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 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 and related governmental and consumer responses on our business, financial condition and results of operations; •our ability to target and execute expense reduction measures in 2021 and thereafter; •supply, demand, prices and other market conditions for our products, including volatility in commodity prices; • the effects of competition in our markets; •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 substantial indebtedness, including the impact of the recent downgrades to our corporate credit rating, secured notes and unsecured notes; •our expectations with respect to our capital improvement and turnaround projects; •our supply and inventory intermediation arrangements expose us to counterparty credit and performance risk; 66 -------------------------------------------------------------------------------- •termination of our Inventory Intermediation Agreements withJ. Aron , which 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. Additionally, we are obligated to repurchase fromJ. Aron certain J. Aron Products located at our J. Aron Storage Tanks upon termination of these agreements; •restrictive covenants in our indebtedness that may adversely affect our operational flexibility; •payments byPBF Energy to the current and former holders of PBF LLC Series A Units and PBF LLC Series B Units underPBF Energy's Tax Receivable Agreement for certain tax benefits we may claim; •our assumptions regarding payments arising underPBF 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 ofPBF 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; •our expectations and timing with respect to our acquisition activity and whether such acquisitions are accretive or dilutive to shareholders; •the impact of disruptions to crude or feedstock supply to any of our refineries, including disruptions due to problems at PBFX or with third-party logistics infrastructure or operations, including pipeline, marine and rail transportation; •the possibility that we might 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 threat of cyber-attacks; •our increased dependence on technology; •the effectiveness of our crude oil sourcing strategies, including our crude by rail strategy and related commitments; •adverse impacts related to legislation by the federal government lifting the restrictions on exportingU.S. crude oil; •adverse impacts from changes in our regulatory environment, such as the effects of compliance with 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 Standard and GHG emission credits required to comply with various GHG emission programs, such as AB32; •our ability to complete the successful integration of theMartinez refinery and any other acquisitions into our business and to realize the benefits from such acquisitions; •unforeseen liabilities associated with the Martinez Acquisition and any other acquisitions; •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 logistics assets that may be transferred to PBFX. 67 -------------------------------------------------------------------------------- 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 ofthe 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 byPBF LLC and its subsidiaries. We were formed inMarch 2008 to pursue the acquisitions of crude oil refineries and downstream assets inNorth America . We own and operate six domestic oil refineries and related assets located inDelaware City, Delaware ,Paulsboro, New Jersey ,Toledo, Ohio ,Chalmette, Louisiana ,Torrance, California , andMartinez, California . Based on current configuration (subsequent to theEast 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 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 The impact of the unprecedented global health and economic crisis sparked by the COVID-19 pandemic was amplified late in the quarter endedMarch 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 has resulted in significant demand reduction for our refined products and atypical volatility in oil commodity prices, which are expected to continue for the foreseeable future. Our results for the year endedDecember 31, 2020 were impacted by the sustained decreased demand for refined products and the significant decline in the price of crude oil, both of which negatively impacted our revenues, cost of products sold and operating income and lowered our liquidity. Throughput rates across our refining system also decreased and we are currently operating our refineries at reduced rates. Refer to "Item 1. Business - Recent Developments" and "Item 1A. Risk Factors" for further information. 68 -------------------------------------------------------------------------------- East Coast Refining Reconfiguration OnDecember 31, 2020 , we completed the East Coast Refining Reconfiguration. As part of the reconfiguration process, we idled certain of our major processing units at thePaulsboro refinery , resulting in lower overall throughput and inventory levels in addition to decreases in capital and operating costs. Based on this reconfiguration, ourEast Coast throughput capacity is approximately 285,000 barrels per day. Turnaround Costs and Assets under Construction As a result of the East Coast Refining Reconfiguration, certain major processing units were temporarily idled. As such, 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 . 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 ofDecember 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 . Severance Costs Following the onset of the COVID-19 pandemic, we have implemented a number of cost reduction initiatives to strengthen our financial flexibility and rationalize overhead expenses, including reductions in our workforce. 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 are included in general and administrative expenses. Tax Receivable Agreement In connection withPBF Energy's initial public offering,PBF Energy entered into a Tax Receivable Agreement pursuant to whichPBF Energy is required to pay the members ofPBF LLC , who exchange their units for PBF Energy Class A common stock or whose unitsPBF Energy purchases, approximately 85% of the cash savings in income taxes thatPBF Energy realizes as a result of the increase in the tax basis of its interest inPBF LLC , including tax benefits attributable to payments made under the Tax Receivable Agreement. There was no Tax Receivable Agreement liability as ofDecember 31, 2020 .PBF Energy has recognized, as ofDecember 31, 2019 and 2018, a liability for the Tax Receivable Agreement of$373.5 million , reflecting the estimate of the undiscounted amounts thatPBF Energy expects to pay under the agreement, net of the impact of a deferred tax asset valuation allowance recognized in accordance with ASC 740, Income Taxes. 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 ofDecember 31, 2020 . 69 -------------------------------------------------------------------------------- In the third quarter of 2018 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 the early termination penalty and a reduced rental fee over the remaining term of the lease. As a result, we recognized an expense of$52.3 million for the year endedDecember 31, 2018 included within Cost of sales consisting of (i) a$40.3 million charge for the early termination penalty and (ii) a$12.0 million charge 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 ofDecember 31, 2018 .Torrance Land Sales OnDecember 30, 2020 ,August 1, 2019 andAugust 7, 2018 , we closed on third-party sales of parcels of real property acquired as part of theTorrance refinery , but not part of the refinery itself. The sales resulted in gains of approximately$8.1 million ,$33.1 million and$43.8 million in the fourth quarter of 2020, third quarter of 2019 and third quarter of 2018, respectively, included within Gain on sale of assets in the Consolidated Statements of Operations. Sale of Hydrogen Plants OnApril 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 through which Air Products will exclusively supply hydrogen, steam, carbon dioxide and other products (the "Products") to theMartinez , Torrance andDelaware City refineries for a specified period (not expected to exceed 18 months). The transition services agreement also requires certain maintenance and operating activities to be provided byPBF Holding , for which we will be reimbursed, during the term of the agreement. InAugust 2020 , the parties executed long-term supply agreements pursuant to which Air Products will supply the Products for a term of fifteen years at these same refineries. Debt and Credit Facilities Credit Ratings During the fourth quarter of 2020, each of our credit rating agencies downgraded our corporate family rating as well as our unsecured and secured notes ratings, with all ratings on negative outlook as the refining sector continues to experience weak refining margins due to the COVID-19 pandemic and related negative demand impact. As a result of the downgrade, the cost of borrowing under our Revolving Credit Facility has increased in accordance with the Revolving Credit Agreement. The 2028 Senior Notes and the 2025 Senior Notes are rated B3 by Moody's, B+ by S&P, and B+ by Fitch. The 2025 Senior Secured Notes are rated Ba3 by Moody's, BB by S&P, and BB by Fitch. Catalyst Financing Obligations OnSeptember 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 ourEast Coast Refining System,Martinez andToledo 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, and the earliest expiration isSeptember 2021 . For all leases not renewed at maturity, we have the ability and intent to finance such debt through availability under our revolving credit facilities. 70 -------------------------------------------------------------------------------- Senior Notes OnMay 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. OnDecember 21, 2020 , we issued$250.0 million , in a tack-on offering, in aggregate principal amount of the additional 2025 Senior Secured Notes. The net proceeds from this offering were approximately$245.7 million after deducting the initial purchasers' discount and estimated offering expenses. We used the net proceeds for general corporate purposes. OnJanuary 24, 2020 , we issued$1.0 billion in aggregate principal amount of the 2028 Senior Notes. The net proceeds from this offering were approximately$987.0 million after deducting the initial purchasers' discount and offering expenses. We used$517.5 million of the proceeds to fully redeem our 2023 Senior Notes and the balance to fund a portion of the cash consideration for the Martinez Acquisition. OnFebruary 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 Debt extinguishment costs in the Consolidated Statements of Operations for the year endingDecember 31, 2020 . Refer to "Note 10 - Credit Facilities and Debt" of our Notes to Consolidated Financial Statements, for further information. PBF Holding Revolving Credit Facility During the year endedDecember 31, 2020 , we used advances under our Revolving Credit Facility to fund a portion of the Martinez Acquisition and for other general corporate purposes. OnMay 2, 2018 ,PBF Holding and certain of its wholly-owned subsidiaries, as borrowers or subsidiary guarantors, replaced our existing asset-based revolving credit agreement dated as ofAugust 15, 2014 (the "August 2014 Revolving Credit Agreement") with the Revolving Credit Facility. Among other things, the Revolving Credit Facility increases the maximum commitment available toPBF Holding from$2.6 billion to$3.4 billion , extends the maturity date toMay 2023 , and redefines certain components of the Borrowing Base, as defined in 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 theAugust 2014 Revolving Credit Agreement and further described in "Note 10 - Credit Facilities and Debt" of our Notes to Consolidated Financial Statements. The outstanding borrowings under the Revolving Credit Facility as ofDecember 31, 2020 were$900.0 million . There were no outstanding borrowings under the Revolving Credit Facility as ofDecember 31, 2019 and 2018, respectively. PBFX Revolving Credit Facility OnJuly 30, 2018 , PBFX entered into the PBFX Revolving Credit Facility withWells Fargo Bank, National Association , as administrative agent, and a syndicate of lenders. The PBFX Revolving Credit Facility amended and restated theMay 2014 PBFX Revolving Credit Facility to, among other things, increase the maximum commitment available to PBFX from$360.0 million to$500.0 million and extend the maturity date toJuly 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 71 -------------------------------------------------------------------------------- increased commitments from 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 theMay 2014 PBFX Revolving Credit Facility. The PBFX Revolving Credit Facility is guaranteed by a limited guaranty of collection fromPBF LLC . During the year endedDecember 31, 2020 , PBFX made net repayments of$83.0 million on the PBFX Revolving Credit Facility. During 2019 and 2018, PBFX incurred net borrowings of$127.0 million and$126.3 million , respectively, primarily to fund acquisitions and capital projects. The outstanding borrowings under the PBFX Revolving Credit Facility were$200.0 million ,$283.0 million and$156.0 million as ofDecember 31, 2020 , 2019 and 2018, respectively. Martinez Acquisition We acquired theMartinez refinery and related logistics assets fromShell Oil Products onFebruary 1, 2020 for an aggregate purchase price of$1,253.4 million , including final working capital of$216.1 million and the obligation to make certain post-closing earn-out payments toShell Oil Products based on certain earnings thresholds of theMartinez 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 theCity of Martinez , 30 miles northeast ofSan 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 inthe United States . The facility is strategically positioned inNorthern California and provides for operating and commercial synergies with theTorrance refinery located inSouthern 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 Agreements The Inventory Intermediation Agreements withJ. Aron were amended in the first quarter of 2019 and amended and restated in the third quarter of 2019, pursuant to which certain terms of the Inventory Intermediation Agreements were amended, including, among other things, the maturity date. OnMarch 29, 2019 the Inventory Intermediation Agreement by and amongJ. Aron ,PBF Holding and DCR was amended to add the East Coast Storage Assets as a location and crude oil as a new product type to be included in the products sold toJ. Aron by DCR. OnAugust 29, 2019 , the Inventory Intermediation Agreement by and amongJ. Aron ,PBF Holding and PRC was extended toDecember 31, 2021 , which term may be further extended by mutual consent of the parties toDecember 31, 2022 and the Inventory Intermediation Agreement by and amongJ. Aron ,PBF Holding and DCR was extended toJune 30, 2021 , which term may be further extended by mutual consent of the parties toJune 30, 2022 . We intend to either extend or replace the Inventory Intermediation Agreements prior to their expirations. Pursuant to each Inventory Intermediation Agreement,J. Aron continues to purchase and hold title to the J. Aron Products produced by the refinery, and delivered into our J. Aron Storage Tanks. The J. Aron Products are sold back to us as they are discharged out of our J. Aron Storage Tanks.J. Aron has the right to store the J. Aron Products purchased in tanks under the Inventory Intermediation Agreements and will retain these storage rights for the term of the agreements. At expiration or termination of each of the Inventory Intermediation Agreements, we will have to repurchase the inventories outstanding under the applicable Inventory Intermediation Agreement at that time.PBF Holding continues to market and sell the J. Aron Products independently to third parties. 72 --------------------------------------------------------------------------------PBF Energy Inc. Public Offerings As a result of the initial public offering and related reorganization transactions,PBF Energy became the sole managing member ofPBF LLC with a controlling voting interest inPBF LLC and its subsidiaries. Effective with completion of the initial public offering,PBF Energy consolidates the financial results ofPBF LLC and its subsidiaries and records a noncontrolling interest in its Consolidated Financial Statements representing the economic interests ofPBF LLC unitholders other thanPBF Energy . Additionally, a series of secondary offerings were made subsequent to our IPO whereby funds affiliated with The Blackstone Group L.P. ("Blackstone") andFirst Reserve Management L.P. ("First Reserve") sold their interests in us. As a result of these secondary offerings,Blackstone and First Reserve no longer hold anyPBF LLC Series A units. OnAugust 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"). As ofDecember 31, 2020 , including the offerings described above,PBF Energy owns 120,122,872PBF LLC Series C Units and our current and former executive officers and directors and certain employees and others beneficially own 970,647PBF LLC Series A Units. The holders of our issued and outstanding shares of PBF Energy Class A common stock have 99.2% of the voting power in us and the members ofPBF LLC , other thanPBF Energy through their holdings of Class B common stock, have the remaining 0.8% of the voting power in us. PBFX Equity Offerings OnApril 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 onApril 29, 2019 . OnJuly 30, 2018 , PBFX closed on a common unit purchase agreement with certain funds managed byTortoise Capital Advisors, L.L.C. providing for the issuance and sale in a registered direct offering of an aggregate of 1,775,750 common units for net proceeds of approximately$34.9 million . As ofDecember 31, 2020 ,PBF LLC held a 48.0% limited partner interest in PBFX with the remaining 52.0% 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 ofPBF Holding , which include minimum volume commitments, for receiving, handling, transferring and storing crude oil, refined products and natural gas. These transactions are eliminated byPBF Energy andPBF 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 endedDecember 31, 2020 are discussed below. 