The diagram below depicts our organizational structure as of December 31, 2017:2020:
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Refining Operations
We own and operate fivesix refineries providing(two of which are operated as a single unit) that provide us with geographic and market diversity. We produce a variety of products at each of our refineries, including gasoline, ULSD, heating oil, jet fuel, lubricants, petrochemicals and asphalt. We sell our products throughout the Northeast, Midwest, Gulf Coast and West Coast of the United States, as well as in other regions of the United States, Canada and Mexico, and are able to ship products to other international destinations.
East Coast Refining System (Delaware City Refinery and Paulsboro Refinery)
Overview. The Delaware City refinery is located on an approximately 5,000-acre site, with access to waterborne cargoes and an extensive distribution network of pipelines, barges and tankers, truck and rail. The Delaware City refinery is a fully integrated operation that receives crude via rail at its crude unloading facilities owned by PBFX, or via ship or barge at itsthe docks owned by the Delaware City refinery located on the Delaware River. The crude and other feedstocks are stored in an extensive tank farm prior to processing. In addition, there is a 15-lane, 76,000 bpd capacity truck loading rack (the “DCR Truck Rack”) located adjacent to the refinery and a 23-mile interstate pipeline (the “DCR Products Pipeline”) that are used to distribute clean products, whichproducts. The DCR Products Pipeline and DCR Truck Rack were sold to PBFX in conjunction withMay 2015 and PBFX owns additional assets that support the Delaware City refinery. The Paulsboro refinery is located on approximately 950 acres on the Delaware River in Paulsboro, New Jersey, near Philadelphia and approximately 30 miles away from Delaware City. Paulsboro receives crude and feedstocks via its acquisition ofmarine terminal on the DCR Products Pipeline and Truck Rack (as defined in “Note 11 - Related Party Transactions” of our Notes to Consolidated Financial Statements) in May 2015.Delaware River.
As a result of its configuration and process units, Delaware City has the capability of processing a slate of heavy crudes with a high concentration of high sulfur crudes, as well as other high sulfur feedstock when economically viable, and is one of the largest and most complex refineries on the East Coast. The Delaware City refinery is one of two heavy crude cokingprocessing refineries, the other being our Paulsboro refinery, on the East Coast of the United States withStates. The Delaware City coking capacity is equal to approximately 25% of crude capacity.
The Delaware City refinery primarily processes a variety of medium to heavy, sour crude oils, but can run light, sweet crude oils as well. The refinery has large conversion capacity with its 82,000 bpd fluid catalytic crackingFCC unit, (“FCC unit”), 47,00054,500 bpd fluid coking unit and 18,00024,000 bpd hydrocracking unit with vacuum distillation.unit.
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The following table approximates the Delaware City refinery’sEast Coast Refining System’s current major process unit capacities. Unit capacities are shown in barrels per stream day.
| Delaware City Refinery Units | Nameplate Capacity | ||||
| Crude Distillation Unit | |||||
| Vacuum Distillation Unit | |||||
| Fluid Catalytic Cracking Unit | 82,000 | ||||
| Hydrotreating Units | |||||
| Hydrocracking Unit | |||||
| Catalytic Reforming Unit | 43,000 | ||||
| Benzene / Toluene Extraction Unit | 15,000 | ||||
| Butane Isomerization Unit | 6,000 | ||||
| Alkylation Unit | |||||
| Polymerization Unit | 16,000 | ||||
| Fluid Coking Unit | |||||
| Paulsboro Refinery Units | Nameplate Capacity | |||||||
Crude Distillation Units (1) | 105,000 | |||||||
Vacuum Distillation Units (1) | 50,000 | |||||||
Fluid Catalytic Cracking Unit (1) | Idled | |||||||
Hydrotreating Units (1) | 61,000 | |||||||
Catalytic Reforming Unit (1) | Idled | |||||||
Alkylation Unit (1) | Idled | |||||||
| Lube Oil Processing Unit | 12,000 | |||||||
Delayed Coking Unit (1) | Idled | |||||||
| Propane Deasphalting Unit | 11,000 | |||||||
(1)Current Nameplate Capacity was fully or partially reduced to reflect the idled units as part of the East Coast Refining Reconfiguration.
Feedstocks and Supply Arrangements. We currently fully source our own crude oil needs for Delaware City primarily through short-term and spot market agreements. We have a contract with Saudi Aramco pursuant to which we have purchased up to approximately 100,000 bpd of crude oil from Saudi Aramco that is processed at Paulsboro. The crude purchased under this contract is priced off the ASCI.
Refined Product Yield and Distribution. The Delaware City refinery predominantly produces gasoline, jet fuel, ULSD and ultra-low sulfur heating oil as well as certain other products. Products produced at the Delaware City refinery are transferred to customers through pipelines, barges or at its truck rack. We market and sell all of our refined products independently to a variety of customers on the spot market or through term agreements. The Paulsboro refinery predominantly manufactures Group I base oils or lubricants and asphalt and jet fuel. Products produced at the Paulsboro refinery are transferred to customers primarily through pipelines, barges, or at its truck rack. We market and sell all of our refined products independently to a variety of customers on the spot market or through term agreements.
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Inventory Intermediation Agreement. On June 26, 2013,August 29, 2019, we entered into an Inventory Intermediation Agreement (the “Inventory Intermediation Agreement”)amended and restated inventory intermediation agreements with J. Aron, & Company, a subsidiary of The Goldman Sachs Group, Inc. (“J. Aron”(as amended from time to time, the “Inventory Intermediation Agreements”), to support the operations of the Delaware City refinery, which commenced upon the termination of the previous product offtake agreement. Pursuant to suchand Paulsboro refineries. The Inventory Intermediation Agreement by and among J. Aron, purchases the Products producedPBF Holding and delivered into the refinery’s storage tanksDCR expires on a daily basis. J. Aron further agrees to sell to us on a daily basis the Products delivered out of the refinery’s storage tanks. On certain dates subsequent to the inception of the Inventory Intermediation Agreements, we and our subsidiary, DCR, entered into amendments to the amended and restated inventory intermediation agreement (as amended, the “Amended Delaware Intermediation Agreement”) with J. Aron pursuant to which certain terms of the Inventory Intermediation Agreements were amended, including, among other things, pricing and an extension of the term. The most recent of these amendments was executed on September 8, 2017 which extended the term to July 1, 2019,June 30, 2021, which term may be further extended by mutual consent of the parties to July 1, 2020.June 30, 2022. The Inventory Intermediation Agreement by and among J. Aron, PBF Holding and PRC expires on December 31, 2021, which term may be further extended by mutual consent of the parties to December 31, 2022.
Pursuant to each Inventory Intermediation Agreement, J. Aron purchases and holds title to certain inventory, including crude oil, intermediate and certain finished products (the “J. Aron Products”), produced by the refinery and delivered into our storage tanks at the Delaware City and Paulsboro refineries and at PBFX’s assets acquired from Crown Point International in October 2018 (the “East Coast Storage Assets” and together with our storage tanks at the Delaware City and Paulsboro refineries, the “J. Aron Storage Tanks”). The J. Aron Products are sold back to us as the J. Aron Products are discharged out of our J. Aron Storage Tanks. At expiration or termination of each of the Inventory Intermediation Agreements, we will have to repurchase the inventories outstanding under the Amended DelawareInventory Intermediation Agreement at that time.
Tankage Capacity. The Delaware City refinery has total storage capacity of approximately 10.0 million barrels. Of the total, approximately 3.6 million barrels of storage capacity are dedicated to crude oil and other feedstock storage with the remaining approximately 6.4 million barrels allocated to finished products, intermediates and other products. The Paulsboro refinery has total storage capacity of approximately 7.5 million barrels. Of the total, approximately 2.1 million barrels are dedicated to crude oil storage with the remaining 5.4 million barrels allocated to finished products, intermediates and other products.
Energy and Other Utilities. Under normal operating conditions, the Delaware City refinery consumes approximately 65,00075,000 MMBTU per day of natural gas supplied via pipeline from third parties. The Delaware City refinery has a 280 MW power plant located on-siteon site that consists of two natural gas-fueled turbines with combined capacity of approximately 140 MW and four turbo-generatorsturbo generators with combined nameplate capacity of approximately 140 MW. Collectively, this power plant produces electricity in excess of Delaware City’s refinery load of approximately 90 MW. Excess electricity is sold into the Pennsylvania-New Jersey-Maryland, or PJM, grid. Steam is primarily produced by a combination of three dedicated boilers, two heat recovery steam generators on the gas turbines, and is supplemented by secondary boilers at the FCC and Coker. Hydrogen is currently provided via the refinery’s steam methane reformer and continuous catalytic reformer.
Hydrogen Plant Project. During 2018, we signed an agreement with a third-party for an additional supply of producing 10 MMSCFD of 99% pure hydrogen. This ancillary hydrogen plant is utilized as a back-up source25.0 million standard cubic feet per day of hydrogen forfrom a new hydrogen generation facility constructed on the refinery’s process units.Delaware City site, which was completed in the second quarter of 2020. This additional hydrogen provides additional complex crude and feedstock processing capabilities.
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Toledo Refinery
Overview. The Toledo refinery primarily processes a slate of light, sweet crudes from Canada, the Mid-Continent, the Bakken region and the U.S. Gulf Coast. The Toledo refinery is located on a 282-acre site near Toledo, Ohio, approximately 60 miles from Detroit. Crude is delivered to the Toledo refinery through three primary pipelines: (1) Enbridge from the north, (2) CaplinePatoka from the southwest and (3) Mid-Valley from the south. Crude is also delivered to a nearby terminal by rail and from local sources by truck to a truck unloading facility within the refinery.
The following table approximates the Toledo refinery’s current major process unit capacities. Unit capacities are shown in barrels per stream day.
| Refinery Units | Nameplate Capacity | ||||
| Crude Distillation Unit | |||||
| Fluid Catalytic Cracking Unit | |||||
| Hydrotreating Units | 95,000 | ||||
| Hydrocracking Unit | |||||
| Catalytic Reforming Units | |||||
| Alkylation Unit | |||||
| Polymerization Unit | 7,000 | ||||
| UDEX Unit | 16,300 | ||||
Feedstocks and Supply Arrangements. We currently fully source our own crude oil needs for Toledo primarily through short-term and spot market agreements.
Refined Product Yield and Distribution. Toledo produces finished products, including gasoline, jet and ULSD, in addition to a variety of high-value petrochemicals including benzene, toluene, xylene, nonene and tetramer. Toledo is connected, via pipelines, to an extensive distribution network throughout Ohio, Illinois, Indiana, Kentucky, Michigan, Pennsylvania and West Virginia. The finished products are transported on pipelines owned by Sunoco Logistics Partners L.P. and Buckeye Partners.Partners L.P. In addition, we have proprietary connections to a variety of smaller pipelines and spurs that help us optimize our clean products distribution. A significant portion of Toledo’s gasoline and ULSD are distributed through the approximately 36various terminals in this network.
We have an agreement with Sunoco whereby Sunoco purchases gasoline and distillate products representing approximately one-third of the Toledo refinery’s gasoline and distillates production. The agreement had an initial three yearthree-year term, subject to certain early termination rights. In March 2017,2019, the agreement was renewed and extended for a two yearthree-year term. We sell the bulk of the petrochemicals produced at the Toledo refinery through short-term contracts or on the spot market and the majority of the petrochemical distribution is done via rail.
Tankage Capacity. The Toledo refinery has total storage capacity of approximately 4.5 million barrels. The Toledo refinery receives its crude through pipeline connections and a truck rack. Of the total, approximately 1.3 million barrels are dedicated to crude oil storage with the remaining 3.2 million barrels allocated to intermediates and products. A portion of storage capacity dedicated to crude oil and finished products was sold to PBFX in conjunction with its acquisition of the Toledoa tank farm related facility, which included a propane storage and loading facility (the “Toledo Storage Facility (as defined in “Note 11 - Related Party Transactions” of our Notes to Consolidated Financial Statements)Facility”) in December 2014.
Energy and Other Utilities. Under normal operating conditions, the Toledo refinery consumes approximately 20,00025,000 MMBTU per day of natural gas supplied via pipeline from third parties. The Toledo refinery purchases its electricity from the PJM grid and has a long-term contract to purchase hydrogen and steam from a local third partythird-party supplier. In addition to the third partythird-party steam supplier, Toledo consumes a portion of the steam that is generated by its various process units.
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Chalmette Refinery
Overview. The Chalmette refinery is located on a 400-acre site near New Orleans, Louisiana. It is a dual-train coking refinery and is capable of processing both light and heavy crude oil thoughthrough its 189,000185,000 bpd crude units and downstream units. Chalmette Refining owns 100% of the MOEM Pipeline, providing access to the Empire Terminal, as well as the CAM Connection Pipeline, providing access to the Louisiana Offshore Oil Port facility through a third partythird-party pipeline. Chalmette Refining also owns 80% of each of the Collins Pipeline Company (“Collins”) and T&M Terminal Company (“T&M”), both located in Collins, Mississippi, which provide a clean products outlet for the refinery
to the Plantation and Colonial Pipelines. Also included in the acquisition wereIn addition, there is also a marine terminal capable of importing waterborne feedstocks and loading or unloading finished products;products. There is also a clean products truck rack whichthat provides access to local markets;markets and a crude and product storage facility.that are owned by PBFX.
The following table approximates the Chalmette refinery’s current major process unit capacities. Unit capacities are shown in barrels per stream day.
| Refinery Units | Nameplate Capacity | ||||
| Crude Distillation | |||||
| Vacuum Distillation Unit | 114,000 | ||||
| Fluid Catalytic Cracking Unit | |||||
| Hydrotreating Units | |||||
| Delayed | |||||
| Catalytic Reforming Unit | |||||
| Alkylation Unit | |||||
| Aromatics Extraction Unit | 17,000 | ||||
Feedstocks and Supply Arrangements. In connection with We source our crude oil and feedstock needs for Chalmette through connections to the Chalmette Acquisition onCAM Pipeline and MOEM Pipeline as well as our marine terminal. On November 1, 2015, we entered into a market-based crude supply agreement with Petróleos de Venezuela S.A. (“PDVSA”) that has a ten yearten-year term with a renewal option for an additional five years, subject to certain early termination rights. The pricing for the crude supply is market based and is agreed upon on a quarterly basis by both parties. We have not sourced crude oil under this agreement since the third quarter of 2017 as PDVSA has suspended deliveries due to the parties’ inability to agree to mutually acceptable payment terms. Since the suspension, we have obtained crudeterms and feedstocks from other sources through connections to the CAM and MOEM pipelines as well as our marine terminal.because of U.S. government sanctions against PDVSA.
Refined Product Yield and Distribution. The Chalmette refinery predominantly produces gasoline and diesel fuels and jet fuel and also manufactures high-value petrochemicals including benzene and xylene. Products produced at the Chalmette refinery are transferred to customers through pipelines, the marine terminal and truck rack. The majority of our clean products are delivered to customers via pipelines. Our ownership of the Collins Pipelinepipeline and T&M Terminalterminal provides Chalmette with strategic access to Southeast and East Coast markets through third partythird-party logistics. We had an offtake agreement with ExxonMobil pursuant to which ExxonMobil purchased approximately 50% of the 14,000 barrel per day truck rack capacity, which expired as of December 31, 2017.
Tankage Capacity. Chalmette has a total tankage capacity of approximately 8.1 million barrels. Of this total, approximately 2.6 million barrels are allocated to crude oil storage with the remaining 5.5 million barrels allocated to intermediates and products.
Energy and Other Utilities. Under normal operating conditions, the Chalmette refinery consumes approximately 30,00025,000 MMBTU per day of natural gas supplied via pipeline from third parties. The Chalmette refinery purchases its electricity from a local utility and has a long-term contract to purchase hydrogen and steam from third party suppliers.a third-party supplier.
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Torrance Refinery
Overview. The Torrance refinery is located on 750 acres in Torrance, California. It is a high-conversion crude, delayed-coking refinery. It isrefinery capable of processing both heavy and medium crude oil thoughoils through its crude unit and downstream units. In addition to refining assets, the Torrance Acquisitionrefinery acquisition included a number of high-quality logistics assets including a sophisticated network of crude and products pipelines, product distribution terminals
and refinery crude and product storage facilities. The most significant of the logistics assetsasset is a crude gathering and transportation system which delivers San Joaquin Valley crude oiloils directly from the field to the refinery.refinery, which is now owned by PBFX. Additionally, included in the transactionthere are several pipelines whichserving the refinery that provide access to sources of waterborne crude oiloils including the Ports of Long Beach and Los Angeles, as well as clean product outlets with a direct pipeline supplyingthat supplies jet fuel to the Los Angeles airport.airport that are held by affiliates of the refinery.
The following table approximates the Torrance refinery’s current major process unit capacities. Unit capacities are shown in barrels per stream day.
| Refinery Units | Nameplate Capacity | ||||
| Crude Distillation Unit | |||||
| Vacuum Distillation Unit | 102,000 | ||||
| Fluid Catalytic Cracking Unit | |||||
| Hydrotreating Units | |||||
| Hydrocracking Unit | |||||
| Alkylation Unit | |||||
| Delayed | |||||
Feedstocks and Supply Arrangements. The Torrance refinery primarily processes a variety of medium and heavy crude oils. In connection with the closing of the Torrance Acquisition,On July 1, 2016, we entered into a crude supply agreement with ExxonMobilExxon Mobil Oil Corporation (“ExxonMobil”) for approximately 60,000 bpd of crude oil that can be processed at our Torrance refinery. This crude supply agreement has a five yearfive-year term with an automatic renewal feature unless either party gives thirty-six months prior written notice.notice of its intent to terminate the agreement. Additionally, we obtain crude and feedstocks from other sources through connections to third partythird-party pipelines as well as ship docks and truck racks.
Refined Product Yield and Distribution. The Torrance refinery predominantly produces gasoline, jet fuel and diesel fuels. Products produced at the Torrance refinery are transferred to customers through pipelines, the marine terminal and truck rack. The majority of clean products are delivered to customers via pipelines. We have an offtake agreement with ExxonMobil pursuant to which ExxonMobil purchases approximately 50%currently market and sell all of our gasoline production. This offtake agreement has an initialrefined products independently to a variety of customers either on the spot market or through term of three years from the date of the Torrance Acquisition at which time it will automatically renew for another three year term unless either party gives six months’ written notice of its intent to terminate the agreement.agreements.
Tankage Capacity. Torrance has a total tankage capacity of approximately 8.6 million barrels. Of this total, approximately 2.1 million barrels are allocated to crude oil storage with the remaining 6.5 million barrels allocated to intermediates and products.
Energy and Other Utilities. Under normal operating conditions, the Torrance refinery consumes approximately 42,00047,000 MMBTU per day of natural gas supplied via pipeline from third parties. The Torrance refinery generates some power internally using a combination of steam and gas turbines and purchases any additional needed power from the local utility. The Torrance refinery has a long-term contract to purchase hydrogen and steam from a third-party supplier.
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Martinez Refinery
We acquired the Martinez refinery and related logistics assets from Equilon Enterprises LLC d/b/a Shell Oil Products US (“Shell Oil Products”) on February 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 to Shell Oil Products based on certain earnings thresholds of the Martinez refinery for a period of up to four years (the “Martinez Acquisition”).
Overview. The Martinez refinery is located on an 860-acre site in the City of Martinez, 30 miles northeast of San Francisco, California. The refinery is a high-conversion, dual-coking facility with a Nelson Complexity Index of 16.1, making it one of the most complex refineries in the United States. The facility is strategically positioned in Northern California and provides for operating and commercial synergies with the Torrance refinery located in Southern California. In addition to refining assets, the Martinez 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.
The following table approximates the Martinez refinery’s current major process unit capacities. Unit capacities are shown in barrels per stream day.
| Refinery Units | Nameplate Capacity | |||||||
| Crude Distillation Unit | 157,000 | |||||||
| Vacuum Distillation Unit | 102,000 | |||||||
| Fluid Catalytic Cracking Unit | 72,000 | |||||||
| Hydrotreating Units | 268,000 | |||||||
| Hydrocracking Unit | 42,900 | |||||||
| Alkylation Unit | 12,500 | |||||||
| Delayed Coking Unit | 25,500 | |||||||
| Flexi Coking Unit | 22,500 | |||||||
| Isomerization Unit | 15,000 | |||||||
Feedstocks and Supply Arrangements. We have entered into various five-year crude supply agreements with Shell Oil Products for approximately 150,000 bpd, in the aggregate, to support our West Coast and Mid-Continent refinery operations. Additionally, we obtain crude and feedstocks from other sources through connections to third-party pipelines as well as ship docks.
Refined Product Yield and Distribution. We entered into certain offtake agreements for our West Coast system with Shell Oil Products for clean products with varying terms up to 15 years. We currently market and sell all of our refined products independently to a variety of customers either on the spot market or through term agreements.
Tankage Capacity. Martinez has a total tankage capacity of approximately 8.8 million barrels. Of this total, approximately 2.5 million barrels are allocated to crude oil storage with the remaining 6.3 million barrels allocated to intermediates and products.
Energy and Other Utilities. Under normal operating conditions, the Martinez refinery consumes approximately 80,000 MMBTU per day of natural gas (including natural gas consumed in hydrogen production) supplied via pipeline from third parties. The Martinez refinery generates some power internally using a combination of steam and gas turbines and purchases any additional needed power from the local utility. The Martinez refinery has a long-term contract to purchase hydrogen from a third-party supplier.
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Agreements with PBFX
Beginning with the completion of the PBFX Offering, we have entered into a series of agreements with PBFX, including commercial and operational agreements. Each of these agreements and their impact to our operations is outlined below.
Contribution Agreements
Immediately prior to the closing of certain contribution agreements, which PBF LLC entered into with PBFX (as defined in the table below, and collectively referred to as the “Contribution Agreements”), we contributed certain assets to PBF LLC. PBF LLC in turn contributed those assets to PBFX pursuant to the Contribution Agreements. Certain proceeds received by PBF LLC from PBFX in accordance with the Contribution Agreements were subsequently contributed by PBF LLC to us. The Contribution Agreements include the following:
| Contribution Agreement | Effective Date | Assets Contributed | Total Consideration | ||||||||
| Contribution Agreement I | 5/8/2014 | DCR Rail Terminal and the Toledo Truck Terminal | 74,053 PBFX common units and 15,886,553 PBFX subordinated units | ||||||||
| Contribution Agreement II | 9/16/2014 | DCR West Rack | $135.0 million in cash and $15.0 million through the issuance of 589,536 PBFX common units | ||||||||
| Contribution Agreement III | 12/2/2014 | Toledo Storage Facility | $135.0 million in cash and $15.0 million through the issuance of 620,935 PBFX common units | ||||||||
| Contribution Agreement IV | 5/5/2015 | DCR Products Pipeline and DCR Truck Rack | $112.5 million in cash and $30.5 million through the issuance of 1,288,420 PBFX common units | ||||||||
| Contribution Agreement V | 8/31/2016 | Torrance Valley Pipeline (50% equity interest in TVPC) | $175.0 million in cash | ||||||||
| Contribution Agreement VI | 2/15/2017 | Paulsboro Natural Gas Pipeline | $11.6 million affiliate promissory note | ||||||||
| Contribution Agreements VII-X | 7/16/2018 | Development Assets | $31.6 million through the issuance of 1,494,134 PBFX common units | ||||||||
| Contribution Agreement XI | 4/24/2019 | Remaining 50% equity interest in TVPC | $200.0 million in cash | ||||||||
On July 16, 2018, PBFX entered into four contribution agreements with PBF LLC pursuant to which we contributed to PBF LLC certain of its subsidiaries (the “Development Assets Contribution Agreements”). Pursuant to the Development Asset Contribution Agreements, we contributed all of the issued and outstanding limited liability company interests of: Toledo Rail Logistics Company LLC, whose assets consist of a loading and unloading rail facility located at the 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 at the Chalmette refinery; Paulsboro Terminaling Company LLC, whose assets consist of a lube oil terminal facility located at the Paulsboro refinery (the “Paulsboro Lube Oil Terminal”); and DCR Storage and Loading Company LLC, whose assets consist of an ethanol storage facility located at the Delaware City refinery (collectively with the Toledo Rail Products Facility, the Chalmette Truck Rack, the Chalmette Rosin Yard, and the Paulsboro Lube Oil Terminal, the “Development Assets”) to PBF LLC. PBFX Operating Company LLC (“PBFX Op Co”), in turn acquired the
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limited liability company interests in the Development Assets from PBF LLC in connection with the Development Assets Contribution Agreements effective July 31, 2018.
On April 24, 2019, PBFX entered into a contribution agreement with PBF LLC, pursuant to which we contributed to PBF LLC, which in turn contributed to PBFX, all of the issued and outstanding limited liability company interests of TVP Holding Company LLC (“TVP Holding”) for total consideration of $200.0 million (the “TVPC Acquisition”). Prior to the TVPC Acquisition, TVP Holding (then our subsidiary) owned a 50% equity interest in Torrance Valley Pipeline Company LLC (“TVPC”). Subsequent to the closing of the TVPC Acquisition on May 31, 2019, PBFX owns 100% of the equity interests in TVPC.
Commercial Agreements
PBFX currently derives the majority of its revenue from long-term, fee-based agreements with us, which generally include a minimum volume commitment (“MVC”), as applicable, and are supported by contractual fee escalations for inflation adjustments and certain increases in operating costs. We believe the terms and conditions under these agreements, as well as the Omnibus Agreement and the Services Agreement (each as defined below), each with PBFX, are generally no less favorable to either party supplier.than those that could have been negotiated with unaffiliated parties with respect to similar services.
Refer to “Note 11 - Related Party Transactions” of our Notes to Consolidated Financial Statements for further discussion regarding the commercial agreements with PBFX.
Omnibus Agreement
In addition to the commercial agreements described above, PBFX entered into an omnibus agreement, which has been amended and restated in connection with the closing of certain of the Contribution Agreements with PBF GP, PBF LLC and us (as amended, the “Omnibus Agreement”). The Omnibus Agreement addresses the payment of an annual fee for the provision of various general and administrative services and reimbursement of salary and benefit costs for certain PBF Energy employees.
The annual fee under the Omnibus Agreement for the year ended December 31, 2020 was $7.6 million, inclusive of obligations under the Omnibus Agreement to reimburse us for certain compensation and benefit costs of employees who devoted more than 50% of their time to PBFX during the year ended December 31, 2020. We currently estimate to receive $8.3 million, inclusive of estimated obligations under the Omnibus Agreement as a reimbursement for certain compensation and benefit costs of employees who devote more than 50% of their time to PBFX for the year ending December 31, 2021.
Services Agreement
Additionally, PBFX entered into an operation and management services and secondment agreement with us and certain of our subsidiaries (as amended, the “Services Agreement”), pursuant to which we provide PBFX with the personnel necessary for PBFX to perform its obligations under its commercial agreements. PBFX reimburses us for the use of such employees and the provision of certain infrastructure-related services to the extent applicable to its operations, including storm water discharge and waste water treatment, steam, potable water, access to certain roads and grounds, sanitary sewer access, electrical power, emergency response, filter press, fuel gas, API solids treatment, fire water and compressed air. For the year ended December 31, 2020, PBFX paid us an annual fee of $8.7 million pursuant to the Services Agreement and we currently estimate to receive the same annual reimbursement pursuant to the Services Agreement for the year ending December 31, 2021.
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On February 13, 2019, we amended the existing Amended and Restated Delaware City Rail Terminaling Services Agreement, by and between Delaware City Terminaling Company LLC and us (as amended effective January 1, 2019, the “Amended and Restated Delaware City Rail Terminaling Services Agreement”) for the inclusion of services through certain rail infrastructure at PBFX’s acquired East Coast Storage Assets (the “East Coast Rail Assets”). We also entered into a new Terminaling Services Agreement, by and between Delaware City Terminaling Company and us, with a four-year term starting in 2022, subsequent to the expiration of the Amended and Restated Delaware City Rail Terminaling Services Agreement, related to the DCR Rail Facilities and the East Coast Rail Assets, which will reduce the MVC to 95,000 bpd and includes additional services to be provided by PBFX as operator of facilities owned by our subsidiaries.
The Services Agreement will terminate upon the termination of the Omnibus Agreement, provided that PBFX may terminate any service on 30-days’ notice.
Principal Products
Our refineries make various grades of gasoline, distillates (including diesel fuel, jet fuel, and ULSD) and other products from crude oil, other feedstocks, and blending components. We sell these products through our commercial accounts, and sales with major oil companies. For the years ended December 31, 2017, 20162020, 2019 and 2015,2018, gasoline and distillates accounted for 84.1%85.1%, 88.1%87.0% and 88.0%84.8% of our revenues, respectively.
Customers
We sell a variety of refined products to a diverse customer base. The majority of our refined products are primarily sold through short-term contracts or on the spot market. However, we do have product offtake arrangements for a portion of our clean products. For the year ended December 31, 2020, only one customer, Royal Dutch Shell, accounted for 10% or more of our revenues (approximately 13%). For the years ended December 31, 2017, 20162019 and 2015,2018, no single customer accounted for 10% or more of our revenues, respectively.revenues. As of December 31, 2017 and 2016, no2020, only one customer, Royal Dutch Shell, accounted for 10% or more of our total trade accounts receivable (approximately 17%). No single customer accounted for 10% or more of our total trade accounts receivable.receivable as of December 31, 2019.
Seasonality
Competition
The refining business is very competitive. We compete directly with various other refining companies on the East, Gulf and West Coasts and in the Mid-Continent, with integrated oil companies, with foreign refiners that import products into the United States and with producers and marketers in other industries supplying alternative forms of energy and fuels to satisfy the requirements of industrial, commercial and individual consumers. Some of our competitors have expanded the capacity of their refineries and internationally new refineries are coming on line which could also affect our competitive position.
Profitability in the refining industry depends largely on refined product margins, which can fluctuate significantly, as well as crude oil prices and differentials between the prices of different grades of crude oil, operating efficiency and reliability, product mix and costs of product distribution and transportation. Certain of our competitors that have larger and more complex refineries may be able to realize lower per-barrel costs or higher margins per barrel of throughput. Several of our principal competitors are integrated national or
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international oil companies that are larger and have substantially greater resources. Because of their integrated operations and larger capitalization, these companies may be more flexible in responding to volatile industry or market conditions, such as shortages of feedstocks or intense price fluctuations. Refining margins are frequently impacted by sharp changes in crude oil costs, which may not be immediately reflected in product prices.
The refining industry is highly competitive with respect to feedstock supply. Unlike certain of our competitors that have access to proprietary controlled sources of crude oil production available for use at their own refineries, we obtain all of our crude oil and substantially all other feedstocks from unaffiliated sources. The availability and cost of crude oil and feedstock are affected by global supply and demand. We have no crude oil reserves and are not engaged in the exploration or production of crude oil. We believe, however, that we will be able to obtain adequate crude oil and other feedstocks at generally competitive prices for the foreseeable future.
Corporate Offices
We currently lease approximately 58,00063,000 square feet for our principal corporate offices in Parsippany, New Jersey. The lease for our principal corporate offices expires in 2019.2022. Functions performed in the Parsippany office
include overall corporate management, refinery and HSEhealth, safety and environmental management, planning and strategy, corporate finance, commercial operations, logistics, contract administration, marketing, investor relations, governmental affairs, accounting, tax, treasury, information technology, legal and human resources support functions.
We lease approximately 4,000 square feet for our regional corporate office in Long Beach, California. The lease for our Long Beach office expires in 2021. Functions performed in the Long Beach office include overall regional corporate management, planning and strategy, commercial operations, logistics, contract administration, marketing and governmental affairs functions.affairs.
Employees and Human Capital
Safety
We believe our responsibility to our employees, neighbors, members and the environment is only fulfilled through our commitment to safety and reliability. Through rigorous training, sharing of expertise across our sites, continuous monitoring and through promoting a culture of excellence in operations, we continuously strive to keep our people, the communities in which we operate in and the environment safe.
Our focus on safety is also evident in our response to the COVID-19 pandemic. We continue to utilize our COVID-19 response team to implement additional social distancing measures across the workplace in addition to the continued enhancement of personal protective equipment and the cleanliness of our facilities. Through the guidance of our COVID-19 response team, we have started to bring back a portion of our workforce to their primary locations on a phased in approach, and we will continue to rely on our team and the evolution of the COVID-19 pandemic as we evaluate the appropriate time and way in which we will phase in the return of the rest of our workforce.
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We are subject to the requirements of the Occupational Safety and Health Administration of the U.S. Department of Labor (“OSHA”) and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA Hazard Communication Standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances.
Development and Retention
The development, attraction and retention of employees is a critical success factor for our Company. To support the advancement of our employees, we offer rigorous training and development programs and encourage the sharing of expertise across our sites. We actively promote inclusion and diversity in our workforce at each of our locations and provide our employees with opportunities to give back through engagement in our local communities through supportive educational programs, philanthropic and volunteer activities.
We believe that a combination of competitive compensation and career growth and development opportunities help increase employee morale and reduce voluntary turnover. Our comprehensive benefit packages are competitive in the marketplace and we believe in recognizing and rewarding talent through our various cash and equity compensation programs.
Headcount
As of December 31, 2017,2020, we had approximately 3,126 employees. At our Paulsboro refinery, 2863,638 employees, of our 461which 1,931 are covered by collective bargaining agreements. Our hourly employees are covered by a collective bargaining agreement. In addition, 1,331agreements through the United Steel Workers (“USW”), the Independent Oil Workers (“IOW”) and the International Brotherhood of our 2,316 employees at our Delaware City, Toledo, Chalmette and Torrance refineries and our related logistics assets are covered by a collective bargaining agreement. None of our corporate employees are covered by a collective bargaining agreement.Electrical Workers (“IBEW”). We consider our relations with the represented employees to be satisfactory. At Delaware City, Toledo, Chalmette and Torrance, most hourly employees are covered by a collective bargaining agreement through the United Steel Workers (“USW”). The agreements with the USW covering Delaware City, Torrance and Chalmette are scheduled to expire in January 2019, while the agreement with the USW covering Toledo is scheduled to expire in February 2019. Similarly, at Paulsboro hourly employees are represented by the Independent Oil Workers (“IOW”) under a contract scheduled to expire in March 2019.
| Location | Number of employees | Employees covered by collective bargaining agreements | Collective bargaining agreements | Expiration date | ||||||||||||||||||||||
| Headquarters | 397 | — | N/A | N/A | ||||||||||||||||||||||
| Delaware City refinery | 518 | 358 | USW | January 2022 | ||||||||||||||||||||||
| Paulsboro refinery | 442 | 260 | IOW | March 2022 | ||||||||||||||||||||||
| Toledo refinery | 483 | 313 | USW | February 2022 | ||||||||||||||||||||||
| Chalmette refinery | 543 | 307 | USW | January 2022 | ||||||||||||||||||||||
| Torrance refinery | 564 | 297 12 | USW IBEW | January 2022 January 2022 | ||||||||||||||||||||||
| Torrance logistics | 106 | 42 4 | USW USW | April 2021 January 2022 | ||||||||||||||||||||||
| Martinez refinery | 585 | 314 24 | USW IBEW | February 2022 February 2022 | ||||||||||||||||||||||
| Total employees | 3,638 | 1,931 | ||||||||||||||||||||||||
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Environmental, Health and Safety Matters
Our refineries, pipelines and related operations are subject to extensive and frequently changing federal, state and local laws and regulations, including, but not limited to, those relating to the discharge of materials into the environment or that otherwise relate to the protection of the environment, waste management and the characteristics and the compositions of fuels. Compliance with existing and anticipated laws and regulations can increase the overall cost of operating the refineries, including remediation, operating costs and capital costs to construct, maintain and upgrade equipment and facilities. Permits are also required under these laws for the operation of our refineries, pipelines and related operations and these permits are subject to revocation, modification and renewal. Compliance with applicable environmental laws, regulations and permits will continue to have an impact on our operations, results of operations and capital requirements. We believe that our current operations are in substantial compliance with existing environmental laws, regulations and permits.
•Item 1A. “Risk Factors”
◦ We may incur significant liability is recorded in Accrued expensesunder, or costs and the non-current portion is recorded in Other long-term liabilities. Ascapital expenditures to comply with, environmental and health and safety regulations, which are complex and change frequently;
◦ Environmental clean-up and remediation costs of December 31, 2017our sites and December 31, 2016, this liability is self-guaranteed by us.environmental litigation could decrease our net cash flow, reduce our results of operations and impair our financial condition;
◦ Changes in laws or cash flows, individuallystandards affecting the transportation of North American crude oil by rail could significantly impact our operations, and as a result cause our costs to increase.
◦ We could incur substantial costs or disruptions in the aggregate.our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with health, safety, environmental and other laws and regulations.
•Item 3. “Legal Proceedings”
•Item 8. “Financial Statements and Supplementary Data”
◦ Note 8 - Accrued Expenses,
◦ Note 10 - Other Long-Term Liabilities and
◦ Note 12 - Commitments and Contingencies
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“ASCI” refers to the Argus Sour Crude Index, a pricing index used to approximate market prices for sour, heavy crude oil.
“Bakken” refers to both a crude oil production region generally covering North Dakota, Montana and Western Canada, and the crude oil that is produced in that region.
“barrel” refers to a common unit of measure in the oil industry, which equates to 42 gallons.
“blendstocks” refers to various compounds that are combined with gasoline or diesel from the crude oil refining process to make finished gasoline and diesel; these may include natural gasoline, FCC unit gasoline, ethanol, reformate or butane, among others.
“bpd” refers to an abbreviation for barrels per day.
“CAA” refers to the Clean Air Act.
“CAM Pipeline” or “CAM Connection Pipeline” refers to the Clovelly-Alliance-Meraux pipeline in Louisiana.
“CARB”refers to the California Air Resources Board; gasoline and diesel fuel sold in the state of California are regulated by CARB and require stricter quality and emissions reduction performance than required by other states.
“catalyst” refers to a substance that alters, accelerates, or instigates chemical changes, but is not produced as a product of the refining process.
“coke” refers to a coal-like substance that is produced from heavier crude oil fractions during the refining process.
“complexity” refers to the number, type and capacity of processing units at a refinery, measured by the Nelson Complexity Index, which is often used as a measure of a refinery’s ability to process lower quality crude in an economic manner.
“COVID-19” refers to the 2019 outbreak of the novel coronavirus pandemic.
“crack spread” refers to a simplified calculation that measures the difference between the price for light products and crude oil. For example, we reference (a) the 2-1-1 crack spread, which is a general industry standard utilized by our Delaware City, Paulsboro and Chalmette refineries that approximates the per barrel refining margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of heating oil or ULSD, (b) the 4-3-1 crack spread, which is a benchmark utilized by our Toledo and Torrance refineries that approximates the per barrel refining margin resulting from processing four barrels of crude oil to produce three barrels of gasoline and one-half barrel of jet fuel and one-half barrel of ULSD and (c) the 3-2-1 crack spread, which is a benchmark utilized by our Martinez refinery that approximates the per barrel refining margin resulting from processing three barrels of crude oil to produce two barrels of gasoline and three-quarters of a barrel jet fuel and one-quarter of a barrel ULSD.
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“Dated Brent” refers to Brent blend oil, a light, sweet North Sea crude oil, characterized by an American Petroleum Institute (“API”) gravity of 38° and a sulfur content of approximately 0.4 weight percent, that is used as a benchmark for other crude oils.
“distillates” refers primarily to diesel, heating oil, kerosene and jet fuel.
“DNREC” refers to the Delaware Department of Natural Resources and Environmental Control.
“downstream” refers to the downstream sector of the energy industry generally describing oil refineries, marketing and distribution companies that refine crude oil and sell and distribute refined products. The opposite of the downstream sector is the upstream sector, which refers to exploration and production companies that search for and/or produce crude oil and natural gas underground or through drilling or exploratory wells.
“EPA” refers to the United States Environmental Protection Agency.
“ethanol” refers to a clear, colorless, flammable oxygenated liquid. Ethanol is typically produced chemically from ethylene, or biologically from fermentation of various sugars from carbohydrates found in agricultural crops. It is used in the United States as a gasoline octane enhancer and oxygenate.
“Ethanol Permit” refers to the Coastal Zone Act permit for ethanol issued to our Delaware City refinery.
“FASB” refers to the Financial Accounting Standards Board which develops U.S. generally accepted accounting principles.
“FCC” refers to fluid catalytic cracking.
“feedstocks” refers to crude oil and partially refined petroleum products that are processed and blended into refined products.
“FERC” refers to the Federal Energy Regulatory Commission.
“GAAP” refers to U.S. generally accepted accounting principles developed by FASB for nongovernmental entities.
“GHG” refers to greenhouse gas.
“Group I base oils or lubricants” refers to conventionally refined products characterized by sulfur content less than 0.03% with a viscosity index between 80 and 120. Typically, these products are used in a variety of automotive and industrial applications.
“heavy crude oil” refers to a relatively inexpensive crude oil with a low API gravity characterized by high relative density and viscosity. Heavy crude oils require greater levels of processing to produce high value products such as gasoline and diesel.
“IMO” refers to the International Maritime Organization.
“IPO” refers to the initial public offering of PBF Energy Class A common stock which closed on December 18, 2012.
“J. Aron” refers to J. Aron & Company, a subsidiary of The Goldman Sachs Group, Inc.
“KV” refers to Kilovolts.
“LCM” refers to a GAAP requirement for inventory to be valued at the lower of cost or market.
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“light crude oil” refers to a relatively expensive crude oil with a high API gravity characterized by low relative density and viscosity. Light crude oils require lower levels of processing to produce high value products such as gasoline and diesel.
“light-heavy differential” refers to the price difference between light crude oil and heavy crude oil.
“light products” refers to the group of refined products with lower boiling temperatures, including gasoline and distillates.
“LLS” refers to Light Louisiana Sweet benchmark for crude oil reflective of Gulf coast economics for light sweet domestic and foreign crudes. It is characterized by an API gravity of between 35° and 40° and a sulfur content of approximately .35 weight percent.
“LPG” refers to liquefied petroleum gas.
“Maya” refers to Maya crude oil, a heavy, sour crude oil characterized by an API gravity of approximately 22° and a sulfur content of approximately 3.3 weight percent that is used as a benchmark for other heavy crude oils.
“MLP” refers to the master limited partnership.
“MMBTU” refers to million British thermal units.
“MOEM Pipeline” refers to a pipeline that originates at a terminal in Empire, Louisiana approximately 30 miles north of the mouth of the Mississippi River. The MOEM Pipeline is 14 inches in diameter, 54 miles long and transports crude from South Louisiana to the Chalmette refinery and transports Heavy Louisiana Sweet (HLS) and South Louisiana Intermediate (SLI) crude.
“MW” refers to Megawatt.
“Nelson Complexity Index” refers to the complexity of an oil refinery as measured by the Nelson Complexity Index, which is calculated on an annual basis by the Oil and Gas Journal. The Nelson Complexity Index assigns a complexity factor to each major piece of refinery equipment based on its complexity and cost in comparison to crude distillation, which is assigned a complexity factor of 1.0. The complexity of each piece of refinery equipment is then calculated by multiplying its complexity factor by its throughput ratio as a percentage of crude distillation capacity. Adding up the complexity values assigned to each piece of equipment, including crude distillation, determines a refinery’s complexity on the Nelson Complexity Index. A refinery with a complexity of 10.0 on the Nelson Complexity Index is considered ten times more complex than crude distillation for the same amount of throughput.
“NYH” refers to the New York Harbor market value of petroleum products.
“NYMEX” refers to the New York Mercantile Exchange.
“PADD” refers to Petroleum Administration for Defense Districts.
“Platts” refers to Platts, a division of The McGraw-Hill Companies.
“PPM” refers to parts per million.
“refined products” refers to petroleum products, such as gasoline, diesel and jet fuel, that are produced by a refinery.
“Renewable Fuel Standard” refers to the Renewable Fuel Standard issued pursuant to Assembly Bill 32the Energy Independence and Security Act of 2007 implementing mandates to blend renewable fuels into petroleum fuels produced and sold in the United States.
“RINs” refers to renewable fuel credits required for compliance with the Renewable Fuel Standard.
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“Saudi Aramco” refers to Saudi Arabian Oil Company.
“SEC” refers to the United States Securities and Exchange Commission.
“sour crude oil” refers to a crude oil that is relatively high in sulfur content, requiring additional processing to remove the sulfur. Sour crude oil is typically less expensive than sweet crude oil.
“Sunoco” refers to Sunoco, LLC.
“sweet crude oil” refers to a crude oil that is relatively low in sulfur content, requiring less processing to remove the sulfur than sour crude oil. Sweet crude oil is typically more expensive than sour crude oil.
“Syncrude” refers to a blend of Canadian synthetic oil, a light, sweet crude oil, typically characterized by API gravity between 30° and 32° and a sulfur content of approximately 0.1-0.2 weight percent.
“throughput” refers to the volume processed through a unit or refinery.
“turnaround” refers to a periodically required shutdown and comprehensive maintenance event to refurbish and maintain a refinery unit or units that involves the cleaning, repair, and inspection of such units and occurs generally on a periodic cycle.
“ULSD” refers to ultra-low-sulfur diesel.
“WCS” refers to Western Canadian Select, a heavy, sour crude oil blend typically characterized by API gravity between 20° and 22° and a sulfur content of approximately 3.5 weight percent that is used as a benchmark for heavy Western Canadian crude oil.
“WTI” refers to West Texas Intermediate crude oil, a light, sweet crude oil, typically characterized by API gravity between 38° and 40° and a sulfur content of approximately 0.3 weight percent that is used as a benchmark for other crude oils.
“WTS” refers to West Texas Sour crude oil, a sour crude oil characterized by API gravity between 30° and 33° and a sulfur content of approximately 1.28 weight percent that is used as a benchmark for other sour crude oils.
“yield” refers to the percentage of refined products that is produced from crude oil and other feedstocks.
Explanatory Note
This Form 10-K is filed by PBF Holding Company LLC (“AB32”PBF Holding”) and PBF Finance Corporation (“PBF Finance”). AB32 imposesPBF Holding is a statewide capwholly-owned subsidiary of PBF Energy Company LLC (“PBF LLC”) and is the parent company for PBF LLC's refinery operating subsidiaries. PBF Finance is a wholly-owned subsidiary of PBF Holding. PBF Holding is an indirect subsidiary of PBF Energy Inc. (“PBF Energy”), which is the sole managing member of, and owner of an equity interest representing approximately 99.2% of the outstanding economic interests in PBF LLC as of December 31, 2020. PBF Energy operates and controls all of the business and affairs and consolidates the financial results of PBF LLC and its subsidiaries. PBF Holding, together with its consolidated subsidiaries, owns and operates oil refineries and related facilities in North America.
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PART I
In this Annual Report on greenhouse gas emissions,Form 10-K, unless the context otherwise requires, references to the “Company,” “we,” “our” or “us” refer to PBF Holding, and, in each case, unless the context otherwise requires, its consolidated subsidiaries. References to “subsidiary guarantors” refer to PBF Services Company LLC (“PBF Services”), PBF Power Marketing LLC (“PBF Power”), Paulsboro Refining Company LLC (“Paulsboro Refining” or “PRC”), Toledo Refining Company LLC (“Toledo Refining”), Delaware City Refining Company LLC (“DCR”), PBF Investments LLC (“PBF Investments”), PBF International Inc., Chalmette Refining, L.L.C. (“Chalmette Refining”), PBF Energy Western Region LLC (“PBF Western Region”), Torrance Refining Company LLC (“Torrance Refining”), Torrance Logistics Company LLC (“Torrance Logistics”), and Martinez Refining Company LLC (“Martinez Refining”), which are the subsidiaries of PBF Holding that guarantee PBF Holding’s 7.25% senior notes due 2025 (the “2025 Senior Notes”), 6.00% senior unsecured notes due 2028 (the “2028 Senior Notes”), and the 9.25% senior secured notes due 2025 (the “2025 Senior Secured Notes”) as of December 31, 2020.
In this Annual Report on Form 10-K, we make certain forward-looking statements, including emissions fromstatements regarding our plans, strategies, objectives, expectations, intentions, and resources. You should read our forward-looking statements together with our disclosures under the heading: “Cautionary Statement Regarding Forward-Looking Statements.” When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in this Annual Report on Form 10-K under “Risk Factors” in Item 1A.
ITEM. 1 BUSINESS
Overview and Corporate Structure
We are one of the largest independent petroleum refiners and suppliers of unbranded transportation fuels, heating oil, petrochemical feedstocks, lubricants and other petroleum products in the United States. We sell our products throughout the Northeast, Midwest, Gulf Coast and West Coast of the United States, as well as in other regions of the United States, Canada and Mexico and are able to ship products to other international destinations. We were formed in 2008 to pursue acquisitions of crude oil refineries and downstream assets in North America. As of December 31, 2020, we own and operate six domestic oil refineries and related assets, which we acquired in 2010, 2011, 2015, 2016 and 2020. Based on the current configuration (as disclosed in “Recent Developments - East Coast Refining Reconfiguration”) our refineries have a combined 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. The Company’s six oil refineries are aggregated into one reportable segment.
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Ownership Structure
We are a Delaware limited liability company and a holding company for our operating subsidiaries. PBF Finance is a wholly-owned subsidiary of PBF Holding. We are a wholly-owned subsidiary of PBF LLC, and PBF Energy is the sole managing member of, and owner of an equity interest as of December 31, 2020 representing approximately 99.2% of the outstanding economic interests in PBF LLC.
On December 18, 2012, our indirect parent, PBF Energy completed its IPO. As a result of PBF Energy’s IPO and related organization transactions, PBF Energy became the sole managing member of PBF LLC and operates and controls all of its business and affairs and consolidates the financial results of PBF LLC and its subsidiaries, including PBF Holding and PBF Finance. As of December 31, 2020, PBF Energy held 120,122,872 PBF LLC Series C Units and its current and former executive officers and directors and certain employees and others beneficially held 970,647 PBF LLC Series A Units, and the holders of PBF Energy’s issued and outstanding shares of its Class A common stock have approximately 99.2% of the voting power in PBF Energy and the members of PBF LLC other than PBF Energy through their holdings of Class B common stock have the remaining 0.8% of the voting power.
PBF Holding Refineries
Our six refineries are located in Delaware City, Delaware, Paulsboro, New Jersey, Toledo, Ohio, Chalmette, Louisiana, Torrance, California and Martinez, California. In 2020, we reconfigured our Delaware and Paulsboro refineries, temporarily idling certain of our major processing units at the Paulsboro refinery, in order to operate the two refineries as one functional unit that we refer to as the “East Coast Refining System”. Refer to “Recent Developments” below for additional information. Each refinery is briefly described in the table below:
| Refinery | Region | Nelson Complexity Index (1) | Throughput Capacity (in barrels per day) (1) | PADD | Crude Processed (2) | Source (2) | ||||||||||||||
| Delaware City | East Coast | 13.6 | 180,000 | 1 | light sweet through heavy sour | water, rail | ||||||||||||||
| Paulsboro | East Coast | 10.4 (3) | 105,000(3) | 1 | light sweet through heavy sour | water | ||||||||||||||
| Toledo | Mid-Continent | 11.0 | 180,000 | 2 | light sweet | pipeline, truck, rail | ||||||||||||||
| Chalmette | Gulf Coast | 13.0 | 185,000 | 3 | light sweet through heavy sour | water, pipeline | ||||||||||||||
| Torrance | West Coast | 13.8 | 166,000 | 5 | medium and heavy | pipeline, water, truck | ||||||||||||||
| Martinez | West Coast | 16.1 | 157,000 | 5 | medium and heavy | pipeline and water | ||||||||||||||
________
(1) Reflects operating conditions at each refinery as of the date of this filing. Changes in complexity and throughput capacity reflect the result of current market conditions such as our East Coast Refining Reconfiguration (defined below), in addition to investments made to improve our facilities and maintain compliance with environmental and governmental regulations. Configurations at each of our refineries are evaluated and updated accordingly.
(2) Reflects the typical crude and feedstocks and related sources utilized under normal operating conditions and prevailing market environments.
(3) Under normal operating conditions and prevailing market environments, our Nelson Complexity Index and throughput capacity for the Paulsboro refinery would be 13.1 and 180,000, respectively. As a result of the east coast refining reconfiguration described below (the “East Coast Refining Reconfiguration”), our Nelson Complexity Index and throughput capacity were reduced.
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Public Offerings of PBF Logistics LP and Subsequent Drop-Down Transactions
PBF Logistics LP (“PBFX”) is an affiliate of ours. PBFX is a fee-based, growth-oriented, publicly-traded Delaware master limited partnership formed by PBF Energy to own or lease, operate, develop and acquire crude oil and refined petroleum products terminals, pipelines, storage facilities and similar logistics assets. PBFX engages in the receiving, handling, storage and transferring of crude oil, refined products, natural gas and intermediates from sources located throughout the United States and Canada for PBF Energy in support of certain of its refineries, as well as for third-party customers. As of December 31, 2020, a substantial majority of PBFX’s revenues are derived from long-term, fee-based commercial agreements with us, which include minimum volume commitments, for receiving, handling, storing and transferring crude oil, refined products, and natural gas. PBF Energy also has agreements with PBFX that establish fees for certain general and administrative services and operational and maintenance services provided by us to PBFX.
