedge term and to protect against volatility in commodity prices. Our hedging arrangements may fail to fully achieve these objectives for a variety of reasons, including our failure to have adequate hedging arrangements, if any, in effect at any particular time and the failure of our hedging arrangements to produce the anticipated results. We may not be able to procure adequate hedging arrangements due to a variety of factors. Moreover, such transactions may limit our ability to benefit from favorable changes in crude oil, refined product and natural gas prices.
In addition, our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which:
•the volumes of our actual use of crude oil or natural gas or production of the applicable refined products is less than the volumes subject to the hedging arrangement;
•accidents, interruptions in feedstock transportation, inclement weather or other events cause unscheduled shutdowns or otherwise adversely affect our refineries, or those of our suppliers or customers;
•changes in commodity prices have a material impact on collateral and margin requirements under our hedging arrangements, resulting in us being subject to margin calls;
•the counterparties to our derivative contracts fail to perform under the contracts; or
•a sudden, unexpected event materially impacts the commodity or crack spread subject to the hedging arrangement.
As a result, the effectiveness of our hedging strategy could have a material impact on our financial results. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”
In addition, these hedging activities involve basis risk. Basis risk in a hedging arrangement occurs when the price of the commodity we hedge is more or less variable than the index upon which the hedged commodity is based, thereby making the hedge less effective. For example, a New York Mercantile Exchange index used for hedging certain volumes of our crude oil or refined products may have more or less variability than the actual cost or price we realize for such crude oil or refined products. We may not hedge all the basis risk inherent in our hedging arrangements and derivative contracts.
Our commodity derivative activities could result in period-to-period earnings volatility.
We do not currently apply hedge accounting to any of our commodity derivative contracts and, as a result, unrealized gains and losses will be charged to our earnings based on the increase or decrease in the market value of such unsettled positions. These gains and losses may be reflected in our income statement in periods that differ from when the settlement 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 substantial 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, 2021, we have total debt of $4,330.8 million, excluding unamortized deferred debt issuance costs of $35.0 million and our PBF LLC Affiliate note payable with PBF Energy that eliminates in consolidation at the PBF Energy level, and we could incur additional borrowings under our credit facilities. We may incur additional indebtedness in the future including additional secured indebtedness, subject to the satisfaction of any debt incurrence and, if applicable, lien incurrence limitation covenants in our existing financing agreements. Although we were in compliance with incurrence covenants during the year ended December 31, 2021, 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 stock or incur new liens.
The level of our indebtedness has several important consequences for our future operations, including that:
•a portion of our cash flow from operations will be dedicated to the payment of principal of, and interest on, our indebtedness and will not be available for other purposes;
•under certain circumstances, covenants contained in our existing debt arrangements limit our ability to borrow additional funds, dispose of assets and make certain investments;
•in certain circumstances these covenants also require us to meet or maintain certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our industry, such as being able to take advantage of acquisition opportunities when they arise;
•our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited; and
•we may be at a competitive disadvantage to those of our competitors that are less leveraged; and we may be more vulnerable to adverse economic and industry conditions.
Our indebtedness increases the risk that we may default on our debt obligations, certain of which contain cross-default and/or cross-acceleration provisions. Our, and our subsidiaries’, ability to meet future principal obligations will be dependent upon our future performance, which in turn will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our business may not continue to generate sufficient cash flow from operations to repay our indebtedness. If we are unable to generate sufficient cash flow from operations, we may be required to sell assets, to refinance all or a portion of our indebtedness or to obtain additional financing. Refinancing may not be possible and additional financing may not be available on commercially acceptable terms, or at all.
We may not be able to secure necessary financing on acceptable terms, or at all.
We currently have notes outstanding with varying maturity dates beginning in 2023 and ending in 2028. Additionally, our most significant credit facilities - the Independent Oil Workers (“IOW”Revolving Credit Facility and the PBFX amended and restated revolving credit facility (the “PBFX Revolving Credit Facility”) - both have maturity dates in 2023. We can make no assurance that we will be able to refinance our outstanding indebtedness on acceptable terms prior to their maturity dates. Market disruptions, such as those experienced in relation to the COVID-19 pandemic, may increase our cost of borrowing or adversely affect our ability to refinance our obligations as they become due. Further, ESG concerns and other pressures on the oil and gas industry could lead to increased costs of financing or limit our access to the capital markets. If we are unable to refinance our indebtedness or access additional credit, or if short-term or long-term borrowing costs significantly increase, our ability to finance current operations and meet our short-term and long-term obligations could be adversely affected.
Despite our substantial 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 current debt levels, the leverage risks described above would increase. Also, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness.
Our future credit ratings could adversely affect our business, the cost of our borrowing, and our ability to obtain credit in the future.
Changes in our credit profile could affect the way crude oil and other suppliers view our ability to make payments and induce them to shorten the payment terms for our purchases or require us to post security or letters of credit prior to payment. Due to the large dollar amounts and volume of our crude oil and other feedstock purchases, any imposition by these suppliers of more burdensome payment terms on us may have a material adverse effect on our liquidity and our ability to make payments to our suppliers. This, in turn, could 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 International Brotherhood7.25% senior unsecured notes due 2025 (the “2025 Senior Notes”) are rated Caa1 by Moody’s, B by S&P, and B- by Fitch. The 9.25% senior secured notes due 2025 (the “2025 Senior Secured Notes”) are rated B2 by Moody’s, BB- by S&P, and BB by Fitch. The 6.875% PBFX senior notes due 2023 (the “PBFX 2023 Senior Notes”) are rated B3 by Moody’s, B by S&P, and B+ by Fitch. During 2021, Moody’s and S&P downgraded our corporate family rating as well as our unsecured and secured notes ratings, with all ratings on negative outlook. If the current market conditions persist or deteriorate, we expect that the credit rating agencies will continue to re-evaluate our corporate credit rating and the ratings of Electrical Workers (“IBEW”). We consider our relationsunsecured and secured notes. Adverse changes in our credit ratings may also negatively impact the terms of credit we receive from our suppliers and require us to prepay or post collateral. Further adverse actions taken by the rating agencies on our corporate credit rating or the rating of our notes may further 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.
Restrictive covenants in our debt instruments, including the indentures governing our notes, may limit our ability to undertake certain types of transactions, which could adversely affect our business, financial condition, results of operations and our ability to service our indebtedness.
Various covenants in our current and future debt instruments and other financing arrangements, including the indentures governing our notes, may restrict our and our subsidiaries’ financial flexibility in a number of ways. Our current indebtedness and the indentures that govern our notes subject us to significant financial and other restrictive covenants, including restrictions on our ability to incur additional indebtedness, place liens upon assets, 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 our debt instruments also require our subsidiaries to satisfy or maintain certain financial condition tests in certain circumstances. Our ability to meet these financial condition tests can be affected by events beyond our control and we may not meet such tests. In addition, a failure to comply with the represented employeesprovisions of our existing debt could result in an event of default that could enable our lenders, subject to the terms and conditions of such debt, to declare the outstanding principal, together with accrued interest, to be satisfactory.immediately due and payable. Events beyond our control, including the impact of the COVID-19 pandemic and related governmental responses and developments in the global oil markets, 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. |
| | | | | | | | | | |
| Location | | Number of employees | | Employees covered by collective bargaining agreements | | Collective bargaining agreements | | Expiration date |
| Headquarters | | 379 |
| | — |
| | N/A | | N/A |
| Delaware City refinery | | 559 |
| | 377 |
| | USW | | January 2022 |
| Paulsboro refinery | | 470 |
| | 291 |
| | IOW | | March 2022 |
| Toledo refinery | | 528 |
| | 331 |
| | USW | | February 2022 |
| Chalmette refinery | | 562 |
| | 264 |
| | USW | | January 2022 |
| Torrance refinery | | 578 |
| | 288 |
| | USW IBEW | | January 2022* January 2022 |
| Torrance logistics | | 108 |
| | 45 |
| | USW | | January 2022* April 2021 |
| PBFX | | 82 |
| | 29 |
| | USW | | February 2022 April 2021 |
| Total employees | | 3,266 |
| | 1,625 |
| | | | |
* TentativeCertain 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, the 2025 Senior Secured Notes, the 2028 Senior Notes and the PBFX 2023 Senior Notes, holders of our notes could require us to repurchase all outstanding notes at 101% of the principal amount thereof, plus accrued and unpaid interest, if any, at the date of repurchase. Certain other significant agreements of ours such as our agreement has been reachedgoverning the Revolving Credit Facility (the “Revolving Credit Agreement”), Tax Receivable Agreement (as defined below) and upon ratification and execution will extend the collective bargaining agreementThird Intermediation Agreement with J. Aron also contain provisions related to Torrance refinerya change in control that could make it more difficult or expensive for a third-party to acquire us.
Risks Related to Our Organizational Structure and Torrance logistics employees coveredPBF 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 USW agreement through January 2022.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.
Executive OfficersThe Revolving Credit Facility, the 2028 Senior Notes, the 2025 Senior Notes, the 2025 Senior Secured 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. PBFX Revolving Credit Facility and PBFX’s indenture governing its PBFX 2023 Senior Notes also contain 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 Registrantdistribution, 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 followingrights 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 2022 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.
PBF Energy is party to a listTax 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.”
PBF Energy has recognized, as of December 31, 2021, a liability for the Tax Receivable Agreement of $48.3 million, reflecting the estimated undiscounted amounts that PBF Energy expects to pay under the agreement, net of a deferred tax asset valuation allowance recognized in accordance with FASB Accounting Standards Codification (“ASC”) 740, Income Taxes (“ASC 740”). As future taxable income is recorded, increases in our Tax Receivable Agreement liability may be necessary in conjunction with the revaluation of 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 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 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 the 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. 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 executive officers asCompany to a third-party and may otherwise make it less likely that a third-party would enter into a change of February 21, 2019:control transaction with us.
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Name | | Age (as of December 31, 2018) | | Position |
Thomas J. Nimbley | | 67 |
| | Chief Executive Officer and ChairmanMoreover, 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 Service 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.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 Board of Directors |
Matthew C. Lucey | | 45 |
| | President |
Erik Young | | 41 |
| | Senior Vice President, Chief Financial Officer |
Paul Davis | | 56 |
| | President, Western Region |
Thomas L. O’Connor | | 46 |
| | Senior Vice President, Commercial |
Herman Seedorf | | 67 |
| | Senior Vice President, Refining |
Trecia Canty | | 49 |
| | Senior Vice President, General Counsel & Corporate Secretary |
Thomas J. Nimbley has served as our Chief Executive Officer since June 2010 and on our Board of Directors, since October 2014. He has servedthe chief executive officer or the Board of 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 Chairmanapproval of 75% or more of all of the outstanding shares of our Board since July 2016. He wascapital stock entitled to vote.
These anti-takeover provisions and other provisions of Delaware law may have the effect of delaying or deterring a change of control of our Executive Vice President, Chief Operating Officer from March 2010 through June 2010. 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, which could cause the value of your investment to decline.
The market price of PBF Energy Class A common stock may be highly volatile and subject to wide fluctuations due to a number of factors including:
•market conditions in the oil refining industry and volatility in commodity prices and the ongoing impact of COVID-19;
•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 his capacity asaddition, 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 Chief Executive Officer, Mr. Nimbley also servesprofitability and reputation.
Our current stockholders could experience dilution, which could further depress the price of our Class A common stock.
We continue to require substantial working 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 shares of Class A common stock. As a result, stockholders may experience substantial dilution, and the market price of our Class A common stock could decline as a directorresult of the introduction of a large number of shares of our Class A common stock, or securities convertible into or exchangeable or exercisable for our Class A common stock, into the market or the perception that these sales could occur. Sales of a large number of shares of our Class A common stock, or securities convertible into or exchangeable or exercisable for our Class A common stock, or the possibility that these sales may occur, also might make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. In addition, any equity securities we issue may have rights, preferences or privileges senior to those of our Class A common stock, and our current debt agreements contain, and any agreements for future debt or preferred equity financings, if available, are likely to contain, covenants limiting or restricting our ability to take specific actions, such as incurring additional debt. Holders of Class A common stock are not entitled to preemptive rights or other protections against dilution. Because our decision to issue securities in any future offering will depend on our capital needs as well as market conditions and other factors beyond om control, we cannot predict or estimate the Chief Executive Officeramount, timing, nature or impact of future issuances, if any. Our Class A common stockholders bear the risk of our future offerings reducing the per share market price of our Class A common stock.
Risks Related to Our Ownership of PBFX
We depend upon PBFX for a substantial portion of our refineries’ logistics needs and have obligations for minimum volume commitments in our commercial agreements with PBFX.
We depend on PBFX to receive, handle, store and transfer crude oil, petroleum products and natural gas for us from our operations and sources located throughout the United States and Canada in support of certain of our subsidiariesrefineries under long-term, fee-based commercial agreements with our subsidiaries. These commercial agreements have an initial term ranging from one to fifteen years and our affiliates, including Chairmangenerally include minimum quarterly commitments and inflation escalators. If we fail to meet the minimum commitments during any calendar quarter, we will be required to make a shortfall payment quarterly to PBFX equal to the volume of the Board of PBF GP. Priorshortfall multiplied by the applicable fee.
PBFX’s operations are subject 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 PBF 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 sectorsall of the broader energy industry,risks and operational hazards inherent in receiving, handling, storing and transferring crude oil, petroleum products and natural gas, including: damages to its facilities, related equipment and surrounding properties caused by floods, fires, severe weather, explosions and other natural disasters and acts of terrorism; mechanical or structural failures at PBFX’s facilities or at third-party facilities on which its operations are dependent; curtailments of operations relative to severe seasonal weather; inadvertent damage to our facilities from 2001construction, farm and utility equipment; and other hazards. Any of these events or factors could result in severe damage or destruction to 2008. Before joining M.E. Zukerman & Co., Mr. Lucey spent six years inPBFX’s assets or the banking industry.
Erik Young has served astemporary or permanent shut-down of PBFX’s facilities. If PBFX is unable to serve our Senior Vice Presidentlogistics needs, our ability to operate our refineries and Chief Financial Officer since April 2014 after joining us in December 2010 as Director, Strategic Planning where he was responsible for both corporate development and capital markets initiatives. Mr. Young is also a director of certain of our subsidiaries, including PBF GP. Prior to joining the Company, Mr. Young spent eleven years in corporate finance, strategic planning and mergers and acquisitions roles across a variety of industries. He began his career in investment banking before joining J.F. Lehman & Company, a private equity investment firm, in 2001.
Paul Davis has served as our President, PBF Energy Western Region LLC since September 2017. 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 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 inreceive crude oil and refineddistribute products could be adversely impacted, which could adversely affect our business, financial condition and results of operations.
In addition, as of December 31, 2021, PBF LLC owns 29,953,631 common units representing 47.9% limited partner interest in PBFX. The inability of PBFX to continue operations, perform under its commercial arrangements with our subsidiaries or the occurrence of any of these risks or operational hazards, could also adversely impact the value of our investment in PBFX and, because PBFX is a consolidated entity, our business, financial condition and results of operations.
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 16 yearsPBF 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 ExxonMobil Corporationpartnership 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 to PBF Energy on account of its indirect interest in various operationalPBFX may not be sufficient for PBF Energy to pay the amount of taxes it will owe on account of its indirect interests in PBFX.
If PBFX was to be treated as a corporation, rather than as a partnership, for U.S. federal income tax purposes or if PBFX was otherwise subject to entity-level taxation, PBFX’s cash available for distribution to its unitholders, including to us, would be reduced, likely causing a substantial reduction in the value of units, including the units held by us.
The present U.S. federal income tax treatment of publicly-traded partnerships, including PBFX, or an investment in its common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time the U.S. Congress considers substantive changes to the existing federal income tax laws that would affect publicly-traded partnerships. Any modification to the U.S. federal income tax laws and commercial positions,interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for PBFX to meet the exception to be treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in PBFX common units.
If PBFX were treated as a corporation for U.S. federal income tax purposes, it would pay U.S. federal income tax on income at the corporate tax rate, which is currently a maximum of 21% under the TCJA, and would likely be liable for state income tax at varying rates. Distributions to PBFX unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to PBFX unitholders. Because taxes would be imposed upon PBFX as a corporation, the cash available for distribution to PBFX unitholders would be substantially reduced. Therefore, PBFX’s treatment as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to PBFX unitholders, likely causing a substantial reduction in the value of the units.
All of the executive officers and a majority of the directors of PBF GP are also current or former officers or directors of PBF Energy. Conflicts of interest could arise as a result of this arrangement.
PBF Energy indirectly owns and controls PBF GP, and appoints all of its officers and directors. All of the executive officers and a majority of the directors of PBF GP are also current or former officers or directors of PBF Energy. These individuals will devote significant time to the business of PBFX. Although the directors and officers of PBF GP have a fiduciary duty to manage PBF GP in a manner that is beneficial to PBF Energy, as directors and officers of PBF GP they also have certain duties to PBFX and its unitholders. Conflicts of interest may arise between PBF Energy and its affiliates, including sourcing refinery feedstocksPBF GP, on the one hand, and crude oilPBFX and its unitholders, on the other hand. In resolving these conflicts of interest, PBF GP may favor its own interests and the dispositioninterests of refined petroleum products, as well as optimization roles within refineries.
Thomas L. O’Connor has served as our Senior Vice President, Commercial since September 2015. Mr. O’Connor joined us as Senior Vice PresidentPBFX over the interests of PBF Energy. In certain circumstances, PBF GP may refer any conflicts of interest or potential conflicts of interest between PBFX, on the one hand, and PBF Energy, on the other hand, to its conflicts committee (which must consist entirely of independent directors) for resolution, which conflicts committee must act in September 2014 with responsibility for business development and growingthe best interests of the public unitholders of PBFX. As a result, PBF GP may manage 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.
Herman Seedorf serves as our Senior Vice President of Refining. Mr. Seedorf originally joined us in February of 2011 as the Delaware City Refinery Plant Manager and became Senior Vice President, Eastern Region Refining, in September of 2013. Prior to 2011, Mr. Seedorf served as the refinery manager of the Wood River Refinery in Roxana, Illinois, and also as an officer of the joint venture between ConocoPhillips and Cenovus Energy Inc. Mr. Seedorf’s oversight responsibilities included the development and execution of the multi-billion dollar upgrade project which enabled the expanded processing of Canadian crude oils. He also served as the refinery manager of the Bayway Refinery in Linden, New Jersey for four years during the time periodway that it was an asset of Tosco. Mr. Seedorf began his career in the petroleum industry with Exxon Corporation (“Exxon”) in 1980.
Trecia Canty has served as our Senior Vice President, General Counsel and 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.
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.
In connection with the Paulsboro refinery acquisition, we assumed certain environmental remediation obligations. The Paulsboro environmental liability of $11.0 million recorded as of December 31, 2018 ($10.3 million as of December 31, 2017) represents the present value of expected future costs discounted at a rate of 8.0%. The current portion of the environmental liability is recorded in Accrued expenses and the non-current portion is recorded in Other long-term liabilities. As of December 31, 2018 and December 31, 2017, this liability is self-guaranteed by us.
In connection with the acquisition of the Delaware City assets, Valero Energy Corporation (“Valero”) remains responsible for certain pre-acquisition environmental obligations up to $20.0 million and the predecessor to Valero in ownership of the refinery retains other historical obligations.
In connection with the acquisition of the Delaware City assets and the Paulsboro refinery, the Company and Valero purchased ten year, $75.0 million environmental insurance policies to insure against unknown environmental liabilities at each site. In connection with the Toledo refinery acquisition, Sunoco, Inc. (R&M) remains responsible for environmental remediation for conditions that existed on the closing date for twenty years from March 1, 2011, subject to certain limitations.
In connection with the acquisition of the Chalmette refinery, we obtained $3.9 million in financial assurance (in the form of a surety bond) to cover estimated potential site remediation costs associated with an agreed to Administrative Order of Consent with the United States Environmental Protection Agency (“EPA”). The estimated cost assumes remedial activities will continue for a minimum of thirty years. Further, in connection with the acquisition of the Chalmette refinery, we purchased a ten year, $100.0 million environmental insurance policy to insure against unknown environmental liabilities at the refinery. At the time we acquired the Chalmette refinery it was subject to a Consolidated Compliance Order and Notice of Potential Penalty (the “Order”) issued by the Louisiana Department of Environmental Quality (“LDEQ”) covering deviations from 2009 and 2010. Chalmette Refining and LDEQ subsequently entered into a dispute resolution agreement to negotiate the resolution of deviations on or before December 31, 2014. On May 18, 2018 the Order was settled by LDEQ and the Chalmette refinery for an administrative penalty of $741,000, of which $100,000 has been paid in cash and the remainder has been spent on beneficial environmental projects.
The Delaware City refinery appealed a Notice of Penalty Assessment and Secretary’s Order issued in March 2017, including a $150,000 fine, alleging violation of a 2013 Secretary’s Order authorizing crude oil shipment by barge. The Delaware Department of Natural Resources and Environmental Control (the “DNREC”) determined that the Delaware City refinery had violated the order by failing to make timely and full disclosure to DNREC about the nature and extent of those shipments, and had misrepresented the number of shipments that went to other facilities. The Penalty Assessment and Secretary’s Order conclude that the 2013 Secretary’s Order was violated by the refinery by shipping crude oilmay differ from the Delaware City terminal to three locations other than the Paulsboro refinery, on 15 days in 2014, making a totalbest interests of 17 separate barge shipments containing approximately 35.7 million gallons of crude oil in total. On April 28, 2017, the Delaware City refinery appealed the Notice of Penalty Assessment and Secretary’s Order. On March 5, 2018, Notice of Penalty Assessment was settled by DNREC, the Delaware Attorney General and Delaware City refinery for $100,000. The Delaware City refinery made no admissions with respect to the alleged violations and agreed to request a Coastal Zone Act status decision prior to making crude oil shipments to destinations other than Paulsboro. The Coastal Zone Act status decision request was submitted to DNREC and the outstanding appeal was withdrawn as required under the settlement agreement.PBF Energy or its stockholders.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
See “Item 1. Business”.
ITEM 3. LEGAL PROCEEDINGS
On December 28, 2016, DNREC issued a Coastal Zone Act permit (the “Ethanol Permit”)the Ethanol Permit to DCR allowing the utilization of existing tanks and existing marine loading equipment at their existing facilities to enable denatured ethanol to be loaded from storage tanks to marine vessels and shipped to offsite facilities. On January 13, 2017, the issuance of the Ethanol Permit was appealed by two environmental groups. On February 27, 2017, the Coastal Zone Industrial Control Board (the “Coastal Zone Board”) held a public hearing and dismissed the appeal, determining that the appellants did not have standing. The appellants filed an appeal of the Coastal Zone Board’s decision with the Delaware Superior Court (the “Superior Court”) on March 30, 2017. On January 19, 2018, the Superior Court rendered an Opinion regarding the decision of the Coastal Zone Board to dismiss the appeal of the Ethanol Permit for the ethanol project. The Judgejudge determined that the record created by the Coastal Zone Board was insufficient for the Superior Court to make a decision, and therefore remanded the case back to the Coastal Zone Board to address the deficiency in the record. Specifically, the Superior Court directed the Coastal Zone Board to address any evidence concerning whether the appellants’ claimed injuries would be affected by the increased quantity of ethanol shipments. On remand, the Coastal Zone Board met on January 28, 2019 and reversed its previous decision on standing ruling that the appellants have standing to appeal the issuance of the Ethanol Permit. The parties to the action filed a joint motion with the Coastal Zone Board, requesting that the Coastal Zone Board concur with the parties’ proposal to secure from the Superior Court confirmation that all rights and claims are preserved for any subsequent appeal to the Superior Court, and that the matter then be scheduled for a hearing on the merits before the Coastal Zone Board. The Coastal Zone Board notified the parties in January of 2020 that it concurred with the parties’ proposed course of action. The appellants and DCR is currently evaluating its appeal options.subsequently filed a motion with the Superior Court requesting relief consistent with what was described to the Coastal Zone Board. In March of 2020, the Superior Court issued a letter relinquishing jurisdiction over the matter, and concurring with the parties’ proposal to allow the case to proceed to a hearing on the merits before the Coastal Zone Board. The parties must now jointly propose to the Coastal Zone Board a schedule for prehearing activity and a merits hearing to resolve the matter. The parties must, therefore, submit to the Coastal Zone Board a joint proposed schedule to govern future proceedings related to the merits hearing to resolve the matter.
AtOn September 11, 2020, DCR received two Citations and Notification of Penalties, with sub-parts, from OSHA related to a combustion incident occurring on March 11, 2020. The citation seeks to impose penalties in the time we acquired the Toledo refinery, EPA had initiated an investigation into the complianceamount of $401,923 related to alleged violations of the refineryOccupation Safety and Health Act of 1970. An informal conference with EPA standards governing flaring pursuant to Section 114 ofOSHA on October 2, 2020 was unsuccessful in resolving the Clean Air Act. On February 1, 2013, EPA issued an Amended Notice of Violation,matter, and, on September 20, 2013, EPA issuedas a result, DCR filed a Notice of Violation and Finding of Violation to Toledo refinery, alleging certain violationsContest with OSHA contesting the citations in their entirety at the end of the Clean Air Act atinformal conference. OSHA filed its PlantComplaint on December 13, 2020, and DCR filed its response on January 4, 2021. OSHA and Plant 9 flaresDCR participated in mandatory meditation on February 2, 2021, which was unsuccessful. On February 25, 2021, the Occupational Safety and Health Review Commission granted the parties’ Joint Motion for Additional Time for the Parties to Discuss Settlement. The Court has since granted multiple additional extensions. On May 27, 2021, the acquisitionparties notified the court that settlement negotiations are continuing and have continued to provide updates on the settlement negotiations. Subsequently, OSHA and DCR reached a settlement agreement with an assessed penalty of $401,923 and DCR agreed to undertake certain abatement measures. On January 24, 2022, DCR and the refineryUnited Steelworkers signed the settlement agreement, and on March 1, 2011. Toledo refineryJanuary 25, 2022, OSHA executed the agreement.
On September 27, 2021, DCR received a Notice of Administrative Penalty Assessment and EPA subsequently entered into tolling agreements pendingSecretary’s Order from DNREC, seeking to impose penalties in the amount of $285,000 related to alleged Title V permit violations occurring in 2019 and 2020. On October 15, 2021, DCR filed a Notice of Appeal before Delaware’s Environmental Appeals Board, contesting the Secretary’s findings and requesting a hearing. On November 2, 2021, the Environmental Appeals Board scheduled a Pre-Hearing Conference for April 8, 2022 and Hearing Date for April 26, 2022. On November 30, 2021, settlement discussions. Although the resolution has not been finalized, the civil administrative penalty is anticipatednegotiations commenced, which are continuing to be approximately $645,000 including supplemental environmental projects. To the extent the administrative penalty exceeds such amount, it is not expected to be material to us.date.
In connection with the acquisition of the Torrance refinery and related logistics assets, we assumed certain pre-existing environmental liabilities totaling $130.8 million as of December 31, 2018 ($136.5 million as of December 31, 2017), related to certain environmental remediation obligations to address existing soil and groundwater contamination and monitoring activities, and other clean-up activities, which reflectsreflect the current estimated cost of the remediation obligations. The current portion of the environmental liability is recorded in Accrued expenses and the non-current portion is recorded in Other long-term liabilities in our consolidated balance sheet. 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
Subsequent to the acquisition, we assumed responsibility for certain specified environmental matters that occurred prior to our ownershipNotices of the refinery and the logistics assets, including specified incidents and/or notices of violationsViolations (“NOVs”) were 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”).
In connection with the acquisition of the Torrance refinery and related logistics assets, we agreed to take responsibility for NOV No. P63405 that ExxonMobil had received from the SCAQMD for Title V deviations that are alleged to have occurred in 2015. On August 14, 2018, we received a letter from SCAQMD offering to settle this NOV for $515,250. We are currently in communication with SCAQMD to resolve this NOV.
Subsequent to the acquisition, further NOVs were issued by the SCAQMD, Cal/OSHA, the City of Torrance, the City of Torrance Fire Department, and the Los Angeles County Sanitation District related to alleged operational violations, emission discharges and/or flaring incidents at the refinery and the logistics assets both before and after our acquisition. EPA in November 2016 conducted a Risk Management Plan (“RMP”) inspection following the acquisition related to Torrance operations and issued preliminary findings in March 2017 concerning RMP potential operational violations. Effective January 9, 2020, we and EPA entered into a Consent Agreement and Final Order (“CAFO”), which contains no admission by us for any alleged violations in the CAFO, includes a release from all alleged violations in the CAFO, requires the payment of a penalty of $125,000 in January 2020 and also requires the implementation of a supplemental environmental project (“SEP”) of at least $219,000 that must be completed by December 15, 2021. The SEP consisted of configuring the northeast fire water monitor to automatically deploy water upon detection of a release. We are currently in communication withcompleted this reconfiguration on December 15, 2021 and expended at least $219,000 as required by the CAFO. On February 11, 2022, we submitted the final SEP Completion Report to EPA, towhich should fully resolve the RMP preliminary findings. this matter.
EPA and the California Department of Toxic Substances Control (“DTSC”) in December 2016 conducted a Resource Conservation and Recovery Act (“RCRA”) inspection following the acquisition related to Torrance operations and also issued in March 2017 preliminary findings concerning RCRA potential operational violations. In April 2017, EPA referred the RCRA preliminary findings to DTSC for final resolution. On March 1, 2018, we received a notice of intent to sue from Environmental Integrity Project, on behalf of Environment California, under RCRA with respect to the alleged violations from EPA’s and DTSC’s December 2016 inspection. On March 2, 2018, DTSC issued an order to correct alleged RCRA violations relating to the accumulation of oil bearing materials in roll off bins during 2016 and 2017. On June 14, 2018, the Torrance refinery and DTSC reached settlement regarding the oil bearing materials in the form of a stipulation and order, wherein the Torrance refinery agreed that it would recycle or properly dispose of the oil bearing materials by the end of 2018 and pay an administrative penalty of $150,000. The Torrance refinery has complied with these requirements.materials. Following this settlement, in June 2018, DTSC referred the remaining alleged RCRA violations from EPA’s and DTSC’s December 2016 inspection to the California Attorney GeneralGeneral. On April 7, 2021, we were notified that these alleged remaining six federal RCRA violations had been referred to EPA for final resolution. On June 2, 2021, EPA conducted a further inspection to the December 2016 RCRA inspection. On August 13, 2021, we received EPA’s additional report indicating that the six federal RCRA findings were closed with no further enforcement action. The Torrance refinery andremaining alleged state RCRA violation is still pending with the California Attorney GeneralGeneral.
On February 4, 2021, we received a letter from the SCAQMD proposing to settle a NOV relating to 15 Title V deviations alleged to have occurred in the second half of 2017 for $1.3 million. On October 8, 2021, we reached settlement in principle with the SCAQMD to pay a penalty of $250,000 for 14 of the Title V deviations and a penalty of $1.3 million for the remaining deviation, which covers the period of 2017 through 2021 and settlement agreements are in process.
On December 4, 2020, the Pennsylvania Department of Environmental Protection ("PaDEP") issued a draft Consent Order and Agreement (“CAO”) to PBF Logistics Products Terminals LLC (“PLPT”) with respect to two alleged violations at the Philadelphia terminal for failure to: 1) test and inspect regulated piping as required in accordance with industry standards; and 2) have a professional engineering certification that all above ground storage tanks meet the applicable performance standards and requirements as a result of an alleged release of oil on January 10, 2020 into the Schuylkill River resulting from a pipe leak that was not contained by emergency containment structure. The draft order included a proposed penalty of $800,000. On December 15, 2021, we entered into a final CAO and agreed to pay the $800,000 penalty. Under the final CAO, we capped our future liability at $250,000 if PaDEP brought a subsequent enforcement action under the Pennsylvania Clean Streams Law (“CSL”) for environmental damage allegedly caused by the release of oil from PLPT’s operational violations. Under the final CAO, we also reserved our rights to challenge any subsequent enforcement action brought by PaDEP under the CSL. On January 13, 2022, we received from
PaDEP, a Consent Assessment of Civil Penalty alleging violations under the CSL of over $1.0 million. However, because of the CAO cap, the PaDEP’s penalty demand to settle these alleged violations is $250,000. We are currently reviewing the alleged violations and settlement offer.
In connection with self-reported flaring events that occurred at the Paulsboro Refinery between 2016 and 2020, in October 2021, the New Jersey Department of Environmental Protection (“NJDEP”) initiated discussions with PRC regarding potential penalties for alleged violations related to the self-reported flaring events. Although a formal NOV has not been issued, NJDEP provided a calculation sheet of potential penalties totaling approximately $1.6 million. We are currently challenging certain of those potential penalties and are in discussions to resolve these remaining alleged RCRA violations. Other than the $150,000 DTSC administrative penalty, no other settlement or penalty demands have been received to date with respect to any of the other NOVs, preliminary findings, or order that are in excess of $100,000. NJDEP regarding a potential settlement.
As the ultimate outcomes of the 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.