73 -------------------------------------------------------------------------------- TVPC Acquisition OnApril 24, 2019 , PBFX entered into the TVPC Contribution Agreement, pursuant to whichPBF LLC contributed to PBFX all of the issued and outstanding limited liability company interests ofTVP Holding for total consideration of$200.0 million . Prior to the TVPC Acquisition,TVP Holding owned a 50% membership interest in TVPC. Subsequent to the closing of the TVPC Acquisition onMay 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 OnFebruary 28, 2019 , PBFX closed on the IDR Restructuring Agreement withPBF LLC and PBF GP, pursuant to which PBFX's IDRs held byPBF LLC were canceled and converted into 10,000,000 newly issued PBFX common units. Subsequent to the closing of the IDR Restructuring, no distributions were made toPBF LLC with respect to the IDRs and the newly issued PBFX common units are entitled to normal distributions by PBFX. East Coast Storage Assets Acquisition OnOctober 1, 2018 , PBFX closed on its agreement withCrown Point to purchase its wholly-owned subsidiary,CPI Operations LLC (the "East Coast Storage Assets Acquisition") for total consideration of approximately$127.0 million , including working capital and the Contingent Consideration (as defined in "Note 4 - Acquisitions" of our Notes to Consolidated Financial Statements), comprised of an initial payment at closing of$75.0 million with a remaining balance of$32.0 million that was paid onOctober 1, 2019 . The residual purchase consideration consists of an earn-out provision related to an existing commercial agreement with a third-party, based on the future results of certain of the acquired idled assets (the "PBFX Contingent Consideration"). The consideration was financed through a combination of cash on hand and borrowings under the PBFX Revolving Credit Facility. Development Assets Acquisition OnJuly 16, 2018 ,PBFX and PBF LLC entered into the Development Assets Contribution Agreements, pursuant to which PBFX acquired fromPBF LLC all of the issued and outstanding limited liability company interests ofToledo Rail Logistics Company LLC , whose assets consist of a loading and unloading rail facility located atPBF Holding's Toledo refinery (the "Toledo Rail Products Facility");Chalmette Logistics Company LLC , whose assets consist of a truck loading rack facility (the "Chalmette Truck Rack") and a rail yard facility (the "Chalmette Rosin Yard"), both of which are located atPBF Holding's Chalmette refinery ;Paulsboro Terminaling Company LLC , whose assets consist of a lube oil terminal facility located atPBF Holding's Paulsboro refinery (the "Paulsboro Lube Oil Terminal "); andDCR Storage and Loading Company LLC , whose assets consist of an ethanol storage facility located atPBF Holding's Delaware City refinery (the "Delaware Ethanol Storage Facility" and collectively with the Toledo Rail Products Facility, the Chalmette Truck Rack, the Chalmette Rosin Yard, and thePaulsboro Lube Oil Terminal , the "Development Assets"). The acquisition of the Development Assets closed onJuly 31, 2018 for total consideration of$31.6 million consisting of 1,494,134 common units representing limited partner interests in PBFX, issued toPBF LLC . Knoxville Terminal Acquisition OnApril 16, 2018 , PBFX completed the purchase of two refined product terminals located inKnoxville, Tennessee , which include product tanks, pipeline connections to theColonial Pipeline Company andPlantation Pipe Line Company pipeline systems and truck loading facilities (the "Knoxville Terminals") fromCummins Terminals, Inc. for total cash consideration of$58.0 million , excluding working capital adjustments. The transaction was financed through a combination of cash on hand and borrowings under the PBFX Revolving Credit Facility. 74 -------------------------------------------------------------------------------- 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 byEPA . 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$326.4 million in RINs costs during the year endedDecember 31, 2020 as compared to$122.7 million and$143.9 million during the years endedDecember 31, 2019 and 2018, 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. 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 ourEast Coast refineries generally follows the Dated Brent (NYH) 2-1-1 benchmark refining margin. OurToledo refinery generally follows the WTI (Chicago ) 4-3-1 benchmark refining margin. OurChalmette refinery generally follows the LLS (Gulf Coast ) 2-1-1 benchmark refining margin. OurTorrance refinery generally follows the Alaskan North Slope ("ANS") (West Coast ) 4-3-1 benchmark refining margin. OurMartinez refinery generally follows the ANS (West Coast ) 3-2-1 benchmark refining margin. 75 -------------------------------------------------------------------------------- While the benchmark refinery margins presented below under "Results of Operations-Market Indicators" are representative of the results of our refineries, each refinery's realized gross margin on a per barrel basis will differ from the benchmark due to a variety of factors affecting the performance of the relevant refinery to its corresponding benchmark. These factors include the refinery's actual type of crude oil throughput, product yield differentials and any other factors not reflected in the benchmark refining margins, such as transportation costs, storage costs, credit fees, fuel consumed during production and any product premiums or discounts, as well as inventory fluctuations, timing of crude oil and other feedstock purchases, a rising or declining crude and product pricing environment and commodity price management activities. As discussed in more detail below, each of our refineries, depending on market conditions, has certain feedstock-cost and product-value advantages and disadvantages as compared to the refinery's relevant benchmark. Credit Risk Management Credit risk refers to the risk that a counterparty will default on its contractual obligations resulting in financial loss to us. Our exposure to credit risk is reflected in the carrying amount of the receivables that are presented in our Consolidated Balance Sheets. To minimize credit risk, all customers are subject to extensive credit verification procedures and extensions of credit above defined thresholds are to be approved by the senior management. Our intention is to trade only with recognized creditworthy third parties. In addition, receivable balances are monitored on an ongoing basis. We also limit the risk of bad debts by obtaining security such as guarantees or letters of credit. We continually monitor our market risk exposure, 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 ourEast Coast refineries access their crude slates from theDelaware River via ship or barge and through our rail facilities atDelaware City , these refineries have the flexibility to purchase crude oils from the Mid-Continent andWestern Canada , as well as a number of different countries. We have not sourced crude oil under our crude supply arrangement withPDVSA since 2017 asPDVSA has suspended deliveries due to our inability to agree to mutually acceptable payment terms and because ofU.S. government sanctions againstPDVSA . In the past several years, we expanded and upgraded the existing on-site railroad infrastructure on the east coast. Currently, crude oil delivered by rail is consumed at ourEast Coast refineries. TheDelaware City rail unloading facilities, and the East Coast Storage Assets, allow ourEast Coast refineries to source WTI-based crude oils fromWestern Canada and the Mid-Continent, which we believe, at times, may provide cost advantages versus traditional Brent-based international crude oils. In support of this rail strategy, we have at times entered into agreements to lease or purchase crude railcars. Certain of these railcars were subsequently sold to a third-party, which has leased the railcars back to us for periods of between four and seven years. In subsequent periods, we have sold or returned railcars to optimize our railcar portfolio. Our railcar fleet, at times, provides transportation flexibility within our crude oil sourcing strategy that allows ourEast Coast refineries to process cost advantaged crude fromCanada 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 theRenewable Fuels Standard. The predominant variable cost is energy, in particular, the price of utilities, natural gas and electricity. 76 -------------------------------------------------------------------------------- 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. East Coast Refining System (Delaware City and Paulsboro Refineries). The benchmark refining margin for the East Coast Refining System is calculated by assuming that two barrels of Dated Brent crude oil are converted into one barrel of gasoline and one barrel of diesel. We calculate this benchmark using the NYH market value of reformulated blendstock for oxygenate blending ("RBOB") and ULSD against the market value of Dated Brent and refer to the benchmark as the Dated Brent (NYH) 2-1-1 benchmark refining margin. The East Coast Refining System has a product slate of approximately 47% 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 (3% petroleum coke, 4% LPGs, 7% black oil and 3% other). For this reason, we believe the Dated Brent (NYH) 2-1-1 is an appropriate benchmark industry refining margin. The majority ofEast Coast refining revenues are generated off NYH-based market prices. The East Coast Refining System's realized gross margin on a per barrel basis is projected to differ from the Dated Brent (NYH) 2-1-1 benchmark refining margin due to the following factors: •the system processes a slate of primarily medium and heavy sour crude oils, which has constituted approximately 60% to 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 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. •thePaulsboro refinery produces Group I lubricants which carry a premium sales price to RBOB and ULSD and the black oil is sold as asphalt which may be sold at a premium or discount to Dated Brent based on the market.Toledo Refinery . The benchmark refining margin for theToledo 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 theChicago market values of CBOB and ULSD and theUnited 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. OurToledo refinery has a product slate of approximately 53% gasoline, 30% distillate, 4% high-value petrochemicals (including nonene, tetramer, benzene, xylene and toluene) with the remaining portion of the product slate comprised of lower-value products (4% LPGs, 8% black oil and 1% other). For this reason, we believe the WTI (Chicago ) 4-3-1 is an appropriate benchmark industry refining margin. The majority ofToledo revenues are generated offChicago -based market prices. 77 --------------------------------------------------------------------------------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: •theToledo 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; •theToledo refinery configuration enables it to produce more barrels of product than throughput which generates a pricing benefit; and •theToledo refinery generates a pricing benefit on some of its refined products, primarily its petrochemicals.Chalmette Refinery . The benchmark refining margin for theChalmette refinery is calculated by assuming two barrels of LLS crude oil are converted into one barrel of gasoline and one barrel of diesel. We calculate this benchmark using theUS 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. OurChalmette refinery has a product slate of approximately 42% gasoline and 32% distillate, 2% high-value petrochemicals with the remaining portion of the product slate comprised of lower-value products (9% 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 ofChalmette revenues are generated offGulf Coast -based market prices.The Chalmette refinery's realized gross margin on a per barrel basis has historically differed from the LLS (Gulf Coast ) 2-1-1 benchmark refining margin due to the following factors: •theChalmette refinery has generally processed a slate of primarily medium and heavy sour crude oils, which has historically constituted approximately 65% to 75% of total throughput. The remaining throughput consists of sweet crude oil and other feedstocks and blendstocks; and •as a result of the heavy, sour crude slate processed atChalmette , 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, the 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 to capture the potential benefit in the price for heavy and high-sulfur feedstocks. The unit has increased the refinery's total coking capacity to approximately 40,000 barrels per day.Torrance Refinery . The benchmark refining margin for theTorrance refinery is calculated by assuming that four barrels of ANS crude oil are converted into three barrels of gasoline, one-half barrel of diesel and one-half barrel of jet fuel. We calculate this benchmark using the West Coast Los Angeles market value ofCalifornia reformulated blendstock for oxygenate blending ("CARBOB"), CARB diesel and jet fuel and refer to the benchmark as the ANS (West Coast ) 4-3-1 benchmark refining margin. OurTorrance refinery has a product slate of approximately 64% gasoline and 19% distillate with the remaining portion of the product slate comprised of lower-value products (3% LPG, 3% black oil and 11% other). For this reason, we believe the ANS (West Coast ) 4-3-1 is an appropriate benchmark industry refining margin. The majority of Torrance revenues are generated off West Coast Los Angeles-based market prices. 78 --------------------------------------------------------------------------------The Torrance refinery's realized gross margin on a per barrel basis has historically differed from the ANS (West Coast ) 4-3-1 benchmark refining margin due to the following factors: •theTorrance 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 anAmerican Petroleum Institute ("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 theMartinez 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 ofCalifornia reformulated blendstock for oxygenate blending (CARBOB), CARB diesel and jet fuel and refer to the benchmark as the ANS (West Coast ) 3-2-1 benchmark refining margin. OurMartinez refinery has a product slate of approximately 56% gasoline and 34% distillate with the remaining portion of the product slate comprised of lower-value products (4% petroleum coke, 3% LPG and 3% other). For this reason, we believe the ANS (West Coast ) 3-2-1 is an appropriate benchmark industry refining margin. The majority ofMartinez 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: •theMartinez 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 atMartinez , we produce lower-value products including petroleum coke and sulfur. These products are priced at a significant discount to gasoline and CARB diesel. 79 -------------------------------------------------------------------------------- Results of Operations The tables below reflect our consolidated financial and operating highlights for the years endedDecember 31, 2020 , 2019 and 2018 (amounts in millions, except per share data). Differences between the results of operations ofPBF Energy andPBF LLC primarily pertain to income taxes, interest expense and noncontrolling interest as shown below. Earnings per share information applies only to the financial results ofPBF 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 logistics 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 revenues and a significant portion of its operating results eliminated in consolidation. 80 --------------------------------------------------------------------------------
PBF Energy Year Ended December 31, 2020 2019 2018 Revenues$ 15,115.9 $ 24,508.2 $ 27,186.1 Cost and expenses: Cost of products and other 14,275.6 21,387.5 24,503.4 Operating expenses (excluding depreciation and amortization expense as reflected below) 1,918.3 1,782.3 1,721.0 Depreciation and amortization expense 551.7 425.3 359.1 Cost of sales 16,745.6 23,595.1 26,583.5 General and administrative expenses (excluding depreciation and amortization expense as reflected below) 248.5 284.0 277.0 Depreciation and amortization expense 11.3 10.8 10.6 Change in fair value of contingent consideration (93.7) (0.8) - Impairment expense 98.8 - - Gain on sale of assets (477.8) (29.9) (43.1) Total cost and expenses 16,532.7 23,859.2 26,828.0 Income (loss) from operations (1,416.8) 649.0 358.1 Other income (expense): Interest expense, net (258.2) (159.6) (169.9) Change in Tax Receivable Agreement liability 373.5 - 13.9 Change in fair value of catalyst obligations (11.8) (9.7) 5.6 Debt extinguishment costs (22.2) - - Other non-service components of net periodic benefit cost 4.3 (0.2) 1.1 Income (loss) before income taxes (1,331.2) 479.5 208.8 Income tax expense 2.1 104.3 33.5 Net income (loss) (1,333.3) 375.2 175.3 Less: net income attributable to noncontrolling interests 59.1 55.8 47.0 Net income (loss) attributable to PBF Energy Inc. stockholders$ (1,392.4) $ 319.4 $ 128.3 Consolidated gross margin$ (1,629.7) $ 913.1 $ 602.6 Gross refining margin (1)$ 496.8
Net income available to Class A common stock per share: Basic$ (11.64) $ 2.66 $ 1.11 Diluted$ (11.64) $ 2.64 $ 1.10 ----------
(1) See Non-GAAP Financial Measures.
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PBF LLC Year Ended December 31, 2020 2019 2018 Revenues$ 15,115.9 $ 24,508.2 $ 27,186.1 Cost and expenses: Cost of products and other 14,275.6 21,387.5 24,503.4 Operating expenses (excluding depreciation and amortization expense as reflected below) 1,918.3 1,782.3 1,721.0 Depreciation and amortization expense 551.7 425.3 359.1 Cost of sales 16,745.6 23,595.1 26,583.5 General and administrative expenses (excluding depreciation and amortization expense as reflected below) 247.7 282.3 275.2 Depreciation and amortization expense 11.3 10.8 10.6 Change in fair value of contingent consideration (93.7) (0.8) - Impairment expense 98.8 - - Gain on sale of assets (477.8) (29.9) (43.1) Total cost and expenses 16,531.9 23,857.5 26,826.2 Income (loss) from operations (1,416.0) 650.7 359.9 Other income (expense): Interest expense, net (268.5) (169.1) (178.5) Change in fair value of catalyst obligations (11.8) (9.7) 5.6 Debt extinguishment costs (22.2) - - Other non-service components of net periodic benefit cost 4.3 (0.2) 1.1 Income (loss) before income taxes (1,714.2) 471.7 188.1 Income tax expense (benefit) 6.1 (8.3) 8.0 Net income (loss) (1,720.3) 480.0 180.1 Less: net income attributable to noncontrolling interests 76.2 51.5 42.3 Net income (loss) attributable to PBF Energy Company LLC$ (1,796.5) $ 428.5 $ 137.8 82
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Operating Highlights Year Ended December 31, 2020 2019 2018 Key Operating Information Production (bpd in thousands) 737.1 825.2 854.5 Crude oil and feedstocks throughput (bpd in thousands) 727.7 823.1 849.7
Total crude oil and feedstocks throughput (millions of barrels)
266.3 300.4 310.0 Consolidated gross margin per barrel of throughput$ (6.12)
$ 3.23 $ 8.51 $ 9.09 Refinery operating expense, per barrel of throughput$ 6.89
Crude and feedstocks (% of total throughput) (2) Heavy 42 % 32 % 36 % Medium 26 % 28 % 30 % Light 17 % 26 % 21 % Other feedstocks and blends 15 % 14 % 13 % Total throughput 100 % 100 % 100 % Yield (% of total throughput) Gasoline and gasoline blendstocks 51 % 49 % 50 % Distillates and distillate blendstocks 30 % 32 % 32 % Lubes 1 % 1 % 1 % Chemicals 1 % 2 % 2 % Other 18 % 16 % 16 % Total yield 101 % 100 % 101 % ---------- (1) See Non-GAAP Financial Measures. (2) We define heavy crude oil as crude oil with an API gravity of less than 24 degrees. We define medium crude oil as crude oil with an API gravity between 24 and 35 degrees. We define light crude oil as crude oil with an API gravity higher than 35 degrees. 83 --------------------------------------------------------------------------------
The table below summarizes certain market indicators relating to our operating results as reported by Platts.