PBF Logistics GP LLC (“PBF GP”) serves as the general partner of PBFX. PBF GP is wholly-owned by PBF LLC. On May 14, 2014, PBFX completed its initial public offering (the “PBFX Offering”). In connection with the aimPBFX Offering, we distributed to PBF LLC, which in turn contributed to PBFX, the assets and liabilities of returningcertain crude oil terminaling assets. In a series of transactions subsequent to the statePBFX Offering, we distributed certain additional assets to 1990 emissionPBF LLC, which in turn contributed those assets to PBFX. See “Agreements with PBFX” below as well as “Note 11 - Related Party Transactions” of our Notes to Consolidated Financial Statements for additional information.
See “Item 1A. Risk Factors” and “Item 13. Certain Relationships and Related Transactions, and Director Independence.”
Recent Developments
COVID-19
The outbreak of the COVID-19 pandemic and certain developments in the global oil markets negatively impacted worldwide economic and commercial activity and financial markets in 2020 and is expected to continue in 2021. The COVID-19 pandemic and the related governmental and consumer responses resulted in significant business and operational disruptions, including business and school closures, supply chain disruptions, travel restrictions, stay-at-home orders and limitations on the availability of workforces and has resulted in significantly lower global demand for refined petroleum and petrochemical products. We believe, but cannot guarantee, that demand for refined petroleum products will ultimately rebound as governmental restrictions are lifted. However, the continued negative impact of the COVID-19 pandemic and these market developments on our business and operations will depend on the ongoing severity, location and duration of the effects and spread of COVID-19, the effectiveness of the vaccine programs and the other actions undertaken by national, regional and local governments and health officials to contain the virus or treat its effects, and how quickly and to what extent economic conditions improve and normal business and operating conditions resume.
We are actively responding to the impacts from these matters on our business. Starting in late March through the end of 2020, we reduced the amount of crude oil processed at our refineries in response to the decreased demand for our products and we temporarily idled various units at certain of our refineries to optimize our production in light of prevailing market conditions. As of the date of this filing, our refineries are still operating at reduced throughput levels and we expect them to continue to do so until market conditions substantially improve. Despite the measures we have taken, we have been, and likely will continue to be, adversely impacted by 2020. AB32 is implementedthe COVID-19 pandemic. We are unable to predict the ultimate outcome of the economic impact and can provide no assurance that measures taken to mitigate the impact of the COVID-19 pandemic will be effective.
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Over the course of 2020 we adjusted our operational plans to the evolving market conditions and executed our plan to lower our 2020 operating expenses through two market mechanismssignificant 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. We expect to continue to target and execute these expense reduction measures in 2021. 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 historic levels, including the Low Carbon Fuel Standard (“LCFS”East Coast Refining Reconfiguration. We operated our refineries at reduced rates during the year ended December 31, 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. We expect near-term throughput to be in the 675,000 to 725,000 barrel per day range for our refining system.
East Coast Refining Reconfiguration
The East Coast Refining Reconfiguration was announced on October 29, 2020 and completed on December 31, 2020. It is expected to provide us with crude optionality and increased flexibility to respond to evolving market conditions. Our East Coast Refining System throughput capacity is approximately 285,000 barrels per day, reflecting the new configuration and idling of certain major processing units. Annual operating and capital expenditures savings are expected to be approximately $100.0 million and $50.0 million, respectively, relative to average historic levels.
Available Information
Our website address is www.pbfenergy.com. Information contained on our website is not part of this Annual Report on Form 10-K. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any other materials filed with (or furnished to) the SEC by us are available on our website (under “Investors”) free of charge, soon after we file or furnish such material.
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The diagram below depicts our organizational structure as of December 31, 2020:
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Refining Operations
We own and Capoperate six refineries (two of which are operated as a single unit) that provide us with geographic and Trade,market diversity. We produce a variety of products at each of our refineries, including gasoline, ULSD, heating oil, jet fuel, lubricants, petrochemicals and asphalt. We sell our products throughout the Northeast, Midwest, Gulf Coast and West Coast of the United States, as well as in other regions of the United States, Canada and Mexico, and are able to ship products to other international destinations.
Our refinery assets as of December 31, 2020 are described below.
East Coast Refining System (Delaware City Refinery and Paulsboro Refinery)
Overview. The Delaware City refinery is located on an approximately 5,000-acre site, with access to waterborne cargoes and an extensive distribution network of pipelines, barges and tankers, truck and rail. The Delaware City refinery is a fully integrated operation that receives crude via rail at crude unloading facilities owned by PBFX, or via ship or barge at the docks owned by the Delaware City refinery located on the Delaware River. The crude and other feedstocks are stored in an extensive tank farm prior to processing. In addition, there is a 15-lane, 76,000 bpd capacity truck loading rack (the “DCR Truck Rack”) located adjacent to the refinery and a 23-mile interstate pipeline (the “DCR Products Pipeline”) that are used to distribute clean products. The DCR Products Pipeline and DCR Truck Rack were sold to PBFX in May 2015 and PBFX owns additional assets that support the Delaware City refinery. The Paulsboro refinery is located on approximately 950 acres on the Delaware River in Paulsboro, New Jersey, near Philadelphia and approximately 30 miles away from Delaware City. Paulsboro receives crude and feedstocks via its marine terminal on the Delaware River.
As a result of its configuration and process units, Delaware City has the capability of processing a slate of heavy crudes with a high concentration of high sulfur crudes, as well as other high sulfur feedstock when economically viable, and is one of the largest and most complex refineries on the East Coast. The Delaware City refinery is one of two heavy crude processing refineries, the other being our Paulsboro refinery, on the East Coast of the United States. The Delaware City coking capacity is equal to approximately 25% of crude capacity.
The Delaware City refinery primarily processes a variety of medium to heavy, sour crude oils, but can run light, sweet crude oils as well. The refinery has large conversion capacity with its 82,000 bpd FCC unit, 54,500 bpd fluid coking unit and 24,000 bpd hydrocracking unit.
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The following table approximates the East Coast Refining System’s current major process unit capacities. Unit capacities are shown in barrels per stream day.
| Delaware City Refinery Units | Nameplate Capacity | ||||
| Crude Distillation Unit | 180,000 | ||||
| Vacuum Distillation Unit | 105,000 | ||||
| Fluid Catalytic Cracking Unit | 82,000 | ||||
| Hydrotreating Units | 180,000 | ||||
| Hydrocracking Unit | 24,000 | ||||
| Catalytic Reforming Unit | 43,000 | ||||
| Benzene / Toluene Extraction Unit | 15,000 | ||||
| Butane Isomerization Unit | 6,000 | ||||
| Alkylation Unit | 12,500 | ||||
| Polymerization Unit | 16,000 | ||||
| Fluid Coking Unit | 54,500 | ||||
| Paulsboro Refinery Units | Nameplate Capacity | |||||||
Crude Distillation Units (1) | 105,000 | |||||||
Vacuum Distillation Units (1) | 50,000 | |||||||
Fluid Catalytic Cracking Unit (1) | Idled | |||||||
Hydrotreating Units (1) | 61,000 | |||||||
Catalytic Reforming Unit (1) | Idled | |||||||
Alkylation Unit (1) | Idled | |||||||
| Lube Oil Processing Unit | 12,000 | |||||||
Delayed Coking Unit (1) | Idled | |||||||
| Propane Deasphalting Unit | 11,000 | |||||||
(1)Current Nameplate Capacity was fully or partially reduced to reflect the idled units as part of the East Coast Refining Reconfiguration.
Feedstocks and Supply Arrangements. We source our crude oil needs for Delaware City primarily through short-term and spot market agreements. We have a contract with Saudi Aramco pursuant to which waswe have purchased up to approximately 100,000 bpd of crude oil from Saudi Aramco that is processed at Paulsboro. The crude purchased under this contract is priced off the ASCI.
Refined Product Yield and Distribution. The Delaware City refinery predominantly produces gasoline, jet fuel, ULSD and ultra-low sulfur heating oil as well as certain other products. Products produced at the Delaware City refinery are transferred to customers through pipelines, barges or at its truck rack. We market and sell all of our refined products independently to a variety of customers on the spot market or through term agreements. The Paulsboro refinery predominantly manufactures Group I base oils or lubricants and asphalt and jet fuel. Products produced at the Paulsboro refinery are transferred to customers primarily through pipelines, barges, or at its truck rack. We market and sell all of our refined products independently to a variety of customers on the spot market or through term agreements.
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Inventory Intermediation Agreement. On August 29, 2019, we entered into amended and restated inventory intermediation agreements with J. Aron, (as amended from time to time, the “Inventory Intermediation Agreements”), to support the operations of the Delaware City and Paulsboro refineries. The Inventory Intermediation Agreement by and among J. Aron, PBF Holding and DCR expires on June 30, 2021, which term may be further extended by mutual consent of the parties to June 30, 2022. The Inventory Intermediation Agreement by and among J. Aron, PBF Holding and PRC expires on December 31, 2021, which term may be further extended by mutual consent of the parties to December 31, 2022.
Pursuant to each Inventory Intermediation Agreement, J. Aron purchases and holds title to certain inventory, including crude oil, intermediate and certain finished products (the “J. Aron Products”), produced by the refinery and delivered into our storage tanks at the Delaware City and Paulsboro refineries and at PBFX’s assets acquired from Crown Point International in October 2018 (the “East Coast Storage Assets” and together with our storage tanks at the Delaware City and Paulsboro refineries, the “J. Aron Storage Tanks”). The J. Aron Products are sold back to us as the J. Aron Products are discharged out of our J. Aron Storage Tanks. At expiration or termination of each of the Inventory Intermediation Agreements, we will have to repurchase the inventories outstanding under the Inventory Intermediation Agreement at that time.
Tankage Capacity. The Delaware City refinery has total storage capacity of approximately 10.0 million barrels. Of the total, approximately 3.6 million barrels of storage capacity are dedicated to crude oil and other feedstock storage with the remaining 6.4 million barrels allocated to finished products, intermediates and other products. The Paulsboro refinery has total storage capacity of approximately 7.5 million barrels. Of the total, approximately 2.1 million barrels are dedicated to crude oil storage with the remaining 5.4 million barrels allocated to finished products, intermediates and other products.
Energy and Other Utilities. Under normal operating conditions, the Delaware City refinery consumes approximately 75,000 MMBTU per day of natural gas supplied via pipeline from third parties. The Delaware City refinery has a 280 MW power plant located on site that consists of two natural gas-fueled turbines with combined capacity of approximately 140 MW and four turbo generators with combined nameplate capacity of approximately 140 MW. Collectively, this power plant produces electricity in excess of Delaware City’s refinery load of approximately 90 MW. Excess electricity is sold into the Pennsylvania-New Jersey-Maryland, or PJM, grid. Steam is primarily produced by a combination of three dedicated boilers, two heat recovery steam generators on the gas turbines, and is supplemented by secondary boilers at the FCC and Coker. Hydrogen is currently provided via the refinery’s steam methane reformer and continuous catalytic reformer.
Under projected normal operating conditions for the reconfiguration, the Paulsboro refinery will consume approximately 38,000 MMBTU per day of natural gas supplied via pipeline from third parties. The Paulsboro refinery will be mostly self-sufficient for electrical power through a mix of gas and steam turbine generators. The Paulsboro refinery generation is projected to supply all of the 20MW total refinery load. There are circumstances where available generation is greater than the total refinery load, and the Paulsboro refinery can export up to about 40MW of power to the utility grid if warranted. If necessary, supplemental electrical power is available on a guaranteed basis from the local utility. The Paulsboro refinery is connected to the grid via three separate 69KV aerial feeders and has the ability to run entirely on imported power. Steam is produced in three boilers and a heat recovery steam generator fed by the exhaust from the gas turbine. In addition, there are a number of waste heat boilers and furnace stack economizers throughout the refinery that supplement the steam generation capacity. The Paulsboro refinery’s hydrogen needs will be met by the steam methane reformer as the catalytic reformer will be idled.
Hydrogen Plant Project. During 2018, we signed an agreement with a third-party for an additional 10 yearssupply of 25.0 million standard cubic feet per day of hydrogen from a new hydrogen generation facility constructed on the Delaware City site, which was completed in the second quarter of 2020. This additional hydrogen provides additional complex crude and feedstock processing capabilities.
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Toledo Refinery
Overview. The Toledo refinery primarily processes a slate of light, sweet crudes from Canada, the Mid-Continent, the Bakken region and the U.S. Gulf Coast. The Toledo refinery is located on a 282-acre site near Toledo, Ohio, approximately 60 miles from Detroit. Crude is delivered to 2030the Toledo refinery through three primary pipelines: (1) Enbridge from the north, (2) Patoka from the west and (3) Mid-Valley from the south. Crude is also delivered to a nearby terminal by rail and from local sources by truck to a truck unloading facility within the refinery.
The following table approximates the Toledo refinery’s current major process unit capacities. Unit capacities are shown in July 2017.barrels per stream day.
| Refinery Units | Nameplate Capacity | ||||
| Crude Distillation Unit | 180,000 | ||||
| Fluid Catalytic Cracking Unit | 82,000 | ||||
| Hydrotreating Units | 95,000 | ||||
| Hydrocracking Unit | 52,000 | ||||
| Catalytic Reforming Units | 52,000 | ||||
| Alkylation Unit | 11,000 | ||||
| Polymerization Unit | 7,000 | ||||
| UDEX Unit | 16,300 | ||||
Feedstocks and Supply Arrangements. We source our crude oil needs for Toledo primarily through short-term and spot market agreements.
Refined Product Yield and Distribution. Toledo produces finished products, including gasoline, jet and ULSD, in addition to a variety of high-value petrochemicals including benzene, toluene, xylene, nonene and tetramer. Toledo is connected, via pipelines, to an extensive distribution network throughout Ohio, Illinois, Indiana, Kentucky, Michigan, Pennsylvania and West Virginia. The finished products are responsibletransported on pipelines owned by Sunoco Logistics Partners L.P. and Buckeye Partners L.P. In addition, we have proprietary connections to a variety of smaller pipelines and spurs that help us optimize our clean products distribution. A significant portion of Toledo’s gasoline and ULSD are distributed through various terminals in this network.
We have an agreement with Sunoco whereby Sunoco purchases gasoline and distillate products representing approximately one-third of the Toledo refinery’s gasoline and distillates production. The agreement had an initial three-year term, subject to certain early termination rights. In March 2019, the agreement was renewed and extended for a three-year term. We sell the bulk of the petrochemicals produced at the Toledo refinery through short-term contracts or on the spot market and the majority of the petrochemical distribution is done via rail.
Tankage Capacity. The Toledo refinery has total storage capacity of approximately 4.5 million barrels. The Toledo refinery receives its crude through pipeline connections and a truck rack. Of the total, approximately 1.3 million barrels are dedicated to crude oil storage with the remaining 3.2 million barrels allocated to intermediates and products. A portion of storage capacity dedicated to crude oil and finished products was sold to PBFX in conjunction with its acquisition of a tank farm related facility, which included a propane storage and loading facility (the “Toledo Storage Facility”) in December 2014.
Energy and Other Utilities. Under normal operating conditions, the Toledo refinery consumes approximately 25,000 MMBTU per day of natural gas supplied via pipeline from third parties. The Toledo refinery purchases its electricity from the PJM grid and has a long-term contract to purchase hydrogen and steam from a local third-party supplier. In addition to the third-party steam supplier, Toledo consumes a portion of the steam that is generated by its various process units.
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Chalmette Refinery
Overview. The Chalmette refinery is located on a 400-acre site near New Orleans, Louisiana. It is a dual-train coking refinery and is capable of processing both light and heavy crude oil through its 185,000 bpd crude units and downstream units. Chalmette Refining owns 100% of the MOEM Pipeline, providing access to the Empire Terminal, as well as the CAM Connection Pipeline, providing access to the Louisiana Offshore Oil Port facility through a third-party pipeline. Chalmette Refining also owns 80% of each of the Collins Pipeline Company (“Collins”) and T&M Terminal Company (“T&M”), both located in Collins, Mississippi, which provide a clean products outlet for the AB32refinery to the Plantation and Colonial Pipelines. In addition, there is also a marine terminal capable of importing waterborne feedstocks and loading or unloading finished products. There is also a clean products truck rack that provides access to local markets and crude storage that are owned by PBFX.
The following table approximates the Chalmette refinery’s current major process unit capacities. Unit capacities are shown in barrels per stream day.
| Refinery Units | Nameplate Capacity | ||||
| Crude Distillation Units | 185,000 | ||||
| Vacuum Distillation Unit | 114,000 | ||||
| Fluid Catalytic Cracking Unit | 75,000 | ||||
| Hydrotreating Units | 189,000 | ||||
| Delayed Coking Unit | 42,000 | ||||
| Catalytic Reforming Unit | 42,000 | ||||
| Alkylation Unit | 17,000 | ||||
| Aromatics Extraction Unit | 17,000 | ||||
Feedstocks and Supply Arrangements. We source our crude oil and feedstock needs for Chalmette through connections to the CAM Pipeline and MOEM Pipeline as well as our marine terminal. On November 1, 2015, we entered into a market-based crude supply agreement with Petróleos de Venezuela S.A. (“PDVSA”) that has a ten-year term with a renewal option for an additional five years, subject to certain early termination rights. The pricing for the crude supply is market based and is agreed upon on a quarterly basis by both parties. We have not sourced crude oil under this agreement since 2017 as PDVSA has suspended deliveries due to the parties’ inability to agree to mutually acceptable payment terms and because of U.S. government sanctions against PDVSA.
Refined Product Yield and Distribution. The Chalmette refinery predominantly produces gasoline and diesel fuels and also manufactures high-value petrochemicals including benzene and xylene. Products produced at the Chalmette refinery are transferred to customers through pipelines, the marine terminal and truck rack. The majority of our clean products are delivered to customers via pipelines. Our ownership of the Collins pipeline and T&M terminal provides Chalmette with strategic access to Southeast and East Coast markets through third-party logistics.
Tankage Capacity. Chalmette has a total tankage capacity of approximately 8.1 million barrels. Of this total, approximately 2.6 million barrels are allocated to crude oil storage with the remaining 5.5 million barrels allocated to intermediates and products.
Energy and Other Utilities. Under normal operating conditions, the Chalmette refinery consumes approximately 25,000 MMBTU per day of natural gas supplied via pipeline from third parties. The Chalmette refinery purchases its electricity from a local utility and has a long-term contract to purchase hydrogen from a third-party supplier.
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Torrance Refinery
Overview. The Torrance refinery is located on 750 acres in Torrance, California. It is a high-conversion crude, delayed-coking refinery capable of processing both heavy and medium crude oils through its crude unit and downstream units. In addition to refining assets, the Torrance refinery acquisition included a number of high-quality logistics assets including a sophisticated network of crude and products pipelines, product distribution terminals and refinery crude and product storage facilities. The most significant logistics asset is a crude gathering and transportation system which delivers San Joaquin Valley crude oils directly from the field to the refinery, which is now owned by PBFX. Additionally, there are several pipelines serving the refinery that provide access to sources of waterborne crude oils including the Ports of Long Beach and Los Angeles, as well as clean product outlets with a direct pipeline that supplies jet fuel to the Los Angeles airport that are held by affiliates of the refinery.
The following table approximates the Torrance refinery’s current major process unit capacities. Unit capacities are shown in barrels per stream day.
| Refinery Units | Nameplate Capacity | ||||
| Crude Distillation Unit | 166,000 | ||||
| Vacuum Distillation Unit | 102,000 | ||||
| Fluid Catalytic Cracking Unit | 90,000 | ||||
| Hydrotreating Units | 155,500 | ||||
| Hydrocracking Unit | 25,000 | ||||
| Alkylation Unit | 25,500 | ||||
| Delayed Coking Unit | 58,000 | ||||
Feedstocks and Supply Arrangements. The Torrance refinery primarily processes a variety of medium and heavy crude oils. On July 1, 2016, we entered into a crude supply agreement with Exxon Mobil Oil Corporation (“ExxonMobil”) for approximately 60,000 bpd of crude oil that can be processed at our Torrance refinery. This crude supply agreement has a five-year term with an automatic renewal feature unless either party gives thirty-six months written notice of its intent to terminate the agreement. Additionally, we obtain crude and feedstocks from other sources through connections to third-party pipelines as well as ship docks and truck racks.
Refined Product Yield and Distribution. The Torrance refinery predominantly produces gasoline, jet fuel and diesel fuels. Products produced at the Torrance refinery are transferred to customers through pipelines, the marine terminal and truck rack. The majority of clean products are delivered to customers via pipelines. We currently market and sell all of our refined products independently to a variety of customers either on the spot market or through term agreements.
Tankage Capacity. Torrance has a total tankage capacity of approximately 8.6 million barrels. Of this total, approximately 2.1 million barrels are allocated to crude oil storage with the remaining 6.5 million barrels allocated to intermediates and products.
Energy and Other Utilities. Under normal operating conditions, the Torrance refinery consumes approximately 47,000 MMBTU per day of natural gas supplied via pipeline from third parties. The Torrance refinery generates some power internally using a combination of steam and gas turbines and purchases any additional needed power from the local utility. The Torrance refinery has a long-term contract to purchase hydrogen from a third-party supplier.
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Martinez Refinery
We acquired the Martinez refinery and related logistics assets from Equilon Enterprises LLC d/b/a Shell Oil Products US (“Shell Oil Products”) on February 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 to Shell Oil Products based on certain earnings thresholds of the Martinez refinery for a period of up to four years (the “Martinez Acquisition”).
Overview. The Martinez refinery is located on an 860-acre site in the City of Martinez, 30 miles northeast of San Francisco, California. The refinery is a high-conversion, dual-coking facility with a Nelson Complexity Index of 16.1, making it one of the most complex refineries in the United States. The facility is strategically positioned in Northern California and provides for operating and commercial synergies with the Torrance refinery located in Southern California. In addition to refining assets, the Martinez 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.
The following table approximates the Martinez refinery’s current major process unit capacities. Unit capacities are shown in barrels per stream day.
| Refinery Units | Nameplate Capacity | |||||||
| Crude Distillation Unit | 157,000 | |||||||
| Vacuum Distillation Unit | 102,000 | |||||||
| Fluid Catalytic Cracking Unit | 72,000 | |||||||
| Hydrotreating Units | 268,000 | |||||||
| Hydrocracking Unit | 42,900 | |||||||
| Alkylation Unit | 12,500 | |||||||
| Delayed Coking Unit | 25,500 | |||||||
| Flexi Coking Unit | 22,500 | |||||||
| Isomerization Unit | 15,000 | |||||||
Feedstocks and Supply Arrangements. We have entered into various five-year crude supply agreements with Shell Oil Products for approximately 150,000 bpd, in the aggregate, to support our West Coast and Mid-Continent refinery operations. Additionally, we obtain crude and feedstocks from other sources through connections to third-party pipelines as well as ship docks.
Refined Product Yield and Distribution. We entered into certain offtake agreements for our West Coast system with Shell Oil Products for clean products with varying terms up to 15 years. We currently market and sell all of our refined products independently to a variety of customers either on the spot market or through term agreements.
Tankage Capacity. Martinez has a total tankage capacity of approximately 8.8 million barrels. Of this total, approximately 2.5 million barrels are allocated to crude oil storage with the remaining 6.3 million barrels allocated to intermediates and products.
Energy and Other Utilities. Under normal operating conditions, the Martinez refinery consumes approximately 80,000 MMBTU per day of natural gas (including natural gas consumed in hydrogen production) supplied via pipeline from third parties. The Martinez refinery generates some power internally using a combination of steam and gas turbines and purchases any additional needed power from the local utility. The Martinez refinery has a long-term contract to purchase hydrogen from a third-party supplier.
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Agreements with PBFX
Beginning with the completion of the PBFX Offering, we have entered into a series of agreements with PBFX, including commercial and operational agreements. Each of these agreements and their impact to our operations is outlined below.
Contribution Agreements
Immediately prior to the closing of certain contribution agreements, which PBF LLC entered into with PBFX (as defined in the table below, and collectively referred to as the “Contribution Agreements”), we contributed certain assets to PBF LLC. PBF LLC in turn contributed those assets to PBFX pursuant to the Contribution Agreements. Certain proceeds received by PBF LLC from PBFX in accordance with the Contribution Agreements were subsequently contributed by PBF LLC to us. The Contribution Agreements include the following:
| Contribution Agreement | Effective Date | Assets Contributed | Total Consideration | ||||||||
| Contribution Agreement I | 5/8/2014 | DCR Rail Terminal and the Toledo Truck Terminal | 74,053 PBFX common units and 15,886,553 PBFX subordinated units | ||||||||
| Contribution Agreement II | 9/16/2014 | DCR West Rack | $135.0 million in cash and $15.0 million through the issuance of 589,536 PBFX common units | ||||||||
| Contribution Agreement III | 12/2/2014 | Toledo Storage Facility | $135.0 million in cash and $15.0 million through the issuance of 620,935 PBFX common units | ||||||||
| Contribution Agreement IV | 5/5/2015 | DCR Products Pipeline and DCR Truck Rack | $112.5 million in cash and $30.5 million through the issuance of 1,288,420 PBFX common units | ||||||||
| Contribution Agreement V | 8/31/2016 | Torrance Valley Pipeline (50% equity interest in TVPC) | $175.0 million in cash | ||||||||
| Contribution Agreement VI | 2/15/2017 | Paulsboro Natural Gas Pipeline | $11.6 million affiliate promissory note | ||||||||
| Contribution Agreements VII-X | 7/16/2018 | Development Assets | $31.6 million through the issuance of 1,494,134 PBFX common units | ||||||||
| Contribution Agreement XI | 4/24/2019 | Remaining 50% equity interest in TVPC | $200.0 million in cash | ||||||||
On July 16, 2018, PBFX entered into four contribution agreements with PBF LLC pursuant to which we contributed to PBF LLC certain of its subsidiaries (the “Development Assets Contribution Agreements”). Pursuant to the Development Asset Contribution Agreements, we contributed all of the issued and outstanding limited liability company interests of: Toledo Rail Logistics Company LLC, whose assets consist of a loading and unloading rail facility located at the 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 at the Chalmette refinery; Paulsboro Terminaling Company LLC, whose assets consist of a lube oil terminal facility located at the Paulsboro refinery (the “Paulsboro Lube Oil Terminal”); and DCR Storage and Loading Company LLC, whose assets consist of an ethanol storage facility located at the Delaware City refinery (collectively with the Toledo Rail Products Facility, the Chalmette Truck Rack, the Chalmette Rosin Yard, and the Paulsboro Lube Oil Terminal, the “Development Assets”) to PBF LLC. PBFX Operating Company LLC (“PBFX Op Co”), in turn acquired the
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limited liability company interests in the Development Assets from PBF LLC in connection with the Development Assets Contribution Agreements effective July 31, 2018.
On April 24, 2019, PBFX entered into a contribution agreement with PBF LLC, pursuant to which we contributed to PBF LLC, which in turn contributed to PBFX, all of the issued and outstanding limited liability company interests of TVP Holding Company LLC (“TVP Holding”) for total consideration of $200.0 million (the “TVPC Acquisition”). Prior to the TVPC Acquisition, TVP Holding (then our subsidiary) owned a 50% equity interest in Torrance Valley Pipeline Company LLC (“TVPC”). Subsequent to the closing of the TVPC Acquisition on May 31, 2019, PBFX owns 100% of the equity interests in TVPC.
Commercial Agreements
PBFX currently derives the majority of its revenue from long-term, fee-based agreements with us, which generally include a minimum volume commitment (“MVC”), as applicable, and are supported by contractual fee escalations for inflation adjustments and certain increases in operating costs. We believe the terms and conditions under these agreements, as well as the Omnibus Agreement and the Services Agreement (each as defined below), each with PBFX, are generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services.
Refer to “Note 11 - Related Party Transactions” of our Notes to Consolidated Financial Statements for further discussion regarding the commercial agreements with PBFX.
Omnibus Agreement
In addition to the commercial agreements described above, PBFX entered into an omnibus agreement, which has been amended and restated in connection with the closing of certain of the Contribution Agreements with PBF GP, PBF LLC and us (as amended, the “Omnibus Agreement”). The Omnibus Agreement addresses the payment of an annual fee for the provision of various general and administrative services and reimbursement of salary and benefit costs for certain PBF Energy employees.
The annual fee under the Omnibus Agreement for the year ended December 31, 2020 was $7.6 million, inclusive of obligations under the Omnibus Agreement to reimburse us for certain compensation and benefit costs of employees who devoted more than 50% of their time to PBFX during the year ended December 31, 2020. We currently estimate to receive $8.3 million, inclusive of estimated obligations under the Omnibus Agreement as a reimbursement for certain compensation and benefit costs of employees who devote more than 50% of their time to PBFX for the year ending December 31, 2021.
Services Agreement
Additionally, PBFX entered into an operation and management services and secondment agreement with us and certain of our subsidiaries (as amended, the “Services Agreement”), pursuant to which we provide PBFX with the personnel necessary for PBFX to perform its obligations under its commercial agreements. PBFX reimburses us for the use of such employees and the provision of certain infrastructure-related services to the extent applicable to its operations, including storm water discharge and waste water treatment, steam, potable water, access to certain roads and grounds, sanitary sewer access, electrical power, emergency response, filter press, fuel gas, API solids treatment, fire water and compressed air. For the year ended December 31, 2020, PBFX paid us an annual fee of $8.7 million pursuant to the Services Agreement and we currently estimate to receive the same annual reimbursement pursuant to the Services Agreement for the year ending December 31, 2021.
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On February 13, 2019, we amended the existing Amended and Restated Delaware City Rail Terminaling Services Agreement, by and between Delaware City Terminaling Company LLC and us (as amended effective January 1, 2019, the “Amended and Restated Delaware City Rail Terminaling Services Agreement”) for the inclusion of services through certain rail infrastructure at PBFX’s acquired East Coast Storage Assets (the “East Coast Rail Assets”). We also entered into a new Terminaling Services Agreement, by and between Delaware City Terminaling Company and us, with a four-year term starting in 2022, subsequent to the expiration of the Amended and Restated Delaware City Rail Terminaling Services Agreement, related to the TorranceDCR Rail Facilities and the East Coast Rail Assets, which will reduce the MVC to 95,000 bpd and includes additional services to be provided by PBFX as operator of facilities owned by our subsidiaries.
The Services Agreement will terminate upon the termination of the Omnibus Agreement, provided that PBFX may terminate any service on 30-days’ notice.
Principal Products
Our refineries make various grades of gasoline, distillates (including diesel fuel, jet fuel, and ULSD) and other products from crude oil, other feedstocks, and blending components. We sell these products through our commercial accounts, and sales with major oil companies. For the years ended December 31, 2020, 2019 and 2018, gasoline and distillates accounted for 85.1%, 87.0% and 84.8% of our revenues, respectively.
Customers
We sell a variety of refined products to a diverse customer base. The majority of our refined products are primarily sold through short-term contracts or on the spot market. However, we do have product offtake arrangements for a portion of our clean products. For the year ended December 31, 2020, only one customer, Royal Dutch Shell, accounted for 10% or more of our revenues (approximately 13%). For the years ended December 31, 2019 and 2018, no single customer accounted for 10% or more of our revenues. As of December 31, 2020, only one customer, Royal Dutch Shell, accounted for 10% or more of our total trade accounts receivable (approximately 17%). No single customer accounted for 10% or more of our total trade accounts receivable as of December 31, 2019.
Seasonality
Traditionally, demand for gasoline and diesel is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and construction work. Decreased demand during the winter months can lower gasoline and diesel prices. However, during 2020, due to the COVID-19 pandemic and related governmental responses, the effects of seasonality on our operating results were skewed. Our operating results have been 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.
Competition
The refining business is very competitive. We compete directly with various other refining companies on the East, Gulf and West Coasts and in the Mid-Continent, with integrated oil companies, with foreign refiners that import products into the United States and with producers and marketers in other industries supplying alternative forms of energy and fuels to satisfy the requirements of industrial, commercial and individual consumers. Some of our competitors have expanded the capacity of their refineries and internationally new refineries are coming on line which could also affect our competitive position.
Profitability in the refining industry depends largely on refined product margins, which can fluctuate significantly, as well as crude oil prices and differentials between the prices of different grades of crude oil, operating efficiency and reliability, product mix and costs of product distribution and transportation. Certain of our competitors that have larger and more complex refineries may be able to realize lower per-barrel costs or higher margins per barrel of throughput. Several of our principal competitors are integrated national or
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international oil companies that are larger and have substantially greater resources. Because of their integrated operations and larger capitalization, these companies may be more flexible in responding to volatile industry or market conditions, such as shortages of feedstocks or intense price fluctuations. Refining margins are frequently impacted by sharp changes in crude oil costs, which may not be immediately reflected in product prices.
The refining industry is highly competitive with respect to feedstock supply. Unlike certain of our competitors that have access to proprietary controlled sources of crude oil production available for use at their own refineries, we obtain all of our crude oil and substantially all other feedstocks from unaffiliated sources. The availability and cost of crude oil and feedstock are affected by global supply and demand. We have no crude oil reserves and are not engaged in the exploration or production of crude oil. We believe, however, that we will be able to obtain adequate crude oil and other feedstocks at generally competitive prices for the foreseeable future.
Pursuant to its Renewable Fuel Standard, EPA has implemented mandates to blend renewable fuels into the petroleum fuels produced and sold in the United States. However, unlike certain of our competitors, we currently do not produce renewable fuels, and increasing the volume of renewable fuels that must be blended into our products displaces an increasing volume of our refineries’ product pool, potentially resulting in lower earnings and profitability. In addition, in order to meet certain of these and future EPA requirements, we may be required to continue to purchase RINs, which historically had, and we expect to have, fluctuating costs based on market conditions. The price of RINs has increased in 2020 and could increase further in 2021.
Corporate Offices
We currently lease approximately 63,000 square feet for our principal corporate offices in Parsippany, New Jersey. The lease for our principal corporate offices expires in 2022. Functions performed in the Parsippany office include overall corporate management, refinery beginningand health, safety and environmental management, planning and strategy, corporate finance, commercial operations, logistics, contract administration, marketing, investor relations, governmental affairs, accounting, tax, treasury, information technology, legal and human resources support functions.
We lease approximately 4,000 square feet for our regional corporate office in Long Beach, California. The lease for our Long Beach office expires in 2021. Functions performed in the Long Beach office include overall regional corporate management, planning and strategy, commercial operations, logistics, contract administration, marketing and governmental affairs.
Employees and Human Capital
Safety
We believe our responsibility to our employees, neighbors, members and the environment is only fulfilled through our commitment to safety and reliability. Through rigorous training, sharing of expertise across our sites, continuous monitoring and through promoting a culture of excellence in operations, we continuously strive to keep our people, the communities in which we operate in and the environment safe.
Our focus on July 1, 2016safety is also evident in our response to the COVID-19 pandemic. We continue to utilize our COVID-19 response team to implement additional social distancing measures across the workplace in addition to the continued enhancement of personal protective equipment and must purchase emission creditsthe cleanliness of our facilities. Through the guidance of our COVID-19 response team, we have started to bring back a portion of our workforce to their primary locations on a phased in approach, and we will continue to rely on our team and the evolution of the COVID-19 pandemic as we evaluate the appropriate time and way in which we will phase in the return of the rest of our workforce.
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We are subject to the requirements of the Occupational Safety and Health Administration of the U.S. Department of Labor (“OSHA”) and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA Hazard Communication Standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances.
Development and Retention
The development, attraction and retention of employees is a critical success factor for our Company. To support the advancement of our employees, we offer rigorous training and development programs and encourage the sharing of expertise across our sites. We actively promote inclusion and diversity in our workforce at each of our locations and provide our employees with opportunities to give back through engagement in our local communities through supportive educational programs, philanthropic and volunteer activities.
We believe that a combination of competitive compensation and career growth and development opportunities help increase employee morale and reduce voluntary turnover. Our comprehensive benefit packages are competitive in the marketplace and we believe in recognizing and rewarding talent through our various cash and equity compensation programs.
Headcount
As of December 31, 2020, we had approximately 3,638 employees, of which 1,931 are covered by collective bargaining agreements. Our hourly employees are covered by collective bargaining agreements through the United Steel Workers (“USW”), the Independent Oil Workers (“IOW”) and the International Brotherhood of Electrical Workers (“IBEW”). We consider our relations with the represented employees to be satisfactory.
| Location | Number of employees | Employees covered by collective bargaining agreements | Collective bargaining agreements | Expiration date | ||||||||||||||||||||||
| Headquarters | 397 | — | N/A | N/A | ||||||||||||||||||||||
| Delaware City refinery | 518 | 358 | USW | January 2022 | ||||||||||||||||||||||
| Paulsboro refinery | 442 | 260 | IOW | March 2022 | ||||||||||||||||||||||
| Toledo refinery | 483 | 313 | USW | February 2022 | ||||||||||||||||||||||
| Chalmette refinery | 543 | 307 | USW | January 2022 | ||||||||||||||||||||||
| Torrance refinery | 564 | 297 12 | USW IBEW | January 2022 January 2022 | ||||||||||||||||||||||
| Torrance logistics | 106 | 42 4 | USW USW | April 2021 January 2022 | ||||||||||||||||||||||
| Martinez refinery | 585 | 314 24 | USW IBEW | February 2022 February 2022 | ||||||||||||||||||||||
| Total employees | 3,638 | 1,931 | ||||||||||||||||||||||||
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Environmental, Health and Safety Matters
Our refineries, pipelines and related operations are subject to extensive and frequently changing federal, state and local laws and regulations, including, but not limited to, those relating to the discharge of materials into the environment or that otherwise relate to the protection of the environment, waste management and the characteristics and the compositions of fuels. Compliance with existing and anticipated laws and regulations can increase the overall cost of operating the refineries, including remediation, operating costs and capital costs to construct, maintain and upgrade equipment and facilities. Permits are also required under these laws for the operation of our refineries, pipelines and related operations and these permits are subject to revocation, modification and renewal. Compliance with applicable environmental laws, regulations and permits will continue to have an impact on our operations, results of operations and capital requirements. We believe that our current operations are in substantial compliance with existing environmental laws, regulations and permits.
We incorporate by reference into this Item the environmental disclosures contained in the following sections of this report:
•Item 1A. “Risk Factors”
◦ We may incur significant liability under, or costs and capital expenditures to comply with, environmental and health and safety regulations, which are complex and change frequently;
◦ Environmental clean-up and remediation costs of our sites and environmental litigation could decrease our net cash flow, reduce our results of operations and impair our financial condition;
◦ We may have capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate;
◦ We are subject to strict laws and regulations regarding employee and process safety, and failure to comply with these obligations. Additionally, in September 2016, the state of California enacted Senate Bill 32 (“SB32”) which further reduces greenhouse gas emissions targets to 40 percent below 1990 levels by 2030.
◦ We could requireincur substantial expenditures for the installationcosts or disruptions in our business if we cannot obtain or maintain necessary permits and operation of systemsauthorizations or otherwise comply with health, safety, environmental and equipment that we do not currently possess.other laws and regulations.
•Item 3. “Legal Proceedings”
•Item 8. “Financial Statements and Supplementary Data”
◦ Note 8 - Accrued Expenses,
◦ Note 10 - Other Long-Term Liabilities and
◦ Note 12 - Commitments and Contingencies
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GLOSSARY OF SELECTED TERMS
Unless otherwise noted or indicated by context, the following terms used in this Annual Report on Form 10-K have the following meanings:
“AB32” refers to the greenhouse gas emission control regulations in the state of California to comply with Assembly Bill 32.
“ASCI” refers to the Argus Sour Crude Index, a pricing index used to approximate market prices for sour, heavy crude oil.
“Bakken” refers to both a crude oil production region generally covering North Dakota, Montana and Western Canada, and the crude oil that is produced in that region.
“barrel” refers to a common unit of measure in the oil industry, which equates to 42 gallons.
“blendstocks” refers to various compounds that are combined with gasoline or diesel from the crude oil refining process to make finished gasoline and diesel; these may include natural gasoline, FCC unit gasoline, ethanol, reformate or butane, among others.
“bpd” refers to an abbreviation for barrels per day.
“CAA” refers to the Clean Air Act.
“CAM Pipeline” or “CAM Connection Pipeline” refers to the Clovelly-Alliance-Meraux pipeline in Louisiana.
“CARB”refers to the California Air Resources Board; gasoline and diesel fuel sold in the state of California are regulated by CARB and require stricter quality and emissions reduction performance than required by other states.
“catalyst” refers to a substance that alters, accelerates, or instigates chemical changes, but is not produced as a product of the refining process.
“coke” refers to a coal-like substance that is produced from heavier crude oil fractions during the refining process.
“complexity” refers to the number, type and capacity of processing units at a refinery, measured by the Nelson Complexity Index, which is often used as a measure of a refinery’s ability to process lower quality crude in an economic manner.
“COVID-19” refers to the 2019 outbreak of the novel coronavirus pandemic.
“crack spread” refers to a simplified calculation that measures the difference between the price for light products and crude oil. For example, we reference (a) the 2-1-1 crack spread, which is a general industry standard utilized by our Delaware City, Paulsboro and Chalmette refineries that approximates the per barrel refining margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of heating oil or ULSD, and (b) the 4-3-1 crack spread, which is a benchmark utilized by our Toledo and Torrance refineries that approximates the per barrel refining margin resulting from processing four barrels of crude oil to produce three barrels of gasoline and one-half barrel of jet fuel and one-half barrel of ULSD and (c) the 3-2-1 crack spread, which is a benchmark utilized by our Martinez refinery that approximates the per barrel refining margin resulting from processing three barrels of crude oil to produce two barrels of gasoline and three-quarters of a barrel jet fuel and one-quarter of a barrel ULSD.
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“Dated Brent” refers to Brent blend oil, (aa light, sweet North Sea crude oil, characterized by an APIAmerican Petroleum Institute (“API”) gravity of 38° and a sulfur content of approximately 0.4 weight percent)percent, that is used as a benchmark for other crude oils.
“distillates” refers primarily to diesel, heating oil, kerosene and jet fuel.
“DNREC” refers to the Delaware Department of Natural Resources and Environmental Control.
“downstream” refers to the downstream sector of the energy industry generally describing oil refineries, marketing and distribution companies that refine crude oil and sell and distribute refined products. The opposite of the downstream sector is the upstream sector, which refers to exploration and production companies that search for and/or produce crude oil and natural gas underground or through drilling or exploratory wells.
“EPA” refers to the United States Environmental Protection Agency.
“ethanol” refers to a clear, colorless, flammable oxygenated liquid. Ethanol is typically produced chemically from ethylene, or biologically from fermentation of various sugars from carbohydrates found in agricultural crops. It is used in the United States as a gasoline octane enhancer and oxygenate.
“Ethanol Permit” refers to the Coastal Zone Act permit for ethanol issued to our Delaware City refinery.
“FASB” refers to the Financial Accounting Standards Board which develops U.S. generally accepted accounting principles.
“FCC” refers to fluid catalytic cracking.
“feedstocks” refers to crude oil and partially refined petroleum products that are processed and blended into refined products.
“FERC” refers to the Federal Energy Regulatory Commission.
“GAAP” refers to U.S. generally accepted accounting principles developed by the Financial Accounting Standards BoardFASB for nongovernmental entities.
“GHG” refers to the greenhouse gas carbon dioxide.gas.
“Group I base oils or lubricants” refers to conventionally refined products characterized by sulfur content less than 0.03% with a viscosity index between 80 and 120. Typically, these products are used in a variety of automotive and industrial applications.
“heavy crude oil” refers to a relatively inexpensive crude oil with a low API gravity characterized by high relative density and viscosity. Heavy crude oils require greater levels of processing to produce high value products such as gasoline and diesel.
“IMO” refers to the International Maritime Organization.
“IPO” refers to the initial public offering of PBF Energy’sEnergy Class A common stock which closed on December 18, 2012.
“J. Aron” refers to J. Aron & Company, a subsidiary of The Goldman Sachs Group, Inc.
“KV” refers to Kilovolts.
“LCM” refers to a GAAP requirement for inventory to be valued at the lower of cost or market.
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“light crude oil” refers to a relatively expensive crude oil with a high API gravity characterized by low relative density and viscosity. Light crude oils require lower levels of processing to produce high value products such as gasoline and diesel.
“light-heavy differential” refers to the price difference between light crude oil and heavy crude oil.
“light products” refers to the group of refined products with lower boiling temperatures, including gasoline and distillates.
“LLS” refers to Light Louisiana Sweet benchmark for crude oil reflective of Gulf coast economics for light sweet domestic and foreign crudes. It is characterized by an API gravity of between 35° and 40° and a sulfur content of approximately .35 weight percent.
“LPG” refers to liquefied petroleum gas.
“Maya” refers to Maya crude oil, a heavy, sour crude oil characterized by an API gravity of approximately 22° and a sulfur content of approximately 3.3 weight percent that is used as a benchmark for other heavy crude oils.
“MLP” refers to the master limited partnership.
“MMBTU” refers to million British thermal units.
“MOEM Pipeline” refers to a pipeline that originates at a terminal in Empire, Louisiana approximately 30 miles north of the mouth of the Mississippi River. The MOEM Pipeline is 14 inches in diameter, 54 miles long and transports crude from South Louisiana to the Chalmette refinery and transports Heavy Louisiana Sweet (HLS) and South Louisiana Intermediate (SLI) crude.
“MSCG”MW” refers to Morgan Stanley Capital Group Inc.Megawatt.
“Nelson Complexity Index” refers to the complexity of an oil refinery as measured by the Nelson Complexity Index, which is calculated on an annual basis by the Oil and Gas Journal. The Nelson Complexity Index assigns a complexity factor to each major piece of refinery equipment based on its complexity and cost in comparison to crude distillation, which is assigned a complexity factor of 1.0. The complexity of each piece of refinery equipment is then calculated by multiplying its complexity factor by its throughput ratio as a percentage of crude distillation capacity. Adding up the complexity values assigned to each piece of equipment, including crude distillation, determines a refinery’s complexity on the Nelson Complexity Index. A refinery with a complexity of 10.0 on the Nelson Complexity Index is considered ten times more complex than crude distillation for the same amount of throughput.
“NYH” refers to the New York Harbor market value of petroleum products.
“NYMEX” refers to the New York Mercantile Exchange.
“PADD” refers to Petroleum Administration for Defense Districts.
“Platts” refers to Platts, a division of The McGraw-Hill Companies.
“PPM” refers to parts per million.
“refined products” refers to petroleum products, such as gasoline, diesel and jet fuel, that are produced by a refinery.
“Renewable Fuel Standard” refers to the Renewable Fuel Standard issued pursuant to the Energy Independence and Security Act of 2007 implementing mandates to blend renewable fuels into petroleum fuels produced and sold in the United States.
“RINs” refers to renewable fuel credits required for compliance with the Renewable Fuel Standard.
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“Saudi Aramco” refers to Saudi Arabian Oil Company.
“SEC” refers to the United States Securities and Exchange Commission.
“sour crude oil” refers to a crude oil that is relatively high in sulfur content, requiring additional processing to remove the sulfur. Sour crude oil is typically less expensive than sweet crude oil.
“Sunoco” refers to Sunoco, LLC.
“sweet crude oil” refers to a crude oil that is relatively low in sulfur content, requiring less processing to remove the sulfur than sour crude oil. Sweet crude oil is typically more expensive than sour crude oil.
“Syncrude” refers to a blend of Canadian synthetic oil, a light, sweet crude oil, typically characterized by API gravity between 30° and 32° and a sulfur content of approximately 0.1-0.2 weight percent.
“throughput” refers to the volume processed through a unit or refinery.
“turnaround” refers to a periodically required shutdown and comprehensive maintenance event to refurbish and maintain a refinery unit or units that involves the cleaning, repair, and inspection of such units and occurs generally on a periodic cycle.
“ULSD” refers to ultra-low-sulfur diesel.
“WCS” refers to Western Canadian Select, a heavy, sour crude oil blend typically characterized by API gravity between 20° and 22° and a sulfur content of approximately 3.5 weight percent that is used as a benchmark for heavy Western Canadian crude oil.
“WTI” refers to West Texas Intermediate crude oil, a light, sweet crude oil, typically characterized by API gravity between 38° and 40° and a sulfur content of approximately 0.3 weight percent that is used as a benchmark for other crude oils.
“WTS” refers to West Texas Sour crude oil, a sour crude oil characterized by API gravity between 30° and 33° and a sulfur content of approximately 1.28 weight percent that is used as a benchmark for other sour crude oils.
“yield” refers to the percentage of refined products that is produced from crude oil and other feedstocks.
Explanatory Note
This Form 10-K is filed by PBF Holding Company LLC (“PBF Holding”) and PBF Finance Corporation (“PBF Finance”). PBF Holding is a wholly-owned subsidiary of PBF Energy Company LLC (“PBF LLC”) and is the parent company for PBF LLC's refinery operating subsidiaries. PBF Finance is a wholly-owned subsidiary of PBF Holding. PBF Holding is an indirect subsidiary of PBF Energy Inc. (“PBF Energy”), which is the sole managing member of, and owner of an equity interest representing approximately 99.2% of the outstanding economic interests in PBF LLC as of December 31, 2020. PBF Energy operates and controls all of the business and affairs and consolidates the financial results of PBF LLC and its subsidiaries. PBF Holding, together with its consolidated subsidiaries, owns and operates oil refineries and related facilities in North America.
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PART I
In this Annual Report on Form 10-K, unless the context otherwise requires, references to the “Company,” “we,” “our” or “us” refer to PBF Holding, and, in each case, unless the context otherwise requires, its consolidated subsidiaries. References to “subsidiary guarantors” refer to PBF Services Company LLC (“PBF Services”), PBF Power Marketing LLC (“PBF Power”), Paulsboro Refining Company LLC (“Paulsboro Refining” or “PRC”), Toledo Refining Company LLC (“Toledo Refining”), Delaware City Refining Company LLC (“DCR”), PBF Investments LLC (“PBF Investments”), PBF International Inc., Chalmette Refining, L.L.C. (“Chalmette Refining”), PBF Energy Western Region LLC (“PBF Western Region”), Torrance Refining Company LLC (“Torrance Refining”), Torrance Logistics Company LLC (“Torrance Logistics”), and Martinez Refining Company LLC (“Martinez Refining”), which are the subsidiaries of PBF Holding that guarantee PBF Holding’s 7.25% senior notes due 2025 (the “2025 Senior Notes”), 6.00% senior unsecured notes due 2028 (the “2028 Senior Notes”), and the 9.25% senior secured notes due 2025 (the “2025 Senior Secured Notes”) as of December 31, 2020.
In this Annual Report on Form 10-K, we make certain forward-looking statements, including statements regarding our plans, strategies, objectives, expectations, intentions, and resources. You should read our forward-looking statements together with our disclosures under the heading: “Cautionary Statement Regarding Forward-Looking Statements.” When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in this Annual Report on Form 10-K under “Risk Factors” in Item 1A.
ITEM. 1 BUSINESS
Overview and Corporate Structure
We are one of the largest independent petroleum refiners and suppliers of unbranded transportation fuels, heating oil, petrochemical feedstocks, lubricants and other petroleum products in the United States. We sell our products throughout the Northeast, Midwest, Gulf Coast and West Coast of the United States, as well as in other regions of the United States, Canada and Mexico and are able to ship products to other international destinations. We were formed in 2008 to pursue acquisitions of crude oil refineries and downstream assets in North America. As of December 31, 2020, we own and operate six domestic oil refineries and related assets, which we acquired in 2010, 2011, 2015, 2016 and 2020. Based on the current configuration (as disclosed in “Recent Developments - East Coast Refining Reconfiguration”) our refineries have a combined 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. The Company’s six oil refineries are aggregated into one reportable segment.
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Ownership Structure
We are a Delaware limited liability company and a holding company for our operating subsidiaries. PBF Finance is a wholly-owned subsidiary of PBF Holding. We are a wholly-owned subsidiary of PBF LLC, and PBF Energy is the sole managing member of, and owner of an equity interest as of December 31, 2020 representing approximately 99.2% of the outstanding economic interests in PBF LLC.