In connectionOn 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 and alleges negligence, strict liability, ultra-hazardous activity, a continuing private nuisance, a permanent private nuisance, a continuing public nuisance, a permanent public nuisance and trespass resulting from the February 18, 2015 electrostatic precipitator (“ESP”) 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 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 to file a Second Amended Complaint alleging groundwater contamination. With the filing of the Second Amended Complaint, plaintiffs added an additional 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 PBFX Plains Asset Purchase (as defined in “Note 4 - Acquisitions” ofnew deadlines. On October 8, 2021, plaintiffs filed their Motion to Appoint Navarro as Class Representative. On October 29, 2021, we filed our Notesopposition to Consolidated Financial Statements), PBFX is responsiblethis 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 environmental remediation costs for conditions that existed onCourt’s consideration. All other dates are stayed pending the closing date up to a maximumCourt issuing its order. We presently believe the outcome of $250,000 per year for ten years, with Plains All American Pipeline, L.P. remaining responsible for any and all additional costs above such amounts during such period. The recorded environmental liability associated with the PBFX Plains Asset Purchase as of December 31, 2018 and December 31, 2017 was $1.6 million and $1.9 million, respectively.
In connection with the Knoxville Terminal Purchase (as defined in “Note 4 - Acquisitions” of our Notes to Consolidated Financial Statements), PBFX and Cummins purchased a ten-year, $30.0 million environmental insurance policy against unknown environmental liabilities. PBFX didthis litigation will not assume, and is currently not aware of, any material pre-existing environmental obligations. Additionally, the seller remains responsible for pre-acquisition environmental obligations up to a specified amount for a specified period of time.
In connection with the East Coast Storage Assets Acquisition (as defined in “Note 4 - Acquisitions” of our Notes to Consolidated Financial Statements), PBFX purchased a ten-year, $30.0 million environmental insurance policy against unknown environmental liabilities. Additionally, the seller remains responsible for pre-acquisition environmental obligations up to a specified amount for a specified period of time. The recorded environmental liability associated with the East Coast Storage Assets Acquisition as of December 31, 2018 was $885,000.
Applicable Federal and State Regulatory Requirements
Our operations and many of the products we manufacture are subject to certain specific requirements of the Clean Air Act (the “CAA”) and related state and local regulations. The CAA contains provisions that require capital expenditures for the installation of certain air pollution control devices at our refineries. Subsequent rule making authorized by the CAA or similar laws or new agency interpretations of existing rules, may necessitate additional expenditures in future years.
In 2010, New York State adopted a Low-Sulfur Heating Oil mandate that, beginning July 1, 2012, requires all heating oil sold in New York State to contain no more than 15 parts per million (“PPM”) sulfur. Since July 1, 2012, other states in the Northeast market began requiring heating oil sold in their state to contain no more than 15 PPM sulfur. Currently, all of the Northeastern states and Washington DC have adopted sulfur controls on heating oil. As of July 1, 2018, most of the Northeastern states require heating oil with 15 PPM or less sulfur (except for Pennsylvania and Maryland - where less than 500 PPM sulfur is required). All of the heating oil we currently produce meet these specifications. The mandate and other requirements do not currently have a material impact on our financial position, results of operations, or cash flows.
On September 7, 2018, in Jeprece Roussell, et al. v. PBF Consultants, LLC, et al., the final Tier 3 Gasoline standardsplaintiff filed an action in the 19th Judicial District Court for the Parish of East Baton Rouge, alleging numerous causes of action, including wrongful death, premises liability, negligence, and gross negligence against PBF Holding, PBFX Operating Company LLC, Chalmette Refining, two individual employees of the Chalmette refinery (the defendants), two entities, PBF Consultants, LLC and PBF Investments that are Louisiana companies that are not associated with our companies, as well as Clean Harbors, Inc. and Clean Harbors Environmental Services, Inc. (collectively, “Clean Harbors”), Mr. Roussell’s employer. Mr. Roussell was fatally injured on March 3, 2014 under the CAA. This final rule establishes more stringent vehicle emission standards31, 2018 while employed by Clean Harbors and further reduces the sulfur content of gasoline starting in January 2017. The new standard is set at 10 PPM sulfur in gasoline on an annual average basis starting January 1, 2017, withperforming clay removal work activities inside a credit trading program to provide compliance flexibility. EPA responded to industry comments on the proposed rule and maintained the per gallon sulfur cap on gasolineclay treating vessel located at the existing 80 PPM cap. The refineries are complyingChalmette refinery. Plaintiff sought unspecified compensatory damages for pain and suffering, past and future mental anguish, impairment, past and future economic loss, attorney’s fees and court costs. On October 8, 2021, we and our insurers reached an agreement in principle to settle this litigation and the related matters. Our portion of the settlement was accrued as of September 30, 2021 and did not have a material impact on our financial position, results of operations, or cash flows. Settlement documents have been executed and payments have been made. A Motion to Dismiss with these new requirements as planned, either directly or using flexibility provided by sulfur credits generated or purchased in advance as an economic optimization. The standards setPrejudice was filed by the new rule areparties on February 3, 2022.
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 expectedpresented 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 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. We presently believe the outcome will not have a material impact on our financial position, results of operations, or cash flows.
We are required to comply with the Renewable Fuel Standard (“RFS”) implemented by EPA, which sets annual quotas for the quantity of renewable fuels (such as ethanol) that must be blended into motor fuels consumed in the United States. In July 2018, EPA issued proposed amendments to the RFS program regulations that would establish annual percentage standards for cellulosic biofuel, biomass-based diesel, advanced biofuel, and renewable fuels that would apply to all gasoline and diesel produced in the U.S. or imported in the year 2019. In addition, the separate proposal includes a proposed biomass-based diesel applicable volume for 2020. It is likely that RIN production will continue to be lower than needed forcing obligated parties, such as us, to purchase cellulosic waiver credits or purchase excess RINs from suppliers on the open market.
In addition, on November 26, 2018 EPA finalized revisions to an existing air regulation concerning Maximum Achievable Control Technologies (“MACT”) for Petroleum Refineries. The regulation requires additional continuous monitoring systems for eligible process safety valves relieving to atmosphere, minimum flare gas heat (Btu) content, and delayed coke drum vent controls to be installed by January 30, 2019. In addition, a program for ambient fence line monitoring for benzene was implemented prior to the deadline of January 30, 2018. We are in the process of implementing the requirements of this regulation. The regulation does not have a material impact on our financial position, results of operations or cash flows.
EPA published a Final Rule to the Clean Water Act (“CWA”) Section 316(b) in August 2014 regarding cooling water intake structures, which includes requirements for petroleum refineries. The purpose of this rule is to prevent fish from being trapped against cooling water intake screens (impingement) and to prevent fish from being drawn through cooling water systems (entrainment). Facilities will be required to implement Best Technology Available (“BTA”) as soon as possible, but state agencies have the discretion to establish implementation time lines. We continue to evaluate the impact of this regulation, and at this time do not anticipate it having a material impact on our financial position, results of operations or cash flows.
As a result of the Torrance Acquisition, we are subject to greenhouse gas emission control regulations in the state of California pursuant to Assembly Bill 32 (“AB32”). AB32 imposes a statewide cap on greenhouse gas emissions, including emissions from transportation fuels, with the aim of returning the state to 1990 emission levels by 2020. AB32 is implemented through two market mechanisms including the Low Carbon Fuel Standard (“LCFS”) and Cap and Trade, which was extended for an additional ten years to 2030 in July 2017. We are responsible for the AB32 obligations related to the Torrance refinery beginning on July 1, 2016 and must purchase emission credits to comply with these obligations. Additionally, in September 2016, the state of California enacted Senate Bill 32 (“SB32”) which further reduces greenhouse gas emissions targets to 40 percent below 1990 levels by 2030.
However, subsequent to the acquisition, we are recovering the majority of these costs from our customers, and as such do not expect this obligation to materially impact our financial position, results of operations, or cash flows. To the degree there are unfavorable changes to AB32 or SB32 regulations or we are unable to recover such compliance costs from customers, these regulations could have a material adverse effect on our financial position, results of operations, and cash flows.
We are subject to obligations to purchase RINs. On February 15, 2017, we received a notification that EPA records indicated that PBF Holding used potentially invalid RINs that were in fact verified under EPA’s RIN Quality Assurance Program (“QAP”) by an independent auditor as QAP A RINs. Under the regulations use of potentially invalid QAP A RINs providedprovides the user with an affirmative defense from civil penalties provided certain conditions are met. We have asserted the affirmative defense and if accepted by EPA will not be required to replace these RINs and will not be subject to civil penalties under the program. It is reasonably possible that EPA will not accept our defense and may assess penalties in these matters, but any such amount is not expected to have a material impact on our financial position, results of operations, or cash flows.
As of January 1, 2011, we are required to comply with EPA’s Control of Hazardous Air Pollutants From Mobile Sources, or MSAT2, regulations on gasoline that impose reductions in the benzene content of our produced gasoline. We purchase benzene credits to meet these requirements. Our planned capital projects will reduce the amount of benzene credits that we need to purchase. In addition, the renewable fuel standards mandate the blending of prescribed percentages of renewable fuels (e.g., ethanol and biofuels) into our produced gasoline and diesel. These new requirements, other requirements of the CAA and other presently existing or future environmental regulations may cause us to make substantial capital expenditures as well as the purchase of credits at significant cost, to enable our refineries to produce products that meet applicable requirements.
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.
ITEM 4. MINE SAFETY DISCLOSURES
None.
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 Energy Class B common stock is not publicly-traded.
As of February 10, 2022 there were 31 holders of record of PBF Energy Class A common stock and 15 holders of record of PBF Energy Class B common stock.
Dividend and Distribution Policy
PBF Energy
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 case with all companies engagedholders of PBF LLC Series A Units, and PBF LLC needs to cause PBF Holding and/or PBFX to make distributions to it, in industries similarat least an amount sufficient to ours, we face potential exposurecover 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 future claims and lawsuits involving environmental 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 expecteda member 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, 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 expenditures formay be, limited by covenants in its Revolving Credit Facility, the 2025 Senior Secured Notes, the 2028 Senior Notes, the 2025 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.
While it is impossible to estimate the duration or ultimate financial impact of the COVID-19 pandemic on our business, our results have been adversely impacted. As part of our strategic plan to navigate these purposescurrent extraordinary and volatile markets, we have suspended PBF Energy’s quarterly dividend on its Class A common stock. We will continue to monitor and evaluate our dividend policy as market conditions develop and our business outlook becomes clearer, however, we do not anticipate that our Board of Directors will declare a dividend in the foreseeable future.
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 materialnot 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).
PBF Logistics LP
Due to the uncertainty of the full impact of the COVID-19 pandemic will have on its business, PBFX has decided to reduce their quarterly distribution to its minimum quarterly distribution of $0.30 per unit, which represents a shift in its distribution strategy to build cash flow coverage, de-lever the business and can be reasonablystrengthen its financial resources as they continue to pursue potential organic growth projects or strategic acquisition opportunities. PBFX intends to continue to pay at least the minimum quarterly distribution to the holders of its common units, including PBF LLC, of at least $0.30 per unit per quarter, or $1.20 per unit on an annualized basis, to the extent PBFX has sufficient cash from operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to PBFX’s general partner. However, there is no guarantee that PBFX will pay the minimum quarterly distribution or any amount on the units they 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 these costs are disclosedby its general partner, taking into consideration the terms of PBFX’s partnership agreement and accrued.debt facilities.
Our operations are also subject to various laws and regulations relating to occupational health and safety. We maintain safety training and maintenance programsDuring 2020, PBF Energy announced that it had suspended its quarterly dividend of $0.30 per share on its Class A common stock as part of our ongoing effortsits strategic plan to ensure compliancerespond to the impact of the COVID-19 outbreak. As a result, there were no dividends or distributions for the year ended December 31, 2021. There were no tax distributions to PBF LLC’s other members in 2021. PBF Holding made $2.7 million in distributions to PBF LLC during the year ended December 31, 2021. In addition, PBFX made aggregate quarterly distributions of $76.0 million ($1.20 per unit) during the year ended December 31, 2021 to holders of its common units, of which $35.9 million was paid to PBF LLC.
PBF LLC expects to continue to make tax distributions to its members in accordance with applicable lawsits amended and regulations. Compliancerestated limited liability company agreement.
Stock Performance Graph
In accordance 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 effectiveSEC 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.
This performance graph and the related textual information are based on historical data and are not indicative of future performance. The following line graph compares the cumulative total return on an investment in our common stock against the cumulative total return of the S&P 500 Composite Index and an index of peer companies (that we selected) for the periods commencing December 31, 2016 through December 31, 2021. Our peer group consists of the following companies that are engaged in refining operations in the U.S.: CVR Energy Inc., Delek US Holdings Inc., HollyFrontier Corp, Marathon Petroleum Corp, Phillips 66 and Valero Energy Corp.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 12/31/2016 | | 12/31/2017 | | 12/31/2018 | | 12/31/2019 | | 12/31/2020 | | 12/31/2021 |
| PBF Energy Class A common stock | $ | 100.00 | | | $ | 133.57 | | | $ | 126.97 | | | $ | 127.18 | | | $ | 29.13 | | | $ | 53.22 | |
| S&P 500 | 100.00 | | | 121.83 | | | 116.49 | | | 153.17 | | | 181.35 | | | 233.41 | |
| Peer Group | 100.00 | | | 132.54 | | | 117.97 | | | 142.91 | | | 94.07 | | | 126.35 | |
Recent Sales of Unregistered Securities—Exchange of PBF LLC Series A Units for PBF Energy Class A Common Stock
In the fourth quarter of 2021, there were 66,202 PBF LLC Series A Units exchanged for 66,202 shares of PBF Energy Class A common stock in transactions exempt from registration under Section 4(a)(2) of the Securities Act. We received no other consideration in connection with any exchanges. No exchanges were made by any of our directors or how existingexecutive officers.
ITEM 6. [RESERVED]
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following review of our results of operations and financial condition should be read in conjunction with “Item 1. Business”, “Item 1A. Risk Factors”, “Item 2. Properties”, and “Item 8. Financial Statements and Supplementary Data,” respectively, included in this Annual Report on Form 10-K.
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 lawsindustry 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 regulations will be administeredlimited 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 upon 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 interpretedpersons 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:
•the effect of the COVID-19 pandemic, including resurgences and variants of the virus, as well as related governmental and consumer responses on our business, financial condition and results of operations;
•supply, demand, prices and other market conditions for our products or crude oil, including volatility in commodity prices or constraints arising from federal, state or local governmental actions or environmental and/or social activists that reduce crude oil production or availability in the regions in which we operate our pipelines and facilities;
•the effectiveness of our crude oil sourcing strategies, including our crude by rail strategy and related commitments;
•our obligation to buy RINs and market risks related to the volatility in the price of RINs required to comply with the Renewable Fuel Standard and GHG emission credits required to comply with various GHG emission programs, such as AB 32;
•our ability to operate our businesses efficiently, manage capital expenditures and costs (including general and administrative expenses) and generate earnings and cash flow;
•our expectations with respect to our operations. Compliance with more stringentcapital improvement and turnaround projects;
•the impact of current and future laws, rulings and governmental regulations, including restrictions on the exploration and/or production of crude oil in the state of California, the implementation of rules and regulations regarding transportation of crude oil by rail or in response to the potential impacts of climate change, decarbonization and future energy transition;
•adverse impacts related to legislation by the federal government lifting the restrictions on exporting U.S. crude oil;
•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 the interpretation of existing requirements or discovery of new informationour regulatory environment, such as unknown contaminationthe 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 may not reinstate dividend payments;
•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, 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 substantial indebtedness, including the impact of potential downgrades to our corporate credit rating, secured notes 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;
•counterparty credit and performance risk exposure related to our supply and inventory intermediation arrangement;
•termination of our Third Inventory Intermediation Agreement with J. Aron, which is scheduled to expire in December 2024 and could have ana material adverse effect on our liquidity, as we would be required to finance our crude oil, intermediate and refined products inventory covered by the financial positionagreement. Additionally, we are obligated to repurchase from J. Aron certain J. Aron Products upon termination of the agreement;
•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 resultsamount and timing of our income;
•the impact of disruptions to crude or feedstock supply to any of our refineries, including disruptions related to PBFX or with third-party logistics infrastructure or operations, including pipeline, marine and could require substantial expenditures forrail transportation;
•risks associated with the installation and operation of systemsPBFX as a separate, publicly-traded entity;
•potential tax consequences related to our investment in PBFX; and equipment
•any decisions we continue to make with respect to our energy-related logistics assets that may be transferred to PBFX.
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 its subsidiaries. We own and operate six domestic oil refineries and related assets located in Delaware City, Delaware, Paulsboro, New Jersey, Toledo, Ohio, Chalmette, Louisiana, Torrance, California, and Martinez, California. Based on current configuration (subsequent to the East Coast Refining Reconfiguration), our refineries have a combined processing capacity, known as throughput, of approximately 1,000,000 bpd, and a weighted-average Nelson Complexity Index of 13.2 based on current operating conditions. The complexity and throughput capacity of our refineries are subject to change dependent upon configuration changes we make to respond to market conditions as well as a result of investments made to improve our facilities and maintain compliance with environmental and governmental regulations. We operate in two reportable business segments: Refining and Logistics. Our six oil refineries are all engaged in the refining of crude oil and other feedstocks into petroleum products, and are aggregated into the Refining segment. PBFX operates certain logistical assets such as crude oil and refined products terminals, pipelines, and storage facilities, which are aggregated into 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.
COVID-19 and Market Developments
The impact of the unprecedented global health and economic crisis sparked by the COVID-19 pandemic was amplified late in the quarter ended March 31, 2020 due to movements made by the world’s largest oil producers to increase market share. This created simultaneous shocks in oil supply and demand resulting in an economic challenge to our industry which has not occurred since our formation. This combination resulted in significant demand reduction for our refined products and atypical volatility in oil commodity prices. In 2021, as a result of the lifting or easing of restrictions by many governmental authorities and the distribution of COVID-19 vaccines and other protective measures, the demand for refined products started to recover, consequently improving our refining margins in comparison to the prior year. While our results for the year ended December 31, 2021 were impacted by lower demand for refined products, we experienced gradual improvements when compared to the year ended December 31, 2020 and favorable impacts on our revenues, cost of products sold, operating income and liquidity. Although we currently possess.
continue to operate our refineries at reduced rates, throughput rates across our refining system have increased in the current year to correlate with the gradual increases in demand.
Debt and Credit Facilities
ITEM 1A. RISK FACTORSSenior Notes
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 May 13, 2020, we issued $1.0 billion in aggregate principal amount of the initial 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 December 21, 2020, we issued 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 January 24, 2020, we issued $1.0 billion in aggregate principal amount of the 2028 Senior Notes. The net proceeds from this offering were approximately $987.0 million after deducting the initial purchasers’ discount and offering expenses. We used $517.5 million of the proceeds to fully redeem our 7.00% senior notes due 2023 (the “2023 Senior Notes”) and the balance to fund a portion of the cash consideration for Martinez Acquisition (as defined below).
On February 14, 2020, we exercised our rights under the indenture governing the 2023 Senior Notes to redeem all of the outstanding 2023 Senior Notes at a price of 103.5% of the aggregate principal amount thereof plus accrued and unpaid interest. The aggregate redemption price for all 2023 Senior Notes approximated $517.5 million plus accrued and unpaid interest. The difference between the carrying value of the 2023 Senior Notes on the date they were redeemed and the amount for which they were redeemed was $22.2 million and has been classified as Loss on extinguishment of debt in the Consolidated Statements of Operations for the year ending December 31, 2020.
Catalyst Financing Obligations
In September and October 2021, we settled certain precious metal financing arrangements, resulting in a reduction to debt of approximately $31.7 million.
On September 25, 2020, we closed on agreements to sell a portion of our precious metals catalyst to certain major commercial banks for approximately $51.9 million and subsequently leased the catalyst back. The precious metals financing arrangements cover a portion of the catalyst used in our East Coast Refining System, Martinez and Toledo refineries.
The volumes of the precious metal catalyst and the interest rates are fixed over the term of each financing arrangement. We are obligated to repurchase the precious metals catalyst at fair market value upon expiration of these leases. For all leases not renewed at maturity, we have the ability and intent to finance such debt through availability under our revolving credit facilities.
PBF Holding Revolving Credit Facility
During the year ended December 31, 2020, we used advances under our Revolving Credit Facility to fund a portion of the Martinez Acquisition (as defined below) and for other general corporate purposes. The outstanding borrowings under the Revolving Credit Facility as of December 31, 2021 and December 31, 2020 were $900.0 million.
PBFX Revolving Credit Facility
During the year ended December 31, 2021 and December 31, 2020, PBFX made net repayments of $100.0 million and $83.0 million on the PBFX Revolving Credit Facility. The outstanding borrowings under the PBFX Revolving Credit Facility were $100.0 million as of December 31, 2021.
Refer to “Note 10 - Credit Facilities and Debt” of our Notes to Consolidated Financial Statements, for further information.
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 and August 1, 2019, we closed on third-party sales of parcels of real property acquired as part of the Torrance refinery, but not part of the refinery itself. The sales resulted in gains of approximately $8.1 million and $33.1 million in the fourth quarter of 2020 and third quarter of 2019, respectively, 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. Based on this reconfiguration, our East Coast throughput capacity currently approximates 285,000 barrels per day.
Turnaround Costs and Assets under Construction
As of December 31, 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 the fourth quarter of 2020.
Capital Project Abandonments
In connection with our ongoing strategic initiative to address the COVID-19 pandemic, including our East Coast Refining Reconfiguration, we reassessed our refinery wide slate of capital projects that were either in process or not yet placed into service as of December 31, 2020. Based on this reassessment and our strategic plan to reduce capital expenditures, we decided to abandon various capital projects across the refining system, resulting in an impairment charge of approximately $79.9 million in the fourth quarter of 2020.
Severance Costs
Following the onset of the COVID-19 pandemic, 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, 2021, a liability for the Tax Receivable Agreement of $48.3 million reflecting the estimate of the undiscounted amounts that PBF Energy expects to pay under the agreement, net of the impact of a deferred tax asset valuation allowance recognized in accordance with ASC 740. 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 14 - Commitments and Contingencies” and “Note 21 - 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.
Martinez Acquisition
We acquired the Martinez refinery and related logistics assets from Shell Oil Products on February 1, 2020 for an aggregate purchase price of $1,253.4 million (the “Martinez Acquisition”), including final working capital of $216.1 million and the obligation to make certain post-closing earn-out payments to Shell Oil Products based on certain earnings thresholds of the Martinez refinery for a period of up to four years (the “Martinez Contingent Consideration”). The transaction was financed through a combination of cash on hand, including proceeds from the 2028 Senior Notes, and borrowings under the Revolving Credit Facility.
The Martinez refinery is located on an 860-acre site in the City of Martinez, 30 miles northeast of San Francisco, California. The refinery is a high-conversion 157,000 bpd, dual-coking facility with a Nelson Complexity Index of 16.1, making it one of the most complex refineries in the United States. The facility is strategically positioned in Northern California and provides for operating and commercial synergies with the Torrance refinery located in Southern California. In addition to refining assets, the Martinez Acquisition includes a number of high-quality onsite logistics assets including a deep-water marine facility, product distribution terminals and refinery crude and product storage facilities with approximately 8.8 million barrels of shell capacity.
Inventory Intermediation Agreement
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.
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.
PBFX Equity Offerings
On April 24, 2019, PBFX entered into subscription agreements to sell an aggregate of 6,585,500 common units to certain institutional investors in a registered direct offering (the “2019 Registered Direct Offering”) for gross proceeds of approximately $135.0 million. The 2019 Registered Direct Offering closed on April 29, 2019.
As of December 31, 2021, PBF LLC held a 47.9% limited partner interest in PBFX with the remaining 52.1% limited partner interest owned by public common unitholders.
PBFX Assets and Transactions
PBFX’s assets consist of various logistics assets (as described in “Item 1. Business”). Apart from business associated with certain third-party acquisitions, PBFX’s revenues are derived from long-term, fee-based commercial agreements with subsidiaries of PBF Holding, which include minimum volume commitments, for receiving, handling, transferring and storing crude oil, refined products and natural gas. These transactions are eliminated by PBF Energy and PBF LLC in consolidation.
Since the inception of PBFX in 2014, PBF LLC and PBFX have entered into a series of drop-down transactions. Such transactions and third-party acquisitions made by PBFX occurring in the three years ended December 31, 2021 are discussed below.
TVPC Acquisition
On April 24, 2019, PBFX entered into a contribution agreement with PBF LLC, pursuant to which PBF LLC contributed to PBFX all of the issued and outstanding limited liability company interests of TVP Holding Company LLC (“TVP Holding”) for total consideration of $200.0 million (the “TVPC Acquisition”). Prior to the TVPC Acquisition, TVP Holding owned a 50% membership interest in Torrance Valley Pipeline Company LLC (“TVPC”). Subsequent to the closing of the TVPC Acquisition on May 31, 2019, PBFX owns 100% of the membership interests in TVPC. The transaction was financed through a combination of proceeds from the 2019 Registered Direct Offering and borrowings under the PBFX Revolving Credit Facility.
Risks Relating to Our Business and Industry
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.
•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;
Our revenues, 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 petroleum 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•Volatility in commodity prices and crude oil and other feedstock costs contracts, our earnings, profitability and cash flows are negatively affected. Refining margins historically 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.
In addition, the nature of our business requires 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. 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, 2018, we recorded an adjustment to value our inventories to the lower of cost or market which decreased income from operations and net income by $351.3 million and $259.9 million, respectively, reflecting the net change in the lower of cost or market (“LCM”) inventory reserve from $300.5 million at December 31, 2017 to $651.7 million at December 31, 2018.demand;
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 profitability is affected by crude•Crude oil differentials and related factors, which fluctuate substantially.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 and Torrance refineries. For our Toledo refinery, aside from recent crude differential volatility, purchased crude prices have historically been slightly 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 Dated Brent/WTI 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 advance certain energy infrastructure projects such as the Keystone XL 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.
A significant interruption•Significant interruptions or casualty losslosses at any of our refineries and related assets could reduce our production, particularly if not fully covered by our insurance. Failure by one or more insurers to honor its coverage commitments for an insured event could materially and adversely affect our future cash flows, operating results and financial condition.
Our business currently consists of owning and operating five refineries and related assets. As a result, our operations could be subject to significant interruption if any of our refineries were to experience a major accident, be damaged by severe weatherlogistics terminals, pipelines 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 logistical 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.facilities;
As protection against these hazards, we maintain insurance coverage against some, but not all, such potential losses and liabilities. 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.
Our refineries are subject to interruptions•Interruptions of supply and distribution as a result ofat our reliance on pipelines and railroads for transportation of crude oil and refined products.refineries;
Our Toledo, Chalmette and Torrance refineries receive a significant portion of their crude oil through pipelines. These pipelines include the Enbridge system, Capline and Mid-Valley pipelines for supplying crude to our Toledo refinery, the MOEM and CAM pipelines for supplying crude to our Chalmette refinery•Renewable fuels mandates and the San Joaquin Pipeline, San Ardo and Coastal Pipeline systems for supplying crude to our Torrance refinery. Additionally, our Toledo, Chalmette and Torrance 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 Toledo, the Collins Pipeline at our Chalmette refinery and Jet Pipeline to the Los Angeles International Airport, the Product Pipeline to Vernon and the Product Pipeline to Atwood at our Torrance 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 abilityRINs;
•Existence of these pipelines to transport crude oil or refined products is disrupted because of accidents, weather interruptions, governmental regulation, terrorism, other third-party action or casualty or other events.
The Delaware City rail unloading facilities and our recently acquired East Coast Storage Assets, allow our East Coast refineries 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.
In addition, 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.
Regulation of emissions of greenhouse gases could force us to incur increased capital 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 greenhouse gases (“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 (the “CAA”). 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 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 AB32 regulations in California). Efforts have also been undertaken to delay, limit or prohibit EPA and possibly state action to regulate GHG emissions, and it is not possible at this time to predict the ultimate form, timing or extent of federal or state regulation. In addition, it is currently uncertain how the current presidential administration will address GHG emissions. 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. Such requirements also could adversely affect demand for the refined petroleum products that we produce. Any increased costs or reduced demand could materially and adversely affect our business and results of operation.
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. Additionally, 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, the California Air Resource Board (“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 requires a 10% reduction in the carbon intensity of gasoline and diesel by 2020. 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.
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 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk.”
In addition, these hedging activities involve basis risk. Basis risk in a hedging arrangement occurs when the price of the commodity we hedge is more or less variable than the index upon which the hedged commodity is based, thereby making the hedge less effective. For example, a NYMEX index used for hedging certain volumes of our crude oil or refined products may have more or less variability than the actual cost or price we realize for such crude oil or refined products. We may not hedge all the basis risk inherent in our hedging arrangements and derivative contracts.
We may have capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate.adequate;
If we cannot generate sufficient cash flows or otherwise secure sufficient liquidity to support our short-term•Regulation of emissions of greenhouse gases 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 toother 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 and Inventory Intermediation Agreements. Pursuant to the Inventory Intermediation Agreements, J. Aron purchases and holds title to certain of the intermediate and finished products (the “Products”) produced by the Delaware City and Paulsboro refineries (the “Refineries”) and delivered into the tanks at the refineries (or at other locations outside of the refineries as agreed upon by both parties). Furthermore, J. Aron agrees to sell the intermediate and finished products back to us as they are discharged out of the refineries’ tanks (or other locations outside of the refineries as agreed upon by both parties). We market and sell the finished products independently to third parties.
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 Inventory Intermediation Agreements with J. Aron would require us to finance our refined products inventory covered by the agreements at terms that may not be as favorable. Additionally, we are obligated to repurchase from J. Aron all volumes of products located at the refineries’ storage tanks (or at other locations outside of the refineries as agreed upon by both parties) upon termination of these agreements, which may have a material adverse impact on our 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 consolidated balance sheet. Our long-term needs for cash include those to support ongoing capital expenditures for equipment maintenance and upgrades 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 and Torrance acquisitions, we assumed certain significant environmental obligations, 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.” Our liquidity condition will affect our ability to satisfy any and all of these needs or obligations.regulations;
We may not be able to obtain funding•Enhanced scrutiny on acceptable terms or at all because of volatilityESG matters;
•Volatility and uncertainty in the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.markets;
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 have experienced periods of extreme volatility that have negatively impacted market liquidity conditions. As a result, the cost of raising money in the debt and equity capital markets has increased substantially at times while the availability of funds from those markets diminished 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.
Competition from companies who 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.
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.
A portion of our workforce is unionized, and we may face labor disruptions that would interfere with our operations.
At Delaware City, Toledo, Chalmette and Torrance, most hourly employees are covered by a collective bargaining agreement through the USW. The agreements with the USW covering the Delaware City refinery and Chalmette refinery are scheduled to expire in January 2022, the agreement with the USW covering Toledo is scheduled to expire in February 2022, the agreement with the USW covering certain Torrance Logistics employees is scheduled to expire in April 2021 and the agreements with the USW covering certain PBFX employees are scheduled to expire in April 2021 and February 2022. The agreements with the USW covering the represented employees at the Torrance refinery and Torrance logistics facilities expired in January 2019, with a tentative agreement in place that would extend the respective collective bargaining agreement expiration dates through January 2022 subject to an affirmative ratification vote and execution. Similarly, at the Paulsboro refinery, hourly employees are represented by the IOW under a contract scheduled to expire in March 2022. Future negotiations as our collective agreements expire 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.
•Any political instability, military strikes, sustained military campaigns, terrorist activity, or changes in foreign policy, could have a material adverse effector other catastrophic events;
•A cyber-attack on, our business, results of operations and financial condition.
Any political instability, military strikes, sustained military campaigns, terrorist activity, or changes in foreign policy in areas or regions of the world where we acquire crude oil and other raw materials or sell our refined petroleum 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. Any act of war or terrorism that resulted in damage to anyfailure of, our refineries or third-party facilities upon whichtechnology infrastructure;
•Competition from companies who have not been adversely impacted as much as we are dependent for our business operations could have a material adverse effect on our business, results of operations and financial condition.
Economic turmoil in the global financial system or an economic slowdown or recession in the future may have an adverse impact on the refining industry.
Our business and profitability are affectedbeen by the overall level of demand for our products, which in turn is affected by factors such as overall levels of economic activity and business and consumer confidence and spending. In the past, declines in global economic activity and consumer and business confidence and spending significantly reduced the level of demand for our products. In addition, macroeconomic trends, such as economic recession, inflation, unemployment and interest rates can affect the level of demand for our products. Reduced demand for our products may have an adverse impact on our business, financial condition, results of operations and cash flows. In addition, downturns in the economy impact the demand for refined fuels and, in turn, result in excess refining capacity. Refining margins are impacted by changes in domestic and global refining capacity, as increases in refining capacity can adversely impact refining margins, earnings and cash flows.COVID-19 pandemic;
Our business is indirectly exposed to risks faced by our suppliers, customers and other business partners. The impact on these constituencies of the risks posed by economic turmoil in the global financial system could include interruptions or delays in the performance by counterparties to our contracts, reductions and delays in customer purchases, delays in or the inability of customers to obtain financing to purchase our products and the inability of customers to pay for our products. Any of these events may have an adverse impact on our business, financial condition, results of operations and cash flows.
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, procurementprograms;
•Product liability and construction of new facilities (or improvementsoperational liability claims 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:litigation;
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•Prospect 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, 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.
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.
Wedividend payments may not be successful in acquiring additionalreinstated;
•Acquisition or integration of new assets and any acquisitionsinto our business;
•Labor disruptions that we do consummate may not produce the anticipated benefits or may have adverse effects onwould interfere with 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 numberoperations;
•Discontinuation 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 diversionemployment 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.