Year Ended December 31, 2020 2019 2018 (dollars per barrel, except as noted) Dated Brent crude oil $ 41.62$ 64.34 $ 71.34 West Texas Intermediate (WTI) crude oil $ 39.25$ 57.03 $ 65.20 Light Louisiana Sweet (LLS) crude oil $ 41.13$ 62.67 $ 70.23 Alaska North Slope (ANS) crude oil $ 42.20$ 65.00 $ 71.54 Crack Spreads Dated Brent (NYH) 2-1-1 $ 9.11$ 12.68 $ 13.17 WTI (Chicago) 4-3-1 $ 6.30$ 15.25 $ 14.84 LLS (Gulf Coast) 2-1-1 $ 7.59$ 12.43 $ 12.30 ANS (West Coast-LA) 4-3-1 $ 11.30$ 18.46 $ 15.48 ANS (West Coast-SF) 3-2-1 $ 9.99$ 17.16 $ 14.49 Crude Oil Differentials Dated Brent (foreign) less WTI $ 2.37$ 7.31 $ 6.14 Dated Brent less Maya (heavy, sour) $ 5.37$ 6.76 $ 8.70 Dated Brent less WTS (sour) $ 2.33$ 8.09 $ 13.90 Dated Brent less ASCI (sour) $ 1.81$ 3.73 $ 4.64 WTI less WCS (heavy, sour) $ 10.72$ 13.61 $ 26.93 WTI less Bakken (light, sweet) $ 2.41$ 0.66 $ 2.86 WTI less Syncrude (light, sweet) $ 2.13$ 0.18 $ 6.84 WTI less LLS (light, sweet) $ (1.88)$ (5.64) $ (5.03) WTI less ANS (light, sweet) $ (2.95)$ (7.97) $ (6.34) Natural gas (dollars per MMBTU) $ 2.13
2020 Compared to 2019 Overview-PBF Energy net loss was$(1,333.3) million for the year endedDecember 31, 2020 compared to net income of$375.2 million for the year endedDecember 31, 2019 .PBF LLC net loss was$(1,720.3) million for the year endedDecember 31, 2020 compared to net income of$480.0 million for the year endedDecember 31, 2019 . Net loss attributable toPBF Energy stockholders was$(1,392.4) million , or$(11.64) per diluted share, for the year endedDecember 31, 2020 ($(11.64 ) per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net loss, or$(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 toPBF Energy stockholders of$319.4 million , or$2.64 per diluted share, for the year endedDecember 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 attributable toPBF Energy stockholders representsPBF Energy's equity interest inPBF LLC's pre-tax income, less applicable income tax expense.PBF Energy's weighted-average equity interest inPBF LLC was 99.1% and 99.0% for the years endedDecember 31, 2020 and 2019, respectively. 84 -------------------------------------------------------------------------------- Our results for the year endedDecember 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 ourTorrance refinery of$8.1 million , or$5.9 million net of tax, a change in fair value of the contingent consideration related to both the Martinez Acquisition and the East Coast Storage Asset Acquisition 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 endedDecember 31, 2020 were negatively impacted by special items consisting 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 the 2023 Senior Notes of$22.2 million , or$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 write-down of certain assets and project abandonments, early return of certain 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 associated with the remeasurement of certain deferred tax assets. Our results for the year endedDecember 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 ourTorrance refinery of$33.1 million , or$24.9 million net of tax. The LCM inventory adjustments were recorded due to movements in the price of crude oil and refined products in the periods presented. Excluding the impact of these special items, our 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 products sold and operating income. In addition, during the year endedDecember 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 endedDecember 31, 2020 compared to the prior year. Our results for the year endedDecember 31, 2020 were negatively impacted by higher general and administrative expenses associated with integration costs associated with the Martinez Acquisition and increased depreciation and amortization expense associated with the Martinez Acquisition and accelerated amortization costs associated with the East Coast Refining Reconfiguration. Revenues- Revenues totaled$15.1 billion for the year endedDecember 31, 2020 compared to$24.5 billion for the year endedDecember 31, 2019 , a decrease of approximately$9.4 billion or 38.4%. Revenues per barrel sold were$49.43 and$69.93 for the years endedDecember 31, 2020 and 2019, respectively, a decrease of 29.3% directly related to lower hydrocarbon commodity prices. For the year endedDecember 31, 2020 , the total throughput rates at ourEast Coast , Mid-Continent,Gulf Coast andWest Coast refineries averaged approximately 263,000 bpd, 96,700 bpd, 137,700 bpd and 230,300 bpd, respectively. For the year endedDecember 31, 2019 , the total throughput rates at ourEast Coast , Mid-Continent,Gulf Coast andWest Coast refineries averaged approximately 336,400 bpd, 153,000 bpd, 177,900 bpd and 155,800 bpd, respectively. For the year endedDecember 31, 2020 , the total barrels sold at ourEast Coast , Mid-Continent,Gulf Coast andWest Coast refineries averaged approximately 296,200 bpd, 114,500 bpd, 159,700 bpd and 265,200 bpd, respectively. For the year endedDecember 31, 2019 , the total barrels sold at ourEast Coast , Mid-Continent,Gulf Coast andWest Coast refineries averaged approximately 382,500 bpd, 163,900 bpd, 225,300 bpd and 188,600 bpd, respectively. The throughput rates at our refineries were lower in the year endedDecember 31, 2020 compared to the same period in 2019. OurMartinez refinery was not acquired until the first quarter of 2020 and is therefore not included in the prior periodWest Coast throughput. We operated our refineries at reduced rates beginning inMarch 2020 , and, based on current market conditions, we plan on continuing to operate our refineries at lower utilization until such time that sustained product demand justifies higher production. Total refined product barrels sold were higher than throughput rates, reflecting sales from inventory, as well as sales and purchases of refined products outside our refineries. 85 -------------------------------------------------------------------------------- Consolidated Gross Margin- Consolidated gross margin totaled$(1,629.7) million for the year endedDecember 31, 2020 , compared to$913.1 million for the year endedDecember 31, 2019 , a decrease of$2,542.8 million . Gross refining margin (as described below in Non-GAAP Financial Measures) totaled$496.8 million , or$1.86 per barrel of throughput, for the year endedDecember 31, 2020 compared to$2,801.2 million , or$9.34 per barrel of throughput, for the year endedDecember 31, 2019 , a decrease of approximately$2,304.4 million . Gross refining margin excluding special items totaled$860.3 million , or$3.23 per barrel of throughput, for the year endedDecember 31, 2020 compared to$2,551.0 million , or$8.51 per barrel of throughput, for the year endedDecember 31, 2019 , a decrease of$1,690.7 million . Consolidated gross margin and gross refining margin were negatively impacted in the current year by a non-cash LCM inventory adjustment of approximately$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 ourEast Coast inventory experienced as part of theEast 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 endedDecember 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 from the year endedDecember 31, 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 endedDecember 31, 2020 in comparison to$122.7 million for the year endedDecember 31, 2019 . Average industry margins were mixed during the year endedDecember 31, 2020 compared with the prior year, primarily due to the 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 first half of the prior year. On theEast Coast , the Dated Brent (NYH) 2-1-1 industry crack spread was approximately$9.11 per barrel, or 28.2% lower, in the year endedDecember 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 theEast 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 endedDecember 31, 2020 , as compared to$15.25 per barrel in the prior year. Our margins were positively impacted from our refinery specific slate in the Mid-Continent by an increasing WTI/Bakken differential, which averaged$2.41 per barrel in the year endedDecember 31, 2020 , as compared to$0.66 per barrel in the prior year. Additionally, the WTI/Syncrude differential averaged$2.13 per barrel for the year endedDecember 31, 2020 as compared to$0.18 per barrel in the prior year. On theGulf Coast , the LLS (Gulf Coast ) 2-1-1 industry crack spread was$7.59 per barrel, or 38.9% lower, in the year endedDecember 31, 2020 as compared to$12.43 per barrel in the prior year. Margins on theGulf 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 endedDecember 31, 2020 as compared to a premium of$5.64 per barrel in the prior year. 86 -------------------------------------------------------------------------------- On theWest Coast , the ANS (West Coast ) 4-3-1 industry crack spread was$11.30 per barrel, or 38.8% lower, in the year endedDecember 31, 2020 as compared to$18.46 per barrel in the prior year. Additionally, margins on theWest 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 endedDecember 31, 2020 as compared to a premium of$7.97 per barrel in the prior year. 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. Operating Expenses- Operating expenses totaled$1,918.3 million for the year endedDecember 31, 2020 compared to$1,782.3 million for the year endedDecember 31, 2019 , an increase of approximately$136.0 million , or 7.6%. Of the total$1,918.3 million of operating expenses for the year endedDecember 31, 2020 ,$1,835.2 million , or$6.89 per barrel of throughput, related to expenses incurred by the Refining segment, while the remaining$83.1 million related to expenses incurred by the Logistics segment ($1,684.3 million or$5.61 per barrel of throughput, and$98.0 million of operating expenses for the year endedDecember 31, 2019 related to the Refining and Logistics segments, respectively). Increases in operating expenses were due to costs associated with theMartinez refinery and related logistic assets which totaled approximately$356.1 million for the year endedDecember 31, 2020 . Total operating expenses for the year endedDecember 31, 2020 excluding ourMartinez refinery , decreased due to our 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 endedDecember 31, 2020 , compared to$284.0 million for the year endedDecember 31, 2019 , a decrease of$35.5 million or 12.5%. The decrease in general and administrative expenses for the year endedDecember 31, 2020 in comparison to the year endedDecember 31, 2019 primarily relates to reduction in our workforce as a result of the East Coast Refining Reconfiguration and reduction in overhead expenses through temporary salary reductions to a large portion of our workforce. These costs decreases were offset by headcount reduction severance costs across the refineries as well as integration costs pertaining to the Martinez Acquisition. Our general and administrative expenses are comprised of personnel, facilities and other infrastructure costs necessary to support our refineries and related logistics assets. Gain on Sale of Assets- There was a gain of$477.8 million for the year endedDecember 31, 2020 related primarily to the sale of five hydrogen plants and the sale of a parcel of land at ourTorrance refinery . There was a gain on sale of assets of$29.9 million for the year endedDecember 31, 2019 , primarily attributable to the sale of a parcel of land at ourTorrance refinery . Depreciation and Amortization Expense- Depreciation and amortization expense totaled$563.0 million for the year endedDecember 31, 2020 (including$551.7 million recorded within Cost of sales) compared to$436.1 million for the year endedDecember 31, 2019 (including$425.3 million recorded within Cost of sales), an increase of$126.9 million . The increase was a result of additional depreciation expense associated with the assets acquired in theMartinez Acquisition and a general increase in our fixed asset base due to capital projects and turnarounds completed 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 Fair Value of Contingent Consideration- Change in fair value of contingent consideration represented a gain of$93.7 million and$0.8 million for the years endedDecember 31, 2020 andDecember 31, 2019 , respectively. This change represents the decrease in the estimated fair value of theMartinez Contingent Consideration and the PBFX Contingent Consideration (as defined in "Note 4 - Acquisitions" of our Notes to Consolidated Financial Statements), both associated with acquisition related earn-out obligations. 87 -------------------------------------------------------------------------------- Change in Fair Value of Catalyst Obligations- Change in fair value of catalyst obligations represented a loss of$11.8 million for the year endedDecember 31, 2020 , compared to a loss of$9.7 million for the year endedDecember 31, 2019 . These 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 repurchase at fair market value on the catalyst financing arrangement termination dates. Impairment expense- Impairment expense totaled$98.8 million for the year endedDecember 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 prior year. Change in Tax Receivable Agreement Liability- Change in Tax Receivable Agreement liability for the year endedDecember 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, Income Taxes, 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 endedDecember 31, 2019 . Debt Extinguishment Costs- Debt extinguishment costs of$22.2 million incurred in the year endedDecember 31, 2020 relate to the early redemption of our 2023 Senior Notes. There were no such costs in the same period of 2019. Interest Expense, net-PBF Energy interest expense totaled$258.2 million for the year endedDecember 31, 2020 , compared to$159.6 million for the year endedDecember 31, 2019 , an increase of$98.6 million . This net increase is mainly attributable to higher interest costs associated with the issuance of the 2028 Senior Notes inJanuary 2020 , the issuance of the 2025 Senior Secured Notes inMay 2020 andDecember 2020 , as well as higher outstanding borrowings on our Revolving Credit Facility. Interest expense includes interest on long-term debt including the PBFX credit facilities, costs related to the sale and leaseback of our precious metal catalysts, financing costs associated with the Inventory Intermediation Agreements withJ. 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$268.5 million and$169.1 million for the year endedDecember 31, 2020 andDecember 31, 2019 , respectively (inclusive of$10.3 million and$9.5 million , respectively, of incremental interest expense on the affiliate note payable withPBF Energy that eliminates in consolidation at thePBF 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 ofChalmette 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 ofPBF LLC are required to include their proportionate share ofPBF LLC's taxable income or loss, which includesPBF 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 ofPBF 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 onPBF Energy's allocable share ofPBF LLC's pre-tax income or loss, which was approximately 99.1% and 99.0%, on a weighted-average basis for the years endedDecember 31, 2020 and 2019, respectively.PBF Energy's Consolidated Financial Statements do not reflect any benefit or provision for income taxes on the pre-tax income or loss attributable to the noncontrolling interests inPBF 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 interests, for the years endedDecember 31, 2020 and 2019 was 0.2% and 21.8%, respectively. The effective tax rate for the year endedDecember 31, 2020 was significantly impacted by the recording of a$358.4 million deferred tax asset valuation allowance. 88 -------------------------------------------------------------------------------- Noncontrolling Interest-PBF Energy is the sole managing member of, and has a controlling interest in,PBF LLC . As the sole managing member ofPBF LLC ,PBF Energy operates and controls all of the business and affairs ofPBF LLC and its subsidiaries.PBF Energy consolidates the financial results ofPBF LLC and its subsidiaries, including PBFX. With respect to the consolidation ofPBF LLC , the Company records a noncontrolling interest for the economic interest inPBF LLC held by members other thanPBF 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 ofPBF Holding , the Company records a 20% noncontrolling interest for the ownership interests in two subsidiaries ofChalmette Refining held by a third party. The total noncontrolling interest on the Consolidated Statements of Operations represents the portion of the Company's earnings or loss attributable to the economic interests held by members ofPBF LLC other thanPBF Energy , by the public common unitholders of PBFX and by the third-party stockholders of certain ofChalmette Refining's subsidiaries. The total noncontrolling interest on the Consolidated Balance Sheets represents the portion of the Company's net assets attributable to the economic interests held by the members ofPBF LLC other thanPBF Energy , by the public common unitholders of PBFX and by the third-party stockholders of the twoChalmette Refining subsidiaries.PBF Energy's weighted-average equity noncontrolling interest ownership percentage inPBF LLC for the years endedDecember 31, 2020 and 2019 was approximately 0.9% and 1.0%, respectively. The carrying amount of the noncontrolling interest on our Consolidated Balance Sheets attributable to the noncontrolling interest is not equal to the noncontrolling interest ownership percentage due to the effect of income taxes and related agreements that pertain solely toPBF Energy . 