On December 18, 2012, our indirect parent, PBF Energy completed its IPO. As a result of PBF Energy’s IPO and related organization transactions, PBF Energy became the sole managing member of PBF LLC and operates and controls all of its business and affairs and consolidates the financial results of PBF LLC and its subsidiaries, including PBF Holding and PBF Finance. As of December 31, 2020, PBF Energy held 120,122,872 PBF LLC Series C Units and its current and former executive officers and directors and certain employees and others beneficially held 970,647 PBF LLC Series A Units, and the holders of PBF Energy’s issued and outstanding shares of its Class A common stock have approximately 99.2% of the voting power in PBF Energy and the members of PBF LLC other than PBF Energy through their holdings of Class B common stock have the remaining 0.8% of the voting power.
PBF Holding Refineries
Our six refineries are located in Delaware City, Delaware, Paulsboro, New Jersey, Toledo, Ohio, Chalmette, Louisiana, Torrance, California and Martinez, California. In 2020, we reconfigured our Delaware and Paulsboro refineries, temporarily idling certain of our major processing units at the Paulsboro refinery, in order to operate the two refineries as one functional unit that we refer to as the “East Coast Refining System”. Refer to “Recent Developments” below for additional information. Each refinery is briefly described in the table below:
| Refinery | Region | Nelson Complexity Index (1) | Throughput Capacity (in barrels per day) (1) | PADD | Crude Processed (2) | Source (2) | ||||||||||||||
| Delaware City | East Coast | 13.6 | 180,000 | 1 | light sweet through heavy sour | water, rail | ||||||||||||||
| Paulsboro | East Coast | 10.4 (3) | 105,000(3) | 1 | light sweet through heavy sour | water | ||||||||||||||
| Toledo | Mid-Continent | 11.0 | 180,000 | 2 | light sweet | pipeline, truck, rail | ||||||||||||||
| Chalmette | Gulf Coast | 13.0 | 185,000 | 3 | light sweet through heavy sour | water, pipeline | ||||||||||||||
| Torrance | West Coast | 13.8 | 166,000 | 5 | medium and heavy | pipeline, water, truck | ||||||||||||||
| Martinez | West Coast | 16.1 | 157,000 | 5 | medium and heavy | pipeline and water | ||||||||||||||
________
(1) Reflects operating conditions at each refinery as of the date of this filing. Changes in complexity and throughput capacity reflect the result of current market conditions such as our East Coast Refining Reconfiguration (defined below), in addition to investments made to improve our facilities and maintain compliance with environmental and governmental regulations. Configurations at each of our refineries are evaluated and updated accordingly.
(2) Reflects the typical crude and feedstocks and related sources utilized under normal operating conditions and prevailing market environments.
(3) Under normal operating conditions and prevailing market environments, our Nelson Complexity Index and throughput capacity for the Paulsboro refinery would be 13.1 and 180,000, respectively. As a result of the east coast refining reconfiguration described below (the “East Coast Refining Reconfiguration”), our Nelson Complexity Index and throughput capacity were reduced.
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Public Offerings of PBF Logistics LP and Subsequent Drop-Down Transactions
PBF Logistics LP (“PBFX”) is an affiliate of ours. PBFX is a fee-based, growth-oriented, publicly-traded Delaware master limited partnership formed by PBF Energy to own or lease, operate, develop and acquire crude oil and refined petroleum products terminals, pipelines, storage facilities and similar logistics assets. PBFX engages in the receiving, handling, storage and transferring of crude oil, refined products, natural gas and intermediates from sources located throughout the United States and Canada for PBF Energy in support of certain of its refineries, as well as for third-party customers. As of December 31, 2020, a substantial majority of PBFX’s revenues are derived from long-term, fee-based commercial agreements with us, which include minimum volume commitments, for receiving, handling, storing and transferring crude oil, refined products, and natural gas. PBF Energy also has agreements with PBFX that establish fees for certain general and administrative services and operational and maintenance services provided by us to PBFX.
PBF Logistics GP LLC (“PBF GP”) serves as the general partner of PBFX. PBF GP is wholly-owned by PBF LLC. On May 14, 2014, PBFX completed its initial public offering (the “PBFX Offering”). In connection with the PBFX Offering, we distributed to PBF LLC, which in turn contributed to PBFX, the assets and liabilities of certain crude oil terminaling assets. In a series of transactions subsequent to the PBFX Offering, we distributed certain additional assets to PBF LLC, which in turn contributed those assets to PBFX. See “Agreements with PBFX” below as well as “Note 11 - Related Party Transactions” of our Notes to Consolidated Financial Statements for additional information.
See “Item 1A. Risk Factors” and “Item 13. Certain Relationships and Related Transactions, and Director Independence.”
Recent Developments
COVID-19
The outbreak of the COVID-19 pandemic and certain developments in the global oil markets negatively impacted worldwide economic and commercial activity and financial markets in 2020 and is expected to continue in 2021. The COVID-19 pandemic and the related governmental and consumer responses resulted in significant business and operational disruptions, including business and school closures, supply chain disruptions, travel restrictions, stay-at-home orders and limitations on the availability of workforces and has resulted in significantly lower global demand for refined petroleum and petrochemical products. We believe, but cannot guarantee, that demand for refined petroleum products will ultimately rebound as governmental restrictions are lifted. However, the continued negative impact of the COVID-19 pandemic and these market developments on our business and operations will depend on the ongoing severity, location and duration of the effects and spread of COVID-19, the effectiveness of the vaccine programs and the other actions undertaken by national, regional and local governments and health officials to contain the virus or treat its effects, and how quickly and to what extent economic conditions improve and normal business and operating conditions resume.
We are actively responding to the impacts from these matters on our business. Starting in late March through the end of 2020, we reduced the amount of crude oil processed at our refineries in response to the decreased demand for our products and we temporarily idled various units at certain of our refineries to optimize our production in light of prevailing market conditions. As of the date of this filing, our refineries are still operating at reduced throughput levels and we expect them to continue to do so until market conditions substantially improve. Despite the measures we have taken, we have been, and likely will continue to be, adversely impacted by the COVID-19 pandemic. We are unable to predict the ultimate outcome of the economic impact and can provide no assurance that measures taken to mitigate the impact of the COVID-19 pandemic will be effective.
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Over the course of 2020 we adjusted our operational plans to the evolving market conditions and executed our plan 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. We expect to continue to target and execute these expense reduction measures in 2021. 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 historic levels, including the East Coast Refining Reconfiguration. We operated our refineries at reduced rates during the year ended December 31, 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. We expect near-term throughput to be in the 675,000 to 725,000 barrel per day range for our refining system.
East Coast Refining Reconfiguration
The East Coast Refining Reconfiguration was announced on October 29, 2020 and completed on December 31, 2020. It is expected to provide us with crude optionality and increased flexibility to respond to evolving market conditions. Our East Coast Refining System throughput capacity is approximately 285,000 barrels per day, reflecting the new configuration and idling of certain major processing units. Annual operating and capital expenditures savings are expected to be approximately $100.0 million and $50.0 million, respectively, relative to average historic levels.
Available Information
Our website address is www.pbfenergy.com. Information contained on our website is not part of this Annual Report on Form 10-K. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any other materials filed with (or furnished to) the SEC by us are available on our website (under “Investors”) free of charge, soon after we file or furnish such material.
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The diagram below depicts our organizational structure as of December 31, 2020:
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Refining Operations
We own and operate six refineries (two of which are operated as a single unit) that provide us with geographic and market diversity. We produce a variety of products at each of our refineries, including gasoline, ULSD, heating oil, jet fuel, lubricants, petrochemicals and asphalt. We sell our products throughout the Northeast, Midwest, Gulf Coast and West Coast of the United States, as well as in other regions of the United States, Canada and Mexico, and are able to ship products to other international destinations.
Our refinery assets as of December 31, 2020 are described below.
East Coast Refining System (Delaware City Refinery and Paulsboro Refinery)
Overview. The Delaware City refinery is located on an approximately 5,000-acre site, with access to waterborne cargoes and an extensive distribution network of pipelines, barges and tankers, truck and rail. The Delaware City refinery is a fully integrated operation that receives crude via rail at crude unloading facilities owned by PBFX, or via ship or barge at the docks owned by the Delaware City refinery located on the Delaware River. The crude and other feedstocks are stored in an extensive tank farm prior to processing. In addition, there is a 15-lane, 76,000 bpd capacity truck loading rack (the “DCR Truck Rack”) located adjacent to the refinery and a 23-mile interstate pipeline (the “DCR Products Pipeline”) that are used to distribute clean products. The DCR Products Pipeline and DCR Truck Rack were sold to PBFX in May 2015 and PBFX owns additional assets that support the Delaware City refinery. The Paulsboro refinery is located on approximately 950 acres on the Delaware River in Paulsboro, New Jersey, near Philadelphia and approximately 30 miles away from Delaware City. Paulsboro receives crude and feedstocks via its marine terminal on the Delaware River.
As a result of its configuration and process units, Delaware City has the capability of processing a slate of heavy crudes with a high concentration of high sulfur crudes, as well as other high sulfur feedstock when economically viable, and is one of the largest and most complex refineries on the East Coast. The Delaware City refinery is one of two heavy crude processing refineries, the other being our Paulsboro refinery, on the East Coast of the United States. The Delaware City coking capacity is equal to approximately 25% of crude capacity.
The Delaware City refinery primarily processes a variety of medium to heavy, sour crude oils, but can run light, sweet crude oils as well. The refinery has large conversion capacity with its 82,000 bpd FCC unit, 54,500 bpd fluid coking unit and 24,000 bpd hydrocracking unit.
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The following table approximates the East Coast Refining System’s current major process unit capacities. Unit capacities are shown in barrels per stream day.
| Delaware City Refinery Units | Nameplate Capacity | ||||
| Crude Distillation Unit | 180,000 | ||||
| Vacuum Distillation Unit | 105,000 | ||||
| Fluid Catalytic Cracking Unit | 82,000 | ||||
| Hydrotreating Units | 180,000 | ||||
| Hydrocracking Unit | 24,000 | ||||
| Catalytic Reforming Unit | 43,000 | ||||
| Benzene / Toluene Extraction Unit | 15,000 | ||||
| Butane Isomerization Unit | 6,000 | ||||
| Alkylation Unit | 12,500 | ||||
| Polymerization Unit | 16,000 | ||||
| Fluid Coking Unit | 54,500 | ||||
| Paulsboro Refinery Units | Nameplate Capacity | |||||||
Crude Distillation Units (1) | 105,000 | |||||||
Vacuum Distillation Units (1) | 50,000 | |||||||
Fluid Catalytic Cracking Unit (1) | Idled | |||||||
Hydrotreating Units (1) | 61,000 | |||||||
Catalytic Reforming Unit (1) | Idled | |||||||
Alkylation Unit (1) | Idled | |||||||
| Lube Oil Processing Unit | 12,000 | |||||||
Delayed Coking Unit (1) | Idled | |||||||
| Propane Deasphalting Unit | 11,000 | |||||||
(1)Current Nameplate Capacity was fully or partially reduced to reflect the idled units as part of the East Coast Refining Reconfiguration.
Feedstocks and Supply Arrangements. We source our crude oil needs for Delaware City primarily through short-term and spot market agreements. We have a contract with Saudi Aramco pursuant to which we have purchased up to approximately 100,000 bpd of crude oil from Saudi Aramco that is processed at Paulsboro. The crude purchased under this contract is priced off the ASCI.
Refined Product Yield and Distribution. The Delaware City refinery predominantly produces gasoline, jet fuel, ULSD and ultra-low sulfur heating oil as well as certain other products. Products produced at the Delaware City refinery are transferred to customers through pipelines, barges or at its truck rack. We market and sell all of our refined products independently to a variety of customers on the spot market or through term agreements. The Paulsboro refinery predominantly manufactures Group I base oils or lubricants and asphalt and jet fuel. Products produced at the Paulsboro refinery are transferred to customers primarily through pipelines, barges, or at its truck rack. We market and sell all of our refined products independently to a variety of customers on the spot market or through term agreements.
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Inventory Intermediation Agreement. On August 29, 2019, we entered into amended and restated inventory intermediation agreements with J. Aron, (as amended from time to time, the “Inventory Intermediation Agreements”), to support the operations of the Delaware City and Paulsboro refineries. The Inventory Intermediation Agreement by and among J. Aron, PBF Holding and DCR expires on June 30, 2021, which term may be further extended by mutual consent of the parties to June 30, 2022. The Inventory Intermediation Agreement by and among J. Aron, PBF Holding and PRC expires on December 31, 2021, which term may be further extended by mutual consent of the parties to December 31, 2022.
Pursuant to each Inventory Intermediation Agreement, J. Aron purchases and holds title to certain inventory, including crude oil, intermediate and certain finished products (the “J. Aron Products”), produced by the refinery and delivered into our storage tanks at the Delaware City and Paulsboro refineries and at PBFX’s assets acquired from Crown Point International in October 2018 (the “East Coast Storage Assets” and together with our storage tanks at the Delaware City and Paulsboro refineries, the “J. Aron Storage Tanks”). The J. Aron Products are sold back to us as the J. Aron Products are discharged out of our J. Aron Storage Tanks. At expiration or termination of each of the Inventory Intermediation Agreements, we will have to repurchase the inventories outstanding under the Inventory Intermediation Agreement at that time.
Tankage Capacity. The Delaware City refinery has total storage capacity of approximately 10.0 million barrels. Of the total, approximately 3.6 million barrels of storage capacity are dedicated to crude oil and other feedstock storage with the remaining 6.4 million barrels allocated to finished products, intermediates and other products. The Paulsboro refinery has total storage capacity of approximately 7.5 million barrels. Of the total, approximately 2.1 million barrels are dedicated to crude oil storage with the remaining 5.4 million barrels allocated to finished products, intermediates and other products.
Energy and Other Utilities. Under normal operating conditions, the Delaware City refinery consumes approximately 75,000 MMBTU per day of natural gas supplied via pipeline from third parties. The Delaware City refinery has a 280 MW power plant located on site that consists of two natural gas-fueled turbines with combined capacity of approximately 140 MW and four turbo generators with combined nameplate capacity of approximately 140 MW. Collectively, this power plant produces electricity in excess of Delaware City’s refinery load of approximately 90 MW. Excess electricity is sold into the Pennsylvania-New Jersey-Maryland, or PJM, grid. Steam is primarily produced by a combination of three dedicated boilers, two heat recovery steam generators on the gas turbines, and is supplemented by secondary boilers at the FCC and Coker. Hydrogen is currently provided via the refinery’s steam methane reformer and continuous catalytic reformer.
Under projected normal operating conditions for the reconfiguration, the Paulsboro refinery will consume approximately 38,000 MMBTU per day of natural gas supplied via pipeline from third parties. The Paulsboro refinery will be mostly self-sufficient for electrical power through a mix of gas and steam turbine generators. The Paulsboro refinery generation is projected to supply all of the 20MW total refinery load. There are circumstances where available generation is greater than the total refinery load, and the Paulsboro refinery can export up to about 40MW of power to the utility grid if warranted. If necessary, supplemental electrical power is available on a guaranteed basis from the local utility. The Paulsboro refinery is connected to the grid via three separate 69KV aerial feeders and has the ability to run entirely on imported power. Steam is produced in three boilers and a heat recovery steam generator fed by the exhaust from the gas turbine. In addition, there are a number of waste heat boilers and furnace stack economizers throughout the refinery that supplement the steam generation capacity. The Paulsboro refinery’s hydrogen needs will be met by the steam methane reformer as the catalytic reformer will be idled.
Hydrogen Plant Project. During 2018, we signed an agreement with a third-party for an additional supply of 25.0 million standard cubic feet per day of hydrogen from a new hydrogen generation facility constructed on the Delaware City site, which was completed in the second quarter of 2020. This additional hydrogen provides additional complex crude and feedstock processing capabilities.
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Toledo Refinery
Overview. The Toledo refinery primarily processes a slate of light, sweet crudes from Canada, the Mid-Continent, the Bakken region and the U.S. Gulf Coast. The Toledo refinery is located on a 282-acre site near Toledo, Ohio, approximately 60 miles from Detroit. Crude is delivered to the Toledo refinery through three primary pipelines: (1) Enbridge from the north, (2) Patoka from the west and (3) Mid-Valley from the south. Crude is also delivered to a nearby terminal by rail and from local sources by truck to a truck unloading facility within the refinery.
The following table approximates the Toledo refinery’s current major process unit capacities. Unit capacities are shown in barrels per stream day.
| Refinery Units | Nameplate Capacity | ||||
| Crude Distillation Unit | 180,000 | ||||
| Fluid Catalytic Cracking Unit | 82,000 | ||||
| Hydrotreating Units | 95,000 | ||||
| Hydrocracking Unit | 52,000 | ||||
| Catalytic Reforming Units | 52,000 | ||||
| Alkylation Unit | 11,000 | ||||
| Polymerization Unit | 7,000 | ||||
| UDEX Unit | 16,300 | ||||
Feedstocks and Supply Arrangements. We source our crude oil needs for Toledo primarily through short-term and spot market agreements.
Refined Product Yield and Distribution. Toledo produces finished products, including gasoline, jet and ULSD, in addition to a variety of high-value petrochemicals including benzene, toluene, xylene, nonene and tetramer. Toledo is connected, via pipelines, to an extensive distribution network throughout Ohio, Illinois, Indiana, Kentucky, Michigan, Pennsylvania and West Virginia. The finished products are transported on pipelines owned by Sunoco Logistics Partners L.P. and Buckeye Partners L.P. In addition, we have proprietary connections to a variety of smaller pipelines and spurs that help us optimize our clean products distribution. A significant portion of Toledo’s gasoline and ULSD are distributed through various terminals in this network.
We have an agreement with Sunoco whereby Sunoco purchases gasoline and distillate products representing approximately one-third of the Toledo refinery’s gasoline and distillates production. The agreement had an initial three-year term, subject to certain early termination rights. In March 2019, the agreement was renewed and extended for a three-year term. We sell the bulk of the petrochemicals produced at the Toledo refinery through short-term contracts or on the spot market and the majority of the petrochemical distribution is done via rail.
Tankage Capacity. The Toledo refinery has total storage capacity of approximately 4.5 million barrels. The Toledo refinery receives its crude through pipeline connections and a truck rack. Of the total, approximately 1.3 million barrels are dedicated to crude oil storage with the remaining 3.2 million barrels allocated to intermediates and products. A portion of storage capacity dedicated to crude oil and finished products was sold to PBFX in conjunction with its acquisition of a tank farm related facility, which included a propane storage and loading facility (the “Toledo Storage Facility”) in December 2014.
Energy and Other Utilities. Under normal operating conditions, the Toledo refinery consumes approximately 25,000 MMBTU per day of natural gas supplied via pipeline from third parties. The Toledo refinery purchases its electricity from the PJM grid and has a long-term contract to purchase hydrogen and steam from a local third-party supplier. In addition to the third-party steam supplier, Toledo consumes a portion of the steam that is generated by its various process units.
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Chalmette Refinery
Overview. The Chalmette refinery is located on a 400-acre site near New Orleans, Louisiana. It is a dual-train coking refinery and is capable of processing both light and heavy crude oil through its 185,000 bpd crude units and downstream units. Chalmette Refining owns 100% of the MOEM Pipeline, providing access to the Empire Terminal, as well as the CAM Connection Pipeline, providing access to the Louisiana Offshore Oil Port facility through a third-party pipeline. Chalmette Refining also owns 80% of each of the Collins Pipeline Company (“Collins”) and T&M Terminal Company (“T&M”), both located in Collins, Mississippi, which provide a clean products outlet for the refinery to the Plantation and Colonial Pipelines. In addition, there is also a marine terminal capable of importing waterborne feedstocks and loading or unloading finished products. There is also a clean products truck rack that provides access to local markets and crude storage that are owned by PBFX.
The following table approximates the Chalmette refinery’s current major process unit capacities. Unit capacities are shown in barrels per stream day.
| Refinery Units | Nameplate Capacity | ||||
| Crude Distillation Units | 185,000 | ||||
| Vacuum Distillation Unit | 114,000 | ||||
| Fluid Catalytic Cracking Unit | 75,000 | ||||
| Hydrotreating Units | 189,000 | ||||
| Delayed Coking Unit | 42,000 | ||||
| Catalytic Reforming Unit | 42,000 | ||||
| Alkylation Unit | 17,000 | ||||
| Aromatics Extraction Unit | 17,000 | ||||
Feedstocks and Supply Arrangements. We source our crude oil and feedstock needs for Chalmette through connections to the CAM Pipeline and MOEM Pipeline as well as our marine terminal. On November 1, 2015, we entered into a market-based crude supply agreement with Petróleos de Venezuela S.A. (“PDVSA”) that has a ten-year term with a renewal option for an additional five years, subject to certain early termination rights. The pricing for the crude supply is market based and is agreed upon on a quarterly basis by both parties. We have not sourced crude oil under this agreement since 2017 as PDVSA has suspended deliveries due to the parties’ inability to agree to mutually acceptable payment terms and because of U.S. government sanctions against PDVSA.
Refined Product Yield and Distribution. The Chalmette refinery predominantly produces gasoline and diesel fuels and also manufactures high-value petrochemicals including benzene and xylene. Products produced at the Chalmette refinery are transferred to customers through pipelines, the marine terminal and truck rack. The majority of our clean products are delivered to customers via pipelines. Our ownership of the Collins pipeline and T&M terminal provides Chalmette with strategic access to Southeast and East Coast markets through third-party logistics.
Tankage Capacity. Chalmette has a total tankage capacity of approximately 8.1 million barrels. Of this total, approximately 2.6 million barrels are allocated to crude oil storage with the remaining 5.5 million barrels allocated to intermediates and products.
Energy and Other Utilities. Under normal operating conditions, the Chalmette refinery consumes approximately 25,000 MMBTU per day of natural gas supplied via pipeline from third parties. The Chalmette refinery purchases its electricity from a local utility and has a long-term contract to purchase hydrogen from a third-party supplier.
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Torrance Refinery
Overview. The Torrance refinery is located on 750 acres in Torrance, California. It is a high-conversion crude, delayed-coking refinery capable of processing both heavy and medium crude oils through its crude unit and downstream units. In addition to refining assets, the Torrance refinery acquisition included a number of high-quality logistics assets including a sophisticated network of crude and products pipelines, product distribution terminals and refinery crude and product storage facilities. The most significant logistics asset is a crude gathering and transportation system which delivers San Joaquin Valley crude oils directly from the field to the refinery, which is now owned by PBFX. Additionally, there are several pipelines serving the refinery that provide access to sources of waterborne crude oils including the Ports of Long Beach and Los Angeles, as well as clean product outlets with a direct pipeline that supplies jet fuel to the Los Angeles airport that are held by affiliates of the refinery.
The following table approximates the Torrance refinery’s current major process unit capacities. Unit capacities are shown in barrels per stream day.
| Refinery Units | Nameplate Capacity | ||||
| Crude Distillation Unit | 166,000 | ||||
| Vacuum Distillation Unit | 102,000 | ||||
| Fluid Catalytic Cracking Unit | 90,000 | ||||
| Hydrotreating Units | 155,500 | ||||
| Hydrocracking Unit | 25,000 | ||||
| Alkylation Unit | 25,500 | ||||
| Delayed Coking Unit | 58,000 | ||||
Feedstocks and Supply Arrangements. The Torrance refinery primarily processes a variety of medium and heavy crude oils. On July 1, 2016, we entered into a crude supply agreement with Exxon Mobil Oil Corporation (“ExxonMobil”) for approximately 60,000 bpd of crude oil that can be processed at our Torrance refinery. This crude supply agreement has a five-year term with an automatic renewal feature unless either party gives thirty-six months written notice of its intent to terminate the agreement. Additionally, we obtain crude and feedstocks from other sources through connections to third-party pipelines as well as ship docks and truck racks.
Refined Product Yield and Distribution. The Torrance refinery predominantly produces gasoline, jet fuel and diesel fuels. Products produced at the Torrance refinery are transferred to customers through pipelines, the marine terminal and truck rack. The majority of clean products are delivered to customers via pipelines. We currently market and sell all of our refined products independently to a variety of customers either on the spot market or through term agreements.
Tankage Capacity. Torrance has a total tankage capacity of approximately 8.6 million barrels. Of this total, approximately 2.1 million barrels are allocated to crude oil storage with the remaining 6.5 million barrels allocated to intermediates and products.
Energy and Other Utilities. Under normal operating conditions, the Torrance refinery consumes approximately 47,000 MMBTU per day of natural gas supplied via pipeline from third parties. The Torrance refinery generates some power internally using a combination of steam and gas turbines and purchases any additional needed power from the local utility. The Torrance refinery has a long-term contract to purchase hydrogen from a third-party supplier.
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Martinez Refinery
We acquired the Martinez refinery and related logistics assets from Equilon Enterprises LLC d/b/a Shell Oil Products US (“Shell Oil Products”) on February 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 to Shell Oil Products based on certain earnings thresholds of the Martinez refinery for a period of up to four years (the “Martinez Acquisition”).
Overview. The Martinez refinery is located on an 860-acre site in the City of Martinez, 30 miles northeast of San Francisco, California. The refinery is a high-conversion, dual-coking facility with a Nelson Complexity Index of 16.1, making it one of the most complex refineries in the United States. The facility is strategically positioned in Northern California and provides for operating and commercial synergies with the Torrance refinery located in Southern California. In addition to refining assets, the Martinez 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.
The following table approximates the Martinez refinery’s current major process unit capacities. Unit capacities are shown in barrels per stream day.
| Refinery Units | Nameplate Capacity | |||||||
| Crude Distillation Unit | 157,000 | |||||||
| Vacuum Distillation Unit | 102,000 | |||||||
| Fluid Catalytic Cracking Unit | 72,000 | |||||||
| Hydrotreating Units | 268,000 | |||||||
| Hydrocracking Unit | 42,900 | |||||||
| Alkylation Unit | 12,500 | |||||||
| Delayed Coking Unit | 25,500 | |||||||
| Flexi Coking Unit | 22,500 | |||||||
| Isomerization Unit | 15,000 | |||||||
Feedstocks and Supply Arrangements. We have entered into various five-year crude supply agreements with Shell Oil Products for approximately 150,000 bpd, in the aggregate, to support our West Coast and Mid-Continent refinery operations. Additionally, we obtain crude and feedstocks from other sources through connections to third-party pipelines as well as ship docks.
Refined Product Yield and Distribution. We entered into certain offtake agreements for our West Coast system with Shell Oil Products for clean products with varying terms up to 15 years. We currently market and sell all of our refined products independently to a variety of customers either on the spot market or through term agreements.
Tankage Capacity. Martinez has a total tankage capacity of approximately 8.8 million barrels. Of this total, approximately 2.5 million barrels are allocated to crude oil storage with the remaining 6.3 million barrels allocated to intermediates and products.
Energy and Other Utilities. Under normal operating conditions, the Martinez refinery consumes approximately 80,000 MMBTU per day of natural gas (including natural gas consumed in hydrogen production) supplied via pipeline from third parties. The Martinez refinery generates some power internally using a combination of steam and gas turbines and purchases any additional needed power from the local utility. The Martinez refinery has a long-term contract to purchase hydrogen from a third-party supplier.
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Agreements with PBFX
Beginning with the completion of the PBFX Offering, we have entered into a series of agreements with PBFX, including commercial and operational agreements. Each of these agreements and their impact to our operations is outlined below.
Contribution Agreements
Immediately prior to the closing of certain contribution agreements, which PBF LLC entered into with PBFX (as defined in the table below, and collectively referred to as the “Contribution Agreements”), we contributed certain assets to PBF LLC. PBF LLC in turn contributed those assets to PBFX pursuant to the Contribution Agreements. Certain proceeds received by PBF LLC from PBFX in accordance with the Contribution Agreements were subsequently contributed by PBF LLC to us. The Contribution Agreements include the following:
| Contribution Agreement | Effective Date | Assets Contributed | Total Consideration | ||||||||
| Contribution Agreement I | 5/8/2014 | DCR Rail Terminal and the Toledo Truck Terminal | 74,053 PBFX common units and 15,886,553 PBFX subordinated units | ||||||||
| Contribution Agreement II | 9/16/2014 | DCR West Rack | $135.0 million in cash and $15.0 million through the issuance of 589,536 PBFX common units | ||||||||
| Contribution Agreement III | 12/2/2014 | Toledo Storage Facility | $135.0 million in cash and $15.0 million through the issuance of 620,935 PBFX common units | ||||||||
| Contribution Agreement IV | 5/5/2015 | DCR Products Pipeline and DCR Truck Rack | $112.5 million in cash and $30.5 million through the issuance of 1,288,420 PBFX common units | ||||||||
| Contribution Agreement V | 8/31/2016 | Torrance Valley Pipeline (50% equity interest in TVPC) | $175.0 million in cash | ||||||||
| Contribution Agreement VI | 2/15/2017 | Paulsboro Natural Gas Pipeline | $11.6 million affiliate promissory note | ||||||||
| Contribution Agreements VII-X | 7/16/2018 | Development Assets | $31.6 million through the issuance of 1,494,134 PBFX common units | ||||||||
| Contribution Agreement XI | 4/24/2019 | Remaining 50% equity interest in TVPC | $200.0 million in cash | ||||||||
On July 16, 2018, PBFX entered into four contribution agreements with PBF LLC pursuant to which we contributed to PBF LLC certain of its subsidiaries (the “Development Assets Contribution Agreements”). Pursuant to the Development Asset Contribution Agreements, we contributed all of the issued and outstanding limited liability company interests of: Toledo Rail Logistics Company LLC, whose assets consist of a loading and unloading rail facility located at the 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 at the Chalmette refinery; Paulsboro Terminaling Company LLC, whose assets consist of a lube oil terminal facility located at the Paulsboro refinery (the “Paulsboro Lube Oil Terminal”); and DCR Storage and Loading Company LLC, whose assets consist of an ethanol storage facility located at the Delaware City refinery (collectively with the Toledo Rail Products Facility, the Chalmette Truck Rack, the Chalmette Rosin Yard, and the Paulsboro Lube Oil Terminal, the “Development Assets”) to PBF LLC. PBFX Operating Company LLC (“PBFX Op Co”), in turn acquired the
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limited liability company interests in the Development Assets from PBF LLC in connection with the Development Assets Contribution Agreements effective July 31, 2018.
On April 24, 2019, PBFX entered into a contribution agreement with PBF LLC, pursuant to which we contributed to PBF LLC, which in turn contributed to PBFX, all of the issued and outstanding limited liability company interests of TVP Holding Company LLC (“TVP Holding”) for total consideration of $200.0 million (the “TVPC Acquisition”). Prior to the TVPC Acquisition, TVP Holding (then our subsidiary) owned a 50% equity interest in Torrance Valley Pipeline Company LLC (“TVPC”). Subsequent to the closing of the TVPC Acquisition on May 31, 2019, PBFX owns 100% of the equity interests in TVPC.
Commercial Agreements
PBFX currently derives the majority of its revenue from long-term, fee-based agreements with us, which generally include a minimum volume commitment (“MVC”), as applicable, and are supported by contractual fee escalations for inflation adjustments and certain increases in operating costs. We believe the terms and conditions under these agreements, as well as the Omnibus Agreement and the Services Agreement (each as defined below), each with PBFX, are generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services.
Refer to “Note 11 - Related Party Transactions” of our Notes to Consolidated Financial Statements for further discussion regarding the commercial agreements with PBFX.
Omnibus Agreement
In addition to the commercial agreements described above, PBFX entered into an omnibus agreement, which has been amended and restated in connection with the closing of certain of the Contribution Agreements with PBF GP, PBF LLC and us (as amended, the “Omnibus Agreement”). The Omnibus Agreement addresses the payment of an annual fee for the provision of various general and administrative services and reimbursement of salary and benefit costs for certain PBF Energy employees.
The annual fee under the Omnibus Agreement for the year ended December 31, 2020 was $7.6 million, inclusive of obligations under the Omnibus Agreement to reimburse us for certain compensation and benefit costs of employees who devoted more than 50% of their time to PBFX during the year ended December 31, 2020. We currently estimate to receive $8.3 million, inclusive of estimated obligations under the Omnibus Agreement as a reimbursement for certain compensation and benefit costs of employees who devote more than 50% of their time to PBFX for the year ending December 31, 2021.
Services Agreement
Additionally, PBFX entered into an operation and management services and secondment agreement with us and certain of our subsidiaries (as amended, the “Services Agreement”), pursuant to which we provide PBFX with the personnel necessary for PBFX to perform its obligations under its commercial agreements. PBFX reimburses us for the use of such employees and the provision of certain infrastructure-related services to the extent applicable to its operations, including storm water discharge and waste water treatment, steam, potable water, access to certain roads and grounds, sanitary sewer access, electrical power, emergency response, filter press, fuel gas, API solids treatment, fire water and compressed air. For the year ended December 31, 2020, PBFX paid us an annual fee of $8.7 million pursuant to the Services Agreement and we currently estimate to receive the same annual reimbursement pursuant to the Services Agreement for the year ending December 31, 2021.
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On February 13, 2019, we amended the existing Amended and Restated Delaware City Rail Terminaling Services Agreement, by and between Delaware City Terminaling Company LLC and us (as amended effective January 1, 2019, the “Amended and Restated Delaware City Rail Terminaling Services Agreement”) for the inclusion of services through certain rail infrastructure at PBFX’s acquired East Coast Storage Assets (the “East Coast Rail Assets”). We also entered into a new Terminaling Services Agreement, by and between Delaware City Terminaling Company and us, with a four-year term starting in 2022, subsequent to the expiration of the Amended and Restated Delaware City Rail Terminaling Services Agreement, related to the DCR Rail Facilities and the East Coast Rail Assets, which will reduce the MVC to 95,000 bpd and includes additional services to be provided by PBFX as operator of facilities owned by our subsidiaries.
The Services Agreement will terminate upon the termination of the Omnibus Agreement, provided that PBFX may terminate any service on 30-days’ notice.
Principal Products
Our refineries make various grades of gasoline, distillates (including diesel fuel, jet fuel, and ULSD) and other products from crude oil, other feedstocks, and blending components. We sell these products through our commercial accounts, and sales with major oil companies. For the years ended December 31, 2020, 2019 and 2018, gasoline and distillates accounted for 85.1%, 87.0% and 84.8% of our revenues, respectively.
Customers
We sell a variety of refined products to a diverse customer base. The majority of our refined products are primarily sold through short-term contracts or on the spot market. However, we do have product offtake arrangements for a portion of our clean products. For the year ended December 31, 2020, only one customer, Royal Dutch Shell, accounted for 10% or more of our revenues (approximately 13%). For the years ended December 31, 2019 and 2018, no single customer accounted for 10% or more of our revenues. As of December 31, 2020, only one customer, Royal Dutch Shell, accounted for 10% or more of our total trade accounts receivable (approximately 17%). No single customer accounted for 10% or more of our total trade accounts receivable as of December 31, 2019.
Seasonality
Traditionally, demand for gasoline and diesel is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and construction work. Decreased demand during the winter months can lower gasoline and diesel prices. However, during 2020, due to the COVID-19 pandemic and related governmental responses, the effects of seasonality on our operating results were skewed. Our operating results have been 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.
Competition
The refining business is very competitive. We compete directly with various other refining companies on the East, Gulf and West Coasts and in the Mid-Continent, with integrated oil companies, with foreign refiners that import products into the United States and with producers and marketers in other industries supplying alternative forms of energy and fuels to satisfy the requirements of industrial, commercial and individual consumers. Some of our competitors have expanded the capacity of their refineries and internationally new refineries are coming on line which could also affect our competitive position.
Profitability in the refining industry depends largely on refined product margins, which can fluctuate significantly, as well as crude oil prices and differentials between the prices of different grades of crude oil, operating efficiency and reliability, product mix and costs of product distribution and transportation. Certain of our competitors that have larger and more complex refineries may be able to realize lower per-barrel costs or higher margins per barrel of throughput. Several of our principal competitors are integrated national or
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international oil companies that are larger and have substantially greater resources. Because of their integrated operations and larger capitalization, these companies may be more flexible in responding to volatile industry or market conditions, such as shortages of feedstocks or intense price fluctuations. Refining margins are frequently impacted by sharp changes in crude oil costs, which may not be immediately reflected in product prices.
The refining industry is highly competitive with respect to feedstock supply. Unlike certain of our competitors that have access to proprietary controlled sources of crude oil production available for use at their own refineries, we obtain all of our crude oil and substantially all other feedstocks from unaffiliated sources. The availability and cost of crude oil and feedstock are affected by global supply and demand. We have no crude oil reserves and are not engaged in the exploration or production of crude oil. We believe, however, that we will be able to obtain adequate crude oil and other feedstocks at generally competitive prices for the foreseeable future.
Pursuant to its Renewable Fuel Standard, EPA has implemented mandates to blend renewable fuels into the petroleum fuels produced and sold in the United States. However, unlike certain of our competitors, we currently do not produce renewable fuels, and increasing the volume of renewable fuels that must be blended into our products displaces an increasing volume of our refineries’ product pool, potentially resulting in lower earnings and profitability. In addition, in order to meet certain of these and future EPA requirements, we may be required to continue to purchase RINs, which historically had, and we expect to have, fluctuating costs based on market conditions. The price of RINs has increased in 2020 and could increase further in 2021.
Corporate Offices
We currently lease approximately 63,000 square feet for our principal corporate offices in Parsippany, New Jersey. The lease for our principal corporate offices expires in 2022. Functions performed in the Parsippany office include overall corporate management, refinery and health, safety and environmental management, planning and strategy, corporate finance, commercial operations, logistics, contract administration, marketing, investor relations, governmental affairs, accounting, tax, treasury, information technology, legal and human resources support functions.
We lease approximately 4,000 square feet for our regional corporate office in Long Beach, California. The lease for our Long Beach office expires in 2021. Functions performed in the Long Beach office include overall regional corporate management, planning and strategy, commercial operations, logistics, contract administration, marketing and governmental affairs.
Employees and Human Capital
Safety
We believe our responsibility to our employees, neighbors, members and the environment is only fulfilled through our commitment to safety and reliability. Through rigorous training, sharing of expertise across our sites, continuous monitoring and through promoting a culture of excellence in operations, we continuously strive to keep our people, the communities in which we operate in and the environment safe.
Our focus on safety is also evident in our response to the COVID-19 pandemic. We continue to utilize our COVID-19 response team to implement additional social distancing measures across the workplace in addition to the continued enhancement of personal protective equipment and the cleanliness of our facilities. Through the guidance of our COVID-19 response team, we have started to bring back a portion of our workforce to their primary locations on a phased in approach, and we will continue to rely on our team and the evolution of the COVID-19 pandemic as we evaluate the appropriate time and way in which we will phase in the return of the rest of our workforce.
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We are subject to the requirements of the Occupational Safety and Health Administration of the U.S. Department of Labor (“OSHA”) and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA Hazard Communication Standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances.
Development and Retention
The development, attraction and retention of employees is a critical success factor for our Company. To support the advancement of our employees, we offer rigorous training and development programs and encourage the sharing of expertise across our sites. We actively promote inclusion and diversity in our workforce at each of our locations and provide our employees with opportunities to give back through engagement in our local communities through supportive educational programs, philanthropic and volunteer activities.
We believe that a combination of competitive compensation and career growth and development opportunities help increase employee morale and reduce voluntary turnover. Our comprehensive benefit packages are competitive in the marketplace and we believe in recognizing and rewarding talent through our various cash and equity compensation programs.
Headcount
As of December 31, 2020, we had approximately 3,638 employees, of which 1,931 are covered by collective bargaining agreements. Our hourly employees are covered by collective bargaining agreements through the United Steel Workers (“USW”), the Independent Oil Workers (“IOW”) and the International Brotherhood of Electrical Workers (“IBEW”). We consider our relations with the represented employees to be satisfactory.
| Location | Number of employees | Employees covered by collective bargaining agreements | Collective bargaining agreements | Expiration date | ||||||||||||||||||||||
| Headquarters | 397 | — | N/A | N/A | ||||||||||||||||||||||
| Delaware City refinery | 518 | 358 | USW | January 2022 | ||||||||||||||||||||||
| Paulsboro refinery | 442 | 260 | IOW | March 2022 | ||||||||||||||||||||||
| Toledo refinery | 483 | 313 | USW | February 2022 | ||||||||||||||||||||||
| Chalmette refinery | 543 | 307 | USW | January 2022 | ||||||||||||||||||||||
| Torrance refinery | 564 | 297 12 | USW IBEW | January 2022 January 2022 | ||||||||||||||||||||||
| Torrance logistics | 106 | 42 4 | USW USW | April 2021 January 2022 | ||||||||||||||||||||||
| Martinez refinery | 585 | 314 24 | USW IBEW | February 2022 February 2022 | ||||||||||||||||||||||
| Total employees | 3,638 | 1,931 | ||||||||||||||||||||||||
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Environmental, Health and Safety Matters
Our refineries, pipelines and related operations are subject to extensive and frequently changing federal, state and local laws and regulations, including, but not limited to, those relating to the discharge of materials into the environment or that otherwise relate to the protection of the environment, waste management and the characteristics and the compositions of fuels. Compliance with existing and anticipated laws and regulations can increase the overall cost of operating the refineries, including remediation, operating costs and capital costs to construct, maintain and upgrade equipment and facilities. Permits are also required under these laws for the operation of our refineries, pipelines and related operations and these permits are subject to revocation, modification and renewal. Compliance with applicable environmental laws, regulations and permits will continue to have an impact on our operations, results of operations and capital requirements. We believe that our current operations are in substantial compliance with existing environmental laws, regulations and permits.
We incorporate by reference into this Item the environmental disclosures contained in the following sections of this report:
•Item 1A. “Risk Factors”
◦ We may incur significant liability under, or costs and capital expenditures to comply with, environmental and health and safety regulations, which are complex and change frequently;
◦ Environmental clean-up and remediation costs of our sites and environmental litigation could decrease our net cash flow, reduce our results of operations and impair our financial condition;
◦ We may have capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate;
◦ We are subject to strict laws and regulations regarding employee and process safety, and failure to comply with these laws and regulations could have a material adverse effect on our results of operations, financial condition and profitability;
◦ Changes in laws or standards affecting the transportation of North American crude oil by rail could significantly impact our operations, and as a result cause our costs to increase.
◦ We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with health, safety, environmental and other laws and regulations.
•Item 3. “Legal Proceedings”
•Item 8. “Financial Statements and Supplementary Data”
◦ Note 8 - Accrued Expenses,
◦ Note 10 - Other Long-Term Liabilities and
◦ Note 12 - Commitments and Contingencies
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Applicable Federal and State Regulatory Requirements
As is the case with all companies engaged in industries similar to ours, we face potential exposure to future claims and lawsuits involving environmental and safety matters. These matters include soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances which we manufactured, handled, used, released or disposed of.
Current and future environmental regulations are expected to require additional expenditures, including expenditures for investigation and remediation, which may be significant, at our refineries and at our other facilities. To the extent that future expenditures for these purposes are material and can be reasonably determined, these costs are disclosed and accrued.
Our operations are also subject to various laws and regulations relating to occupational health and safety. We maintain safety training and maintenance programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations. Compliance with applicable health and safety laws and regulations has required and continues to require substantial expenditures.
We cannot predict what additional health, safety and environmental legislation or regulations will be enacted or become effective in the future or how existing or future laws or regulations will be administered or interpreted with respect to our operations. Compliance with more stringent laws or regulations or adverse changes in the interpretation of existing requirements or discovery of new information such as unknown contamination could have an adverse effect on the financial position and the results of our operations and could require substantial expenditures for the installation and operation of systems and equipment that we do not currently possess.
We incorporate by reference into this Item the federal and state regulatory requirements disclosures contained in the following sections of this report:
•Item 8. “Financial Statements and Supplementary Data”
◦ Note 12 - Commitments and Contingencies
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ITEM 1A. RISK FACTORS
Summary of Risk Factors
Operating in our industry involves a high degree of risk. These risks are discussed more fully below and include, but are not limited to, the following, any of which could have a material adverse effect on our financial condition, results of operations and cash flows:
Risks Related to the COVID-19 Pandemic
•The COVID-19 pandemic and its effects on our liquidity, business, financial condition and results of operations.
Risks Relating to Our Business and Industry
•The price volatility of crude oil, other feedstocks, blendstocks, refined products and fuel and utility services may have a material adverse effect on our revenues, profitability, cash flows and liquidity.services.
•Existence of these pipelines to transport crude oil or refined products is disrupted because of accidents, weather interruptions, governmental regulation, terrorism, other third party action or casualty or other events.
•Significant interruptions or in some cases, cease to provide funding to borrowers. Due to these factors, we cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due. Moreover, without adequate funding, we may be unable to execute our growth strategy, complete future acquisitions, take advantage of other business opportunities or respond to competitive pressures,casualty losses at any of which could have a material adverse effectour refineries and related assets.
•Interruptions of supply and distribution at our refineries.
•Regulation of emissions of greenhouse gases and other environmental and health and safety regulations.
•Integration of the recently acquired Martinez Refinery into our business.
•A cyber-attack on, or other failure of, our revenues and results of operations.technology infrastructure.
•Competition from companies who produce their own supply of feedstocks, have extensive retail outlets, make alternative fuels ornot been adversely impacted as much as we have greater financial and other resources than we do could materially and adversely affect our business and results of operations.been by the COVID-19 pandemic.
•Any political instability, military strikes, sustained military campaigns, terrorist activity, or changes in foreign policy, could have a material adverse effect on our business, results of operations and financial condition.
•Discontinuation of vendors and suppliers;
•Changes in our credit profile could adversely affect our business.profile.
Risks Related to Our Indebtedness
•Our substantial levels of indebtedness.
•Changes in our credit ratings.
•Limitations on our operations arising out of restrictive covenants in our debt instruments.
•Anti-takeover provisions in our indentures.
•The discontinuation of the London Interbank Offering Rate (“LIBOR”), and the adoption of an alternative reference rate.
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Risk Factors
You should carefully read the risks and uncertainties described below. The risks and uncertainties described below are not the only ones facing our company. Additional risks and uncertainties may also impair our business operations. If any of the following risks actually occur, our business, financial condition, results of operations or cash flows would likely suffer.
Risks Related to the COVID-19 Pandemic
The outbreak of the COVID-19 pandemic significantly affected our liquidity, business, financial condition and results of operations in 2020 and caused our market value to substantially decline, and may continue to do so thereafter. There can be no assurance that our liquidity, business, financial condition and results of operations will revert to pre-2020 levels once the impacts of COVID-19 pandemic cease.
The outbreak of the COVID-19 pandemic and certain developments in the global oil markets negatively impacted worldwide economic and commercial activity and financial markets, as well as global demand for petroleum and petrochemical products in 2020 and is expected to continue in 2021. The COVID-19 pandemic and related governmental responses resulted in significant business and operational disruptions, including business closures, supply chain disruptions, travel restrictions, stay-at-home orders and limitations on the availability of workforces. Largely, as a result of decreased demand for our products, our business results and cash flows were significantly adversely impacted by the COVID-19 pandemic. Specifically, PBF Holding’s earnings and cash flow from operations decreased from $388.2 million and $789.6 million in 2019 to $(1,857.5) million and $(820.0) million in 2020, respectively.
In addition, the impact of the COVID-19 pandemic has created simultaneous shocks in oil supply and demand resulting in an economic challenge to our industry which has not occurred since our formation. We expect the combination of significant demand reduction for our refined products and abnormal volatility in oil commodity prices to continue for the foreseeable future. The duration of the impact of the COVID-19 pandemic and these market developments is unknown. The continued negative impact of the COVID-19 pandemic and these market developments on our business and operations will depend on the ongoing severity, location and duration of the effects and spread of COVID-19, the effectiveness of the vaccine programs and the other actions undertaken by national, regional and local governments and health officials to contain the virus or treat its effects, and how quickly and to what extent economic conditions improve and normal business and operating conditions resume in 2021 or thereafter.
We continue to work with federal, state and local health authorities to respond to COVID-19 cases in the regions we operate and are taking or supporting measures to try to limit the spread of the virus and to mitigate the burden on the healthcare system. Many of these measures will continue to have an adverse impact on our business and financial results that we are not currently able to fully quantify. For example, we are continuing to phase back employees to their respective work locations and we are carefully evaluating projects at our refineries and limiting or postponing projects and other non-essential work. Based on market conditions, our refineries operated at reduced rates in 2020 and we expect them to continue to do so until market conditions substantially improve. We significantly reduced our capital expenditures in 2020 and have lowered our capital program for 2021 as compared to historic levels. We have planned a level of capital expenditures we believe will allow us to satisfy and comply with all required safety, environmental and planned regulatory capital commitments and other regulatory requirements, although there are no assurances that we will be able to continue to do so. Non-compliance with applicable environmental and safety requirements, including as a result of reduced staff due to an outbreak at one of our refineries, may impair our operations, may subject us to fines or penalties assessed by governmental authorities and/or may result in an environmental or safety incident. We may also be subject to liability as a result of claims against us by impacted workers or third parties.
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The East Coast Refining Reconfiguration was announced on October 29, 2020 and completed on December 31, 2020. It is expected to provide us with crude optionality and increased flexibility to respond to evolving market conditions. Our East Coast Refining System throughput capacity is approximately 285,000 barrels per day, reflecting the new configuration and idling of certain major processing units. Annual operating and capital expenditures savings are expected to be approximately $100.0 million and $50.0 million, respectively, relative to average historic levels. There is no certainty that we will be able to achieve these cost savings measures as part of our new configuration.
The persistence or worsening or market conditions related to the COVID-19 pandemic may require us to raise additional capital to meet our obligations and operate our business.
In 2020, low crude oil prices and deteriorating market conditions reduced our borrowing capacity under our asset-based revolving credit agreement (the “Revolving Credit Facility”) and our borrowing capacity is expected to be similarly affected in 2021. Our borrowing base availability under the Revolving Credit Facility was $2,759.2 million as of December 31, 2020. In 2020, we required additional capital and raised approximately $1.8 billion through $1.3 billion of secured debt issuances and approximately $550.0 million of asset divestitures. Certain of these asset divestitures were accompanied by payment and/or purchase obligations that will impact our liquidity in 2021 and beyond. If current market conditions persist or worsen, we may require additional capital to meet these obligations as well as to operate our business, and additional financing and/or assets sales may not be possible on favorable terms or at all. Broad economic factors resulting from the current COVID-19 pandemic, including increasing unemployment rates, substantially reduced travel and reduced business and consumer spending, also affect our business.
Demand for our refined products has significantly declined and we expect reduced demand to continue into 2021.
Business closings and layoffs in the markets we operate has adversely affected demand for our refined products. Sustained deterioration of general economic conditions or weak demand levels persisting in 2021 could require additional actions on our part to lower our operating costs, including temporarily or permanently ceasing to operate units at our facilities, as occurred in 2020 in the case of the East Coast Refining Reconfiguration. There may be significant incremental costs associated with such actions. Continued or further deterioration of economic conditions may harm our liquidity and ability to repay our outstanding debt.
We recorded an impairment charge during the year ended December 31, 2020 and may be required to record additional impairment charges.
We recorded impairment expense totaling $91.8 million for the year ended December 31, 2020, associated with the write-down of certain assets as a result of the East Coast Refining Reconfiguration and other refinery wide project abandonments. In addition, as a result of 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 of December 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. Any impairment could have a material adverse effect on our Consolidated Financial Statements.
In addition, our results and financial condition may be adversely affected by federal or state laws, regulations, orders, or other governmental or regulatory actions addressing the current COVID-19 pandemic or the U.S. refining industry, which, if adopted, could result in direct or indirect restrictions to our business, financial condition, results of operations and cash flow.
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Furthermore, the current COVID-19 pandemic has caused disruption in the financial markets and the businesses of financial institutions. These factors have caused a slowdown in the decision-making of these institutions, which may affect the timing on which we may obtain any additional funding. There can be no assurance that we will be able to raise additional funds on terms acceptable to us, if at all.
The foregoing and other continued disruptions to our business as a result of the COVID-19 pandemic could result in a material adverse effect on our business, result of operations, financial condition, cash flows and our ability to service our indebtedness and other obligations. There can also be no assurance that our liquidity, business, financial condition and results of operations will revert to pre-2020 levels once the impacts of COVID-19 pandemic cease.
To the extent the COVID-19 pandemic continues to adversely affect our business, financial condition, results of operations and liquidity, it may also have the effect of heightening many of the other risks associated with our company, our business and our industry, as those risk factors are amended or supplemented by reports and documents we file with the SEC after the date of this Form 10-K.
Risks Relating to Our Business and Industry
The price volatility of crude oil, other feedstocks, blendstocks, refined products and fuel and utility services may have a material adverse effect on our revenues, profitability, cash flows and liquidity.