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 disruptionsemployees;
•Our activity 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 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.
Derivatives legislation, including compliance with the Dodd-Frank Act, could have an adverse effect on our business, including our ability to use derivatives contracts to reduce the effect of commodity price, interest rate and other risks associated with our business.markets.
The United States Congress in 2010 passed the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) which, among other things, established federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. In connection with the Dodd-Frank Act, the Commodity Futures Trading Commission, or the CFTC, has established rules to set position limits for certain futures and option contracts, and for swaps that are their economic equivalent, in the major energy markets. The legislation and related regulations require us to comply with margin requirements and with certain clearing and trade-execution requirements if we are in scope and do not otherwise satisfy certain specific exceptions. The legislation and related regulations could significantly increase the cost of regulatory compliance as well as derivatives contracts (including through requirements to post collateral), materially alter the terms of derivatives contracts, reduce the availability of derivatives to protect against risks we encounter and reduce our ability to monetize or restructure our existing derivatives contracts. If we fail to comply with applicable regulations or the costs of compliance becomes prohibitive, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.
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.
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. For example, the SCAQMD is currently considering further regulations on, or potentially banning the use of, modified hydrofluoric acid, also known as MHF, in Southern California. We utilize MHF as an alkylation catalyst in the manufacturing of gasoline at our Torrance refinery. If MHF usage is limited or restricted by the SCAQMD, our current Torrance refinery operations would be adversely affected, which could have a material adverse effect on our business, financial condition, cash flows and results of operations. Our operations are also subject to extensive laws and regulations relating to occupational health and safety.
We cannot predict what additional environmental, health and safety legislation or regulations may be adopted in the future, or how existing or future laws or regulations may be administered or interpreted with respect to our operations. Many of these laws and regulations have become increasingly stringent over time, and the cost of compliance with these requirements can be expected to increase over time.
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.
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.
We are subject to liability for the investigation and clean-up of environmental contamination at each of the properties that we own 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 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contractual Obligations and Commitments” and “Item 1. Business—Environmental, Health and Safety Matters.”
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 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.
Our operations could be disrupted if our critical information systems are hacked or fail, causing increased expenses and loss of sales.
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. If a key system was hacked or otherwise interfered with by an unauthorized access, or was to fail or experience unscheduled downtime for any reason, even if only for a short period, our operations and financial results could be affected adversely. Our systems could be damaged or interrupted by a security breach, cyber-attack, human error, fraud, fire, flood, power loss, telecommunications failure or similar event. We have a formal disaster recovery plan in place, but this plan may not prevent delays or other complications that could arise from an information systems failure.
As the frequency of attempted cyber-attacks has increased in recent years, we have taken several actions to enhance our strategy to address and monitor cyber related risks. We have instituted a cybersecurity team that is dedicated and responsible for the design and execution of our cyber-risk management strategy. However, there can be no assurance that these efforts will be effective to prevent cyber attacks or other interruptions of, or damage to, our key systems, business or operations, or that our business interruption insurance will compensate us adequately for losses that may occur, which could materially, adversely affect our business, financial condition, results of operations and cash flows.
Product liability claims and litigation could adversely affect our business and results of operations.
Product liability is a significant commercial risk. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers 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 our shippers and customers, and also arise from contaminated or off-specification product in commingled pipelines and storage tanks and/or defective fuels. Product liability claims against us could have a material adverse effect on our business or results of operations.
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 petroleum 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.
Renewable fuels mandates may reduce demand for the refined fuels we produce, which could have a material adverse effect on our results of operations and financial condition. 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 Renewable Fuel Standards, or RFS, implementing mandates to blend renewable fuels into the petroleum fuels produced and sold in the United States. Under RFS, the volume of renewable fuels that obligated refineries must blend into their finished petroleum fuels increases annually over time until 2022. 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 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. We incurred approximately $143.9 million in RINs costs during the year ended December 31, 2018 as compared to $293.7 million and $347.5 million during the years ended December 31, 2017 and 2016, 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.
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.
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 Occupational Safety & Health Administration, or 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 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.
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 are continuously being enacted or proposed that 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.
Furthermore, the Tax Cuts and Jobs Act (“TCJA”) that was enacted on December 22, 2017 made significant permanent and temporary amendments to the Internal Revenue Code of 1986, including a reduction in corporate income taxes, elimination of the corporate minimum tax, the immediate expensing of certain capital investments, allowing for an indefinite carryforward of tax net operating losses incurred in tax years beginning after December 31, 2017 and fundamentally changing the taxation of multinational entities. Additionally, the TCJA potentially limits the amount of interest expense currently deductible, provides for a transition tax for previously unrepatriated foreign earnings, provides for current taxation of certain foreign income, a minimum tax on low-taxed foreign earnings, and new measures to deter base erosion. Certain of the amendments included in the TCJA and the regulations promulgated thereunder may adversely affect our business, result of operations and financial condition.
Changes in accounting standards issued by the FASB could have a material effect on our balance sheet, revenue and result of operations, and could require a significant expenditure of time, attention and resources, especially by senior management.
Our accounting and financial reporting policies conform to GAAP, which are periodically revised and/or expanded. The application of accounting principles is also subject to varying interpretations over time. Accordingly, we are required to adopt new or revised accounting standards or comply with revised interpretations that are issued from time to time by various parties, including accounting standard setters and those who interpret the standards, such as the FASB and the SEC and our independent registered public accounting firm. Such new financial accounting standards may result in significant changes that could adversely affect our business, financial condition, cash flow and results of operations.
Refer to “Note 2 - Summary of Significant Accounting Policies” of our Notes to Consolidated Financial Statements for further discussion of new accounting standards, including the implementation status and potential impact to our consolidated financial statements.
Changes in our credit profile could adversely affect our business.
Changes in our credit profile could affect the way crude oil 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 our 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.
Changes in laws or standards affecting the transportation of North American crude oil by rail could significantly impact our operations, and as a result cause our costs to increase.
Investigations into past rail accidents involving the transport of crude oil have prompted government agencies and other interested parties to call for increased regulation of the transport of crude oil by rail including in the areas of crude oil constituents, rail car design, routing of trains and other matters. Regulation governing shipments of petroleum crude oil by rail requires shippers to properly test and classify petroleum crude oil and further requires shippers to treat Class 3 petroleum crude oil transported by rail in tank cars as a Packing Group I or II hazardous material only, which creates further classification and testing requirements, along with more severe penalties for violations. The DOT issued additional rules and regulations that require rail carriers to provide certain notifications to State agencies along routes utilized by trains over a certain length carrying crude oil, enhance safety training standards under the Rail Safety Improvement Act of 2008, require each railroad or contractor to develop and submit a training program to perform regular oversight and annual written reviews and establish enhanced tank car standards and operational controls for high-hazard flammable trains. These rules and any further changes in law, regulations or industry standards that require us to reduce the volatile or flammable constituents in crude oil that is transported by rail, alter the design or standards for rail cars we use, change the routing or scheduling of trains carrying crude oil, or any other changes that detrimentally affect the economics of delivering North American crude oil by rail to our, or subsequently to third-party, refineries, could increase our costs, which could have a material adverse effect on our financial condition, results of operations, cash flows and our ability to service our indebtedness.
We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with health, safety, environmental and other laws and regulations.
Our operations require numerous permits and authorizations under various laws and regulations. These authorizations and permits are subject to revocation, renewal or modification and can require operational changes to limit impacts or potential impacts on the environment and/or health and safety. A violation of authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions, and/or facility shutdowns. In addition, major modifications of our operations could require modifications to our existing permits or upgrades to our existing pollution control equipment. Any or all of these matters could have a negative effect on our business, results of operations and cash flows.
We may incur significant liability under, or costs and capital expenditures to comply with, 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 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.
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.
Risks Related to Our Indebtedness
•Our indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under our indebtedness.substantial levels of indebtedness;
•Our indebtedness may significantly affect our financial flexibilityability to secure necessary financing on acceptable terms;
•Changes in the future. As of December 31, 2018, we have total debt of $1,974.7 million, excluding deferred debt issuance costs of $41.0 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 $1,420.1 million under our credit facilities. We may incur additional indebtedness in the future. Our strategy includes executing future refinery and logistics acquisitions. Any significant acquisition would likely require us to incur additional indebtedness in order to finance all or a portion of such acquisition. The level of our indebtedness has several important consequences for our future operations, including that:ratings;
a portion of our cash flow from operations will be dedicated to the payment of principal of, and interest•Limitations 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, disposeoperations arising out of assets and make certain investments;
in certain circumstances these covenants also require us to meet or maintain certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our industry, such as being able to take advantage of acquisition opportunities when they arise;
our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited; and
we may be at a competitive disadvantage to those of our competitors that are less leveraged; and we may be more vulnerable to adverse economic and industry conditions.
Our indebtedness increases the risk that we may default on our debt obligations, certain of which contain cross-default and/or cross-acceleration provisions. Our, and our subsidiaries’, ability to meet future principal obligations will be dependent upon our future performance, which in turn will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our business may not continue to generate sufficient cash flow from operations to repay our indebtedness. If we are unable to generate sufficient cash flow from operations, we may be required to sell assets, to refinance all or a portion of our indebtedness or to obtain additional financing. Refinancing may not be possible and additional financing may not be available on commercially acceptable terms, or at all.
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 anticipated debt levels, the leverage risks described above would increase. Also, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness.
Restrictiverestrictive covenants in our debt instruments may limit our ability to undertake certain types of transactions.instruments;
Various covenants•Anti-takeover provisions in our debt instruments and other financing arrangements may restrict our and our subsidiaries’ financial flexibility in a number of ways. Our indebtedness subjects us to 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 these debt instruments also require our subsidiaries to satisfy or maintain certain financial tests in certain circumstances. Our subsidiaries’ ability to meet these financial tests can be affected by events beyond our control and they may not meet such tests.indentures.
Provisions in our indentures 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 in control” as described in the indentures governing the Senior Notes and PBFX Senior Notes (both of which are defined below), holders of our notes could require us to repurchase all outstanding notes at 101% of the principal amount thereof, plus accrued and unpaid interest, if any, at the date of repurchase.
Our future credit ratings could adversely affect the cost of our borrowing as well as our ability to obtain credit in the future.
Our Senior Notes (as defined below) are rated BB by Standard & Poor’s Rating Services and B1 by Moody’s Investors Service. Any adverse effect on our credit rating may increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which would impair our ability to grow our business and make cash distributions to our shareholders.
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 dependsEnergy’s dependence upon distributions from PBF LLC and its subsidiaries to pay its taxes and meet its other obligations and/or pay dividends in the future.obligations;
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.
The new PBF Holding asset-based revolving credit agreement (the “Revolving Credit Facility”), the PBF Holding 7.00% senior notes due 2023 (the “2023 Senior Notes”), the PBF Holding 7.25% senior notes due 2025 (the “2025 Senior Notes”, and together with the 2023 Senior Notes, the “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. PBFX’s five-year, $500.0 million amended and restated revolving credit facility (the “PBFX Revolving Credit Facility”) and PBFX’s
indenture governing its PBFX 2023 Senior Notes (as defined in Item 7. Management’s Discussion and Analysis) also contain 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.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 2019 Proxy Statement.
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•Obligations under the Tax Receivable Agreement, and such amounts are expected to be substantial.as defined below;
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.”
We expect that the payments that PBF Energy may make under the Tax Receivable Agreement will be substantial. As of December 31, 2018, PBF Energy has recognized a liability for the Tax Receivable Agreement of $373.5 million reflecting PBF Energy’s estimate of the undiscounted amounts that it expects to pay under the agreement due to exchanges that occurred prior to that date, and to range over the next five years from approximately $15.0 million to $65.0 million per year and decline thereafter. Future payments by PBF Energy in respect of subsequent exchanges of PBF LLC Series A Units would be in addition to these amounts and are expected to be material as well. 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 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 $32.67 per share (the closing price on December 31, 2018) and that LIBOR were to be 1.85%, we estimate that, as of December 31, 2018 the aggregate amount of these accelerated payments would have been approximately $327.7 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.
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 Service 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 board of 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 board of directors 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 board of directors 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 under Delaware law may discourage or delay a change in control.law;
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•Volatility of our outstanding common stock;stock price;
provide that special meetings of stockholders may be called only by the chairman of the board of directors, the chief executive officer or the board of 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•Potential dilution of our capital stock entitled to vote.current stockholders.
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, which could cause the value of your investment to decline.
The market price of PBF Energy Class A common stock may be highly volatile and could be subject to wide fluctuations due to a number of factors including:
variations in actual or anticipated operating results or dividends, if any, to stockholders;
changes in, or failure to meet, earnings estimates of securities analysts;
market conditions in the oil refining industry and volatility in commodity prices;
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 and subsequent impact of any future acquisitions 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 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.
Risks Related to Our Ownership of PBFX
•Obligations for minimum volume commitments in our commercial agreements with PBFX;
•Potential tax consequences related to our involvement in PBFX.
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 Related to the COVID-19 Pandemic
The outbreak of the COVID-19 pandemic significantly and adversely affected our liquidity, business, financial condition and results of operations starting in the first quarter of 2020. While we have seen the demand for our products return in 2021, there can be no assurance that our liquidity, business, financial condition and results of operations will revert to pre-COVID-19 pandemic levels going forward.
The outbreak of the COVID-19 pandemic starting in the first quarter of 2020, negatively impacted, and may continue to impact, worldwide economic and commercial activity and financial markets. The COVID-19 pandemic, and variants thereof, and the related governmental responses resulted in significant business and operational disruptions, including business and school closures, supply chain disruptions, travel restrictions, stay-at-home orders and limitations on the availability of workforces, inclusive of mandatory quarantine periods, and has resulted in significantly lower global demand for refined petroleum and petrochemical products. Although demand for these products started to recover throughout the year ended December 31, 2021 following the lifting or easing of certain restrictions and the distribution of COVID-19 vaccines and other protective measures, there can be no assurance that future periods will not be negatively impacted by the continuing effect of the COVID-19 pandemic, including resurgences and variants of the virus.
In addition, the impact of the COVID-19 pandemic has created simultaneous shocks in oil supply and demand resulting in an economic challenge to our industry which has not occurred since our formation. It is impossible to estimate the duration or significance of the financial impact that will result from the COVID-19 pandemic. However, the extent of the impact of the COVID-19 pandemic on our business, financial condition, results of operations and liquidity will depend largely on future developments, including the duration and severity of the pandemic and variants thereof, particularly within the geographic areas where we operate, the effectiveness of vaccine programs, and the related impact on overall economic activity, all of which cannot be predicted with certainty at this time.
We continue to work with federal, state and local health authorities to respond to COVID-19 cases in the regions we operate and are taking or supporting measures to try to limit the spread of the virus and to mitigate the burden on the healthcare system. Many of these measures will continue to have an adverse impact on our business and financial results that we are not currently able to fully quantify. For example, we are carefully
evaluating projects and non-essential work at our refineries. Based on market conditions, our refineries have been operating at reduced rates, while constantly monitoring and adjusting our production to correlate to increases in product demand. We lowered our capital program for 2021 and will continue to plan to do so in 2022 as compared to historic levels. We have planned a level of capital expenditures we believe will allow us to satisfy and comply with all required safety, environmental and planned regulatory capital commitments and other regulatory requirements, although there are no assurances that we will be able to continue to do so. Non-compliance with applicable environmental and safety requirements, including as a result of reduced staff due to an outbreak at one of our refineries, may impair our operations, may subject us to fines or penalties assessed by governmental authorities and/or may result in an environmental or safety incident. We may also be subject to liability as a result of claims against us by impacted workers or third parties.
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 have adversely affected 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 in the case of the East Coast Refining Reconfiguration. There may be significant incremental costs associated with such actions. Further 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 persistence or worsening or market conditions related to the COVID-19 pandemic may require us to raise additional capital to meet our obligations and operate our business.
Our borrowing base under PBF Holding’s asset-based revolving credit facility (the “Revolving Credit Facility”) could be reduced if market conditions deteriorate or crude prices decrease significantly. Our borrowing base availability under the Revolving Credit Facility was $3,400.0 million as of December 31, 2021. If current market conditions return to levels experienced during the height of the COVID-19 pandemic, or worsen, we may require additional capital to meet our obligations as well as to operate our business, and additional financing and/or assets sales may not be possible on favorable terms or at all. Potential economic factors resulting from the COVID-19 pandemic, which could lead to increasing unemployment rates, substantially reduced travel and reduced business and consumer spending, could also affect our business.
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.
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, as we experienced in 2020, 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. Although we reduced our crude oil, feedstock and refined product inventories in 2020 to strengthen our financial position in response to the COVID-19 pandemic, inventory has slowly returned to normalized levels in 2021. 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. 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, reflecting the net change in the LCM inventory reserve from $401.6 million at December 31, 2019 to $669.6 million at December 31, 2020. At December 31, 2021, the replacement value of inventories exceeded the LIFO carrying value, therefore no LCM inventory reserve was recorded.
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 slightly 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.
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 as a result of our reliance on pipelines and railroads for transportation of crude oil and refined products.
Our Toledo, Chalmette, Torrance and Martinez refineries receive a significant portion of their crude oil through our owned, as well as third-party, pipelines. These pipelines include the Enbridge system, Capline and Mid-Valley pipelines for supplying crude to our Toledo refinery, the MOEM Pipeline (which is owned by our subsidiary) and CAM Pipeline for supplying crude to our Chalmette refinery and the San Joaquin Pipeline, San Pablo Bay Pipeline, San Ardo and Coastal Pipeline systems for supplying crude to our Torrance and Martinez refineries. Additionally, our Toledo, Chalmette, Torrance and Martinez refineries deliver a significant portion of the refined products through pipelines. These pipelines include pipelines such as the Sunoco Logistics Partners L.P. and Buckeye Partners L.P. pipelines at the Toledo refinery, the Collins pipeline (which is owned by our subsidiary) at our Chalmette refinery, the Jet Pipeline to the Los Angeles International Airport, the Product Pipeline to Vernon and the Product Pipeline to Atwood at our Torrance refinery and the KinderMorgan SFPP North Pipeline at our Martinez refinery. We could experience an interruption of supply or delivery, or an increased cost of receiving crude oil and delivering refined products to market, if the ability of these pipelines to transport crude oil or refined products is disrupted because of accidents, weather interruptions, governmental regulation, terrorism, other third-party action or casualty or other events.
The Delaware City rail unloading facilities and the assets acquired in connection with the PBFX 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.
In addition, 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.
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 Renewable Fuel Standard, implementing mandates to blend renewable fuels into the petroleum fuels produced and sold in the United States. Under the Renewable Fuel Standard, 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 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 2021 and could increase further in 2022. We incurred approximately $726.0 million in RINs costs during the year ended December 31, 2021 as compared to $326.4 million and $122.7 million during the years ended December 31, 2020 and 2019, 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. EPA’s proposed volumes of renewable fuels that obligated refineries must blend into their final petroleum fuels are expected to be finalized by the end of the first quarter of 2022. 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.
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, 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.
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. For example, on July 21, 2021, the board of Bay Area Air Quality Management District (“BAAQMD”) voted to adopt proposed 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 by 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.
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 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.
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. The N-79-20 Order encourages zero emissions technologies such as electric vehicles, and accelerated deployment of affordable fueling and charging options. It is currently uncertain how the N-79-20 Order may be ultimately implemented by various California regulatory agencies. In the event we do incur increased costs as a result of increased efforts to control GHG emissions through future adopted regulatory requirements, we may not be able to pass these costs to our customers. These future regulatory requirements also could adversely
affect demand for the refined products that we produce. Any increased costs or reduced demand could materially and adversely affect our business and results of operations.
Environmental clean-up and remediation costs of our sites and environmental litigation 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—Contractual Obligations and Commitments”.
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.
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.
We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with health, safety, environmental and other laws and regulations.
Our operations require numerous permits and authorizations under various laws and regulations. These authorizations and permits are subject to revocation, renewal or modification and can require operational changes to limit impacts or potential impacts on the environment and/or health and safety. A violation of authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions, and/or facility shutdowns. In addition, major modifications of our operations could require modifications to our existing permits or upgrades to our existing pollution control equipment. Any or all of these matters could have a negative effect on our business, results of operations and cash flows.
We may incur significant liabilities under, or costs and capital expenditures to comply with, health, safety, environmental and other laws and regulations, which are complex and change frequently. Our operations are subject to federal, state and local laws regulating, among other things, the handling of petroleum and other regulated materials, the emission and discharge of materials into the environment, waste management, and remediation of discharges of petroleum and petroleum products, characteristics and composition of gasoline and distillates and other matters otherwise relating to the protection of the environment. Our operations are also subject to extensive laws and regulations relating to occupational health and safety, in addition to laws and regulations affecting the transportation of crude oil by rail in North America.
We cannot predict what additional environmental, health and safety legislation or regulations may be adopted in the future, or how existing or future laws or regulations may be administered or interpreted with respect to our operations. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time.
Certain environmental laws impose strict, and in certain circumstances joint and several liability for, costs of investigation and cleanup of such spills, discharges or releases on owners and operators of, as well as persons who arrange for treatment or disposal of regulated materials at contaminated sites. Under these laws, we may incur liability or be required to pay penalties for past contamination, and third parties may assert claims against us for damages allegedly arising out of any past or future contamination. The potential penalties and clean-up costs for past or future releases or spills, the failure of prior owners of our facilities to complete their clean-up obligations, the liability to third parties for damage to their property, or the need to address newly-discovered information or conditions that may require a response could be significant, and the payment of these amounts could have a material adverse effect on our business, financial condition and results of operations.
Enhanced scrutiny on ESG matters may 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.
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 have experienced periods of extreme volatility that have negatively impacted market liquidity conditions, including as a result of the impact of the COVID-19 pandemic. As a result, the cost of raising money in the debt and equity capital markets has increased substantially at times while the availability of funds from those markets diminished 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.
Any political instability, military strikes, sustained military campaigns, terrorist activity, changes in foreign policy in areas or regions of the world where we acquire crude oil and other raw materials or sell our refined products may affect our business in unpredictable ways, including forcing us to increase security measures and causing disruptions of supplies and distribution markets. We may also be subject to United States trade and economic sanctions laws, which change frequently as a result of foreign policy developments, and which may necessitate changes to our crude oil acquisition activities. Further, like other industrial companies, our facilities may be the target of terrorist activities or subject to catastrophic events such as natural disasters and pandemic illness. Any act of war, terrorism, or other catastrophic events that resulted in damage to, or otherwise disrupts the operating activities of, any of our refineries or third-party facilities upon which we are dependent for our business operations could have a material adverse effect on our business, results of operations and financial condition.
A cyber-attack on, or other failure of, our technology infrastructure could affect our business and assets, and have a material adverse effect on our financial condition, results of operations and cash flows.
We are becoming increasingly dependent on our technology infrastructure and certain critical information systems which process, transmit and store electronic information, including information we use to safely and effectively operate our respective assets and businesses. These information systems include data network and telecommunications, internet access, our websites, and various computer hardware equipment and software applications, including those that are critical to the safe operation of our refineries and logistics assets. We have invested, and expect to continue to invest, significant time, manpower and capital in our technology infrastructure and information systems. These information systems are subject to damage or interruption from a number of potential sources including natural disasters, software viruses or other malware, power failures, cybersecurity threats to gain unauthorized access to sensitive information, cyber-attacks, which may render data systems unusable, and physical threats to the security of our facilities and infrastructure. Additionally, our business is highly dependent on financial, accounting and other data processing systems and other communications and information systems, including our enterprise resource planning tools. We process a large number of transactions on a daily basis and rely upon the proper functioning of computer systems. Furthermore, we rely on information systems across our respective operations, including the management of supply chain and various other processes and transactions. As a result, a disruption on any information systems at our refineries or logistics assets, may cause disruptions to our collective operations.
The potential for such security threats or system failures has subjected our operations to increased risks that could have a material adverse effect on our business. To the extent that these information systems are under our control, we have implemented measures such as virus protection software, emergency recovery processes and a formal disaster recovery plan to address the outlined risks. However, security measures for information systems cannot be guaranteed to be failsafe, and our formal disaster recovery plan and other implemented measures may not prevent delays or other complications that could arise from an information systems failure. If a key system were hacked or otherwise interfered with by an unauthorized user, or were to fail or experience unscheduled downtime for any reason, even if only for a short period, or any compromise of our data security or our inability to use or access these information systems at critical points in time, it could unfavorably impact the timely and efficient operation of our business, damage our reputation and subject us to additional costs and liabilities. The increase in companies and individuals working remotely has increased the frequency and scope of cyber-attacks and the risk of potential cybersecurity incidents, both deliberate attacks and unintentional events. While, to date, we have not had a significant cybersecurity breach or attack that had a material impact on our business or results of operations, if we were to be subject to a material successful cyber intrusion, it could result in remediation or service restoration costs, increased cyber protection costs, lost revenues, litigation or regulatory actions by governmental authorities, increased insurance premiums, reputational damage and damage to our competitiveness, financial condition, results of operations and cash flows.
Cyber-attacks against us or others in our industry could result in additional regulations, and U.S. government warnings have indicated that infrastructure assets, including pipelines, may be specifically targeted by certain groups. These attacks include, without limitation, malicious software, ransomware, attempts to gain unauthorized access to data, and other electronic security breaches. These attacks may be perpetrated by state-sponsored groups, “hacktivists”, criminal organizations or private individuals (including employee malfeasance). Current efforts by the federal government, including the Strengthening the Cybersecurity of Federal Networks and Critical Infrastructure executive order, the issuance of new cybersecurity requirements for critical pipeline owners and operators issued by the Department of Homeland Security’s Transportation Security Administration following a cyber-attack on a major petroleum pipeline in 2021, and any potential future regulations could lead to increased regulatory compliance costs, insurance coverage cost or capital expenditures. We cannot predict the potential impact to our business or the energy industry resulting from additional regulations.
Further, our business interruption insurance may not compensate us adequately for losses that may occur. We do not carry insurance specifically for cybersecurity events; however, certain of our insurance policies may allow for coverage for a cyber-event resulting in ensuing property damage from an otherwise insured peril. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, results of operations and cash flows. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.
Competition from companies who have not been adversely impacted as much as we have been by the COVID-19 pandemic, 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. Many of our competitors have not been adversely impacted by the COVID-19 pandemic as much as we have been impacted. Certain of our competitors have larger and more complex refineries, and may be able to realize lower per-barrel costs or higher margins per barrel of throughput. Several of our principal competitors are integrated national or international oil companies that are larger and have substantially greater resources than we do and access to proprietary sources of controlled crude oil production. Unlike these competitors, we obtain substantially all of our feedstocks from unaffiliated sources. We are not engaged in the petroleum exploration and production business and therefore do not produce any of our crude oil feedstocks. We do not have a retail business and therefore are dependent upon others for outlets for our refined products. Because of their integrated operations and larger capitalization, these companies may be more flexible in responding to volatile industry or market conditions, such as shortages of crude oil supply and other feedstocks or intense price fluctuations and they may also be able to obtain more favorable trade credit terms.
Newer or upgraded refineries will often be more efficient than our refineries, which may put us at a competitive disadvantage. We have taken significant measures to maintain our refineries including the installation of new equipment and redesigning older equipment to improve our operations. However, these actions involve significant uncertainties, since upgraded equipment may not perform at expected throughput levels, the yield and product quality of new equipment may differ from design specifications and modifications may be needed to correct equipment that does not perform as expected. Any of these risks associated with new equipment, redesigned older equipment or repaired equipment could lead to lower revenues or higher costs or otherwise have an adverse effect on future results of operations and financial condition. Over time, our refineries or certain refinery units may become obsolete, or be unable to compete, because of the construction of new, more efficient facilities by our competitors.
We must make substantial capital expenditures on our operating facilities to maintain their reliability and efficiency. If we are unable to complete capital projects at their expected costs and/or in a timely manner, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations or cash flows could be materially and adversely affected.
Delays or cost increases related to capital spending programs involving engineering, procurement and construction of new facilities (or improvements and repairs to our existing facilities and equipment, including turnarounds) could adversely affect our ability to achieve targeted internal rates of return and operating results. Such delays or cost increases may arise as a result of unpredictable factors in the marketplace, many of which are beyond our control, including:
•denial or delay in obtaining regulatory approvals and/or permits;
•unplanned increases in the cost of construction materials or labor;
•disruptions in transportation of modular components and/or construction materials;
•severe adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors and suppliers;
•shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
•market-related increases in a project’s debt or equity financing costs; and/or
•non-performance or force majeure by, or disputes with, vendors, suppliers, contractors or sub-contractors involved with a project.
Our refineries contain many processing units, a number of which have been in operation for many years. Equipment, even if properly maintained, may require significant capital expenditures and expenses to keep it operating at optimum efficiency. One or more of the units may require unscheduled downtime for unanticipated maintenance or repairs that are more frequent than our scheduled turnarounds for such units. Scheduled and unscheduled maintenance could reduce our revenues during the period of time that the units are not operating.
Our forecasted internal rates of return are also based upon our projections of future market fundamentals, which are not within our control, including changes in general economic conditions, 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.
PBF Energy has suspended its quarterly dividend and does not anticipate that it will declare dividends in the foreseeable future.
On March 30, 2020, PBF Energy announced that it has suspended its quarterly cash dividend of $0.30 per share on its Class A common stock, as part of its strategic plan to respond to the impact of the COVID-19 outbreak and related market activity. 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). Any future declaration, amount and payment of any dividends will be at the sole discretion of our Board of Directors, however, because the impact of the COVID-19 outbreak and related market activity is difficult to predict, we do not anticipate that our Board of Directors will determine to declare a dividend in the foreseeable future. Our Board of Directors 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 Board of Directors 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.
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 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 are continuously being enacted or proposed that 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.
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. Certain of these agreements have expired while others are scheduled to expire on various dates in 2022 through 2024 (See “Item 1. Business” - Employees). For the agreements that expired, terms related to new collective bargaining agreements have been agreed to on local bargaining issues and are pending settlement of the National Oil Bargaining Program which will set contract term, wages, health care contributions and any other agreed upon issues prior to being executed.During this interim period, the terms of the expired agreements will remain in place under rolling 24-hour extensions until new agreements are finalized. Future negotiations prior to the expiration of our collective agreements may result in labor unrest for which a strike or work stoppage is possible. Strikes and/or work stoppages could negatively affect our operational and financial results and may increase operating expenses at the refineries.
Our business may suffer if any of our senior executives or other key employees discontinues employment with us. Furthermore, a shortage of skilled labor or disruptions in our labor force may make it difficult for us to maintain labor productivity.
Our future success depends to a large extent on the services of our senior executives and other key employees. Our business depends on our continuing ability to recruit, train and retain highly qualified employees in all areas of our operations, including engineering, accounting, business operations, finance and other key back-office and mid-office personnel. Furthermore, our operations require skilled and experienced employees with proficiency in multiple tasks. The competition for these employees is intense, and the loss of these executives or employees could harm our business. If any of these executives or other key personnel resigns or becomes unable to continue in his or her present role and is not adequately replaced, our business operations could be materially adversely affected.
Our hedging activities may limit our potential gains, exacerbate potential losses and involve other risks.
We may enter into commodity derivatives contracts to hedge our crude price risk or crack spread risk with respect to a portion of our expected gasoline and distillate production on a rolling basis or to hedge our exposure to the price of natural gas, which is a significant component of our refinery operating expenses. Consistent with that policy we may hedge some percentage of our future crude and natural gas supply. We may enter into hedging arrangements with the intent to secure a minimum fixed cash flow stream on the volume of products hedged during the hedge term and to protect against volatility in commodity prices. Our hedging arrangements may fail to fully achieve these objectives for a variety of reasons, including our failure to have adequate hedging arrangements, if any, in effect at any particular time and the failure of our hedging arrangements to produce the anticipated results. We may not be able to procure adequate hedging arrangements due to a variety of factors. Moreover, such transactions may limit our ability to benefit from favorable changes in crude oil, refined product and natural gas prices.
In addition, our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which:
•the volumes of our actual use of crude oil or natural gas or production of the applicable refined products is less than the volumes subject to the hedging arrangement;
•accidents, interruptions in feedstock transportation, inclement weather or other events cause unscheduled shutdowns or otherwise adversely affect our refineries, or those of our suppliers or customers;
•changes in commodity prices have a material impact on collateral and margin requirements under our hedging arrangements, resulting in us being subject to margin calls;
•the counterparties to our derivative contracts fail to perform under the contracts; or
•a sudden, unexpected event materially impacts the commodity or crack spread subject to the hedging arrangement.
As a result, the effectiveness of our hedging strategy could have a material impact on our financial results. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”
In addition, these hedging activities involve basis risk. Basis risk in a hedging arrangement occurs when the price of the commodity we hedge is more or less variable than the index upon which the hedged commodity is based, thereby making the hedge less effective. For example, a New York Mercantile Exchange index used for hedging certain volumes of our crude oil or refined products may have more or less variability than the actual cost or price we realize for such crude oil or refined products. We may not hedge all the basis risk inherent in our hedging arrangements and derivative contracts.
Our commodity derivative activities could result in period-to-period earnings volatility.