2019 Compared to 2018 Overview-PBF Energy net income was$375.2 million for the year endedDecember 31, 2019 compared to net income of$175.3 million for the year endedDecember 31, 2018 .PBF LLC net income was$480.0 million for the year endedDecember 31, 2019 compared to net income of$180.1 million for the year endedDecember 31, 2018 . Net income attributable toPBF Energy stockholders was$319.4 million , or$2.64 per diluted share, for the year endedDecember 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) compared to net income attributable toPBF Energy stockholders of$128.3 million , or$1.10 per diluted share, for the year endedDecember 31, 2018 ($1.10 per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income, or$3.26 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 attributable toPBF Energy stockholders representsPBF Energy's equity interest inPBF LLC's pre-tax income, less applicable income tax expense.PBF Energy's weighted-average equity interest inPBF LLC was 99.0% and 98.3% for the years endedDecember 31, 2019 and 2018, respectively. Our results for the year endedDecember 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 ourTorrance refinery of$33.1 million , or$24.9 million net of tax. Our results for the year endedDecember 31, 2018 were negatively impacted by special items consisting of a non-cash, pre-tax LCM inventory adjustment of approximately$351.3 million , or$260.0 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 benefit associated with the change in the Tax Receivable Agreement liability of$13.9 million , or$10.3 million net of tax, and a pre-tax gain on the sale of land at ourTorrance refinery of$43.8 million , or$32.4 million net of tax. 89 -------------------------------------------------------------------------------- Excluding the impact of these special items, our results were negatively impacted by unfavorable movements in crude differentials and overall lower throughput volumes and barrels sold across our refineries, partially offset by higher crack spreads realized at ourWest Coast refinery . Refining margins for the current year compared to the prior year were weaker at ourEast Coast , Mid-Continent andGulf Coast refineries, offset by significantly stronger margins realized on theWest Coast . Our results for the year endedDecember 31, 2019 were also negatively impacted by increased operating expenses and depreciation and amortization expense associated with our continued investment in our refining assets and the effect of significant turnaround and maintenance activity during 2019. Revenues- Revenues totaled$24.5 billion for the year endedDecember 31, 2019 compared to$27.2 billion for the year endedDecember 31, 2018 , a decrease of approximately$2.7 billion , or 9.9%. Revenues per barrel sold were$69.93 and$77.08 for the years endedDecember 31, 2019 and 2018, respectively, a decrease of 9.3% directly related to lower hydrocarbon commodity prices. For the year endedDecember 31, 2019 , the total throughput rates at ourEast Coast , Mid-Continent,Gulf Coast andWest Coast refineries averaged approximately 336,400 bpd, 153,000 bpd, 177,900 bpd and 155,800 bpd, respectively. For the year endedDecember 31, 2018 , the total throughput rates at ourEast Coast , Mid-Continent,Gulf Coast andWest Coast refineries averaged approximately 344,700 bpd, 149,600 bpd, 185,600 bpd and 169,800 bpd, respectively. The throughput rates at ourEast Coast andWest Coast refineries were lower in the year endedDecember 31, 2019 compared to the same period in 2018 due to planned downtime associated with turnarounds of the coker and associated units at ourDelaware City and Torrance refineries and the crude unit at ourPaulsboro refinery , all of which were completed in the first half of 2019, and unplanned downtime at ourDelaware City refinery in the first quarter of 2019. Throughput rates at ourMid-Continent refinery were higher in the year endedDecember 31, 2019 compared to 2018 due to a planned turnaround at ourToledo refinery in the first half of 2018. Throughput rates at ourGulf Coast refinery were lower in the year endedDecember 31, 2019 compared to the same period in 2018 due to unplanned downtime in the fourth quarter of 2019. For the year endedDecember 31, 2019 , the total barrels sold at ourEast Coast , Mid-Continent,Gulf Coast andWest Coast refineries averaged approximately 382,500 bpd, 163,900 bpd, 225,300 bpd and 188,600 bpd, respectively. For the year endedDecember 31, 2018 , the total barrels sold at ourEast Coast , Mid-Continent,Gulf Coast andWest Coast refineries averaged approximately 372,700 bpd, 161,800 bpd, 233,700 bpd and 198,100 bpd, respectively. 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. Consolidated Gross Margin- Consolidated gross margin totaled$913.1 million for the year endedDecember 31, 2019 , compared to$602.6 million for the year endedDecember 31, 2018 , an increase of$310.5 million . Gross refining margin (as described below in Non-GAAP Financial Measures) totaled$2,801.2 million , or$9.34 per barrel of throughput, for the year endedDecember 31, 2019 compared to$2,419.4 million , or$7.79 per barrel of throughput, for the year endedDecember 31, 2018 , an increase of approximately$381.8 million . Gross refining margin excluding special items totaled$2,551.0 million , or$8.51 per barrel of throughput for the year endedDecember 31, 2019 compared to$2,823.0 million or$9.09 per barrel of throughput, for the year endedDecember 31, 2018 , a decrease of$272.0 million . Consolidated gross margin and gross refining margin were positively impacted in the year endedDecember 31, 2019 by a non-cash LCM inventory adjustment of approximately$250.2 million on a net basis, resulting from the increase in crude oil and refined product prices from the year ended 2018. Gross refining margin excluding the impact of special items decreased due to unfavorable movements in certain crude differentials and refining margins and reduced throughput rates at the majority of our refineries, partially offset by higher throughput rates in the Mid-Continent and stronger crack spreads on theWest Coast . For the year endedDecember 31, 2018 , special items impacting our margin calculations included a non-cash LCM inventory adjustment of approximately$351.3 million on a net basis, resulting from a decrease in crude oil and refined product prices and a$52.3 million charge resulting from costs associated with the early return of certain leased railcars. 90 -------------------------------------------------------------------------------- Additionally, our results continue to be impacted by significant costs to comply with the Renewable Fuel Standard, although at a reduced level from the prior year. Total Renewable Fuel Standard costs were$122.7 million for the year endedDecember 31, 2019 compared with$143.9 million for the year endedDecember 31, 2018 . Average industry margins were mixed during the year endedDecember 31, 2019 compared with the prior year, primarily as a result of varying regional product inventory levels and seasonal and unplanned refining downtime issues impacting product margins. Crude oil differentials were generally unfavorable compared with the prior year, with notable light-heavy crude differential compression negatively impacting our gross refining margin and moving our overall crude slate lighter. On theEast Coast , the Dated Brent (NYH) 2-1-1 industry crack spread was approximately$12.68 per barrel, or 3.7% lower, in the year endedDecember 31, 2019 as compared to$13.17 per barrel in the same period in 2018. Our margins were negatively impacted from our refinery specific slate on theEast Coast by tightening in the Dated Brent/Maya and WTI/Bakken differentials, which decreased$1.94 per barrel and$2.20 per barrel, respectively, in comparison to the prior year. In addition, the WTI/WCS differential decreased significantly to$13.61 per barrel in 2019 compared to$26.93 per barrel in 2018, which unfavorably impacted our cost of heavy Canadian crude. Across the Mid-Continent, the WTI (Chicago ) 4-3-1 industry crack spread was$15.25 per barrel, or 2.8% higher, in the year endedDecember 31, 2019 , as compared to$14.84 per barrel in the same period in 2018. Our margins were negatively impacted from our refinery specific slate in the Mid-Continent by a decreasing WTI/Bakken differential, which averaged approximately$0.66 per barrel in the year endedDecember 31, 2019 , as compared to$2.86 per barrel in the prior year. Additionally, the WTI/Syncrude differential averaged$0.18 per barrel for the year endedDecember 31, 2019 as compared to$6.84 per barrel in the same period of 2018. In theGulf Coast , the LLS (Gulf Coast ) 2-1-1 industry crack spread was$12.43 per barrel, or 1.1% higher, in the year endedDecember 31, 2019 as compared to$12.30 per barrel in the prior year. Margins in theGulf Coast were negatively impacted from our refinery specific slate by a weakening WTI/LLS differential, which averaged a premium of$5.64 for the year endedDecember 31, 2019 as compared to a premium of$5.03 per barrel experienced in the prior year. On theWest Coast , the ANS (West Coast ) 4-3-1 industry crack spread was$18.46 per barrel, or 19.3% higher, in the year endedDecember 31, 2019 as compared to$15.48 per barrel in the same period in 2018. Margins on theWest Coast were negatively impacted from our refinery specific slate by a weakening WTI/ANS differential, which averaged a premium of$7.97 per barrel for the year endedDecember 31, 2019 as compared to a premium of$6.34 per barrel in the same period of 2018. 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. Operating Expenses- Operating expenses totaled$1,782.3 million for the year endedDecember 31, 2019 compared to$1,721.0 million for the year endedDecember 31, 2018 , an increase of approximately$61.3 million , or 3.6%. Of the total$1,782.3 million of operating expenses for the year endedDecember 31, 2019 ,$1,684.3 million , or$5.61 per barrel of throughput, related to expenses incurred by the Refining segment, while the remaining$98.0 million related to expenses incurred by the Logistics segment ($1,654.8 million or$5.34 per barrel of throughput, and$66.2 million of operating expenses for the year endedDecember 31, 2018 related to the Refining and Logistics segments respectively). Increases in operating expenses were mainly attributed to higher outside service costs related to turnaround and maintenance activity. Operating expenses related to our Logistics segment increased when compared to 2018 due to expenses related to the operations of PBFX's recently acquired assets and higher environmental clean-up remediation costs and product contamination remediation costs. 91 -------------------------------------------------------------------------------- General and Administrative Expenses- General and administrative expenses totaled$284.0 million for the year endedDecember 31, 2019 , compared to$277.0 million for the year endedDecember 31, 2018 , an increase of$7.0 million or 2.5%. The increase in general and administrative expenses for the year endedDecember 31, 2019 compared with the year endedDecember 31, 2018 primarily related to higher outside services, including legal settlement charges, and transaction costs related to the Martinez Acquisition, partially offset by a reduction in incentive compensation. Our general and administrative expenses are comprised of personnel, facilities and other infrastructure costs necessary to support our refineries and related logistics assets. Gain on Sale of Assets- Gain on sale of assets was$29.9 million and$43.1 million for the year endedDecember 31, 2019 andDecember 31, 2018 , respectively, mainly attributed to the sale of two separate parcels of land at ourTorrance refinery . Depreciation and Amortization Expense- Depreciation and amortization expense totaled$436.1 million for the year endedDecember 31, 2019 (including$425.3 million recorded within Cost of sales) compared to$369.7 million for the year endedDecember 31, 2018 (including$359.1 million recorded within Cost of sales), an increase of$66.4 million . The increase was a result of additional depreciation expense associated with a general increase in our fixed asset base due to capital projects and turnarounds completed during 2019 and 2018, as well as accelerated amortization related to theDelaware City andTorrance refinery turnarounds, which were completed in the first half of 2019. Change in Tax Receivable Agreement Liability- There was no change in the Tax Receivable Agreement liability for the year endedDecember 31, 2019 . Change in the Tax Receivable Agreement liability for the year endedDecember 31, 2018 represented a gain of$13.9 million . Change in Fair Value of Catalyst Obligations- Change in the fair value of catalyst obligations represented a loss of$9.7 million for the year endedDecember 31, 2019 , compared to a gain of$5.6 million for the year endedDecember 31, 2018 . 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 on the catalyst financing arrangement termination dates. Interest Expense, net-PBF Energy interest expense totaled$159.6 million for the year endedDecember 31, 2019 , compared to$169.9 million for the year endedDecember 31, 2018 , a decrease of$10.3 million . This net decrease is mainly attributable to lower outstanding revolver borrowings for the year endedDecember 31, 2019 . Interest expense includes interest on long-term debt including the PBFX credit facilities, costs related to the sale and leaseback of our precious metal catalysts, financing costs associated with the Inventory Intermediation Agreements withJ. Aron , letter of credit fees associated with the purchase of certain crude oils and the amortization of deferred financing costs.PBF LLC interest expense totaled$169.1 million and$178.5 million for the year endedDecember 31, 2019 and 2018, respectively (inclusive of$9.5 million and$8.6 million , respectively, of incremental interest expense on the affiliate note payable withPBF Energy that eliminates in consolidation at thePBF 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 ofChalmette Refining andPBF Ltd. are treated as C-Corporations for income tax purposes and may incur income taxes with respect to their earnings, as applicable. The members ofPBF LLC are required to include their proportionate share ofPBF LLC's taxable income or loss, which includesPBF 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 ofPBF 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 onPBF Energy's allocable share ofPBF LLC's pre-tax income or loss, which was approximately 99.0% and 98.3%, on a weighted-average basis for the years endedDecember 31, 2019 and 2018, respectively.PBF Energy's Consolidated Financial Statements do not reflect any benefit or provision for income taxes on the pre-tax income or loss attributable to the noncontrolling interests inPBF LLC or PBFX (although, as described above,PBF LLC must make tax distributions to all its members on a 92 -------------------------------------------------------------------------------- pro-rata basis).PBF Energy's effective tax rate, excluding the impact of noncontrolling interest, for the years endedDecember 31, 2019 and 2018 was 21.8% and 16.0%, respectively, reflecting tax adjustments for discrete items and the impact of tax return to income tax provision adjustments. Noncontrolling Interest-PBF Energy is the sole managing member of, and has a controlling interest in,PBF LLC . As the sole managing member ofPBF LLC ,PBF Energy operates and controls all of the business and affairs ofPBF LLC and its subsidiaries.PBF Energy consolidates the financial results ofPBF LLC and its subsidiaries, including PBFX. With respect to the consolidation ofPBF LLC , the Company records a noncontrolling interest for the economic interest inPBF LLC held by members other thanPBF 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 ofPBF Holding , the Company records a 20% noncontrolling interest for the ownership interests in two subsidiaries ofChalmette Refining held by a third-party. The total noncontrolling interest on the Consolidated Statements of Operations represents the portion of the Company's earnings or loss attributable to the economic interests held by members ofPBF LLC other thanPBF Energy , by the public common unitholders of PBFX and by the third-party stockholders of certain ofChalmette Refining's subsidiaries. The total noncontrolling interest on the Consolidated Balance Sheets represents the portion of the Company's net assets attributable to the economic interests held by the members ofPBF LLC other thanPBF Energy , by the public common unitholders of PBFX and by the third-party stockholders of the twoChalmette Refining subsidiaries.PBF Energy's weighted-average equity noncontrolling interest ownership percentage inPBF LLC for the years endedDecember 31, 2019 and 2018 was approximately 1.0% and 1.7%, respectively. The carrying amount of the noncontrolling interest on our Consolidated Balance Sheets attributable to the noncontrolling interest is not equal to the noncontrolling interest ownership percentage due to the effect of income taxes and related agreements that pertain solely toPBF 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 ofPBF Energy's results and are not presented or discussed in respect toPBF 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 for the periods presented relate to LCM inventory adjustments, changes in the Tax Receivable Agreement liability, debt extinguishment costs, changes in fair value of contingent consideration, gain on sale of hydrogen plants, severance costs related to reductions in workforce, impairment expense, net tax expense on remeasurement of deferred tax assets, gains on sale of assets at ourTorrance refinery , charges associated with the early return of certain leased railcars, turnaround acceleration costs, reconfiguration costs and a LIFO inventory decrement. 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. 93 -------------------------------------------------------------------------------- Adjusted Fully-Converted Net Income (Loss) and Adjusted Fully-Converted Net Income (Loss) Excluding Special ItemsPBF Energy utilizes results presented on an Adjusted Fully-Converted basis that reflects an assumed exchange of allPBF 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 comparePBF 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 presented in accordance with GAAP. Adjusted Fully-Converted Net Income (Loss) and Adjusted Fully-Converted Net Income (Loss) excluding special items presented by other companies may not be comparable to our presentation, since each company may define these terms differently. The differences between Adjusted Fully-Converted and GAAP results are as follows:
1. Assumed exchange of all
common stock. As a result of the assumed exchange of all
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
2. Income Taxes. Prior to
liability company treated as a "flow-through" entity for income tax purposes, and
even after
income taxes. Adjustments have been made to the Adjusted Fully-Converted tax
provisions and earnings to assume that
tax structure for all periods presented and is taxed as a C-corporation in the
at the prevailing corporate rates. These assumptions are consistent with the
assumption in clause 1 above that all
shares of PBF Energy Class A common stock, as the assumed exchange would change the
amount of
94 --------------------------------------------------------------------------------
The following table reconciles
Year Ended December 31, 2020 2019 2018
Net income (loss) attributable to
0.1 0.5 0.7
Income (loss) available to
(1,392.5) 318.9 127.6
Add: Net income (loss) attributable to noncontrolling interests(1)
(17.1) 4.3 4.6 Less: Income tax benefit (expense) (2) 4.6 (1.0) (1.2) Adjusted fully-converted net income (loss) $
(1,405.0)
268.0 (250.2) 351.3 Add: Change in fair value of contingent consideration (93.7) - - Add: Gain on sale of hydrogen plants (471.1) - - Add: Gain on Torrance land sales (8.1) (33.1) (43.8) 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 - 52.3 Add: Debt extinguishment costs 22.2 - - Add: Change in Tax Receivable Agreement liability (373.5) - (13.9) Add: Net tax expense on remeasurement of deferred tax assets 259.1 - - Less: Recomputed income tax on special items 99.9 70.4 (89.9)
Adjusted fully-converted net income (loss) excluding special items
$
(1,421.7)
Weighted-average shares outstanding of PBF Energy Inc. 119,617,998 119,887,646 115,190,262 Conversion of PBF LLC Series A Units (4) 1,042,667 1,207,581 1,938,089 Common stock equivalents (5) - 758,072 1,645,255 Fully-converted shares outstanding-diluted 120,660,665 121,853,299 118,773,606 Diluted net income (loss) per share $
(11.64)
$
(11.64)
----------
See Notes to Non-GAAP Financial Measures.