Our revenues, profitability, cash flows and liquidity from operations depend primarily on the margin above operating expenses (including the cost of refinery feedstocks, such as crude oil, intermediate partially refined petroleum products, and natural gas liquids that are processed and blended into refined products) at which we are able to sell refined products. Refining is primarily a margin-based business and, to increase profitability, it is important to maximize the yields of high value finished products while minimizing the costs of feedstock and operating expenses. When the margin between refined product prices and crude oil and other feedstock costs contracts, as occurred in 2020, our earnings, profitability and cash flows are negatively affected. While the COVID-19 pandemic was the primary driver of the impact to our earnings, profitability and cash flows in 2020, historically, refining margins have been volatile, and are likely to continue to be volatile, as a result of a variety of factors, including fluctuations in the prices of crude oil, other feedstocks, refined products and fuel and utility services. An increase or decrease in the price of crude oil will likely result in a similar increase or decrease in prices for refined products; however, there may be a time lag in the realization, or no such realization, of the similar increase or decrease in prices for refined products. The effect of changes in crude oil prices on our refining margins therefore depends in part on how quickly and how fully refined product prices adjust to reflect these changes.
Although we reduced our crude oil, feedstock and refined product inventories in 2020 to strengthen our financial position in response to the COVID-19 pandemic, historically, the nature of our business has required us to maintain substantial crude oil, feedstock and refined product inventories. Because crude oil, feedstock and refined products are commodities, we have no control over the changing market value of these inventories. Our crude oil, feedstock and refined product inventories are valued at the lower of cost or market value under the last-in-first-out (“LIFO”) inventory valuation methodology. If the market value of our crude oil, feedstock and refined product inventory declines to an amount less than our LIFO cost, we would record a write-down of inventory and a non-cash impact to cost of products and other. For example, during the year ended December 31, 2020, we recorded an adjustment to value our inventories to the lower of cost or market which decreased both income from operations and net income by $268.0 million, reflecting the net change in the LCM inventory reserve from $401.6 million at December 31, 2019 to $669.6 million at December 31, 2020.
Prices of crude oil, other feedstocks, blendstocks, and refined products depend on numerous factors beyond our control, including the supply of and demand for crude oil, other feedstocks, gasoline, diesel, ethanol, asphalt and other refined products. Such supply and demand are affected by a variety of economic, market, environmental and political conditions.
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Our direct operating expense structure also impacts our profitability. Our major direct operating expenses include employee and contract labor, maintenance and energy. Our predominant variable direct operating cost is energy, which is comprised primarily of fuel and other utility services. The volatility in costs of fuel, principally natural gas, and other utility services, principally electricity, used by our refineries and other operations affect our operating costs. Fuel and utility prices have been, and will continue to be, affected by factors outside our control, such as supply and demand for fuel and utility services in both local and regional markets. Natural gas prices have historically been volatile and, typically, electricity prices fluctuate with natural gas prices. Future increases in fuel and utility prices may have a negative effect on our refining margins, profitability and cash flows.
Our working capital, cash flows and liquidity can be significantly impacted by volatility in commodity prices and refined product demand.
Payment terms for our crude oil purchases are typically longer than those terms we extend to our customers for sales of refined products. Additionally, reductions in crude oil purchases tend to lag demand decreases for our refined products. As a result of this timing differential, the payables for our crude oil purchases are generally proportionally larger than the receivables for our refined product sales. As we are normally in a net payables position, a decrease in commodity prices generally results in a use of working capital. Given we process a significant volume of crude oil, the impact can materially affect our working capital, cash flows and liquidity, all of which were, and continue to be, adversely affected by the COVID-19 pandemic.
Our profitability is affected by crude oil differentials and related factors, which fluctuate substantially.
A significant portion of our profitability is derived from the ability to purchase and process crude oil feedstocks that historically have been less expensive than benchmark crude oils, such as the heavy, sour crude oils processed at our Delaware City, Paulsboro, Chalmette, Torrance and Martinez refineries. For our Toledo refinery, aside from recent crude differential volatility, purchased crude prices have historically been slightly above the WTI benchmark, however, such crude slate typically results in favorable refinery production yield. For all locations, these crude oil differentials can vary significantly from quarter to quarter depending on overall economic conditions and trends and conditions within the markets for crude oil and refined products. Any change in these crude oil differentials may have an impact on our earnings. Our rail investment and strategy to acquire cost advantaged Mid-Continent and Canadian crude, which are priced based on WTI, could be adversely affected when the WTI/Dated Brent or related differentials narrow. A narrowing of the WTI/Dated Brent differential may result in our Toledo refinery losing a portion of its crude oil price advantage over certain of our competitors, which negatively impacts our profitability. In addition, efforts in Canada to control the imbalance between its production and capacity to export crude may continue to result in price volatility and the narrowing of the WTI/WCS differential, which is a proxy for the difference between light U.S. and heavy Canadian crude oil, and may reduce our refining margins and adversely affect our profitability and earnings. Divergent views have been expressed as to the expected magnitude of changes to these crude differentials in future periods. Any continued or further narrowing of these differentials could have a material adverse effect on our business and profitability.
Additionally, governmental and regulatory actions, including continued resolutions by the Organization of the Petroleum Exporting Countries to restrict crude oil production levels and executive actions by the current U.S. presidential administration to advance certain energy infrastructure projects such as the Keystone XL pipeline, may continue to impact crude oil prices and crude oil differentials. Any increase in crude oil prices or unfavorable movements in crude oil differentials due to such actions or changing regulatory environment may negatively impact our ability to acquire crude oil at economical prices and could have a material adverse effect on our business and profitability.
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A significant interruption or casualty loss at any of our refineries and related assets could reduce our production, particularly if not fully covered by our insurance. Failure by one or more insurers to honor its coverage commitments for an insured event could materially and adversely affect our future cash flows, operating results and financial condition.
Our business currently consists of owning and operating six refineries and related assets. As a result, our operations could be subject to significant interruption if any of our refineries were to experience a major accident, be damaged by severe weather or other natural disaster, or otherwise be forced to shut down or curtail production due to unforeseen events, such as acts of God, nature, orders of governmental authorities, supply chain disruptions impacting our crude rail facilities or other logistics assets, power outages, acts of terrorism, fires, toxic emissions and maritime hazards. Any such shutdown or disruption would reduce the production from that refinery. There is also risk of mechanical failure and equipment shutdowns both in general and following unforeseen events. Further, in such situations, undamaged refinery processing units may be dependent on or interact with damaged sections of our refineries and, accordingly, are also subject to being shut down. In the event any of our refineries is forced to shut down for a significant period of time, it would have a material adverse effect on our earnings, our other results of operations and our financial condition as a whole.
As protection against these hazards, we maintain insurance coverage against some, but not all, such potential losses and liabilities, including claims against us by third parties relating to our operations and products. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may increase substantially. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, coverage for hurricane damage can be limited, and coverage for terrorism risks can include broad exclusions. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position.
Our insurance program includes a number of insurance carriers. Significant disruptions in financial markets could lead to a deterioration in the financial condition of many financial institutions, including insurance companies and, therefore, we may not be able to obtain the full amount of our insurance coverage for insured events. Even where we have insurance in place, there can be no assurance that the carriers will honor their obligations under the policies.
Our refineries are subject to interruptions of supply and distribution as a result of our reliance on pipelines and railroads for transportation of crude oil and refined products.
Our Toledo, Chalmette, Torrance and Martinez refineries receive a significant portion of their crude oil through our owned, as well as third party, pipelines. These pipelines include the Enbridge system, Capline and Mid-Valley pipelines for supplying crude to our Toledo refinery, the MOEM Pipeline (which is owned by PBFX) and CAM Pipeline for supplying crude to our Chalmette refinery and the San Joaquin Pipeline, San Pablo Bay Pipeline, San Ardo and Coastal Pipeline systems for supplying crude to our Torrance and Martinez refineries. Additionally, our Toledo, Chalmette, Torrance and Martinez refineries deliver a significant portion of the refined products through pipelines. These pipelines include pipelines such as the Sunoco Logistics Partners L.P. and Buckeye Partners L.P. pipelines at Toledo, the Collins pipeline (which is owned by PBFX) at our Chalmette refinery, the Jet Pipeline to the Los Angeles International Airport, the Product Pipeline to Vernon and the Product Pipeline to Atwood at our Torrance refinery and the KinderMorgan SFPP North Pipeline at our Martinez refinery. We could experience an interruption of supply or delivery, or an increased cost of receiving crude oil and delivering refined products to market, if the ability of these pipelines to transport crude oil or refined products is disrupted because of accidents, weather interruptions, governmental regulation, terrorism, other third-party action or casualty or other events.
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The Delaware City rail unloading facilities and the East Coast Storage Assets allow our East Coast Refining System to source WTI-based crudes from Western Canada and the Mid-Continent, which may provide significant cost advantages versus traditional Brent-based international crudes in certain market environments. Any disruptions or restrictions to our supply of crude by rail due to problems with third-party logistics infrastructure or operations or as a result of increased regulations, could increase our crude costs and negatively impact our results of operations and cash flows.
In addition, due to the common carrier regulatory obligation applicable to interstate oil pipelines, capacity allocation among shippers can become contentious in the event demand is in excess of capacity. Therefore, nominations by new shippers or increased nominations by existing shippers may reduce the capacity available to us. Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that we rely upon for transportation of crude oil and refined products could have a further material adverse effect on our business, financial condition, results of operations and cash flows.
Regulation of emissions of greenhouse gases could force us to incur increased capital and operating costs and could have a material adverse effect on our results of operations and financial condition.
Both houses of Congress have actively considered legislation to reduce emissions of GHGs, such as carbon dioxide and methane, including proposals to: (i) establish a cap and trade system, (ii) create a federal renewable energy or “clean” energy standard requiring electric utilities to provide a certain percentage of power from such sources, and (iii) create enhanced incentives for use of renewable energy and increased efficiency in energy supply and use. In addition, EPA is taking steps to regulate GHGs under the existing federal CAA. EPA has already adopted regulations limiting emissions of GHGs from motor vehicles, addressing the permitting of GHG emissions from stationary sources, and requiring the reporting of GHG emissions from specified large GHG emission sources, including refineries. These and similar regulations could require us to incur costs to monitor and report GHG emissions or reduce emissions of GHGs associated with our operations. In addition, various states, individually as well as in some cases on a regional basis, have taken steps to control GHG emissions, including adoption of GHG reporting requirements, cap and trade systems and renewable portfolio standards (such as AB32). On September 23, 2020 the Governor of California issued an executive order effectively banning the sale of new gasoline-powered passenger cars and trucks by 2035 and requiring zero-emission medium to heavy duty vehicles by 2045 everywhere feasible. The executive order requires state agencies to build out sufficient electric vehicle charging infrastructure. It is not possible at this time to predict the ultimate form, timing or extent of federal or state regulation. In addition, it is currently uncertain how the current presidential administration or future administrations will address GHG emissions. In the event we do incur increased costs as a result of increased efforts to control GHG emissions, we may not be able to pass on any of these costs to our customers. Regulatory requirements also could adversely affect demand for the refined petroleum products that we produce. Any increased costs or reduced demand could materially and adversely affect our business and results of operations.
Requirements to reduce emissions could result in increased costs to operate and maintain our facilities as well as implement and manage new emission controls and programs put in place. For example, in September 2016, the state of California enacted Senate Bill 32 which further reduces greenhouse gas emissions targets to 40 percent below 1990 levels by 2030. Two regulations implemented to achieve these goals are Cap-and-Trade and the Low Carbon Fuel Standard (“LCFS”). In 2012, CARB implemented Cap-and-Trade. This program currently places a cap on GHGs and we are required to acquire a sufficient number of credits to cover emissions from our refineries and our in-state sales of gasoline and diesel. In 2009, CARB adopted the LCFS, which required a 10% reduction in the carbon intensity of gasoline and diesel by 2020. In 2018, CARB amended the LCFS to require a 20% reduction by 2030. Compliance is achieved through blending lower carbon intensity biofuels into gasoline and diesel or by purchasing credits. Compliance with each of these programs is facilitated through a market-based credit system. If sufficient credits are unavailable for purchase or we are unable to pass through costs to our customers, we have to pay a higher price for credits or if we are otherwise unable to meet our compliance obligations, our financial condition and results of operations could be adversely affected.
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On September 23, 2020, the California Governor issued Executive Order N-79-20 (“N-79-20 Order”) intended to further reduce GHGs within the state. The N-79-20 Order sets a 2035 goal of no sale of internal combustion engines for passenger cars and pickup trucks within California, and a 2045 goal of no sale of internal combustion engine medium- and heavy-duty trucks, and off-road vehicles and equipment. However, the N-79-20 Order would still allow used internal combustion engine vehicles to be used and sold after these dates. The N-79-20 Order encourages zero emissions technologies such as electric vehicles, and accelerated deployment of affordable fueling and charging options. It is currently uncertain how the N-79-20 Order may be ultimately implemented by various California regulatory agencies. In the event we do incur increased costs as a result of increased efforts to control GHG emissions through future adopted regulatory requirements, we may not be able to pass these costs to our customers. These future regulatory requirements also could adversely affect demand for the refined petroleum products that we produce. Any increased costs or reduced demand could materially and adversely affect our business and results of operations.
We may not be able to successfully integrate the recently acquired Martinez refinery into our business, or realize the anticipated benefits of this acquisition.
The integration of the recently acquired Martinez refinery into our operations has been impacted by the COVID-19 pandemic and may continue to be a complex and time-consuming process that may not be successful. Even if we successfully integrate this business into our operations, there can be no assurance that we will realize the anticipated benefits and operating synergies. Our estimates regarding the earnings, operating cash flow, capital expenditures and liabilities resulting from this acquisition may prove to be incorrect. This acquisition involves risks, including:
•unexpected losses of key employees, customers and suppliers of the acquired operations;
•challenges in managing the increased scope, geographic diversity and complexity of our operations;
•diversion of management time and attention from our existing business;
•liability for known or unknown environmental conditions or other contingent liabilities and greater than anticipated expenditures required for compliance with environmental, safety or other regulatory standards or for investments to improve operating results; and
•the incurrence of additional indebtedness to finance acquisitions or capital expenditures relating to acquired assets.
In connection with the Martinez Acquisition, we did not have access to the type of historical financial information that we may require regarding the prior operation of the refinery. As a result, it may be difficult for investors to evaluate the probable impact of this acquisition on our financial performance until we have operated the acquired refinery for a substantial period of time.
A cyber-attack on, or other failure of, our technology infrastructure could affect our business and assets, and have a material adverse effect on our financial condition, results of operations and cash flows.
We are becoming increasingly dependent on our technology infrastructure and certain critical information systems which process, transmit and store electronic information, including information we use to safely and effectively operate our respective assets and businesses. These information systems include data network and telecommunications, internet access, our websites, and various computer hardware equipment and software applications, including those that are critical to the safe operation of our refineries and logistics assets. We have invested, and expect to continue to invest, significant time, manpower and capital in our technology infrastructure and information systems. These information systems are subject to damage or interruption from a number of potential sources including natural disasters, software viruses or other malware, power failures, cybersecurity threats to gain unauthorized access to sensitive information, cyber-attacks, which may render data systems unusable, and physical threats to the security of our facilities and infrastructure. Additionally, our business is highly dependent on financial, accounting and other data processing systems and other communications and information systems, including our enterprise resource planning tools. We process a large number of transactions on a daily basis and rely upon the proper functioning of computer systems. Furthermore, we rely on information systems across our respective operations, including the management of supply chain and
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various other processes and transactions. As a result, a disruption on any information systems at our refineries or logistics assets, may cause disruptions to our collective operations.
The potential for such security threats or system failures has subjected our operations to increased risks that could have a material adverse effect on our business. To the extent that these information systems are under our control, we have implemented measures such as virus protection software, emergency recovery processes and a formal disaster recovery plan to address the outlined risks. However, security measures for information systems cannot be guaranteed to be failsafe, and our formal disaster recovery plan and other implemented measures may not prevent delays or other complications that could arise from an information systems failure. If a key system were hacked or otherwise interfered with by an unauthorized user, or were to fail or experience unscheduled downtime for any reason, even if only for a short period, or any compromise of our data security or our inability to use or access these information systems at critical points in time, it could unfavorably impact the timely and efficient operation of our business, damage our reputation and subject us to additional costs and liabilities. The implementation of social distancing measures and other limitations on our workforce in response to the COVID-19 pandemic have necessitated portions of our workforce switching to remote work arrangements. The increase in companies and individuals working remotely has increased the frequency and scope of cyber-attacks and the risk of potential cybersecurity incidents, both deliberate attacks and unintentional events. While, to date, we have not had a significant cybersecurity breach or attack that had a material impact on our business or results of operations, if we were to be subject to a material successful cyber intrusion, it could result in remediation or service restoration costs, increased cyber protection costs, lost revenues, litigation or regulatory actions by governmental authorities, increased insurance premiums, reputational damage and damage to our competitiveness, financial condition, results of operations and cash flows.
Cyber-attacks against us or others in our industry could result in additional regulations, and U.S. government warnings have indicated that infrastructure assets, including pipelines, may be specifically targeted by certain groups. These attacks include, without limitation, malicious software, ransomware, attempts to gain unauthorized access to data, and other electronic security breaches. These attacks may be perpetrated by state-sponsored groups, “hacktivists”, criminal organizations or private individuals (including employee malfeasance). Current efforts by the federal government, such as the Strengthening the Cybersecurity of Federal Networks and Critical Infrastructure executive order, and any potential future regulations could lead to increased regulatory compliance costs, insurance coverage cost or capital expenditures. We cannot predict the potential impact to our business or the energy industry resulting from additional regulations.
Further, our business interruption insurance may not compensate us adequately for losses that may occur. We do not carry insurance specifically for cybersecurity events; however, certain of our insurance policies may allow for coverage for a cyber-event resulting in ensuing property damage from an otherwise insured peril. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, results of operations and cash flows. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.
Our hedging activities may limit our potential gains, exacerbate potential losses and involve other risks.
We may enter into commodity derivatives contracts to hedge our crude price risk or crack spread risk with respect to a portion of our expected gasoline and distillate production on a rolling basis or to hedge our exposure to the price of natural gas, which is a significant component of our refinery operating expenses. Consistent with that policy we may hedge some percentage of our future crude and natural gas supply. We may enter into hedging arrangements with the intent to secure a minimum fixed cash flow stream on the volume of products hedged during the hedge term and to protect against volatility in commodity prices. Our hedging arrangements may fail to fully achieve these objectives for a variety of reasons, including our failure to have adequate hedging arrangements, if any, in effect at any particular time and the failure of our hedging arrangements to produce the anticipated results. We may not be able to procure adequate hedging arrangements due to a variety of factors. Moreover, such transactions may limit our ability to benefit from favorable changes in crude oil, refined product and natural gas prices.
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In addition, our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which:
•the volumes of our actual use of crude oil or natural gas or production of the applicable refined products is less than the volumes subject to the hedging arrangement;
•accidents, interruptions in feedstock transportation, inclement weather or other events cause unscheduled shutdowns or otherwise adversely affect our refineries, or those of our suppliers or customers;
•changes in commodity prices have a material impact on collateral and margin requirements under our hedging arrangements, resulting in us being subject to margin calls;
•the counterparties to our derivative contracts fail to perform under the contracts; or
•a sudden, unexpected event materially impacts the commodity or crack spread subject to the hedging arrangement.
As a result, the effectiveness of our hedging strategy could have a material impact on our financial results. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”
In addition, these hedging activities involve basis risk. Basis risk in a hedging arrangement occurs when the price of the commodity we hedge is more or less variable than the index upon which the hedged commodity is based, thereby making the hedge less effective. For example, a NYMEX index used for hedging certain volumes of our crude oil or refined products may have more or less variability than the actual cost or price we realize for such crude oil or refined products. We may not hedge all the basis risk inherent in our hedging arrangements and derivative contracts.
We may have capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate.
Our cash flow from operations decreased from $789.6 million in 2019 to a loss of $820.0 million in 2020. If our cash flow from operations does not improve in 2021 or we cannot otherwise secure sufficient liquidity to support our short-term and long-term capital requirements, we may not be able to meet our payment obligations or our future debt obligations, comply with certain deadlines related to environmental regulations and standards, or pursue our business strategies, including acquisitions, in which case our operations may not perform as we currently expect. We have substantial short-term capital needs and may have substantial long-term capital needs. Our short-term working capital needs are primarily related to financing certain of our crude oil and refined products inventory not covered by our various supply and Inventory Intermediation Agreements.
If we cannot adequately handle our crude oil and feedstock requirements or if we are required to obtain our crude oil supply at our other refineries without the benefit of the existing supply arrangements or the applicable counterparty defaults in its obligations, our crude oil pricing costs may increase as the number of days between when we pay for the crude oil and when the crude oil is delivered to us increases. Termination of our Inventory Intermediation Agreements with J. Aron, which are currently scheduled to expire in 2021, would require us to finance the J. Aron Products covered by the agreements, which financing may not be available at terms that are as favorable or at all. We are obligated to repurchase from J. Aron all volumes of the J. Aron Products upon expiration or earlier termination of these agreements, which may have a material adverse impact on our liquidity, working capital and financial condition. Further, if we are not able to market and sell our finished products to credit worthy customers, we may be subject to delays in the collection of our accounts receivable and exposure to additional credit risk. Such increased exposure could negatively impact our liquidity due to our increased working capital needs as a result of the increase in the amount of crude oil inventory and accounts receivable we would have to carry on our balance sheet. Our long-term needs for cash include those to repay our indebtedness and other contractual obligations, support ongoing capital expenditures for equipment maintenance and upgrades, including during turnarounds at our refineries, and to complete our routine and normally scheduled maintenance, regulatory and security expenditures.
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In addition, from time to time, we are required to spend significant amounts for repairs when one or more processing units experiences temporary shutdowns. We continue to utilize significant capital to upgrade equipment, improve facilities, and reduce operational, safety and environmental risks. In connection with the Paulsboro and Torrance acquisitions, we assumed certain significant environmental obligations, and may similarly do so in future acquisitions. We will likely incur substantial compliance costs in connection with new or changing environmental, health and safety regulations. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Our liquidity and financial condition will affect our ability to satisfy any and all of these needs or obligations.
We may not be able to obtain funding on acceptable terms or at all because of volatility and uncertainty in the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.
In the past, global financial markets and economic conditions have been, and may again be, subject to disruption and volatile due to a variety of factors, including uncertainty in the financial services sector, low consumer confidence, falling commodity prices, geopolitical issues and generally weak economic conditions. In addition, the fixed income markets have experienced periods of extreme volatility that have negatively impacted market liquidity conditions, including as a result of the impact of the COVID-19 pandemic. As a result, the cost of raising money in the debt and equity capital markets has increased substantially at times while the availability of funds from those markets diminished significantly. In particular, as a result of concerns about the stability of financial markets generally, which may be subject to unforeseen disruptions, the cost of obtaining money from the credit markets may increase as many lenders and institutional investors increase interest rates, enact tighter lending standards, refuse to refinance existing debt on similar terms or at all and reduce or, in some cases, cease to provide funding to borrowers. Due to these factors, we cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due.
Our results of operations continue to be impacted by significant costs to comply with renewable fuels mandates. The market prices for RINs have been volatile and may harm our profitability.
Pursuant to the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007, EPA has issued the Renewable Fuel Standard, implementing mandates to blend renewable fuels into the petroleum fuels produced and sold in the United States. Under the Renewable Fuel Standard, the volume of renewable fuels that obligated refineries must blend into their finished petroleum fuels increases annually over time until 2022. In addition, certain states have passed legislation that requires minimum biodiesel blending in finished distillates. On October 13, 2010, EPA raised the maximum amount of ethanol allowed under federal law from 10% to 15% for cars and light trucks manufactured since 2007. The maximum amount allowed under federal law currently remains at 10% ethanol for all other vehicles. Existing laws and regulations could change, and the minimum volumes of renewable fuels that must be blended with refined petroleum fuels may increase. Because we do not produce renewable fuels, increasing the volume of renewable fuels that must be blended into our products displaces an increasing volume of our refinery’s product pool, potentially resulting in lower earnings and profitability. In addition, in order to meet certain of these and future EPA requirements, we may be required to purchase RINs, which may have fluctuating costs based on market conditions. The price of RINS has increased in 2020 and could increase further in 2021. We incurred approximately $326.4 million in RINs costs during the year ended December 31, 2020 as compared to $122.7 million and $143.9 million during the years ended December 31, 2019 and 2018, respectively. The fluctuations in our RINs costs are due primarily to volatility in prices for ethanol-linked RINs and increases in our production of on-road transportation fuels since 2012. Our RINs purchase obligation is dependent on our actual shipment of on-road transportation fuels domestically and the amount of blending achieved which can cause variability in our profitability.
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Competition from companies who have not been adversely impacted as much as we have been by the COVID-19 pandemic, produce their own supply of feedstocks, have extensive retail outlets, make alternative fuels or have greater financial and other resources than we do could materially and adversely affect our business and results of operations.
Our refining operations compete with domestic refiners and marketers in regions of the United States in which we operate, as well as with domestic refiners in other regions and foreign refiners that import products into the United States. In addition, we compete with other refiners, producers and marketers in other industries that supply their own renewable fuels or alternative forms of energy and fuels to satisfy the requirements of our industrial, commercial and individual consumers. Many of our competitors have not been adversely impacted by the COVID-19 pandemic as much as we have been impacted. Certain of our competitors have larger and more complex refineries, and may be able to realize lower per-barrel costs or higher margins per barrel of throughput. Several of our principal competitors are integrated national or international oil companies that are larger and have substantially greater resources than we do and access to proprietary sources of controlled crude oil production. Unlike these competitors, we obtain substantially all of our feedstocks from unaffiliated sources. We are not engaged in the petroleum exploration and production business and therefore do not produce any of our crude oil feedstocks. We do not have a retail business and therefore are dependent upon others for outlets for our refined products. Because of their integrated operations and larger capitalization, these companies may be more flexible in responding to volatile industry or market conditions, such as shortages of crude oil supply and other feedstocks or intense price fluctuations and they may also be able to obtain more favorable trade credit terms.
Newer or upgraded refineries will often be more efficient than our refineries, which may put us at a competitive disadvantage. We have taken significant measures to maintain our refineries including the installation of new equipment and redesigning older equipment to improve our operations. However, these actions involve significant uncertainties, since upgraded equipment may not perform at expected throughput levels, the yield and product quality of new equipment may differ from design specifications and modifications may be needed to correct equipment that does not perform as expected. Any of these risks associated with new equipment, redesigned older equipment or repaired equipment could lead to lower revenues or higher costs or otherwise have an adverse effect on future results of operations and financial condition. Over time, our refineries or certain refinery units may become obsolete, or be unable to compete, because of the construction of new, more efficient facilities by our competitors.
A portion of our workforce is unionized, and we may face labor disruptions that would interfere with our operations.
Most hourly employees at our refineries are covered by collective bargaining agreements through the USW, the IOW and the IBEW. These agreements are scheduled to expire on various dates in 2021 and 2022 (See “Item 1. Business” - Employees). Future negotiations prior to the expiration of our collective agreements may result in labor unrest for which a strike or work stoppage is possible. Strikes and/or work stoppages could negatively affect our operational and financial results and may increase operating expenses at the refineries.
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Any political instability, military strikes, sustained military campaigns, terrorist activity, changes in foreign policy, or other catastrophic events could have a material adverse effect on our business, results of operations and financial condition.
Any political instability, military strikes, sustained military campaigns, terrorist activity, changes in foreign policy in areas or regions of the world where we acquire crude oil and other raw materials or sell our refined petroleum products may affect our business in unpredictable ways, including forcing us to increase security measures and causing disruptions of supplies and distribution markets. We may also be subject to United States trade and economic sanctions laws, which change frequently as a result of foreign policy developments, and which may necessitate changes to our crude oil acquisition activities. Further, like other industrial companies, our facilities may be the target of terrorist activities or subject to catastrophic events such as natural disasters and pandemic illness. Any act of war, terrorism, or other catastrophic events that resulted in damage to, or otherwise disrupts the operating activities of, any of our refineries or third-party facilities upon which we are dependent for our business operations could have a material adverse effect on our business, results of operations and financial condition.
We must make substantial capital expenditures on our operating facilities to maintain their reliability and efficiency. If we are unable to complete capital projects at their expected costs and/or in a timely manner, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations or cash flows could be materially and adversely affected.
Delays or cost increases related to capital spending programs involving engineering, procurement and construction of new facilities (or improvements and repairs to our existing facilities and equipment, including turnarounds) could adversely affect our ability to achieve targeted internal rates of return and operating results. Such delays or cost increases may arise as a result of unpredictable factors in the marketplace, many of which are beyond our control, including:
•denial or delay in obtaining regulatory approvals and/or permits;
•unplanned increases in the cost of construction materials or labor;
•disruptions in transportation of modular components and/or construction materials;
•severe adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors and suppliers;
•shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
•market-related increases in a project’s debt or equity financing costs; and/or
•non-performance or force majeure by, or disputes with, vendors, suppliers, contractors or sub-contractors involved with a project.
Our refineries contain many processing units, a number of which have been in operation for many years. Equipment, even if properly maintained, may require significant capital expenditures and expenses to keep it operating at optimum efficiency. One or more of the units may require unscheduled downtime for unanticipated maintenance or repairs that are more frequent than our scheduled turnarounds for such units. Scheduled and unscheduled maintenance could reduce our revenues during the period of time that the units are not operating.
Our forecasted internal rates of return are also based upon our projections of future market fundamentals, which are not within our control, including changes in general economic conditions, impact of new regulations, available alternative supply and customer demand. Any one or more of these factors could have a significant impact on our business. If we were unable to make up the delays associated with such factors or to recover the related costs, or if market conditions change, it could materially and adversely affect our financial position, results of operations or cash flows.
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Our business may suffer if any of our senior executives or other key employees discontinues employment with us. Furthermore, a shortage of skilled labor or disruptions in our labor force may make it difficult for us to maintain labor productivity.
Our future success depends to a large extent on the services of our senior executives and other key employees. Our business depends on our continuing ability to recruit, train and retain highly qualified employees in all areas of our operations, including engineering, accounting, business operations, finance and other key back-office and mid-office personnel. Furthermore, our operations require skilled and experienced employees with proficiency in multiple tasks. The competition for these employees is intense, and the loss of these executives or employees could harm our business. If any of these executives or other key personnel resigns or becomes unable to continue in his or her present role and is not adequately replaced, our business operations could be materially adversely affected.
Our commodity derivative activities could result in period-to-period earnings volatility.
We do not currently apply hedge accounting to any of our commodity derivative contracts and, as a result, unrealized gains and losses will be charged to our earnings based on the increase or decrease in the market value of such unsettled positions. These gains and losses may be reflected in our income statement in periods that differ from when the settlement of the underlying hedged items are reflected in our income statement. Such derivative gains or losses in earnings may produce significant period-to-period earnings volatility that is not necessarily reflective of our underlying operational performance.
We may incur significant liability under, or costs and capital expenditures to comply with, environmental and health and safety regulations, which are complex and change frequently.
Our operations are subject to federal, state and local laws regulating, among other things, the use and/or handling of petroleum and other regulated materials, the emission and discharge of materials into the environment, waste management, and remediation of discharges of petroleum and petroleum products, characteristics and composition of gasoline and distillates and other matters otherwise relating to the protection of the environment and the health and safety of the surrounding community. Our operations are also subject to extensive laws and regulations relating to occupational health and safety.
We cannot predict what additional environmental, health and safety legislation or regulations may be adopted in the future, or how existing or future laws or regulations may be administered or interpreted with respect to our operations. Many of these laws and regulations have become increasingly stringent over time, and the cost of compliance with these requirements can be expected to increase over time.
Certain environmental laws impose strict, and in certain circumstances, joint and several, liability for costs of investigation and cleanup of spills, discharges or releases on owners and operators of, as well as persons who arrange for treatment or disposal of regulated materials at, contaminated sites. Under these laws, we may incur liability or be required to pay penalties for past contamination, and third parties may assert claims against us for damages allegedly arising out of any past or future contamination. The potential penalties and clean-up costs for past or future spills, discharges or releases, the failure of prior owners of our facilities to complete their clean-up obligations, the liability to third parties for damage to their property, or the need to address newly-discovered information or conditions that may require a response could be significant, and the payment of these amounts could have a material adverse effect on our business, financial condition, cash flows and results of operations.
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Environmental clean-up and remediation costs of our sites and environmental litigation could decrease our net cash flow, reduce our results of operations and impair our financial condition.
We are subject to liability for the investigation and clean-up of environmental contamination at each of the properties that we own or operate and at off-site locations where we arrange for the treatment or disposal of regulated materials. We may become involved in litigation or other proceedings related to the foregoing. If we were to be held responsible for damages in any such litigation or proceedings, such costs may not be covered by insurance and may be material. Historical soil and groundwater contamination has been identified at our refineries. Currently, remediation projects for such contamination are underway in accordance with regulatory requirements at our refineries. In connection with the acquisitions of certain of our refineries and logistics assets, the prior owners have retained certain liabilities or indemnified us for certain liabilities, including those relating to pre-acquisition soil and groundwater conditions, and in some instances we have assumed certain liabilities and environmental obligations, including certain existing and potential remediation obligations. If the prior owners fail to satisfy their obligations for any reason, or if significant liabilities arise in the areas in which we assumed liability, we may become responsible for remediation expenses and other environmental liabilities, which could have a material adverse effect on our business, financial condition, results of operations and cash flow. As a result, in addition to making capital expenditures or incurring other costs to comply with environmental laws, we also may be liable for significant environmental litigation or for investigation and remediation costs and other liabilities arising from the ownership or operation of these assets by prior owners, which could materially adversely affect our business, financial condition, results of operations and cash flow. See “Item 1. Business—Environmental, Health and Safety Matters” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contractual Obligations and Commitments”.
We may also face liability arising from current or future claims alleging personal injury or property damage due to exposure to chemicals or other regulated materials, such as various perfluorinated compounds, including perfluorooctanoate, perfluorooctane sulfonate, perfluorohexane sulfonate, or other per-and polyfluoroalkyl substances, asbestos, benzene, silica dust and petroleum hydrocarbons, at or from our facilities. We may also face liability for personal injury, property damage, natural resource damage or clean-up costs for the alleged migration of contamination from our properties. A significant increase in the number or success of these claims could materially adversely affect our business, financial condition, results of operations and cash flow.
Product liability and operational liability claims and litigation could adversely affect our business and results of operations.
Product liability and liability arising from our operations are significant risks. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers of petroleum products based upon claims for injuries and property damage caused by the use of or exposure to various products. Failure of our products to meet required specifications or claims that a product is inherently defective could result in product liability claims from our shippers and customers, and also arise from contaminated or off-specification product in commingled pipelines and storage tanks and/or defective fuels. We may also be subject to personal injury claims arising from incidents that occur in connection with or relating to our operations. Product liability and personal injury claims against us could have a material adverse effect on our business, financial condition or results of operations.
Potential further laws and regulations related to climate change could have a material adverse impact on our operations and adversely affect our facilities.
Some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. We believe the issue of climate change will likely continue to receive scientific and political attention, with the potential for further laws and regulations that could materially adversely affect our ongoing operations.
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In addition, as many of our facilities are located near coastal areas, rising sea levels may disrupt our ability to operate those facilities or transport crude oil and refined petroleum products. Extended periods of such disruption could have an adverse effect on our results of operation. We could also incur substantial costs to protect or repair these facilities.
Our pipelines are subject to federal and/or state regulations, which could reduce profitability and the amount of cash we generate.
Our transportation activities are subject to regulation by multiple governmental agencies. The regulatory burden on the industry increases the cost of doing business and affects profitability. Additional proposals and proceedings that affect the oil industry are regularly considered by Congress, the states, the FERC, the United States Department of Transportation, and the courts. We cannot predict when or whether any such proposals may become effective or what impact such proposals may have. Projected operating costs related to our pipelines reflect the recurring costs resulting from compliance with these regulations, and these costs may increase due to future acquisitions, changes in regulation, changes in use, or discovery of existing but unknown compliance issues.
We are subject to strict laws and regulations regarding employee and process safety, and failure to comply with these laws and regulations could have a material adverse effect on our results of operations, financial condition and profitability.
We are subject to the requirements of the OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, OSHA requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees, state and local governmental authorities, and local residents. Failure to comply with OSHA requirements, including general industry standards, process safety standards and control of occupational exposure to regulated substances, could result in claims against us that could have a material adverse effect on our results of operations, financial condition and the cash flows of the business if we are subjected to significant fines or compliance costs.
Compliance with and changes in tax laws could adversely affect our performance.
We are subject to extensive tax liabilities, including federal, state, local and foreign taxes such as income, excise, sales/use, payroll, franchise, property, gross receipts, withholding and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future. These liabilities are subject to periodic audits by the respective taxing authorities, which could increase our tax liabilities. Subsequent changes to our tax liabilities as a result of these audits may also subject us to interest and penalties. There can be no certainty that our federal, state, local or foreign taxes could be passed on to our customers.
Changes in our credit profile could adversely affect our business.
Changes in our credit profile could affect the way crude oil and other suppliers view our ability to make payments and induce them to shorten the payment terms for our purchases or require us to post security or letters of credit prior to payment. Due to the large dollar amounts and volume of our crude oil and other feedstock purchases, any imposition by these suppliers of more burdensome payment terms on us may have a material adverse effect on our liquidity and our ability to make payments to our suppliers. This, in turn, could cause us to be unable to operate one or more of our refineries at full capacity.
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We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with health, safety, environmental and other laws and regulations.
Our operations require numerous permits and authorizations under various laws and regulations. These authorizations and permits are subject to revocation, renewal or modification and can require operational changes to limit impacts or potential impacts on the environment and/or health and safety. A violation of authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions, and/or facility shutdowns. In addition, major modifications of our operations could require modifications to our existing permits or upgrades to our existing pollution control equipment. Any or all of these matters could have a negative effect on our business, results of operations and cash flows.
We may incur significant liabilities under, or costs and capital expenditures to comply with, health, safety, environmental and other laws and regulations, which are complex and change frequently. Our operations are subject to federal, state and local laws regulating, among other things, the handling of petroleum and other regulated materials, the emission and discharge of materials into the environment, waste management, and remediation of discharges of petroleum and petroleum products, characteristics and composition of gasoline and distillates and other matters otherwise relating to the protection of the environment. Our operations are also subject to extensive laws and regulations relating to occupational health and safety, in addition to laws and regulations affecting the transportation of crude oil by rail in North America.
We cannot predict what additional environmental, health and safety legislation or regulations may be adopted in the future, or how existing or future laws or regulations may be administered or interpreted with respect to our operations. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time.
Certain environmental laws impose strict, and in certain circumstances joint and several liability for, costs of investigation and cleanup of such spills, discharges or releases on owners and operators of, as well as persons who arrange for treatment or disposal of regulated materials at contaminated sites. Under these laws, we may incur liability or be required to pay penalties for past contamination, and third parties may assert claims against us for damages allegedly arising out of any past or future contamination. The potential penalties and clean-up costs for past or future releases or spills, the failure of prior owners of our facilities to complete their clean-up obligations, the liability to third parties for damage to their property, or the need to address newly-discovered information or conditions that may require a response could be significant, and the payment of these amounts could have a material adverse effect on our business, financial condition and results of operations.
Risks Related to Our Indebtedness
Our substantial indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under our indebtedness.
Our indebtedness may significantly affect our financial flexibility in the future. As of December 31, 2017,2020, we have total debt including our Note payable, of $1,668.0$3,985.5 million, excluding unamortized deferred debt issuance costs of $25.2$45.3 million, and we could incur an additional $869.0 millionborrowings under our credit facilities.Revolving Credit Facility. As disclosed in this Annual Report on Form 10-K, on May 13, 2020, we issued $1.0 billion in aggregate principal amount of 9.25% senior secured notes due 2025 (the “initial 2025 Senior Secured Notes”), and on December 21, 2020, we issued $250.0 million in aggregate principal amount of 9.25% senior secured notes due 2025 (the “additional 2025 Senior Secured Notes” and together with the initial 2025 Senior Secured Notes, the 2025 Senior Secured Notes), and on January 24, 2020, we issued $1.0 billion of the 2028 Senior Notes, the proceeds of which were used primarily to fully redeem the 7.00% senior notes due 2023 (the “2023 Senior Notes”) and to fund a portion of the cash consideration for the Martinez Acquisition. Additionally, during the year ended December 31, 2020, we used advances under our Revolving Credit Facility to fund a portion of the Martinez Acquisition and for other general corporate purposes. The amounts set forth above do not include any post-closing payments in connection with the Martinez Acquisition to the seller if certain conditions are met, including earn-out payments based on certain earnings thresholds of the Martinez refinery (as set forth in the sale and purchase agreement,
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for a period of up to four years following the closing date). We may incur additional indebtedness in the future. Our strategy includes executing future refineryincluding additional secured indebtedness, subject to the satisfaction of any debt incurrence and, logistics acquisitions. Any significant acquisition would likely require usif applicable, lien incurrence limitation covenants in our existing financing agreements. Although we were in compliance with incurrence covenants during the year ended December 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 additional indebtedness in ordernew debt ( including secured debt) and also may limit the extent to finance allwhich we may make new investments or a portion of such acquisition. incur new liens.
The level of our indebtedness has several important consequences for our future operations, including that:
•a portion of our cash flow from operations will be dedicated to the payment of principal of, and interest on, our indebtedness and will not be available for other purposes;
•under certain circumstances, covenants contained in our existing debt arrangements limit our ability to borrow additional funds, dispose of assets and make certain investments;
•in certain circumstances these covenants also require us to meet or maintain certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our industry, such as being able to take advantage of acquisition opportunities when they arise;
•our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited; and
•we may be at a competitive disadvantage to those of our competitors that are less leveraged; and we may be more vulnerable to adverse economic and industry conditions.
Our indebtedness increases the risk that we may default on our debt obligations, certain of which contain cross-default and/or cross-acceleration provisions. Our, and our subsidiaries’, ability to meet future principal obligations will be dependent upon our future performance, which in turn will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our business may not continue to generate sufficient cash flow from operations to repay our indebtedness. If we are unable to generate sufficient cash flow from operations, we may be required to sell assets, to refinance all or a portion of our indebtedness or to obtain additional financing. Refinancing may not be possible and additional financing may not be available on commercially acceptable terms, or at all.
Despite our substantial level of indebtedness, we and our subsidiaries may be able to incur substantially more debt, which could exacerbate the risks described above.
We and our subsidiaries may be able to incur additional indebtedness in the future including additional secured or unsecured debt. Although our debt instruments and financing arrangements contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions, and the indebtedness incurred in compliance with these restrictions could be substantial. To the extent new debt
is added to our currently anticipatedcurrent debt levels, the leverage risks described above would increase. Also, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness.
Our future credit ratings could adversely affect the cost of our borrowing as well as our ability to obtain credit in the future.
On January 24, 2020, we issued the 2028 Senior Notes. The proceeds from this offering were used in part to subsequently redeem our outstanding 2023 Senior Notes. In response to the impact of COVID-19 on our financial condition and business, to strengthen our liquidity, on May 13, 2020, we issued the initial 2025 Senior Secured Notes and then, on December 21, 2020, we issued the additional 2025 Senior Secured Notes in a tack-on offering. 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. 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 a result of the downgrades, the
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cost of borrowings under our Revolving Credit Facility increased in accordance with the agreement governing the Revolving Credit Facility (the “Revolving Credit Agreement”). If the current market conditions persist or deteriorate, we expect that the credit rating agencies will continue to re-evaluate our corporate credit rating and the ratings of our unsecured and secured notes. Adverse changes in our credit ratings may also negatively impact the terms of credit we receive from our suppliers and require us to prepay or post collateral. Further adverse actions taken by the rating agencies on our corporate credit rating or the rating of our notes may further increase our cost of borrowings or hinder our ability to raise financing in the capital markets or have an unfavorable impact on the credit terms we have with our suppliers, which could impair our ability to grow our business, increase our liquidity and make cash distributions to our members.
Provisions in our indentures and other agreements could discourage an acquisition of us by a third-party.
Certain provisions of our indentures could make it more difficult or more expensive for a third-party to acquire us. Upon the occurrence of certain transactions constituting a “change of control” as described in the indentures governing the 2025 Senior Notes, the 2025 Senior Secured Notes and the 2028 Senior Notes, holders of our notes could require us to repurchase all outstanding notes at 101% of the principal amount thereof, plus accrued and unpaid interest, if any, at the date of repurchase. Certain other significant agreements of ours such as our Revolving Credit Agreement and Intermediation Agreements with J. Aron also contain provisions related to a change in control that could make it more difficult or expensive for a third-party to acquire us.
Restrictive covenants in our debt instruments, including the indentures governing our notes, may limit our ability to undertake certain types of transactions.transactions, which could adversely affect our business, financial condition, results of operations and our ability to service our indebtedness.
Various covenants in our current and future debt instruments and other financing arrangements, including the indentures governing our notes, may restrict our and our subsidiaries’ financial flexibility in a number of ways. Our current indebtedness subjectsand the indentures that govern our notes subject us to significant financial and other restrictive covenants, including restrictions on our ability to incur additional indebtedness, place liens upon assets, pay dividends or make certain other restricted payments and investments, consummate certain asset sales or asset swaps, conduct businesses other than our current businesses, or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of our assets. Some of theseour debt instruments also require our subsidiaries to satisfy or maintain certain financial condition tests in certain circumstances. Our subsidiaries’ ability to meet these financial condition tests can be affected by events beyond our control and theywe may not meet such tests.
If we incur indebtedness provided or guaranteed by the U.S. Government, including pursuant to the Coronavirus Aid, Relief and Economic Security Act, signed into law on March 27, 2020, we may become subject to additional restrictions on our operations, including limitations on employee headcount and compensation reductions and other cost reduction activities that could adversely affect us.
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The discontinuation of LIBOR, and the adoption of an alternative reference rate, may have a material adverse impact on our floating rate indebtedness and financing costs.
We are subject to interest rate risk on floating interest rate borrowings under our Revolving Credit Facility and our $35.0 million term loan (the “PBF Rail Term Loan”). These borrowings have the optionality to use LIBOR as a benchmark for establishing the interest rate. On November 30, 2020, the ICE Benchmark Administration (“IBA”) announced that it intends to continue publishing LIBOR until the end of June 2023, beyond the previously announced 2021 cessation date. The IBA announcement was supported by announcements from the United Kingdom’s Financial Conduct Authority (“FCA”), which regulates LIBOR, and the Board of Governors of the Federal Reserve System, Federal Deposit Insurance Corporation and Office of the Comptroller of the Currency (the “U.S. Regulators”). However, both the FCA and U.S. Regulators in their announcements also advised banks to cease entering into new contracts referencing LIBOR after December 2021. These announcements indicate that the continuation of LIBOR on the current basis may not be assured after 2021 and will not be assured beyond 2023. In light of these recent announcements, the future of LIBOR at this time is uncertain and any changes in the future.methods by which LIBOR is determined, or regulatory activity related to LIBOR’s phaseout, could cause LIBOR to perform differently than in the past or cease to exist.
Risks Related to Our Organizational Structure
Under a tax receivable agreement, PBF Energy is required to pay the pre-IPO owners of PBF LLC for certain realized or assumed tax benefits it may claim arising in connection with its initial public offering and future exchanges of PBF LLC Series A Units for shares of its Class A common stock and related transactions (the “Tax Receivable Agreement”). The indentureindentures governing the senior notes allowsallow us, under certain circumstances, to make distributions sufficient for PBF Energy to pay its obligations arising from the Tax Receivable Agreement, and such amounts are expected to be substantial.Agreement.
PBF Energy entered into a Tax Receivable Agreement that provides for the payment from time to time (“On-Going Payments”) by PBF Energy to the holders of PBF LLC Series A Units and PBF LLC Series B Units for certain tax benefits it may claim arising in connection with its prior offerings and future exchanges of PBF LLC Series A Units for shares of its Class A Common Stockcommon stock and related transactions, and the amounts it may pay could be significant.
PBF Energy’s payment obligations under the Tax Receivable Agreement are PBF Energy’s obligations and not obligations of PBF Holding, PBF Finance, or any of PBF Holding’s other subsidiaries. However, because PBF Energy is primarily a holding company with limited operations of its own, its ability to make payments under the Tax Receivable Agreement is dependent on our ability to make future distributions to it. The indentures governing the Senior Notessenior notes allow us to make tax distributions (as defined in the indenture)applicable indentures), and it is expected that PBF Energy’s share of these tax distributions will be in amounts sufficient to allow PBF Energy to make On-Going Payments. The indentures governing the Senior Notessenior notes also allow us to make a distribution sufficient to allow PBF Energy to make any payments required under the Tax Receivable Agreement upon a change in control, so long as we offer to purchase all of the Senior Notessenior notes outstanding at a price in cash equal to 101% of the aggregate principal amount thereof, plus accrued and unpaid interest thereon, if any. If PBF Energy’s share of the distributions it receives under these specific provisions of the indentures is insufficient to satisfy its obligations under the Tax
Receivable Agreement, PBF Energy may cause us to make distributions in accordance with other provisions of the indentures in order to satisfy such obligations. In any case, based on our estimates of PBF Energy’s obligations under the Tax Receivable Agreement, the amount of our distributions on account of PBF Energy’s obligations under the Tax Receivable Agreement are expected to be substantial.
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Our existing indebtedness may limit our ability to make distributions to PBF LLC, and in turn tofor PBF Energy to pay these obligations. These provisions may deter a potential sale of us to a third partythird-party and may otherwise make it less likely a third partythird-party would enter into a change of control transaction with PBF Energy or us.
Risks Related to Our Affiliation with PBFX
We depend upon PBFX for a substantial portion of our refineries’ logistics needs and have obligations for minimum volume commitments in our commercial agreements with PBFX.
We depend on PBFX to receive, handle, store and transfer crude oil, petroleum products and natural gas for us from our operations and sources located throughout the United States and Canada in support of certain of our refineries under long-term, fee-based commercial agreements with us. These commercial agreements have an initial term of approximately sevenranging from one to tenfifteen years and generally include minimum quarterly commitments and inflation escalators. If we fail to meet the minimum commitments during any calendar quarter, we will be required to make a shortfall payment quarterly to PBFX equal to the volume of the shortfall multiplied by the applicable fee.
PBFX’s operations are subject to all of the risks and operational hazards inherent in receiving, handling, storing and transferring crude oil, petroleum products and natural gas, including: damages to its facilities, related equipment and surrounding properties caused by floods, fires, severe weather, explosions and other natural disasters and acts of terrorism; mechanical or structural failures at PBFX’s facilities or at third-party facilities on which its operations are dependent; curtailments of operations relative to severe seasonal weather; inadvertent damage to our facilities from construction, farm and utility equipment; and other hazards. Any of these events or factors could result in severe damage or destruction to PBFX’s assets or the temporary or permanent shut-down of PBFX’s facilities. If PBFX is unable to serve our logistics needs, our ability to operate our refineries and receive crude oil and distribute products could be adversely impacted, which could adversely affect our business, financial condition and results of operations.
All of the executive officers and a majority of the directors of PBF GP are also current or former officers or directors of PBF Energy. Conflicts of interest could arise as a result of this arrangement.
PBF Energy indirectly owns and controls PBF GP, and appoints all of its officers and directors. All of the executive officers and a majority of the directors of PBF GP are also current or former officers or directors of PBF Energy. These individuals will devote significant time to the business of PBFX. Although the directors and officers of PBF GP have a fiduciary duty to manage PBF GP in a manner that is beneficial to PBF Energy, as directors and officers of PBF GP they also have certain duties to PBFX and its unit holders.unitholders. Conflicts of interest may arise between PBF Energy and its affiliates, including PBF GP, on the one hand, and PBFX and its unit holders,unitholders, on the other hand. In resolving these conflicts of interest, PBF GP may favor its own interests and the interests of PBFX over the interests of PBF Energy and its subsidiaries. In certain circumstances, PBF GP may refer any conflicts of interest or potential conflicts of interest between PBFX, on the one hand, and PBF Energy, on the other hand, to its conflicts committee (which must consist entirely of independent directors) for resolution, which conflicts committee must act in the best interests of the public unit holdersunitholders of PBFX. As a result, PBF GP may manage the business of PBFX in a way that may differ from the best interests of PBF Energy or us.its stockholders.
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ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
See “Item 1. Business”.