We do not currently apply hedge accounting to any of our commodity derivative contracts and, as a result, unrealized gains and losses will be charged to our earnings based on the increase or decrease in the market value of such unsettled positions. These gains and losses may be reflected in our income statement in periods that differ from when the settlement 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 substantial 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, 2021, we have total debt of $4,330.8 million, excluding unamortized deferred debt issuance costs of $35.0 million and our PBF LLC Affiliate note payable with PBF Energy that eliminates in consolidation at the PBF Energy level, and we could incur additional borrowings under our credit facilities. We may incur additional indebtedness in the future including additional secured indebtedness, subject to the satisfaction of any debt incurrence and, if applicable, lien incurrence limitation covenants in our existing financing agreements. Although we were in compliance with incurrence covenants during the year ended December 31, 2021, 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 stock or incur new liens.
The level of our indebtedness has several important consequences for our future operations, including that:
•a portion of our cash flow from operations will be dedicated to the payment of principal of, and interest on, our indebtedness and will not be available for other purposes;
•under certain circumstances, covenants contained in our existing debt arrangements limit our ability to borrow additional funds, dispose of assets and make certain investments;
•in certain circumstances these covenants also require us to meet or maintain certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our industry, such as being able to take advantage of acquisition opportunities when they arise;
•our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited; and
•we may be at a competitive disadvantage to those of our competitors that are less leveraged; and we may be more vulnerable to adverse economic and industry conditions.
Our indebtedness increases the risk that we may default on our debt obligations, certain of which contain cross-default and/or cross-acceleration provisions. Our, and our subsidiaries’, ability to meet future principal obligations will be dependent upon our future performance, which in turn will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our business may not continue to generate sufficient cash flow from operations to repay our indebtedness. If we are unable to generate sufficient cash flow from operations, we may be required to sell assets, to refinance all or a portion of our indebtedness or to obtain additional financing. Refinancing may not be possible and additional financing may not be available on commercially acceptable terms, or at all.
We may not be able to secure necessary financing on acceptable terms, or at all.
We currently have notes outstanding with varying maturity dates beginning in 2023 and ending in 2028. Additionally, our most significant credit facilities - the Revolving Credit Facility and the PBFX amended and restated revolving credit facility (the “PBFX Revolving Credit Facility”) - both have maturity dates in 2023. We can make no assurance that we will be able to refinance our outstanding indebtedness on acceptable terms prior to their maturity dates. Market disruptions, such as those experienced in relation to the COVID-19 pandemic, may increase our cost of borrowing or adversely affect our ability to refinance our obligations as they become due. Further, ESG concerns and other pressures on the oil and gas industry could lead to increased costs of financing or limit our access to the capital markets. If we are unable to refinance our indebtedness or access additional credit, or if short-term or long-term borrowing costs significantly increase, our ability to finance current operations and meet our short-term and long-term obligations could be adversely affected.
Despite our substantial 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 current debt levels, the leverage risks described above would increase. Also, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness.
Our future credit ratings could adversely affect our business, the cost of our borrowing, and our ability to obtain credit in the future.
Changes in our credit profile could affect the way crude oil and other suppliers view our ability to make payments and induce them to shorten the payment terms for our purchases or require us to post security or letters of credit prior to payment. Due to the large dollar amounts and volume of our crude oil and other feedstock purchases, any imposition by these suppliers of more burdensome payment terms on us may have a material adverse effect on our liquidity and our ability to make payments to our suppliers. This, in turn, could 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 Caa1 by Moody’s, B by S&P, and B- by Fitch. The 9.25% senior secured notes due 2025 (the “2025 Senior Secured Notes”) are rated B2 by Moody’s, BB- by S&P, and BB by Fitch. The 6.875% PBFX senior notes due 2023 (the “PBFX 2023 Senior Notes”) are rated B3 by Moody’s, B by S&P, and B+ by Fitch. During 2021, Moody’s and S&P downgraded our corporate family rating as well as our unsecured and secured notes ratings, with all ratings on negative outlook. If the current market conditions persist or deteriorate, we expect that the credit rating agencies will continue to re-evaluate our corporate credit rating and the ratings of our unsecured and secured notes. Adverse changes in our credit ratings may also negatively impact the terms of credit we receive from our suppliers and require us to prepay or post collateral. Further adverse actions taken by the rating agencies on our corporate credit rating or the rating of our notes may further 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.
Restrictive covenants in our debt instruments, including the indentures governing our notes, may limit our ability to undertake certain types of transactions, which could adversely affect our business, financial condition, results of operations and our ability to service our indebtedness.
Various covenants in our current and future debt instruments and other financing arrangements, including the indentures governing our notes, may restrict our and our subsidiaries’ financial flexibility in a number of ways. Our current indebtedness and the indentures that govern our notes subject us to significant financial and other restrictive covenants, including restrictions on our ability to incur additional indebtedness, place liens upon assets, 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 our debt instruments also require our subsidiaries to satisfy or maintain certain financial condition tests in certain circumstances. Our ability to meet these financial condition tests can be affected by events beyond our control and we may not meet such tests. In addition, a failure to comply with the provisions of our existing debt could result in an event of default that could enable our lenders, subject to the terms and conditions of such debt, to declare the outstanding principal, together with accrued interest, to be immediately due and payable. Events beyond our control, including the impact of the COVID-19 pandemic and related governmental responses and developments in the global oil markets, 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, the 2025 Senior Secured Notes, the 2028 Senior Notes and the PBFX 2023 Senior Notes, holders of our notes could require us to repurchase all outstanding notes at 101% of the principal amount thereof, plus accrued and unpaid interest, if any, at the date of repurchase. Certain other significant agreements of ours such as our agreement governing the Revolving Credit Facility (the “Revolving Credit Agreement”), Tax Receivable Agreement (as defined below) and the Third Intermediation Agreement with J. Aron also contain provisions related to a change in control that could make it more difficult or expensive for a third-party to acquire us.
Risks Related to Our Organizational Structure 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.
The Revolving Credit Facility, the 2028 Senior Notes, the 2025 Senior Notes, the 2025 Senior Secured 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. PBFX Revolving Credit Facility and PBFX’s indenture governing its PBFX 2023 Senior Notes also contain 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 2022 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.
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.”
PBF Energy has recognized, as of December 31, 2021, a liability for the Tax Receivable Agreement of $48.3 million, reflecting the estimated undiscounted amounts that PBF Energy expects to pay under the agreement, net of a deferred tax asset valuation allowance recognized in accordance with FASB Accounting Standards Codification (“ASC”) 740, Income Taxes (“ASC 740”). As future taxable income is recorded, increases in our Tax Receivable Agreement liability may be necessary in conjunction with the revaluation of 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 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 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 the 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. 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.
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 Service 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.
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 Board of Directors, the chief executive officer or the Board of 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.
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, which could cause the value of your investment to decline.
The market price of PBF Energy Class A common stock may be highly volatile and subject to wide fluctuations due to a number of factors including:
•market conditions in the oil refining industry and volatility in commodity prices and the ongoing impact of COVID-19;
•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 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.
Our current stockholders could experience dilution, which could further depress the price of our Class A common stock.
We continue to require substantial working 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 shares of Class A common stock. As a result, stockholders may experience substantial dilution, and the 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 our Class A common stock, into the market or the perception that these sales could occur. Sales of a large number of shares of our Class A common stock, or securities convertible into or exchangeable or exercisable for our Class A common stock, or the possibility that these sales may occur, also might make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. In addition, any equity securities we issue may have rights, preferences or privileges senior to those of our Class A common stock, and our current debt agreements contain, and any agreements for future debt or preferred equity financings, if available, are likely to contain, covenants limiting or restricting our ability to take specific actions, such as incurring additional debt. Holders of Class A common stock are not entitled to preemptive rights or other protections against dilution. Because our decision to issue securities in any future offering will depend on our capital needs as well as market conditions and other factors beyond om control, we cannot predict or estimate the amount, timing, nature or impact of future issuances, if any. Our Class A common stockholders bear the risk of our future offerings reducing the per share market price of our Class A common stock.
Risks Related to Our Ownership of PBFX
We depend upon PBFX for a substantial portion of our refineries’ logistics needs and have obligations for minimum volume commitments in our commercial agreements with PBFX.
We depend on PBFX to receive, handle, store and transfer crude oil, petroleum products and natural gas for us from our operations and sources located throughout the United States and Canada in support of certain of our refineries under long-term, fee-based commercial agreements with our subsidiaries. These commercial agreements have an initial term ranging from one to fifteen years and generally include minimum quarterly commitments and inflation escalators. If we fail to meet the minimum commitments during any calendar quarter, we will be required to make a shortfall payment quarterly to PBFX equal to the volume of the shortfall multiplied by the applicable fee.
PBFX’s operations are subject to all of the risks and operational hazards inherent in receiving, handling, storing and transferring crude oil, petroleum products and natural gas, including: damages to its facilities, related equipment and surrounding properties caused by floods, fires, severe weather, explosions and other natural disasters and acts of terrorism; mechanical or structural failures at PBFX’s facilities or at third-party facilities on which its operations are dependent; curtailments of operations relative to severe seasonal weather; inadvertent damage to our facilities from construction, farm and utility equipment; and other hazards. Any of these events or factors could result in severe damage or destruction to PBFX’s assets or the temporary or permanent shut-down of PBFX’s facilities. If PBFX is unable to serve our logistics needs, our ability to operate our refineries and receive crude oil and distribute products could be adversely impacted, which could adversely affect our business, financial condition and results of operations.
In addition, as of December 31, 2018,2021, PBF LLC owns 19,953,63129,953,631 common units representing 44.0%47.9% limited partner interest in PBFX. The inability of PBFX to continue operations, perform under its commercial arrangements with our subsidiaries or the occurrence of any of these risks or operational hazards, could also adversely impact the value of our investment in PBFX and, because PBFX is a consolidated entity, our business, financial condition and results of operations.
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
to PBF Energy on account of its indirect interest in PBFX may not be sufficient for PBF Energy to pay the amount of taxes it will owe on account of its indirect interests in PBFX.
If PBFX was to be treated as a corporation, rather than as a partnership, for U.S. federal income tax purposes or if PBFX was otherwise subject to entity-level taxation, PBFX’s cash available for distribution to its unitholders, including to us, would be reduced, likely causing a substantial reduction in the value of units, including the units held by us.
The present U.S. federal income tax treatment of publicly-traded partnerships, including PBFX, or an investment in its common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time the U.S. Congress considers substantive changes to the existing federal income tax laws that would affect publicly-traded partnerships. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for PBFX to meet the exception to be treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in PBFX common units.
If PBFX were treated as a corporation for U.S. federal income tax purposes, it would pay U.S. federal income tax on income at the corporate tax rate, which is currently a maximum of 21% under the TCJA, and would likely be liable for state income tax at varying rates. Distributions to PBFX unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to PBFX unitholders. Because taxes would be imposed upon PBFX as a corporation, the cash available for distribution to PBFX unitholders would be substantially reduced. Therefore, PBFX’s treatment as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to PBFX unitholders, likely causing a substantial reduction in the value of the units.
All of the executive officers and a majority of the directors of PBF GP are also current or former officers or directors of PBF Energy. Conflicts of interest could arise as a result of this arrangement.
PBF Energy indirectly owns and controls PBF GP, and appoints all of its officers and directors. All of the executive officers and a majority of the directors of PBF GP are also current or former officers or directors of PBF Energy. These individuals will devote significant time to the business of PBFX. Although the directors and officers of PBF GP have a fiduciary duty to manage PBF GP in a manner that is beneficial to PBF Energy, as directors and officers of PBF GP they also have certain duties to PBFX and its unitholders. Conflicts of interest may arise between PBF Energy and its affiliates, including PBF GP, on the one hand, and PBFX and its unitholders, on the other hand. In resolving these conflicts of interest, PBF GP may favor its own interests and the interests of PBFX over the interests of PBF Energy. In certain circumstances, PBF GP may refer any conflicts of interest or potential conflicts of interest between PBFX, on the one hand, and PBF Energy, on the other hand, to its conflicts committee (which must consist entirely of independent directors) for resolution, which conflicts committee must act in the best interests of the public unitholders of PBFX. As a result, PBF GP may manage the business of PBFX in a way that may differ from the best interests of PBF Energy or its stockholders.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
See “Item 1. Business”.
ITEM 3. LEGAL PROCEEDINGS
On July 24, 2013, DNREC issued a Notice of Administrative Penalty Assessment and Secretary’s Order to Delaware City Refining for alleged air emission violations that occurred during the re-start of the refinery in 2011 and subsequent to the re-start. The penalty assessment seeks $460,200 in penalties and $69,030 in cost recovery for DNREC’s expenses associated with investigation of the incidents. We dispute the amount of the penalty assessment and allegations made in the order, and are in discussions with DNREC to resolve the assessment. It is possible that DNREC will assess a penalty in this matter but any such amount is not expected to be material to us.
At the time we acquired the Chalmette refinery it was subject to the Order issued by LDEQ covering deviations from 2009 and 2010. Chalmette Refining and LDEQ subsequently entered into a dispute resolution agreement to negotiate the resolution of deviations on or before December 31, 2014. On May 18, 2018 the Order was settled by LDEQ and the Chalmette refinery for an administrative penalty of $741,000, of which $100,000 has been paid in cash and the remainder has been spent on beneficial environmental projects.
On April 7, 2015, DNREC issued a NOV (W-15-SWD-01) alleging violations of the Delaware City refinery’s NPDES discharge permit during the period between December 12, 2014 through January 4, 2015. On March 5, 2018, a settlement agreement was finalized resolving the alleged violations contained in the April 7, 2015 Notice of Violation, as well as additional alleged violations occurring during the period between January 2014 through January 2018. Pursuant to this settlement agreement, the Delaware City refinery was either going to pay a penalty of $30,000 and fund an approved Environmental Improvement Project (“EIP”) in the amount of $88,000, or pay a penalty in the amount of $118,000. A cost recovery payment of $7,433 will be assessed in either case. The Delaware City refinery has elected to pay the $30,000 penalty and fund the EIP in the amount of $88,000. The Delaware City refinery has paid the penalty and the cost recovery payment and will fund the approved EIP as soon as the project scope is finalized.
The Delaware City refinery appealed a Notice of Penalty Assessment and Secretary’s Order issued in March 2017, including a $150,000 fine, alleging violation of a 2013 Secretary’s Order authorizing crude oil shipment by barge. DNREC determined that the Delaware City refinery had violated the order by failing to make timely and full disclosure to DNREC about the nature and extent of those shipments, and had misrepresented the number of shipments that went to other facilities. The Penalty Assessment and Secretary’s Order conclude that the 2013 Secretary’s Order was violated by the refinery by shipping crude oil from the Delaware City terminal to three locations other than the Paulsboro refinery, on 15 days in 2014, making a total of 17 separate barge shipments containing approximately 35.7 million gallons of crude oil in total. On April 28, 2017, the Delaware City refinery appealed the Notice of Penalty Assessment and Secretary’s Order. On March 5, 2018, Notice of Penalty Assessment was settled by DNREC, the Delaware Attorney General and Delaware City refinery for $100,000. The Delaware City refinery made no admissions with respect to the alleged violations and agreed to request a Coastal Zone Act status decision prior to making crude oil shipments to destinations other than Paulsboro. The Delaware City refinery has paid the penalty. The Coastal Zone Act status decision request was submitted to DNREC and the outstanding appeal was withdrawn as required under the settlement agreement.
On December 28, 2016, DNREC issued the Ethanol Permit to DCR allowing the utilization of existing tanks and existing marine loading equipment at their existing facilities to enable denatured ethanol to be loaded from storage tanks to marine vessels and shipped to offsite facilities. On January 13, 2017, the issuance of the Ethanol Permit was appealed by two environmental groups. On February 27, 2017, the Coastal Zone Industrial Control Board (the “Coastal Zone Board”) held a public hearing and dismissed the appeal, determining that the appellants did not have standing. The appellants filed an appeal of the Coastal Zone Board’s decision with the Delaware Superior Court (the “Superior Court”) on March 30, 2017. On January 19, 2018, the Superior Court rendered an Opinion regarding the decision of the Coastal Zone Board to dismiss the appeal of the Ethanol Permit for the ethanol project. The judge determined that the record created by the Coastal Zone Board was insufficient for the Superior Court to make a decision, and therefore remanded the case back to the Coastal Zone Board to address the deficiency in the record. Specifically, the Superior Court directed the Coastal Zone Board to address any evidence concerning whether the appellants’ claimed injuries would be affected by the increased quantity of ethanol shipments. On remand, the Coastal Zone Board met on January 28, 2019 and reversed its previous decision on standing ruling that the appellants have standing to appeal the issuance of the Ethanol Permit. The parties to the action filed a joint motion with the Coastal Zone Board, requesting that the Coastal Zone Board concur with the parties’ proposal to secure from the Superior Court confirmation that all rights and claims are preserved for any subsequent appeal to the Superior Court, and that the matter then be scheduled for a hearing on the merits before the Coastal Zone Board. The Coastal Zone Board notified the parties in January of 2020 that it concurred with the parties’ proposed course of action. The appellants and DCR is currently evaluating its appeal options.
Atsubsequently filed a motion with the time we acquiredSuperior Court requesting relief consistent with what was described to the Toledo refinery, EPA had initiated an investigation intoCoastal Zone Board. In March of 2020, the compliance of the refinery with EPA standards governing flaring pursuant to Section 114 of the Clean Air Act. On February 1, 2013, EPA issued an Amended NOV, and on September 20, 2013, EPASuperior Court issued a NOVletter relinquishing jurisdiction over the matter, and Findingconcurring with the parties’ proposal to allow the case to proceed to a hearing on the merits before the Coastal Zone Board. The parties must now jointly propose to the Coastal Zone Board a schedule for prehearing activity and a merits hearing to resolve the matter. The parties must, therefore, submit to the Coastal Zone Board a joint proposed schedule to govern future proceedings related to the merits hearing to resolve the matter.
On September 11, 2020, DCR received two Citations and Notification of ViolationPenalties, with sub-parts, from OSHA related to Toledo refinery, alleging certaina combustion incident occurring on March 11, 2020. The citation seeks to impose penalties in the amount of $401,923 related to alleged violations of the Clean AirOccupation Safety and Health Act of 1970. An informal conference with OSHA on October 2, 2020 was unsuccessful in resolving the matter, and, as a result, DCR filed a Notice of Contest with OSHA contesting the citations in their entirety at its Plant 4 and Plant 9 flares since the acquisitionend of the refineryinformal conference. OSHA filed its Complaint on March 1, 2011. Toledo refineryDecember 13, 2020, and EPA subsequently entered into tolling agreements pendingDCR filed its response on January 4, 2021. OSHA and DCR participated in mandatory meditation on February 2, 2021, which was unsuccessful. On February 25, 2021, the Occupational Safety and Health Review Commission granted the parties’ Joint Motion for Additional Time for the Parties to Discuss Settlement. The Court has since granted multiple additional extensions. On May 27, 2021, the parties notified the court that settlement discussions. Althoughnegotiations are continuing and have continued to provide updates on the resolution has not been finalized,settlement negotiations. Subsequently, OSHA and DCR reached a settlement agreement with an assessed penalty of $401,923 and DCR agreed to undertake certain abatement measures. On January 24, 2022, DCR and the civil administrative penalty is anticipatedUnited Steelworkers signed the settlement agreement, and on January 25, 2022, OSHA executed the agreement.
On September 27, 2021, DCR received a Notice of Administrative Penalty Assessment and Secretary’s Order from DNREC, seeking to be approximately $645,000 including supplemental environmental projects. Toimpose penalties in the extentamount of $285,000 related to alleged Title V permit violations occurring in 2019 and 2020. On October 15, 2021, DCR filed a Notice of Appeal before Delaware’s Environmental Appeals Board, contesting the administrative penalty exceeds such amount, it is not expectedSecretary’s findings and requesting a hearing. On November 2, 2021, the Environmental Appeals Board scheduled a Pre-Hearing Conference for April 8, 2022 and Hearing Date for April 26, 2022. On November 30, 2021, settlement negotiations commenced, which are continuing to be material to us.date.
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 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 SCAQMD and Cal/OSHA. In connection with the acquisition of the Torrance refinery and related logistics assets, we agreed to take responsibility for NOV No. P63405 that ExxonMobil had received from the SCAQMD for Title V deviations that are alleged to have occurred in 2015. On August 14, 2018, we received a letter from SCAQMD offering to settle this NOV for $515,250. We are currently in communication with SCAQMD to resolve this NOV.
Subsequent to the acquisition, further NOVsNotices of Violations (“NOVs”) were issued by the SCAQMD, Cal/OSHA,South Coast Air Quality Management District (“SCAQMD”), Division of Occupational Safety and Health of the State of California, the City of Torrance, the City of Torrance Fire Department, and the Los Angeles County Sanitation District related to alleged operational violations, emission discharges and/or flaring incidents at the refinery and the logistics assets both before and after our acquisition. EPA in November 2016 conducted a RMPRisk Management Plan (“RMP”) inspection following the acquisition related to Torrance operations and issued preliminary findings in March 2017 concerning RMP potential operational violations. Effective January 9, 2020, we and EPA entered into a Consent Agreement and Final Order (“CAFO”), which contains no admission by us for any alleged violations in the CAFO, includes a release from all alleged violations in the CAFO, requires the payment of a penalty of $125,000 in January 2020 and also requires the implementation of a supplemental environmental project (“SEP”) of at least $219,000 that must be completed by December 15, 2021. The Company is currently in communication withSEP consisted of configuring the northeast fire water monitor to automatically deploy water upon detection of a release. We completed this reconfiguration on December 15, 2021 and expended at least $219,000 as required by the CAFO. On February 11, 2022, we submitted the final SEP Completion Report to EPA, towhich should fully resolve the RMP preliminary findings. this matter.
EPA and DTSCthe California Department of Toxic Substances Control (“DTSC”) in December 2016 conducted a RCRAResource Conservation and Recovery Act (“RCRA”) inspection following the acquisition related to Torrance operations and also issued in March 2017 preliminary findings concerning RCRA potential operational violations. In April 2017, EPA referred the RCRA preliminary findings to DTSC for final resolution. On March 1, 2018, we received a notice of intent to sue from Environmental Integrity Project, on behalf of Environment California, under RCRA with respect to the alleged RCRA violations from December 2016 EPA’s and DTSC’s inspection. On March 2, 2018, DTSC issued an order to correct alleged RCRA violations relating to the accumulation of oil bearing materials in roll off bins during 2016 and 2017. On June 14, 2018, the Torrance refinery and DTSC reached settlement regarding the oil bearing materials in the form of a stipulation and order, wherein the Torrance refinery agreed that it would recycle or properly dispose of the oil bearing materials by the end of 2018 and pay an administrative penalty of $150,000. The Torrance refinery has complied with these requirements.materials. Following this settlement, in June 2018,
DTSC referred the remaining alleged RCRA violations from EPA’s and DTSC’s December 2016 inspection to the California Attorney GeneralGeneral. On April 7, 2021, we were notified that these alleged remaining six federal RCRA violations had been referred to EPA for final resolution. On June 2, 2021, EPA conducted a further inspection to the December 2016 RCRA inspection. On August 13, 2021, we received EPA’s additional report indicating that the six federal RCRA findings were closed with no further enforcement action. The Torrance refinery andremaining alleged state RCRA violation is still pending with the California Attorney GeneralGeneral.
On February 4, 2021, we received a letter from the SCAQMD proposing to settle a NOV relating to 15 Title V deviations alleged to have occurred in the second half of 2017 for $1.3 million. On October 8, 2021, we reached settlement in principle with the SCAQMD to pay a penalty of $250,000 for 14 of the Title V deviations and a penalty of $1.3 million for the remaining deviation, which covers the period of 2017 through 2021 and settlement agreements are in process.
On December 4, 2020, the Pennsylvania Department of Environmental Protection ("PaDEP") issued a draft Consent Order and Agreement (“CAO”) to PBF Logistics Products Terminals LLC (“PLPT”) with respect to two alleged violations at the Philadelphia terminal for failure to: 1) test and inspect regulated piping as required in accordance with industry standards; and 2) have a professional engineering certification that all above ground storage tanks meet the applicable performance standards and requirements as a result of an alleged release of oil on January 10, 2020 into the Schuylkill River resulting from a pipe leak that was not contained by emergency containment structure. The draft order included a proposed penalty of $800,000. On December 15, 2021, we entered into a final CAO and agreed to pay the $800,000 penalty. Under the final CAO, we capped our future liability at $250,000 if PaDEP brought a subsequent enforcement action under the Pennsylvania Clean Streams Law (“CSL”) for environmental damage allegedly caused by the release of oil from PLPT’s operational violations. Under the final CAO, we also reserved our rights to challenge any subsequent enforcement action brought by PaDEP under the CSL. On January 13, 2022, we received from
PaDEP, a Consent Assessment of Civil Penalty alleging violations under the CSL of over $1.0 million. However, because of the CAO cap, the PaDEP’s penalty demand to settle these alleged violations is $250,000. We are currently reviewing the alleged violations and settlement offer.
In connection with self-reported flaring events that occurred at the Paulsboro Refinery between 2016 and 2020, in October 2021, the New Jersey Department of Environmental Protection (“NJDEP”) initiated discussions with PRC regarding potential penalties for alleged violations related to the self-reported flaring events. Although a formal NOV has not been issued, NJDEP provided a calculation sheet of potential penalties totaling approximately $1.6 million. We are currently challenging certain of those potential penalties and are in discussions to resolve these alleged remaining RCRA violations. Other than the $150,000 DTSC administrative penalty, no other settlement or penalty demands have been received to date with respect to any of the other NOVs, preliminary findings, or order that are in excess of $100,000. NJDEP regarding a potential settlement.
As the ultimate outcomes of the 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.
On September 2, 2011, prior to our ownership of the Chalmette refinery, the plaintiff in Vincent Caruso, et al. v. Chalmette Refining, L.L.C., filed an action on behalf of himself and potentially several thousand other Louisiana residents who live or own property in St. Bernard Parish and Orleans Parish and whose property was allegedly contaminated and who allegedly suffered any property damages and clean-up costs as a result of an emission of spent catalyst from the Chalmette refinery on September 6, 2010. Plaintiffs claim to have suffered injuries, symptoms, and property damage as a result of the release, although the trial court has limited recovery to property damages and clean-up expenses. Plaintiffs seek to recover unspecified damages, interest and costs. In 2016, there was a mini-trial for four plaintiffs for property damage relating to home and vehicle cleaning and the trial court rendered judgment awarding damages related to the cost for home cleaning and vehicle cleaning to the four plaintiffs. The trial court found Chalmette Refining and co-defendant Eaton Corporation (“Eaton”), to be solidarily liable for the damages. Chalmette Refining and Eaton filed an appeal in August 2016 of the judgment on the mini-trial and on June 28, 2017, the appellate court unanimously reversed the judgment awarding damages to the plaintiffs, and plaintiffs request for rehearing was later denied. The parties reached a comprehensive settlement of this matter on December 3, 2018, which received final court approval on January 17, 2019. We presently believe this matter will not have a material impact on our financial position, results of operations or cash flows.
On December 5, 1990, prior to 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 2007. 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. 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. Although no trial date has been set by the state trial court, the parties are preparing for a mini-trial of up to 10 plaintiffs, relating to 5 separate flaring events that occurred between 2002 and 2007. Because of the number of potential claimants is unknown and the differing events underlying the claims, the potential amount of the claims is not determinable. It is possible that an adverse outcome may have a material adverse effect on our financial position, results of operations, or cash flows.
On February 17, 2017, in Arnold Goldstein, et al. v. Exxon Mobil Corporation, et al.al., we and PBF Energy Company LLC, and our subsidiaries, PBF Energy Western Region LLC and Torrance Refining Company LLC and the manager of our Torrance refinery along with Exxon Mobil CorporationExxonMobil 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 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, Exxon hasExxonMobil 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 Courtcourt 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. As this matter isplaintiff, 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 class certification phase,motion for leave to amend plaintiffs presented to the Court. On June 9, 2021, we cannot currently estimatefiled a Motion to Dismiss/Strike the amount orTAC. 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 timingMotion 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. All other dates are stayed pending the Court issuing its resolution.order. 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 18, 2018, in Michelle Kendig and Jim Kendig, et al. v. ExxonMobil Oil Corporation, et al., PBF Energy Limited and Torrance Refining Company LLC along with ExxonMobil Oil Corporation and ExxonMobil Pipeline Company were named as defendants in a class action and representative action complaint filed on behalf of Michelle Kendig, Jim Kendig and others similarly situated. The complaint was filed in the Superior Court of the State of California, County of Los Angeles and alleges failure to authorize and permit uninterrupted rest and meal periods, failure to furnish accurate wage statements, violation of the Private Attorneys General Act and violation of the California Unfair Business and Competition Law. Plaintiffs seek to recover unspecified economic damages, statutory damages, civil penalties provided by statute, disgorgement of profits, injunctive relief, declaratory relief, interest, attorney’s fees and costs. To the extent that plaintiffs’ claims accrued prior to July 1, 2016, 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 and logistics assets. On October 26, 2018, the matter was removed to the Federal Court, California Central District. As this matter is in the class certification phase, we cannot currently estimate the amount or the timing of its resolution. We presently believe the outcome will not have a material impact on our financial position, results of operations or cash flows.
On September 7, 2018, in Jeprece Roussell, et al.al. v. PBF Consultants, LLC, etal. al., the Plaintiffplaintiff filed an action in the 19th Judicial District Court for the Parish of East Baton Rouge, allegesalleging numerous causes of action, including wrongful death, premises liability, negligence, and gross negligence against PBF Holding, Company LLC, PBFX Operating Company LLC, Chalmette Refining, L.L.C., two individual employees of the Chalmette Refinery (“the PBF Defendants”)refinery (the defendants), two entities, PBF Consultants, LLC and PBF Investments LLC that are Louisiana companies that are not associated with our companies, as well as Clean Harbors, Inc. and Clean Harbors Environmental Services, Inc. (collectively, “Clean Harbors”), Mr. Roussell’s employer. Mr. Roussell was fatally injured on March 31, 2018 while employed by Clean Harbors and performing clay removal work activities inside a clay treating vessel located at the Chalmette Refinery.refinery. Plaintiff seekssought unspecified compensatory damages for pain and suffering, past and future mental anguish, impairment, past and future economic loss, attorney’s fees and court costs. The PBF DefendantsOn October 8, 2021, we and our insurers reached an agreement in principle to settle this litigation and the related matters. Our portion of the settlement was accrued as of September 30, 2021 and did not have issued a tendermaterial impact on our financial position, results of defenseoperations, or cash flows. Settlement documents have been executed and indemnitypayments have been made. A Motion to Clean Harbors and its insurer pursuant to indemnity obligations contained inDismiss with Prejudice was filed by the associated services agreement. parties on February 3, 2022.
On September 25, 2018,7, 2021, MRC filed a Verified Petition for Writ of Mandate and Complaint for Declaratory and Injunctive Relief against the PBF Defendants filed an Answer inBAAQMD requesting the state court action denyingCourt to declare as invalid, unenforceable, and ultra vires the allegations. On October 10, 2018,BAAMQD’s July 21, 2021, adoption of Rule 6-5 Amendment. MRC is also seeking a writ of mandate ordering the PBF Defendants filedBAAQMD to removevacate and rescind the caseadoption 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 United States District Court forBAAQMD Board when the Middle DistrictRule 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 Louisiana. On November 9, 2018, Plaintiff filed a motion to remand the matter back to state courtCalifornia Environmental Quality Act and the PBF Defendants filed a responseCalifornia 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 November 30, 2018. OnOctober 27, 2021 and December 21, 2018, Plaintiff filed a motion for leave to file a reply memorandum and the reply memorandum was filed December 27, 2018. As this matter was recently filed, we cannot currently estimate the amount or the timing of its resolution.15, 2021. We presently believe the outcome will not have a material impact on our financial position, results of operations, or cash flows.
We are subject to obligations to purchase RINs. On February 15, 2017, we received notification that EPA records indicated that PBF Holding used potentially invalid RINs that were in fact verified under EPA’s RIN Quality Assurance Program (“QAP”) by an independent auditor as QAP A RINs. Under the regulations use of potentially invalid QAP A RINs providedprovides the user with an affirmative defense from civil penalties provided certain conditions are met. We have asserted the affirmative defense and if accepted by EPA will not be required to replace these RINs and will not be subject to civil penalties under the program. It is reasonably possible that EPA will not accept our defense and may assess penalties in these matters, but any such amount is not expected to have a material impact on our financial position, results of operations, or cash flows.
The federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances. Under CERCLA, such persons may be subject to joint and several liability for investigation and the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. As discussed more fully above, certain of our sites are subject to these laws and we may be held liable for investigation and remediation costs or claims for natural resource damages. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Analogous state laws impose similar responsibilities and liabilities on responsible parties. In our current normal operations, we have generated waste, some of which falls within the statutory definition of a “hazardous substance” and some of which may have been disposed of at sites that may require cleanup under Superfund.
ITEM 4. MINE SAFETY DISCLOSUREDISCLOSURES
None.
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 19, 201910, 2022 there were 17331 holders of record of PBF Energy Class A common stock and 2015 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 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 2025 Senior Secured Notes, the 2028 Senior Notes, (each as defined in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”)the 2025 Senior Notes and other debt instruments. Subject to certain exceptions, the Revolving Credit Facility and the indentures governing the Senior Notessenior 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.
While it is impossible to estimate the duration or ultimate financial impact of the COVID-19 pandemic on our business, our results have been adversely impacted. As part of our strategic plan to navigate these current extraordinary and volatile markets, we have suspended PBF Energy’s quarterly dividend on its Class A common stock. We will continue to monitor and evaluate our dividend policy as market conditions develop and our business outlook becomes clearer, however, we do not anticipate that our Board of Directors will declare a dividend in the foreseeable future.