95 -------------------------------------------------------------------------------- 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 (revenues less cost of products and other) to industry refining margin benchmarks and crude oil prices as defined in the table below. Neither gross refining margin nor gross refining margin excluding special items should be considered an alternative to consolidated gross margin, income from operations, net cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Gross refining margin and gross refining margin excluding special items presented by other companies may not be comparable to our presentation, since each company may define these terms differently. The following table presents our GAAP calculation of gross margin and a reconciliation of gross refining margin to the most directly comparable GAAP financial measure, consolidated gross margin, on a historical basis, as applicable, for each of the periods indicated (in millions, except per barrel amounts): Year Ended December 31, 2020 2019 2018 per barrel of per barrel of per barrel of $ throughput $ throughput $ throughput Calculation of consolidated gross margin: Revenues$ 15,115.9 $ 56.76 $ 24,508.2 $ 81.58 $ 27,186.1 $ 87.67 Less: Cost of sales 16,745.6 62.88 23,595.1 78.54 26,583.5 85.73 Consolidated gross margin$ (1,629.7) $ (6.12) $ 913.1 $ 3.04 $ 602.6 $ 1.94 Reconciliation of consolidated gross margin to gross refining margin: Consolidated gross margin$ (1,629.7) $ (6.12)
99.9 0.38 118.7 0.40 84.4 0.27 Add: PBFX depreciation expense 53.7 0.19 38.6 0.13 29.4 0.09 Less: Revenues of PBFX (360.3) (1.35) (340.2) (1.13) (281.5) (0.91) Add: Refinery operating expense 1,835.2 6.89 1,684.3 5.61 1,654.8 5.34 Add: Refinery depreciation expense 498.0 1.87 386.7 1.29 329.7 1.06 Gross refining margin$ 496.8 $ 1.86 $ 2,801.2 $ 9.34 $ 2,419.4 $ 7.79 Special Items: (3) Add: Non-cash LCM inventory adjustment 268.0 1.01 (250.2) (0.83) 351.3 1.13 Add: LIFO inventory decrement 83.0 0.31 - - - - Add: Early railcar return expense 12.5 0.05 - - 52.3 0.17 Gross refining margin excluding special items$ 860.3 $ 3.23 $ 2,551.0 $ 8.51 $ 2,823.0 $ 9.09 ----------
See Notes to Non-GAAP Financial Measures.
96 -------------------------------------------------------------------------------- EBITDA, EBITDA Excluding Special Items and Adjusted EBITDA Our management uses EBITDA (earnings before interest, income taxes, depreciation and amortization), EBITDA excluding special items and Adjusted EBITDA as measures of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with our board of directors, creditors, analysts and investors concerning our financial performance. Our outstanding indebtedness for borrowed money and other contractual obligations also include similar measures as a basis for certain covenants under those agreements which may differ from the Adjusted EBITDA definition described below. EBITDA, EBITDA excluding special items and Adjusted EBITDA are not presentations made in accordance with GAAP and our computation of EBITDA, EBITDA excluding special items and Adjusted EBITDA may vary from others in our industry. In addition, Adjusted EBITDA contains some, but not all, adjustments that are taken into account in the calculation of the components of various covenants in the agreements governing our senior notes and other credit facilities. EBITDA, EBITDA excluding special items and Adjusted EBITDA should not be considered as alternatives to income from operations or net income as measures of operating performance. In addition, EBITDA, EBITDA excluding special items and Adjusted EBITDA are not presented as, and should not be considered, an alternative to cash flows from operations as a measure of liquidity. Adjusted EBITDA is defined as EBITDA before adjustments for items such as stock-based compensation expense, the non-cash change in the fair value of catalyst obligations, gain on sale of hydrogen plants, the write down of inventory to the LCM, changes in the liability related to the Tax Receivable Agreement due to factors out ofPBF Energy's control such as changes in tax rates, debt extinguishment costs 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. 97 -------------------------------------------------------------------------------- The following tables reconcile net income (loss) as reflected inPBF Energy's results of operations to EBITDA, EBITDA excluding special items and Adjusted EBITDA for the periods presented (in millions):
Year Ended
2020 2019 2018
Reconciliation of net income (loss) to EBITDA and EBITDA excluding special items: Net income (loss)
$ (1,333.3) $ 375.2 $ 175.3 Add: Depreciation and amortization expense 563.0 436.1 369.7 Add: Interest expense, net 258.2 159.6 169.9 Add: Income tax expense 2.1 104.3 33.5 EBITDA$ (510.0)
Special Items: (3) Add: Non-cash LCM inventory adjustment 268.0 (250.2) 351.3 Add: Change in fair value of contingent consideration (93.7) - - Add: Gain on sale of hydrogen plants (471.1) - - Add: Gain on Torrance land sales (8.1) (33.1) (43.8) Add: Impairment expense 98.8 - - Add: LIFO inventory decrement 83.0 - - Add: Severance and reconfiguration costs 30.0 - - Add: Early railcar return expense 12.5 - 52.3 Add: Debt extinguishment costs 22.2 - - Add: Change in Tax Receivable Agreement liability (373.5) - (13.9) EBITDA excluding special items$ (941.9)
Reconciliation of EBITDA to Adjusted EBITDA: EBITDA$ (510.0) $ 1,075.2 $ 748.4 Add: Stock based compensation 34.2 37.3 26.0 Add: Change in fair value of catalyst obligations 11.8 9.7 (5.6) Add: Non-cash LCM inventory adjustment (3) 268.0 (250.2) 351.3
Add: Change in fair value of contingent consideration (3)
(93.7) - - Add: Gain on sale of hydrogen plants (3) (471.1) - - Add: Gain on Torrance land sales (3) (8.1) (33.1) (43.8) Add: Impairment expense (3) 98.8 - - Add: LIFO inventory decrement (3) 83.0 - - Add: Severance and reconfiguration costs (3) 30.0 - - Add: Early railcar return expense (3) 12.5 - 52.3 Add: Debt extinguishment costs (3) 22.2 - - Add: Change in Tax Receivable Agreement liability (3) (373.5) - (13.9) Adjusted EBITDA$ (895.9) $ 838.9 $ 1,114.7 ----------
See Notes to Non-GAAP Financial Measures.
98 -------------------------------------------------------------------------------- Notes to Non-GAAP Financial Measures The following notes are applicable to the Non-GAAP Financial Measures above: (1) Represents the elimination of the noncontrolling interest associated with the ownership by the members ofPBF LLC other thanPBF Energy , as if such members had fully exchanged theirPBF LLC Series A Units for shares of PBF Energy Class A common stock. (2) Represents an adjustment to reflectPBF Energy's annualized statutory corporate tax rate of approximately 26.6%, 24.9% and 26.0% for the 2020, 2019 and 2018 periods, respectively, applied to the net income (loss) attributable to noncontrolling interest for all periods presented. The adjustment assumes the full exchange of existingPBF LLC Series A Units as described in (1) above. (3) Special items: LCM inventory adjustment - LCM is a GAAP requirement related to inventory valuation that mandates inventory to be stated at the lower of cost or market. Our inventories are stated at the lower of cost or market. Cost is determined using the LIFO inventory valuation methodology, in which the most recently incurred costs are charged to cost of sales and inventories are valued at base layer acquisition costs. Market is determined based on an assessment of the current estimated replacement cost and net realizable selling price of the inventory. In periods where the market price of our inventory declines substantially, cost values of inventory may exceed market values. In such instances, we record an adjustment to write down the value of inventory to market value in accordance with GAAP. In subsequent periods, the value of inventory is reassessed and an LCM inventory adjustment is recorded to reflect the net change in the LCM inventory reserve between the prior period and the current period. The net impact of these LCM inventory adjustments are included in the Refining segment's income from operations, but are excluded from the operating results presented, as applicable, in order to make such information comparable between periods. The following table includes the LCM inventory reserve as of each date presented (in millions): 2020 2019 2018 January 1,$ 401.6 $ 651.8 $ 300.5 December 31, 669.6 401.6 651.8 The following table includes the corresponding impact of changes in the LCM inventory reserve on income (loss) from operations and net income (loss) for the periods presented (in millions): Year Ended
2020 2019 2018 Net LCM inventory adjustment (charge) benefit in income (loss) from operations$ (268.0) $ 250.2 $ (351.3) Net LCM inventory adjustment (charge) benefit in net income (loss) (196.7) 188.0 (260.0)
Change in fair value of contingent consideration - During the year ended
99 -------------------------------------------------------------------------------- Gain on sale of hydrogen plants - During the year endedDecember 31, 2020 , we recorded a gain on the sale of five hydrogen plants. The gain increased income from operations and net income by$471.1 million and$345.8 million , respectively. There were no such gains in the years endedDecember 31, 2019 andDecember 31, 2018 . Gain on Torrance land sales - During the years endedDecember 31, 2020 ,December 31, 2019 andDecember 31, 2018 , we recorded gains on the sale of three separate parcels of real property acquired as part of theTorrance refinery , but not part of the refinery itself. The gain on sale increased income from operations and net income by$8.1 million and$5.9 million , respectively, during the year endedDecember 31, 2020 . The gain on sale increased income from operations and net income by$33.1 million and$24.9 million , respectively, during the year endedDecember 31, 2019 . The gain on sale increased income from operations and net income by$43.8 million and$32.4 million , respectively, during the year endedDecember 31, 2018 . Impairment expense - During the year endedDecember 31, 2020 , we recorded an impairment charge which decreased income from operations and net income by$98.8 million and$72.5 million , respectively, resulting from the write-down of certain assets as a result of the East Coast Refining Reconfiguration, project abandonments and the write-down of certain PBFX long-lived assets. There were no such charges during the years endedDecember 31, 2019 andDecember 31, 2018 . LIFO inventory decrement - As part of our overall reduction in throughput in 2020 and our reduction in inventory volume as ofDecember 31, 2020 , the Company recorded a pre-tax charge to cost of products and other related to a LIFO inventory layer decrement. The majority of the decrement related to our East Coast LIFO inventory layer and the reduction to ourEast Coast inventory experienced as part of the East Coast Refining Reconfiguration. These charges decreased income from operations and net income by$83.0 million and$60.9 million , respectively, for the year endedDecember 31, 2020 . Decrements recorded in the years endedDecember 31, 2019 andDecember 31, 2018 were not significant. Turnaround acceleration costs - During the year endedDecember 31, 2020 , we accelerated the recognition of turnaround amortization associated with units that were temporarily idled as part of the East Coast Refining Reconfiguration. These costs decreased income from operations and net income by$56.2 million and$41.3 million , respectively. There were no such costs in the years endedDecember 31, 2019 andDecember 31, 2018 . Severance and reconfiguration costs - During the year endedDecember 31, 2020 , we recorded severance charges related to reductions in our workforce. These charges decreased income from operations and net income by$24.7 million and$18.1 million , respectively. There were no such costs in the years endedDecember 31, 2019 andDecember 31, 2018 . During the year endedDecember 31, 2020 , we recorded reconfiguration charges related to the temporary idling of certain assets as part of our East Coast Refining System. These charges decreased income from operations and net income by$5.3 million and$3.9 million , respectively. There were no such costs in the years endedDecember 31, 2019 andDecember 31, 2018 . Early return of railcars - During the years endedDecember 31, 2020 andDecember 31, 2018 we recognized certain expenses within Cost of sales associated with the voluntary early return of certain leased railcars. These charges decreased income from operations and net income by$12.5 million and$9.2 million , respectively, during the year endedDecember 31, 2020 . These charges decreased income from operations and net income by$52.3 million and$38.7 million , respectively, during the year endedDecember 31, 2018 . There were no such expenses recorded in the year endedDecember 31, 2019 . 100 -------------------------------------------------------------------------------- Debt extinguishment costs - During the year endedDecember 31, 2020 , we recorded pre-tax debt extinguishment costs of$22.2 million related to the redemption of the 2023 Senior Notes. These nonrecurring charges decreased net income by$16.3 million for the year endedDecember 31, 2020 . There were no such costs in the years endedDecember 31, 2019 andDecember 31, 2018 . Change in Tax Receivable Agreement liability - During the year endedDecember 31, 2020 , we recorded a change in the Tax Receivable Agreement liability that increased income before income taxes and net income by$373.5 million and$274.1 million , respectively. During the year endedDecember 31, 2018 ,PBF Energy recorded a change in the Tax Receivable Agreement liability that increased income before taxes and net income by$13.9 million and$10.3 million , respectively. There was no such change during the year endedDecember 31, 2019 . The changes in the Tax Receivable Agreement liability reflect charges or benefits attributable to changes inPBF Energy's obligation under the Tax Receivable Agreement due to factors out of our control such as changes in tax rates, as well as periodic adjustments to our liability based, in part, on an updated estimate of the amounts that we expect to pay, using assumptions consistent with those used in our concurrent estimate of the deferred tax asset valuation allowance. Net tax expense on remeasurement of deferred tax assets - During the year endedDecember 31, 2020 , we recorded a deferred tax valuation allowance of$358.4 million in accordance with ASC 740, Income Taxes. This amount includes tax expense of approximately$99.3 million related to our net change in the Tax Receivable Agreement liability or a net tax expense of$259.1 million related primarily to the remeasurement of deferred tax assets. There was no such expense in the years endedDecember 31, 2019 andDecember 31, 2018 . Recomputed income tax on special items - The income tax impact on special items, other than the net tax expense special item discussed below, is calculated using the tax rates shown in (2) above. (4) Represents an adjustment to weighted-average diluted shares outstanding to assume the full exchange of existingPBF LLC Series A Units as described in (1) above. (5) Represents weighted-average diluted shares outstanding assuming the conversion of all common stock equivalents, including options and warrants forPBF LLC Series A Units and performance share units and options for shares of PBF Energy Class A common stock as calculated under the treasury stock method (to the extent the impact of such exchange would not be anti-dilutive) for the years endedDecember 31, 2020 , 2019 and 2018, respectively. Common stock equivalents exclude the effects of performance share units and options and warrants to purchase 14,446,894, 6,765,526 and 1,293,242 shares of PBF Energy Class A common stock andPBF LLC Series A Units because they are anti-dilutive for the years endedDecember 31, 2020 , 2019 and 2018, respectively. For periods showing a net loss, all common stock equivalents and unvested restricted stock are considered anti-dilutive. 