ITEM 3. LEGAL PROCEEDINGS
On December 28, 2016, DNREC issued the Ethanol Permit to DCR allowing the utilization of existing tanks and existing marine loading equipment at their existing facilities to enable denatured ethanol to be loaded from storage tanks to marine vessels and shipped to offsite facilities. On January 13, 2017, the issuance of the Ethanol Permit was appealed by two environmental groups. On February 27, 2017, the Coastal Zone Industrial Control Board (the “Coastal Zone Board”) held a public hearing and dismissed the appeal, determining that the appellants did not have standing. The appellants filed an appeal of the Coastal Zone Board’s decision with the Delaware Superior Court (the “Superior Court”) on March 30, 2017. On January 19, 2018, the Superior Court rendered an Opinion regarding the decision of the Coastal Zone Board to dismiss the appeal of the Ethanol Permit for the ethanol project. The judge determined that the record created by the Coastal Zone Board was insufficient for the Superior Court to make a decision, and therefore remanded the case back to the Coastal Zone Board to address the deficiency in the record. Specifically, the Superior Court directed the Coastal Zone Board to address any evidence concerning whether the appellants’ claimed injuries would be affected by the increased quantity of ethanol shipments. DuringOn remand, the Coastal Zone Board met on January 28, 2019 and reversed its previous decision on standing ruling that the appellants have standing to appeal the issuance of the Ethanol Permit. The parties to the action filed a joint motion with the Coastal Zone Board, requesting that the Board concur with the parties’ proposal to secure from the Superior Court confirmation that all rights and claims are preserved for any subsequent appeal to the Superior Court, and that the matter then be scheduled for a hearing on the merits before the Coastal Zone Board. The Coastal Zone Board on standing, onenotified the parties in January of 2020 that it concurred with the appellants’ witnesses madeparties’ proposed course of action. The appellants and DCR subsequently filed a referencemotion with the Superior Court requesting relief consistent with what was described to the flammabilityCoastal Zone Board. In March of ethanol, without any indication of2020, the significance of flammability/explosivitySuperior Court issued a letter relinquishing jurisdiction over the matter, and concurring with the parties’ proposal to specific concerns. Moreover,allow the appellants did not introduce atcase to proceed to a hearing any evidence ofon the relative flammability of ethanol as comparedmerits before the Coastal Zone Board. The parties must now jointly propose to other materials shipped to and from the refinery. However, the sole dissenting opinion from the Coastal Zone Board focuseda schedule for prehearing activity and a merits hearing to resolve the matter. The parties must, therefore, submit to the Coastal Zone Board a joint proposed schedule to govern future proceedings related to the merits hearing to resolve the matter.
On September 11, 2020, DCR received two Citations and Notification of Penalties, with sub-parts, from OSHA related to a combustion incident occurring on March 11, 2020. The citation seeks to impose penalties in the flammability/explosivity issue, alleging thatamount of $401,923 related to alleged violations of the appellants’ testimony raisedOccupation Safety and Health Act of 1970. An informal conference with OSHA on October 2, 2020 was unsuccessful in resolving the issuematter, and, as a distinct basis for potential harms. Once the Board responds to the remand, it will go back to the Superior Court to complete its analysis and issue a decision.
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In connection with the acquisition of the Torrance refinery and related logistics assets, we assumed certain pre-existing environmental liabilities related to certain environmental remediation obligations to address existing soil and groundwater contamination and monitoring activities, which reflect the estimated cost of the remediation obligations. In addition, in connection with the acquisition of the Torrance refinery and related logistics assets, we purchased a ten year, $100.0 million environmental insurance policy to insure against unknown environmental liabilities. Furthermore, in connection with the acquisition, we assumed responsibility for certain specified environmental matters that occurred prior to our ownership of the refinery and logistics assets, including specified incidents and/or NOVsNotices of Violations (“NOVs”) issued by regulatory agencies in various years before our ownership, including the SCAQMDSouth Coast Air Quality Management District (“SCAQMD”) and Cal/OSHA. Following the closingDivision of Occupational Safety and Health of the State of California (“Cal/OSHA”).
Subsequent to the acquisition, further NOVs were issued by the SCAQMD, Cal/OSHA, the City of Torrance, and the City of Torrance Fire Department, and the Los Angeles County Sanitation District related to alleged operational violations, emission discharges and/or flaring incidents at the refinery and the logistics assets both before and after our acquisition. In addition, subsequent toEPA in November 2016 conducted a Risk Management Plan (“RMP”) inspection following the acquisition EPA and the DTSC conducted inspections related to Torrance operations and issued preliminary findings related toin March 2017 concerning RMP potential operational violations. OnSince EPA’s issuance of the preliminary findings in March 1, 2018,2017, we recevedhave been in substantive discussions to resolve the preliminary findings. Effective January 9, 2020, we and EPA entered into a noticeConsent Agreement and Final Order (“CAFO”), effective as of intentJanuary 9, 2020, which contains no admission by us for any alleged violations in the CAFO, includes a release from all alleged violations in the CAFO, requires payment of a penalty of $125,000 and the implementation of a supplemental environmental project (“SEP”) of at least $219,000 that must be completed by December 15, 2021. The SEP will consist of configuring the northeast fire water monitor to sue from Environmental Integrity Project, on behalfautomatically deploy water upon detection of Environmenta release.
EPA and the California under theDepartment of Toxic Substances Control (“DTSC”) in December 2016 conducted a Resource Conservation and Recovery Act with respect(“RCRA”) inspection following the acquisition related to Torrance operations and also issued in March 2017 preliminary findings concerning RCRA potential operational violations. On June 14, 2018, the Torrance refinery and DTSC reached settlement regarding the oil bearing materials. Following this settlement, in June 2018, DTSC referred the remaining alleged RCRA violations from EPA’s and DTSC’s inspections. December 2016 inspection to the California Attorney General for final resolution. The Torrance refinery and the California Attorney General are in discussions to resolve these alleged remaining RCRA violations.
On March 2, 2018, DTSC issued an orderMay 8, 2020, we received a letter from the SCAQMD proposing to correct alleged violationssettle a NOV relating to Title V deviations alleged to have occurred in the accumulationfirst half of oil bearing materials. No2017 for $878,450. We have offered to settle the NOV for approximately $430,000 and are awaiting a response from the SCAQMD.
On February 4, 2021, we received a letter from the SCAQMD proposing to settle a NOV relating to Title V deviations alleged to have occurred in the second half of 2017 for $1.3 million. We are evaluating the allegations and will be communicating with the SCAQMD regarding the allegations and the settlement oroffer upon the completion of our review.
On November 30, 2020, the San Francisco Bay Regional Water Quality Control Board (“RWQCB”) issued a draft Stipulated Order to the Martinez refinery in connection with alleged total suspended solids exceedances that occurred in March 2020, which draft order included a proposed penalty demands have been receivedof $310,000. Subsequently, the RWQCB proposed to datesettle these alleged exceedances for $126,000. We are reviewing and will be communicating with respect to anythe RWQCB regarding the allegations and the revised settlement offer upon the completion of the NOVs, preliminary findings, or order that are in excess of $100,000. our review.
As the ultimate outcomes of the matters discussed above are uncertain, we cannot currently estimate the final amount or timing of their resolution. It is reasonably possible that SCAQMD, Cal/OSHA, the City of Torrance, EPA and/or DTSC will assess penalties in excess of $100,000,resolution but any such amount is not expected to have a material impact on our financial position, results of operations or cash flows, individually or in the aggregate.
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On December 5, 1990, prior to our ownership of the Chalmette refinery, the plaintiff in Adam Thomas, et al. v. Exxon Mobil Corporationand Chalmette Refining L.L.C., filed an action on behalf of himself and potentially thousands of other individuals in St. Bernard Parish and PlaqueminesOrleans Parish who were allegedly exposed to hydrogen sulfide and sulfur dioxide as a result of more than 100 separate flaring events that occurred between 1989 and 2007. This litigation is proceeding as a mass action with individually named2010. The plaintiffs as a result of a 2008 trial court decision, affirmed by the court of appeals, that denied class certification. The Plaintiffs claimclaimed to have suffered physical injuries, property damage, and other damages as a result of the releases. Plaintiffs seek to recover unspecified compensatory and punitive damages, interest, and costs. On June 18, 2020, plaintiffs and defendants entered into a settlement agreement and release, the terms and conditions of which are confidential. On that same date, the court entered a final judgment that dismissed with prejudice all claims asserted against defendants in this matter. The state trial court has scheduled a mini-trial of up to 10 plaintiffs in 2018, relating to 5 separate flaring events that occurred between 2002 and 2007. Because of the number of potential claimants is unknown and the differing events underlying the claims, the potential amount of the claims isoutcome did not determinable. It is possible that an adverse outcome may have a material adverse effectimpact on our financial position, results of operations or cash flows.
On February 17, 2017, in Arnold Goldstein, et al. v. Exxon Mobil Corporation, et al., we and PBF Energy, Company LLC, and our subsidiaries, PBF Energy Western Region LLC and Torrance Refining Company LLC and the manager of our Torrance refinery along with Exxon Mobil CorporationExxonMobil were named as defendants in a class action and representative action complaint filed on behalf of Arnold Goldstein, John Covas, Gisela Janette La Bella and others similarly situated. The complaint was filed in the Superior Court of the State of California, County of Los Angeles and alleges negligence, strict liability, ultrahazardous activity, a continuing private nuisance, a permanent private nuisance, a continuing public nuisance, a permanent public nuisance and trespass resulting from the February 18, 2015 electrostatic precipitator (“ESP”) explosion at the Torrance Refineryrefinery which was then owned and operated by Exxon.ExxonMobil. The operation of the Torrance Refineryrefinery by the PBF entities subsequent to our acquisition in July 2016 is also referenced in the complaint. To the extent that plaintiffs’ claims relate to the ESP explosion, ExxonExxonMobil retained responsibility for any liabilities that would arise from the lawsuit pursuant to the agreement relating to the acquisition of the Torrance refinery. On July 2, 2018, the court granted leave to plaintiffs’ to file a Second Amended Complaint alleging groundwater contamination. With the filing of the Second Amended Complaint, plaintiffs’ added an additional plaintiff, Hany Youssef. On March 18, 2019, the class certification hearing was held and the court took the matter under submission. On April 1, 2019, the court issued an order denying class certification. On April 15, 2019, plaintiffs filed a Petition for Permission to Appeal the Order Denying Motion for Class Certification. On May 3, 2019, plaintiffs filed a Motion with the Central District Court for Leave to File a Renewed Motion for Class Certification. On May 22, 2019, the judge granted plaintiffs’ motion. We filed our opposition to the motion on July 29, 2019. The plaintiffs’ motion was heard on September 23, 2019. On October 15, 2019, the judge granted certification to two limited classes of property owners with Youssef as the sole class representative and named plaintiff, rejecting two other proposed subclasses based on negligence and on strict liability for ultrahazardous activities. The certified subclasses relate to trespass claims for ground contamination and nuisance for air emissions. On February 5, 2021, our motion for Limited Extension of Discovery Cut-Off and a Motion by plaintiffs for Leave to File Third Amended Complaint were heard by the court. On February 9, 2021, the court issued an order taking both motions under submission pending additional discovery and briefing related to plaintiff Youssef and whether a new class representative should be substituted. The Court has also ordered that the rebuttal expert disclosure deadline, the expert discovery cut-off, the motion hearing cut-off, and all other case deadlines be stayed pending the court’s decision as to whether the case can proceed with a new class representative and whether defendants will be permitted to conduct additional soil vapor sampling in the ground subclass area. Trial was previously scheduled to commence on July 27, 2021. We presently believe the outcome will not have a material impact on our financial position, results of operations or cash flows.
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On September 18, 2018, in Michelle Kendig and Jim Kendig, et al. v. ExxonMobil Oil Corporation, et al., PBF Energy Limited and Torrance Refining along with ExxonMobil Oil Corporation and ExxonMobil Pipeline Company were named as defendants in a class action and representative action complaint filed on behalf of Michelle Kendig, Jim Kendig and others similarly situated. The complaint was filed in the Superior Court of the State of California, County of Los Angeles and alleged failure to authorize and permit uninterrupted rest and meal periods, failure to furnish accurate wage statements, violation of the Private Attorneys General Act and violation of the California Unfair Business and Competition Law. Plaintiffs sought unspecified economic damages, statutory damages, civil penalties provided by statute, disgorgement of profits, injunctive relief, declaratory relief, interest, attorney’s fees and costs. To the extent that plaintiffs’ claims accrued prior to July 1, 2016, ExxonMobil has retained responsibility for any liabilities that would arise from the lawsuit pursuant to the agreement relating to the acquisition of the Torrance Refinery. Thisrefinery and logistics assets. On October 26, 2018, the matter iswas removed to the Federal Court, California Central District. A mediation hearing between the parties was held on August 23, 2019, and the parties reached a tentative agreement in principle to settle. On March 17, 2019, plaintiffs filed with the court a Notice of Motion and Motion for Preliminary Approval of Settlement Agreement for the Court’s approval of the proposed settlement pursuant to which Torrance Refining would pay $2.9 million to resolve the matter and receive a full release and discharge from any and all claims and make no admission of any wrongdoing or liability. On May 1, 2020 the court entered an order preliminarily approving the proposed settlement. On August 6, 2020, the settlement of $2.9 million was paid to the class claims administrator. On August 17, 2020 the court granted approval of the final settlement.
On September 7, 2018, in Jeprece Roussell, et al. v. PBF Consultants, LLC, etal., the plaintiff filed an action in the initial stages19th Judicial District Court for the Parish of discoveryEast Baton Rouge, alleging numerous causes of action, including wrongful death, premises liability, negligence, and wegross negligence against PBF Holding, PBFX Op Co, Chalmette Refining, two individual employees of the Chalmette refinery (the “PBF Defendants”), two entities, PBF Consultants, LLC (“PBF Consultants”) and PBF Investments that are Louisiana companies that are not associated with our companies, as well as Clean Harbors, Inc. and Clean Harbors Environmental Services, Inc. (collectively, “Clean Harbors”), Mr. Roussell’s employer. Mr. Roussell was fatally injured on March 31, 2018 while employed by Clean Harbors and performing clay removal work activities inside a clay treating vessel located at the Chalmette refinery. Plaintiff seeks unspecified compensatory damages for pain and suffering, past and future mental anguish, impairment, past and future economic loss, attorney’s fees and court costs. On September 25, 2018, the PBF Defendants filed an answer in the state court action denying the allegations. On October 10, 2018, the PBF Defendants filed to remove the case to the United States District Court for the Middle District of Louisiana. On November 9, 2018, plaintiff filed a motion to remand the matter back to state court and the PBF Defendants filed a response on November 30, 2018. On April 15, 2019, the Federal Magistrate Judge filed a Report and Recommendation denying Plaintiff’s motion to remand and dismissing without prejudice the claims against John Sprafka, Wayne LaCombe, PBF Consultants and PBF Investments. On June 24, 2019, the Federal Judge adopted the Magistrate Judge’s Report and Recommendation denying plaintiff’s motion to remand and dismissing without prejudice the claims against John Sprafka, Wayne LaCombe, PBF Consultants and PBF Investments. On September 18, 2020, the Federal Magistrate Judge granted plaintiff’s motion to amend in order to add a non-diverse plaintiff and remand to state court. PBF Defendants filed an opposition to plaintiff’s motion to amend on October 2, 2020. On October 5, 2020, the Magistrate Judge granted plaintiff’s motion to amend and remanded the case back to state court. Discovery will continue in state court. We cannot currently estimate the amount or the timing of the resolution of this matter. The PBF Defendants previously issued a tender of defense and indemnity to Clean Harbors and its resolution.insurer pursuant to indemnity obligations contained in the associated services agreement. Clean Harbors has accepted the tender of defense and indemnity, and Clean Harbors’ insurer has accepted the tender of defense and indemnity subject to a reservation of rights. We presently believe the outcome will not have a material impact on our financial position, results of operations or cash flows.
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In Varga, Sabrina, et al., v. CRU Railcar Services, LLC, et al., we and other of our entities were named as defendants along with CRU Railcar Services, LLC (“CRU”) in a lawsuit arising from a railcar explosion that occurred while CRU employees were cleaning a railcar owned by us. The initial lawsuit alleged that an employee of CRU was fatally injured as a result of the explosion. On July 5, 2019, a petition for intervention was filed alleging that another CRU employee was fatally injured in the same explosion. On October 7, 2019, a third CRU employee joined the lawsuit alleging severe injuries from the incident. We have issued a tender of defense and indemnity to CRU and its insurer pursuant to indemnity obligations contained in the associated services agreement which have not been accepted at this time. Discovery is currently ongoing and the trial date is currently set for April 12, 2021. We cannot currently estimate the amount or the timing of the resolution of this matter. We presently believe the outcome will not have a material impact on our financial position, results of operations or cash flows.
We are subject to obligations to purchase RINs. On February 15, 2017, we received notification that EPA records indicated that PBF Holding used potentially invalid RINs that were in fact verified under the EPA’s RIN Quality Assurance Program (“QAP”) by an independent auditor as QAP A RINs. Under the regulations use of potentially invalid QAP A RINs provided the user with an affirmative defense from civil penalties provided certain conditions are met. We have asserted the affirmative defense and if accepted by the EPA will not be required to replace these RINs and will not be subject to civil penalties under the program. It is reasonably possible that the EPA will not accept our defense and may assess penalties in these matters but any such amount is not expected to have a material impact on our financial position, results of operations or cash flows.
ITEM 4. MINE SAFETY DISCLOSURE
None.
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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
We are a privately-owned company with no established public trading market for our membership units.
Holders
At December 31, 2017,2020, 100% of our outstanding membership interests waswere held by PBF LLC. PBF Finance had 100 shares of common stock outstanding, all of which were held by us. None of the membership interests are publicly traded,publicly-traded, and none were issued or sold in 2017.2020.
Dividend and Distribution Policy
We currently intendare a holding company and all of our operations are conducted through our subsidiaries. We have no independent means of generating revenue other than through assets owned by our subsidiaries. In order for us to make quarterlyany distributions, we will need to cause our subsidiaries to make distributions to us. We and our subsidiaries are generally prohibited under Delaware law from making a distribution to a member to the extent that, at the time of the distribution, after giving effect to the distribution, liabilities of the limited liability company (with certain exceptions) exceed the fair value of its assets. As a result, we may be unable to obtain cash from our subsidiaries to satisfy our obligations and make distributions to PBF LLC, when necessary.
We make, from time to time, cash distributions in amounts sufficient for PBF LLC to make tax distributions to its members and may make additional distributions to the extent necessary for PBF Energy to declare and pay a quarterly cash dividend of approximately $0.30 per share on its Class A common stock. The declaration, amount and payment of this and any other future distributions by us will be at the sole discretion of our board of directors and the board of directors of PBF Energy, which is the sole managing member of our sole member (PBF LLC), and we are not obligated under any applicable laws, governing documents or any contractual agreements with PBF LLC’s existing owners or otherwise to declare or pay any dividends or other distributions (other than the obligations of PBF LLC to make tax distributions to its members).
We paid $61.1$23.1 million in distributions to PBF LLC during the year ended December 31, 2017.2020. PBF LLC used $58.6$19.5 million of this amount to fund a portion of four separateone non-tax distributions of $0.30 per unit ($1.20 per unit in total) to its members totaling $36.3 million, of which $131.8$35.9 million was distributed to PBF Energy and the balance was distributed to PBF LLC’s other members. PBF Energy used this $131.8$35.9 million to pay four separateone equivalent
cash dividends of $0.30 per share of its Class A common stock on March 13, 2017, May 31, 2017, August 31, 2017 and November 29, 2017.17, 2020.
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| Year Ended December 31, | |||||||||||||||||||||
| 2017 | 2016 | 2015 | 2014 | 2013 | |||||||||||||||||
| Statement of operations data: | |||||||||||||||||||||
| Revenues | $ | 21,772,478 | $ | 15,908,537 | $ | 13,123,929 | $ | 19,828,155 | $ | 19,151,455 | |||||||||||
| Cost and expenses: | |||||||||||||||||||||
| Cost of products and other | 19,095,827 | 13,765,088 | 11,611,599 | 18,514,054 | 17,803,314 | ||||||||||||||||
| Operating expenses (excluding depreciation and amortization expense as reflected below) | 1,627,616 | 1,390,582 | 889,368 | 880,701 | 812,652 | ||||||||||||||||
| Depreciation and amortization expense | 254,271 | 204,005 | 181,422 | — | 165,413 | 98,622 | |||||||||||||||
| Cost of sales | 20,977,714 | 15,359,675 | 12,682,389 | 19,560,168 | 18,714,588 | ||||||||||||||||
General and administrative expenses (excluding depreciation and amortization expense as reflected below) (1) | 198,164 | 149,643 | 166,904 | 140,150 | 95,794 | ||||||||||||||||
| Depreciation and amortization expense | 12,964 | 5,835 | 9,688 | 13,583 | 12,857 | ||||||||||||||||
| Equity income in investee | (14,565 | ) | (5,679 | ) | — | — | — | ||||||||||||||
| Loss (gain) on sale of asset | 1,458 | 11,374 | (1,004 | ) | (895 | ) | (183 | ) | |||||||||||||
| Total cost and expenses | 21,175,735 | 15,520,848 | 12,857,977 | 19,713,006 | 18,823,056 | ||||||||||||||||
| Income from operations | 596,743 | 387,689 | 265,952 | 115,149 | 328,399 | ||||||||||||||||
| Other income (expense): | |||||||||||||||||||||
| Change in fair value of catalyst leases | (2,247 | ) | 1,422 | 10,184 | 3,969 | 4,691 | |||||||||||||||
| Debt extinguishment costs | (25,451 | ) | — | — | — | — | |||||||||||||||
| Interest expense, net | (122,628 | ) | (129,536 | ) | (88,194 | ) | (98,001 | ) | (94,214 | ) | |||||||||||
| Income before income taxes | 446,417 | 259,575 | 187,942 | 21,117 | 238,876 | ||||||||||||||||
| Income tax (benefit) expense | (10,783 | ) | 23,689 | 648 | — | — | |||||||||||||||
| Net Income | 457,200 | 235,886 | 187,294 | 21,117 | 238,876 | ||||||||||||||||
| Less: net income attributable to noncontrolling interest | 95 | 269 | 274 | — | — | ||||||||||||||||
| Net income attributable to PBF Holding Company LLC | $ | 457,105 | $ | 235,617 | $ | 187,020 | $ | 21,117 | $ | 238,876 | |||||||||||
| Balance sheet data (at end of period) : | |||||||||||||||||||||
| Total assets | $ | 7,506,178 | $ | 6,566,897 | $ | 5,082,722 | $ | 4,013,762 | $ | 4,192,504 | |||||||||||
Total debt (2) | 1,668,035 | 1,601,836 | 1,272,937 | 750,349 | 747,576 | ||||||||||||||||
| Total equity | 3,184,102 | 2,588,933 | 1,821,284 | 1,630,516 | 1,772,153 | ||||||||||||||||
| Other financial data : | |||||||||||||||||||||
Capital expenditures (3) | $ | 642,913 | $ | 1,498,191 | $ | 979,481 | $ | 625,403 | $ | 415,702 | |||||||||||
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following review of our results of operations and financial condition should be read in conjunction with Items 1, 1A,“Item 1. Business”, “Item 1A. Risk Factors”, “Item 2. Properties”, and 2, “Business, Risk Factors, and Properties,” Item 6, “Selected“Item 8. Financial Data,” and Item 8, “Financial Statements and Supplementary Data,”Data”, respectively, included in this Annual Report on Form 10-K.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains certain “forward-looking statements” of expected future developments that involve riskrisks and uncertainties. You can identify forward-looking statements because they contain words such as “believes,” “expects,” “may,” “should,” “seeks,” “approximately,” “intends,” “plans,” “estimates,” “anticipates” or similar expressions that relate to our strategy, plans or intentions. All statements we make relating to our estimated and projected earnings, margins, costs, expenditures, cash flows, growth rates and financial results or to our strategies, objectives, intentions, resources and expectations regarding future industry trends are forward-looking statements. In addition, we, through our senior management, from time to time make forward-looking public statements concerning our expected future operations and performance and other developments. These forward-looking statements are subject to risks and uncertainties that may change at any time, and, therefore, our actual results may differ materially from those that we expected. We derive many of our forward-looking statements from our operating budgets and forecasts, which are based 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 indebtedness;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;
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•termination of our A&RInventory Intermediation Agreements with J. 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 from J. Aron certain intermediates and finished productsJ. Aron Products located at the Paulsboro and Delaware City refineries’ storage tanksour J. Aron Storage Tanks upon termination of these agreements;
•restrictive covenants in our indebtedness that may adversely affect our operational flexibility or ability to make distributions;
•our assumptions regarding payments arising under PBF Energy’s Tax Receivable Agreement and other arrangements relating to PBF Energy;
•our expectations and timing with respect to our acquisition activity;
•our expectations with respect to our capital improvement and turnaround projects;
•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 impact of the newly enacted federal income tax legislation on our business;
commitments;
•adverse impacts related to legislation by the federal government lifting the restrictions on exporting U.S. crude oil;
•adverse impacts from changes in our regulatory environment, such as the effects of compliance with the California Global Warming Solutions Act (also referred to as “AB32”),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 StandardsStandard and GHG emission credits required to comply with various GHG emission programs, such as AB32;
•our ability to successfully integrate recently completedcomplete the successful integration of the Martinez refinery and any other acquisitions into our business and to realize the benefits from such acquisitions;
•unforeseen liabilities arising from recent acquisitions that are unforeseen or exceed our expectations;associated with the Martinez Acquisition and any other acquisitions; and
•any decisions we continue to make with respect to our energy-related logisticallogistics assets that may be transferred to PBFX.
We caution you that the foregoing list of important factors may not contain all of the material factors that are important to you. In addition, in light of these risks and uncertainties, the matters referred to in the forward-looking statements contained in this Annual Report on Form 10-K may not in fact occur. Accordingly, investors should not place undue reliance on those statements.
Our forward-looking statements speak only as of the date of this Annual Report on Form 10-K. Except as required by applicable law, including the securities laws of the United States, we do not intend to update or revise any forward-looking statements. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the foregoing.
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Executive Summary
We were formed in March 2008 to pursue the acquisitions of crude oil refineries and downstream assets in North America. We currently own and operate fivesix domestic oil refineries and related assets located in Toledo, Ohio, Delaware City, Delaware, Paulsboro, New Jersey, New Orleans,Toledo, Ohio, Chalmette, Louisiana, Torrance, California and Torrance,Martinez, California. OurBased on current configuration (subsequent to the East Coast Refining Reconfiguration), our refineries have a combined processing capacity, known as throughput of approximately 900,0001,000,000 bpd, and a weighted averageweighted-average Nelson Complexity Index of 12.2.13.2 based on current operating conditions. The complexity and throughput capacity of our refineries are subject to change dependent upon configuration changes we make to respond to market conditions as well as a result of investments made to improve our facilities and maintain compliance with environmental and governmental regulations. Our fivesix oil refineries are all engaged in the refining of crude oil and other feedstocks into petroleum products, and are aggregated into one reportable segment.
Factors Affecting Comparability
Our results over the past three years have been affected by the following events, the understanding of which will aid in assessing the comparability of our period to period financial performance and financial condition.
COVID-19 and Market Developments
The impact of the unprecedented global health and economic crisis sparked by the COVID-19 pandemic was amplified late in the quarter ended March 31, 2020 due to movements made by the world’s largest oil producers to increase market share. This created simultaneous shocks in oil supply and demand resulting in an economic challenge to our industry which has not occurred since our formation. This combination 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 ended December 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.
East Coast Refining Reconfiguration
On December 31, 2020, we completed the East Coast Refining Reconfiguration. As part of the reconfiguration process, we idled certain of our major processing units at the Paulsboro refinery, resulting in lower overall throughput and inventory levels in addition to decreases in capital and operating costs. Based on this reconfiguration, our East Coast throughput capacity 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 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 of December 31, 2020. Based on this reassessment and our strategic plan to reduce capital expenditures, we decided to abandon various capital projects across the refining system, resulting in an impairment charge of approximately $79.9 million.
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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.
Early Return of Railcars
In the fourth quarter of 2020 we agreed to voluntarily return a portion of railcars under an operating lease in order to rationalize certain components of our railcar fleet. Under the terms of the lease amendment, we agreed to pay amounts in lieu of satisfaction of return conditions (the “early termination penalty”). As a result, we recognized an expense of $12.5 million within Cost of sales, consisting of charges for the early termination penalty and charges related to the remaining lease payments associated with the railcars identified within the amended lease, all of which were idled and out of service as of December 31, 2020.
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 ended December 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 of December 31, 2018.
Torrance Land Sales
On December 30, 2020, August 1, 2019 and August 7, 2018, we closed on third-party sales of parcels of real property acquired as part of the Torrance refinery, but not part of the refinery itself. The sales resulted in gains of approximately $8.1 million, $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
On April 17, 2020, we closed on the sale of five hydrogen plants to Air Products and Chemicals, Inc. (“Air Products”) in a sale-leaseback transaction for gross cash proceeds of $530.0 million and recognized a gain of $471.1 million. In connection with the sale, we entered into a transition services agreement through which Air Products will exclusively supply hydrogen, steam, carbon dioxide and other products (the “Products”) to the Martinez, Torrance and Delaware 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 by PBF Holding, for which we will be reimbursed, during the term of the agreement. In August 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.
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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
On September 25, 2020, we closed on agreements to sell a portion of our precious metals catalyst to certain major commercial banks for approximately $51.9 million and subsequently leased the catalyst back. The precious metals financing arrangements cover a portion of the catalyst used in our East Coast Refining System, Martinez and Toledo refineries. The volumes of the precious metal catalyst and the interest rates are fixed over the term of each financing arrangement. We are obligated to repurchase the precious metals catalyst at fair market value upon expiration of these leases, and the earliest expiration is September 2021. For all leases not renewed at maturity, we have the ability and intent to finance such debt through availability under our Revolving Credit Facility.
Senior Notes
On May 13, 2020, we issued $1.0 billion in aggregate principal amount of the initial 2025 Senior Secured Notes. The net proceeds from this offering were approximately $982.9 million after deducting the initial purchasers’ discount and offering expenses. We used the net proceeds for general corporate purposes.
On December 21, 2020, we issued $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.
On January 24, 2020, we issued $1.0 billion in aggregate principal amount of the 2028 Senior Notes. The net proceeds from this offering were approximately $987.0 million after deducting the initial purchasers’ discount and offering expenses. We used $517.5 million of the proceeds to fully redeem our 2023 Senior Notes and the balance to fund a portion of the cash consideration for the Martinez Acquisition.
On February 14, 2020, we exercised our rights under the indenture governing the 2023 Senior Notes to redeem all of the outstanding 2023 Senior Notes at a price of 103.5% of the aggregate principal amount thereof plus accrued and unpaid interest. The aggregate redemption price for all 2023 Senior Notes approximated $517.5 million plus accrued and unpaid interest. The difference between the carrying value of the 2023 Senior Notes on the date they were redeemed and the amount for which they were redeemed was $22.2 million and has been classified as Debt extinguishment costs in the Consolidated Statements of Operations for the year ending December 31, 2020.
Refer to “Note 9 - Credit Facilities and Debt” of our Notes to Consolidated Financial Statements, for further information.
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PBF Holding Revolving Credit Facility
During the year ended December 31, 2020, we used advances under our Revolving Credit Facility to fund a portion of the Martinez Acquisition and for other general corporate purposes.
On May 2, 2018, us and certain of our wholly-owned subsidiaries, as borrowers or subsidiary guarantors, replaced our existing asset-based revolving credit agreement dated as of August 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 to us from $2.6 billion to $3.4 billion, extends the maturity date to May 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 the August 2014 Revolving Credit Agreement and further described in “Note 9 - Credit Facilities and Debt” of our Notes to Consolidated Financial Statements.
The outstanding borrowings under the Revolving Credit Facility as of December 31, 2020 were $900.0 million. There were no outstanding borrowings under the Revolving Credit Facility as of December 31, 2019 and 2018, respectively.
Martinez Acquisition
Inventory Intermediation Agreements
The aggregate purchase price for the Chalmette Acquisition was $322.0 million in cash, plus inventory and working capital of $246.0 million, which was finalizedInventory Intermediation Agreements with J. Aron were amended in the first quarter of 2016.2019 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. On March 29, 2019, the Inventory Intermediation Agreement by and among J. Aron, us 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 to J. Aron by DCR. On August 29, 2019, the Inventory Intermediation Agreement by and among J. Aron, us and PRC was extended to December 31, 2021, which term may be further extended by mutual consent of the parties to December 31, 2022, and the Inventory Intermediation Agreement by and among J. Aron, us and DCR was extended to June 30, 2021, which term may be further extended by mutual consent of the parties to June 30, 2022. We intend to either extend or replace the Inventory Intermediation Agreements prior to their expirations.
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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 transaction was financed through a combinationJ. Aron Products are sold back to us as they are discharged out of cash on handour J. Aron Storage Tanks. J. Aron has the right to store the J. Aron Products purchased in tanks under the Inventory Intermediation Agreements and borrowingswill 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 our Revolving Loan.the applicable Inventory Intermediation Agreement at that time. PBF Holding continues to market and sell the J. Aron Products independently to third parties.
Renewable Fuels Standard
We are subject to obligations to purchase RINs required to comply with the Renewable Fuels Standard. Our overall RINs obligation is based on a percentage of domestic shipments of on-road fuels as established by the EPA. To the degree we are unable to blend the required amount of biofuels to satisfy our RINs obligation, RINs must be purchased on the open market to avoid penalties and fines. We record our RINs obligation on a net basis in Accrued expenses when our RINs liability is greater than the amount of RINs earned and purchased in a given period and in Prepaid and other current assets when the amount of RINs earned and purchased is greater than the RINs liability. We have experienced fluctuations in the costs to comply with our renewable energy credit. We incurred approximately $293.7$326.4 million in RINs costs during the year ended December 31, 20172020 as compared to $347.5$122.7 million and $171.6$143.9 million during the years ended December 31, 20162019 and 2015,2018, 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.
Agreements with PBFX
PBFX is a fee-based, growth-oriented, publicly tradedpublicly-traded Delaware master limited partnershipMLP formed by our indirect parent company, PBF Energy, to own or lease, operate, develop and acquire crude oil, and refined petroleum products terminals, pipelines, storage facilities and similar logistics assets. PBFX engages in the receiving, handling, storage and transferring of crude oil, refined products, natural gas and intermediates from sources located throughout the United States and Canada for us in support of certain of our refineries, as well as for third partythird-party customers.
Beginning with the completion of the PBFX Offering, we have entered into a series of agreements with PBFX, including contribution, commercial and operational agreements. Each of these agreements and their impact to our operations is described in “Item 1. Business” and “Note 11 - Related Party Transactions” of our Notes to Consolidated Financial Statements.
A summary of our affiliate transactions with PBFX is as follows (in thousands)millions):
| Year Ended December 31, | ||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||
| Reimbursements under affiliate agreements: | ||||||||||||||||||||
| Services Agreement | $ | 8.7 | $ | 8.6 | $ | 7.5 | ||||||||||||||
| Omnibus Agreement | 7.6 | 7.7 | 7.5 | |||||||||||||||||
| Total expenses under affiliate agreements | 289.4 | 300.9 | 259.4 | |||||||||||||||||
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| Year Ended December 31, | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| Reimbursements under affiliate agreements: | ||||||||||||
| Services Agreement | $ | 6,626 | $ | 5,121 | $ | 4,533 | ||||||
| Omnibus Agreement | 6,899 | 4,805 | 5,297 | |||||||||
| Total expenses under affiliate agreements | 240,654 | 175,448 | 142,102 | |||||||||
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 operating income from operations fluctuate significantly with movements in industry refined petroleum product prices, our materials cost fluctuate significantly with movements in crude oil prices and our other operating expenses fluctuate with movements in the price of energy to meet the power needs of our refineries. In addition, the effect of changes in crude oil prices on our operating results is influenced by how the prices of refined products adjust to reflect such changes.
Crude oil and other feedstock costs and the prices of refined petroleum products have historically been subject to wide fluctuation. Expansion and upgrading of existing facilities and installation of additional refinery distillation or conversion capacity, price volatility, governmental regulations, international political and economic developments and other factors beyond our control are likely to continue to play an important role in refining industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction or increase in product margins. Moreover, the industry typically experiences seasonal fluctuations in demand for refined petroleum products, such as for gasoline and diesel, during the summer driving season and for home heating oil during the winter.
Benchmark Refining Margins
In assessing our operating performance, we compare the refining margins (revenue less materials cost) of each of our refineries against a specific benchmark industry refining margin based on crack spreads. Benchmark refining margins take into account both crude and refined petroleum product prices. When these prices are combined in a formula they provide a single value—a gross margin per barrel—that, when multiplied by throughput, provides an approximation of the gross margin generated by refining activities.
The performance of our East Coast refineries generally follows the Dated Brent (NYH) 2-1-1 benchmark refining margin. Our Toledo refinery generally follows the WTI (Chicago) 4-3-1 benchmark refining margin. Our Chalmette refinery generally follows the LLS (Gulf Coast) 2-1-1 benchmark refining margin. Our Torrance refinery generally follows the Alaskan North Slope (“ANS”) (West Coast) 4-3-1 benchmark refining margin. Our Martinez refinery generally follows the ANS (West Coast) 4-3-13-2-1 benchmark refining margin.
While the benchmark refinery margins presented below under “Results of Operations—Market Indicators” are representative of the results of our refineries, each refinery’s realized gross margin on a per barrel basis will differ from the benchmark due to a variety of factors affecting the performance of the relevant refinery to its corresponding benchmark. These factors include the refinery’s actual type of crude oil throughput, product yield differentials and any other factors not reflected in the benchmark refining margins, such as transportation costs, storage costs, credit fees, fuel consumed during production and any product premiums or discounts, as well as inventory fluctuations, timing of crude oil and other feedstock purchases, a rising or declining crude and product pricing environment and commodity price management activities. As discussed in more detail below, each of our refineries, depending on market conditions, has certain feedstock-cost and product-value advantages and disadvantages as compared to the refinery’s relevant benchmark.
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Credit Risk Management
Credit risk refers to the risk that a counterparty will default on its contractual obligations resulting in financial loss to us. Our exposure to credit risk is reflected in the carrying amount of the receivables that are presented in our balance sheet.Consolidated Balance Sheets. To minimize credit risk, all customers are subject to extensive credit verification procedures and extensions of credit above defined thresholds are to be approved by the senior management. Our intention is to trade only with recognized creditworthy third parties. In addition, receivable balances are monitored on an ongoing basis. We also limit the risk of bad debts by obtaining security such as guarantees or letters of credit.
We continually monitor our market risk exposure, including the impact and developments related to the COVID-19 pandemic and the related governmental and consumer responses which have introduced significant volatility in the financial markets.
Other Factors
We currently source our crude oil for our refineries on a global basis through a combination of market purchases and short-term purchase contracts, and through our crude oil supply agreements with Saudi Aramco, PDVSA, ExxonMobil and others.agreements. We believe purchases based on market pricing has given us flexibility in obtaining crude oil at lower prices and on a more accurate “as needed” basis. Since our Paulsboro and Delaware CityEast Coast refineries access their crude slates from the Delaware River via ship or barge and through our rail facilities at Delaware City, these refineries have the flexibility to purchase crude oils from the Mid-Continent and Western Canada, as well as a number of different countries. We have not sourced crude oil under our crude supply arrangement with PDVSA since the third quarter of 2017 as PDVSA has suspended deliveries due to our inability to agree to mutually acceptable payment terms.terms and because of U.S. government sanctions against PDVSA.
In the past several years, we expanded and upgraded the existing on-site railroad infrastructure aton the Delaware City refinery.east coast. Currently, crude oil delivered by rail to this facility is consumed at our Delaware City and PaulsboroEast Coast refineries. The Delaware City rail unloading facility,facilities, which waswere sold to PBFX in 2014, allowsand the East Coast Storage Assets, allow our East Coast refineries to source WTI-based crude oils from Western Canada and the Mid-Continent, which we believe, at times, may provide cost advantages versus traditional Brent-based international crude oils. In support of this rail strategy, we have at times entered into agreements to lease or purchase crude railcars. A portion of these railcars were purchased via the Rail Facility entered into during 2014, which was terminated in connection with the execution of the PBF Rail Term Loan in 2016. Certain of these railcars were subsequently sold to a third party,third-party, which has leased the railcars back to us for periods of between four and seven years. In 2016,subsequent periods, we have sold approximately 120 of theseor returned railcars to optimize our railcar portfolio. Our railcar fleet, at times, provides transportation flexibility within our crude oil sourcing strategy that allows our East Coast refineries to process cost advantaged crude from Canada and the Mid-Continent.
Our operating cost structure is also important to our profitability. Major operating costs include costs relating to employees and contract labor, energy, maintenance and environmental compliance and emission control regulations, including the cost of RINs required for compliance with the Renewable Fuels Standard. The predominant variable cost is energy, in particular, the price of utilities, natural gas and electricity.
Our operating results are also affected by the reliability of our refinery operations. Unplanned downtime of our refinery assets generally results in lost margin opportunity and increased maintenance expense. The financial impact of planned downtime, such as major turnaround maintenance, is managed through a planning process that considers such things as the margin environment, the availability of resources to perform the needed maintenance and feed logistics, whereas unplanned downtime does not afford us this opportunity.
Furthermore, during 2020 our operating results were negatively impacted by the ongoing COVID-19 pandemic which has caused a significant decline in the demand for our refined products and a decrease in the prices for crude oil and refined products, both of which have negatively impacted our revenues, cost of sales and operating income.
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Refinery-Specific Information
The following section includes refinery-specific information related to our operations, crude oil differentials, ancillary costs, and local premiums and discounts.
The Delaware City refinery’sEast Coast Refining System’s realized gross margin on a per barrel basis has historically differedis projected to differ from the Dated Brent (NYH) 2-1-1 benchmark refining margin due to the following factors:
•the Delaware City refinerysystem processes a slate of primarily medium and heavy sour crude oils, which has constituted approximately 55%60% to 65%70% of total throughput. The remaining throughput consists of sweet crude oil and other feedstocks and blendstocks. In addition, we have the capability to process a significant volume of light, sweet crude oil depending on market conditions. Our total throughput costs have historically priced at a discount to Dated Brent; and
•as a result of the heavy, sour crude slate processed at Delaware City,our East Coast Refining System, we produce lower value products including sulfur, carbon dioxide and petroleum coke. These products are priced at a significant discount to RBOB and ULSD and represent approximately 5% to 7% of our total production volume.ULSD.
•the Paulsboro refinery produces Group I lubricants which carry a premium sales price to RBOB and ULSD.ULSD and the black oil is sold as asphalt which may be sold at a premium or discount to Dated Brent based on the market.
Toledo Refinery. The benchmark refining margin for the Toledo refinery is calculated by assuming that four barrels of WTI crude oil are converted into three barrels of gasoline, one-half barrel of ULSD and one-half barrel of jet fuel. We calculate this refining margin using the Chicago market values of conventional blendstock for oxygenate blending (“CBOB”)CBOB and ULSD and the United States Gulf Coast value of jet fuel against the market value of WTI crude oil and refer to this benchmark as the WTI (Chicago) 4-3-1 benchmark refining margin. Our Toledo refinery has a product slate of approximately 54%53% gasoline, 34%30% distillate, 6%4% high-value petrochemicals (including nonene, tetramer, benzene, xylene
and toluene) with the remaining portion of the product slate comprised of lower-value products (5%(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 of Toledo revenues are generated off Chicago-based market prices.
The Toledo refinery’s realized gross margin on a per barrel basis has historically differed from the WTI (Chicago) 4-3-1 benchmark refining margin due to the following factors:
•the Toledo refinery processes a slate of domestic sweet and Canadian synthetic crude oil. Historically, Toledo’s blended average crude costs have been higher thandiffered from the market value of WTI crude oil;
•the Toledo refinery configuration enables it to produce more barrels of product than throughput which generates a pricing benefit; and
•the Toledo refinery generates a pricing benefit on some of its refined products, primarily its petrochemicals.
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Chalmette Refinery. The benchmark refining margin for the Chalmette refinery is calculated by assuming two barrels of Light Louisiana Sweet (“LLS”)LLS crude oil are converted into one barrel of gasoline and one barrel of diesel. We calculate this benchmark using the US Gulf Coast market value of 87 conventional gasoline and ULSD against the market value of LLS and refer to this benchmark as the LLS (Gulf Coast) 2-1-1 benchmark refining margin. Our Chalmette refinery has a product slate of approximately 47%42% gasoline and 32% distillate, 3%2% high-value petrochemicals (including benzene and xylenes) with the remaining portion of the product slate comprised of lower-value products (10%(9% black oil, 5% LPGs, 4% petroleum coke and 3%6% other). For this reason, we believe the LLS (Gulf Coast) 2-1-1 is an appropriate benchmark industry refining margin. The majority of Chalmette revenues are generated off Gulf Coast-based market prices.
The Chalmette refinery’s realized gross margin on a per barrel basis has historically differed from the LLS (USGC)(Gulf Coast) 2-1-1 benchmark refining margin due to the following factors:
•the Chalmette refinery has generally processed a slate of primarily medium and heavy sour crude oils, which has historically constituted approximately 55%65% to 65%75% of total throughput. The remaining throughput consists of sweet crude oil and other feedstocks and blendstocks; and
•as a result of the heavy, sour crude slate processed at Chalmette, we produce lower-value products including sulfur and petroleum coke. These products are priced at a significant discount to 87 conventional gasoline and ULSD and represent approximately 4% to 6% of our total production volume.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 the Torrance refinery is calculated by assuming that four barrels of Alaskan North Slope (“ANS”)ANS crude oil are converted into three barrels of gasoline, one-half barrel of diesel and one-half barrel of jet fuel. We calculate this benchmark using the West Coast Los Angeles market value of California reformulated blendstock for oxygenate blending (CARBOB)(“CARBOB”), California Air Resources Board (CARB)CARB diesel and jet fuel and refer to the benchmark as the ANS (WCLA)(West Coast) 4-3-1 benchmark refining margin. Our Torrance refinery has a product slate of approximately 64% gasoline and 22%19% distillate with the remaining portion of the product slate comprised of lower-value products (9% petroleum coke, 2%(3% LPG, 1%3% black oil and 2%11% other). For this reason, we believe the ANS (West Coast) 4-3-1 is an appropriate benchmark industry refining margin. The majority of Torrance revenues are generated off West Coast Los Angeles-based market prices.
The Torrance refinery’s realized gross margin on a per barrel basis has historically differed from the ANS (WCLA)(West Coast) 4-3-1 benchmark refining margin due to the following factors:
•the Torrance refinery has generally processed a slate of primarily heavy sour crude oils, which has historically constituted approximately 80% to 90% of total throughput. The Torrance crude slate has the lowest API gravity (typically an American Petroleum Institute (“API”)API gravity of less than 20 degrees) of all of our refineries. The remaining throughput consists of other feedstocks and blendstocks; and
•as a result of the heavy, sour crude slate processed at Torrance, we produce lower-value products including petroleum coke and sulfur. These products are priced at a significant discount to gasoline and diesel.
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Martinez Refinery. The benchmark refining margin for the Martinez refinery is calculated by assuming that three barrels of ANS crude oil are converted into two barrels of gasoline, one-quarter barrel of diesel and representthree-quarter barrel of jet fuel. We calculate this benchmark using the West Coast San Francisco market value of California reformulated blendstock for oxygenate blending (CARBOB), CARB diesel and jet fuel and refer to the benchmark as the ANS (West Coast) 3-2-1 benchmark refining margin. Our Martinez refinery has a product slate of approximately 9% to 11%56% gasoline and 34% distillate with the remaining portion of our total production volume.
The Martinez refinery’s realized gross margin on a subtotal within operating costs and expenses referredper barrel basis has historically differed from the ANS (West Coast) 4-3-1 benchmark refining margin due to as “Costthe following factors:
•the Martinez refinery has generally processed a slate of sales” and the reclassificationprimarily heavy sour crude oils, which has historically constituted approximately 80% to 90% of total depreciationthroughput. The remaining throughput consists of other feedstocks and amortization expense between such amounts attributableblendstocks; and
•as a result of the heavy, sour crude slate processed at Martinez, we produce lower-value products including petroleum coke and sulfur. These products are priced at a significant discount to cost of salesgasoline and other operating costs and expenses. The amount of depreciation and amortization expense that is presented separately within the “Cost of Sales” subtotal represents depreciation and amortization of refining and logistics assets that are integral to the refinery production process.CARB diesel.
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Results of Operations
The following tables reflect our consolidated financial and operating highlights for the years ended December 31, 2017, 20162020, 2019 and 20152018 (amounts in thousands)millions, unless otherwise noted).
| Year Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||||||||||||||||||||
| 2017 | 2016 | 2015 | 2020 | 2019 | 2018 | ||||||||||||||||||||||||||||||||||||
| Revenues | $ | 21,772,478 | $ | 15,908,537 | $ | 13,123,929 | Revenues | $ | 15,045.0 | $ | 24,468.9 | $ | 27,164.0 | ||||||||||||||||||||||||||||
| Cost and expenses: | Cost and expenses: | ||||||||||||||||||||||||||||||||||||||||
| Cost of products and other | 19,095,827 | 13,765,088 | 11,611,599 | Cost of products and other | 14,548.2 | 21,667.7 | 24,744.6 | ||||||||||||||||||||||||||||||||||
| Operating expenses (excluding depreciation and amortization expense as reflected below) | 1,627,616 | 1,390,582 | 889,368 | Operating expenses (excluding depreciation and amortization expense as reflected below) | 1,835.2 | 1,684.3 | 1,654.8 | ||||||||||||||||||||||||||||||||||
| Depreciation and amortization expense | 254,271 | 204,005 | 181,422 | Depreciation and amortization expense | 498.0 | 386.7 | 329.7 | ||||||||||||||||||||||||||||||||||
| Cost of sales | 20,977,714 | 15,359,675 | 12,682,389 | Cost of sales | 16,881.4 | 23,738.7 | 26,729.1 | ||||||||||||||||||||||||||||||||||
| General and administrative expenses (excluding depreciation and amortization expense as reflected below) | 198,164 | 149,643 | 166,904 | General and administrative expenses (excluding depreciation and amortization expense as reflected below) | 229.0 | 258.7 | 253.8 | ||||||||||||||||||||||||||||||||||
| Depreciation and amortization expense | 12,964 | 5,835 | 9,688 | Depreciation and amortization expense | 11.3 | 10.8 | 10.6 | ||||||||||||||||||||||||||||||||||
| Change in fair value of contingent consideration | Change in fair value of contingent consideration | (79.3) | — | — | |||||||||||||||||||||||||||||||||||||
| Impairment Expense | Impairment Expense | 91.8 | — | — | |||||||||||||||||||||||||||||||||||||
| Equity income in investee | (14,565 | ) | (5,679 | ) | — | Equity income in investee | — | (7.9) | (17.8) | ||||||||||||||||||||||||||||||||
| Loss (gain) on sale of assets | 1,458 | 11,374 | (1,004 | ) | |||||||||||||||||||||||||||||||||||||
| Gain on sale of assets | Gain on sale of assets | (477.8) | (29.9) | (43.1) | |||||||||||||||||||||||||||||||||||||
| Total cost and expenses | 21,175,735 | 15,520,848 | 12,857,977 | Total cost and expenses | 16,656.4 | 23,970.4 | 26,932.6 | ||||||||||||||||||||||||||||||||||
| Income from operations | 596,743 | 387,689 | 265,952 | ||||||||||||||||||||||||||||||||||||||
| Income (loss) from operations | Income (loss) from operations | (1,611.4) | 498.5 | 231.4 | |||||||||||||||||||||||||||||||||||||
| Other income (expense): | Other income (expense): | ||||||||||||||||||||||||||||||||||||||||
| Change in fair value of catalyst leases | (2,247 | ) | 1,422 | 10,184 | |||||||||||||||||||||||||||||||||||||
| Interest expense, net | Interest expense, net | (210.3) | (108.7) | (127.1) | |||||||||||||||||||||||||||||||||||||
| Change in fair value of catalyst obligations | Change in fair value of catalyst obligations | (11.8) | (9.7) | 5.6 | |||||||||||||||||||||||||||||||||||||
| Debt extinguishment costs | (25,451 | ) | — | — | Debt extinguishment costs | (22.2) | — | — | |||||||||||||||||||||||||||||||||
| Interest expense, net | (122,628 | ) | (129,536 | ) | (88,194 | ) | |||||||||||||||||||||||||||||||||||
| Income before income taxes | 446,417 | 259,575 | 187,942 | ||||||||||||||||||||||||||||||||||||||
| Income tax (benefit) expense | (10,783 | ) | 23,689 | 648 | |||||||||||||||||||||||||||||||||||||
| Net income | 457,200 | 235,886 | 187,294 | ||||||||||||||||||||||||||||||||||||||
| Less: net income attributable to noncontrolling interests | 95 | 269 | 274 | ||||||||||||||||||||||||||||||||||||||
| Net income attributable to PBF Holding Company LLC | $ | 457,105 | $ | 235,617 | $ | 187,020 | |||||||||||||||||||||||||||||||||||
| Other non-service components of net periodic benefit cost | Other non-service components of net periodic benefit cost | 4.3 | (0.2) | 1.1 | |||||||||||||||||||||||||||||||||||||
| Income (loss) before income taxes | Income (loss) before income taxes | (1,851.4) | 379.9 | 111.0 | |||||||||||||||||||||||||||||||||||||
| Income tax expense (benefit) | Income tax expense (benefit) | 6.1 | (8.3) | 8.0 | |||||||||||||||||||||||||||||||||||||
| Net income (loss) | Net income (loss) | (1,857.5) | 388.2 | 103.0 | |||||||||||||||||||||||||||||||||||||
| Less: net income (loss) attributable to noncontrolling interests | Less: net income (loss) attributable to noncontrolling interests | (0.3) | — | 0.1 | |||||||||||||||||||||||||||||||||||||
| Net income (loss) attributable to PBF Holding Company LLC | Net income (loss) attributable to PBF Holding Company LLC | $ | (1,857.2) | $ | 388.2 | $ | 102.9 | ||||||||||||||||||||||||||||||||||
| Gross margin | $ | 794,764 | $ | 548,862 | $ | 441,539 | |||||||||||||||||||||||||||||||||||
| Consolidated gross margin | Consolidated gross margin | $ | (1,836.4) | $ | 730.2 | $ | 434.9 | ||||||||||||||||||||||||||||||||||
Gross refining margin (1) | 2,676,651 | 2,143,449 | 1,512,330 | Gross refining margin (1) | 496.8 | 2,801.2 | 2,419.4 | ||||||||||||||||||||||||||||||||||
——————————
(1)See Non-GAAP Financial Measures.