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).
PBF Logistics LP
Due to the uncertainty of the full impact of the COVID-19 pandemic will have on its business, PBFX has decided to reduce their quarterly distribution to its minimum quarterly distribution of $0.30 per unit, which represents a shift in its distribution strategy to build cash flow coverage, de-lever the business and strengthen its financial resources as they continue to pursue potential organic growth projects or strategic acquisition opportunities. PBFX intends to make acontinue to pay at least the minimum quarterly distribution to the holders of its common units, including PBF LLC, of at least $0.30 per unit per quarter, or $1.20 per unit on an annualized basis, to the extent PBFX has sufficient cash from operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to PBFX’s general partner. However, there is no guarantee that PBFX will pay the minimum quarterly distribution or any amount on the units wethey 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.
During 2020, PBF Energy announced that it had suspended its quarterly dividend of $0.30 per share on its Class A common stock as part of its strategic plan to respond to the impact of the COVID-19 outbreak. As a result, there were no dividends or distributions for the year ended December 31, 2021. There were no tax distributions to PBF LLC’s other members in 2021. PBF Holding made $52.6$2.7 million in distributions to PBF LLC during the year ended December 31, 2018. PBF LLC used $141.3 million, which included $39.5 million distributed from PBF Holding, to make four separate non-tax distributions of $0.30 per unit ($1.20 per unit in total) to its members, of which $139.3 million was distributed to PBF Energy and the balance was distributed to PBF LLC’s other members. PBF Energy used this $139.3 million to pay four separate equivalent cash dividends of $0.30 per share of its Class A common stock on March 14, 2018, May 30, 2018, August 30, 2018 and November 30, 2018. There were no tax distributions to PBF LLC members in 2018.2021. In addition, PBFX made aggregate quarterly distributions of $100.1$76.0 million ($1.971.20 per unit) during the year ended December 31, 20182021 to holders of its common units, of which $50.6$35.9 million was paid to PBF LLC including payments related to IDRs.
Prior to the IDR Restructuring, PBF LLC owned all of the IDRs of PBFX. The IDRs entitled PBF LLC to receive increasing percentages, up to a maximum of 50.0%, of the cash PBFX distributed from operating surplus in excess of $0.345 per unit per quarter. The maximum distribution of 50.0% included distributions paid to PBF LLC on its partnership interest. The maximum distribution of 50.0% did not include any distributions that PBF LLC previously received on common units that it owns. PBFX made IDR payments of $12.7 million and $7.6 million to PBF LLC based on its distributions for the years ended December 31, 2018 and 2017, respectively. Subsequent to the closing of the IDR Restructuring, the IDRs will be canceled, no distributions will be made to PBF LLC with respect to IDRs and the newly issued common units will be entitled to normal distributions.LLC.
PBF LLC expects to continue to make tax distributions to its members in accordance with its amended and restated limited liability company agreement.
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.
This performance graph and the related textual information are based on historical data and are not indicative of future performance. The following line graph compares the cumulative total return on an investment in our common stock against the cumulative total return of the S&P 500 Composite Index and an index of peer companies (that we selected) for the periods commencing December 31, 20132016 through December 31, 2018.2021. Our peer group consists of the following companies that are engaged in refining operations in the U.S.: CVR Energy Inc., Delek US Holdings Inc., HollyFrontier Corp, Marathon Petroleum Corp, Phillips 66 and Valero Energy Corp.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 12/31/2016 | | 12/31/2017 | | 12/31/2018 | | 12/31/2019 | | 12/31/2020 | | 12/31/2021 |
| PBF Energy Class A common stock | $ | 100.00 | | | $ | 133.57 | | | $ | 126.97 | | | $ | 127.18 | | | $ | 29.13 | | | $ | 53.22 | |
| S&P 500 | 100.00 | | | 121.83 | | | 116.49 | | | 153.17 | | | 181.35 | | | 233.41 | |
| Peer Group | 100.00 | | | 132.54 | | | 117.97 | | | 142.91 | | | 94.07 | | | 126.35 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | 12/31/2013 | | 12/31/2014 | | 12/31/2015 | | 12/31/2016 | | 12/31/2017 | | 12/31/2018 |
| PBF Energy Inc. Class A Common Stock | $ | 100.00 |
| | $ | 88.58 |
| | $ | 127.21 |
| | $ | 101.07 |
| | $ | 134.99 |
| | $ | 128.32 |
|
| S&P 500 | 100.00 |
| | 113.69 |
| | 115.26 |
| | 129.05 |
| | 157.22 |
| | 150.33 |
|
| Peer Group | 100.00 |
| | 96.28 |
| | 118.80 |
| | 121.27 |
| | 161.06 |
| | 143.37 |
|
Recent Sales of Unregistered Securities—Exchange of PBF LLC Series A Units for PBF Energy Class A Common Stock
In the fourth quarter of 2018,2021, there were no exchanges of66,202 PBF LLC Series A Units exchanged for 66,202 shares of PBF Energy Class A common stock in transactions exempt from registration under Section 4(2)4(a)(2) of the Securities Act. We received no other consideration in connection with any exchanges. No exchanges were made by any of our directors or executive officers.
Share Repurchase Program
Our Board of Directors previously authorized the repurchase of up to $300.0 million of PBF Energy Class A common stock (as amended from time to time, the “Repurchase Program”), which expired on September 30, 2018 and was not renewed. 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 might have been effected through Rule 10b5-1 and Rule 10b-18 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 not obligated to purchase any shares under the Repurchase Program, and repurchases could be suspended or discontinued at any time without prior notice.
There were no repurchases of PBF Energy Class A Common Stock during the fourth quarter of 2018. For the period of time from the inception of the Repurchase Program through its expiration date, we purchased 6,050,717 shares for $150.8 million.
ITEM 6. SELECTED FINANCIAL DATA
The following tables present selected historical consolidated financial data of PBF Energy and PBF LLC. The selected historical consolidated financial data as of December 31, 2018 and 2017 and for each of the three years in the period ended December 31, 2018, have been derived from our audited financial statements, included in “Item 8. Financial Statements and Supplementary Data.” The selected historical consolidated financial data as of December 31, 2016, 2015 and 2014 and for the years ended December 31, 2015 and 2014 have been derived from the audited financial statements of PBF Energy and PBF LLC not included in this Annual Report on Form 10-K. As a result of the Chalmette and Torrance acquisitions, the historical consolidated financial results of PBF Energy and PBF LLC only include the results of operations for the Chalmette and Torrance refineries from November 1, 2015 and July 1, 2016 forward, respectively.
The historical consolidated financial data and other statistical data presented below should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and the related notes thereto, included in “Item 8. Financial Statements and Supplementary Data.”
The consolidated financial information may not be indicative of our future financial condition, results of operations or cash flows.
[RESERVED]
|
| | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| PBF Energy | | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| | | (in thousands, except share and per share data) |
| Revenues | | $ | 27,186,093 |
| | $ | 21,786,637 |
| | $ | 15,920,424 |
| | $ | 13,123,929 |
| | $ | 19,828,155 |
|
| Cost and expenses: | | | | | | | | | | |
| Cost of products and other | | 24,503,393 |
| | 18,863,621 |
| | 13,598,341 |
| | 11,481,614 |
| | 18,471,203 |
|
Operating expenses (excluding depreciation and amortization expense as reflected below) (1) | | 1,720,959 |
| | 1,684,435 |
| | 1,422,751 |
| | 902,808 |
| | 881,046 |
|
| Depreciation and amortization expense | | 359,126 |
| | 277,992 |
| | 216,341 |
| | 187,729 |
| | 166,799 |
|
| Cost of sales | | 26,583,478 |
| | 20,826,048 |
| | 15,237,433 |
| | 12,572,151 |
| | 19,519,048 |
|
General and administrative expenses (excluding depreciation and amortization expense as reflected below) (1)(2) | | 276,955 |
| | 214,547 |
| | 166,319 |
| | 181,266 |
| | 146,661 |
|
| Depreciation and amortization expense | | 10,634 |
| | 12,964 |
| | 5,835 |
| | 9,688 |
| | 13,583 |
|
| (Gain) loss on sale of asset | | (43,094 | ) | | 1,458 |
| | 11,374 |
| | (1,004 | ) | | (895 | ) |
| Total cost and expenses | | 26,827,973 |
| | 21,055,017 |
| | 15,420,961 |
| | 12,762,101 |
| | 19,678,397 |
|
| Income from operations | | 358,120 |
| | 731,620 |
| | 499,463 |
| | 361,828 |
| | 149,758 |
|
| Other income (expense): | | | | | | | | | | |
| Change in Tax Receivable Agreement liability | | 13,893 |
| | 250,922 |
| | 12,908 |
| | 18,150 |
| | 2,990 |
|
| Change in fair value of catalyst leases | | 5,587 |
| | (2,247 | ) | | 1,422 |
| | 10,184 |
| | 3,969 |
|
| Debt extinguishment costs | | — |
| | (25,451 | ) | | — |
| | — |
| | — |
|
| Interest expense, net | | (169,911 | ) | | (154,427 | ) | | (150,045 | ) | | (106,187 | ) | | (98,764 | ) |
Other non-service components of net periodic benefit cost (1) | | 1,109 |
| | (1,402 | ) | | (580 | ) | | (1,717 | ) | | (2,094 | ) |
| Income before income taxes | | 208,798 |
| | 799,015 |
| | 363,168 |
| | 282,258 |
| | 55,859 |
|
| Income tax expense (benefit) | | 33,507 |
| | 315,584 |
| | 137,650 |
| | 86,725 |
| | (22,412 | ) |
| Net income | | 175,291 |
| | 483,431 |
| | 225,518 |
| | 195,533 |
| | 78,271 |
|
| Less: net income attributable to noncontrolling interests | | 46,976 |
| | 67,914 |
| | 54,707 |
| | 49,132 |
| | 116,508 |
|
| Net income (loss) attributable to PBF Energy Inc. stockholders | | $ | 128,315 |
| | $ | 415,517 |
| | $ | 170,811 |
| | $ | 146,401 |
| | $ | (38,237 | ) |
| Weighted-average shares of Class A common stock outstanding: | | | | | | | | | | |
| Basic | | 115,190,262 |
| | 109,779,407 |
| | 98,334,302 |
| | 88,106,999 |
| | 74,464,494 |
|
| Diluted | | 118,773,606 |
| | 113,898,845 |
| | 103,606,709 |
| | 94,138,850 |
| | 74,464,494 |
|
| Net income (loss) available to Class A common stock per share: | | | | | | | | | | |
| Basic | | $ | 1.11 |
| | $ | 3.78 |
| | $ | 1.74 |
| | $ | 1.66 |
| | $ | (0.51 | ) |
| Diluted | | $ | 1.10 |
| | $ | 3.73 |
| | $ | 1.74 |
| | $ | 1.65 |
| | $ | (0.51 | ) |
| Dividends per common share | | $ | 1.20 |
| | $ | 1.20 |
| | $ | 1.20 |
| | $ | 1.20 |
| | $ | 1.20 |
|
| Balance sheet data (at end of period) : | | | | | | | | | | |
| Total assets | | $ | 8,005,415 |
| | $ | 8,117,993 |
| | $ | 7,621,927 |
| | $ | 6,105,124 |
| | $ | 5,164,008 |
|
Total debt (3) | | 1,974,726 |
| | 2,226,109 |
| | 2,180,700 |
| | 1,881,637 |
| | 1,260,349 |
|
| Total equity | | 3,248,479 |
| | 2,902,949 |
| | 2,570,684 |
| | 2,095,857 |
| | 1,693,316 |
|
| Other financial data : | | | | | | | | | | |
Capital expenditures (4) | | $ | 733,887 |
| | $ | 727,035 |
| | $ | 1,612,871 |
| | $ | 981,080 |
| | $ | 631,332 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| PBF LLC | | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| | | (in thousands) |
| Revenues | | $ | 27,186,093 |
| | $ | 21,786,637 |
| | $ | 15,920,424 |
| | $ | 13,123,929 |
| | $ | 19,828,155 |
|
| | | | | | | | | | | |
| Cost and expenses: | | | | | | | | | | |
| Cost of products and other | | 24,503,393 |
| | 18,863,621 |
| | 13,598,341 |
| | 11,481,614 |
| | 18,471,203 |
|
Operating expenses (excluding depreciation and amortization expense as reflected below) (1) | | 1,720,959 |
| | 1,684,435 |
| | 1,422,751 |
| | 902,808 |
| | 881,046 |
|
| Depreciation and amortization expense | | 359,126 |
| | 277,992 |
| | 216,341 |
| | 187,729 |
| | 166,799 |
|
| Cost of sales | | 26,583,478 |
| | 20,826,048 |
| | 15,237,433 |
| | 12,572,151 |
| | 19,519,048 |
|
General and administrative expenses (excluding depreciation and amortization expense as reflected below) (1)(2) | | 275,205 |
| | 214,222 |
| | 166,119 |
| | 180,310 |
| | 146,592 |
|
| Depreciation and amortization expense | | 10,634 |
| | 12,964 |
| | 5,835 |
| | 9,688 |
| | 13,583 |
|
| (Gain) loss on sale of assets | | (43,094 | ) | | 1,458 |
| | 11,374 |
| | (1,004 | ) | | (895 | ) |
| Total cost and expenses | | 26,826,223 |
| | 21,054,692 |
| | 15,420,761 |
| | 12,761,145 |
| | 19,678,328 |
|
| | | | | | | | | | | |
| Income from operations | | 359,870 |
| | 731,945 |
| | 499,663 |
| | 362,784 |
| | 149,827 |
|
| | | | | | | | | | | |
| Other income (expense): | | | | | | | | | | |
| Change in fair value of catalyst leases | | 5,587 |
| | (2,247 | ) | | 1,422 |
| | 10,184 |
| | 3,969 |
|
| Debt extinguishment costs | | — |
| | (25,451 | ) | | — |
| | — |
| | — |
|
| Interest expense, net | | (178,421 | ) | | (162,383 | ) | | (155,819 | ) | | (109,411 | ) | | (100,352 | ) |
Other non-service components of net periodic benefit cost (1) | | 1,109 |
| | (1,402 | ) | | (580 | ) | | (1,717 | ) | | (2,094 | ) |
| Income before income taxes | | 188,145 |
| | 540,462 |
| | 344,686 |
| | 261,840 |
| | 51,350 |
|
| Income tax expense (benefit) | | 7,999 |
| | (10,783 | ) | | 23,689 |
| | 648 |
| | — |
|
| Net income | | 180,146 |
| | 551,245 |
| | 320,997 |
| | 261,192 |
| | 51,350 |
|
| Less: net income attributable to noncontrolling interests | | 42,308 |
| | 51,168 |
| | 40,109 |
| | 34,880 |
| | 14,740 |
|
| Net income attributable to PBF Energy Company LLC | | $ | 137,838 |
| | $ | 500,077 |
| | $ | 280,888 |
| | $ | 226,312 |
| | $ | 36,610 |
|
| Balance sheet data (at end of period) : | | | | | | | | | | |
| Total assets | | $ | 7,953,036 |
| | $ | 8,038,985 |
| | $ | 7,133,492 |
| | $ | 5,501,167 |
| | $ | 4,525,920 |
|
Total debt (3) | | 2,300,808 |
| | 2,518,953 |
| | 2,370,793 |
| | 2,096,261 |
| | 1,370,103 |
|
| Total equity | | 3,219,249 |
| | 2,878,503 |
| | 2,487,820 |
| | 1,909,395 |
| | 1,652,837 |
|
| Other financial data : | | | | | | | | | | |
Capital expenditures (4) | | $ | 733,887 |
| | $ | 727,035 |
| | $ | 1,612,871 |
| | $ | 981,080 |
| | $ | 631,332 |
|
——————————
| |
(1) | Amounts disclosed include the retrospective adjustments recorded as part of the adoption of ASU 2017-07, “Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”. As part of the adoption of this ASU in 2018, other non-service components of the net periodic benefit cost are disclosed separately outside of income (loss) from operations with retrospective adjustments made to the amounts previously recorded within Operating expenses and General and administrative expenses for all periods presented. Refer to “Note 2 - Summary of Significant Accounting Policies” of our Notes to Consolidated Financial Statements for further details. |
| |
(2) | Includes acquisition related expenses consisting primarily of consulting and legal expenses related to completed and other pending and non-consummated acquisitions of $2.9 million, $1.0 million, $17.5 million and $5.8 million in 2018, 2017, 2016 and 2015, respectively. |
| |
(3) | Total debt, excluding debt issuance costs, includes current maturities, note payable and our Delaware Economic Development Authority Loan (which was fully converted to a grant as of December 31, 2016). PBF LLC debt also includes an affiliate note payable to PBF Energy which eliminates in consolidation at the PBF Energy level. |
| |
(4) | Includes expenditures for acquisitions, construction in progress, property, plant and equipment (including railcar purchases), deferred turnaround costs and other assets, excluding the proceeds from sales of assets. |
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.
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 upon 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:
•the effect of the COVID-19 pandemic, including resurgences and variants of the virus, as well as related governmental and consumer responses on our business, financial condition and results of operations;
•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 effectseffectiveness of competitionour crude oil sourcing strategies, including our crude by rail strategy and related commitments;
•our obligation to buy RINs and market risks related to the volatility in our markets;the price of RINs required to comply with the Renewable Fuel Standard and GHG emission credits required to comply with various GHG emission programs, such as AB 32;
•changes in currency exchange rates, interest rates and capital costs;
•adverse developments in our relationship with both our key employees and unionized employees;
•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;our expectations with respect to our capital improvement and turnaround projects;
•the impact of current and future laws, rulings and governmental regulations, including restrictions on the exploration and/or production of crude oil in the state of California, the implementation of rules and regulations regarding transportation of crude oil by rail or in response to the potential impacts of climate change, decarbonization and future energy transition;
•adverse impacts related to legislation by the federal government lifting the restrictions on exporting U.S. crude oil;
•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 may not reinstate dividend payments;
•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, 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 expectationsrelationship with respectboth our key employees and unionized employees;
•our substantial indebtedness, including the impact of potential downgrades to our corporate credit rating, secured notes and unsecured notes;
•changes in currency exchange rates, interest rates and capital improvementcosts;
•restrictive covenants in our indebtedness that may adversely affect our operational flexibility;
•counterparty credit and turnaround projects;
•performance risk exposure related to our supply and inventory intermediation arrangements expose us to counterparty credit and performance risk;arrangement;
•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 intermediates and finished products located at the Paulsboro and Delaware City refineries’ storage tanksJ. Aron Products upon termination of these agreements;the agreement;
•restrictive covenants in our indebtedness that may adversely affect our operational flexibility;
•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 duerelated to problems at PBFX or with third-party logistics infrastructure or operations, including pipeline, marine and rail transportation;
•the possibility that we might reduce or not make further dividend payments;
•the inability of our subsidiaries to freely pay dividends or make distributions to us;
•the impact of current and future laws, rulings and governmental regulations, including the implementation of rules and regulations regarding transportation of crude oil by rail;
•the impact of the newly enacted federal income tax legislation on our business;
•the effectiveness of our crude oil sourcing strategies, including our crude by rail strategy and related commitments;
•adverse impact related to regulation by the federal government lifting the restrictions on exporting U.S. crude oil;
•adverse impacts from changes in our regulatory environment, such as the effects of compliance with the California Global Warming Solutions Act (also referred to as “AB32”), or from actions taken by environmental interest groups;
•market risks related to the volatility in the price of RINs required to comply with the Renewable Fuel Standards and GHG emission credits required to comply with various GHG emission programs, such as AB32;
•our ability to successfully integrate recently completed acquisitions into our business and realize the benefits from such acquisitions;
•liabilities arising from recent acquisitions that are unforeseen or exceed our expectations;
•risk associated with the operation of PBFX as a separate, publicly-traded entity;
•potential tax consequences related to our investment in PBFX; and
•any decisions we continue to make with respect to our energy-related logisticallogistics assets that may be transferred to PBFX.
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 its subsidiaries. We were formed in March 2008 to pursue the acquisitions of crude oil refineries and downstream assets in North America. We currently own and operate fivesix domestic oil refineries and related assets located in Delaware City, Delaware, Paulsboro, New Jersey, Toledo, Ohio, New Orleans,Chalmette, Louisiana, Torrance, California, and Torrance,Martinez, California. OurBased on current configuration (subsequent to the East Coast Refining Reconfiguration), 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 12.2.13.2 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 fivesix oil refineries are all engaged in the refining of crude oil and other feedstocks into petroleum products, and are aggregated into the Refining segment. PBFX operates certain logistical assets such as crude oil and refined petroleum products terminals, pipelines, and storage facilities, which are aggregated into 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.
COVID-19 and Market Developments
Early ReturnThe impact of Railcars
On September 30, 2018, we agreed to voluntarily return a portion of railcars under an operating lease in order to rationalize certain components of our railcar fleet based on prevailing market conditionsthe unprecedented global health and economic crisis sparked by the COVID-19 pandemic was amplified late in the crudequarter ended March 31, 2020 due to movements made by the world’s largest oil by rail market. Under the termsproducers to increase market share. This created simultaneous shocks in oil supply and demand resulting in an economic challenge to our industry which has not occurred since our formation. This combination resulted in significant demand reduction for our refined products and atypical volatility in oil commodity prices. In 2021, as a result of the lease amendment, we will pay agreed amounts in lieulifting or easing of satisfaction of return conditions (the “early termination penalty”) and will pay a reduced rental fee over the remaining term of the lease. Certain of these railcars were idle as of September 30, 2018restrictions by many governmental authorities and the remaining railcars were taken outdistribution of service duringCOVID-19 vaccines and other protective measures, the fourth quarter of 2018 and subsequently fully returneddemand for refined products started to recover, consequently improving our refining margins in comparison to the lessor. As a result, we recognized an expense of $52.3 millionprior year. While our results for the year ended December 31, 2018 included within Cost of sales consisting of (i) a $40.3 million charge2021 were impacted by lower demand for the early termination penalty and (ii) a $12.0 million charge relatedrefined products, we experienced gradual improvements when compared to the remaining lease payments associatedyear ended December 31, 2020 and favorable impacts on our revenues, cost of products sold, operating income and liquidity. Although we currently continue to operate our refineries at reduced rates, throughput rates across our refining system have increased in the current year to correlate with the railcars identified withingradual increases in demand.
Debt and Credit Facilities
Senior Notes
During the amended lease,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 May 13, 2020, we issued $1.0 billion in aggregate principal amount of the initial 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 December 21, 2020, we issued 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 January 24, 2020, we issued $1.0 billion in aggregate principal amount of the 2028 Senior Notes. The net proceeds from this offering were approximately $987.0 million after deducting the initial purchasers’ discount and offering expenses. We used $517.5 million of the proceeds to fully redeem our 7.00% senior notes due 2023 (the “2023 Senior Notes”) and the balance to fund a portion of the cash consideration for Martinez Acquisition (as defined below).
On February 14, 2020, we exercised our rights under the indenture governing the 2023 Senior Notes to redeem all of which were idled and outthe outstanding 2023 Senior Notes at a price of service as of December 31, 2018.
Torrance Land Sale
On August 7, 2018, we closed on a third-party sale of a parcel of real property acquired as part103.5% of the Torrance Refinery, but not partaggregate 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 refinery itself. The sale resulted2023 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 a gain of approximately $43.8 million included within (Gain) loss on sale of assets within the Consolidated Statements of Operations.Operations for the year ending December 31, 2020.
PBF Energy Inc. Public Offerings
Catalyst Financing Obligations
In September and October 2021, we settled certain precious metal financing arrangements, resulting in a resultreduction to debt of approximately $31.7 million.
On September 25, 2020, we closed on agreements to sell a portion of our precious metals catalyst to certain major commercial banks for approximately $51.9 million and subsequently leased the catalyst back. The precious metals financing arrangements cover a portion of the initial public offeringcatalyst used in our East Coast Refining System, Martinez and related reorganization transactions, PBF Energy became the sole managing member of PBF LLC with a controlling voting interest in PBF LLC and its subsidiaries. Effective with completionToledo refineries.
The volumes of the initial public offering, PBF Energy consolidatesprecious metal catalyst and the financial resultsinterest rates are fixed over the term of PBF LLC and its subsidiaries and records a noncontrolling interest in its consolidated financial statements representingeach financing arrangement. We are obligated to repurchase the economic interests of PBF LLC unitholders other than PBF Energy. Additionally, a series of secondary offerings were made subsequent to our IPO whereby funds affiliated with The Blackstone Group L.P. (“Blackstone”) and First Reserve Management L.P. (“First Reserve”) sold their interests in us. As a resultprecious metals catalyst at fair market value upon expiration of these secondary offerings, Blackstone and First Reserve no longer hold any PBF LLC Series A units.
On August 14, 2018, PBF Energy completed a public offering of an aggregate of 6,000,000 shares of PBF Energy Class A common stock for net proceeds of $287.3 million, after deducting underwriting discounts and commissions and other offering expenses (the “August 2018 Equity Offering”).
On December 19, 2016, PBF Energy completed a public offering of an aggregate of 10,000,000 shares of PBF Energy Class A common stock for net proceeds of $274.3 million, after deducting underwriting discounts and commissions and other offering expenses (the “December 2016 Equity Offering”).
As of December 31, 2018, including the offerings described above, PBF Energy owns 119,895,422 PBF LLC Series C Units and our current and former executive officers and directors and certain employees and others beneficially own 1,206,325 PBF LLC Series A Units, and the holders of our issued and outstanding shares of PBF Energy Class A common stock have 99.0% of the voting power in us and the members of PBF LLC other than PBF Energy through their holdings of Class B common stockleases. For all leases not renewed at maturity, we have the remaining 1.0% of the voting power in us.
PBFX Equity Offerings
On July 30, 2018, PBFX closed on a common unit purchase agreement with certain funds managed by Tortoise Capital Advisors, L.L.C. providing for the issuanceability and sale in a registered direct offering (the “Registered Direct Offering”) of an aggregate of 1,775,750 common units for net proceeds of approximately $34.8 million.
On August 17, 2016, PBFX completed a public offering of an aggregate of 4,000,000 common units, and granted the underwriter an optionintent to purchase an additional 600,000 common units, of which 375,000 units were subsequently purchased on September 14, 2016, for total net proceeds of $86.8 million, after deducting underwriting discounts and commissions and other offering expenses.
On April 5, 2016, PBFX completed a public offering of an aggregate of 2,875,000 common units, including 375,000 common units that were sold pursuant to the full exercise by the underwriter of its option to purchase additional common units, for net proceeds of $51.6 million, after deducting underwriting discounts and commissions and other offering expenses.
As a result of the PBFX equity offerings, as of December 31, 2018, PBF LLC held a 44.0% limited partner interest in PBFX and owned all of PBFX’s IDRs, with the remaining 56.0% limited partner interest owned by public common unitholders. Immediately following the closing of the IDR Restructuring, the IDRs will be canceled and PBF LLC will hold an approximately 54.1% limited partner interest in PBFX.
PBFX Assets and Transactions
PBFX’s assets consist of various logistics assets (as described in “Item 1. Business”). Apart from certain third-party acquisitions, PBFX’s revenue is derived from long-term, fee-based commercial agreements with subsidiaries of PBF Holding, which include minimum volume commitments, for receiving, handling, transferring and storing crude oil, refined products and natural gas. These transactions are eliminated by PBF Energy and PBF LLC in consolidation.
Since the inception of PBFX in 2014, PBF LLC and PBFX have entered into a series of drop-down transactions. Such transactions and third-party acquisitions made by PBFX occurring in the three years ended December 31, 2018 are discussed below.
On July 16, 2018, PBFX entered into an agreement with Crown Point to purchase its wholly-owned subsidiary, CPI Operations LLC for total consideration of approximately $127.0 million, including working capital and the Contingent Consideration (as defined in “Note 4 - Acquisitions” offinance such debt through availability under our Notes to Consolidated Financial Statements), comprised of an initial payment at closing of $75.0 million with a remaining $32.0 million balance being payable one year after closing. The East Coast Storage Assets Acquisition closed on October 1, 2018.revolving credit facilities.
On July 16, 2018, PBFX entered into the Development Assets Contribution Agreements between PBFX and PBF LLC, pursuant to which PBFX acquired from PBF LLC all of the issued and outstanding limited liability company interests of the Development Assets. The acquisition of the Development Assets closed on July 31, 2018 for total consideration of $31.6 million consisting of 1,494,134 common units representing limited partner interests in PBFX, issued to PBF LLC (the “Development Assets Acquisition”).
On April 16, 2018, PBFX completed the purchase of Knoxville Terminals from Cummins Terminals, Inc. for total cash consideration of $58.0 million, excluding working capital adjustments (the “Knoxville Terminals Purchase”). The transaction was financed through a combination of cash on hand and borrowings under the PBFX Revolving Credit Facility.
On February 15, 2017, we entered into the Chalmette Storage Services Agreement under which PBFX, through PBFX Op Co, assumed construction of the Chalmette Storage Tank. The Chalmette Storage Tank commenced operations in November 2017 upon completion of construction.
On February 15, 2017, PBFX entered into the PNGPC Contribution Agreement between PBFX and PBF LLC, pursuant to which PBFX Op Co acquired from PBF LLC all of the issued and outstanding limited liability company interests of PNGPC. PNGPC owns and operates an existing interstate natural gas pipeline. In August 2017, PBFX Op Co completed the construction of a new pipeline which replaced the existing pipeline and commenced services.
On August 31, 2016, PBFX acquired from PBF LLC 50% of the issued and outstanding limited liability company interests of TVPC, whose assets consist of the Torrance Valley Pipeline.
On April 29, 2016, PBFX’s wholly-owned subsidiary, PBF Logistics Products Terminals LLC, completed the purchase of the four refined products terminals in the greater Philadelphia region (the “East Coast Terminals”) from an affiliate of Plains All American Pipeline, L.P.
PBF Holding Revolving Credit Facility
On May 2, 2018, PBF Holding and certain of its wholly-owned subsidiaries, as borrowers or subsidiary guarantors, replacedDuring the year ended December 31, 2020, we used advances under our existing asset-based revolving credit agreement dated as of August 15, 2014 (the “August 2014 Revolving Credit Agreement”) withFacility to fund a portion of the Revolving Credit Facility. AmongMartinez Acquisition (as defined below) and for other things,general corporate purposes. The outstanding borrowings under the Revolving Credit Facility increased the maximum commitment available to PBF Holding from $2.6 billion to $3.4 billion, extended the maturity date to May 2023, and redefined certain components of the Borrowing Base, as defined in the agreement governing the Revolving Credit Facility (the “Revolving Credit Agreement”), to make more funding available for working capital and other general corporate purposes. In addition, an accordion feature allows for commitments of up to $3.5 billion. The commitment fees on the unused portion, the interest rate on advances and the fees for letters of credit are consistent with the August 2014 Revolving Credit Agreement and further described in “Note 9 - Credit Facility and Debt” of our Notes to Consolidated Financial Statements.
There were no outstanding borrowings on the revolver as of December 31, 2018. At December 31, 20172021 and December 31, 2016, there was $350.0 million outstanding under the August 2014 Revolving Credit Agreement, respectively.2020 were $900.0 million.
PBFX Revolving Credit Facility
On July 30, 2018,During the year ended December 31, 2021 and December 31, 2020, PBFX entered intomade net repayments of $100.0 million and $83.0 million on the PBFX Revolving Credit Facility. The outstanding borrowings under the PBFX Revolving Credit Facility with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of lenders. The PBFX Revolving Credit Facility amended and restated the May 2014 PBFX Revolving Credit Facility. Among other things, the amended PBFX Revolving Credit Facility increased the maximum commitment available to PBFX from $360.0 million to $500.0 million and extended the maturity date to July 2023. PBFX has the ability to increase the maximum amount of the PBFX Revolving Credit Facility by an aggregate amount of up to $250.0 million to a total facility size of $750.0 million, subject to receiving increased commitments from the lenders or other financial institutions and satisfaction of certain conditions. The commitment fees on the unused portion, the interest rate on advances, and the fees for letters of credit are consistent with the May 2014 PBFX Revolving Credit Facility. The PBFX Revolving Credit Facility is guaranteed by a guaranty of collection from PBF LLC. During 2018, PBFX borrowed $126.3 million, net including borrowings for the Knoxville Terminals Purchase and the East Coast Storage Assets Acquisition.
The outstanding balance under the PBFX revolving credit facility was $156.0 million and $29.7were $100.0 million as of December 31, 2018 and December 31, 2017, respectively.2021.
Senior Notes
On May 30, 2017, PBF Holding and PBF Finance issued $725.0 million, in aggregate, principal amount of the 2025 Senior Notes. We used the net proceeds of $711.6 millionRefer to fund the cash tender offer (the “Tender Offer”) for any and all of the outstanding 8.25% senior secured notes due 2020 (the “2020 Senior Secured Notes”), 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 910 - Credit FacilityFacilities and Debt” of our Notes to Consolidated Financial Statements, upon the satisfaction and discharge of the 2020 Senior Secured Notes in connection with the closing of the Tender Offer and the redemption, the 2023 Senior Notes became unsecured and certain covenants were modified, as provided for in the indenture governing the 2023 Senior Notes and related documents.further information.