101 -------------------------------------------------------------------------------- Liquidity and Capital Resources Overview Typically our primary sources of liquidity are our cash flows from operations, cash and cash equivalents and borrowing availability under our credit facilities, as described below; however, due to the COVID-19 pandemic and the related governmental and consumer responses, our business and results of operations are being negatively impacted. The demand destruction as a result of the worldwide economic slowdown and governmental responses, including travel restrictions, and stay-at-home orders, has resulted in a significant decrease in the demand for and market prices of our products. In addition, the global geopolitical and macroeconomic events that took place during the first quarter of 2020 further contributed to the overall volatility in crude oil and refined product prices, contributing to an adverse impact on our liquidity. We continue to be focused on assessing and adapting to the challenging operating environment and evaluating our strategic measures to preserve liquidity and strengthen our balance sheet. Our response to the current economic environment and its impact on our liquidity is more fully described in the "Liquidity" section below. Cash Flow Analysis Cash Flows from Operating Activities Net cash used in operating activities was$(631.6) million for the year endedDecember 31, 2020 compared to net cash provided by operating activities of$933.5 million for the year endedDecember 31, 2019 . Our operating cash flows for the year endedDecember 31, 2020 included our net loss of$1,333.3 million , gain on sale of assets of$477.8 million mainly related to the sale of the hydrogen plants and the sale of land at ourTorrance refinery , change in the Tax Receivable Agreement liability of$373.5 million , net non-cash charges relating to the change in the fair value of our inventory repurchase obligations of$12.6 million and change in the fair value of the contingent consideration of$93.7 million , partially offset by depreciation and amortization of$581.1 million , net non-cash charge of$268.0 million relating to an LCM inventory adjustment, impairment expense of$98.8 million , pension and other post-retirement benefits costs of$55.7 million , stock-based compensation of$34.2 million , debt extinguishment costs related to the early redemption of our 2023 Senior Notes of$22.2 million , change in the fair value of our catalyst obligations of$11.8 million and deferred income taxes of$1.6 million . In addition, net changes in operating assets and liabilities reflects cash inflows of$585.9 million driven by the timing of inventory purchases, payments for accrued expenses and accounts payable and collections of accounts receivable. Our operating cash flows for the year endedDecember 31, 2019 included our net income of$375.2 million , depreciation and amortization of$447.5 million , deferred income tax expense of$103.7 million , pension and other post-retirement benefits costs of$44.8 million , stock-based compensation of$37.3 million , net non-cash charges relating to the change in the fair value of our inventory repurchase obligations of$25.4 million , and changes in the fair value of our catalyst obligations of$9.7 million , partially offset by a net non-cash benefit of$250.2 million relating to an LCM inventory adjustment, a gain on sale of assets of$29.9 million and change in fair value of contingent consideration of$0.8 million . In addition, net changes in operating assets and liabilities reflected cash inflows of approximately$170.8 million driven by the timing of inventory purchases, payments for accrued expenses and accounts payable and collections of accounts receivables. Net cash provided by operating activities was$933.5 million for the year endedDecember 31, 2019 compared to net cash provided by operating activities of$838.0 million for the year endedDecember 31, 2018 . Our operating cash flows for the year endedDecember 31, 2018 included our net income of$175.3 million , depreciation and amortization of$378.6 million , deferred income tax expense of$32.7 million , pension and other post-retirement benefits costs of$47.4 million , a net non-cash charge of$351.3 million relating to an LCM inventory adjustment and stock-based compensation of$26.0 million , partially offset by a gain on sale of assets of$43.1 million , net non-cash charges relating to the change in the fair value of our inventory repurchase obligations of$31.8 million , change in the Tax Receivable Agreement liability of$13.9 million and changes in the fair value of our catalyst obligations of$5.6 million . In addition, net changes in operating assets and 102 -------------------------------------------------------------------------------- liabilities reflected uses of cash of approximately$78.9 million driven by the timing of inventory purchases, payments for accrued expenses and accounts payable and collections of accounts receivables. Cash Flows from Investing Activities Net cash used in investing activities was$1,026.5 million for the year endedDecember 31, 2020 compared to$712.6 million for the year endedDecember 31, 2019 . The net cash flows used in investing activities for the year endedDecember 31, 2020 was comprised of cash outflows of$1,176.2 million used to fund the Martinez Acquisition, capital expenditures totaling$196.2 million , expenditures for refinery turnarounds of$188.1 million , and expenditures for other assets of$9.1 million , partially offset by proceeds from sale of assets of$543.1 million . Net cash used in investing activities for the year endedDecember 31, 2019 was comprised of cash outflows of$404.9 million for capital expenditures, expenditures for refinery turnarounds of$299.3 million and expenditures for other assets of$44.7 million , partially offset by proceeds of$36.3 million related to the sale of land at ourTorrance refinery . Net cash used in investing activities was$712.6 million for the year endedDecember 31, 2019 compared to$685.6 million for the year endedDecember 31, 2018 . Net cash used in investing activities for the year endedDecember 31, 2018 was comprised of cash outflows of$317.5 million for capital expenditures, expenditures for refinery turnarounds of$266.0 million , expenditures for other assets of$17.0 million , expenditures for the acquisition of theEast Coast Storage Assets by PBFX of$75.0 million and expenditures for the acquisition of the Knoxville Terminals by PBFX of$58.4 million , partially offset by proceeds of$48.3 million related to the sale of land at ourTorrance refinery . Cash Flows from Financing Activities Net cash provided by financing activities was$2,452.7 million for the year endedDecember 31, 2020 compared to net cash used in financing activities of$3.3 million for the year endedDecember 31, 2019 . For the year endedDecember 31, 2020 , net cash provided by financing activities consisted of cash proceeds of$1,228.7 million from the issuance of the 2025 Senior Secured Notes net of related issuance costs, cash proceeds of$469.9 million from the issuance of the 2028 Senior Notes net of cash paid to redeem the 2023 Senior Notes and related issuance costs, net borrowings under our Revolving Credit Facility of$900.0 million , and proceeds from catalyst financing arrangements of$51.9 million , partially offset by net repayments on the PBFX Revolving Credit Facility of$83.0 million , net settlements of precious metal catalyst obligations of$8.8 million , distributions and dividends of$82.2 million , principal amortization payments of the PBF Rail Term Loan of$7.2 million , payments on finance leases of$12.4 million , taxes paid for net settlement of equity-based compensation of$2.1 million , repurchases of our common stock in connection with tax withholding obligations upon the vesting of certain restricted stock awards of$1.6 million and deferred financing costs and other of$0.5 million . For the year endedDecember 31, 2019 , net cash used in financing activities consisted primarily of distributions and dividends of$209.2 million , principal amortization payments of the PBF Rail Term Loan of$7.0 million , settlements of catalyst obligations of$6.5 million , taxes paid for net settlement of equity-based compensation of$4.8 million , repurchases of our common stock in connection with tax withholding obligations upon the vesting of certain restricted stock awards of$4.9 million and deferred payment for the East Coast Storage Assets Acquisition of$32.0 million , partially offset by$132.5 million in net proceeds from the issuance of PBFX common units, net borrowings from the PBFX Revolving Credit Facility of$127.0 million and deferred financing costs and other of$1.6 million . Additionally, during the year endedDecember 31, 2019 , we borrowed and repaid$1,350.0 million under our Revolving Credit Facility resulting in no net change to amounts outstanding for the year endedDecember 31, 2019 . 103 -------------------------------------------------------------------------------- Net cash used in financing activities was$3.3 million for the year endedDecember 31, 2019 compared to net cash used in financing activities of$128.1 million for the year endedDecember 31, 2018 . For the year endedDecember 31, 2018 , net cash used in financing activities consisted primarily of distributions and dividends of$189.3 million , principal amortization payments of the PBF Rail Term Loan of$6.8 million , repayment of the note payable of$5.6 million , settlements of catalyst obligations of$9.1 million , taxes paid for net settlement of equity-based compensation of$5.4 million , deferred financing costs and other of$16.2 million , repurchases of our common stock in connection with tax withholding obligations upon the vesting of certain restricted stock awards of$8.2 million , and net repayments of our Revolving Credit Facility of$350.0 million , partially offset by$287.3 million in net proceeds from theAugust 2018 Equity Offering,$34.9 million in net proceeds from the issuance of PBFX common units, net borrowings from the PBFX Revolving Credit Facility of$126.3 million and proceeds from stock options exercised of$14.0 million . The cash flow activity ofPBF LLC for the years endedDecember 31, 2020 , 2019 and 2018 is materially consistent with that ofPBF Energy discussed above, other than changes in deferred income taxes and certain working capital items, which are different fromPBF Energy due to certain tax related items not applicable toPBF LLC . Additionally,PBF LLC reflects net borrowings of$0.1 million and$3.1 million and net proceeds of$44.1 million for the years endedDecember 31, 2020 , 2019 and 2018, respectively, related to an affiliate loan withPBF Energy , included in cash flows from financing activities, which eliminates in consolidation atPBF Energy . 104 --------------------------------------------------------------------------------
Capitalization
Our capital structure was comprised of the following as of
December 31, 2020 Debt, including current maturities: (1)PBF LLC debt Affiliate note payable $ 376.3 PBF Holding debt 2025 Senior Secured Notes 1,250.0 2028 Senior Notes 1,000.0 2025 Senior Notes 725.0 Revolving Credit Facility 900.0 PBF Rail Term Loan 7.4 Catalyst financing arrangements 102.5 PBF Holding debt 3,984.9 PBFX debt PBFX 2023 Senior Notes 525.0 PBFX Revolving Credit Facility
200.0
PBFX debt
725.0
Unamortized deferred financing costs
(51.1)
Unamortized premium 2.2
5,037.3
Less: Affiliate note payable
(376.3)
TotalPBF Energy debt, net of unamortized deferred financing costs and premium (2) $ 4,661.0 Total PBF Energy Equity $ 2,202.3 Total PBF Energy Capitalization (3) $
6,863.3
Total PBF Energy Debt to Capitalization Ratio 68 %
_______________________________________________
(1) Refer to "Note 10 - Credit Facilities and Debt" and "Note 11 - Affiliate Note Payable -PBF LLC " of our Notes to Consolidated Financial Statements for further discussion related to debt. (2) Excludes thePBF LLC affiliate note payable that is eliminated at thePBF Energy level. (3) Total Capitalization refers to the sum of debt, excluding intercompany debt, plus total Equity. Revolving Credit Facilities Overview Typically, one of our primary sources of liquidity are borrowings available under our revolving lines of credit. As ofDecember 31, 2020 ,PBF Energy had$1,609.5 million of cash and cash equivalents, a$900.0 million outstanding balance under the Revolving Credit Facility and$200.0 million outstanding under the PBFX Revolving Credit Facility.PBF LLC cash and cash equivalents totaled$1,607.3 million as ofDecember 31, 2020 . 105 --------------------------------------------------------------------------------
We had available capacity under revolving credit facilities as follows at
Amount Borrowed as Total of December 31, Outstanding Borrowing base Commitment 2020 Letters of Credit Availability Expiration date Revolving Credit Facility (a)$ 3,400.0 $ 900.0 $ 184.4$ 2,759.2 May 2023 PBFX Revolving Credit Facility 500.0 200.0 4.9 295.1 July 2023 Total Credit Facilities$ 3,900.0 $ 1,100.0 $ 189.3$ 3,054.3
___________________________________
(a) The amount available for borrowings and letters of credit under the Revolving Credit Facility is calculated according to a "borrowing base" formula based on (i) 90% of the book value of Eligible Accounts with respect to investment grade obligors plus (ii) 85% of the book value of Eligible Accounts with respect to non-investment grade obligors plus (iii) 80% of the cost of Eligible Hydrocarbon Inventory plus (iv) 100% of Cash and Cash Equivalents in deposit accounts subject to a control agreement, in each case as defined in the Revolving Credit Agreement. The borrowing base is subject to customary reserves and eligibility criteria and in any event cannot exceed$3.4 billion . Additional Information on Indebtedness Our debt, including our revolving credit facilities, term loans and senior notes, include certain typical financial covenants and restrictions on our subsidiaries' ability to, among other things, incur or guarantee new debt, engage in certain business activities including transactions with affiliates and asset sales, make investments or distributions, engage in mergers or pay dividends in certain circumstances. These covenants are subject to a number of important exceptions and qualifications. We are in compliance as ofDecember 31, 2020 with all covenants, including financial covenants, in all of our debt agreements. For further discussion of our indebtedness and these covenants and restrictions, see "Note 10 - Credit Facilities and Debt" of our Notes to Consolidated Financial Statements. Liquidity The outbreak of the COVID-19 pandemic and certain developments in the global oil markets began negatively impacting our liquidity beginning towards the end of the first quarter of 2020. As ofDecember 31, 2020 , our liquidity was approximately$2.3 billion ($2.3 billion as ofDecember 31, 2019 ) based on$1.6 billion of cash, excluding cash held at PBFX, and more than$700.0 million of availability under our Revolving Credit Facility. Our total liquidity includes the amount of excess availability under the Revolving Credit Facility, which includes our cash on hand. In addition, as ofDecember 31, 2020 , PBFX had approximately$295.1 million of borrowing capacity under the PBFX Revolving Credit Facility compared with$340.0 million as ofDecember 31, 2019 . The PBFX Revolving Credit Facility is available to fund working capital, acquisitions, distributions, capital expenditures, and other general corporate purposes incurred by PBFX. Due to the unprecedented events caused by the COVID-19 pandemic and the negative impact it has caused to our liquidity, we executed a plan to strengthen our balance sheet and increase our flexibility and responsiveness by incorporating the following measurements: •Implemented cost reduction and cash preservation initiatives, including a significant decrease in 2020 capital expenditures, lowering 2020 operating expenses driven by minimizing discretionary activities and third party services, headcount reductions, and cutting corporate overhead expenses through temporary salary reductions to a significant portion of our workforce; •Suspended our quarterly dividend of$0.30 per share, anticipated to preserve approximately$35.0 million of cash each quarter, to support the balance sheet; •Closed on the sale of five hydrogen facilities for gross cash proceeds of$530.0 million onApril 17, 2020 ; 106 -------------------------------------------------------------------------------- •In May andDecember 2020 , issued, respectively,$1.0 billion and$250.0 million in aggregate principal amount of 2025 Senior Secured Notes for net proceeds of approximately$982.9 million and$245.7 million , respectively. See "Note 10 - Credit Facilities and Debt" of our Notes to Consolidated Financial Statements for additional details related to the notes offerings; •Entered into catalyst financing arrangements onSeptember 25, 2020 for net proceeds of approximately$51.9 million ; •As ofDecember 31, 2020 completed the operational reconfiguration of our East Coast Refining System comprised of ourDelaware City andPaulsboro refineries. The reconfiguration resulted in the temporary idling of certainPaulsboro Refining units and overall lower throughput and inventory levels. Annual operating and capital expenditures savings are expected to be approximately$100.0 million and$50.0 million , respectively, relative to average historic levels; •OnDecember 30, 2020 , closed on a third-party sale of parcels of real property acquired as part of theTorrance refinery , but not part of the refinery itself, for net proceeds of$13.7 million ; and •In the fourth quarter of 2020, sold AB32 credits to a third party for gross proceeds of approximately$87.5 million and concurrently entered into forward purchase agreements to repurchase these credits in the fourth quarter of 2021 prior to settlement of our AB32 obligation. We are actively responding to the impacts of the COVID-19 pandemic and ongoing rebalancing in the global oil markets. We adjusted our operational plans to the evolving market conditions and took steps to lower our 2020 operating expenses through significant reductions in discretionary activities and third party services. We successfully reduced our 2020 operating expenses by$235.0 million , excluding energy savings, and exceeded our full-year goal of$140.0 million in total operating