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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 | $ | (6.90) | $ | 2.44 | $ | 1.39 | ||||||||||||||
Gross refining margin, excluding special items, per barrel of throughput (1) | $ | 3.23 | $ | 8.51 | $ | 9.09 | ||||||||||||||
| Refinery operating expense, per barrel of throughput | $ | 6.89 | $ | 5.61 | $ | 5.34 | ||||||||||||||
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 API gravity between 24 and 35 degrees. We define light crude oil as crude oil with an API gravity higher than 35 degrees. | ||||||||||||||||||||
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| Year Ended December 31, | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| Key Operating Information | ||||||||||||
| Production (bpd in thousands) | 802.9 | 734.3 | 511.9 | |||||||||
| Crude oil and feedstocks throughput (bpd in thousands) | 807.4 | 727.7 | 516.4 | |||||||||
| Total crude oil and feedstocks throughput (millions of barrels) | 294.7 | 266.4 | 188.4 | |||||||||
| Gross margin per barrel of throughput | $ | 2.70 | $ | 2.06 | $ | 2.34 | ||||||
Gross refining margin, excluding special items, per barrel of throughput (1) | $ | 8.08 | $ | 6.09 | $ | 10.29 | ||||||
| Refinery operating expense, excluding depreciation, per barrel of throughput | $ | 5.52 | $ | 5.22 | $ | 4.72 | ||||||
Crude and feedstocks (% of total throughput) (2) | ||||||||||||
| Heavy | 34 | % | 26 | % | 14 | % | ||||||
| Medium | 30 | % | 37 | % | 49 | % | ||||||
| Light | 21 | % | 25 | % | 26 | % | ||||||
| Other feedstocks and blends | 15 | % | 12 | % | 11 | % | ||||||
| Total throughput | 100 | % | 100 | % | 100 | % | ||||||
| Yield (% of total throughput) | ||||||||||||
| Gasoline and gasoline blendstocks | 50 | % | 50 | % | 49 | % | ||||||
| Distillates and distillate blendstocks | 30 | % | 31 | % | 35 | % | ||||||
| Lubes | 1 | % | 1 | % | 1 | % | ||||||
| Chemicals | 2 | % | 3 | % | 3 | % | ||||||
| Other | 16 | % | 15 | % | 12 | % | ||||||
| Total yield | 99 | % | 100 | % | 100 | % | ||||||
(1) See Non-GAAP Financial measures below. | ||||||||||||
(2) We define heavy crude oil as crude oil with American Petroleum Institute (API) gravity less than 24 degrees. We define medium crude oil as crude oil with API gravity between 24 and 35 degrees. We define light crude oil as crude oil with API gravity higher than 35 degrees. | ||||||||||||
The table below summarizes certain market indicators relating to our operating results as reported by Platts.
| Year Ended December 31, | ||||||||||||||||||||
| 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 | $ | 2.53 | $ | 3.07 | ||||||||||||||
| Year Ended December 31, | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| (dollars per barrel, except as noted) | ||||||||||||
| Dated Brent Crude | $ | 54.18 | $ | 43.91 | $ | 52.56 | ||||||
| West Texas Intermediate (WTI) crude oil | $ | 50.79 | $ | 43.34 | $ | 48.71 | ||||||
| Light Louisiana Sweet (LLS) crude oil | $ | 54.02 | $ | 45.03 | $ | 52.36 | ||||||
| Alaska North Slope (ANS) crude oil | $ | 54.43 | $ | 43.67 | $ | 52.44 | ||||||
| Crack Spreads | ||||||||||||
| Dated Brent (NYH) 2-1-1 | $ | 14.74 | $ | 13.49 | $ | 16.35 | ||||||
| WTI (Chicago) 4-3-1 | $ | 15.88 | $ | 12.38 | $ | 17.91 | ||||||
| LLS (Gulf Coast) 2-1-1 | $ | 13.57 | $ | 10.75 | $ | 14.39 | ||||||
| ANS (West Coast) 4-3-1 | $ | 17.43 | $ | 16.46 | $ | 26.46 | ||||||
| Crude Oil Differentials | ||||||||||||
| Dated Brent (foreign) less WTI | $ | 3.39 | $ | 0.56 | $ | 3.85 | ||||||
| Dated Brent less Maya (heavy, sour) | $ | 7.16 | $ | 7.36 | $ | 8.45 | ||||||
| Dated Brent less WTS (sour) | $ | 4.37 | $ | 1.42 | $ | 3.59 | ||||||
| Dated Brent less ASCI (sour) | $ | 3.66 | $ | 3.92 | $ | 4.57 | ||||||
| WTI less WCS (heavy, sour) | $ | 12.24 | $ | 12.57 | $ | 11.87 | ||||||
| WTI less Bakken (light, sweet) | $ | (0.26 | ) | $ | 1.32 | $ | 2.89 | |||||
| WTI less Syncrude (light, sweet) | $ | (1.74 | ) | $ | (2.01 | ) | $ | (1.45 | ) | |||
| WTI less LLS (light, sweet) | $ | (3.23 | ) | $ | (1.69 | ) | $ | (3.67 | ) | |||
| WTI less ANS (light, sweet) | $ | (3.63 | ) | $ | (0.33 | ) | $ | (3.73 | ) | |||
| Natural gas (dollars per MMBTU) | $ | 3.02 | $ | 2.55 | $ | 2.63 | ||||||
Overview— Our net incomeloss was $457.2$(1,857.5) million for the year ended December 31, 20172020 compared to $235.9net income of $388.2 million for the year ended December 31, 2016.2019.
Our results for the year ended December 31, 20172020 were positively impacted by special items consisting of a positive LCM inventory adjustment (as defined ingain on the Notes to Non-GAAP Financial Measures below)sale of approximately $295.5hydrogen plants of $471.1 million, a gain on the sale of land at our Torrance refinery of $8.1 million and a charge related to debt extinguishment costschange in fair value of $25.5 million associated with the early retirementMartinez Contingent Consideration of our 2020 Senior Secured Notes.$79.3 million. Our results for the year ended December 31, 20162020 were negatively impacted by special items consisting of a non-cash LCM inventory adjustment of approximately $268.0 million, debt extinguishment costs associated with the early redemption of the 2023 Senior Notes of $22.2 million, severance costs related to reductions in workforce of $24.7 million, impairment expense of $91.8 million related to the write-down of certain assets and project abandonments, early return of certain leased railcars of $12.5 million, accelerated turnaround amortization costs of $56.2 million , LIFO inventory decrement of $83.0 million, and reconfiguration charges of $5.3 million. Our results for the year ended December 31, 2019 were positively impacted by an LCM inventory adjustment of approximately $521.3$250.2 million and gain on the sale of land at our Torrance refinery of $33.1 million. 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 ended December 31, 2020 we experienced unfavorable movements in certain crude differentials and overall lower throughput volumes and barrels sold across our refineries, as well as lower refining margins. All our operating regions experienced lower refining margins for the year ended December 31, 20172020 compared to the prior year. Our results for the year ended December 31, 2020 were positivelynegatively impacted by higher throughput volumes at the majority of our refineriesgeneral and higher crack spreads realized at each of our refineries, which were impacted by the hurricane-related reduction in refining throughput in the Gulf Coast region and tightening product inventories, specifically distillates, in the second half of the year as well as loweradministrative expenses associated
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with integration costs to complyassociated with the RFS. Notably, we benefited fromMartinez Acquisition and increased depreciation and amortization expense associated with the improved operating performance of our ChalmetteMartinez Acquisition and Torrance refineries.accelerated amortization costs associated with the East Coast Refining Reconfiguration.
Revenues— Revenues totaled $21.8$15.0 billion for the year ended December 31, 20172020 compared to $15.9$24.5 billion for the year ended December 31, 2016, an increase2019, a decrease of approximately $5.9$9.5 billion or 36.9%38.8%. Revenues per barrel sold were $64.86$49.20 and $59.72$69.81 for the years ended December 31, 20172020 and 2016,2019, respectively, an increasea decrease of 8.6%29.5% directly related to higherlower hydrocarbon commodity prices. For the year ended December 31, 2017,2020, the total throughput rates at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 338,200263,000 bpd, 145,20096,700 bpd, 184,500137,700 bpd and 139,500230,300 bpd, respectively. For the year ended December 31, 2016,2019, the total throughput rates at our East Coast, Mid-Continent, Gulf Coast and GulfWest Coast refineries averaged approximately 327,000336,400 bpd, 159,100153,000 bpd, 177,900 bpd and 169,300155,800 bpd, respectively. For the period from its acquisition on July 1, 2016 through December 31, 2016, our West Coast refinery’s throughput averaged 143,900 bpd. The throughput rates at our East Coast and Gulf Coast refineries were higher in 2017 compared to 2016. Our West Coast refinery was not acquired until the beginning of the third quarter of 2016. The decrease in throughput rates at our West Coast refinery in 2017 compared to 2016 is primarily due to planned downtime at our Torrance refinery for its first significant turnaround under our ownership, which was completed early in the third quarter of 2017. However, our West Coast refinery throughput averaged 164,000 bpd for the last six months of the year upon completion of the
The throughput rates at our refineries were lower in the period from its acquisition on July 1, 2016 throughyear ended December 31, 2016, refined product barrels sold at our2020 compared to the same period in 2019. Our Martinez refinery was not acquired until the first quarter of 2020 and is therefore not included in the prior period West Coast refinery averaged approximately 179,200 bpd.throughput. We operated our refineries at reduced rates beginning in March 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 theour refineries.
Consolidated Gross Margin— Consolidated gross margin totaled $(1,836.4) million for the year ended December 31, 2020, compared to $730.2 million for the year ended December 31, 2019, a decrease of $2,566.6 million. Gross refining margin including refinery operating expenses and depreciation,(as described below in Non-GAAP Financial Measures) totaled $794.8$496.8 million, or $2.70$1.86 per barrel of throughput, for the year ended December 31, 2017,2020 compared to $548.9$2,801.2 million, or $2.06$9.34 per barrel of throughput, for the year ended December 31, 2016, an increase2019, a decrease of approximately $245.9$2,304.4 million. Gross refining margin (as defined below in Non-GAAP Financial Measures)excluding special items totaled $2,676.7$860.3 million, or $9.08$3.23 per barrel of throughput, ($2,381.1 million or $8.08 per barrel of throughput excluding the impact of special items) for the year ended December 31, 20172020 compared to $2,143.4$2,551.0 million, or $8.05$8.51 per barrel of throughput, ($1,622.1 million or $6.09 per barrel of throughput excluding the impact of special items) for the year ended December 31, 2016, an increase2019, a decrease of approximately $533.2 million or an increase of approximately $759.0 million excluding special items.$1,690.7 million.
Additionally, our results continue to be impacted by significant costs to comply with the Renewable Fuel Standard. Total Renewable Fuel Standard costs were $326.4 million for the year ended December 31, 2020 in comparison to $122.7 million for the year ended December 31, 2019.
Average industry refining margins in the Mid-Continent were strongermixed during the year ended December 31, 2017, as2020 compared with the prior year, primarily due to the same periodimpacts of the COVID-19 pandemic on regional demand and commodity prices in 2016. The WTI (Chicago) 4-3-1 industry crack spread was $15.88 per barrel, or 28.3% higher,2020, in addition to impacts related to 2019 planned turnarounds, all of which were completed in the year ended December 31, 2017 as compared to $12.38 per barrel infirst half of the same period in 2016. Our margins were unfavorably impacted by our refinery specific crude slate in the Mid-Continent which was impacted by a declining WTI/Bakken differential partially offset by an improving WTI/Syncrude differential, which averaged a premium of $1.74 per barrel for the year ended December 31, 2017 as compared to a premium of $2.01 per barrel in the same period in 2016.prior year.
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On the East Coast, the Dated Brent (NYH) 2-1-1 industry crack spread was approximately $14.74$9.11 per barrel, or 9.3% higher,28.2% lower, in the year ended December 31, 20172020, as compared to $13.49$12.68 per barrel in the same period in 2016.2019. Our margins were negatively impacted from our refinery specific slate on the East Coast by weakened Dated Brent/Maya differential, which decreased by $1.39 per barrel, in comparison to the same period in 2019. Additionally, WTI/WCS differential decreased to $10.72 per barrel in 2020 compared to $13.61 per barrel in 2019, which unfavorably impacted our cost of heavy Canadian crude. The Dated Brent/WTI/Bakken differentials increased by $1.75 per barrel when compared to 2019.
Across the Mid-Continent, the WTI differential(Chicago) 4-3-1 industry crack spread was $2.83 higher$6.30 per barrel, or 58.7% lower, in the year ended December 31, 2017,2020, as compared to the same period in 2016, partially offset by year over year decreases$15.25 per barrel in the Dated Brent/Maya differential andprior year. Our margins were positively impacted from our refinery specific slate in the Mid-Continent by an increasing WTI/Bakken differential, of $0.20 and $1.58, respectively.
On the Gulf Coast, the LLS (Gulf Coast) 2-1-1 industry crack spread was $13.57$7.59 per barrel, or 26.2% higher,38.9% lower, in the year ended December 31, 20172020 as compared to $10.75$12.43 per barrel in the same period in 2016. Crude differentials weakened withprior year. Margins on the Gulf Coast were positively impacted from our refinery specific slate by a strengthening WTI/LLS differential, averagingwhich averaged a premium of $3.23$1.88 per barrel duringfor the year ended December 31, 20172020 as compared to a premium of $1.69$5.64 per barrel in the same period of 2016.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 $1,627.6$1,835.2 million, or $5.52$6.89 per barrel of throughput, for the year ended December 31, 20172020 compared to $1,390.6$1,684.3 million, or $5.22$5.61 per barrel of throughput, for the year ended December 31, 2016,2019, an increase of $237.0$150.9 million, or 17.0%9.0%. The increaseIncreases in operating expenses was mainly attributablewere due to the operating expensescosts associated with our Torrancethe Martinez refinery and related logisticslogistic assets which were included in our results for the full year of 2017 as compared with only six months of 2016. For the year ended December 31, 2017 the Torrance refinery and related logistics assets incurred operating expenses oftotaled approximately $475.9 million in comparison to $250.5 million for the period from its acquisition on July 1, 2016 to December 31, 2016. Total operating expenses at our refineries, excluding our Torrance refinery, increased slightly for the year ended December 31, 2017, primarily due to higher energy costs and maintenance costs. The increase in energy costs was mainly due to higher natural gas prices while the increase in maintenance costs was mainly due to timing of repairs.
General and Administrative Expenses— General and administrative expenses totaled $229.0 million for the year ended December 31, 2016, an increase2020, compared to $258.7 million for the year ended December 31, 2019, a decrease of $48.5$29.7 million or 32.4%. The increase11.5%.The decrease in general and administrative expenses primarily relates to increased employee related expenses of $58.2 million driven by higher incentive compensation costs infor the year ended December 31, 2017 as compared2020 in comparison to the same period in 2016, attributable to higher average employee headcount and better operating performance. These increases were partially offset by lower costs associated with the acquisition and integration related activities which were approximately $8.6 million lower in the year ended December 31, 20172019 primarily relates to reduction in our workforce as compareda 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 same period of 2016.Martinez Acquisition. Our general and administrative expenses are comprised of the personnel, facilities and other infrastructure costs necessary to support our refineries.
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Depreciation and Amortization Expense— Depreciation and amortization expense totaled $509.3 million for the year ended December 31, 20162020 (including $204.0$498.0 million recorded within Cost of sales) compared to $397.5 million for the year ended December 31, 2019 (including $386.7 million recorded within Cost of sales), an increase of $57.4$111.8 million. The increase was a result of additional depreciation expense associated with the assets acquired in the TorranceMartinez Acquisition and a general increase in our fixed asset base due to capital projects and turnarounds completed during 2017 and 2016.since the third quarter of 2019. Additionally, amortization expense recorded in 2020 includes $56.2 million of accelerated unamortized deferred turnaround costs associated with assets that were idled as part of the East Coast Refining Reconfiguration.
Change in Fair Value of Catalyst LeasesContingent Consideration — Change in the fair value of catalyst leasescontingent consideration represented a lossgain of $2.2$79.3 million for the year ended December 31, 2017, compared to2020. This change represents the decrease in the estimated fair value of the Martinez Contingent Consideration associated with acquisition related earn-out obligations. There was no such change in the prior year.
Change in Fair Value of Catalyst Obligations— Change in fair value of catalyst obligations represented a gainloss of $1.4$11.8 million for the year ended December 31, 2016.2020, compared to a loss of $9.7 million for the year ended December 31, 2019. These gains and losses relate to the change in value of the precious metals underlying the sale and leaseback of our refineries’ precious metals catalyst,metal catalysts, which we are obligated to return or repurchase at fair market value on the leasecatalyst financing arrangement termination dates.
Impairment expense— Impairment expense totaled $91.8 million for the year ended December 31, 2020, and was associated with the write-down of certain assets as a result of the East Coast Refining Reconfiguration and other refinery wide project abandonments. There was no such expense recorded in the prior year.
Debt extinguishment costs—Extinguishment Costs—Debt extinguishment costs of $25.5$22.2 million incurred in the year ended December 31, 20172020 relate to nonrecurring charges associated with debt refinancing activity calculated based on the difference between the carrying valueearly redemption of the 2020our 2023 Senior Secured Notes on the date that they were reacquired and the amount for which they were reacquired.Notes. There were no such costs in the same period of 2016.2019.
Interest Expense, net— Interest expense totaled $122.6$210.3 million for the year ended December 31, 2017,2020, compared to $129.5$108.7 million for the year ended December 31, 2016, a decrease2019, an increase of $6.9$101.6 million. This net decreaseincrease is mainly attributable to lowerhigher interest expense on a portioncosts associated with the issuance of our senior notes that were refinancedthe 2028 Senior Notes in January 2020, the issuance of the 2025 Senior Secured Notes in May 2017 (see “Note 8 - Credit Facility2020 and Debt” of our Notes to Consolidated Financial Statements, for additional details) and lower interest costs related to the affiliate notes payable partially offset byDecember 2020, as well as higher averageoutstanding borrowings underon our Revolving Loan.Credit Facility. Interest expense includes interest on long-term debt, costs related to the sale and leaseback of our precious metals catalyst,metal catalysts, financing costs associated with the A&RInventory Intermediation Agreements with J. Aron, letter of credit fees associated with the purchase of certain crude oils and the amortization of deferred financing costs.
Income Tax Expense— As we are a limited liability company treated as a “flow-through” entity for income tax purposes, our consolidated financial statements generally do not include a benefit or expense for income taxes for the years ended December 31, 20172020 and 2016,2019, respectively, apart from the income tax attributable to two subsidiaries acquired in connection with the acquisition of our Chalmette Acquisition in the fourth quarter of 2015refinery and our wholly-owned Canadian subsidiary, PBF Energy Limited (“PBF Ltd”Ltd.”). These subsidiaries are treated as C-Corporations for income tax purposes. An income tax benefitexpense of $10.8$6.1 million was recorded for the year ended December 31, 20172020 in comparison to income tax expensebenefit of $23.7$8.3 million recorded for the year ended December 31, 2016. Income tax expense for2019, primarily attributable to volatility in the year ended December 31, 2016 included a chargeresults of $30.7 million related to a correction of prior periods.our taxable subsidiaries.
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Overview—Our net income was $235.9$388.2 million for the year ended December 31, 20162019 compared to $187.3$103.0 million for the year ended December 31, 2015.2018.
Our results for the year ended December 31, 20162019 were positively impacted by special items comprised of a non-cash special item consisting of a LCM inventory adjustment of approximately $521.3$250.2 million whereasand a gain on the sale of land at our Torrance refinery of $33.1 million. Our results for the year ended December 31, 2018 were negatively impacted by an LCM inventory adjustment of approximately $351.3 million and the early return of certain leased railcars, resulting in a charge of $52.3 million. These unfavorable impacts were partially offset by a special item related to a gain on the sale of land at our Torrance refinery of $43.8 million.
Excluding the impact of these special items, our results for the year ended December 31, 20152019 were negatively impacted by a LCM inventory adjustment of approximately $427.2 million. These LCM inventory adjustmentsunfavorable movements in crude differentials and overall lower throughput volumes and barrels sold across our refineries, partially offset by higher crack spreads realized at our West Coast refinery. Refining margins for the current year compared to the prior year were recorded due to significant changes inweaker at our East Coast, Mid-Continent and Gulf Coast refineries, offset by significantly stronger margins realized on the price of crude oil and refined products in the periods presented. Excluding the impact of the net change in LCM inventory reserve, ourWest Coast. Our results for the year ended December 31, 20162019 were also negatively impacted by unfavorable movementsincreased operating expenses and depreciation and amortization expense associated with our continued investment in certain crude oil differentials, lower crack spreads, increased costs to comply withour refining assets and the RFS,effect of significant turnaround and increased interest costs, partially offset by positive earnings contributions from the Chalmette and Torrance refineries and higher throughput in the Mid-Continent. Throughput volumes for 2015 in the Mid-Continent were impacted by unplanned downtime in the second quarter of 2015.maintenance activity during 2019.
Revenues—Revenues totaled $15.9$24.5 billion for the year ended December 31, 20162019 compared to $13.1$27.2 billion for the year ended December 31, 2015, an increase2018, a decrease of approximately $2.8$2.7 billion or 21.2%9.9%. Revenues per barrel sold were $59.72$69.81 and $69.66$77.01 for the years ended December 31, 20162019 and 2015,2018, respectively, a decrease of 14.3%9.3% directly related to lower hydrocarbon commodity prices. For the year ended December 31, 2016, the total throughput rates in the East Coast, Mid-Continent and Gulf Coast refineries averaged approximately 327,000 bpd, 159,100 bpd and 169,300 bpd, respectively. For the period from its acquisition on July 1, 2016 through December 31, 2016, our West Coast refinery’s throughput averaged 143,900 bpd. For the year ended December 31, 2015,2019, the total throughput rates at our East Coast, Mid-Continent, Gulf Coast and Mid-Continent,West Coast refineries averaged approximately 330,700336,400 bpd, 153,000 bpd, 177,900 bpd and 153,800155,800 bpd, respectively. For the period from its acquisition on November 1, 2015 throughyear ended December 31, 2015, our Gulf Coast refinery’s throughput averaged 190,800 bpd. The slight decrease in2018, the total throughput rates at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 344,700 bpd, 149,600 bpd, 185,600 bpd and 169,800 bpd, respectively. The throughput rates at our East Coast and West Coast refineries were lower in 2016the year ended December 31, 2019 compared to 2015 was primarilythe same period in 2018 due to weather-relatedplanned downtime associated with turnarounds of the coker and associated units at our Delaware City and Torrance refineries and the crude unit at our Paulsboro refinery, all of which were completed in the first half of 2019, and unplanned downtime at our Delaware City refinery in the first quarter of 2016, partially offset by downtime at our Delaware City refinery in 2015. The increase in throughput2019. Throughput rates at our Mid-Continent refinery were higher in 2016 isthe year ended December 31, 2019 compared to 2018 due to a planned turnaround at our Toledo refinery in the first half of 2018. Throughput rates at our Gulf Coast refinery were lower in the year ended December 31, 2019 compared to the same period in 2018 due to unplanned downtime in the secondfourth quarter of 2015. Our2019. For the year ended December 31, 2019, the total barrels sold at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries were not acquired until the fourth quarter of 2015averaged approximately 382,500 bpd, 163,900 bpd, 225,300 bpd and the third quarter of 2016,188,600 bpd, respectively. For the year ended December 31, 2016,2018, the total refined product barrels sold at our East Coast, Mid-Continent, Gulf Coast and GulfWest Coast refineries averaged approximately 364,100372,700 bpd, 171,800161,800 bpd, 233,700 bpd and 206,400198,100 bpd, respectively. For the period from its acquisition on July 1, 2016 through December 31, 2016, the total refined product barrels sold at our West Coast refinery averaged approximately 179,200 bpd. For the year ended December 31, 2015, the total refined product barrels sold at our East Coast and Mid-Continent refineries averaged approximately 366,100 bpd and 162,600 bpd, respectively. For the period from its acquisition on November 1, 2015 through December 31, 2015, the total refined product barrels sold at our Gulf Coast refinery averaged 216,100 bpd. 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 $730.2 million, for the year ended December 31, 2019, compared to $434.9 million, for the year ended December 31, 2018, an increase of $295.3 million. Gross refining margin including refinery operating expenses and depreciation,(as described below in Non-GAAP Financial Measures) totaled $548.9$2,801.2 million, or $2.06$9.34 per barrel of throughput, for the year ended December 31, 2016,2019 compared to $441.5$2,419.4 million, or $2.34$7.79 per barrel of throughput, for the year ended December 31, 2015,2018, an increase of $107.3approximately $381.8 million. Gross refining margin (as defined below in Non-GAAP Financial Measures)excluding special items totaled $2,143.4$2,551.0 million, or $8.05$8.51 per barrel of throughput, ($1,622.1 million or $6.09 per barrel of throughput excluding the impact of special items) for the year ended December 31, 20162019 compared to $1,512.3$2,823.0 million, or $8.02$9.09 per barrel of throughput, ($1,939.6 million, or $10.29 per barrel of throughput excluding the impact of special items) for the year ended December 31, 2015, an increase of $631.1 million or2018, a decrease of $317.5$272.0 million.
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Consolidated gross margin and gross refining margin were positively impacted in the year ended December 31, 2019 by a non-cash LCM inventory adjustment of approximately $250.2 million resulting from the increase in crude oil and refined product prices from the year ended 2018. Gross refining margin excluding special items.
Additionally, our results continue to be impacted by significant costs to comply with our obligation under the RFS totaled $236.2Renewable Fuel Standard, although at a reduced level from the prior year. Total Renewable Fuel Standard costs were $122.7 million for the year ended December 31, 2016 (excluding our Gulf Coast and West Coast refineries, whose costs to comply2019 compared with RFS totaled $111.3$143.9 million for the year ended December 31, 2016) compared to $163.6 million for the year ended December 31, 2015 (excluding our Gulf Coast, whose costs to comply with RFS totaled $8.0 million for the year ended December 31, 2015). In addition, gross margin and gross refining margin were positively impacted by a non-cash LCM inventory adjustment of approximately $521.3 million resulting from the change in crude oil and refined product prices from the end of 2015 to the end of 2016 which, in addition to remaining below historical costs, increased since the prior year. The non-cash LCM inventory adjustment decreased gross margin and gross refining margin by approximately $427.2 million in the year ended December 31, 2015.
2018.
Average industry refining margins in the Mid-Continent were weakermixed during the year ended December 31, 2016, as2019 compared towith the same period in 2015. The WTI (Chicago) 4-3-12018, 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 the East Coast, the Dated Brent (NYH) 2-1-1 industry crack spread was $12.38approximately $12.68 per barrel, or 30.9%3.7% lower, in the year ended December 31, 2016,2019 as compared to $17.91$13.17 per barrel in the same period in 2015.2018. Our margins were negatively impacted from our refinery specific crudeslate on the East 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 same period in 2018. 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 ended December 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 which was impacted by a decliningdecreasing WTI/Bakken differential, and a decliningwhich averaged approximately $0.66 per barrel in the year ended December 31, 2019, as compared to $2.86 per barrel in the same period in 2018. Additionally, the WTI/Syncrude differential which averaged a premium of $2.01$0.18 per barrel for the year ended December 31, 20162019 as compared to a premium$6.84 per barrel in the same period of $1.452018.
In the Gulf Coast, the LLS (Gulf Coast) 2-1-1 industry crack spread was $12.43 per barrel, or 1.1% higher, in the year ended December 31, 2019 as compared to $12.30 per barrel in the same period in 2015.2018. Margins in the Gulf 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 ended December 31, 2019 as compared to a premium of $5.03 per barrel experienced in the same period in 2018.
Favorable movements in 2015. In addition, the WTI/Bakken differential was approximately $1.57 per barrel less favorablethese benchmark crude differentials typically result in the year ended December 31, 2016 as compared to the same period in 2015. Reductionslower 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.
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Operating Expenses—Operating expenses totaled $1,390.6$1,684.3 million, or $5.22$5.61 per barrel of throughput, for the year ended December 31, 20162019 compared to $889.4$1,654.8 million, or $4.72$5.34 per barrel of throughput, for the year ended December 31, 2015,2018, an increase of $501.2$29.5 million, or 56.4%1.8%. The increaseIncrease in operating expenses waswere mainly attributableattributed to the operating expenses associated with the Chalmette and Torrance refineries andhigher outside service costs related logistics assets. For the year ended December 31, 2016 and for the period from its acquisition on November 1, 2015 to December 31, 2015, the Chalmette refinery and related logistics assets incurred operating expenses of approximately $343.9 million and $52.1 million, respectively. In the period from its acquisition on July 1, 2016 to December 31, 2016, the Torrance refinery and related logistics assets incurred operating expenses of approximately $250.5 million. Total operating expenses at our refineries, excluding our Chalmette and Torrance refineries, decreased slightly for the year ended December 31, 2016, primarily due to lower energy coststurnaround and maintenance costs. The reduction in energy costs was mainly due to lower natural gas prices while the reduction in maintenance costs was mainly due to timing of repairs and certain non-recurring maintenance costs incurred in 2015. These reductions were partially offset by higher employee-related expenses, primarily attributable to merit increases in salaries.activity.
General and Administrative Expenses—General and administrative expenses totaled $149.6$258.7 million for the year ended December 31, 2016,2019, compared to $166.9$253.8 million for the year ended December 31, 2015, a decrease2018, an increase of $17.3$4.9 million or 10.3%1.9%.The decreaseincrease in general and administrative expenses for the year ended December 31, 2019 compared with the year ended December 31, 2018 primarily relatesrelated to reduced employeehigher outside services, including legal settlement charges and transaction costs related expenses of $39.3 million mainly due to lower incentive compensation expenses,the Martinez Acquisition, partially offset by $12.9 milliona reduction in additional outside services and other costs to support our acquisitions and related integration activities, and an increase of $9.1 million in equity compensation expense related to incremental grants in 2016 and accelerated vesting of awards due to retirements.incentive compensation. Our general and administrative expenses are comprised of the personnel, facilities and other infrastructure costs necessary to support our refineries.refineries and related logistics assets.
Depreciation and Amortization Expense—Depreciation and amortization expense totaled $209.8$397.5 million for the year ended December 31, 2016,2019 (including $386.7 million recorded within Cost of sales), compared to $191.1$340.3 million for the year ended December 31, 2015,2018 (including $329.7 million recorded within Cost of sales), an increase of $18.7$57.2 million. The increase was a result of additional depreciation expense associated with the assets acquired in the Chalmette and Torrance Acquisitions and a general increase in our fixed asset base due to capital projects and turnarounds completed since 2015.during 2019 and 2018, as well as accelerated amortization related to the Delaware City and Torrance refinery turnarounds, which were completed in the first half of 2019.
Change in Fair Value of Catalyst LeasesObligations— Change in the fair value of catalyst leasesobligations represented a gainloss of $1.4$9.7 million for the year ended December 31, 2016,2019, compared to a gain of $10.2$5.6 million for the year ended December 31, 2015. This gain relates2018. These gains and losses relate to the change in value of the precious metals underlying the sale and leaseback of our refineries’ precious metals catalyst,metal catalysts, which we are obligated to return or repurchase at fair market value on the leasecatalyst financing arrangement termination dates.
Interest Expense, net— Interest expense totaled $129.5$108.7 million for the year ended December 31, 2016,2019, compared to $88.2$127.1 million for the year ended December 31, 2015, an increase2018, or a decrease of $41.3$18.4 million. The increaseThis decrease is mainly attributable to higher interest costs associated withlower outstanding revolver borrowings for the issuance of the 2023 Senior Secured Notes in November 2015, increased interest expense related to the affiliate notes payable and the drawdown on our Revolving Loan to partially fund the Torrance Acquisition in July 2016, partially offset by lower letter of credit fees.year ended December 31, 2019. Interest expense includes interest on long-term debt, and notes payable, costs related to the sale and leaseback of our precious metals catalyst,metal catalysts, financing costs associated with the A&RInventory Intermediation Agreements with J. Aron, letter of credit fees associated with the purchase of certain crude oils and the amortization of deferred financing costs.
Income Tax Expense— As we are a limited liability company treated as a “flow-through” entity for income tax purposes, our consolidated financial statements generally do not include a benefit or expense for income taxes for the years ended December 31, 20162019 and 20152018, respectively, apart from the income tax attributable to two subsidiaries acquired in connection with the acquisition of our Chalmette Refiningrefinery and PBF Ltd. thatThese subsidiaries are treated as C-Corporations for income tax purposes. The two Chalmette subsidiaries incurred approximately $1.4 million of income tax expense and PBF Holding incurredAn income tax benefit of approximately $8.4$8.3 million attributable to PBF Ltdwas recorded for the year ended December 31, 2016. In addition, we recorded $30.7 million of incremental2019 in comparison to income tax expense of $8.0 million recorded for the year ended December 31, 2018 primarily attributable to volatility in 2016 relating to a correctionthe results of prior period income taxes.our taxable subsidiaries.
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Non-GAAP Financial Measures
Management uses certain financial measures to evaluate our operating performance that are calculated and presented on the basis of methodologies other than in accordance with GAAP (“Non-GAAP”). These measures should not be considered a substitute for, or superior to, measures of financial performance prepared in accordance with GAAP, and our calculations thereof may not be comparable to similarly entitled measures reported by other companies.
Special Items
The Non-GAAP measures presented include EBITDA excluding special items and gross refining margin excluding special items. The specialSpecial items for the periods presented relate to an LCM inventory adjustment andadjustments, debt extinguishment costs, (as further explainedchanges in “Notesfair value of contingent consideration, gain on sale of hydrogen plants, severance costs related to Non-GAAP Financial Measures” belowreductions in workforce, impairment expense, gains on page 68).sale of assets at our Torrance 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.
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Gross Refining Margin and Gross Refining Margin Excluding Special Items
Gross refining margin is defined as consolidated gross margin excluding refinery depreciation and operating expensesexpense related to the refineries. We believe both gross refining margin and gross refining margin excluding special items are important measures of operating performance and provide useful information to investors because they are helpful metric comparisons to the industry refining margin benchmarks, as the refining margin benchmarks do not include a charge for refinery operating expenses and depreciation. In order to assess our operating performance, we compare our gross refining margin (revenue(revenues less cost of products and other) to industry refining margin benchmarks and crude oil prices as defined in the table below.
Neither gross refining margin nor gross refining margin excluding special items should be considered an alternative to consolidated gross margin, operating income from operations, net cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Gross refining margin and gross refining margin excluding special items presented by other companies may not be comparable to our presentation, since each company may define these terms differently.
The following table presents our GAAP calculation of gross margin and a reconciliation of gross refining margin to the most directly comparable GAAP financial measure, consolidated gross margin, on a historical basis, as applicable, for each of the periods indicated (in thousands,millions, except per barrel amounts):
| Year Ended December 31, | |||||||||||||||||||||
| 2017 | 2016 | 2015 | |||||||||||||||||||
| $ | per barrel of throughput | $ | per barrel of throughput | $ | per barrel of throughput | ||||||||||||||||
| Calculation of gross margin: | |||||||||||||||||||||
| Revenues | $ | 21,772,478 | $ | 73.88 | $ | 15,908,537 | $ | 59.72 | $ | 13,123,929 | $ | 69.66 | |||||||||
| Less: Cost of products and other | 19,095,827 | 64.80 | 13,765,088 | 51.67 | 11,611,599 | 61.64 | |||||||||||||||
| Less: Refinery operating expense | 1,627,616 | 5.52 | 1,390,582 | 5.22 | 889,368 | 4.72 | |||||||||||||||
| Less: Refinery depreciation expense | 254,271 | 0.86 | 204,005 | 0.77 | 181,423 | 0.96 | |||||||||||||||
| Gross margin | $ | 794,764 | $ | 2.70 | $ | 548,862 | $ | 2.06 | $ | 441,539 | $ | 2.34 | |||||||||
| Reconciliation of gross margin to gross refining margin: | |||||||||||||||||||||
| Gross margin | $ | 794,764 | $ | 2.70 | $ | 548,862 | $ | 2.06 | $ | 441,539 | $ | 2.34 | |||||||||
| Add: Refinery operating expense | 1,627,616 | 5.52 | 1,390,582 | 5.22 | 889,368 | 4.72 | |||||||||||||||
| Add: Refinery depreciation expense | 254,271 | 0.86 | 204,005 | 0.77 | 181,423 | 0.96 | |||||||||||||||
| Gross refining margin | $ | 2,676,651 | $ | 9.08 | $ | 2,143,449 | $ | 8.05 | $ | 1,512,330 | $ | 8.02 | |||||||||
| Special items: | |||||||||||||||||||||
Add: Non-cash LCM inventory adjustment (1) | (295,532 | ) | (1.00 | ) | (521,348 | ) | (1.96 | ) | 427,226 | 2.27 | |||||||||||
| Gross refining margin excluding special items | $ | 2,381,119 | $ | 8.08 | $ | 1,622,101 | $ | 6.09 | $ | 1,939,556 | $ | 10.29 | |||||||||
| Year Ended December 31, | |||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||||||||||||||
| $ | per barrel of throughput | $ | per barrel of throughput | $ | per barrel of throughput | ||||||||||||||||||||||||
| Calculation of consolidated gross margin: | |||||||||||||||||||||||||||||
| Revenues | $ | 15,045.0 | $ | 56.49 | $ | 24,468.9 | $ | 81.45 | $ | 27,164.0 | $ | 87.60 | |||||||||||||||||
| Less: Cost of sales | 16,881.4 | 63.39 | 23,738.7 | 79.01 | 26,729.1 | 86.21 | |||||||||||||||||||||||
| Consolidated gross margin | $ | (1,836.4) | $ | (6.90) | $ | 730.2 | $ | 2.44 | $ | 434.9 | $ | 1.39 | |||||||||||||||||
| Reconciliation of consolidated gross margin to gross refining margin: | |||||||||||||||||||||||||||||
| Consolidated gross margin | $ | (1,836.4) | $ | (6.90) | $ | 730.2 | $ | 2.44 | $ | 434.9 | $ | 1.39 | |||||||||||||||||
| 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: (1) | |||||||||||||||||||||||||||||
| 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 on page 68Measures.
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EBITDA, EBITDA Excluding Special Items and Adjusted EBITDA
Our management uses EBITDA (earnings before interest, income taxes, depreciation and amortization), EBITDA excluding special items and Adjusted EBITDA as measures of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with our board of directors, creditors, analysts and investors concerning our financial performance. Our outstanding indebtedness for borrowed money and other contractual obligations also include similar measures as a basis for certain covenants under those agreements which may differ from the Adjusted EBITDA definition described below.
EBITDA, EBITDA excluding special items and Adjusted EBITDA are not presentations made in accordance with GAAP and our computation of EBITDA, EBITDA excluding special items and Adjusted EBITDA may vary from others in our industry. In addition, Adjusted EBITDA contains some, but not all, adjustments that are taken into account in the calculation of the components of various covenants in the agreements governing our senior notes and other credit facilities. EBITDA, EBITDA excluding special items and Adjusted EBITDA should not be considered as alternatives to operating income (loss)from operations or net income (loss) 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 equity-basedstock-based compensation expense, gains (losses) from certain derivative activities and contingent consideration, the non-cash change in the deferralfair value of gross profit related to thecatalyst obligations, gain on sale of certain finished products, andhydrogen plants, the write down of inventory to the LCM, and debt extinguishment costs related to refinancing activities. 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 a comparative measure.measures. EBITDA, EBITDA excluding special items and Adjusted EBITDA also have limitations as analytical tools and should not be considered in isolation, or as a substitute for analysis of our results as
reported under GAAP. Some of these limitations include that EBITDA, EBITDA excluding special items and Adjusted EBITDA:
•do not reflect depreciation expense or our cash expenditures, or future requirements, for capital expenditures or contractual commitments;
•do not reflect changes in, or cash requirements for, our working capital needs;
•do not reflect our interest expense, or the cash requirements necessary to service interest or principal payments, on our debt;
•do not reflect realized and unrealized gains and losses from certain hedging activities, which may have a substantial impact on our cash flow;
•do not reflect certain other non-cash income and expenses; and
•exclude income taxes that may represent a reduction in available cash.
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The following tables reconcile net income (loss) as reflected in our results of operations to EBITDA, EBITDA excluding special items and Adjusted EBITDA for the periods presented (in thousands)millions):
| Year Ended December 31, | |||||||||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||||||||||||||||||||
| Reconciliation of net income (loss) to EBITDA and EBITDA excluding special items: | |||||||||||||||||||||||||||||||||||
| Net income (loss) | $ | (1,857.5) | $ | 388.2 | $ | 103.0 | |||||||||||||||||||||||||||||
| Add: Depreciation and amortization expense | 509.3 | 397.5 | 340.3 | ||||||||||||||||||||||||||||||||
| Add: Interest expense, net | 210.3 | 108.7 | 127.1 | ||||||||||||||||||||||||||||||||
| Add: Income tax (benefit) expense | 6.1 | (8.3) | 8.0 | ||||||||||||||||||||||||||||||||
| EBITDA | $ | (1,131.8) | $ | 886.1 | $ | 578.4 | |||||||||||||||||||||||||||||
Special Items: (1) | |||||||||||||||||||||||||||||||||||
| Add: Non-cash LCM inventory adjustment | 268.0 | (250.2) | 351.3 | ||||||||||||||||||||||||||||||||
| Add: Change in fair value of contingent consideration | (79.3) | — | — | ||||||||||||||||||||||||||||||||
| Add: Gain on sale of hydrogen plants | (471.1) | — | — | ||||||||||||||||||||||||||||||||
| Add: Gain on Torrance land sales | (8.1) | (33.1) | (43.8) | ||||||||||||||||||||||||||||||||
| Add: Impairment expense | 91.8 | — | — | ||||||||||||||||||||||||||||||||
| Add: LIFO inventory decrement | 83.0 | — | — | ||||||||||||||||||||||||||||||||
| Add: Severance costs and reconfiguration costs | 30.0 | — | — | ||||||||||||||||||||||||||||||||
| Add: Early railcar return expense | 12.5 | — | 52.3 | ||||||||||||||||||||||||||||||||
| Add: Debt extinguishment costs | 22.2 | — | — | ||||||||||||||||||||||||||||||||
| EBITDA excluding special items | $ | (1,182.8) | $ | 602.8 | $ | 938.2 | |||||||||||||||||||||||||||||
| Reconciliation of EBITDA to Adjusted EBITDA: | |||||||||||||||||||||||||||||||||||
| EBITDA | $ | (1,131.8) | $ | 886.1 | $ | 578.4 | |||||||||||||||||||||||||||||
| Add: Stock based compensation | 29.3 | 30.5 | 20.2 | ||||||||||||||||||||||||||||||||
| Add: Change in fair value of catalyst obligations | 11.8 | 9.7 | (5.6) | ||||||||||||||||||||||||||||||||
Add: Non-cash LCM inventory adjustment (1) | 268.0 | (250.2) | 351.3 | ||||||||||||||||||||||||||||||||
Add: Change in fair value of contingent consideration (1) | (79.3) | — | — | ||||||||||||||||||||||||||||||||
Add: Gain on sale of hydrogen plants (1) | (471.1) | — | — | ||||||||||||||||||||||||||||||||
Add: Gain on Torrance land sales (1) | (8.1) | (33.1) | (43.8) | ||||||||||||||||||||||||||||||||
Add: Impairment expense (1) | 91.8 | — | — | ||||||||||||||||||||||||||||||||
Add: LIFO inventory decrement (1) | 83.0 | — | — | ||||||||||||||||||||||||||||||||
Add: Severance costs and reconfiguration costs (1) | 30.0 | — | — | ||||||||||||||||||||||||||||||||
Add: Early railcar return expense (1) | 12.5 | — | 52.3 | ||||||||||||||||||||||||||||||||
Add: Debt extinguishment costs (1) | 22.2 | — | — | ||||||||||||||||||||||||||||||||
| Adjusted EBITDA | $ | (1,141.7) | $ | 643.0 | $ | 952.8 | |||||||||||||||||||||||||||||
| Year Ended December 31, | |||||||||||||
| 2017 | 2016 | 2015 | |||||||||||
| Reconciliation of net income to EBITDA and EBITDA excluding special items: | |||||||||||||
| Net income | $ | 457,200 | $ | 235,886 | $ | 187,294 | |||||||
| Add: Depreciation and amortization expense | 267,235 | 209,840 | 191,110 | ||||||||||
| Add: Interest expense, net | 122,628 | 129,536 | 88,194 | ||||||||||
| Add: Income tax (benefit) expense | (10,783 | ) | 23,689 | 648 | |||||||||
| EBITDA | $ | 836,280 | $ | 598,951 | $ | 467,246 | |||||||
| Special Items: | |||||||||||||
Add: Non-cash LCM inventory adjustment (1) | (295,532 | ) | (521,348 | ) | 427,226 | ||||||||
Add: Debt extinguishment costs (1) | 25,451 | — | — | ||||||||||
| EBITDA excluding special items | $ | 566,199 | $ | 77,603 | $ | 894,472 | |||||||
| Reconciliation of EBITDA to Adjusted EBITDA: | |||||||||||||
| EBITDA | $ | 836,280 | $ | 598,951 | $ | 467,246 | |||||||
| Add: Stock based compensation | 21,503 | 18,296 | 9,218 | ||||||||||
Add: Non-cash LCM inventory adjustment (1) | (295,532 | ) | (521,348 | ) | 427,226 | ||||||||
| Add: Non-cash change in fair value of catalyst leases | 2,247 | (1,422 | ) | (10,184 | ) | ||||||||
Add: Debt extinguishment costs (1) | 25,451 | — | — | ||||||||||
| Adjusted EBITDA | $ | 589,949 | $ | 94,477 | $ | 893,506 | |||||||
——————————
See Notes to Non-GAAP Financial Measures on page 68Measures.
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Notes to Non-GAAP Financial Measures
The following notes are applicable to the Non-GAAP Financial Measures above:
(1) Special items:
LCM inventory adjustment - LCM is a GAAP requirement related to inventory valuation that mandates inventory to be stated at the lower of cost or market. Our inventories are stated at the lower of cost or market. Cost is determined using the LIFO inventory valuation methodology, in which the most recently incurred costs are charged to cost of sales and inventories are valued at base layer acquisition costs. Market is determined based on an assessment of the current estimated replacement cost and net realizable selling price of the inventory. In periods where the market price of our inventory declines substantially, cost values of inventory may exceed market values. In such instances, we record an adjustment to write down the value of inventory to market value in accordance with GAAP. In subsequent periods, the value of inventory is reassessed and an LCM inventory adjustment is recorded to reflect the net change in the LCM inventory reserve between the prior period and the current period. The net impact of these LCM inventory adjustments are included in income from operations, but are excluded from the operating results presented, as applicable, in order to make such information comparable between periods.
The following table includes the lower of cost or marketLCM inventory reserve as of each date presented (in thousands)millions):
| 2017 | 2016 | 2015 | 2020 | 2019 | 2018 | |||||||||||||||||||||||
| January 1, | $ | 595,988 | $ | 1,117,336 | $ | 690,110 | January 1, | $ | 401.6 | $ | 651.8 | $ | 300.5 | |||||||||||||||
| December 31, | 300,456 | 595,988 | 1,117,336 | December 31, | 669.6 | 401.6 | 651.8 | |||||||||||||||||||||
The following table includes the corresponding impact of changes in the lower of cost or marketLCM inventory reserve on both operating income (loss) from operations and net income (loss) for the periods presented (in thousands)millions):
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| Net LCM inventory adjustment (charge) benefit in both income (loss) from operations and net income (loss) | $ | (268.0) | $ | 250.2 | $ | (351.3) | |||||||||||
| Year Ended December 31, | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Net LCM inventory adjustment benefit (charge) in both operating and net income | $ | 295,532 | $ | 521,348 | $ | (427,226 | ) | ||||
Gain on sale of hydrogen plants - During the year ended December 31, 2017.2020, we recorded a gain on the sale of five hydrogen plants. The gain increased income from operations and net income by $471.1 million. There were no such gains in the years ended December 31, 2019 and December 31, 2018.
Gain on Torrance land sales - During the years ended December 31, 2020, December 31, 2019 and December 31, 2018, we recorded gains on the sale of three separate parcels of real property acquired as part of the Torrance refinery, but not part of the refinery itself. The gain on sale increased income from operations and net income by $8.1 million, $33.1 million and $43.8 million during the years ended December 31, 2020, December 31, 2019 and December 31, 2018, respectively.
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Impairment expense - During the year ended December 31, 2020, we recorded an impairment charge which decreased income from operations and net income by $91.8 million, resulting from the write-down of certain assets as a result of the East Coast Refining Reconfiguration and project abandonments. There were no such charges during the years ended December 31, 2019 and December 31, 2018.
LIFO inventory decrement - As part of our overall reduction in throughput in 2020 and our reduction in inventory volume as of December 31, 2020, the Company recorded a charge to cost of products and other related to a LIFO inventory layer decrement. The majority of the decrement related to our East Coast LIFO inventory layer and the reduction to our East Coast inventory experienced as part of the East Coast Refining Reconfiguration. These charges decreased income from operations and net income by $83.0 million. Decrements recorded in the years ended December 31, 2019 and December 31, 2018 were not significant.
Turnaround acceleration costs - During the year ended December 31, 2020, we accelerated the recognition of turnaround amortization associated with units that were temporarily idled as part of the East Coast Refining Reconfiguration. These costs decreased income from operations and net income by $56.2 million. There were no such costs in the years ended December 31, 20162019 and December 31, 2015.2018.
Severance and reconfiguration costs - During the year ended December 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. There were no such costs in the years ended December 31, 2019 and December 31, 2018. During the year ended December 31, 2020, we recorded reconfiguration charges related to the temporary idling of certain assets as part of our East Coast Refining System. These charges decreased income from operations and net income by $5.3 million. There were no such costs in the years ended December 31, 2019 and December 31, 2018.
Early return of railcars - During the years ended December 31, 2020 and December 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, during the year ended December 31, 2020. These charges decreased income from operations and net income by $52.3 million, during the year ended December 31, 2018. There were no such expenses recorded in the year ended December 31, 2019.
Debt extinguishment costs - During the year ended December 31, 2020, we recorded debt extinguishment costs which decreased net income by $22.2 million related to the redemption of the 2023 Senior Secured Notes. There were no such costs in the years ended December 31, 2019 and December 31, 2018.