On October 6, 2017, PBFX issued $175.0 million in aggregate principal amount of 6.875% Senior Notes due 2023 (the “new PBFX 2023 Senior Notes” and, together with the initial PBFX 2023 Senior Notes, the “PBFX 2023 Senior Notes”). The new PBFX 2023 Senior Notes were issued at 102% of face value with an effective rate of 6.442% and were issued under the indenture governing the initial PBFX 2023 Senior Notes dated May 12, 2015. PBFX used the net proceeds from the offering of the new PBFX 2023 Senior Notes to repay a portion of the PBFX Revolving Credit Facility and for general capital purposes.
PBF Rail Term LoanLand Sales
On December 22, 2016, PBF Rail Logistics Company LLC (“PBF Rail”) entered into20, 2021, PBFX closed on a $35.0 million term loan (the “PBF Rail Term Loan”) with a bank previously party to the Rail Facility. The PBF Rail Term Loan amortizes monthly over its five-year term and bears interestthird-party sale of real property at the one month LIBOR plus the margin as definedrefined products terminals in the agreement governing the PBF Rail Term Loan (the “Rail Credit Agreement”greater Philadelphia area (“East Coast Terminals”). As security for the PBF Rail Term Loan, PBF Rail pledged, among other things: (i) certain Eligible Railcars (ii) the Debt Service Reserve Account (as definedThe sale resulted in a gain of approximately $2.8 million in the Rail Credit Agreement); and (iii) PBF Holding’s member interest in PBF Rail. Additionally, the Rail Credit Agreement contains customary terms, eventsfourth quarter of default and covenants for transactions2021, included within Gain on sale of this nature. PBF Rail may at any time repay the PBF Rail Term Loan without penaltyassets in the event that railcars collateralizingConsolidated Statements of Operations.
On December 30, 2020 and August 1, 2019, we closed on third-party sales of parcels of real property acquired as part of the loan are sold, scrapped or otherwise removed fromTorrance refinery, but not part of the collateral pool.
refinery itself. The outstanding balance under the PBF Rail Term Loan was $21.6sales resulted in gains of approximately $8.1 million and $28.4$33.1 million in the fourth quarter of 2020 and third quarter of 2019, respectively, 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. Based on this reconfiguration, our East Coast throughput capacity currently approximates 285,000 barrels per day.
Turnaround Costs and Assets under Construction
As of December 31, 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 the fourth quarter of 2020.
Capital Project Abandonments
In connection with our ongoing strategic initiative to address the COVID-19 pandemic, including our East Coast Refining Reconfiguration, we reassessed our refinery wide slate of capital projects that were either in process or not yet placed into service as of December 31, 20182020. 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 the fourth quarter of 2020.
Severance Costs
Following the onset of the COVID-19 pandemic, 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, 2017, respectively.2021, a liability for the Tax Receivable Agreement of $48.3 million reflecting the estimate of the undiscounted amounts that PBF Energy expects to pay under the agreement, net of the impact of a deferred tax asset valuation allowance recognized in accordance with ASC 740. 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 14 - Commitments and Contingencies” and “Note 21 - 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.
Martinez Acquisition
On July 1, 2016, weWe acquired from ExxonMobil and its subsidiary, Mobil Pacific Pipeline Company, the TorranceMartinez refinery and related logistics assets. The Torrance refinery, locatedassets from Shell Oil Products on 750 acres in Torrance, California, is a high-conversion 155,000 bpd, delayed-coking refinery with a Nelson Complexity Index of 14.9. The facility is strategically positioned in Southern California with advantaged logistics connectivity that offers flexible raw material sourcing and product distribution opportunities primarily in the California, Las Vegas and Phoenix area markets. The Torrance Acquisition increased our total throughput capacity to approximately 900,000 bpd.
In addition to refining assets, the Torrance Acquisition included a number of high-quality logistics assets consisting of a sophisticated network of crude and products pipelines, product distribution terminals and refinery crude and product storage facilities. The most significant of the logistics assets is a 189-mile crude gathering and transportation system which delivers San Joaquin Valley crude oil directly from the field to the refinery. Additionally, included in the transaction were several pipelines which provide access to sources of crude oil including the Ports of Long Beach and Los Angeles, as well as clean product outlets with a direct pipeline supplying jet fuel to the Los Angeles airport. The Torrance refinery also has crude and product storage facilities with approximately 8.6 million barrels of shell capacity.
TheFebruary 1, 2020 for an aggregate purchase price for the assets was approximately $521.4of $1,253.4 million in cash after post-closing purchase price adjustments, plus(the “Martinez Acquisition”), including final working capital of $450.6 million. The final purchase price$216.1 million and fair value allocation were completed asthe obligation to make certain post-closing earn-out payments to Shell Oil Products based on certain earnings thresholds of June 30, 2017.the Martinez refinery for a period of up to four years (the “Martinez Contingent Consideration”). The transaction was financed through a combination of cash on hand, including proceeds from certain equity offerings,the 2028 Senior Notes, and borrowings under our August 2014the Revolving Credit Agreement.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 AgreementsAgreement
On certain dates subsequent toOctober 25, 2021, PBF Holding and its subsidiaries, the inception ofPBF Entities, entered into the Third Inventory Intermediation Agreements, we and our subsidiaries, DCR and PRC, entered into amendments to the amended and restated inventory intermediation agreement (as amended, the “Inventory Intermediation Agreements”)Agreement with J. Aron, pursuant to which certainthe terms of the existing inventory intermediation agreements were amended and restated in their entirety, including, among other things, pricing and an extension of the term.terms. The most recent of these was on September 8, 2017 whichThird Inventory Intermediation Agreement extends the term of the Inventory Intermediation Agreement relating to DCR and PRC to July 1, 2019 and December 31, 2019, respectively,2024, which termsterm may be further extended by mutual consent of the parties to July 1, 2020 and December 31, 2020, respectively.2025.
Pursuant to eachthe Third Inventory Intermediation Agreement, J. Aron continueswill continue to purchase and hold title to the J. Aron Products purchased or produced by the Refineries and delivered into tanks at the Refineries.Storage Tanks. Furthermore, J. Aron agrees to sell the J. Aron Products back to PRC and DCR (and, at the Refinerieselection of the PBF Entities, Chalmette Refining) as the J. Aron Products are discharged out of the Refineries’ tanks.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 AgreementsAgreement and will retain these storage rights for the term of the agreements. PBF Holding continuesagreement. We intend to utilize the crude oil and will market and sell the Productsrefined products independently to third parties.
PBFX Equity Offerings
On April 24, 2019, PBFX entered into subscription agreements to sell an aggregate of 6,585,500 common units to certain institutional investors in a registered direct offering (the “2019 Registered Direct Offering”) for gross proceeds of approximately $135.0 million. The 2019 Registered Direct Offering closed on April 29, 2019.
As of December 31, 2021, PBF LLC held a 47.9% limited partner interest in PBFX with the remaining 52.1% limited partner interest owned by public common unitholders.
PBFX Assets and Transactions
PBFX’s assets consist of various logistics assets (as described in “Item 1. Business”). Apart from business associated with certain third-party acquisitions, PBFX’s revenues are derived from long-term, fee-based commercial agreements with subsidiaries of PBF Holding, which include minimum volume commitments, for receiving, handling, transferring and storing crude oil, refined products and natural gas. These transactions are eliminated by PBF Energy and PBF LLC in consolidation.
Since the inception of PBFX in 2014, PBF LLC and PBFX have entered into a series of drop-down transactions. Such transactions and third-party acquisitions made by PBFX occurring in the three years ended December 31, 2021 are discussed below.
TVPC Acquisition
On April 24, 2019, PBFX entered into a contribution agreement with PBF LLC, pursuant to which PBF LLC contributed to PBFX all of the issued and outstanding limited liability company interests of TVP Holding Company LLC (“TVP Holding”) for total consideration of $200.0 million (the “TVPC Acquisition”). Prior to the TVPC Acquisition, TVP Holding owned a 50% membership interest in Torrance Valley Pipeline Company LLC (“TVPC”). Subsequent to the closing of the TVPC Acquisition on May 31, 2019, PBFX owns 100% of the membership interests in TVPC. The transaction was financed through a combination of proceeds from the 2019 Registered Direct Offering and borrowings under the PBFX Revolving Credit Facility.
PBFX IDR Restructuring Agreement
On February 28, 2019, PBFX closed on the transaction contemplated by the equity restructuring agreement (the “IDR Restructuring Agreement”) with PBF LLC and PBF GP, pursuant to which PBFX’s IDRs held by PBF LLC were canceled and converted into 10,000,000 newly issued PBFX common units. Subsequent to the closing of the IDR Restructuring Agreement, no distributions were made to PBF LLC with respect to the IDRs and the newly issued PBFX common units are entitled to normal distributions by PBFX.
Renewable Fuels Standard
We are subject to obligations to purchase RINs required to comply with the Renewable Fuels 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 $143.9$726.0 million in RINs costs during the year ended December 31, 20182021 as compared to $293.7$326.4 million and $347.5$122.7 million during the years ended December 31, 20172020 and 2016,2019, respectively. The fluctuations 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. Our RINs purchase obligation is dependent on our actual shipment of on-road transportation fuels domestically and the amount of blending achieved.
Crude Oil Acquisition Agreements
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 Chalmette Acquisition 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 the third quarter of 2017 as PDVSA has suspended deliveries due to the parties’ inability to agree to mutually acceptable payment terms. 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 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.
Tax Receivable Agreement
In connection with PBF Energy’s initial public offering, 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, 2018, a liability for the Tax Receivable Agreement of $373.5 million, reflecting its estimate of the undiscounted amounts that it expects to pay under the agreement due to exchanges including those in connection with its IPO and its secondary offerings. 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 its future business operations, assuming no material changes in the relevant tax law. Periodically, it may adjust the liability based, in part, 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. For example, PBF Energy must adjust the estimated Tax Receivable Agreement liability each time it purchases PBF LLC Series A Units or upon an exchange of PBF LLC Series A Units for PBF Energy Class A common stock. These periodic adjustments to the tax receivable liability, if any, are recorded in general and administrative expense and may result in adjustments to its income tax expense and deferred tax assets and liabilities. As a result of the reduction of the corporate tax rate to 21% as part of the TCJA, the liability associated with the Tax Receivable Agreement was reduced. Accordingly, the deferred tax assets associated with the payments made or expected to be made were also reduced.
Share Repurchase Program
Our Board of Directors previously authorized the repurchase of up to $300.0 million of PBF Energy Class A common stock. On September 26, 2016, our Board of Directors approved a two year extension to the existing Repurchase Program. As a result of the extension, the Repurchase Program ran through September 30, 2018 but was not renewed further or thereafter. There were no repurchases of PBF Energy Class A common stock during the year ended December 31, 2018. For the period of time from the inception of the Repurchase Program through its expiration date, we purchased 6,050,717 shares of PBF Energy Class A common stock for $150.8 million through open market transactions.
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 might have been effected through Rule 10b5-1 and Rule 10b-18 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 not obligated to purchase any shares under the Repurchase Program, and repurchases might have been suspended or discontinued at any time without prior notice.
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.
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 sheet.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, including the impact and developments related to the COVID-19 pandemic and the related governmental and consumer responses which have introduced 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 the third quarter of 2017 as PDVSA has suspended deliveries due to our inability to agree to mutually acceptable payment terms.terms and because of U.S. government sanctions against PDVSA.
In the past several years, we expanded and upgraded the existing on-site railroad infrastructure at the Delaware City refinery. Currently, crude oil delivered by rail to this facility is consumed at our Delaware City and PaulsboroEast Coast refineries. The Delaware City rail unloading facilities, and our recently acquiredthe 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. As discussed in “Note 8 - Accrued expenses” of our Notes to Consolidated Financial Statements, on September 30, 2018, we agreed to voluntarily return a portion of railcars under an operating lease in order to rationalize certain components of our railcar fleet based on prevailing market conditions in the crude oil by rail market. Under the terms of the lease amendment, we agreed to pay an early termination penalty and will pay a reduced rental fee over the remaining term of the lease. 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 Fuels 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.
Furthermore, during 2020 our operating results were negatively impacted by the ongoing COVID-19 pandemic which has caused a significant decline in the demand for our refined products and a decrease in the prices for crude oil and refined products, both of which have negatively impacted our revenues, cost of sales and operating income.
Refinery-Specific Information
The following section includes refinery-specific information related to our operations, crude oil differentials, ancillary costs, and local premiums and discounts.
DelawareEast Coast Refining System (Delaware City Refinery.and Paulsboro Refineries). The benchmark refining margin for the Delaware City refineryEast 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 ultra-low sulfur diesel (“ULSD”)ULSD against the market value of Dated Brent and refer to the benchmark as the Dated Brent (NYH) 2-1-1 benchmark refining margin. Our Delaware City refineryThe East Coast Refining System has a product slate of approximately 55%44% gasoline, 32% distillate, 2% high-value Group I lubricants, 2% high-value petrochemicals, with the remaining portion of the product slate comprised of lower-value products (5%(4% petroleum coke, 3%4% LPGs, 2%9% black oil and 1%3% other). For this reason, we believe the Dated Brent (NYH) 2-1-1 is an appropriate benchmark industry refining margin. The majority of Delaware CityEast Coast refining revenues are generated off NYH-based market prices.
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%70% 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.
Paulsboro Refinery. The benchmark refining margin for the Paulsboro refinery 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 RBOB and ULSD diesel against the market value of Dated Brent and refer to the benchmark as the Dated Brent (NYH) 2-1-1 benchmark refining margin. Our Paulsboro refinery has a product slate of approximately 42% gasoline, 33% distillate and 4% high-value Group I lubricants, with the remaining portion of the product slate comprised of lower-value products (14% black oil, 3% petroleum coke, 2% LPGs and 2% other). For this reason, we believe the Dated Brent (NYH) 2-1-1 is an appropriate benchmark industry refining margin. The majority of Paulsboro revenues are generated off NYH-based market prices.
The Paulsboro refinery’s realized gross margin on a per barrel basis has historically differed from the Dated Brent (NYH) 2-1-1 benchmark refining margin due to the following factors:
•the Paulsboro refinery processes a slate of primarily medium and heavy sour crude oils, which has historically constituted approximately 75% to 85% of total throughput. The remaining throughput consists of sweet crude oil and other feedstocks and blendstocks;
•as a result of the heavy, sour crude slate processed at Paulsboro, we produce lower value products including sulfur and petroleum coke. These products are priced at a significant discount to RBOB and ULSD; and
•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 blending (“CBOB”)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 55%56% gasoline, 33%30% 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, 2% black oil and 3%2% other). 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.
Chalmette Refinery. The benchmark refining margin for the Chalmette refinery is calculated by assuming two barrels of Light Louisiana Sweet (“LLS”)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%45% gasoline and 30%33% distillate, 2% high-value petrochemicals with the remaining portion of the product slate comprised of lower-value products (10%(8% black oil, 5% LPGs, 4% petroleum coke, 3% LPGs and 3% 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 (USGC)(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.
The PRL (pre-treater, reformer, light ends) project was completed in 2017 which has increased high-octane, ultra-low sulfur reformate and chemicals production. The new crude oil tank was also commissioned in 2017 and is allowing additional gasoline and diesel exports, reduced RINs compliance costs and lower crude ship demurrage costs.
Additionally, we are in the process of restarting our idled 12,000 barrel per day coker unit was restarted in the fourth quarter of 2019 to increase the refinery’s long-term feedstock flexibility and to be better positioned tocapture the potential benefit from potential dislocations in the price for heavy and high-sulfur feedstocks. The unit is expected to be in service by the end of 2019 and will increasehas increased the refinery’s total coking capacity to approximately 42,00040,000 barrels per day.
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”), California Air Resources Board (CARB)CARB diesel and jet fuel and refer to the benchmark as the ANS (WCLA)(West Coast) 4-3-1 benchmark refining margin. Our Torrance refinery has a product slate of approximately 60%63% gasoline and 26%21% distillate with the remaining portion of the product slate comprised of lower-value products (9% petroleum coke, 2%(3% LPG, 2%3% black oil and 1%10% other). For this reason, we believe the ANS (West Coast) 4-3-1 is an appropriate benchmark industry refining margin. The majority of Torrance revenues are generated off West Coast Los Angeles-based market prices.
The Torrance refinery’s realized gross margin on a per barrel basis has historically differed from the ANS (WCLA)(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% 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.
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 60% gasoline and 30% distillate with the remaining portion of the product slate comprised of lower-value products (4% petroleum coke, 4% LPG and 2% 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 80% 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, 2018, 20172021, 2020 and 20162019 (amounts in thousands,millions, except per share data). Differences between the results of operations of PBF Energy and PBF LLC primarily pertain to income tax expense,taxes, interest expense and non-controllingnoncontrolling 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 owned by PBFX, are all engaged in the refining of crude oil and other feedstocks into petroleum products, and are aggregated into the Refining segment. PBFX is a publicly-traded MLP that operates certain logisticallogistics assets such as crude oil and refined petroleum products terminals, pipelines and storage facilities. PBFX’s operations are aggregated into 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 revenuerevenues and a significant portion of its operating results eliminateeliminated in consolidation.
| | | PBF Energy | | Year Ended December 31, | PBF Energy | | Year Ended December 31, |
| | | 2018 | | 2017 | | 2016 | | | 2021 | | 2020 | | 2019 |
| Revenues | | $ | 27,186,093 |
| | $ | 21,786,637 |
| | $ | 15,920,424 |
| Revenues | | $ | 27,253.4 | | | $ | 15,115.9 | | | $ | 24,508.2 | |
| | | | | | | | |
| Cost and expenses: | | | | | | | Cost and expenses: | |
| Cost of products and other | | 24,503,393 |
| | 18,863,621 |
| | 13,598,341 |
| Cost of products and other | | 23,826.8 | | | 14,275.6 | | | 21,387.5 | |
| Operating expenses (excluding depreciation and amortization expense as reflected below) | | 1,720,959 |
| | 1,684,435 |
| | 1,422,751 |
| Operating expenses (excluding depreciation and amortization expense as reflected below) | | 2,085.9 | | | 1,918.3 | | | 1,782.3 | |
| Depreciation and amortization expense | | 359,126 |
| | 277,992 |
| | 216,341 |
| Depreciation and amortization expense | | 453.5 | | | 551.7 | | | 425.3 | |
| Cost of sales | | 26,583,478 |
| | 20,826,048 |
| | 15,237,433 |
| Cost of sales | | 26,366.2 | | | 16,745.6 | | | 23,595.1 | |
| General and administrative expenses (excluding depreciation and amortization expense as reflected below) | | 276,955 |
| | 214,547 |
| | 166,319 |
| General and administrative expenses (excluding depreciation and amortization expense as reflected below) | | 247.3 | | | 248.5 | | | 284.0 | |
| Depreciation and amortization expense | | 10,634 |
| | 12,964 |
| | 5,835 |
| Depreciation and amortization expense | | 13.3 | | | 11.3 | | | 10.8 | |
| (Gain) loss on sale of assets | | (43,094 | ) | | 1,458 |
| | 11,374 |
| |
| Change in fair value of contingent consideration | | Change in fair value of contingent consideration | | 32.4 | | | (93.7) | | | (0.8) | |
| Impairment expense | | Impairment expense | | — | | | 98.8 | | | — | |
| Gain on sale of assets | | Gain on sale of assets | | (3.0) | | | (477.8) | | | (29.9) | |
| Total cost and expenses | | 26,827,973 |
| | 21,055,017 |
| | 15,420,961 |
| Total cost and expenses | | 26,656.2 | | | 16,532.7 | | | 23,859.2 | |
| | | | | | | | | | | | | |
| Income from operations | | 358,120 |
| | 731,620 |
| | 499,463 |
| |
| Income (loss) from operations | | Income (loss) from operations | | 597.2 | | | (1,416.8) | | | 649.0 | |
| | | | | | | | |
| Other income (expense): | | | | | | | Other income (expense): | |
| Interest expense, net | | Interest expense, net | | (317.5) | | | (258.2) | | | (159.6) | |
| Change in Tax Receivable Agreement liability | | 13,893 |
| | 250,922 |
| | 12,908 |
| Change in Tax Receivable Agreement liability | | (48.3) | | | 373.5 | | | — | |
| Change in fair value of catalyst leases | | 5,587 |
| | (2,247 | ) | | 1,422 |
| |
| Debt extinguishment costs | | — |
| | (25,451 | ) | | — |
| |
| Interest expense, net | | (169,911 | ) | | (154,427 | ) | | (150,045 | ) | |
| Change in fair value of catalyst obligations | | Change in fair value of catalyst obligations | | 8.5 | | | (11.8) | | | (9.7) | |
| Gain (loss) on extinguishment of debt | | Gain (loss) on extinguishment of debt | | 79.9 | | | (22.2) | | | — | |
| Other non-service components of net periodic benefit cost | | 1,109 |
| | (1,402 | ) | | (580 | ) | Other non-service components of net periodic benefit cost | | 7.8 | | | 4.3 | | | (0.2) | |
| Income before income taxes | | 208,798 |
| | 799,015 |
| | 363,168 |
| |
| Income (loss) before income taxes | | Income (loss) before income taxes | | 327.6 | | | (1,331.2) | | | 479.5 | |
| Income tax expense | | 33,507 |
| | 315,584 |
| | 137,650 |
| Income tax expense | | 12.1 | | | 2.1 | | | 104.3 | |
| Net income | | 175,291 |
| | 483,431 |
| | 225,518 |
| |
| Net income (loss) | | Net income (loss) | | 315.5 | | | (1,333.3) | | | 375.2 | |
| Less: net income attributable to noncontrolling interests | | 46,976 |
| | 67,914 |
| | 54,707 |
| Less: net income attributable to noncontrolling interests | | 84.5 | | | 59.1 | | | 55.8 | |
| Net income attributable to PBF Energy Inc. stockholders | | $ | 128,315 |
| | $ | 415,517 |
| | $ | 170,811 |
| |
| Net income (loss) attributable to PBF Energy Inc. stockholders | | Net income (loss) attributable to PBF Energy Inc. stockholders | | $ | 231.0 | | | $ | (1,392.4) | | | $ | 319.4 | |
| | | | | | | | | | | | | |
| Consolidated gross margin | | $ | 602,615 |
| | $ | 960,589 |
| | $ | 682,991 |
| Consolidated gross margin | | $ | 887.2 | | | $ | (1,629.7) | | | $ | 913.1 | |
| | | | | | | | |
Gross refining margin (1) | | $ | 2,419,389 |
| | $ | 2,676,651 |
| | $ | 2,143,449 |
| Gross refining margin (1) | | $ | 3,087.7 | | | $ | 496.8 | | | $ | 2,801.2 | |
| | | | | | | | |
| Net income available to Class A common stock per share: | | | | | | | Net income available to Class A common stock per share: | |
| Basic | | $ | 1.11 |
| | $ | 3.78 |
| | $ | 1.74 |
| Basic | | $ | 1.92 | | | $ | (11.64) | | | $ | 2.66 | |
| Diluted | | $ | 1.10 |
| | $ | 3.73 |
| | $ | 1.74 |
| Diluted | | $ | 1.90 | | | $ | (11.64) | | | $ | 2.64 | |
——————————
(1) See Non-GAAP Financial Measures below.
Measures.
| | | PBF LLC | | Year Ended December 31, | PBF LLC | | Year Ended December 31, |
| | | 2018 | | 2017 | | 2016 | | | 2021 | | 2020 | | 2019 |
| Revenues | | $ | 27,186,093 |
| | $ | 21,786,637 |
| | $ | 15,920,424 |
| Revenues | | $ | 27,253.4 | | | $ | 15,115.9 | | | $ | 24,508.2 | |
| | | | | | | | |
| Cost and expenses: | | | | | | | Cost and expenses: | |
| Cost of products and other | | 24,503,393 |
| | 18,863,621 |
| | 13,598,341 |
| Cost of products and other | | 23,826.8 | | | 14,275.6 | | | 21,387.5 | |
| Operating expenses (excluding depreciation and amortization expense as reflected below) | | 1,720,959 |
| | 1,684,435 |
| | 1,422,751 |
| Operating expenses (excluding depreciation and amortization expense as reflected below) | | 2,085.9 | | | 1,918.3 | | | 1,782.3 | |
| Depreciation and amortization expense | | 359,126 |
| | 277,992 |
| | 216,341 |
| Depreciation and amortization expense | | 453.5 | | | 551.7 | | | 425.3 | |
| Cost of sales | | 26,583,478 |
| | 20,826,048 |
| | 15,237,433 |
| Cost of sales | | 26,366.2 | | | 16,745.6 | | | 23,595.1 | |
| General and administrative expenses (excluding depreciation and amortization expense as reflected below) | | 275,205 |
| | 214,222 |
| | 166,119 |
| General and administrative expenses (excluding depreciation and amortization expense as reflected below) | | 245.2 | | | 247.7 | | | 282.3 | |
| Depreciation and amortization expense | | 10,634 |
| | 12,964 |
| | 5,835 |
| Depreciation and amortization expense | | 13.3 | | | 11.3 | | | 10.8 | |
| (Gain) loss on sale of assets | | (43,094 | ) | | 1,458 |
| | 11,374 |
| |
| Change in fair value of contingent consideration | | Change in fair value of contingent consideration | | 32.4 | | | (93.7) | | | (0.8) | |
| Impairment expense | | Impairment expense | | — | | | 98.8 | | | — | |
| Gain on sale of assets | | Gain on sale of assets | | (3.0) | | | (477.8) | | | (29.9) | |
| Total cost and expenses | | 26,826,223 |
| | 21,054,692 |
| | 15,420,761 |
| Total cost and expenses | | 26,654.1 | | | 16,531.9 | | | 23,857.5 | |
| | | | | | | | | | | | | |
| Income from operations | | 359,870 |
| | 731,945 |
| | 499,663 |
| |
| Income (loss) from operations | | Income (loss) from operations | | 599.3 | | | (1,416.0) | | | 650.7 | |
| | | | | | | | |
| Other income (expense): | | | | | | | Other income (expense): | |
| Change in fair value of catalyst leases | | 5,587 |
| | (2,247 | ) | | 1,422 |
| |
| Debt extinguishment costs | | — |
| | (25,451 | ) | | — |
| |
| Interest expense, net | | (178,421 | ) | | (162,383 | ) | | (155,819 | ) | Interest expense, net | | (327.8) | | | (268.5) | | | (169.1) | |
| Change in fair value of catalyst obligations | | Change in fair value of catalyst obligations | | 8.5 | | | (11.8) | | | (9.7) | |
| Gain (loss) on extinguishment of debt | | Gain (loss) on extinguishment of debt | | 79.9 | | | (22.2) | | | — | |
| Other non-service components of net periodic benefit cost | | 1,109 |
| | (1,402 | ) | | (580 | ) | Other non-service components of net periodic benefit cost | | 7.8 | | | 4.3 | | | (0.2) | |
| Income before income taxes | | 188,145 |
| | 540,462 |
| | 344,686 |
| |
| Income tax expense (benefit) | | 7,999 |
| | (10,783 | ) | | 23,689 |
| |
| Net income | | 180,146 |
| | 551,245 |
| | 320,997 |
| |
| Income (loss) before income taxes | | Income (loss) before income taxes | | 367.7 | | | (1,714.2) | | | 471.7 | |
| Income tax (benefit) expense | | Income tax (benefit) expense | | (14.0) | | | 6.1 | | | (8.3) | |
| Net income (loss) | | Net income (loss) | | 381.7 | | | (1,720.3) | | | 480.0 | |
| Less: net income attributable to noncontrolling interests | | 42,308 |
| | 51,168 |
| | 40,109 |
| Less: net income attributable to noncontrolling interests | | 82.1 | | | 76.2 | | | 51.5 | |
| Net income attributable to PBF Energy Company LLC | | $ | 137,838 |
| | $ | 500,077 |
| | $ | 280,888 |
| |
| Net income (loss) attributable to PBF Energy Company LLC | | Net income (loss) attributable to PBF Energy Company LLC | | $ | 299.6 | | | $ | (1,796.5) | | | $ | 428.5 | |
Operating Highlights
| | | | | Year Ended December 31, | | | Year Ended December 31, |
| | | 2018 | | 2017 | | 2016 | | | 2021 | | 2020 | | 2019 | |
| Key Operating Information | | | | | | | Key Operating Information | | | | | | | |
| Production (bpd in thousands) | | 854.5 |
| | 802.9 |
| | 734.3 |
| Production (bpd in thousands) | | 852.2 | | | 737.1 | | | 825.2 | | |
| Crude oil and feedstocks throughput (bpd in thousands) | | 849.7 |
| | 807.4 |
| | 727.7 |
| Crude oil and feedstocks throughput (bpd in thousands) | | 834.5 | | | 727.7 | | | 823.1 | | |
| Total crude oil and feedstocks throughput (millions of barrels) | | 310.0 |
| | 294.7 |
| | 266.4 |
| Total crude oil and feedstocks throughput (millions of barrels) | | 304.6 | | | 266.3 | | | 300.4 | | |
| Consolidated gross margin per barrel of throughput | | $ | 1.94 |
| | $ | 3.25 |
| | $ | 2.56 |
| Consolidated gross margin per barrel of throughput | | $ | 2.91 | | | $ | (6.12) | | | $ | 3.04 | | |
Gross refining margin, excluding special items, per barrel of throughput (1) | | $ | 9.09 |
| | $ | 8.08 |
| | $ | 6.09 |
| Gross refining margin, excluding special items, per barrel of throughput (1) | | $ | 7.94 | | | $ | 3.23 | | | $ | 8.51 | | |
| Refinery operating expense, per barrel of throughput | | $ | 5.34 |
| | $ | 5.52 |
| | $ | 5.22 |
| Refinery operating expense, per barrel of throughput | | $ | 6.56 | | | $ | 6.89 | | | $ | 5.61 | | |
| | | | | | | | | |
Crude and feedstocks (% of total throughput) (2) | | | | | | | Crude and feedstocks (% of total throughput) (2) | | |
| Heavy | | 36 | % | | 34 | % | | 26 | % | Heavy | | 34 | % | | 42 | % | | 32 | % | |
| Medium | | 30 | % | | 30 | % | | 37 | % | Medium | | 31 | % | | 26 | % | | 28 | % | |
| Light | | 21 | % | | 21 | % | | 25 | % | Light | | 18 | % | | 17 | % | | 26 | % | |
| Other feedstocks and blends | | 13 | % | | 15 | % | | 12 | % | Other feedstocks and blends | | 17 | % | | 15 | % | | 14 | % | |
| Total throughput | | 100 | % | | 100 | % | | 100 | % | Total throughput | | 100 | % | | 100 | % | | 100 | % | |
| | | | | | | | | | | | | | |
| Yield (% of total throughput) | | | | | | | Yield (% of total throughput) | | |
| Gasoline and gasoline blendstocks | | 50 | % | | 50 | % | | 50 | % | Gasoline and gasoline blendstocks | | 53 | % | | 51 | % | | 49 | % | |
| Distillates and distillate blendstocks | | 32 | % | | 30 | % | | 31 | % | Distillates and distillate blendstocks | | 30 | % | | 30 | % | | 32 | % | |
| Lubes | | 1 | % | | 1 | % | | 1 | % | Lubes | | 1 | % | | 1 | % | | 1 | % | |
| Chemicals | | 2 | % | | 2 | % | | 3 | % | Chemicals | | 2 | % | | 1 | % | | 2 | % | |
| Other | | 16 | % | | 16 | % | | 15 | % | Other | | 16 | % | | 18 | % | | 16 | % | |
| Total yield | | 101 | % | | 99 | % | | 100 | % | Total yield | | 102 | % | | 101 | % | | 100 | % | |
——————————
(1) See Non-GAAP Financial Measures below.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.