expense reductions. Including energy expenses, our full-year operating expenses reductions for 2020 totaled approximately$325.0 million . While some of these savings are a result of reduced operational tempo, the majority are deliberate operating and other expense reductions. Looking ahead, we expect operating expenses on a system-wide basis for 2021 to be reduced by$200.0 million to$225.0 million annually as a result of our efforts versus 2019 levels, including the East Coast Reconfiguration. We aggressively managed our capital expenditures in 2020, with total refining capital expenditures of$370.4 million , an almost 50% reduction to our planned 2020 expenditures. While it is impossible to estimate the duration or complete financial impact of the COVID-19 pandemic, we believe that the strategic actions we have taken, plus our cash flows from operations and available capital resources will be sufficient to meet our and our subsidiaries' capital expenditures, working capital needs, and debt service requirements, for the next twelve months. We cannot assure you that our assumptions used to estimate our liquidity requirements will be correct because the impact that the COVID-19 pandemic is having on us and our industry is ongoing and unprecedented. The extent of the impact of the COVID-19 pandemic on our business, financial condition, results of operation and liquidity will depend largely on future developments, including the duration of the outbreak, particularly within the geographic areas where we operate, and the related impact on overall economic activity, all of which are uncertain and cannot be predicted with certainty at this time. As a result, we may require additional capital, and, from time to time, may pursue funding strategies in the capital markets or through private transactions to strengthen our liquidity and/or fund strategic initiatives. Such additional financing may not be available on favorable terms or at all. 107 -------------------------------------------------------------------------------- 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 endedDecember 31, 2020 , 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. During the fourth quarter of 2020, each of our credit rating agencies downgraded our corporate credit rating in addition to the ratings on both our unsecured and secured notes, and maintained our outlook as negative as the refining sector continues to experience weak refining margins due to the COVID-19 pandemic and related negative demand impact. As a result of the downgrade, the cost of borrowings under our Revolving Credit Facility has increased in accordance with the Revolving Credit Agreement. Given the current market conditions, we expect that our other credit ratings agencies may also re-evaluate our corporate credit rating and the ratings of our unsecured and secured notes. 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, which could impair our ability to operate our business, increase our liquidity and make future cash distributions to our shareholders. Working CapitalPBF Energy's working capital atDecember 31, 2020 was approximately$1,415.9 million , consisting of$3,867.4 million in total current assets and$2,451.5 million in total current liabilities.PBF Energy's working capital atDecember 31, 2019 was$1,314.5 million , consisting of$3,823.7 million in total current assets and$2,509.2 million in total current liabilities.PBF LLC's working capital atDecember 31, 2020 was approximately$1,374.1 million , consisting of$3,865.2 million in total current assets and$2,491.1 million in total current liabilities.PBF LLC's working capital atDecember 31, 2019 was$1,281.7 million , consisting of$3,821.5 million in total current assets and$2,539.8 million in total current liabilities. Working capital has increased during the year endedDecember 31, 2020 primarily as a result of proceeds from financing activities, partially offset by operating losses. Crude and Feedstock Supply Agreements Certain of our purchases of crude oil under our agreements with foreign national oil companies require that we post letters of credit, if open terms are exceeded, and arrange for shipment. We pay for the crude when invoiced, at which time any applicable letters of credit are lifted. We have a contract with Saudi Aramco pursuant to which we have been purchasing up to approximately 100,000 bpd of crude oil from Saudi Aramco that is processed at ourPaulsboro refinery . In connection with the acquisition of theChalmette refinery we entered into a contract withPDVSA for the supply of 40,000 to 60,000 bpd of crude oil that can be processed at any of our East orGulf Coast refineries. We have not sourced crude oil under this agreement since 2017 whenPDVSA suspended deliveries due to the parties' inability to agree to mutually acceptable payment terms and because ofU.S. government sanctions againstPDVSA . Notwithstanding the suspension, the recentU.S. government sanctions imposed againstPDVSA andVenezuela would prevent us from purchasing crude oil under this agreement. In connection with the closing of the acquisition of theTorrance refinery , we entered into a crude supply agreement with ExxonMobil for approximately 60,000 bpd of crude oil that can be processed at ourTorrance 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 ourDelaware City andToledo refineries. 108 -------------------------------------------------------------------------------- We have entered into various five-year crude supply agreements withShell Oil Products for approximately 145,000 bpd, in the aggregate, to support ourWest Coast andMid-Continent refinery operations. In addition, we have entered into certain offtake agreements for ourWest Coast system with the same counterparty for clean products with varying terms up to 15 years. Inventory Intermediation Agreements We entered into Inventory Intermediation Agreements withJ. Aron , to support the operations of theDelaware City andPaulsboro refineries. The Inventory Intermediation Agreement by and amongJ. Aron ,PBF Holding and DCR expires onJune 30, 2021 , which term may be further extended by mutual consent of the parties toJune 30, 2022 . The Inventory Intermediation Agreement by and amongJ. Aron ,PBF Holding and PRC expires onDecember 31, 2021 , which term may be further extended by mutual consent of the parties toDecember 31, 2022 . If not extended or replaced, at expiration, we will be required to repurchase the inventories outstanding under the Inventory Intermediation Agreements at that time. We intend to either extend or replace the Inventory Intermediation Agreements prior to their expirations. AtDecember 31, 2020 , the LIFO value of the J. Aron Products included within Inventory in our Consolidated Balance Sheets was$266.5 million . We accrue a corresponding liability for such crude oil, intermediates and finished products. Capital Spending Capital spending, excluding$1,176.2 million attributed to theMartinez Acquisition, was$393.4 million for the year endedDecember 31, 2020 , which primarily included costs for the construction of theDelaware City refinery hydrogen plant, turnaround costs at ourToledo refinery , safety related enhancements and facility improvements at our refineries, and approximately$12.3 million of capital expenditures related to PBFX. Due to current challenging market conditions, we have taken strategic steps to increase our flexibility and responsiveness, one of which is the reduction of capital expenditures. Total refining capital expenditures for the year endedDecember 31, 2020 totaled$370.4 million , an almost 50% reduction to our planned 2020 expenditures. We currently expect to spend an aggregate of approximately$400.0 million to$475.0 million in net refining capital expenditures during 2021, excluding PBFX, for facility improvements, refinery maintenance and turnarounds with the intention of satisfying all required safety, environmental and regulatory capital commitments. In addition, PBFX expects to spend an aggregate of approximately$10.0 million to$20.0 million in net capital expenditures during 2021. OnFebruary 1, 2020 we acquired theMartinez refinery and related logistic assets. The purchase price for the Martinez Acquisition was$960.0 million in cash, plus final working capital of$216.1 million and$77.3 million related to the Martinez Contingent Consideration. The transaction was financed through a combination of cash on hand including proceeds from the 2028 Senior Notes, and borrowings under the Revolving Credit Facility. 109 -------------------------------------------------------------------------------- Contractual Obligations and Commitments The following table summarizes our material contractual payment obligations as ofDecember 31, 2020 (in millions). The table below does not include any contractual obligations with PBFX as these related party transactions are eliminated upon consolidation of our financial statements. Payments due by period Less than More than Total 1 year 1-3 Years 3-5 Years 5 years PBF Energy: Credit facilities and debt (a)$ 4,709.9 $ 86.3
1,396.7 306.4 568.0 372.3 150.0 Leases and other rental-related commitments (b) 2,500.2 265.7 413.8 361.6 1,459.1 Purchase obligations: (c) Crude and Feedstock Supply and Inventory Intermediation Agreements 14,406.6 4,879.4 6,966.1 2,561.1 - Other Supply and Capacity Agreements 254.6 83.9 53.0 35.1 82.6 AB32 Settlement Obligations 249.7 249.7 - - - Construction obligations 32.1 32.1 - - - Environmental obligations (d) 159.9 12.0 34.6 18.2 95.1 Pension and post-retirement obligations (e) 312.5 36.9 34.2 28.5 212.9 Contingent Consideration (f) 12.1 12.1 - - - Total contractual cash obligations for PBF Energy$ 24,034.3 $ 5,964.5
Add: Affiliate Note Payable (g) 376.3 - - - 376.3 Total contractual cash obligations for PBF LLC$ 24,410.6 $ 5,964.5
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(a) Credit Facilities, debt and related interest payments Credit and debt obligations represent (i) the repayment of the outstanding borrowings under the Revolving Credit Facility; (ii) the repayment of indebtedness incurred in connection with the 2025 Senior Secured Notes, 2028 Senior Notes and 2025 Senior Notes; (iii) the repayment of our catalyst financing obligations on their maturity dates; (iv) the repayment of outstanding amounts under the PBFX Revolving Credit Facility and the PBFX 2023 Senior Notes and (v) the repayment of our PBF Rail Term Loan. Interest payments on debt facilities include cash interest payments on the 2025 Senior Secured Notes, 2028 Senior Notes, 2025 Senior Notes, PBFX Revolving Credit Facility, PBFX 2023 Senior Notes, catalyst financing obligations, PBF Rail Term Loan, plus cash payments for the commitment fees on the unused portion on our revolving credit facilities and letter of credit fees on the letters of credit outstanding atDecember 31, 2020 . With the exception of our PBF Rail Term Loan and our catalyst financing obligations, we have no debt maturing before 2023 as ofDecember 31, 2020 . Refer to "Note 10 - Credit Facilities and Debt" of our Notes to Consolidated Financial Statements for further discussion related to debt. 110 -------------------------------------------------------------------------------- (b) Leases and other rental-related commitments We enter into leases and other rental-related agreements in the normal course of business. As described in "Note 2 - Summary of Significant Accounting Policies" of our Notes to Consolidated Financial Statements, we adopted new guidance on leases effectiveJanuary 1, 2019 which brought substantially all leases with initial terms of over twelve months outstanding as of the implementation date onto our Consolidated Balance Sheets. Leases with initial terms of twelve months or less are considered short-term and we elected the practical expedient in the new lease guidance to exclude these leases from our Consolidated Balance Sheets. Some of our leases provide us with the option to renew the lease at or before expiration of the lease terms. Future lease obligations would change if we chose to exercise renewal options or if we enter into additional operating or finance lease agreements. Certain of our lease obligations contain a fixed and variable component. The table above reflects the fixed component of our lease obligations, including short-term lease expense. The variable component could be significant. In addition, we have entered into certain agreements for the supply of hydrogen that contain both lease and non-lease components. The table above also includes such non-lease components of these agreements. See "Note 15 - Leases" of our Notes to Consolidated Financial Statements for further details and disclosures regarding our operating and finance lease obligations. We also enter into contractual obligations with third parties for the right to use property for locating pipelines and accessing certain of our assets (also referred to as land easements) in the normal course of business. Our obligations regarding such land easements are included within Leases and other rental-related commitments in the table above. (c) Purchase obligations We have obligations to repurchase the J. Aron Products under the Inventory Intermediation Agreements withJ. Aron as further explained in "Note 2 - Summary of Significant Accounting Policies", "Note 6 - Inventories" and "Note 9 - Accrued Expenses" of our Notes to Consolidated Financial Statements. Additionally, purchase obligations under "Crude and Feedstock Supply and Inventory Intermediation Agreements" include commitments to purchase crude oil from certain counterparties under supply agreements entered into to ensure adequate supplies of crude oil for our refineries. These obligations are based on aggregate minimum volume commitments at 2020 year end market prices. Payments under "Other Supply and Capacity Agreements" include contracts for the transportation of crude oil and supply of hydrogen, steam, or natural gas to certain of our refineries, contracts for the treatment of wastewater, and contracts for pipeline capacity. We enter into these contracts to facilitate crude oil deliveries and to ensure an adequate supply of energy or essential services to support our refinery operations. Substantially all of these obligations are based on fixed prices. Certain agreements include fixed or minimum volume requirements, while others are based on our actual usage. The amounts included in this table are based on fixed or minimum quantities to be purchased and the fixed or estimated costs based on market conditions as ofDecember 31, 2020 . Payments under "AB32 Settlement Obligations" include future obligations to repurchase AB32 credits previously sold to third parties and will be used to settle our AB32 liability. Liabilities related to these obligations are included in "Accrued expenses" in the Consolidated Balance Sheets atDecember 31, 2020 . See "Note 9 - Accrued Expenses" of our Notes to Consolidated Financial Statements for details. The amounts included in this table exclude our crude supply agreement withPDVSA . We have not sourced crude oil under this agreement since the third quarter of 2017 asPDVSA has suspended deliveries due to the parties inability to agree to mutually acceptable payment terms and because ofU.S. government sanctions againstPDVSA . 111 -------------------------------------------------------------------------------- (d) Environmental obligations In connection with certain of our refinery and logistics acquisitions, we have assumed certain environmental remediation obligations to address matters that were outstanding at the time of such acquisitions. In addition, in connection with most of these acquisitions, we have purchased environmental insurance policies to insure against unknown environmental liabilities at each site. The obligations in the table above reflect our undiscounted best estimate in cost and tenure to remediate our outstanding obligations and are further discussed in "Note 14 - Commitments and Contingencies" of our Notes to Consolidated Financial Statements. (e) Pension and post-retirement obligations Pension and post-retirement obligations include only those amounts we expect to pay out in benefit payments and are further explained in "Note 19 - Employee Benefit Plans" of our Notes to Consolidated Financial Statements. (f) Contingent Consideration Contingent consideration includes our obligations to pay certain contractual earn-outs entered into as part of acquisitions. As ofDecember 31, 2020 we do not expect to achieve any earn-out obligations related to theMartinez acquisition. Our earn-out obligation related to the East Coast Storage Assets acquisition and our amount payable toCrown Point relates to our year one earn-out obligation payable in 2021 with no future estimated earn-out obligations for years thereafter. (g) Affiliate Note Payable As described in "Note 11 - Affiliate Note Payable -PBF LLC " of our Notes to Consolidated Financial Statements, as ofDecember 31, 2020 ,PBF LLC had an outstanding note payable withPBF Energy for an aggregate principal amount of$376.3 million . The note has an interest rate of 2.5% and matures inApril 2030 , but may be prepaid in whole or in part at any time, at the option ofPBF LLC without penalty or premium. This affiliate note payable is a cash obligation ofPBF LLC only and eliminates in consolidation forPBF Energy . (h) Tax Receivable Agreement obligation The table above does not include an amount associated with our Tax Receivable Agreement obligation as our liability was reduced to zero as ofDecember 31, 2020 in conjunction with our recording of a deferred tax asset valuation allowance recognized in accordance with ASC 740, Income Taxes. Refer to "Note 14 - Commitments and Contingencies" and "Note 21 - Income Taxes" of our Notes to Consolidated Financial Statements for further discussion of the Tax Receivable Agreement. 