Liquidity and Capital Resources
Overview
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Cash Flow Analysis
Cash Flows from Operating Activities
Net cash provided byused in operating activities was $471.1$820.0 million for the year ended December 31, 20172020 compared to net cash provided by operating activities of $551.6$789.6 million for the year ended December 31, 2016.2019. Our operating cash flows for the year ended December 31, 20172020 included our net incomeloss of $457.2$1,857.5 million, depreciationgain on sale of assets of $477.8 million mainly related to the sale of the hydrogen plants and amortizationthe sale of $274.7 million, pension and other post-retirement benefits costs of $42.2 million, debt extinguishment costs of $25.5 million, equity-based compensation of $21.5 million,land at our Torrance refinery, net non-cash impact relating to the change in the fair value of our inventory repurchase obligations of $13.8$12.6 million, $5.7and change in the fair value of the contingent consideration associated with the Martinez Acquisition of $79.3 million, partially offset by depreciation and amortization of $523.8 million, a non-cash charge of $268.0 million related to an LCM inventory adjustment, impairment expense of $91.8 million, pension and other post-retirement benefits costs of $55.7 million, stock-based compensation of $29.3 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 $7.3 million. In addition, net changes in operating assets and liabilities reflects cash inflows of $597.3 million driven by the timing of inventory purchases, payments for accrued expenses and accounts payables and collections of accounts receivables. Our operating cash flows for the year ended December 31, 2019 included our net income of $388.2 million, depreciation and amortization of $404.4 million, pension and other post-retirement benefits costs of $44.8 million, stock-based compensation of $30.5 million, non-cash charges relating to the change in the fair value of our inventory repurchase obligations of $25.4 million, changes in the fair value of our catalyst obligations of $9.7 million and distributions receivedfrom our equity method investment in excessTVPC of $7.9 million, partially offset by a non-cash benefit of $250.2 million relating to an LCM inventory adjustment, a gain on sale of assets of $29.9 million, deferred income taxes of $8.8 million and income from our equity method investment in TVPC changes in the fair value of our catalyst leases of $2.2 million and a loss on sale of assets of $1.5 million, partially offset by a non-cash benefit of $295.5 million relating to an LCM inventory adjustment and deferred income taxes of $12.5$7.9 million. In addition, net changes in operating assets and liabilities reflected usescash inflows of cash of $65.1 million driven by the
Net cash provided by operating activities was $551.6$789.6 million for the year ended December 31, 20162019 compared to net cash provided by operating activities of $652.4$695.0 million for the year ended December 31, 2015.2018. Our operating cash flows for the year ended December 31, 20152018 included our net income of $187.3$103.0 million, plus netdepreciation and amortization of $346.7 million, a non-cash chargescharge of $351.3 million relating to an LCM inventory adjustment, pension and other post-retirement benefits costs of $427.2$47.4 million, depreciationstock-based compensation of $20.2 million, deferred income taxes of $7.2 million and amortizationdistributions from our equity method investment in TVPC of $199.4$17.8 million, partially offset by a gain on sale of assets of $43.1 million, non-cash charges relating to the change in the fair value of our inventory repurchase obligations of $63.4$31.8 million, pension and other post-retirement benefits costsincome from our equity method investment in TVPC of $27.0$17.8 million and equity-based compensation of $9.2 million, partially offset by the changechanges in the fair value of our catalyst leasesobligations of $10.2 million, and gain on sale of assets of $1.0$5.6 million. In addition, net changes in operating assets and liabilities reflected uses of cash of approximately $249.9$100.3 million driven by the timing of inventory purchases, payments for accrued expenses and accounts payable and collections of accounts receivable.receivables.
Cash Flows from Investing Activities
Net cash used in investing activities was $641.6$1,014.2 million for the year ended December 31, 20172020 compared to net cash used in investing activities of $1,473.5$680.2 million for the year ended December 31, 2016.2019. The net cash flows used in investing activities for the year ended December 31, 20172020 was comprised of cash outflows of $1,176.2 million used to fund the Martinez Acquisition, capital expenditures totaling $232.7$183.9 million, expenditures for refinery turnarounds of $379.1$188.1 million, and expenditures for other assets of $31.1$9.1 million, partially offset by proceeds from sale of assets of $543.1 million. Net cash used in investing activities for the year ended December 31, 2019 was comprised of cash outflows of $373.1 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 our Torrance refinery and a $1.3$0.6 million return of capital from our equity method investment in TVPC. The net cash flows used in investing activities for the year ended December 31, 2016 was comprised of cash outflows of $971.9 million used to fund the Torrance Acquisition, capital expenditures totaling $282.4 million, expenditures for turnarounds of $198.7 million, expenditures for other assets of $42.5 million and the final working capital settlement related to the acquisition of the Chalmette refinery of $2.7 million, partially offset by $24.7 million in proceeds from the sale of assets.
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Net cash used in investing activities was $1,473.5$680.2 million for the year ended December 31, 20162019 compared to $811.2$509.6 million for the year ended December 31, 2015. The net2018. Net cash used in investing activities for the year ended December 31, 20152018 was comprised of $565.3cash outflows of $277.3 million used in the acquisition of the Chalmette refinery,for capital expenditures, totaling $352.4 million, expenditures for refinery turnarounds of $53.6$266.0 million, and expenditures for other assets of $8.2$17.0 million, partially offset by $168.3proceeds of $48.3 million in proceeds fromrelated to the sale of assets.land at our Torrance refinery and a $2.4 million return of capital from our equity method investment in TVPC.
Cash Flows from Financing Activities
Net cash provided by financing activities was $70.0$2,641.2 million for the year ended December 31, 20172020 compared to net cash provided by financialfinancing activities of $633.8$92.0 million for the year ended December 31, 2016.2019. For the year ended December 31, 2017,2020, 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, proceeds from contributions from PBF LLC of $42.4 million, net borrowings under our Revolving Credit Facility of $900.0 million and proceeds from catalyst financing arrangements of $51.9 million, partially offset by distributions to members of $23.1 million, net settlements of precious metal catalyst obligations of $8.8 million, principal amortization payments of the PBF Rail Term Loan of $7.2 million, payments on finance leases of $12.4 million and deferred financing costs and other of $0.2 million. For the year ended December 31, 2019, net cash provided by financing activities consisted primarily of a contribution from our parent of $97.0$228.5 million, payments received from affiliate notes receivable of $11.6 million, proceeds from catalyst leases of $10.8 million and cash proceeds of $21.4 million from the issuance of the 2025 Senior Notes net of cash paid to redeem the 2020 Senior Secured Notes, partially offset by distributions to members of $61.1$121.6 million, distributions to T&M and Collins shareholders of $1.8 million,principal amortization payments of principal under the PBF Rail Term Loan of $6.6$7.0 million, settlements of catalyst obligations of $6.5 million and repaymentsdeferred financing costs and other of our note payable of $1.2$1.4 million. Additionally, during the year ended December 31, 2017,2019, we borrowed and repaid $490.0$1,350.0 million under our Revolving LoanCredit Facility resulting in no net change to amounts outstanding for the year ended December 31, 2017. For the year ended December 31, 2016, net cash provided by financing activities consisted primarily of net proceeds from the Revolving Loan of $350.0 million, a contribution from our parent of $450.3 million, proceeds from the PBF Rail Term Loan of $35.0 million and proceeds from catalyst leases of $15.6 million, partially offset by distribution to members of $139.4 million, repayments of the Rail Facility of $67.5 million and net repayments of the affiliate notes payable of $10.1 million.2019.
Net cash provided by financing activities was $633.8$92.0 million for the year ended December 31, 20162019 compared to net cash provided byused in financing activities of $855.2$149.9 million for the year ended December 31, 2015.2018. For the year ended December 31, 2015,2018, net cash provided byused in financing activities consisted primarily of $500.0 million in proceeds from the 2023 Senior Secured Notes, capital contributionsnet repayments of $345.0 million, proceeds from affiliate notes payable of $347.8 million,
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Capitalization
Our capital structure was comprised of the following as of December 31, 20172020 (in millions):
| December 31, 2017 | |||
| Debt, including current maturities: | |||
| 7.25% Senior Notes due 2025 | 725.0 | ||
7.00% Senior Notes due 2023 (1) | 500.0 | ||
| Revolving Loan | 350.0 | ||
| PBF Rail Term Loan | 28.4 | ||
| Note payable | 5.6 | ||
| Catalyst leases | 59.0 | ||
| Total debt | 1,668.0 | ||
| Unamortized deferred financing costs | (25.2 | ) | |
| Total debt, net of unamortized deferred financing costs | 1,642.8 | ||
| Total Equity | 3,184.1 | ||
| Total Capitalization | $ | 4,826.9 | |
| Total Debt to Capitalization Ratio | 34 | % | |
| December 31, 2020 | |||||
Debt, including current maturities: (1) | |||||
| 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 | ||||
| Total debt | 3,984.9 | ||||
| Unamortized deferred financing costs | (45.3) | ||||
| Unamortized premium | 0.6 | ||||
| Total debt, net of unamortized deferred financing costs and premium | 3,940.2 | ||||
| Total Equity | 2,090.8 | ||||
Total Capitalization (2) | $ | 6,031.0 | |||
| Total Debt to Capitalization Ratio | 65 | % | |||
____________________________
(1) These notes became unsecured following Refer to “Note 9 - Credit Facilities and Debt” of our Notes to Consolidated Financial Statements for further discussion related to debt.
(2) Total Capitalization refers to the occurrencesum of the “Collateral Fall-Away Event” as defined under the indenture governing the 2025 Senior Notes, which occurred on May 30, 2017.
Revolving Credit Facilities Overview
| Total Commitment | Amount Borrowed as of December 31, 2020 | Outstanding Letters of Credit | Borrowing base Availability | Expiration date | ||||||||||||||||||||||||||||
| Revolving Credit Facility (a) | $ | 3,400.0 | $ | 900.0 | $ | 184.4 | $ | 2,759.2 | May 2023 | |||||||||||||||||||||||
___________________________
(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.
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| Total Capacity | Amount Borrowed as of December 31, 2017 | Outstanding Letters of Credit | Available Capacity | Expiration date | ||||||||||||||
| PBF Holding Revolving Loan (a) | $ | 2,635.0 | $ | 350.0 | $ | 586.3 | $ | 869.0 | August 2019 | |||||||||
Additional Information on Indebtedness
Our debt, including our revolving credit facility,Revolving Credit Facility, term loan and senior notes, include certain typical financial covenants and restrictions on our subsidiaries’ ability to, among other things, incur or guarantee new debt, engage in certain business activities including transactions with affiliates and asset sales, make investments or distributions, engage in mergers or pay dividends in certain circumstances. These covenants are subject to a number of important exceptions and qualifications. We are in compliance as of December 31, 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 89 - Credit Facilities and Debt” of our Notes to Consolidated Financial Statements.
The outbreak of the COVID-19 pandemic and certain developments in compliance withthe global oil markets began negatively impacting our covenants asliquidity beginning towards the end of December 31, 2017.
As of December 31, 2017,2020, our cash and cash equivalents totaled $526.2 million.
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 atsheet 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 PBF Energy’s 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 on April 17, 2020;
•In May and December 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 9 - Credit Facilities and Debt” of our Notes to Consolidated Financial Statements for additional details related to the notes offerings;
•Entered into catalyst financing arrangements on September 25, 2020 for net proceeds of approximately $51.9 million;
•As of December 31, 2017.2020 completed the operational reconfiguration of our East Coast Refining System comprised of our Delaware City and Paulsboro refineries. The reconfiguration resulted in the temporary idling of certain Paulsboro 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;
•On December 30, 2020, closed on a third-party sale of parcels of real property acquired as part of the Torrance refinery, but not part of the refinery itself, 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.
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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 Refining 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.
We may incur additional indebtedness in the future including additional secured indebtedness, subject to the satisfaction of any debt incurrence and, if applicable, lien incurrence limitation covenants in our existing financing agreements. Although we were in compliance with incurrence covenants during the year ended December 31, 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 make new investments 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 members.
Working Capital
Working capital at December 31, 20172020 was approximately $1,310.3$1,265.4 million, consisting of $3,749.0$3,819.1 million in total current assets and $2,438.7$2,553.7 million in total current liabilities. Working capital at December 31, 20162019 was $1,111.0$1,167.5 million, consisting of $3,154.3$3,766.4 million in total current assets and $2,043.3$2,598.9 million in total current liabilities. Working capital has increased primarily as a result of positive earnings, offset by capital expenditures, including turnaround costs, and distributions during the year ended December 31, 2017.2020 primarily as a result of proceeds from financing activities, partially offset by operating losses.
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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 theany 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 and feedstock supply agreementsoil from Saudi Aramco that is processed at our Paulsboro refinery. In connection with the acquisition of the Chalmette refinery we entered into a contract with PDVSA tofor the supply of 40,000 bpd to 60,000 bpd of crude oil that can be processed at any of our East andor Gulf Coast refineries. We have not sourced crude oil under this arrangementagreement since the third quarter of 2017 aswhen PDVSA has suspended deliveries due to the parties’ inability to agree to mutually acceptable payment terms.
terms and because of U.S. government sanctions against PDVSA. Notwithstanding the suspension, the U. S. government sanctions imposed against PDVSA and Venezuela prevents us from purchasing crude oil under this agreement. In connection with the closing of the acquisition of the Torrance Acquisition,refinery, we entered into a crude supply agreement with ExxonMobil for approximately 60,000 bpd of crude oil that can be processed at our Torrance refinery. We currently purchase all of our crude and feedstock needs independently from a variety of suppliers on the spot market or through term agreements for our Delaware City and Toledo refineries.
We have entered into various five-year crude supply agreements with Shell Oil Products for approximately 145,000 bpd, in the aggregate, to support our West Coast and Mid-Continent refinery operations. In addition, we have entered into certain offtake agreements for our West Coast system with the same counterparty for clean products with varying terms up to 15 years.
Inventory Intermediation Agreements
At December 31, 2017,2020, the LIFO value of intermediates and finished products owned bythe J. Aron Products included within inventory onInventory in our balance sheetConsolidated Balance Sheets was $311.5$266.5 million. We accrue a corresponding liability for such crude oil, intermediates and finished products.
Capital Spending
On February 1, 2020 we acquired the Martinez 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.
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Contractual Obligations and Commitments
The following table summarizes our material contractual payment obligations as of December 31, 20172020 (in thousands):millions).
| Payments due by period | |||||||||||||||||||||||||||||||||||||||||||||||||
| Payments due by period | Total | Less than 1 year | 1-3 Years | 3-5 Years | More than 5 years | ||||||||||||||||||||||||||||||||||||||||||||
| Credit Facilities and debt (a) | Credit Facilities and debt (a) | $ | 3,984.8 | $ | 86.2 | $ | 923.6 | $ | 1,975.0 | $ | 1,000.0 | ||||||||||||||||||||||||||||||||||||||
| Interest payments on credit facilities and debt (a) | Interest payments on credit facilities and debt (a) | 1,290.7 | 264.2 | 504.2 | 372.3 | 150.0 | |||||||||||||||||||||||||||||||||||||||||||
| Total | Less than 1 year | 1-3 Years | 3-5 Years | More than 5 years | |||||||||||||||||||||||||||||||||||||||||||||
| Long-term debt (a) | $ | 1,662,414 | $ | 16,065 | $ | 392,983 | $ | 28,366 | $ | 1,225,000 | |||||||||||||||||||||||||||||||||||||||
| Interest payments on debt facilities (a) | 620,953 | 96,443 | 182,199 | 175,905 | 166,406 | ||||||||||||||||||||||||||||||||||||||||||||
| Operating Leases (b) | 396,681 | 105,281 | 170,650 | 90,773 | 29,977 | ||||||||||||||||||||||||||||||||||||||||||||
| Leases and other rental-related commitments (b) | Leases and other rental-related commitments (b) | 3,220.1 | 392.8 | 667.0 | 586.1 | 1,574.2 | |||||||||||||||||||||||||||||||||||||||||||
| Purchase obligations (c): | Purchase obligations (c): | ||||||||||||||||||||||||||||||||||||||||||||||||
| Crude and Feedstock Supply and Inventory Intermediation Agreements | 10,201,901 | 2,816,889 | 4,478,361 | 2,906,651 | — | 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 | 1,078,328 | 192,078 | 229,368 | 165,871 | 491,011 | Other Supply and Capacity Agreements | 254.6 | 83.9 | 53.0 | 35.1 | 82.6 | ||||||||||||||||||||||||||||||||||||||
| AB32 Settlement Obligations | AB32 Settlement Obligations | 249.7 | 249.7 | — | — | — | |||||||||||||||||||||||||||||||||||||||||||
| Minimum volume commitments with PBFX (d) | 1,444,175 | 223,830 | 439,404 | 340,273 | 440,668 | Minimum volume commitments with PBFX (d) | 467.8 | 115.7 | 178.3 | 173.8 | — | ||||||||||||||||||||||||||||||||||||||
| Construction obligations | 25,382 | 25,382 | — | — | — | Construction obligations | 31.1 | 31.1 | — | — | — | ||||||||||||||||||||||||||||||||||||||
| Environmental obligations (e) | 152,037 | 7,622 | 15,860 | 14,769 | 113,786 | Environmental obligations (e) | 158.2 | 11.7 | 33.8 | 17.7 | 95.0 | ||||||||||||||||||||||||||||||||||||||
| Pension and post-retirement obligations (f) | 336,076 | 10,303 | 21,818 | 24,939 | 279,016 | Pension and post-retirement obligations (f) | 312.5 | 36.9 | 34.2 | 28.5 | 212.9 | ||||||||||||||||||||||||||||||||||||||
| Total contractual cash obligations | $ | 15,917,947 | $ | 3,493,893 | $ | 5,930,643 | $ | 3,747,547 | $ | 2,745,864 | Total contractual cash obligations | $ | 24,376.1 | $ | 6,151.6 | $ | 9,360.2 | $ | 5,749.6 | $ | 3,114.7 | ||||||||||||||||||||||||||||
(a) Long-term DebtCredit facilities, debt and Interest Payments on Debt Facilitiesinterest payments
Interest payments on debt facilities include cash interest payments on the 2025 Senior Secured Notes, 2028 Senior Notes and 2025 Senior Notes, catalyst leasefinancing obligations, PBF Rail Term Loan, plus cash payments for the commitment feefees on the unused portion on our Revolving LoanCredit Facility and letter of credit fees on the letters of credit outstanding at December 31, 2017.2020. With the exception of certain catalyst leasesour PBF Rail Term Loan and our note payable,catalyst financing obligations, we have no long-term debt maturing before 20192023 as of December 31, 2017.2020.
(b) Operating Leases and other rental-related commitments
We enter into operating leases and other rental-related agreements in the normal course of business, somebusiness. As described in “Note 2 - Summary of Significant Accounting Policies” of our Notes to Consolidated Financial Statements, we adopted new guidance on leases effective January 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 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 purchasebefore expiration of the leased item.lease terms. Future operating lease obligations would change if we chose to exercise renewal options andor 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, excludingincluding short-term lease expense and affiliate leases with affiliates which are reflected separately within Minimum volume commitments with PBFX as described below.PBFX. The variable component could be significant. Our operatingIn addition, we have entered into certain
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agreements for the supply of hydrogen that contain both lease obligations are further explained inand non-lease components. The table above also includes such non-lease components of these agreements. See “Note 1213 - Commitments and Contingencies”Leases” of our Notes to the Consolidated Financial Statements. In supportStatements 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 rail strategy, we have at times entered into agreementsassets (also referred to lease or purchase crude railcars. A portionas land easements) in the normal course of these railcars were purchased viabusiness. Our obligations regarding such land easements are included within Leases and other rental-related commitments in the Rail Facility entered into during 2014, which was repaid in full and terminated in connection with the execution of the PBF Rail Term Loan in 2016. Certain of these railcars were subsequently sold to third parties, which have leased the railcars back to us for periods of between four and seven years.table above.
(c) Purchase Obligationsobligations
We have obligations to repurchase certain intermediates and refined productsthe J. Aron Products under separate inventory intermediation agreementsthe Inventory Intermediation Agreements with J. Aron as further explained in “Note 2 - Summary of Significant Accounting Policies”, “Note 45 - Inventories” and “Note 78 - Accrued Expenses” of our Notes to the 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 20172020 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 of December 31, 2017.2020.
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 at December 31, 2020. See “Note 8 - Accrued Expenses” of our Notes to Consolidated Financial Statements for details.
The amounts included in this table exclude our crude supply agreement with PDVSA. We have not sourced crude oil under this agreement since the third quarter of 2017 as PDVSA has suspended deliveries due to the parties inability to agree to mutually acceptable payment terms and because of U.S. government sanctions against PDVSA.
(d) Minimum commitmentsVolume Commitments with PBFX
We have minimum obligations under our commercial agreements entered into with PBFX. Refer to “Note 11 - Related Party Transactions” and “Note 12 - Commitments and Contingencies” of our Notes to the Consolidated Financial Statements for a detailed explanation of each of these agreements.agreements and quantification of minimum amounts due in subsequent periods, respectively.
Included in the table above are our obligations related to the minimum volume commitments required under these commercial agreements.agreements that were determined to not be leases under GAAP. Any incremental volumes above any minimumsminimum throughput under these agreements would increase our obligations. Our obligation with respect to certain crude oil and refined product storage agreements is based on the estimated shell capacity of the storage tanks to be utilized.
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(e) Environmental Obligationsobligations
In connection with the Paulsboro acquisition,certain of our refinery acquisitions, we have assumed certain environmental remediation obligations to address existing soil and groundwater contaminationmatters that were outstanding at the site and recorded as a liabilitytime of such acquisitions. In addition, in the amount of $10.3 million which reflects the present value of the current estimated cost of the remediation obligations assumed based on investigative work to-date. The undiscounted estimated costs related to these environmental remediation obligations were $15.8 million as of December 31, 2017.
(f) Pension and Post-retirement Obligationspost-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 1516 - Employee Benefit Plans” of our Notes to Consolidated Financial Statements.
(g) Contingent Consideration
Contingent consideration includes our obligations to pay certain contractual earn-outs entered into as part of the Martinez acquisition. As of December 31, 2020 we do not expect to achieve any earn-out obligations and therefore we have excluded this potential obligation from the table above.
(h) Tax Receivable Agreement ObligationsObligation
The Contractual Obligations and Commitments Tabletable above does not include tax distributions or other distributions that we expect to make on account of PBF Energy’s obligationsobligation under the Tax Receivable Agreement.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements as of December 31, 2017,2020, other than outstanding letters of credit in the amount of approximately $586.3 million and operating leases.
Critical Accounting Policies
The following summary provides further information about our critical accounting policies that involve critical accounting estimates and should be read in conjunction with “Note 2 - Summary of Significant Accounting Policies” of our Notes to Consolidated Financial Statements, “Item 8. Financial Statements and Supplementary Data.”Statements. The following accounting policies involve estimates that are considered critical due to the level of subjectivity and judgment involved, as well as the impact on our financial position and results of operations. We believe that all of our estimates are reasonable. Unless otherwise noted, estimates of the sensitivity to earnings that would result from changes in the assumptions used in determining our estimates is not practicable due to the number of assumptions and contingencies involved, and the wide range of possible outcomes.
Inventory
Inventories are carried at the lower of cost or market. The cost of crude oil, feedstocks, blendstocks and refined products is determined under the LIFO method using the dollar value LIFO method with increments valued based on average cost during the year. The cost of supplies and other inventories is determined principally on the weighted average cost method. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years that inventory volumes decline as the result of charging cost of sales with LIFO inventory costs generated in prior periods. At December 31, 20172020 and 2016,2019, market values had fallen below historical LIFO inventory costs and, as a result, we recorded lower of costan LCM or market inventory valuation reserves of $300.5$669.6 million and $596.0$401.6 million, respectively. The $300.5 million lower of costLCM or market inventory valuation reserve, as of December 31, 2017, 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
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decreases in overall inventory values could result in additional charges to cost of products sold should the lower of costLCM or market inventory valuation reserve be increased.
Environmental Matters
Liabilities for future clean-up costs are recorded when environmental assessments and/or clean-up efforts are probable and the costs can be reasonably estimated. Other than for 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. Additionally, in connection with the Torrance Acquisition on July 1, 2016, we assumed certain pre-existing environmental liabilities. 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.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 fivesix 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.
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Derivative Instruments
We are exposed to market risk, primarily related to changes in commodity prices for the crude oil and feedstocks we useused in the refining process, as well as the prices of the refined products we sell.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 balance sheetConsolidated 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 in PBF 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 of December 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.
Recent Accounting Pronouncements
Refer to “Note 2 - Summary of Significant Accounting Policies” of our Notes to Consolidated Financial Statements, for additional Recently Issued Accounting Pronouncements.
Supplemental Guarantor Financial Information
As of December 31, 2020, PBF Services, DCR, PBF Power, PRC, Toledo Refining, Chalmette Refining, PBF Western Region, Torrance Refining, Martinez Refining, PBF International Inc. and PBF Investments are 100% owned subsidiaries of PBF Holding and serve as guarantors of the obligations under the 2025 Senior Secured Notes, 2025 Senior Notes and 2028 Senior Notes. These guarantees are full and unconditional and joint and several. PBF Holding serves as the “Issuer”. The indentures dated May 30, 2017 and January 24, 2020, among PBF Holding, PBF Finance, the guarantors party thereto, Wilmington Trust, National Association, as trustee and Deutsche Bank Trust Company Americas, as Paying Agent, Registrar, Transfer Agent and Authenticating Agent, and the indenture dated May 13, 2020, among PBF Holding, PBF Finance, the guarantors party thereto and Wilmington Trust, National Association, as Trustee, Paying Agent, Registrar, Transfer Agent, Authenticating Agent and Notes Collateral Agent, govern subsidiaries designated as “Guarantor Subsidiaries”. PBF Ltd, PBF Transportation Company LLC, PBF Rail Logistics Company LLC, MOEM Pipeline LLC, Collins, T&M, Torrance Basin Pipeline Company LLC, Torrance Logistics, Torrance Pipeline Company LLC, Martinez Terminal Company LLC, Martinez Pipeline Company LLC and PBFWR Logistics Holdings LLC are consolidated subsidiaries of the Company that are not guarantors of the 2025 Senior Secured Notes, 2025 Senior Notes and 2028 Senior Notes. The 2025 Senior Secured Notes, 2025 Senior Notes and 2028 Senior Notes were co-issued by PBF Finance. For purposes of the following information, PBF Finance is referred to as “Co-Issuer.” The Co-Issuer has no independent assets or operations.
The following tables present summarized information for the Issuer and the Guarantor Subsidiaries on a combined basis after elimination of (i) intercompany transactions and balances among the Issuer and the Guarantor Subsidiaries and (ii) equity in earnings from and investments in any subsidiary that is a non-guarantor.
| Summarized Balance Sheets (in millions) | December 31, 2020 | December 31, 2019 | |||||||||
| ASSETS | |||||||||||
Current Assets (1) | $ | 3,559.0 | $ | 3,500.0 | |||||||
| Non-Current Assets | 5,990.0 | 4,842.5 | |||||||||
| Due from non-guarantor subsidiaries | 13,813.0 | 12,311.4 | |||||||||
| LIABILITIES AND EQUITY | |||||||||||
Current liabilities (1) | $ | 2,350.0 | $ | 2,364.8 | |||||||
| Long-term liabilities | 5,411.0 | 2,300.6 | |||||||||
| Due to non-guarantor subsidiaries | 13,770.0 | 12,295.9 | |||||||||
| (1) Includes $4.9 million and $53.2 million of accounts receivables and accounts payables, respectively, related to transactions with PBFX as of December 31, 2020. Includes $6.5 million and $48.1 million of accounts receivables and accounts payables, respectively, related to transactions with PBFX as of December 31, 2019. Refer to “Note 11 - Related Party Transactions” of the Notes to Consolidated Financial Statements for further disclosures. | |||||||||||
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| Summarized Statements of Operations (in millions) | December 31, 2020 | December 31, 2019 | |||||||||||||||
| Revenues | $ | 14,732.0 | $ | 24,178.8 | |||||||||||||
| Cost of sales | 15,394.0 | 20,748.0 | |||||||||||||||
| Gross margin | (662.0) | 3,430.8 | |||||||||||||||
| Income (loss) from operations | (445.2) | 3,189.5 | |||||||||||||||
| Net income (loss) | (680.9) | 3,054.9 | |||||||||||||||
| Net income (loss) attributable to PBF Holding Company LLC | (680.6) | 3,054.8 | |||||||||||||||
| Non-guarantor intercompany sales with the Issuer and Guarantor subsidiaries | $ | 1,197.2 | $ | 2,759.1 | |||||||||||||
| Non-guarantor intercompany cost of sales with the Issuer and Guarantor subsidiaries | 20.6 | 92.4 | |||||||||||||||
Affiliate revenues related to transactions with PBFX (1) | 16.3 | 16.3 | |||||||||||||||
Affiliate expenses related to transactions with PBFX (1) | 289.4 | 300.9 | |||||||||||||||
| (1) Refer to “Note 11 - Related Party Transactions” of our Notes to Condensed Consolidated Financial Statements for further information. | |||||||||||||||||
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risks, including changes in commodity prices and interest rates. Our primary commodity price risk is associated with the difference between the prices we sell our refined products and the prices we pay for crude oil and other feedstocks. We may use derivative instruments to manage the risks from changes in the prices of crude oil and refined products, natural gas, interest rates, or to capture market opportunities.
Commodity Price Risk
Our earnings, cash flow and liquidity are significantly affected by a variety of factors beyond our control, including the supply of, and demand for, crude oil, other feedstocks, refined products and natural gas. The supply of and demand for these commodities depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, planned and unplanned downtime in refineries, pipelines and production facilities, production levels, the availability of imports, the marketing of competitive and alternative
fuels, and the extent of government regulation. As a result, the prices of these commodities can be volatile. Our revenues fluctuate significantly with movements in industry refined product prices, our cost of sales fluctuates significantly with movements in crude oil and feedstock prices and our operating expenses fluctuate with movements in the price of natural gas. We manage our exposure to these commodity price risks through our supply and offtake agreements as well as through the use of various commodity derivative instruments.
We may use non-trading derivative instruments to manage exposure to commodity price risks associated with the purchase or sale of crude oil and feedstocks, finished products and natural gas outside of our supply and offtake agreements. The derivative instruments we use include physical commodity contracts and exchange-traded and over-the-counter financial instruments. We mark-to-market our commodity derivative instruments and recognize the changes in their fair value in our statements of operations.
The negative impact of the unprecedented global health and economic crisis sparked by the COVID-19 pandemic, combined with uncertainty around future output levels of the world’s largest oil producers has increased unpredictability 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 reduction in demand for our refined products and abnormal volatility in oil commodity prices, which may continue for the foreseeable future.
At December 31, 20172020 and 2016,2019, we had gross open commodity derivative contracts representing 24.310.0 million barrels and 8.811.3 million barrels, respectively, with an unrealized net loss of $74.3$3.0 million and $3.5unrealized net gain of $0.2 million, respectively. The open commodity derivative contracts as of December 31, 20172020 expire at various times during 2018.2021.
We carry inventories of crude oil, intermediates and refined products (“hydrocarbon inventories”) on our balance sheet,Consolidated Balance Sheets, the values of which are subject to fluctuations in market prices. Our hydrocarbon inventories totaled approximately 30.128.2 million barrels and 29.430.2 million barrels at December 31, 20172020 and 2016,2019, respectively. The average cost of our hydrocarbon inventories was approximately $80.21$78.64 and $80.50$79.63 per barrel on a LIFO basis at December 31, 20172020 and 2016,2019, respectively, excluding the impact of LCM inventory adjustments of approximately $300.5$669.6 million and $596.0$401.6 million, respectively. If market prices of our inventory decline to a level below our average cost, we may be required to further write down the carrying value of our hydrocarbon inventories to market.
Our predominant variable operating cost is energy, in particular, the pricewhich is comprised primarily of utilities, natural gas and electricity. We are therefore sensitive to movements in natural gas prices. Assuming normal operating conditions, we annually consume a total of approximately 68between 75 million and 97 million MMBTUs of natural gas amongst our fivesix refineries as of December 31, 2017.2020. Accordingly, a $1.00 per MMBTU change in natural gas prices would increase or decrease our natural gas costs by approximately $68.0$75.0 million to $97.0 million.
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Compliance Program Price Risk
We are exposed to market risks related to the volatility in the price of credits needed to comply with various governmental and regulatory compliance programs, which includes RINs, required to comply with the RFS.Renewable Fuel Standard. Our overall RINs obligation is based on a percentage of our domestic shipments of on-road fuels as established by the EPA. To the degree we are unable to blend the required amount of biofuels to satisfy our RINs obligation, we must purchase RINs on the open market. To mitigate the impact of this risk on our results of operations and cash flows we may purchase RINs or other environmental credits when the price of these instruments is deemed favorable.
In addition, we are exposed to risks associated with complying with federal and state legislative and regulatory measures to address greenhouse gas and other emissions. Requirements to reduce emissions could result in increased costs to operate and maintain our facilities as well as implement and manage new emission controls and programs put in place. For example, AB32 in California requires the state to reduce its GHG emissions to 1990 levels by 2020. Compliance with such emission standards may require the purchase of emission credits or similar instruments.
Certain of these compliance contracts or instruments qualify as derivative instruments. We generally elect the normal purchase normal sale exception under ASC 815, Derivatives and Hedging, for such instruments,and therefore do not record these contracts at their fair value.
Interest Rate Risk
The maximum availabilitycommitment under our Revolving LoanCredit Facility is $2.64$3.4 billion. Borrowings under the Revolving LoanCredit Facility bear interest either at the Alternative Base Rate plus the Applicable Margin or at Adjusted LIBOR.LIBOR plus the Applicable Margin, all as defined in the Revolving Credit Agreement. If this facility was fully drawn, a 1.0% change in the interest rate would increase or decrease our interest expense by approximately $26.4$24.9 million annually.
We also have interest rate exposure in connection with our A&RInventory Intermediation Agreements under which we pay a time value of money charge based on LIBOR.
Credit Risk
We are subject to risk of losses resulting from nonpayment or nonperformance by our counterparties. We continue to closely monitor the creditworthiness of customers to whom we grant credit and establish credit limits in accordance with our credit policy.
Concentration Risk
For the year ended December 31, 2020, only one customer, Royal Dutch Shell, accounted for 10% or more of our revenues, (approximately 13%). For the years ended December 31, 2017, 20162019 and 2015,2018, no single customer accounted for 10% or more of our revenues, respectively.revenues.
As of December 31, 2017 and 2016, no2020, only one customer, Royal Dutch Shell, accounted for 10% or more of our total trade accounts receivable (approximately 17%) No single customer accounted for 10% or more of our total trade accounts receivable.receivable as of December 31, 2019.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this item is set forth beginning on page F-1 of this Annual Report on Form 10-K.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
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ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Exchange Act. Our internal control system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America. Due to its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
On February 1, 2020, we completed the Martinez Acquisition. As of December 31, 2020 we were in the process of integrating Martinez Refining’s operations, including internal controls over financial reporting and, therefore, management's evaluation and conclusion as to the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Annual Report on Form 10-K excludes any evaluation of the internal controls over financial reporting of the Martinez Refining. Martinez Refining accounts for approximately 8% of our total assets and approximately 13% of our total revenues as of the year ended December 31, 2020. During the first quarter of 2021 we completed the integration of Martinez Refining's operations, including internal controls over financial reporting.
Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2017,2020, using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework (2013). Based on such assessment, we concludemanagement concluded that as of December 31, 2017,2020, the Company’s internal control over financial reporting is effective.
This Annual Report on Form 10-K does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting as permitted by Item 308(b) of Regulation S-K for non-accelerated filers.
Changes in Internal Control Over Financial Reporting
On February 1, 2020, we completed the Martinez Acquisition. As of December 31, 2020 we were in the process of integrating Martinez Refining's operations, including internal controls over financial reporting. There has been no other change in our internal control over financial reporting during the quarter ended December 31, 20172020 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
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PART III
Explanatory Note:
We are a limited liability company wholly ownedwholly-owned and controlled by PBF LLC. PBF Energy is the sole managing member of PBF LLC. Our directors and executive officers are the executive officers of PBF Energy. The compensation paid to these executive officers is for services provided to both entities (i.e., they are not separately compensated for their services as an officer or director of PBF Holding). PBF Holding does not file a proxy statement. If the information were required it would be identical (other than as expressly set forth below) to the information contained in Items 10, 11, 12, 13 and 14 of the Annual Report on Form 10-K of PBF Energy that will appear in the Proxy Statement of PBF Energy furnished to its stockholders in connection with its 20182021 Annual Meeting. Such information is incorporated by reference in this Annual Report on Form 10-K.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERANCEGOVERNANCE
Information About Our Directors and Executive Officers of PBF Holding
The following is a list of our directors and executive officers as of March 9, 2018:
3, 2021:
| Name | Age (as of December 31, | Position | ||||||||||||
| Thomas J. Nimbley | Chief Executive Officer | |||||||||||||
| Matthew C. Lucey | President | |||||||||||||
| Erik Young | Senior Vice President, Chief Financial Officer | |||||||||||||
| Paul Davis | President, Western Region | |||||||||||||
| Thomas L. O’Connor | Senior Vice President, Commercial | |||||||||||||
| Herman Seedorf | Senior Vice President, | |||||||||||||
| Trecia Canty | Senior Vice President, General Counsel & Corporate Secretary | |||||||||||||
Messrs. Nimbley and Lucey and Ms. Canty serve as the sole directors of PBF Holding and PBF Finance. We believe that each of their experience as executive officers of PBF Holding make them qualified to serve as its directors.
Thomas J. Nimbley has served as our and PBF Energy’s Chief Executive Officer since June 2010 and was Executive Vice President, Chief Operating Officer from March 2010 through June 2010. In his capacity as our Chief Executive Officer, Mr. Nimbley also serves as a director and the Chief Executive Officer of certain of our subsidiaries and our affiliates, including Chairman of the Board of PBF GP. Prior to joining us, Mr. Nimbley served as a Principal for Nimbley Consultants LLC from June 2005 to March 2010, where he provided consulting services and assisted on the acquisition of two refineries. He previously served as Senior Vice President and head of Refining for Phillips Petroleum Company (“Phillips”) and subsequently Senior Vice President and head of Refining for ConocoPhillips (“ConocoPhillips”) domestic refining system (13 locations) following the merger of Phillips and Conoco Inc. Before joining Phillips at the time of its acquisition of Tosco Corporation (“Tosco”) in September 2001, Mr. Nimbley served in various positions with Tosco and its subsidiaries starting in April 1993.
Matthew C. Lucey has served as our and PBF Energy’s President since January 2015 and was our Executive Vice President from April 2014 to December 2014. Mr. Lucey served as our Senior Vice President, Chief Financial Officer from April 2010 to March 2014. Mr. Lucey joined us as Vice President, Finance in April 2008. Mr. Lucey is also a director of certain of PBF Energy’s subsidiaries, including PBF GP. Prior thereto, Mr. Lucey served as a Managing Director of M.E. Zukerman & Co., a New York-based private equity firm specializing in several sectors of the broader energy industry, from 2001 to 2008. Before joining M.E. Zukerman & Co., Mr. Lucey spent six years in the banking industry.
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Erik Young has served as our and PBF Energy’s Senior Vice President and Chief Financial Officer since April 2014 after joining us in December 2010 as Director, Strategic Planning where he was responsible for both corporate development and capital markets initiatives. Mr. Young is also a director of certain of PBF Energy’s subsidiaries, including PBF GP. Prior to joining the Company, Mr. Young spent eleven years in corporate finance, strategic planning and mergers and acquisitions roles across a variety of industries. He began his career in investment banking before joining J.F. Lehman & Company, a private equity investment firm, in 2001.
Paul Davis has served as our and PBF Energy’s President, PBF Energy Western Region LLC since September 2017. Mr. Davis joined us in April of 2012 and served as head ofheld various executive roles in our commercial operations, related to crude oil and refinery feedstock sourcing from May of 2013 to January 2015 and, from January 2015 to September 2015, served as ourincluding Co-Head of Commercial, and servedprior to serving as Senior Vice President, Western Region Commercial Operations from September 2015 to September 2017. Previously, Mr. Davis was responsible for managing the U.S. clean products commercial operations for Hess Energy Trading Company (“HETCO”) from 2006 to 2012. Prior to that, Mr. Davis was responsible for Premcor’s U.S. Midwest clean products disposition group. Mr. Davis has over 29 years of experience in commercial operations in crude oil and refined products, including 16 years with the ExxonMobil Corporation in various operational and commercial positions, including sourcing refinery feedstocks and crude oil and the disposition of refined petroleum products, as well as optimization roles within refineries.
Thomas L. O’Connor has served as our and PBF Energy Senior Vice President, Commercial since September 2015. Mr. O’Connor joined us and PBF Energy as Senior Vice President in September 2014 with responsibility for business development and growing the business of PBFX, and from January to September 2015, served as Co-Head of commercial activities. Prior to joining us, Mr. O’Connor worked at Morgan Stanley since 2000 in various positions, most recently as a Managing Director and Global Head of Crude Oil Trading and Global Co-Head of Oil Flow Trading. Prior to joining Morgan Stanley, Mr. O’Connor worked for Tosco from 1995 to 2000 in the Atlantic Basin Fuel Oil and Feedstocks group.
Herman Seedorf serveshas served as our and PBF Energy’s Senior Vice President of Refining.Refining since May 2014. Mr. Seedorf originally joined us in February of 2011 as the Delaware City Refinery Plant Manager and becameserved as Senior Vice President, Eastern Region Refining, infrom September of 2013.2013 to May 2014. Prior to 2011, Mr. Seedorf served as the refinery manager of the Wood River Refinery in Roxana, Illinois, and also as an officer of the joint venture between ConocoPhillips and Cenovus Energy Inc. Mr. Seedorf’s oversight responsibilities included the development and execution of the multi-billion dollar upgrade project which enabled the expanded processing of Canadian crude oils. He also served as the refinery manager of the Bayway Refinery in Linden, New Jersey for four years during the time period that it was an asset of Tosco. Mr. Seedorf began his career in the petroleum industry with Exxon Corporation (“Exxon”) in 1980.
Trecia Canty has served as our Senior Vice President, General Counsel and Corporate Secretary since September 2015. In her role, Ms. Canty is responsible for the Legal Departmentlegal department and Contracts Administration.outside counsel, which provide a broad range of support for the Company’s business activities, including corporate governance, compliance, litigations and mergers and acquisitions. Previously, Ms. Canty was named Vice President, Senior Deputy General Counsel and Assistant Secretary in October 2014 and led our commercial and finance legal operations since joining us in November 2012. Ms. Canty is also a director of certain of PBF Energy’s subsidiaries. Prior to joining us, Ms. Canty served as Associate General Counsel, Corporate and Assistant Secretary of Southwestern Energy Company, where her responsibilities included finance and mergers and acquisitions, securities and corporate compliance and corporate governance. She also provided legal support to the midstream marketing and logistics businesses. Prior to joining Southwestern Energy Company in 2004, she was an associate with Cleary, Gottlieb, Steen & Hamilton.
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Corporate Governance Matters
PBF Energy, our indirect parent, has adopted a Code of Business Conduct and Ethics that applies to our principal executive officer, principal financial officer and principal accounting officer. The Code of Business Conduct and Ethics is available at www.pbfenergy.com under the heading “Investors”. Any amendments to the Code of Business Conduct and Ethics or any grant of a waiver from the provisions of the Code of Business Conduct and Ethics requiring disclosure under applicable Securities and Exchange Commission rules will be disclosed on such website.
Additional information required by this Item will be contained in PBF Energy’s 20182021 Proxy Statement, incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
Compensation of Directors of PBF Holding Company LLC
Directors of PBF Holding receive no separate compensation for service on the board of directors or committees thereof.
Additional information required under this Item will be contained in PBF Energy’s 20182021 Proxy Statement, incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
As of December 31, 2017,2020, 100% of the membership interests of PBF Holding were owned by PBF LLC, and PBF Finance had 100 shares of common stock outstanding, all of which were held by PBF Holding. Refer to Note 13 “Equity“Note 14 - Equity Structure” of our Notes to Consolidated Financial Statements.
The stockholders of PBF Energy may be deemed to beneficially own an interest in our membership interests by virtue of their beneficial ownership of shares of Class A common stock of PBF Energy. PBF Energy reports separately on the beneficial ownership of its officers, directors and significant stockholders. For additional information, we refer you to PBF Energy’s 20182021 Proxy Statement, which is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Refer to “Note 9 - Affiliate Notes Payable”, “Note 11 - Related Party Transactions” and “Note 20 - Subsequent Events” of our Notes to Consolidated Financial Statements.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Deloitte & Touche LLP (“Deloitte”) is our independent registered public accounting firm. Our audit fees are determined as part of the overall audit fees for PBF Energy and are approved by the audit committee of the board of directors of PBF Energy. PBF Energy reports separately on the fees and services of its principal accountants. For additional information, we refer you to PBF Energy’s 20182021 Proxy Statement, which is incorporated herein by reference.
The following table presents fees billedincurred for the years ended December 31, 20172020 and 20162019 for professional services performed by Deloitte.
| (in thousands) | 2020 | 2019 | |||||||||
Audit Fees (1) | $ | 4,660.0 | $ | 4,254.0 | |||||||
Audit-related Fees (2) | 576.0 | 33.5 | |||||||||
Tax Fees (3) | 57.8 | 78.3 | |||||||||
| Total Fees | $ | 5,293.8 | $ | 4,365.8 | |||||||
| (1) Represents the aggregate fees for professional services rendered by Deloitte in connection with its audits of PBF Holding and its indirect parent, PBF Energy’s consolidated financial statements, including the audits of internal control over financial reporting of PBF Energy and related accounting consultation services provided to support the performance of such audits. Fees, and related expenses, are for services performed in connection with the audit of our fiscal years ended December 31, 2020 and 2019 financial statements regardless of when incurred. | |||||||||||
| (2) Represents fees for professional services rendered in connection with various filings for PBF Holding and its indirect parent, PBF Energy, including (i) services rendered in connection with the filing of multiple registration statements with the SEC and (ii) attestation services performed in connection with certain regulatory filings. | |||||||||||
| (3) Represents fees associated with tax services rendered for income tax planning and sales, use and excise tax matters. | |||||||||||
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| 2017 | 2016 | |||||
Audit Fees and Expenses (1) | $ | 4,299,000 | $ | 3,988,690 | ||
Audit-related Fees (2) | 588,000 | 867,767 | ||||
Tax Fees (3) | — | — | ||||
| All Other Fees | — | — | ||||
| Total Fees and Expenses | $ | 4,887,000 | $ | 4,856,457 | ||
| (1) Represents the aggregate fees for professional services rendered by Deloitte in connection with its audits of PBF Holding and its indirect parent, PBF Energy’s consolidated financial statements, including the audits of internal control over financial reporting of PBF Energy, and reviews of the condensed consolidated financial statements included in Quarterly Reports on Form 10-Q. | ||||||
| (2) Represents fees for professional services rendered in connection with various filings for PBF Energy and its subsidiaries, including (i) services rendered in connection with the PBF Energy public offerings in 2016 and the Senior Notes offerings and related notes registrations in 2016 and 2017, (ii) audits performed relating to subsequent asset contributions by PBF LLC to PBF Logistics LP, and (iii) consultations on accounting issues. | ||||||
| (3) Represents fees associated with tax services rendered for income tax planning and sales, use and excise tax matters. | ||||||
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
2. Financial Statement Schedules and Other Financial Information. No financial statement schedules are submitted because either they are inapplicable or because the required information is included in the consolidated financial statements or notes thereto.