The table below summarizes certain market indicators relating to our operating results as reported by
Platts. |
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | (dollars per barrel, except as noted) |
| Dated Brent crude oil | | $ | 71.34 |
| | $ | 54.18 |
| | $ | 43.91 |
|
| West Texas Intermediate (WTI) crude oil | | $ | 65.20 |
| | $ | 50.79 |
| | $ | 43.34 |
|
| Light Louisiana Sweet (LLS) crude oil | | $ | 70.23 |
| | $ | 54.02 |
| | $ | 45.03 |
|
| Alaska North Slope (ANS) crude oil | | $ | 71.54 |
| | $ | 54.43 |
| | $ | 43.67 |
|
| Crack Spreads | | | | | | |
| Dated Brent (NYH) 2-1-1 | | $ | 13.17 |
| | $ | 14.74 |
| | $ | 13.49 |
|
| WTI (Chicago) 4-3-1 | | $ | 14.84 |
| | $ | 15.88 |
| | $ | 12.38 |
|
| LLS (Gulf Coast) 2-1-1 | | $ | 12.30 |
| | $ | 13.57 |
| | $ | 10.75 |
|
| ANS (West Coast) 4-3-1 | | $ | 15.48 |
| | $ | 17.43 |
| | $ | 16.46 |
|
| Crude Oil Differentials | | | | | | |
| Dated Brent (foreign) less WTI | | $ | 6.14 |
| | $ | 3.39 |
| | $ | 0.56 |
|
| Dated Brent less Maya (heavy, sour) | | $ | 8.70 |
| | $ | 7.16 |
| | $ | 7.36 |
|
| Dated Brent less WTS (sour) | | $ | 13.90 |
| | $ | 4.37 |
| | $ | 1.42 |
|
| Dated Brent less ASCI (sour) | | $ | 4.64 |
| | $ | 3.66 |
| | $ | 3.92 |
|
| WTI less WCS (heavy, sour) | | $ | 26.93 |
| | $ | 12.24 |
| | $ | 12.57 |
|
| WTI less Bakken (light, sweet) | | $ | 2.86 |
| | $ | (0.26 | ) | | $ | 1.32 |
|
| WTI less Syncrude (light, sweet) | | $ | 6.84 |
| | $ | (1.74 | ) | | $ | (2.01 | ) |
| WTI less LLS (light, sweet) | | $ | (5.03 | ) | | $ | (3.23 | ) | | $ | (1.69 | ) |
| WTI less ANS (light, sweet) | | $ | (6.34 | ) | | $ | (3.63 | ) | | $ | (0.33 | ) |
| Natural gas (dollars per MMBTU) | | $ | 3.07 |
| | $ | 3.02 |
| | $ | 2.55 |
|
2018 | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2021 | | 2020 | | 2019 |
| | (dollars per barrel, except as noted) |
| Dated Brent crude oil | | $ | 70.89 | | | $ | 41.62 | | | $ | 64.34 | |
| West Texas Intermediate (WTI) crude oil | | $ | 68.10 | | | $ | 39.25 | | | $ | 57.03 | |
| Light Louisiana Sweet (LLS) crude oil | | $ | 69.59 | | | $ | 41.13 | | | $ | 62.67 | |
| Alaska North Slope (ANS) crude oil | | $ | 70.56 | | | $ | 42.20 | | | $ | 65.00 | |
| Crack Spreads | | | | | | |
| Dated Brent (NYH) 2-1-1 | | $ | 16.84 | | | $ | 9.11 | | | $ | 12.68 | |
| WTI (Chicago) 4-3-1 | | $ | 16.34 | | | $ | 6.30 | | | $ | 15.25 | |
| LLS (Gulf Coast) 2-1-1 | | $ | 16.03 | | | $ | 7.59 | | | $ | 12.43 | |
| ANS (West Coast-LA) 4-3-1 | | $ | 20.10 | | | $ | 11.30 | | | $ | 18.46 | |
| ANS (West Coast-SF) 3-2-1 | | $ | 20.55 | | | $ | 9.99 | | | $ | 17.16 | |
| Crude Oil Differentials | | | | | | |
| Dated Brent (foreign) less WTI | | $ | 2.80 | | | $ | 2.37 | | | $ | 7.31 | |
| Dated Brent less Maya (heavy, sour) | | $ | 6.47 | | | $ | 5.37 | | | $ | 6.76 | |
| Dated Brent less WTS (sour) | | $ | 2.63 | | | $ | 2.33 | | | $ | 8.09 | |
| Dated Brent less ASCI (sour) | | $ | 3.90 | | | $ | 1.81 | | | $ | 3.73 | |
| WTI less WCS (heavy, sour) | | $ | 14.19 | | | $ | 10.72 | | | $ | 13.61 | |
| WTI less Bakken (light, sweet) | | $ | (0.14) | | | $ | 2.41 | | | $ | 0.66 | |
| WTI less Syncrude (light, sweet) | | $ | 2.25 | | | $ | 2.13 | | | $ | 0.18 | |
| WTI less LLS (light, sweet) | | $ | (1.50) | | | $ | (1.88) | | | $ | (5.64) | |
| WTI less ANS (light, sweet) | | $ | (2.46) | | | $ | (2.95) | | | $ | (7.97) | |
| Natural gas (dollars per MMBTU) | | $ | 3.73 | | | $ | 2.13 | | | $ | 2.53 | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
2021 Compared to 20172020
Overview— Net income for PBF Energy net income was $175.3$315.5 million for the year ended December 31, 20182021 compared to net incomeloss of $483.4$(1,333.3) million for the year ended December 31, 2017.2020. PBF LLC net income was $180.1$381.7 million for the year ended December 31, 20182021 compared to net incomeloss of $551.2$(1,720.3) million for the year ended December 31, 2017.2020. Net income attributable to PBF Energy stockholders was $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) compared to net incomeloss attributable to PBF Energy stockholders of $415.5$(1,392.4) million, or $3.73$(11.64) per diluted share, for the year ended December 31, 20172020 ($3.73(11.64) per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income,loss, or $1.14$(11.78) 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 98.3%99.2% and 96.6%99.1% for the years ended December 31, 20182021 and 2017,2020, respectively.
Our results for the year ended December 31, 20182021 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 contingent consideration related to the PBFX acquisition of the East Coast Storage Assets from Crown Point International, LLC (“Crown Point”) (the “East Coast Storage Assets Acquisition”) of $32.4 million, or $24.0 million net of tax. Our results for the year ended December 31, 2020 were positively impacted by special items consisting of a gain on the sale of hydrogen plants of $471.1 million, or $345.8 million net of tax, a pre-tax gain on the sale of land at our Torrance refinery of $8.1 million, or $5.9 million net of tax, a change in fair value of the Martinez Contingent Consideration and the contingent consideration associated with the East Coast Storage Asset Acquisition (the “PBFX Contingent Consideration”) of $93.7 million, or $68.8 million net of tax and a pre-tax change in the Tax Receivable Agreement liability of $373.5 million, or $274.1 million net of tax. Our results for the year ended December 31, 2020 were negatively impacted by special items consisting of a non-cash, pre-tax LCM inventory adjustment of approximately $351.3$268.0 million, or $259.9$196.7 million net of tax, and the early return of certain leased railcars, resulting in a pre-tax, charge of $52.3 million, or $38.7 million net of tax. These unfavorable impacts were partially offset by special items related to a pre-tax benefitdebt extinguishment costs associated with the change inearly redemption of the Tax Receivable Agreement liability2023 Senior Notes of $13.9$22.2 million, or $10.3$16.3 million net of tax, and a pre-tax gain on the Torrance land saleseverance costs related to reductions in workforce of $43.8$24.7 million, or $32.4 million net of tax. Our results for the year ended December 31, 2017 were positively impacted by special items consisting of a non-cash, pre-tax LCM inventory adjustment of approximately $295.5 million, or $178.5$18.1 million net of tax, and a pre-tax benefitimpairment expense of $250.9$98.8 million or $151.5$72.5 million net of tax, related to the change in our Tax Receivable Agreement liability. These favorable impacts were partially offset by special items related to pre-tax debt extinguishment costswrite-down of $25.5certain assets and project abandonments, early return of certain leased railcars of $12.5 million or $15.4$9.2 million net of tax, related to the redemptionaccelerated turnaround amortization costs of the 2020 Senior Secured Notes$56.2 million or $41.3 million net of tax, a LIFO inventory decrement of $83.0 million or $60.9 million net of tax, reconfiguration charges of $5.3 million or $3.9 million net of tax and the enactment$259.1 million of the TCJA resulting in a net tax expense of $20.2 million associated with the remeasurement of the Tax Receivable Agreement associatedcertain deferred tax assets and related reduction of our deferred tax liabilities.assets.
Excluding the impact of these special items, our results were positively impacted by favorable movementsincreases in crude differentials,the demand for our refined products and improved margins for refined product, which have positively impacted our revenues, cost of products sold and operating income. When comparing the results to the year ended December 31, 2020, demand for our products has started to recover, evidenced by higher throughput volumes and barrels sold across the majority of our refineries and reduced regulatory compliance costs, offset by lower crack spreads realized at the majority of ourthe refineries, which were favorably impacted in the prior year by the hurricane-related effect onas well as higher refining margins due to tightening product inventories, specifically distillates. Ourmargins. Additionally, our results for the year ended December 31, 20182021 were positively impacted by lower general and administrative expenses when compared to prior year. During the year ended December 31, 2020 our results were negatively impacted by higher general and administrative expenses associated with integration costs in connection with the Martinez Acquisition and increased depreciation andaccelerated amortization expense.costs associated with the East Coast Refining Reconfiguration.
Revenues— Revenues totaled $27.2$27.3 billion for the year ended December 31, 20182021 compared to $21.8$15.1 billion for the year ended December 31, 2017,2020, an increase of approximately $5.4$12.2 billion or 24.8%80.8%. Revenues per barrel sold were $77.08$80.79 and $64.90$49.43 for the years ended December 31, 20182021 and 2017,2020, respectively, an increase of 18.8%63.4% directly related to higher hydrocarbon commodity prices. 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. For the year ended December 31, 2017,2020, the total throughput rates at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 338,200263,000 bpd, 145,20096,700 bpd, 184,500137,700 bpd and 139,500230,300 bpd, respectively. The throughput rates at our East Coast, Mid-Continent and West Coast refineries were higher in the year ended December 31, 2018 compared to the same period in 2017. Throughput rates at our Gulf Coast refinery was in line with the prior year despite planned downtimes during the first half of 2018. The throughput rates at our East Coast refineries increased due to planned downtime at our Delaware City refinery during 2017, whereas our Mid-Continent refinery ran at modestly higher rates during the year, taking advantage of a relatively strong margin environment. The throughput rates at our West Coast refinery increased due to planned downtime in the prior year as part of the first significant turnaround of the refinery under our ownership and improved refinery performance experienced in the current year. For the year ended December 31, 2018,2021, the total refined product 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. For the year ended December 31, 2017,2020, the total refined product barrels sold at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 363,800296,200 bpd, 160,400114,500 bpd, 227,200159,700 bpd and 168,300265,200 bpd, respectively.
The throughput rates at our refineries were higher in the year ended December 31, 2021 compared to the same period in 2020, with the exception of lower rates in the East Coast as a result of the East Coast Refining Reconfiguration, which took place in the fourth quarter of 2020. We operated our refineries at reduced rates beginning in March 2020, and increased throughput rates across our entire refining system to correlate with the gradual increases in demand experienced during the year ended December 31, 2021, while still running below historic levels. We plan on continuing to operate our refineries at lower utilization levels until such time that sustained product demand justifies higher production. 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 $602.6$887.2 million for the year ended December 31, 2018,2021, compared to $960.6$(1,629.7) million for the year ended December 31, 2017, a decrease2020, an increase of $358.0$2,516.9 million. Gross refining margin (as described below in Non-GAAP Financial Measures) totaled $2,419.4$3,087.7 million, or $7.79$10.14 per barrel of throughput, for the year ended December 31, 20182021 compared to $2,676.7$496.8 million, or $9.08$1.86 per barrel of throughput, for the year ended December 31, 2017, a decrease2020, an increase of approximately $257.3$2,590.9 million. Gross refining margin excluding special items totaled $2,823.0$2,418.1 million, or $9.09$7.94 per barrel of throughput, for the year ended December 31, 20182021 compared to $2,381.1$860.3 million, or $8.08$3.23 per barrel of throughput, for the year ended December 31, 2017,2020, an increase of $441.9$1,557.8 million.
Consolidated gross margin and gross refining margin were negativelypositively impacted by a non-cash LCM adjustment of $669.6 million on a net basis resulting from the increase in crude oil and refined product prices from the current year byended December 31, 2020 to the year ended December 31, 2021. Gross refining margin, excluding the impact of special items.items, increased due to favorable movements in certain crude differentials and an overall increase in throughput rates and refining margins. For the year ended December 31, 2018,2020, special items impacting our margin calculations included aan unfavorable non-cash LCM inventory adjustment of approximately $351.3$268.0 million on a net basis, resulting from a decrease in crude oil and refined product prices in comparisonfrom the year ended December 31, 2019, a LIFO inventory decrement charge of $83.0 million mainly related to our East Coast LIFO inventory layer and the prices atreduction to our East Coast inventory experienced as part of the end of 2017East Coast Refining Reconfiguration, and a $52.3 million charge resulting from costs associated with the early return of certain leased railcars. The non-cash LCM inventory adjustment increased consolidated gross margin and gross refining margin by approximately $295.5 million in the year ended December 31, 2017. Excluding the impactrailcars of special items, consolidated gross margin and gross refining margin increased due to generally favorable movements in crude differentials and higher throughput volumes and barrels sold across all of our refineries.$12.5 million.
Additionally, our results continue to be impacted by significant costs to comply with RFS, although at a reduced level from the prior year.Renewable Fuel Standard. Total RFSRenewable Fuel Standard costs were $143.9$726.0 million for the year ended December 31, 20182021 in comparison to $293.7$326.4 million for the year ended December 31, 2017.2020.
Average industry margins were weakermostly favorable during the year ended December 31, 2018 in comparison to2021 compared with the prior year, primarily as a result of 2017 being favorably impacted by the hurricane-related effect on refining margins in the second halfdue to varying timing and extent of the year due to tightening product inventories, specifically distillates. Crude oil differentials were generally favorable in comparison toimpacts of the prior year, with beneficial differentials experienced across the East CoastCOVID-19 pandemic on regional demand and Mid-Continent, partially offset by marginally unfavorable impacts related to our refinery specific crude slate in the Gulf and West Coast.
On the East Coast, the Dated Brent (NYH) 2-1-1 industry crack spread was approximately $13.17 per barrel, or 10.7% lower, incommodity prices. For the year ended December 31, 2018, as compared to $14.74 per barrel2021, we experienced an increase in demand for our products in connection with the same period in 2017. Our margins were positively impacted from our refinery specific slate onlifting or easing of restrictions by many governmental authorities and the East Coast by an improving Dated Brent/WTI differential, which increased $2.75 per barrel in comparison to the prior yeardistribution of COVID-19 vaccines and increases in the Dated Brent/Maya and WTI/Bakken differentials, which increased $1.54 per barrel and $3.12 per barrel, respectively, in comparison to the prior
year. In addition, the WTI/WCS differential widened significantly to $26.93 per barrel in 2018 compared to $12.24 in 2017, which favorably impacted our cost of heavy Canadian crude.
Across the Mid-Continent, the WTI (Chicago) 4-3-1 industry crack spread was $14.84 per barrel, or 6.5% lower, in the year ended December 31, 2018, as compared to $15.88 per barrel in the same period in 2017. Our margins were positively impacted from our refinery specific slate in the Mid-Continent by an improving WTI/Bakken differential, which was approximately $2.86 per barrel in the year ended December 31, 2018, as compared to a premium of $0.26 per barrel in the same period in 2017. Additionally, the WTI/Syncrude differential averaged a discount of $6.84 per barrel for the year ended December 31, 2018 as compared to a premium of $1.74 per barrel in the same period in 2017.
In the Gulf Coast, the LLS (Gulf Coast) 2-1-1 industry crack spread was $12.30 per barrel, or 9.4% lower, in the year ended December 31, 2018 as compared to $13.57 per barrel in the same period in 2017. Margins in the Gulf Coast were negatively impacted from our refinery specific slate by a declining WTI/LLS differential, which averaged a premium of $5.03 for the year ended December 31, 2018 as compared to an average premium of $3.23 experienced in the prior year.
On the West Coast, the ANS (West Coast) 4-3-1 industry crack spread was $15.48 per barrel, or 11.2% lower, in the year ended December 31, 2018 as compared to $17.43 per barrel in the same period in 2017. Margins on the West Coast were negatively impacted from our refinery specific slate by a declining WTI/ANS differential, which averaged a premium of $6.34 for the year ended December 31, 2018 as compared to an average premium of $3.63 experienced in the prior year.other protective measures.
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 $16.84 per barrel, or 84.9% higher, in the year ended December 31, 2021, as compared to $9.11 per barrel in the same period in 2020. Our margins were positively impacted from our refinery specific slate on the East Coast by strengthened Dated Brent/Maya differential, which increased by $1.10 per barrel, offset by weakened WTI/Bakken differential, which decreased by $2.55 per barrel in comparison to the same period in 2020. The WTI/WCS differential increased to $14.19 per barrel in 2021 compared to $10.72 per barrel in 2020, which favorably impacted our cost of heavy Canadian crude.
Across the Mid-Continent, the WTI (Chicago) 4-3-1 industry crack spread was $16.34 per barrel, or 159.4% higher, in the year ended December 31, 2021, as compared to $6.30 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 $0.14 per barrel in the year ended December 31, 2021, as compared to a discount of $2.41 per barrel in the prior year. This decrease was slightly offset by strengthening WTI/Syncrude differential which averaged $2.25 per barrel for the year ended December 31, 2021 as compared to $2.13 per barrel in the prior year.
On the Gulf Coast, the LLS (Gulf Coast) 2-1-1 industry crack spread was $16.03 per barrel, or 111.2% higher, in the year ended December 31, 2021 as compared to $7.59 per barrel in the prior year. Margins on the Gulf Coast were positively impacted from our refinery specific slate by a strengthening WTI/LLS differential, which averaged a premium of $1.50 per barrel for the year ended December 31, 2021 as compared to a premium of $1.88 per barrel in the prior year.
On the West Coast, the ANS (West Coast) 4-3-1 industry crack spread was $20.10 per barrel, or 77.9% higher, in the year ended December 31, 2021 as compared to $11.30 per barrel in the prior year. Additionally, the ANS (West Coast) 3-2-1 industry crack spread was $20.55 per barrel, or 105.7% higher, in the year ended December 31, 2021 as compared to $9.99 per barrel in the prior year. Our margins on the West Coast were positively impacted from our refinery specific slate by a strengthening WTI/ANS differential, which averaged a premium of $2.46 per barrel for the year ended December 31, 2021 as compared to a premium of $2.95 per barrel in the prior year.
Operating Expenses— Operating expenses totaled $1,721.0$2,085.9 million for the year ended December 31, 20182021 compared to $1,684.4$1,918.3 million for the year ended December 31, 2017, an2020, increase of approximately $36.5$167.6 million, or 2.2%8.7%. Of the total $1,721.0$2,085.9 million of operating expenses for the year ended December 31, 2018, $1,654.72021, $1,999.1 million, or $5.34$6.56 per barrel of throughput, related to expenses incurred by the Refining segment, while the remaining approximately $66.2$86.8 million related to expenses incurred by the Logistics segment ($1,626.41,835.2 million or $5.52$6.89 per barrel of throughput, and $58.0$83.1 million of operating expenses for the year ended December 31, 20172020 related to the Refining and Logistics segment,segments, respectively). DecreasesIncreases in operating expenses on a per barrel basis were driven bymainly attributable to increases in natural gas volumes and price across our refineries when compared to the year ended December 31, 2020. Additionally, we experienced higher maintenance and operational costs due to increased system reliability and our focused efforts on reducing operating costs. The increase in operating expenses overall in comparisonproduction when compared to the prior year was mainly attributable to higher energy and utility costsyear. These increases were partially offset by cost-savings realized in 2021 as a result of higher natural gas pricingthe East Coast Refining Reconfiguration (East Coast operating expenses decreased by $18.7 million when compared to 2020) as well as reductions in discretionary activities and overall increased throughput. This increase was slightly offset by a decreasethird-party services, which are in supplies and materials dueline with our cost reduction initiatives taken to strengthen our Torrance refinery experiencing higher costs in 2017 related to its turnaround. Operating expenses related to our Logistics segment were generally consistent with the prior year and consist of costs related to the operation and maintenance of PBFX’s assets.financial flexibility.
General and Administrative Expenses— General and administrative expenses totaled $277.0$247.3 million for the year ended December 31, 2018,2021, compared to $214.5$248.5 million for the year ended December 31, 2017, an increase2020, a decrease of $62.4$1.2 million or 29.1%0.5%. The increaseslight decrease in general and administrative expenses for the year ended December 31, 20182021 in comparison to the year ended December 31, 20172020 primarily related to higher employee-related expenses, including incentive compensationreductions in outside service costs offset by increases in salaries, wages and retirement benefits.benefits and other fixed expenses. Our general and administrative expenses are comprised of the personnel, facilities and other infrastructure costs necessary to support our refineries and related logisticallogistics assets.
(Gain) Loss on Sale of AssetsDepreciation and Amortization Expense— There was a net gain of $43.1Depreciation and amortization expense totaled $466.8 million for the year ended December 31, 2018 mainly attributable to a $43.8 million gain related to the Torrance land sale. There was a loss of $1.5 million for the year ended December 31, 2017 relating to the sale of non-operating refining assets.
Depreciation and Amortization Expense— Depreciation and amortization expense totaled $369.8 million for the year ended December 31, 20182021 (including $359.1$453.5 million recorded within Cost of sales) compared to $291.0$563.0 million for the year ended December 31, 20172020 (including $278.0$551.7 million recorded within Cost of sales), an increasea decrease of $78.8$96.2 million. The increasedecrease was a result of additionalreduced depreciation and amortization expense associated with certain units temporarily idled as a general increaseresult of the East Coast Refining Reconfiguration.
Change in Fair Value of Contingent Consideration— Change in fair value of contingent consideration represented a loss of $32.4 million and a gain of $93.7 million for the years ended December 31, 2021 and December 31, 2020, respectively. These losses and gains were related to the changes in estimated fair value of the Martinez Contingent Consideration and the PBFX Contingent Consideration, both associated with acquisition related earn-out obligations.
Impairment expense— There was no impairment expense for the year ended December 31, 2021. Impairment expense totaled $98.8 million for the year ended December 31, 2020, and was associated with the write-down of certain assets as a result of the East Coast Refining Reconfiguration, other refinery wide project abandonments and the write-down of certain PBFX long-lived assets.
Gain on Sale of 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. There was a gain of $477.8 million for the year ended December 31, 2020 related primarily to the sale of five hydrogen plants and the sale of a parcel of land at our fixed asset base due to capital projects and turnarounds completed during 2018 and 2017, which included the first significant Torrance refinery turnaround under our ownership.refinery.
Change in Tax Receivable Agreement Liability—Change in the Tax Receivable Agreement liability for the year ended December 31, 20182021, represented a loss of $48.3 million. Change in the Tax Receivable Agreement liability for the year ended December 31, 2020, represented a gain of $13.9 million compared$373.5 million. These losses and gains were primarily the result of a deferred tax asset valuation allowance recorded in accordance with 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 and based on future taxable income.
Change in Fair Value of Catalyst Obligations— Change in fair value of catalyst obligations represented a gain of $250.9$8.5 million for the year ended December 31, 2017.
Change in Fair Value2021, compared to a loss of Catalyst Leases— Change in the fair value of catalyst leases represented a gain of $5.6$11.8 million for the year ended December 31, 2018, compared to a loss of $2.2 million for the year ended December 31, 2017.
2020. These gains and losses relate to the change in value of the precious metals underlying the sale and leaseback of our refineries’ precious metal catalysts, which we are obligated to return or repurchase at fair market value upon lease termination.
Gain (loss) on the lease termination dates.
Debt extinguishment costs— Debtof debt— We incurred a gain on extinguishment costs of $25.5debt of $79.9 million incurred for the year ended December 31, 2017 relate to nonrecurring charges associated with debt refinancing activity calculated based on the difference between the carrying value of the 2020 Senior Secured Notes on the date that they were reacquired and the amount for which they were reacquired. There were no such costs incurred in the year ended December 31, 2018.2021 related to the repurchase of a portion of our 2028 Senior Notes and 2025 Senior Notes. We incurred debt extinguishment costs of $22.2 million in the year ended December 31, 2020 related to the redemption of our 2023 Senior Notes.
Interest Expense, net— PBF Energy interest expense totaled $169.9$317.5 million for the year ended December 31, 2018,2021, compared to $154.4$258.2 million for the year ended December 31, 2017,2020, an increase of $15.5$59.3 million. This net increase is mainly attributable to thehigher interest costs associated with the issuance of the new PBFX 20232025 Senior Secured Notes in May 2020 and December 2020, partially offset by lower interest expense associated with the repurchase of a portion of the 2028 Senior Notes in October 2017 and higher borrowings under the PBFX Revolving Credit Facility.2025 Senior Notes. Interest expense includes interest on long-term debt including the PBFX credit facilities, costs related to the sale and leaseback of our precious metals catalyst,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 and the amortization of discounted liabilities.costs. PBF LLC interest expense totaled $178.4$327.8 million and $162.4$268.5 million for the year ended December 31, 20182021 and December 31, 2017,2020, respectively (inclusive of $8.5 million and $8.0$10.3 million, respectively, of incremental interest expense on the affiliate note payable with PBF Energy that eliminates in consolidation)consolidation at the PBF Energy level).
Income Tax Expense— PBF LLC is organized as a limited liability company and PBFX is an MLP, 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 98.3%99.2% and 96.6%99.1%, on a weighted-average basis for the years ended December 31, 20182021 and 2017,2020, respectively. PBF Energy’s consolidated financial statementsConsolidated 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, 20182021 and 20172020 was 16.0%3.7% and 39.5%0.2%, respectively, reflecting discrete tax items primarily related to return to provision adjustments pertaining to equity compensation and the impact of the TCJA which, among other things, reduced the U.S federal corporaterespectively. The effective tax rate from 35%for the year ended December 31, 2021 was significantly impacted by the change in deferred tax valuation allowance, which resulted in a tax benefit of $49.9 million for the year ended December 31, 2021, compared to 21%.a charge of $358.4 million for the year ended December 31, 2020.
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 records 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 records a noncontrolling interest for the economic interests in PBFX held by the public unitholders of PBFX, and with respect to the consolidation of PBF Holding, the Company records 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 statementsConsolidated Statements of operationsOperations 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 and by the third-party stockholderstockholders of certain of Chalmette Refining’s subsidiaries. The total noncontrolling interest on the consolidated balance sheetConsolidated 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, 20182021 and 20172020 was approximately 1.7%0.8% and 3.4%0.9%, respectively. The carrying amount of the noncontrolling interest on our consolidated balance sheetConsolidated 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.
2020 Compared to 20162019
Overview— PBF Energy net incomeloss was $483.4$(1,333.3) million for the year ended December 31, 20172020 compared to net income of $225.5$375.2 million for the year ended December 31, 2016.2019. PBF LLC net incomeloss was $551.2$(1,720.3) million for the year ended December 31, 20172020 compared to net income of $321.0$480.0 million for the year ended December 31, 2016.2019. Net incomeloss attributable to PBF Energy stockholders was $415.5$(1,392.4) million, or $3.73$(11.64) per diluted share, for the year ended December 31, 20172020 ($3.73(11.64) per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income,loss, or net income of $1.14 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 $170.8 million, or $1.74 per diluted share, for the year ended December 31, 2016 ($1.74 per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income, or a net loss of $1.41$(11.78) per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net loss excluding special items, as described below in Non-GAAP Financial Measures) compared to net income attributable to PBF Energy stockholders of $319.4 million, or $2.64 per diluted share, for the year ended December 31, 2019 ($2.64 per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income, or $0.90 per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income excluding special items, as described below in Non-GAAP Financial Measures). The net income or loss attributable to PBF Energy stockholders represents PBF Energy’s equity interest in PBF LLC’s pre-tax income, (loss), less applicable income tax expense. PBF Energy’s weighted-average equity interest in PBF LLC was 96.6%99.1% and 95.3%99.0% for the years ended December 31, 20172020 and 2016,2019, respectively.
Our results for the year ended December 31, 2017 were positively impacted by special items including a non-cash pre-tax LCM inventory adjustment of approximately $295.5 million, or $178.5 million net of tax, and a pre-tax benefit of $250.9 million, or $151.5 million net of tax, related to the change in PBF Energy Tax Receivable Agreement liability. Our results for the year ended December 31, 20162020 were positively impacted by special items consisting of a pre-tax LCM inventory adjustmentgain on the sale of approximately $521.3hydrogen plants of $471.1 million, or $317.7$345.8 million net of tax, a pre-tax gain on the sale of land at our Torrance refinery of $8.1 million, or $5.9 million net of tax, a change in fair value of both the Martinez Contingent Consideration and the PBFX Contingent Consideration of $93.7 million, or $68.8 million net of tax and a pre-tax benefitchange in the Tax Receivable Agreement liability of $12.9$373.5 million, or $7.8$274.1 million net of tax related to the change in PBF Energy Tax Receivable Agreement liability.tax. Our results for the year ended December 31, 20172020 were alsonegatively impacted by special items related toconsisting of a non-cash, pre-tax LCM inventory adjustment of approximately $268.0 million, or $196.7 million net of tax, pre-tax, debt extinguishment costs associated with the early redemption of $25.5the 2023 Senior Notes of $22.2 million, or $15.4$16.3 million net of tax, severance costs related to reductions in workforce of $24.7 million, or $18.1 million net of tax, impairment expense of $98.8 million or $72.5 million net of tax, related to the redemptionwrite-down of the 2020 Senior Secured Notescertain assets and the enactmentproject abandonments, early return of the TCJA resulting incertain leased railcars of $12.5 million or $9.2 million net of tax, accelerated turnaround amortization costs of $56.2 million or $41.3 million net of tax, a LIFO inventory decrement of $83.0 million or $60.9 million net of tax, reconfiguration charges of $5.3 million or $3.9 million net of tax and $259.1 million of tax expense of $193.5 million associated with the remeasurement of Tax Receivable Agreement associatedcertain deferred tax assetsassets. Our results for the year ended December 31, 2019 were positively impacted by special items consisting 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 tax benefit of $173.3 million fortax. The LCM inventory adjustments were recorded due to movements in the reductionprice of our deferred tax liabilities.crude oil and refined products in the periods presented.
Excluding the impact of these special items, our results were positively impacted by higher throughput volumes at the majority of our refineries and higher crack spreads realized at each of our refineries, which werenegatively impacted by the hurricane-related reduction in refining throughputCOVID-19 pandemic which caused a significant decline in the Gulf Coast regiondemand for our refined products and tightening product inventories, specifically distillates,a decrease in the second halfprices for crude oil and refined products, both of which negatively impacted our revenues, cost of products sold and operating income. In addition, during the year ended December 31, 2020 we experienced unfavorable movements in certain crude differentials and overall lower throughput volumes and barrels sold across our refineries, as well as lower refining margins. All our operating regions experienced lower refining margins for the year ended December 31, 2020 compared to the prior year. Our results for the year ended December 31, 2020 were negatively impacted by higher general and administrative expenses associated with integration costs to complyassociated with the RFS. Notably, we benefited fromMartinez Acquisition and increased depreciation and amortization expense associated with the improved operating performance of our ChalmetteMartinez Acquisition and Torrance refineries.accelerated amortization costs associated with the East Coast Refining Reconfiguration.
Revenues— Revenues totaled $21.8$15.1 billion for the year ended December 31, 20172020 compared to $15.9$24.5 billion for the year ended December 31, 2016, an increase2019, a decrease of approximately $5.9$9.4 billion, or 36.8%38.4%. Revenues per barrel sold were $64.90$49.43 and $59.77$69.93 for the years ended December 31, 20172020 and 2016,2019, respectively, an increasea decrease of 8.6%29.3% directly related to higherlower hydrocarbon commodity prices. For the year ended December 31, 2017,2020, the total throughput rates at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 338,200263,000 bpd, 145,20096,700 bpd, 184,500137,700 bpd and 139,500230,300 bpd, respectively. For the year ended December 31, 2016,2019, the total throughput rates at our East Coast, Mid-Continent, Gulf Coast and GulfWest Coast refineries averaged approximately 327,000336,400 bpd, 159,100153,000 bpd, 177,900 bpd and 169,300155,800 bpd, respectively. For the period from its acquisition on July 1, 2016 through December 31, 2016, our West Coast refinery’s throughput averaged 143,900 bpd. The throughput rates at our East Coast and Gulf Coast refineries were higher in 2017 compared to 2016. Our West Coast refinery was not acquired until the beginning of the third quarter of 2016. The decrease in throughput rates at our West Coast refinery in 2017 compared to 2016 is primarily due to planned downtime at our Torrance refinery for its first significant turnaround under our ownership, which was completed early in the third quarter of 2017. However, our West Coast refinery throughput averaged 164,000 bpd for the last six months of the year upon completion of the turnaround. For the year ended December 31, 2017,2020, the total refined product barrels sold at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 363,800296,200 bpd, 160,400114,500 bpd, 227,200159,700 bpd and 168,300265,200 bpd, respectively. For the year ended December 31, 2016,2019, the total refined product barrels sold at our East Coast, Mid-Continent, Gulf Coast and GulfWest Coast refineries averaged approximately 364,100382,500 bpd, 171,800163,900 bpd, 225,300 bpd and 206,400188,600 bpd, respectively. For
The throughput rates at our refineries were lower in the period from its acquisition on July 1, 2016 throughyear ended December 31, 2016,2020 compared to the total refined product barrels sold at oursame period in 2019. Our Martinez refinery was not acquired until the first quarter of 2020 and is therefore not included in 2019 West Coast refinery averaged 179,200 bpd.throughput. We operated our refineries at reduced rates beginning in March 2020, and, based on market conditions, we continued to operate our refineries at lower utilization. Total refined product barrels sold were higher than throughput rates, reflecting sales from inventory, as well as sales and purchases of refined products outside the refineries.our refineries.
Consolidated Gross Margin— Consolidated gross margin totaled $960.6$(1,629.7) million for the year ended December 31, 2017,2020, compared to $683.0$913.1 million for the year ended December 31, 2016, an increase2019, a decrease of $277.6$2,542.8 million. Gross refining margin (as defineddescribed below in Non-GAAP Financial Measures) totaled $2,676.7$496.8 million, or $9.08$1.86 per barrel of throughput, ($2,381.1 million or $8.08 per barrel of throughput excluding the impact of special items), for the year ended December 31, 20172020 compared to $2,143.4$2,801.2 million, or $8.05$9.34 per barrel of throughput, ($1,622.1 million or $6.09 per barrel of throughput
excluding the impact of special items), for the year ended December 31, 2016, an increase2019, a decrease of approximately $533.2$2,304.4 million. Gross refining margin excluding special items totaled $860.3 million, or an increase$3.23 per barrel of approximately $759.0throughput for the year ended December 31, 2020 compared to $2,551.0 million excluding special items.or $8.51 per barrel of throughput, for the year ended December 31, 2019, a decrease of $1,690.7 million.