112 -------------------------------------------------------------------------------- Tax DistributionsPBF LLC is required to make periodic tax distributions to the members ofPBF LLC , includingPBF Energy , pro rata in accordance with their respective percentage interests for such period (as determined under the amended and restated limited liability company agreement ofPBF LLC ), subject to available cash and applicable law and contractual restrictions (including pursuant to our debt instruments) and based on certain assumptions. Generally, these tax distributions will be an amount equal to our estimate of the taxable income ofPBF LLC for the year multiplied by an assumed tax rate equal to the highest effective marginal combinedU.S. federal, state and local income tax rate prescribed for an individual or corporate resident inNew York, New York (taking into account the nondeductibility of certain expenses). If, with respect to any given calendar year, the aggregate periodic tax distributions were less than the actual taxable income ofPBF LLC multiplied by the assumed tax rate,PBF LLC will make a "true up" tax distribution, no later thanMarch 15 of the following year, equal to such difference, subject to the available cash and borrowings ofPBF LLC . As these distributions are conditional they have been excluded from the table above. Off-Balance Sheet Arrangements We have no off-balance sheet arrangements as ofDecember 31, 2020 , other than outstanding letters of credit of approximately$189.3 million . Critical Accounting Policies The following summary provides further information about our critical accounting policies that involve critical accounting estimates and should be read in conjunction with "Note 2 - Summary of Significant Accounting Policies" of our Notes to Consolidated Financial Statements. The following accounting policies involve estimates that are considered critical due to the level of subjectivity and judgment involved, as well as the impact on our financial position and results of operations. We believe that all of our estimates are reasonable. Unless otherwise noted, estimates of the sensitivity to earnings that would result from changes in the assumptions used in determining our estimates is not practicable due to the number of assumptions and contingencies involved, and the wide range of possible outcomes. Inventory Inventories are carried at the lower of cost or market. The cost of crude oil, feedstocks, blendstocks and refined products is determined under the LIFO method using the dollar value LIFO method with increments valued based on average cost during the year. The cost of supplies and other inventories is determined principally on the weighted average cost method. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years that inventory volumes decline as the result of charging cost of sales with LIFO inventory costs generated in prior periods. AtDecember 31, 2020 and 2019, market values had fallen below historical LIFO inventory costs and, as a result, we recorded an LCM or market inventory valuation reserves of$669.6 million and$401.6 million , respectively. The LCM or market inventory valuation reserve, or a portion thereof, is subject to reversal as a reduction to cost of products sold in subsequent periods as inventories giving rise to the reserve are sold, and a new reserve is established. Such a reduction to cost of products sold could be significant if inventory values return to historical cost price levels. Additionally, further decreases in overall inventory values could result in additional charges to cost of products sold should the LCM or market inventory valuation reserve be increased. 113 -------------------------------------------------------------------------------- Environmental Matters Liabilities for future clean-up costs are recorded when environmental assessments and/or clean-up efforts are probable and the costs can be reasonably estimated. Other than for assessments, the timing and magnitude of these accruals generally are based on the completion of investigations or other studies or a commitment to a formal plan of action. Environmental liabilities are based on best estimates of probable future costs using currently available technology and applying current regulations, as well as our own internal environmental policies. The actual settlement of our liability for environmental matters could materially differ from our estimates due to a number of uncertainties such as the extent of contamination, changes in environmental laws and regulations, potential improvements in remediation technologies and the participation of other responsible parties. While we believe that our current estimates of the amounts and timing of the costs related to the remediation of these liabilities are reasonable, we have had limited experience with certain of these environmental obligations due to our short operating history with certain of our assets. It is possible that our estimates of the costs and duration of the environmental remediation activities related to these liabilities could materially change. Business Combinations We use the acquisition method of accounting for the recognition of assets acquired and liabilities assumed in business combinations at their estimated fair values as of the date of acquisition. Any excess consideration transferred over the estimated fair values of the identifiable net assets acquired is recorded as goodwill. Significant judgment is required in estimating the fair value of assets acquired. As a result, in the case of significant acquisitions, we obtain the assistance of third-party valuation specialists in estimating fair values of tangible and intangible assets based on available historical information and on expectations and assumptions about the future, considering the perspective of marketplace participants. While management believes those expectations and assumptions are reasonable, they are inherently uncertain. Unanticipated market or macroeconomic events and circumstances may occur, which could affect the accuracy or validity of the estimates and assumptions. Certain of our acquisitions may include earn-out provisions or other forms of contingent consideration. As of the acquisition date, we record contingent consideration, as applicable, at the estimated fair value of expected future payments associated with the earn-out. Any changes to the recorded fair value of contingent consideration, subsequent to the measurement period, will be recognized as earnings in the period in which it occurs. Such contingent consideration liabilities are based on best estimates of future expected payment obligations, which are subject to change due to many factors outside of our control. Changes to the estimate of expected future contingent consideration payments may occur, from time to time, due to various reasons, including actual results differing from estimates and adjustments to the revenue or earnings assumptions used as the basis for the liability based on historical experience. While we believe that our current estimate of the fair value of our contingent consideration liability is reasonable, it is possible that the actual future settlement of our earn-out obligations could materially differ. Deferred Turnaround Costs Refinery turnaround costs, which are incurred in connection with planned major maintenance activities at our refineries, are capitalized when incurred and amortized on a straight-line basis over the period of time estimated until the next turnaround occurs (generally three to six years). While we believe that the estimates of time until the next turnaround are reasonable, it should be noted that factors such as competition, regulation or environmental matters could cause us to change our estimates thus impacting amortization expense in the future. 114 -------------------------------------------------------------------------------- Derivative Instruments We are exposed to market risk, primarily related to changes in commodity prices for the crude oil and feedstocks used in the refining process, as well as the prices of the refined products sold and the risk associated with the price of credits needed to comply with various governmental and regulatory environmental compliance programs. The accounting treatment for commodity and environmental compliance contracts depends on the intended use of the particular contract and on whether or not the contract meets the definition of a derivative. Non-derivative contracts are recorded at the time of delivery. All derivative instruments that are not designated as normal purchases or sales are recorded in our Consolidated Balance Sheets as either assets or liabilities measured at their fair values. Changes in the fair value of derivative instruments that either are not designated or do not qualify for hedge accounting treatment or normal purchase or normal sale accounting are recognized in income. Contracts qualifying for the normal purchases and sales exemption are accounted for upon settlement. We elect fair value hedge accounting for certain derivatives associated with our inventory repurchase obligations. Derivative accounting is complex and requires management judgment in the following respects: identification of derivatives and embedded derivatives; determination of the fair value of derivatives; identification of hedge relationships; assessment and measurement of hedge ineffectiveness; and election and designation of the normal purchases and sales exception. All of these judgments, depending upon their timing and effect, can have a significant impact on earnings. Impairment of Long-Lived Assets Long-lived assets are tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. A long-lived asset is not recoverable if its carrying amount exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. If a long-lived asset is not recoverable, an impairment loss is recognized for the amount by which the carrying amount of the long-lived asset exceeds its fair value, with fair value determined based on discounted estimated net cash flows or other appropriate methods. The global crisis resulting from the COVID-19 pandemic has had a substantial impact on the economy and overall consumer demand for energy and hydrocarbon products. As a result of the significant decrease inPBF Energy's stock price in 2020, enduring throughput reductions across our refineries and noticeable decrease in demand for our products, we determined that an impairment triggering event had occurred. Therefore, we performed an impairment assessment on certain long-lived assets as ofDecember 31, 2020 . As a result of the impairment test, we determined that our long-lived assets were not impaired when comparing the carrying value of the long-lived assets to the estimated undiscounted future cash flows expected to result from use of the assets over their remaining estimated useful life. If adverse market conditions persist or there is further deterioration in the general economic environment due to the COVID-19 pandemic, there could be additional indicators that our assets are impaired requiring evaluation that may result in future impairment charges to earnings. Refer to "Note 1 - Description of the Business and Basis of Presentation" of our Notes to Consolidated Financial Statements. 115 -------------------------------------------------------------------------------- Income Taxes and Tax Receivable Agreement As a result ofPBF Energy's acquisition ofPBF LLC Series A Units or exchanges ofPBF LLC Series A Units for PBF Energy Class A common stock, it expects to benefit from amortization and other tax deductions reflecting the step up in tax basis in the acquired assets. Those deductions will be allocated toPBF Energy and will be taken into account in reporting its taxable income. As a result of a federal income tax election made byPBF LLC , applicable to a portion ofPBF Energy's acquisition ofPBF LLC Series A Units, the income tax basis of the assets ofPBF LLC , underlying a portion of the unitsPBF Energy acquired, has been adjusted based upon the amount thatPBF Energy paid for that portion of itsPBF LLC Series A Units.PBF Energy entered into the Tax Receivable Agreement (as defined in "Note 14 - Commitments and Contingencies" of the Notes to our Consolidated Financial Statements) which provides for the payment byPBF Energy equal to 85% of the amount of the benefits, if any, that it is deemed to realize as a result of (i) increases in tax basis and (ii) certain other tax benefits related to entering into the Tax Receivable Agreement, including tax benefits attributable to payments under the Tax Receivable Agreement. As a result of these transactions,PBF Energy's tax basis in its share ofPBF LLC's assets will be higher than the book basis of these same assets. This resulted in a deferred tax asset of$155.2 million as ofDecember 31, 2020 . Deferred taxes are calculated using a liability method, whereby deferred tax assets are recognized for deductible temporary differences and deferred tax liabilities are recognized for taxable temporary differences. Temporary differences represent the differences between reported amounts of assets and liabilities and their tax bases. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effect of changes in tax laws and rates on the date of enactment. We recognize tax benefits for uncertain tax positions only if it is more likely than not that the position is sustainable based on its technical merits. Interest and penalties on uncertain tax positions are included as a component of the provision for income taxes on the Consolidated Statements of Operations. As a result of management's assessment of the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit use of the existing deferred tax assets as ofDecember 31, 2020 , a valuation allowance of$358.4 million was recorded to recognize only the portion of deferred tax assets that are more likely than not to be realized. The amount of the deferred tax assets considered realizable, however, could be adjusted if estimates of future taxable income are reduced or increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as our projections for future taxable income. As a result of the valuation allowance, the liability associated with the Tax Receivable Agreement was reduced to zero. Pursuant to the Tax Receivable Agreement PBF Energy entered into at the time of its initial public offering, it is required to pay the current and former PBF LLC Series A unitholders, who exchange their units forPBF Energy stock or whose units we purchase, approximately 85% of the cash savings in income taxes thatPBF Energy is deemed to realize as a result of the increase in the tax basis of its interest inPBF LLC , including tax benefits attributable to payments made under the Tax Receivable Agreement. These payment obligations are ofPBF Energy and not ofPBF LLC or any of its subsidiaries.PBF Energy has recognized a liability for the Tax Receivable Agreement reflecting its estimate of the undiscounted amounts that it expects to pay under the agreement.PBF Energy's estimate of the Tax Receivable Agreement liability is based, in part, on forecasts of future taxable income over the anticipated life ofPBF Energy's future business operations, assuming no material changes in the relevant tax law. The assumptions used in the forecasts are subject to substantial uncertainty aboutPBF Energy's future business operations and the actual payments that it is required to make under the Tax Receivable Agreement could differ materially from its current estimates.PBF Energy must adjust the estimated Tax Receivable Agreement liability each time we purchasePBF LLC Series A Units or upon an exchange ofPBF LLC Series A Units forPBF Energy Class A common stock. Such adjustments will be based on forecasts of future taxable income andPBF Energy's future business operations at the time of such purchases or exchanges. Periodically,PBF Energy may adjust the liability based on an updated estimate of the amounts that it expects to pay, using assumptions consistent with those used in its concurrent estimate of the deferred tax asset valuation allowance. These periodic adjustments to the Tax Receivable Agreement liability, if any, are 116
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recorded in general and administrative expense and may result in adjustments to our income tax expense and deferred tax assets and liabilities. Recent Accounting Pronouncements Refer to "Note 2 - Summary of Significant Accounting Policies" of our Notes to Consolidated Financial Statements, for Recently Issued Accounting Pronouncements.
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