Consolidated gross margin and gross refining margin increased due to improved crack spreads across each of our refineries, reduced costs to comply with the RFS and positive margin contributions from our Torrance refinery following its first significant turnaround under our ownership, which was completed earlywere negatively impacted in the third quarter of 2017. Costs to comply with our obligation under the RFS totaled $255.2 million for the year ended December 31, 2017 (excluding our West Coast refinery, whose cost to comply with RFS totaled $38.5 million for the year ended December 31, 2017) compared to $325.3 million for the year ended December 31, 2016 (excluding our West Coast refinery, whose costs to comply with RFS totaled $22.2 million for the year ended December 31, 2016). In addition, gross margin and gross refining margin were positively impacted2020 by a non-cash LCM inventory adjustment of approximately $295.5$268.0 million on a net basis, resulting from the decrease in crude oil and refined product prices from the year ended 2019, a LIFO inventory decrement charge of $83.0 million mainly 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, and early return of certain leased railcars of $12.5 million. Gross refining margin, excluding the impact of special items, decreased due to unfavorable movements in certain crude differentials and an overall decrease in throughput rates. For the year ended December 31, 2019, special items impacting our margin calculations included a favorable non-cash LCM inventory adjustment of approximately $250.2 million on a net basis, resulting from an increase in crude oil and refined product prices in comparison to the prices at the end of 2016. The non-cash LCM inventory adjustment increased consolidated gross margin and gross refining margin by approximately $521.3 million infrom the year ended December 31, 2016.2018.
Additionally, our results continue to be impacted by significant costs to comply with the Renewable Fuel Standard. Total Renewable Fuel Standard costs were $326.4 million for the year ended December 31, 2020 in comparison to $122.7 million for the year ended December 31, 2019.
Average industry refining margins in the Mid-Continent were strongermixed during the year ended December 31, 2017, as2020 compared to the same period in 2016. The WTI (Chicago) 4-3-1 industry crack spread was $15.88 per barrel or 28.3% higher, inwith the year ended December 31, 2017, as compared2019, primarily due to $12.38 per barrelthe impacts of the COVID-19 pandemic on regional demand and commodity prices in 2020, in addition to impacts related to 2019 planned turnarounds, all of which were completed in the same period in 2016. Our margins were unfavorably impacted by our refinery specific crude slate in the Mid-Continent which was impacted by a declining WTI/Bakken differential partially offset by an improving WTI/Syncrude differential, which averaged a premiumfirst half of $1.74 per barrel for the year ended December 31, 2017 as compared to a premium of $2.01 per barrel in the same period in 2016.
On the East Coast, the Dated Brent (NYH) 2-1-1 industry crack spread was approximately $14.74 per barrel, or 9.3% higher, in the year ended December 31, 2017 as compared to $13.49 per barrel in the same period in 2016. The Dated Brent/WTI differential was $2.83 higher in the year ended December 31, 2017, as compared to the same period in 2016, partially offset by year over year decreases in the Dated Brent/Maya differential and WTI/Bakken differential of $0.20 and $1.58, respectively.
Gulf Coast industry refining margins improved during the year ended December 31, 2017 as compared to the same period in 2016. The LLS (Gulf Coast) 2-1-1 industry crack spread was $13.57 per barrel, or 26.2% higher, in the year ended December 31, 2017 as compared to $10.75 per barrel in the same period in 2016. Crude differentials weakened with the WTI/LLS differential averaging a premium of $3.23 per barrel during the year ended December 31, 2017 as compared to a premium of $1.69 per barrel in the same period of 2016.
Additionally, we benefited from improvements in the West Coast industry refining margins during the year ended December 31, 2017 as compared to the same period in 2016. The ANS (West Coast) 4-3-1 industry crack spread was $17.43 per barrel, or 5.9% higher, in the year ended December 31, 2017 as compared to $16.46 per barrel in the same period in 2016. Partially offsetting the improved crack spreads, crude differentials weakened with the WTI/ANS differential averaging a premium of $3.63 per barrel during the year ended December 31, 2017 as compared to a premium of $0.33 per barrel in the same period of 2016. As the Torrance refinery was not acquired until the beginning of the third quarter of 2016, we did not benefit from the contribution of this refinery for the full twelve months of the prior year.2019.
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 $9.11 per barrel, or 28.2% lower, in the year ended December 31, 2020, as compared to $12.68 per barrel in the same period in 2019. Our margins were negatively impacted from our refinery specific slate on the East Coast by weakened Dated Brent/Maya differential, which decreased by $1.39 per barrel, in comparison to the same period in 2019. Additionally, WTI/WCS differential decreased to $10.72 per barrel in 2020 compared to $13.61 per barrel in 2019, which unfavorably impacted our cost of heavy Canadian crude. The WTI/Bakken differentials increased by $1.75 per barrel when compared to 2019.
Across the Mid-Continent, the WTI (Chicago) 4-3-1 industry crack spread was $6.30 per barrel, or 58.7% lower, in the year ended December 31, 2020, as compared to $15.25 per barrel in 2019. Our margins were positively impacted from our refinery specific slate in the Mid-Continent by an increasing WTI/Bakken differential, which averaged $2.41 per barrel in the year ended December 31, 2020, as compared to $0.66 per barrel in 2019. Additionally, the WTI/Syncrude differential averaged $2.13 per barrel for the year ended December 31, 2020 as compared to $0.18 per barrel in 2019.
On the Gulf Coast, the LLS (Gulf Coast) 2-1-1 industry crack spread was $7.59 per barrel, or 38.9% lower, in the year ended December 31, 2020 as compared to $12.43 per barrel in 2019. Margins on the Gulf Coast were positively impacted from our refinery specific slate by a strengthening WTI/LLS differential, which averaged a premium of $1.88 per barrel for the year ended December 31, 2020 as compared to a premium of $5.64 per barrel in 2019.
On the West Coast, the ANS (West Coast) 4-3-1 industry crack spread was $11.30 per barrel, or 38.8% lower, in the year ended December 31, 2020 as compared to $18.46 per barrel in 2019. Additionally, margins on the West Coast were positively impacted from our refinery specific slate by a strengthening WTI/ANS differential, which averaged a premium of $2.95 per barrel for the year ended December 31, 2020 as compared to a premium of $7.97 per barrel in 2019.
Operating Expenses— Operating expenses totaled $1,684.4$1,918.3 million for the year ended December 31, 20172020 compared to $1,422.8$1,782.3 million for the year ended December 31, 2016,2019, an increase of $261.7approximately $136.0 million, or 18.4%7.6%. Of the total $1,684.4$1,918.3 million of operating expenses approximately $1,626.4for the year ended December 31, 2020, $1,835.2 million, or $5.52$6.89 per barrel of throughput, related to expenses incurred by the Refining segment, while the remaining $58.0$83.1 million related to expenses incurred by the Logistics segment ($1,390.11,684.3 million or $5.22$5.61 per barrel of throughput, and $32.6$98.0 million of operating expenses for the year ended December 31, 20162019 related to the Refining and Logistics segmentsegments, respectively). The increaseIncreases in operating expenses was mainly attributablewere due to the operating expensescosts associated with our Torrancethe Martinez refinery and related logistics assets which were included in our results for the year ended December 31, 2017 as compared with only six months of 2016. For the year ended December 31, 2017 the Torrance refinery and related logistics assets incurred operating expenses oftotaled approximately $475.9 million in comparison to $250.5 million for the period from its acquisition on July 1, 2016 to December 31, 2016. Total operating expenses at our refineries, excluding our Torrance refinery, increased slightly for the year ended December 31, 2017, primarily due to higher energy costs and maintenance costs. The increase in energy costs was mainly due to higher natural gas prices while the increase in maintenance costs was mainly due to timing of repairs. The operating expenses related to the Logistics segment consists of costs related to the operation and maintenance of PBFX’s assets, which were higher
primarily as a result of current period expenses related to certain assets including the Toledo Products Terminal and Torrance Valley Pipeline, which were not in service for the full comparable period in 2016, and higher operating expenses associated with the East Coast Terminals.
General and Administrative Expenses— General and administrative expenses totaled $214.5$356.1 million for the year ended December 31, 2017, compared2020. Total operating expenses for the year ended December 31, 2020 excluding our Martinez refinery, decreased due to $166.3our cost reduction initiatives taken to strengthen our financial flexibility and offset the negative impact of COVID-19, such as significant reductions in discretionary activities and third-party services. Operating expenses related to our Logistics segment decreased as a result of lower discretionary spending, including maintenance and outside service costs, in response to the COVID-19 pandemic, as well as lower environmental clean-up remediation costs and lower utility expenses due to reduced energy usage.
General and Administrative Expenses— General and administrative expenses totaled $248.5 million for the year ended December 31, 2016, an increase2020, compared to $284.0 million for the year ended December 31, 2019, a decrease of $48.2$35.5 million or 29.0%12.5%. The increasedecrease in general and administrative expenses primarily relates to increased employee related expenses of $58.2 million driven by higher incentive compensation costs infor the year ended December 31, 2017 as compared2020 in comparison to the same period in 2016, attributable to higher average employee headcount and better operating performance. These increases were partially offset by lower costs associated with acquisition and integration related activities which were approximately $8.6 million lower in the year ended December 31, 20172019 primarily related to reduction in our workforce as compareda result of the East Coast Refining Reconfiguration and reduction in overhead expenses through temporary salary reductions for a large portion of our workforce. These cost decreases were offset by headcount reduction severance costs across the refineries as well as integration costs pertaining to the same period in 2016.Martinez Acquisition. Our general and administrative expenses are comprised of the personnel, facilities and other infrastructure costs necessary to support our refineries and related logisticallogistics assets.
Gain on Sale of Assets— There was a lossgain of $1.5 million on sale of assets for the year ended December 31, 2017 relating to non-operating refinery assets. There was a loss of $11.4$477.8 million for the year ended December 31, 2016 relating2020 related primarily to the sale of non-operating refining assets.
Depreciationfive hydrogen plants and Amortization Expense— Depreciation and amortization expense totaled $291.0the sale of a parcel of land at our Torrance refinery. There was a gain on sale of assets of $29.9 million for the year ended December 31, 20172019, primarily attributable to the sale of a parcel of land at our Torrance refinery.
Depreciation and Amortization Expense— Depreciation and amortization expense totaled $563.0 million for the year ended December 31, 2020 (including $278.0$551.7 million recorded within Cost of sales) compared to $222.2$436.1 million for the year ended December 31, 20162019 (including $216.3$425.3 million recorded within Cost of sales), an increase of $68.8$126.9 million. The increase was a result of additional depreciation expense associated with the assets acquired in the TorranceMartinez Acquisition and a general increase in our fixed asset base due to capital projects and turnarounds completed during 2017 and 2016.since the third quarter of 2019. Additionally, amortization expense recorded in 2020 includes $56.2 million of accelerated unamortized deferred turnaround costs associated with assets that were idled as part of the East Coast Refining Reconfiguration.
Change in Tax Receivable Agreement LiabilityFair Value of Contingent Consideration— Change in the Tax Receivable Agreement liability for the year ended December 31, 2017fair value of contingent consideration represented a gain of $250.9$93.7 million as compared toand $0.8 million for the years ended December 31, 2020 and December 31, 2019, respectively. This change represented the decrease in the estimated fair value of the Martinez Contingent Consideration and the PBFX Contingent Consideration, both associated with acquisition related earn-out obligations.
Change in Fair Value of Catalyst Obligations— Change in fair value of catalyst obligations represented a gainloss of $12.9$11.8 million for the year ended December 31, 2016.This gain was primarily a result of the TCJA enacted in December 2017 and related remeasurement of the liability based on the decrease in the federal tax rate from 35%2020, compared to 21%.
Change in Fair Value of Catalyst Leases— Change in the fair value of catalyst leases represented a loss of $2.2$9.7 million for the year ended December 31, 2017, compared to a gain of $1.4 million for the year ended December 31, 2016.2019. These gains and losses relaterelated to the change in value of the precious metals underlying the sale and leaseback of our refineries’ precious metal catalysts, which we are obligated to return or repurchase at fair market value on the leasecatalyst financing arrangement termination dates.
Impairment expense— Impairment expense totaled $98.8 million for the year ended December 31, 2020, and was associated with the write-down of certain assets as a result of the East Coast Refining Reconfiguration, other refinery wide project abandonments and the write-down of certain PBFX long-lived assets. There was no such expense recorded in the year ended December 31, 2019.
Change in Tax Receivable Agreement Liability— Change in Tax Receivable Agreement liability for the year ended December 31, 2020, represented a gain of $373.5 million. This gain was primarily the result of a deferred tax asset valuation allowance recorded in accordance with 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 and based on future taxable income. There was no change in the Tax Receivable Agreement liability for the year ended December 31, 2019.
Debt extinguishment costs— Extinguishment Costs— Debt extinguishment costs of $25.5$22.2 million incurred in the year ended December 31, 20172020 relate to nonrecurring charges associated with debt refinancing activity calculated based on the difference between the carrying valueearly redemption of the 2020our 2023 Senior Secured Notes on the date that they were reacquired and the amount for which they were reacquired.Notes. There were no such costs in the same period of 2016.2019.
Interest Expense, net— Interest PBF Energy interest expense totaled $154.4$258.2 million for the year ended December 31, 2017,2020, compared to $150.0$159.6 million for the year ended December 31, 2016,2019, an increase of $4.4$98.6 million. This net increase is mainly attributable to higher averageinterest costs associated with the issuance of the 2028 Senior Notes in January 2020, the issuance of the 2025 Senior Secured Notes in May 2020 and December 2020, as well as higher outstanding borrowings underon our August 2014 Revolving Credit Agreement partially offset by lower interest expense on a portion of our senior notes that were refinanced in May 2017 (see “Note 9 - Credit Facility and Debt” of our Notes to the Consolidated Financial Statements, for additional details).Facility. Interest expense includesincluded interest on long-term debt including the PBFX credit facilities, costs related to the sale and leaseback of our precious metals catalyst,metal catalysts, financing costs associated with the Inventory Intermediation Agreementsprevious inventory intermediation agreements 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 $162.4$268.5 million and $155.8$169.1 million for the yearsyear ended December 31, 20172020 and 2016,December 31, 2019, respectively (inclusive of $8.0$10.3 million and $5.8$9.5 million, respectively, of incremental interest expense on the affiliate note payable with PBF Energy that eliminates in consolidation at the PBF Energy level).
Income Tax Expense— PBF LLC is organized as a limited liability company and PBFX is an MLP, 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 subsidiaryPBF 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 96.6%99.1% and 95.3%99.0%, on a weighted-average
basis for the years ended December 31, 20172020 and 2016,2019, respectively. PBF Energy’s consolidated financial statementsConsolidated 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, including the impact of noncontrolling interest, for the years ended December 31, 20172020 and 20162019 was 39.5%0.2% and 37.9%21.8%, respectively, reflecting tax adjustments for discrete items and the impact of the TCJA which, among other things, reduced the U.S. federal corporaterespectively. The effective tax rate from 35% percent to 21% percent.for the year ended December 31, 2020 was significantly impacted by the recording of a $358.4 million deferred tax asset valuation allowance.
Noncontrolling Interests— 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 records 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 records a noncontrolling interest for the economic interests in PBFX held by the public unitholders of PBFX, and with respect to the consolidation of PBF Holding, the Company records 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 statementConsolidated Statements of operationsOperations represents the portion of the Company’s earnings or loss attributable to the economic interests held by members of PBF EnergyLLC other than PBF Energy, and by the public common unitholders of PBFX and by the third-party holderstockholders of certain of Chalmette Refining’s subsidiaries. The total noncontrolling interest on the consolidated balance sheetConsolidated 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 stockholderstockholders of T&M Terminal Company and Collins Pipeline Company.the two Chalmette Refining subsidiaries. PBF Energy’s weighted-average equity noncontrolling interest ownership percentage in PBF LLC for the years ended December 31, 20172020 and 20162019 was approximately 3.4%0.9% and 4.7%1.0%, respectively. The carrying amount of the noncontrolling interest on our consolidated balance sheetConsolidated 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.
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, EBITDA excluding special items and gross refining margin excluding special items. Special items presented for the year ended December 31, 2018periods presented relate to an LCM inventory adjustment,adjustments, changes in fair value of contingent consideration, changes in the Tax Receivable Agreement liability, (gain) loss on extinguishment of debt, gain on the sale of hydrogen plants, severance and reconfiguration costs, impairment expense, net tax (benefit) expense on remeasurement of deferred tax assets, related to the Torrancegains on land sale andsales, charges associated with the early return of certain leased railcars. Special items for the year ended December 31, 2017 relate to an LCM inventory adjustment, changes in the Tax Receivable Agreement liability, debt extinguishmentrailcars, turnaround 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.
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:
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| | | | |
11. | 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. |
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| | | | |
22. | 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 ourits earnings are subject to corporate-level income taxes. Adjustments have been made to the Adjusted Fully-Converted tax provisions and earnings to assume that wePBF Energy had adopted ourits post-IPO corporate tax structure for all periods presented and areis 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. |
The following table reconciles PBF EnergyEnergy’s Adjusted Fully-Converted results with its results presented in accordance with GAAP for the years ended December 31, 2018, 20172021, 2020 and 20162019 (in thousands,millions, except share and per share amounts):
|
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| Net income attributable to PBF Energy Inc. stockholders | | $ | 128,315 |
| | $ | 415,517 |
| | $ | 170,811 |
|
| Less: Income allocated to participating securities | | 748 |
| | 1,043 |
| | — |
|
| Income available to PBF Energy Inc. stockholders - basic | | 127,567 |
| | 414,474 |
| | 170,811 |
|
Add: Net income attributable to noncontrolling interest(1) | | 4,668 |
| | 16,746 |
| | 14,903 |
|
Less: Income tax expense(2) | | (1,214 | ) | | (6,633 | ) | | (5,821 | ) |
| Adjusted fully-converted net income | | $ | 131,021 |
| | $ | 424,587 |
| | $ | 179,893 |
|
Special Items:(3) | | | | | | |
| Add: Non-cash LCM inventory adjustment | | 351,278 |
| | (295,532 | ) | | (521,348 | ) |
| Add: Change in Tax Receivable Agreement liability | | (13,893 | ) | | (250,922 | ) | | (12,908 | ) |
| Add: Debt extinguishment costs | | — |
| | 25,451 |
| | — |
|
Add: Net tax benefit related to the TCJA | | — |
| | (173,346 | ) | | — |
|
| Add: Net tax expense on remeasurement of Tax Receivable Agreement associated deferred tax assets | | — |
| | 193,499 |
| | — |
|
| Add: Gain on Torrance land sale | | (43,761 | ) | | — |
| | — |
|
| Add: Early railcar return expense | | 52,313 |
| | — |
| | — |
|
| Less: Recomputed income taxes on special items | | (89,944 | ) | | 206,364 |
| | 208,686 |
|
| Adjusted fully-converted net income (loss) excluding special items | | $ | 387,014 |
| | $ | 130,101 |
| | $ | (145,677 | ) |
| | | | | | | |
| Weighted-average shares outstanding of PBF Energy Inc. | | 115,190,262 |
| | 109,779,407 |
| | 98,334,302 |
|
Conversion of PBF LLC Series A Units (4) | | 1,938,089 |
| | 3,823,783 |
| | 4,865,133 |
|
Common stock equivalents (5) | | 1,645,255 |
| | 295,655 |
| | 407,274 |
|
| Fully-converted shares outstanding—diluted | | 118,773,606 |
| | 113,898,845 |
| | 103,606,709 |
|
| | | | | | | |
| Diluted net income per share | | $ | 1.10 |
| | $ | 3.73 |
| | $ | 1.74 |
|
| Adjusted fully-converted net income per fully exchanged, fully diluted shares outstanding | | $ | 1.10 |
| | $ | 3.73 |
| | $ | 1.74 |
|
| Adjusted fully-converted net income (loss) excluding special items per fully exchanged, fully diluted shares outstanding | | $ | 3.26 |
| | $ | 1.14 |
| | $ | (1.41 | ) |
| | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2021 | | 2020 | | 2019 |
| Net income (loss) attributable to PBF Energy Inc. stockholders | | $ | 231.0 | | | $ | (1,392.4) | | | $ | 319.4 | |
| Less: Income allocated to participating securities | | — | | | 0.1 | | | 0.5 | |
| Income (loss) available to PBF Energy Inc. stockholders - basic | | 231.0 | | | (1,392.5) | | | 318.9 | |
Add: Net income (loss) attributable to noncontrolling interests(1) | | 2.4 | | | (17.1) | | | 4.3 | |
Less: Income tax (expense) benefit (2) | | (0.6) | | | 4.6 | | | (1.0) | |
| Adjusted fully-converted net income (loss) | | $ | 232.8 | | | $ | (1,405.0) | | | $ | 322.2 | |
Special Items:(3) | | | | | | |
| Add: Non-cash LCM inventory adjustment | | (669.6) | | | 268.0 | | | (250.2) | |
| Add: Change in fair value of contingent consideration | | 32.4 | | | (93.7) | | | — | |
| Add: Gain on sale of hydrogen plants | | — | | | (471.1) | | | — | |
| Add: Gain on land sales | | (2.8) | | | (8.1) | | | (33.1) | |
| 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: (Gain) loss on extinguishment of debt | | (79.9) | | | 22.2 | | | — | |
| Add: Change in Tax Receivable Agreement liability | | 48.3 | | | (373.5) | | | — | |
| | | | | | |
| Add: Net tax (benefit) expense on remeasurement of deferred tax assets | | (37.4) | | | 259.1 | | | — | |
| Less: Recomputed income tax on special items | | 173.9 | | | 99.9 | | | 70.4 | |
| Adjusted fully-converted net income (loss) excluding special items | | $ | (302.3) | | | $ | (1,421.7) | | | $ | 109.3 | |
| | | | | | |
| Weighted-average shares outstanding of PBF Energy Inc. | | 120,240,009 | | | 119,617,998 | | | 119,887,646 | |
Conversion of PBF LLC Series A Units (4) | | 988,730 | | | 1,042,667 | | | 1,207,581 | |
Common stock equivalents (5) | | 1,409,415 | | | — | | | 758,072 | |
| | | | | | |
| Fully-converted shares outstanding—diluted | | 122,638,154 | | | 120,660,665 | | | 121,853,299 | |
| | | | | | |
| Diluted net income (loss) per share | | $ | 1.90 | | | $ | (11.64) | | | $ | 2.64 | |
Adjusted fully-converted net income (loss) per fully exchanged, fully diluted shares outstanding (5) | | $ | 1.90 | | | $ | (11.64) | | | $ | 2.64 | |
| Adjusted fully-converted net income (loss) excluding special items per fully exchanged, fully diluted shares outstanding | | $ | (2.50) | | | $ | (11.78) | | | $ | 0.90 | |
——————————
See Notes to Non-GAAP Financial Measures.
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, 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 depreciation. In order to assess our operating performance, we compare our gross refining margin (revenue(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 thousands,millions, except per barrel amounts):
| | | | | Year Ended December 31, | | Year Ended December 31, |
| | | 2018 | | 2017 | | 2016 | | 2021 | | 2020 | | 2019 |
| | | $ | per barrel of throughput | | $ | per barrel of throughput | | $ | per barrel of throughput | | $ | per barrel of throughput | | $ | per barrel of throughput | | $ | per barrel of throughput |
| Calculation of consolidated gross margin: | | | | | | | | Calculation of consolidated gross margin: | | | | | | |
| Revenues | | $ | 27,186,093 |
| $ | 87.67 |
| | $ | 21,786,637 |
| $ | 73.92 |
| | $ | 15,920,424 |
| $ | 59.77 |
| Revenues | | $ | 27,253.4 | | $ | 89.46 | | | $ | 15,115.9 | | $ | 56.76 | | | $ | 24,508.2 | | $ | 81.58 | |
| Less: Cost of Sales | | 26,583,478 |
| 85.73 |
| | 20,826,048 |
| 70.67 |
| | 15,237,433 |
| 57.21 |
| |
| Less: Cost of sales | | Less: Cost of sales | | 26,366.2 | | 86.55 | | | 16,745.6 | | 62.88 | | | 23,595.1 | | 78.54 | |
| Consolidated gross margin | | $ | 602,615 |
| $ | 1.94 |
| | $ | 960,589 |
| $ | 3.25 |
| | $ | 682,991 |
| $ | 2.56 |
| Consolidated gross margin | | $ | 887.2 | | $ | 2.91 | | | $ | (1,629.7) | | $ | (6.12) | | | $ | 913.1 | | $ | 3.04 | |
| Reconciliation of consolidated gross margin to gross refining margin: | | | | | | | Reconciliation of consolidated gross margin to gross refining margin: | |
| Consolidated gross margin | | $ | 602,615 |
| $ | 1.94 |
| | $ | 960,589 |
| $ | 3.25 |
| | $ | 682,991 |
| $ | 2.56 |
| Consolidated gross margin | | $ | 887.2 | | $ | 2.91 | | | $ | (1,629.7) | | $ | (6.12) | | | $ | 913.1 | | $ | 3.04 | |
| Add: PBFX operating expense | | 84,410 |
| 0.27 |
| | 66,443 |
| 0.23 |
| | 41,317 |
| 0.15 |
| Add: PBFX operating expense | | 103.4 | | 0.35 | | | 99.9 | | 0.38 | | | 118.7 | | 0.40 | |
| Add: PBFX depreciation expense | | 29,417 |
| 0.09 |
| | 23,721 |
| 0.08 |
| | 12,337 |
| 0.05 |
| Add: PBFX depreciation expense | | 37.8 | | 0.13 | | | 53.7 | | 0.19 | | | 38.6 | | 0.13 | |
| Less: Revenues of PBFX | | (281,511 | ) | (0.91 | ) | | (254,813 | ) | (0.86 | ) | | (187,335 | ) | (0.70 | ) | Less: Revenues of PBFX | | (355.5) | | (1.17) | | | (360.3) | | (1.35) | | | (340.2) | | (1.13) | |
| Add: Refinery operating expense | | 1,654,749 |
| 5.34 |
| | 1,626,440 |
| 5.52 |
| | 1,390,134 |
| 5.22 |
| Add: Refinery operating expense | | 1,999.1 | | 6.56 | | | 1,835.2 | | 6.89 | | | 1,684.3 | | 5.61 | |
| Add: Refinery depreciation expense | | 329,709 |
| 1.06 |
| | 254,271 |
| 0.86 |
| | 204,005 |
| 0.77 |
| Add: Refinery depreciation expense | | 415.7 | | 1.36 | | | 498.0 | | 1.87 | | | 386.7 | | 1.29 | |
| Gross refining margin | | $ | 2,419,389 |
| $ | 7.79 |
| | $ | 2,676,651 |
| $ | 9.08 |
| | $ | 2,143,449 |
| $ | 8.05 |
| Gross refining margin | | $ | 3,087.7 | | $ | 10.14 | | | $ | 496.8 | | $ | 1.86 | | | $ | 2,801.2 | | $ | 9.34 | |
Special Items: (3) | | | | | | | Special Items: (3) | |
| Add: Non-cash LCM inventory adjustment | | 351,278 |
| 1.13 |
| | (295,532 | ) | (1.00 | ) | | (521,348 | ) | (1.96 | ) | Add: Non-cash LCM inventory adjustment | | (669.6) | | (2.20) | | | 268.0 | | 1.01 | | | (250.2) | | (0.83) | |
| Add: LIFO inventory decrement | | Add: LIFO inventory decrement | | — | | — | | | 83.0 | | 0.31 | | | — | | — | |
| Add: Early railcar return expense | | 52,313 |
| 0.17 |
| | — |
| — |
| | — |
| — |
| Add: Early railcar return expense | | — | | — | | | 12.5 | | 0.05 | | | — | | — | |
| Gross refining margin excluding special items | | $ | 2,822,980 |
| $ | 9.09 |
| | $ | 2,381,119 |
| $ | 8.08 |
| | $ | 1,622,101 |
| $ | 6.09 |
| Gross refining margin excluding special items | | $ | 2,418.1 | | $ | 7.94 | | | $ | 860.3 | | $ | 3.23 | | | $ | 2,551.0 | | $ | 8.51 | |
——————————
See Notes to Non-GAAP Financial Measures.
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 leases,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, debt(gain) loss on extinguishment costsof debt related to refinancing activities, 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.
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 thousands)millions):
| | | | | | | | | | | Year Ended December 31, |
| | | Year Ended December 31, | | 2021 | | 2020 | | 2019 |
| | | 2018 | | 2017 | | 2016 | |
| Reconciliation of net income to EBITDA and EBITDA excluding special items: | | | | | | |
| Net income | $ | 175,291 |
| | $ | 483,431 |
| | $ | 225,518 |
| |
| 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) | $ | 315.5 | | | $ | (1,333.3) | | | $ | 375.2 | |
| Add: Depreciation and amortization expense | Add: Depreciation and amortization expense | 369,760 |
| | 290,956 |
| | 222,176 |
| Add: Depreciation and amortization expense | 466.8 | | | 563.0 | | | 436.1 | |
| Add: Interest expense, net | Add: Interest expense, net | 169,911 |
| | 154,427 |
| | 150,045 |
| Add: Interest expense, net | 317.5 | | | 258.2 | | | 159.6 | |
| Add: Income tax expense | Add: Income tax expense | 33,507 |
| | 315,584 |
| | 137,650 |
| Add: Income tax expense | 12.1 | | | 2.1 | | | 104.3 | |
| EBITDA | EBITDA | $ | 748,469 |
| | $ | 1,244,398 |
| | $ | 735,389 |
| EBITDA | $ | 1,111.9 | | | $ | (510.0) | | | $ | 1,075.2 | |
Special Items: (3) | Special Items: (3) | | | | | | Special Items: (3) | |
| Add: Non-cash LCM inventory adjustment | Add: Non-cash LCM inventory adjustment | 351,278 |
| | (295,532 | ) | | (521,348 | ) | Add: Non-cash LCM inventory adjustment | (669.6) | | | 268.0 | | | (250.2) | |
| Add: Change in fair value of contingent consideration | | Add: Change in fair value of contingent consideration | 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) | | | (33.1) | |
| 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: (Gain) loss on extinguishment of debt | | Add: (Gain) loss on extinguishment of debt | (79.9) | | | 22.2 | | | — | |
| Add: Change in Tax Receivable Agreement liability | Add: Change in Tax Receivable Agreement liability | (13,893 | ) | | (250,922 | ) | | (12,908 | ) | Add: Change in Tax Receivable Agreement liability | 48.3 | | | (373.5) | | | — | |
| Add: Debt extinguishment costs | — |
| | 25,451 |
| | — |
| |
| Add: Gain on Torrance land sale | (43,761 | ) | | — |
| | — |
| |
| Add: Early railcar return expense | 52,313 |
| | — |
| | — |
| |
| | EBITDA excluding special items | EBITDA excluding special items | $ | 1,094,406 |
| | $ | 723,395 |
| | $ | 201,133 |
| EBITDA excluding special items | $ | 440.3 | | | $ | (941.9) | | | $ | 791.9 | |
| | | | | | | | | | | | | |
| Reconciliation of EBITDA to Adjusted EBITDA: | Reconciliation of EBITDA to Adjusted EBITDA: |
| | | | | Reconciliation of EBITDA to Adjusted EBITDA: | |
| EBITDA | EBITDA | $ | 748,469 |
| | $ | 1,244,398 |
| | $ | 735,389 |
| EBITDA | $ | 1,111.9 | | | $ | (510.0) | | | $ | 1,075.2 | |
| Add: Stock based compensation | Add: Stock based compensation | 25,969 |
| | 26,848 |
| | 22,656 |
| Add: Stock based compensation | 35.6 | | | 34.2 | | | 37.3 | |
| Add: Net non-cash change in fair value of catalyst leases | (5,587 | ) | | 2,247 |
| | (1,422 | ) | |
| Add: Change in fair value of catalyst obligations | | Add: Change in fair value of catalyst obligations | (8.5) | | | 11.8 | | | 9.7 | |
Add: Non-cash LCM inventory adjustment (3) | Add: Non-cash LCM inventory adjustment (3) | 351,278 |
| | (295,532 | ) | | (521,348 | ) | Add: Non-cash LCM inventory adjustment (3) | (669.6) | | | 268.0 | | | (250.2) | |
Add: Change in fair value of contingent consideration (3) | | Add: Change in fair value of contingent consideration (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) | | | (33.1) | |
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: (Gain) loss on extinguishment of debt (3) | | Add: (Gain) loss on extinguishment of debt (3) | (79.9) | | | 22.2 | | | — | |
Add: Change in Tax Receivable Agreement liability (3) | Add: Change in Tax Receivable Agreement liability (3) | (13,893 | ) | | (250,922 | ) | | (12,908 | ) | Add: Change in Tax Receivable Agreement liability (3) | 48.3 | | | (373.5) | | | — | |
Add: Debt extinguishment costs (3) | — |
| | 25,451 |
| | — |
| |
| | Adjusted EBITDA | Adjusted EBITDA | $ | 1,106,236 |
| | $ | 752,490 |
| | $ | 222,367 |
| Adjusted EBITDA | $ | 467.4 | | | $ | (895.9) | | | $ | 838.9 | |
See Notes to Non-GAAP Financial Measures.