3. Exhibits. Filed as part of this Annual Report on Form 10-K are the following exhibits:
| Number | Description | |||||||
| Contribution Agreement dated as of | ||||||||
| Sale and Purchase Agreement dated June 11, 2019 by and between PBF Holding Company LLC and | ||||||||
| Amendment No. 1 dated February 1, 2020 to Sale and Purchase Agreement dated June 11, 2019 by and between PBF Holding Company LLC and Equilon Enterprises LLC d/b/a Shell Oil Products US (incorporated by reference to Exhibit 2.2 filed with PBF Energy Inc.'s Current Report on Form 8-K dated February 6, 2020 (File No. 001-35764)). | ||||||||
| Certificate of Formation of PBF Holding Company LLC (Incorporated by reference to Exhibit 3.1 filed with PBF Holding Company LLC’s Registration Statement on Form S-4 dated January 14, 2013 (Registration No. 333-186007)). | ||||||||
| Limited Liability Company Agreement of PBF Holding Company LLC (Incorporated by reference to Exhibit 3.2 filed with PBF Holding Company LLC’s Registration Statement on Form S-4 (Registration No. 333-186007)). | ||||||||
| Certificate of Incorporation of PBF Finance Corporation (Incorporated by reference to Exhibit 3.3 filed with PBF Holding Company LLC’s Registration Statement on Form S-4 (Registration No. 333-186007)). | ||||||||
| Bylaws of PBF Finance Corporation (Incorporated by reference to Exhibit 3.4 filed with PBF Holding Company LLC’s Registration Statement on Form S-4 (Registration No. 333-186007)). | ||||||||
| Indenture dated as of May 30, 2017, among PBF Holding Company LLC, PBF Finance Corporation, the Guarantors named on the signature pages thereto, Wilmington Trust, National Association, as Trustee and Deutsche Bank Trust Company Americas, as Paying Agent, Registrar, Transfer Agent and Authenticating Agent and | ||||||||
| Indenture dated as of | ||||||||
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| Registration Rights Agreement dated | ||||||||
| First Supplemental Indenture dated February 3, 2020, among PBF Holding Company LLC, PBF Finance Corporation, Martinez Refining Company LLC, Martinez Terminal Company LLC, Wilmington Trust, National Association, as trustee, and Deutsche Bank Trust Company Americas, as paying agent, transfer agent, registrar and authenticating agent (6.00% Senior Notes due 2028) (incorporated by reference to Exhibit 4.3 filed with PBF Energy Inc.’s Quarterly Report on Form 10-Q dated May 15, 2020 (File No. 001-35764). | ||||||||
| First Supplemental Indenture dated February 3, 2020, among PBF Holding Company LLC, PBF Finance Corporation, Martinez Refining Company LLC, Martinez Terminal Company LLC, Wilmington Trust, National Association, as trustee, and Deutsche Bank Trust Company Americas, as paying agent, transfer agent, registrar and authenticating agent (7.25% Senior Notes due 2025) (incorporated by reference to Exhibit 4.4 filed with PBF Energy Inc.’s Quarterly Report on Form 10-Q dated May 15, 2020 (File No. 001-35764). | ||||||||
| Eighth Supplemental Indenture dated March 4, 2020, among PBFX Ace Holdings LLC, PBF Logistics LP, PBF Logistics Finance Corporation, and Deutsche Bank Trust Company Americas, as trustee (incorporated by reference to Exhibit 4.1 filed with PBF Logistics LP’s Quarterly Report on Form 10-Q dated May 15, 2020 (File No. 001-36446)). | ||||||||
| Indenture dated as of May 13, 2020, among PBF Holding Company LLC, PBF Finance Corporation, the Guarantors named on the signature pages thereto, Wilmington Trust, National Association, as Trustee, Paying Agent, Registrar, Transfer Agent, Authenticating Agent and Notes Collateral Agent and form of 9.25% Senior Secured Notes due 2025 (included as exhibit A) (incorporated by reference to Exhibit 4.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated May 13, 2020 (File No. 001-35764)). | ||||||||
| Supplemental Indenture dated December 21, 2020, among PBF Holding Company LLC, PBF Finance Corporation, the Guarantors named on the signature pages thereto, Wilmington Trust, National Association, as Trustee, Paying Agent, Registrar, Transfer Agent, Authenticating Agent and Notes Collateral Agent (9.25% Senior Secured Notes due 2025) (incorporated by reference to Exhibit 4.3 filed with PBF Energy Inc.’s Current Report on Form 8-K dated December 22, 2020 (File No. 001-35764)). | ||||||||
| PBF Energy Inc. Amended and Restated 2012 Equity Incentive Plan (incorporated by reference to DEF 14A filed with PBF Energy Inc.’s Proxy Statement dated March 22, 2016 (File No. 001-35764)). | ||||||||
| PBF Energy Inc. Amended and Restated 2017 Equity Incentive Plan (incorporated by reference to Appendix A to PBF Energy Inc.’s Definitive Proxy Statement on Schedule 14A filed on April 13, 2018 (File No. 001-35764)). | ||||||||
| Form of PBF Energy Non-Qualified Stock Option Agreement (prior to 2020) under the Amended and Restated PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit | ||||||||
| Form of PBF Energy Performance Share Unit Award Agreement (prior to 2020) under the Amended and Restated PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.2 filed with PBF Energy Inc.’s Current Report on Form 8-K dated November 2, 2018 (File No. 001-35764)). | ||||||||
| Form of PBF Energy Performance Unit Award Agreement (prior to 2020) under the Amended and Restated PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.3 filed with PBF Energy Inc.’s Current Report on Form 8-K dated November 2, 2018 (File No. 001-35764)). | ||||||||
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| Form of PBF Energy Non-Qualified Stock Option Agreement (2020 and thereafter) under the Amended and Restated PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated November 13, 2020 (File No. 001-35764)). | ||||||||
| Form of PBF Energy Performance Share Unit Award Agreement (2020 and thereafter) under the Amended and Restated PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.2 filed with PBF Energy Inc.’s Current Report on Form 8-K dated November 13, 2020 (File No. 001-35764)). | ||||||||
| Form of PBF Energy Performance Unit Award Agreement (2020 and thereafter) under the Amended and Restated PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.3 filed with PBF Energy Inc.’s Current Report on Form 8-K dated November 13, 2020 (File No. 001-35764)). | ||||||||
| Form of Non-Qualified Stock Option Agreement under the PBF Energy Inc. 2012 Equity Incentive Plan (incorporated by reference to Exhibit 10.28 filed with PBF Energy Inc.’s Amendment No. 6 to Registration Statement on Form S-1 (Registration No. 333-177933)) | ||||||||
| . | ||||||||
| Form of Restricted Stock Agreement for | ||||||||
| Form of 2017 Equity Incentive Plan Restricted Stock Agreement for employees (incorporated by reference to Exhibit 10.1 of PBF Energy Inc.’s Current Report on Form 8-K (File No. 001-35764) filed on October 31, 2017). | ||||||||
| Form of 2017 Equity Incentive Plan Non-Qualified Stock Agreement (incorporated by reference to Exhibit 10.2 of PBF Energy Inc.’s Current Report on Form 8-K (File No. 001-35764) filed on October 31, 2017). | ||||||||
| Form of Amended and Restated Non-Qualified Stock Option Agreement under the PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Current Report on Form 8-K dated February 16, 2018 (File No. 001-35764)). | ||||||||
| Amended and Restated Restricted Stock Agreement for non-employee Directors under the PBF Energy Inc. 2017 Equity Incentive Plan. (incorporated by reference to Exhibit 10.3 of PBF Energy Inc.’s Annual Report on Form 10-K (File No. 001-35764) filed on February 23, 2018). | ||||||||
| Form of Amended and Restated Restricted Stock Agreement for employees under PBF Energy Inc. 2017 Equity Incentive Plan (incorporated by reference to Exhibit 10.7 of PBF Energy Inc.’s Annual Report on Form 10-K (File No. 001-35764) filed on February 23, 2018). | ||||||||
| Transportation Services Agreement dated as of August 31, 2016 among PBF Holding Company LLC and Torrance Valley Pipeline Company LLC (incorporated by reference to Exhibit 10.3 filed with PBF Energy Inc.’s Current Report on Form 8-K dated September 7, 2016 (File No. 001-35764)). | ||||||||
| Pipeline Service Order dated as of August 31, 2016, by and between Torrance Valley Pipeline Company LLC, and PBF Holding Company LLC (incorporated by reference to Exhibit 10.4 filed with PBF Energy Inc.’s Current Report on Form 8-K dated September 7, 2016 (File No. 001-35764)). | ||||||||
| Pipeline Service Order dated as of August 31, 2016, by and between Torrance Valley Pipeline Company LLC, and PBF Holding Company LLC (incorporated by reference to Exhibit 10.5 filed with PBF Energy Inc.’s Current Report on Form 8-K dated September 7, 2016 (File No. 001-35764)) | ||||||||
| . | ||||||||
| Dedicated Storage Service Order dated as of August 31, 2016, by and between Torrance Valley Pipeline Company LLC, and PBF Holding Company LLC (incorporated by reference to Exhibit 10.6 filed with PBF Energy Inc.’s Current Report on Form 8-K dated September 7, 2016 (File No. 001-35764)). | ||||||||
103
| Throughput Storage Service Order dated as of August 31, 2016, by and between Torrance Valley Pipeline Company LLC, and PBF Holding Company LLC (incorporated by reference to Exhibit 10.7 filed with PBF Energy Inc.’s Current Report on Form 8-K dated September 7, 2016 (File No. 001-35764)). | ||||||||
| Senior Secured Revolving Credit Agreement dated as of May | ||||||||
| Amendment dated as of February 18, 2020 to Senior Secured Revolving Credit Agreement dated as of May 2, 2018 (incorporated by reference to Exhibit 10.3 filed with PBF Energy Inc.’s Quarterly Report on Form 10-Q dated May 15, 2020 (File No. 001-35764). | ||||||||
| Sixth Amended and Restated Operation and Management Services and Secondment Agreement dated as of July 31, 2018, among PBF Holding Company LLC, Delaware City Refining Company LLC, Toledo Refining Company LLC, Torrance Refining Company LLC, Torrance Logistics Company LLC, Chalmette Refining L.L.C., Paulsboro Refining Company LLC, PBF Logistics GP LLC, PBF Logistics LP, DCR Storage and Loading LLC, Delaware City Terminaling Company LLC, Toledo Terminaling Company LLC, Delaware Pipeline Company LLC, Delaware City Logistics Company LLC, Paulsboro Terminaling Company LLC, Paulsboro Natural Gas Pipeline Company LLC, Toledo Rail Logistics Company LLC, Chalmette Logistics Company LLC and PBFX Operating Company LLC (incorporated by reference to Exhibit 10.3 filed with PBF Logistics LP’s Quarterly Report on Form 10-Q dated October 31, 2018 (File No. 001-36446)). | ||||||||
| Fifth Amended and Restated Omnibus Agreement dated as of | ||||||||
| . | ||||||||
| Amended and Restated Delaware City Rail Terminaling Services Agreement (incorporated by reference to Exhibit 10.1 filed with PBF Logistics LP’s Quarterly Report on Form 10-Q dated May 3, 2018 (File No. 001-36446)). | ||||||||
| Amended and Restated Delaware City West Ladder Rack Terminaling Services Agreement (incorporated by reference to Exhibit 10.2 filed with PBF Logistics LP’s Quarterly Report on Form 10-Q dated May 3, 2018 (File No. 001-36446)). | ||||||||
| Delaware Pipeline Services Agreement dated as of May 15, 2015 among PBF Holding Company LLC and Delaware Pipeline Company LLC (incorporated by reference to Exhibit 10.3 filed with PBF Energy Inc.’s Current Report on Form 8-K dated May 12, 2015 (File No. 001-35764)). | ||||||||
104
| Delaware City Truck Loading Services Agreement dated as of May 15, 2015 among PBF Holding Company LLC and Delaware City Logistics Company LLC (incorporated by reference to Exhibit 10.4 filed with PBF Energy Inc.’s Current Report on Form 8-K dated May 12, 2015 (File No. 001-35764)). | ||||||||
| Second Amended and Restated Inventory Intermediation Agreement dated as of | ||||||||
| Amended to the Inventory Intermediation Agreement dated as of November 19, 2020, among J. Aron & Company LLC, PBF Holding Company LLC and Delaware City Refining Company LLC (incorporated by reference to Exhibit | ||||||||
| Amendment to | ||||||||
| Amended and Restated Toledo Truck Unloading & Terminaling Agreement effective as of June 1, 2014 (incorporated by reference to Exhibit 10.10 filed with PBF Energy Inc.’s Quarterly Report on Form 10-Q dated August 7, 2014 (File No. 001-35764)) | ||||||||
| . | ||||||||
| Assignment and Amendment of Amended and Restated Toledo Truck Unloading & Terminaling Agreement dated as of December 12, 2014 by and between PBF Holding Company LLC, PBF Logistics LP and Toledo Terminaling Company LLC (incorporated by reference to Exhibit 10.4 filed with PBF Logistics LP’s Current Report on Form 8-K dated December 16, 2014 (File No. 001-36446)). | ||||||||
| Firm Transportation Service Agreement dated as of August 3, 2017, by and between Paulsboro Natural Gas Pipeline Company LLC and Paulsboro Refining Company LLC (incorporated by reference to Exhibit 10.1 | ||||||||
| Storage and Terminaling Services Agreement dated as of December 12, 2014 among PBF Holding Company LLC and Toledo Terminaling Company LLC (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on December 16, 2014 (File No. 001-36446)). | ||||||||
105
| Joinder Agreement to the ABL Security Agreement dated as of February 1, 2020, among Martinez Refining Company LLC, Martinez Terminal Company LLC and Bank of America, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 filed with PBF Energy Inc.’s Quarterly Report on Form 10-Q dated May 15, 2020 (File No. 001-35764). | ||||||||
| Joinder Agreement to the Credit Agreement dated as of February 1, 2020, among PBF Holding Company LLC, the Guarantors named on the signature pages thereto including Martinez Refining Company LLC, Martinez Terminal Company LLC and Bank of America, N.A., as Administrative Agent to Senior Secured Revolving Credit Agreement dated as of May 2, 2018 (incorporated by reference to Exhibit 10.2 filed with PBF Energy Inc.’s Quarterly Report on Form 10-Q dated May 15, 2020 (File No. 001-35764). | ||||||||
| Employment Agreement dated as of September 4, 2014 between PBF Investments LLC and Thomas O’Connor (incorporated by reference to Exhibit 10.9 filed with PBF Energy Inc.’s Annual Report on Form 10-K dated February 29, 2016 (File No. 001-35764)). | ||||||||
| Employment Agreement dated as of April 1, 2014 between PBF Investments LLC and Timothy Paul Davis (incorporated by reference to Exhibit 10.4 filed with PBF Energy Inc.’s Quarterly Report on Form 10-Q dated May 7, 2014 (File No. 001-35764)). | ||||||||
| Employment Agreement dated as of April 1, 2014 between PBF Investments LLC and Erik Young (incorporated by reference to Exhibit 10.2 filed with PBF Energy Inc.’s Quarterly Report on Form 10-Q dated May 7, 2014 (File No. 001-35764)). | ||||||||
| Amended and Restated Employment Agreement dated as of December 17, 2012, between PBF Investments LLC and Thomas J. Nimbley (incorporated by reference to Exhibit 10.8 filed with PBF Energy Inc.’s Current Report on Form 8-K dated December 18, 2012 (File No. 001-35764)). | ||||||||
| Second Amended and Restated Employment Agreement, dated as of December 17, 2012, between PBF Investments LLC and Matthew C. Lucey (incorporated by reference to Exhibit 10.9 filed with PBF Energy Inc.’s Current Report on Form 8-K dated December 18, 2012 (File No. 001-35764)). | ||||||||
| Subsidiaries of PBF Holding Company LLC | ||||||||
| List of Guarantor Subsidiaries | ||||||||
| Power of Attorney (included on signature page) | ||||||||
| Certification by Chief Executive Officer of PBF Holding Company LLC pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | ||||||||
| Certification by Chief Financial Officer of PBF Holding Company LLC pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | ||||||||
| Certification by Chief Executive Officer of PBF Holding Company LLC pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | ||||||||
| Certification by Chief Financial Officer of PBF Holding Company LLC pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | ||||||||
| 101.INS | XBRL Instance Document. | |||||||
| 101.SCH | XBRL Taxonomy Extension Schema Document. | |||||||
| 101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document. | |||||||
| 101.DEF | XBRL Taxonomy Extension Definition Linkbase Document. | |||||||
| 101.LAB | XBRL Taxonomy Extension Label Linkbase Document. | |||||||
| 101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document. | |||||||
——————————
106
| * | Filed herewith. | ||||
| ** | |||||
| Indicates management compensatory plan or arrangement. | |||||
| † | |||||
| (1) | This exhibit should not be deemed to be “filed” for purposes of Section 18 of the Exchange Act. | ||||
107
PBF HOLDING COMPANY LLC
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
F- 1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To PBF Energy Inc., the Managing Member of
PBF Holding Company LLC
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of PBF Holding Company LLC and subsidiaries (the "Company") as of December 31, 20172020 and 2016,2019, the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows, for each of the three years in the period ended December 31, 2017,2020, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172020 and 2016,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2020, in conformity with accounting principles generally accepted in the United States of America.
Change in Accounting Principle
As discussed in Note 2 to the financial statements, effective January 1, 2019, the Company adopted FASB Accounting Standards Update 2016-02, Leases (ASC 842), using the modified retrospective approach. Consistent with management’s disclosure in Note 2, the adoption of ASC 842 has a material effect on the financial statements and financial statement disclosures. As of the date of implementation on January 1, 2019, the impact of the adoption of ASC 842 resulted in the recognition of a right of use asset and lease liabilities on the Company’s consolidated balance sheet of approximately $853.9 million, of which $604.4 million is attributable to leases with affiliates. As the right of use asset and the lease liabilities were the same upon adoption of ASC 842, there was no cumulative effect on the Company’s retained earnings.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
F- 2
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing a separate opinion on the critical audit matters or on the accounts or disclosures to which it relates.
Acquisitions - Martinez Acquisition Valuation and Purchase Price Allocation — Refer to Note 3 to the financial statements
Critical Audit Matter Description
On February 1, 2020, the Company completed the acquisition of the Martinez refinery for an aggregate purchase price of $1,253.4 million, including working capital and contingent consideration. Management of the Company accounted for the acquisition of the Martinez refinery as a business combination. Accordingly, the purchase price was allocated to the assets acquired and liabilities assumed based on their estimated fair values at the date of acquisition. The primary asset acquired was property, plant and equipment the valuation of which involved management making significant estimates and assumptions related to discount rate, replacement cost and market value of the acquired property, plant and equipment. Contingent consideration also involved management making significant estimates related to discount rate and projected future cash flows.
We identified the valuation of property, plant and equipment and the valuation of the liability for contingent consideration related to the Martinez refinery as a critical audit matter because of the significant estimates and assumptions made by management.This required a high degree of auditor judgment and an increased extent of effort, including the involvement of our fair value specialists, when performing audit procedures to evaluate the reasonableness of management’s projected future cash flows, the selection of a discount rate and the replacement cost and market value of the acquired property, plant and equipment.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to management’s projected future cash flows, the selection of a discount rate, and the replacement cost and market value of acquired property, plant and equipment for the Martinez refinery included the following, among others:
•We tested the effectiveness of controls over the purchase price allocation, including management’s controls over the assumptions used in the valuation of the property, plant and equipment, including estimating the replacement cost and market value of the acquired property, plant and equipment, determination of the discount rate, and reviewing the work of third-party specialists. We also tested the effectiveness of controls over the contingent consideration valuation, including management’s estimation of future cash flows and determination of the discount rate.
•With the assistance of our fair value specialists;
◦We tested the appropriateness of the valuation methodology
◦We tested the cost to acquire or construct comparable assets and the remaining useful lives used for the cost approach for property, plant and equipment, including comparing such estimates to independent market information to determine reasonableness
◦We tested the underlying source information used for the market approach for land
◦We tested the reasonableness of the discount rate and the underlying source information
F- 3
◦We tested the valuation of the contingent consideration by evaluating the valuation model and assumptions, including an assessment of the probability of achieving projected future cash flows, assessing the mathematical accuracy of the valuation, and performing a sensitivity analysis to ensure reasonableness
Summary of Significant Accounting Policies – Impairment Assessment and COVID-19 and Market Developments and Commitments and Contingencies – Contingent Consideration— Refer to Notes 2 and 12 to the financial statements
Critical Audit Matter Description
Management of the Company prepares and uses projected operational results (“Management’s Projections”) for various accounting analysis and considerations, including the impairment analysis of long-lived assets, the determination of the contingent consideration liability in connection with the Martinez refinery acquisition, and the evaluation of the Company’s future liquidity. The assumptions used in Management’s Projections are subject to substantial uncertainty about the results of the Company’s future business operations. The development of Management’s Projections involves management making significant judgments and assumptions in estimating future cash flows, including assumptions related to future refinery throughput, future gross margin, future operating expenses and future levels of sustaining capital expenditures.
Given that the development of Management’s Projections require management to make significant estimates related to assumptions, performing audit procedures to evaluate the reasonableness of these assumptions required a high degree of auditor judgment and an increased extent of effort, including the need to involve our fair value specialists to evaluate future pricing data assumed in Management’s Projections.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to Management’s Projections included the following, among others:
•We tested the effectiveness of controls over the determination of Management’s Projections, including management’s controls over the determination of future refinery throughput, future gross margin, future operating expenses, and future levels of sustaining capital expenditures.
•We tested the reasonableness of management’s future refinery throughput, future gross margin, future operating expenses and future levels of sustaining capital expenditures by comparing the forecasts to:
◦Historical refinery throughput, operating expenses, and levels of sustaining capital expenditures
◦Analyst EBITDA projections
◦Internal communications to management and the Board of Directors
◦Industry reports for the Company and certain of its peer companies
•With the assistance of our fair value specialists we tested the future pricing used in Management’s Projections in determining future gross margin by agreeing future pricing to independently obtained information.
/s/ Deloitte & Touche LLP
Parsippany, New Jersey
March 9, 20183, 2021
We have served as the Company's auditor since 2011.
PBF HOLDING COMPANY LLC
CONSOLIDATED BALANCE SHEETS
(in thousands)millions)
| December 31, 2020 | December 31, 2019 | ||||||||||
| ASSETS | |||||||||||
| Current assets: | |||||||||||
| Cash and cash equivalents | $ | 1,570.1 | $ | 763.1 | |||||||
| Accounts receivable | 501.5 | 826.6 | |||||||||
| Accounts receivable - affiliate | 4.9 | 6.5 | |||||||||
| Inventories | 1,686.2 | 2,122.2 | |||||||||
| Prepaid and other current assets | 56.4 | 48.0 | |||||||||
| Total current assets | 3,819.1 | 3,766.4 | |||||||||
| Property, plant and equipment, net | 4,023.1 | 3,168.6 | |||||||||
| Lease right of use assets - third party | 916.7 | 330.3 | |||||||||
| Lease right of use assets - affiliate | 571.0 | 650.3 | |||||||||
| Deferred charges and other assets, net | 862.7 | 930.0 | |||||||||
| Total assets | $ | 10,192.6 | $ | 8,845.6 | |||||||
| LIABILITIES AND EQUITY | |||||||||||
| Current liabilities: | |||||||||||
| Accounts payable | $ | 402.3 | $ | 591.2 | |||||||
| Accounts payable - affiliate | 53.2 | 48.1 | |||||||||
| Accrued expenses | 1,881.8 | 1,791.4 | |||||||||
| Deferred revenue | 45.1 | 17.0 | |||||||||
| Current operating lease liabilities - third party | 78.3 | 72.0 | |||||||||
| Current operating lease liabilities - affiliate | 85.6 | 79.2 | |||||||||
| Current debt | 7.4 | 0 | |||||||||
| Total current liabilities | 2,553.7 | 2,598.9 | |||||||||
| Long-term debt | 3,932.8 | 1,262.8 | |||||||||
| Deferred tax liabilities | 38.7 | 31.4 | |||||||||
| Long-term operating lease liabilities - third party | 755.9 | 232.9 | |||||||||
| Long-term operating lease liabilities - affiliate | 485.4 | 571.1 | |||||||||
| Long-term financing lease liabilities - third party | 68.3 | 18.4 | |||||||||
| Other long-term liabilities | 267.0 | 232.9 | |||||||||
| Total liabilities | 8,101.8 | 4,948.4 | |||||||||
| Commitments and contingencies (Note 12) | 0 | 0 | |||||||||
| Equity: | |||||||||||
| PBF Holding Company LLC equity | |||||||||||
| Member’s equity | 2,809.7 | 2,739.1 | |||||||||
| Retained earnings (accumulated deficit) | (723.4) | 1,156.9 | |||||||||
| Accumulated other comprehensive loss | (6.1) | (9.7) | |||||||||
| Total PBF Holding Company LLC equity | 2,080.2 | 3,886.3 | |||||||||
| Noncontrolling interest | 10.6 | 10.9 | |||||||||
| Total equity | 2,090.8 | 3,897.2 | |||||||||
| Total liabilities and equity | $ | 10,192.6 | $ | 8,845.6 | |||||||
See notes to consolidated financial statements.
F- 5
| December 31, 2017 | December 31, 2016 | ||||||
| ASSETS | |||||||
| Current assets: | |||||||
| Cash and cash equivalents | $ | 526,160 | $ | 626,705 | |||
| Accounts receivable | 951,129 | 615,881 | |||||
| Accounts receivable - affiliate | 8,352 | 7,631 | |||||
| Inventories | 2,213,797 | 1,863,560 | |||||
| Prepaid and other current assets | 49,523 | 40,536 | |||||
| Total current assets | 3,748,961 | 3,154,313 | |||||
| Property, plant and equipment, net | 2,805,390 | 2,728,699 | |||||
| Investment in equity method investee | 171,903 | 179,882 | |||||
| Deferred charges and other assets, net | 779,924 | 504,003 | |||||
| Total assets | $ | 7,506,178 | $ | 6,566,897 | |||
| LIABILITIES AND EQUITY | |||||||
| Current liabilities: | |||||||
| Accounts payable | $ | 572,932 | $ | 530,365 | |||
| Accounts payable - affiliate | 40,817 | 37,863 | |||||
| Accrued expenses | 1,800,859 | 1,462,729 | |||||
| Current debt | 10,987 | — | |||||
| Deferred revenue | 7,495 | 12,340 | |||||
| Note payable | 5,621 | — | |||||
| Total current liabilities | 2,438,711 | 2,043,297 | |||||
| Long-term debt | 1,626,249 | 1,576,559 | |||||
| Affiliate notes payable | — | 86,298 | |||||
| Deferred tax liabilities | 33,155 | 45,699 | |||||
| Other long-term liabilities | 223,961 | 226,111 | |||||
| Total liabilities | 4,322,076 | 3,977,964 | |||||
| Commitments and contingencies (Note 12) | |||||||
| Equity: | |||||||
| PBF Holding Company LLC equity | |||||||
| Member’s equity | 2,359,791 | 2,155,863 | |||||
| Retained earnings | 840,431 | 446,519 | |||||
| Accumulated other comprehensive loss | (26,928 | ) | (25,962 | ) | |||
| Total PBF Holding Company LLC equity | 3,173,294 | 2,576,420 | |||||
| Noncontrolling interest | 10,808 | 12,513 | |||||
| Total equity | 3,184,102 | 2,588,933 | |||||
| Total liabilities and equity | $ | 7,506,178 | $ | 6,566,897 | |||
PBF HOLDING COMPANY LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)millions)
| Year Ended December 31, | |||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||||||||||||||
| Revenues | $ | 15,045.0 | $ | 24,468.9 | $ | 27,164.0 | |||||||||||||||||||||||
| Cost and expenses: | |||||||||||||||||||||||||||||
| Cost of products and other | 14,548.2 | 21,667.7 | 24,744.6 | ||||||||||||||||||||||||||
| Operating expenses (excluding depreciation and amortization expense as reflected below) | 1,835.2 | 1,684.3 | 1,654.8 | ||||||||||||||||||||||||||
| Depreciation and amortization expense | 498.0 | 386.7 | 329.7 | ||||||||||||||||||||||||||
| Cost of sales | 16,881.4 | 23,738.7 | 26,729.1 | ||||||||||||||||||||||||||
| General and administrative expenses (excluding depreciation and amortization expense as reflected below) | 229.0 | 258.7 | 253.8 | ||||||||||||||||||||||||||
| Depreciation and amortization expense | 11.3 | 10.8 | 10.6 | ||||||||||||||||||||||||||
| Change in fair value of contingent consideration | (79.3) | 0 | 0 | ||||||||||||||||||||||||||
| Impairment Expense | 91.8 | 0 | 0 | ||||||||||||||||||||||||||
| Equity income in investee | 0 | (7.9) | (17.8) | ||||||||||||||||||||||||||
| Gain on sale of assets | (477.8) | (29.9) | (43.1) | ||||||||||||||||||||||||||
| Total cost and expenses | 16,656.4 | 23,970.4 | 26,932.6 | ||||||||||||||||||||||||||
| Income (loss) from operations | (1,611.4) | 498.5 | 231.4 | ||||||||||||||||||||||||||
| Other income (expense): | |||||||||||||||||||||||||||||
| Interest expense, net | (210.3) | (108.7) | (127.1) | ||||||||||||||||||||||||||
| Change in fair value of catalyst obligations | (11.8) | (9.7) | 5.6 | ||||||||||||||||||||||||||
| Debt extinguishment costs | (22.2) | 0 | 0 | ||||||||||||||||||||||||||
| Other non-service components of net periodic benefit cost | 4.3 | (0.2) | 1.1 | ||||||||||||||||||||||||||
| Income (loss) before income taxes | (1,851.4) | 379.9 | 111.0 | ||||||||||||||||||||||||||
| Income tax expense (benefit) | 6.1 | (8.3) | 8.0 | ||||||||||||||||||||||||||
| Net income (loss) | (1,857.5) | 388.2 | 103.0 | ||||||||||||||||||||||||||
| Less: net income (loss) attributable to noncontrolling interests | (0.3) | 0 | 0.1 | ||||||||||||||||||||||||||
| Net income (loss) attributable to PBF Holding Company LLC | $ | (1,857.2) | $ | 388.2 | $ | 102.9 | |||||||||||||||||||||||
See notes to consolidated financial statements.
F- 6
| Year Ended December 31, | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| Revenues | $ | 21,772,478 | $ | 15,908,537 | $ | 13,123,929 | ||||||
| Cost and expenses: | ||||||||||||
| Cost of products and other | 19,095,827 | 13,765,088 | 11,611,599 | |||||||||
| Operating expenses (excluding depreciation and amortization expense as reflected below) | 1,627,616 | 1,390,582 | 889,368 | |||||||||
| Depreciation and amortization expense | 254,271 | 204,005 | 181,422 | |||||||||
| Cost of sales | 20,977,714 | 15,359,675 | 12,682,389 | |||||||||
| General and administrative expenses (excluding depreciation and amortization expense as reflected below) | 198,164 | 149,643 | 166,904 | |||||||||
| Depreciation and amortization expense | 12,964 | 5,835 | 9,688 | |||||||||
| Equity income in investee | (14,565 | ) | (5,679 | ) | — | |||||||
| Loss (gain) on sale of assets | 1,458 | 11,374 | (1,004 | ) | ||||||||
| Total cost and expenses | 21,175,735 | 15,520,848 | 12,857,977 | |||||||||
| Income from operations | 596,743 | 387,689 | 265,952 | |||||||||
| Other income (expense): | ||||||||||||
| Change in fair value of catalyst leases | (2,247 | ) | 1,422 | 10,184 | ||||||||
| Debt extinguishment costs | (25,451 | ) | — | — | ||||||||
| Interest expense, net | (122,628 | ) | (129,536 | ) | (88,194 | ) | ||||||
| Income before income taxes | 446,417 | 259,575 | 187,942 | |||||||||
| Income tax (benefit) expense | (10,783 | ) | 23,689 | 648 | ||||||||
| Net income | 457,200 | 235,886 | 187,294 | |||||||||
| Less: net income attributable to noncontrolling interests | 95 | 269 | 274 | |||||||||
| Net income attributable to PBF Holding Company LLC | $ | 457,105 | $ | 235,617 | $ | 187,020 | ||||||
PBF HOLDING COMPANY LLC
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)millions)
| Year Ended December 31, | |||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||||||||||||||
| Net income (loss) | $ | (1,857.5) | $ | 388.2 | $ | 103.0 | |||||||||||||||||||||||
| Other comprehensive income (loss): | |||||||||||||||||||||||||||||
| Unrealized (loss) gain on available for sale securities | (0.1) | 0.4 | (0.1) | ||||||||||||||||||||||||||
| Net gain on pension and other post-retirement benefits | 3.7 | 13.8 | 3.1 | ||||||||||||||||||||||||||
| Total other comprehensive income | 3.6 | 14.2 | 3.0 | ||||||||||||||||||||||||||
| Comprehensive income (loss) | (1,853.9) | 402.4 | 106.0 | ||||||||||||||||||||||||||
| Less: comprehensive income (loss) attributable to noncontrolling interests | (0.3) | 0 | 0.1 | ||||||||||||||||||||||||||
| Comprehensive income (loss) attributable to PBF Holding Company LLC | $ | (1,853.6) | $ | 402.4 | $ | 105.9 | |||||||||||||||||||||||
See notes to consolidated financial statements.
F- 7
| Year Ended December 31, | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Net income | $ | 457,200 | $ | 235,886 | $ | 187,294 | |||||
| Other comprehensive (loss) income: | |||||||||||
| Unrealized (loss) gain on available for sale securities | (16 | ) | (42 | ) | 124 | ||||||
| Net (loss) gain on pension and other post-retirement benefits | (950 | ) | (2,550 | ) | 1,982 | ||||||
| Total other comprehensive (loss) income | (966 | ) | (2,592 | ) | 2,106 | ||||||
| Comprehensive income | 456,234 | 233,294 | 189,400 | ||||||||
| Less: comprehensive income attributable to noncontrolling interests | 95 | 269 | 274 | ||||||||
| Comprehensive income attributable to PBF Holding Company LLC | $ | 456,139 | $ | 233,025 | $ | 189,126 | |||||
PBF HOLDING COMPANY LLC
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(in thousands)millions)
| Member's Equity | Accumulated Other Comprehensive Income (Loss) | Retained Earnings (Accumulated Deficit) | Noncontrolling Interest | Total Equity | ||||||||||||||||||||||||||||
| Balance, January 1, 2018 | $ | 2,359.7 | $ | (26.9) | $ | 840.4 | $ | 10.8 | $ | 3,184.0 | ||||||||||||||||||||||
| Member distributions | 0 | 0 | (52.6) | 0 | (52.6) | |||||||||||||||||||||||||||
| Capital contributions from PBF LLC | 287.0 | 0 | 0 | 0 | 287.0 | |||||||||||||||||||||||||||
| Distribution of assets to PBF LLC | (13.7) | 0 | 0 | 0 | (13.7) | |||||||||||||||||||||||||||
| Stock based compensation | 19.7 | 0 | 0 | 0 | 19.7 | |||||||||||||||||||||||||||
| Comprehensive income | 0 | 3.0 | 102.9 | 0.1 | 106.0 | |||||||||||||||||||||||||||
| Other | (0.2) | 0 | (0.4) | 0 | (0.6) | |||||||||||||||||||||||||||
| Balance, December 31, 2018 | 2,652.5 | (23.9) | 890.3 | 10.9 | 3,529.8 | |||||||||||||||||||||||||||
| Member distributions | 0 | 0 | (121.6) | 0 | (121.6) | |||||||||||||||||||||||||||
| Capital contributions from PBF LLC | 228.5 | 0 | 0 | 0 | 228.5 | |||||||||||||||||||||||||||
| Distribution of assets to PBF LLC | (0.3) | 0 | 0 | 0 | (0.3) | |||||||||||||||||||||||||||
| Distribution of TVPC investment | (168.8) | 0 | 0 | 0 | (168.8) | |||||||||||||||||||||||||||
| Stock based compensation | 27.2 | 0 | 0 | 0 | 27.2 | |||||||||||||||||||||||||||
| Comprehensive income | 0 | 14.2 | 388.2 | 0 | 402.4 | |||||||||||||||||||||||||||
| Balance, December 31, 2019 | 2,739.1 | (9.7) | 1,156.9 | 10.9 | 3,897.2 | |||||||||||||||||||||||||||
| Member distributions | 0 | 0 | (23.1) | 0 | (23.1) | |||||||||||||||||||||||||||
| Capital contributions from PBF LLC | 42.4 | 0 | 0 | 0 | 42.4 | |||||||||||||||||||||||||||
| Stock based compensation | 28.2 | 0 | 0 | 0 | 28.2 | |||||||||||||||||||||||||||
| Comprehensive income (loss) | 0 | 3.6 | (1,857.2) | (0.3) | (1,853.9) | |||||||||||||||||||||||||||
| Balance, December 31, 2020 | $ | 2,809.7 | $ | (6.1) | $ | (723.4) | $ | 10.6 | $ | 2,090.8 | ||||||||||||||||||||||
See notes to consolidated financial statements.
F- 8
| Member's Equity | Accumulated Other Comprehensive Loss | Retained Earnings | Noncontrolling Interest | Total Equity | ||||||||||||||||
| Balance, January 1, 2015 | $ | 1,144,100 | $ | (26,876 | ) | $ | 513,292 | $ | — | $ | 1,630,516 | |||||||||
| Member distributions | — | — | (350,658 | ) | — | (350,658 | ) | |||||||||||||
| Capital contributions | 345,000 | — | — | — | 345,000 | |||||||||||||||
| Distribution of assets to PBF LLC | (19,233 | ) | — | — | — | (19,233 | ) | |||||||||||||
| Stock based compensation | 9,218 | — | — | — | 9,218 | |||||||||||||||
| Exercise of options and other | 90 | — | — | — | 90 | |||||||||||||||
| Net income | — | — | 187,020 | 274 | 187,294 | |||||||||||||||
| Other comprehensive income | — | 2,106 | — | — | 2,106 | |||||||||||||||
| Noncontrolling interest acquired in Chalmette Acquisition | — | — | — | 16,951 | 16,951 | |||||||||||||||
| Balance, December 31, 2015 | 1,479,175 | (24,770 | ) | 349,654 | 17,225 | 1,821,284 | ||||||||||||||
| Member distributions | — | — | (139,434 | ) | — | (139,434 | ) | |||||||||||||
| Capital contributions | 830,247 | — | — | — | 830,247 | |||||||||||||||
| Distribution of assets to PBF LLC | (172,743 | ) | — | — | — | (172,743 | ) | |||||||||||||
| Stock based compensation | 18,296 | — | — | — | 18,296 | |||||||||||||||
| Exercise of options and other | 886 | — | — | — | 886 | |||||||||||||||
| Net income | — | — | 235,617 | 269 | 235,886 | |||||||||||||||
| Other comprehensive loss | — | (2,592 | ) | — | — | (2,592 | ) | |||||||||||||
| Other | 2 | 1,400 | 682 | (4,981 | ) | (2,897 | ) | |||||||||||||
| Balance, December 31, 2016 | 2,155,863 | (25,962 | ) | 446,519 | 12,513 | 2,588,933 | ||||||||||||||
| Member distributions | — | — | (61,149 | ) | — | (61,149 | ) | |||||||||||||
| Capital contributions | 183,298 | — | — | — | 183,298 | |||||||||||||||
| Stock based compensation | 21,503 | — | — | — | 21,503 | |||||||||||||||
| Net income | — | — | 457,105 | 95 | 457,200 | |||||||||||||||
| Other comprehensive loss | — | (966 | ) | — | — | (966 | ) | |||||||||||||
| Other | (873 | ) | — | (2,044 | ) | (1,800 | ) | (4,717 | ) | |||||||||||
| Balance, December 31, 2017 | $ | 2,359,791 | $ | (26,928 | ) | $ | 840,431 | $ | 10,808 | $ | 3,184,102 | |||||||||
PBF HOLDING COMPANY LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)millions)
| Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||||||
| 2017 | 2016 | 2015 | 2020 | 2019 | 2018 | |||||||||||||||||||||||
| Cash flows from operating activities: | Cash flows from operating activities: | |||||||||||||||||||||||||||
| Net income | $ | 457,200 | $ | 235,886 | $ | 187,294 | ||||||||||||||||||||||
| Adjustments to reconcile net income to net cash provided by operations: | ||||||||||||||||||||||||||||
| Net income (loss) | Net income (loss) | $ | (1,857.5) | $ | 388.2 | $ | 103.0 | |||||||||||||||||||||
| Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities: | Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities: | |||||||||||||||||||||||||||
| Depreciation and amortization | 274,651 | 218,933 | 199,383 | Depreciation and amortization | 523.8 | 404.4 | 346.7 | |||||||||||||||||||||
| Impairment expense | Impairment expense | 91.8 | 0 | 0 | ||||||||||||||||||||||||
| Stock-based compensation | 21,503 | 18,296 | 9,218 | Stock-based compensation | 29.3 | 30.5 | 20.2 | |||||||||||||||||||||
| Change in fair value of catalyst leases | 2,247 | (1,422 | ) | (10,184 | ) | |||||||||||||||||||||||
| Change in fair value of catalyst obligations | Change in fair value of catalyst obligations | 11.8 | 9.7 | (5.6) | ||||||||||||||||||||||||
| Deferred income taxes | (12,526 | ) | 19,802 | — | Deferred income taxes | 7.3 | (8.8) | 7.2 | ||||||||||||||||||||
| Non-cash change in inventory repurchase obligations | 13,779 | 29,453 | 63,389 | Non-cash change in inventory repurchase obligations | (12.6) | 25.4 | (31.8) | |||||||||||||||||||||
| Non-cash lower of cost or market inventory adjustment | (295,532 | ) | (521,348 | ) | 427,226 | Non-cash lower of cost or market inventory adjustment | 268.0 | (250.2) | 351.3 | |||||||||||||||||||
| Change in fair value of contingent consideration | Change in fair value of contingent consideration | (79.3) | 0 | 0 | ||||||||||||||||||||||||
| Debt extinguishment costs | 25,451 | — | — | Debt extinguishment costs | 22.2 | 0 | 0 | |||||||||||||||||||||
| Pension and other post-retirement benefit costs | 42,242 | 37,987 | 26,982 | Pension and other post-retirement benefit costs | 55.7 | 44.8 | 47.4 | |||||||||||||||||||||
| Income from equity method investee | (14,565 | ) | (5,679 | ) | — | Income from equity method investee | 0 | (7.9) | (17.8) | |||||||||||||||||||
| Distributions from equity method investee | 20,244 | — | — | Distributions from equity method investee | 0 | 7.9 | 17.8 | |||||||||||||||||||||
| Loss (gain) on sale of assets | 1,458 | 11,374 | (1,004 | ) | ||||||||||||||||||||||||
| Gain on sale of assets | Gain on sale of assets | (477.8) | (29.9) | (43.1) | ||||||||||||||||||||||||
| Changes in operating assets and liabilities: | Changes in operating assets and liabilities: | |||||||||||||||||||||||||||
| Accounts receivable | (335,248 | ) | (161,122 | ) | 97,636 | Accounts receivable | 325.1 | (115.9) | 240.4 | |||||||||||||||||||
| Due to/from affiliates | 3,233 | 9,721 | 12,104 | Due to/from affiliates | 6.7 | 12.6 | (3.5) | |||||||||||||||||||||
| Inventories | (54,705 | ) | 236,602 | (271,892 | ) | Inventories | 392.2 | (8.0) | (1.5) | |||||||||||||||||||
| Prepaid and other current assets | (9,191 | ) | (5,783 | ) | (631 | ) | Prepaid and other current assets | (3.0) | 4.4 | (2.9) | ||||||||||||||||||
| Accounts payable | 34,527 | 213,514 | (25,015 | ) | Accounts payable | (200.6) | 132.0 | (110.7) | ||||||||||||||||||||
| Accrued expenses | 353,115 | 227,986 | (37,737 | ) | Accrued expenses | 111.5 | 209.5 | (233.0) | ||||||||||||||||||||
| Deferred revenue | (4,845 | ) | 8,297 | 2,816 | Deferred revenue | 28.2 | (0.2) | 9.6 | ||||||||||||||||||||
| Other assets and liabilities | (51,974 | ) | (20,878 | ) | (27,182 | ) | Other assets and liabilities | (62.8) | (58.9) | 1.3 | ||||||||||||||||||
| Net cash provided by operations | 471,064 | 551,619 | 652,403 | |||||||||||||||||||||||||
| Net cash (used in) provided by operating activities | Net cash (used in) provided by operating activities | $ | (820.0) | $ | 789.6 | $ | 695.0 | |||||||||||||||||||||
| Cash flows from investing activities: | Cash flows from investing activities: | |||||||||||||||||||||||||||
| Acquisition of Torrance refinery and related logistics assets | — | (971,932 | ) | — | ||||||||||||||||||||||||
| Acquisition of Chalmette refinery, net of cash acquired | — | (2,659 | ) | (565,304 | ) | |||||||||||||||||||||||
| Expenditures for property, plant and equipment | (232,656 | ) | (282,430 | ) | (352,365 | ) | Expenditures for property, plant and equipment | (183.9) | (373.1) | (277.3) | ||||||||||||||||||
| Expenditures for deferred turnaround costs | (379,114 | ) | (198,664 | ) | (53,576 | ) | Expenditures for deferred turnaround costs | (188.1) | (299.3) | (266.0) | ||||||||||||||||||
| Expenditures for other assets | (31,143 | ) | (42,506 | ) | (8,236 | ) | Expenditures for other assets | (9.1) | (44.7) | (17.0) | ||||||||||||||||||
| Acquisition of Martinez refinery | Acquisition of Martinez refinery | (1,176.2) | 0 | 0 | ||||||||||||||||||||||||
| Proceeds from sale of assets | — | 24,692 | 168,270 | Proceeds from sale of assets | 543.1 | 36.3 | 48.3 | |||||||||||||||||||||
| Equity method investment - return of capital | 1,300 | — | — | Equity method investment - return of capital | 0 | 0.6 | 2.4 | |||||||||||||||||||||
| Net cash used in investing activities | $ | (641,613 | ) | $ | (1,473,499 | ) | $ | (811,211 | ) | Net cash used in investing activities | $ | (1,014.2) | $ | (680.2) | $ | (509.6) | ||||||||||||
| Cash flows from financing activities: | |||||||||||
| Contributions from PBF LLC | $ | 97,000 | $ | 450,300 | $ | 345,000 | |||||
| Distributions to members | (61,149 | ) | (139,434 | ) | (350,658 | ) | |||||
| Distributions to T&M and Collins shareholders | (1,800 | ) | — | — | |||||||
| Payment received for affiliate note receivable | 11,600 | — | — | ||||||||
| Proceeds from affiliate notes payable | — | 43,396 | 347,783 | ||||||||
| Repayments of affiliate notes payable | — | (53,524 | ) | — | |||||||
| Proceeds from 2025 7.25% Senior Notes | 725,000 | — | — | ||||||||
| Cash paid to extinguish 2020 8.25% Senior Secured Notes | (690,209 | ) | — | — | |||||||
| Proceeds from revolver borrowings | 490,000 | 550,000 | 170,000 | ||||||||
| Repayments of revolver borrowings | (490,000 | ) | (200,000 | ) | (170,000 | ) | |||||
| Proceeds from Rail Facility revolver borrowings | — | — | 102,075 | ||||||||
| Repayments of Rail Facility revolver borrowings | — | (67,491 | ) | (71,938 | ) | ||||||
| Proceeds from PBF Rail Term Loan | — | 35,000 | — | ||||||||
| Repayments of PBF Rail Term Loan | (6,633 | ) | — | — | |||||||
| Proceeds from 2023 Senior Notes | — | — | 500,000 | ||||||||
| Proceeds from catalyst lease | 10,830 | 15,589 | — | ||||||||
| Repayments of note payable | (1,210 | ) | — | — | |||||||
| Deferred financing costs and other | (13,425 | ) | — | (17,108 | ) | ||||||
| Net cash provided by financing activities | $ | 70,004 | $ | 633,836 | $ | 855,154 | |||||
| Net (decrease) increase in cash and cash equivalents | $ | (100,545 | ) | $ | (288,044 | ) | $ | 696,346 | |||
| Cash and equivalents, beginning of period | 626,705 | 914,749 | 218,403 | ||||||||
| Cash and equivalents, end of period | $ | 526,160 | $ | 626,705 | $ | 914,749 | |||||
| Supplemental cash flow disclosure | |||||||||||
| Non-cash activities: | |||||||||||
| Conversion of affiliate notes payable to capital contribution | $ | 86,298 | $ | 379,947 | $ | — | |||||
| Conversion of Delaware Economic Development Authority loan to grant | — | 4,000 | 4,000 | ||||||||
| Accrued and unpaid capital expenditures | 25,382 | 34,055 | 7,974 | ||||||||
| Distribution of assets to PBF Energy Company LLC | 25,547 | 172,743 | 19,233 | ||||||||
| Note payable issued for purchase of property, plant and equipment | 6,831 | — | — | ||||||||
| Cash paid during the year for: | |||||||||||
| Interest (net of capitalized interest of $5,937, $8,333 and $3,529 in 2017, 2016 and 2015, respectively) | $ | 131,416 | $ | 108,547 | $ | 79,842 | |||||
| Income taxes | — | 2,449 | — | ||||||||
See notes to consolidated financial statements.
F- 89
PBF HOLDING COMPANY LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
(in millions)
| Cash flows from financing activities: | |||||||||||||||||
| Contributions from PBF LLC | $ | 42.4 | $ | 228.5 | $ | 287.0 | |||||||||||
| Distributions to members | (23.1) | (121.6) | (52.6) | ||||||||||||||
| Proceeds from 2025 9.25% Senior Secured Notes | 1,250.6 | 0 | 0 | ||||||||||||||
| Proceeds from 2028 6.00% Senior Notes | 1,000.0 | 0 | 0 | ||||||||||||||
| Redemption of 2023 7.00% Senior Notes | (517.5) | 0 | 0 | ||||||||||||||
| Proceeds from revolver borrowings | 1,450.0 | 1,350.0 | 0 | ||||||||||||||
| Repayments of revolver borrowings | (550.0) | (1,350.0) | (350.0) | ||||||||||||||
| Repayments of PBF Rail Term Loan | (7.2) | (7.0) | (6.8) | ||||||||||||||
| Repayments of note payable | 0 | 0 | (5.6) | ||||||||||||||
| Settlements of catalyst obligations | (8.8) | (6.5) | (9.1) | ||||||||||||||
| Proceeds from catalyst financing arrangements | 51.9 | 0 | 0 | ||||||||||||||
| Payments on financing leases | (12.4) | 0 | 0 | ||||||||||||||
| Deferred financing costs and other | (34.7) | (1.4) | (12.8) | ||||||||||||||
| Net cash provided by (used in) financing activities | $ | 2,641.2 | $ | 92.0 | $ | (149.9) | |||||||||||
| Net increase in cash and cash equivalents | 807.0 | 201.4 | 35.5 | ||||||||||||||
| Cash and cash equivalents, beginning of period | 763.1 | 561.7 | 526.2 | ||||||||||||||
| Cash and cash equivalents, end of period | $ | 1,570.1 | $ | 763.1 | $ | 561.7 | |||||||||||
| Supplemental cash flow disclosures | |||||||||||||||||
| Non-cash activities: | |||||||||||||||||
| Accrued and unpaid capital expenditures | $ | 31.1 | $ | 36.0 | $ | 89.5 | |||||||||||
| Assets acquired under operating and financing leases | 702.0 | 1,194.3 | 0 | ||||||||||||||
| Fair value of the Martinez Contingent Consideration at acquisition | 77.3 | 0 | 0 | ||||||||||||||
| Distribution of assets to PBF Energy Company LLC | 0 | 169.1 | 13.7 | ||||||||||||||
| Cash paid during the year for: | |||||||||||||||||
| Interest (net of capitalized interest of $11.9, $17.6 and $9.3 in 2020, 2019 and 2018, respectively) | $ | 162.9 | $ | 107.0 | $ | 124.4 | |||||||||||
| Income taxes | 1.0 | 1.2 | 0.6 | ||||||||||||||
See notes to consolidated financial statements.
F- 10
PBF HOLDING COMPANY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION
Description of the Business
PBF Holding Company LLC (“PBF Holding” or the “Company”), a Delaware limited liability company, together with its consolidated subsidiaries, owns and operates oil refineries and related facilities in North America. PBF Holding is a wholly-owned subsidiary of PBF Energy Company LLC (“PBF LLC”). PBF Energy Inc. (“PBF Energy”) is the sole managing member of, and owner of an equity interest representing approximately 96.7%99.2% of the outstanding economic interest in PBF LLC as of December 31, 2017.2020. PBF Investments LLC, (“PBF Investments”), Toledo Refining Company LLC, (“Toledo Refining” or “TRC”), Paulsboro Refining Company LLC (“Paulsboro Refining” or “PRC”PRC”), Delaware City Refining Company LLC (“Delaware City Refining” or “DCR”DCR”), Chalmette Refining, L.L.C. (“Chalmette Refining”), PBF Energy Western Region LLC, (“PBF Western Region”), Torrance Refining Company LLC, (“Torrance Refining”) and Torrance Logistics Company LLC and Martinez Refining Company LLC are PBF LLC’s principal operating subsidiaries and are all wholly-owned subsidiaries of PBF Holding. Collectively, PBF Holding and its consolidated subsidiaries are referred to hereinafter as the “Company”.
On May 14, 2014, PBF Logistics LP (“PBFX”), a Delaware master limited partnership, completed its initial public offering (the “PBFX Offering”) of 15,812,500 common units.. PBF Logistics GP LLC (“PBF GP”) serves as the general partner of PBFX. PBF GP is wholly-owned by PBF LLC. In connection with the PBFX Offering, PBF Holding contributed to PBFX the assets and liabilities of certain crude oil terminaling assets. In a series of additional transactions subsequent to the PBFX Offering, PBF Holding distributed certain additional assets to PBF LLC, which in turn contributed those assets to PBFX (as described in “Note 11 - Related Party Transactions”).
Substantially all of the Company’s operations are in the United States. As of December 31, 2017,2020, the Company’s oil refineries are all engaged in the refining of crude oil and other feedstocks into petroleum products, and have been aggregated to form one1 reportable segment. To generate earnings and cash flows from operations, the Company is primarily dependent upon processing crude oil and selling refined petroleum products at margins sufficient to cover fixed and variable costs and other expenses. Crude oil and refined petroleum products are commodities; and factors that are largely out of the Company’s control can cause prices to vary over time. The resulting potential margin volatility can have a material effect on the Company’s financial position, earnings and cash flow.flows.
COVID-19 and Market Developments
The impact of the unprecedented global health and economic crisis sparked by the novel coronavirus (“COVID-19”) pandemic and related adverse impact on economic and commercial activity has resulted in a significant reduction in demand for refined petroleum and petrochemical products. This significant demand reduction has had an adverse impact on the Company’s results of operations and liquidity position for the year ended December 31, 2020. In response, the Company has reduced throughput rates across its entire refining system and is currently operating all refineries at reduced rates.
It is impossible to estimate the duration or significance of the financial impact that will result from the COVID-19 pandemic. However, the extent of the impact of the COVID-19 pandemic on the Company’s business, financial condition, results of operations and liquidity will depend largely on future developments, including the duration of the outbreak, particularly within the geographic areas where the Company operates, and the related impact on overall economic activity, all of which are uncertain and cannot be predicted with certainty at this time.
F- 11
PBF HOLDING COMPANY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation and Presentation
These consolidated financial statementsConsolidated Financial Statements include the accounts of PBF Holding and its consolidated subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.
| Year Ended December 31, 2016 | ||||||||||
| As Previously Reported | Adjustments | As Reclassified | ||||||||
| Cost and expenses: | ||||||||||
| Cost of products and other | $ | 13,765,088 | — | $ | 13,765,088 | |||||
| Operating expenses (excluding depreciation and amortization expense as reflected below) | 1,390,582 | — | 1,390,582 | |||||||
| Depreciation and amortization expense | — | 204,005 | 204,005 | |||||||
| Cost of sales | 15,359,675 | |||||||||
| General and administrative expenses (excluding depreciation and amortization expense as reflected below) | 149,643 | — | 149,643 | |||||||
| Depreciation and amortization expense | 209,840 | (204,005) | 5,835 | |||||||
| Equity income in investee | (5,679) | — | (5,679) | |||||||
| Loss on sale of assets | 11,374 | — | 11,374 | |||||||
| Total cost and expenses | $ | 15,520,848 | $ | 15,520,848 | ||||||
| Year Ended December 31, 2015 | ||||||||||
| As Previously Reported | Adjustments | As Reclassified | ||||||||
| Cost and expenses: | ||||||||||
| Cost of products and other | $ | 11,611,599 | — | $ | 11,611,599 | |||||
| Operating expenses (excluding depreciation and amortization expense as reflected below) | 889,368 | — | 889,368 | |||||||
| Depreciation and amortization expense | — | 181,422 | 181,422 | |||||||
| Cost of sales | 12,682,389 | |||||||||
| General and administrative expenses (excluding depreciation and amortization expense as reflected below) | 166,904 | — | 166,904 | |||||||
| Depreciation and amortization expense | 191,110 | (181,422) | 9,688 | |||||||
| Gain on sale of assets | (1,004) | — | (1,004) | |||||||
| Total cost and expenses | $ | 12,857,977 | $ | 12,857,977 | ||||||
Cost Classifications
Cost of products and other consists of the cost of crude oil, other feedstocks, blendstocks and purchased refined products and the related in-bound freight and transportation costs.
Operating expenses (excluding depreciation and amortization) consists of direct costs of labor, maintenance and services, utilities, property taxes, environmental compliance costs and other direct operating costs incurred in connection with our refining operations. Such expenses exclude depreciation related to refining and logistics assets that are integral to the refinery production process, which is presented separately as Depreciation and amortization expense as a component of Cost of sales on the Company’s consolidated statementsConsolidated Statements of operations.Operations.
Reclassification
Use of Estimates
The preparation of the financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures. Actual results could differ from those estimates.
Impairment Assessment
The global crisis resulting from the spread of the COVID-19 pandemic continues to have a substantial impact on the economy and overall consumer demand for energy and hydrocarbon products. As a result of the enduring throughput reductions across the Company’s refineries and continued decrease in demand for the Company’s products, the Company determined an impairment triggering event had occurred as of December 31, 2020. As such, the Company performed an impairment assessment on its long-lived assets as of December 31, 2020. As a result of the impairment test, the Company concluded that the carrying values of its 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.
In connection with the Company’s ongoing strategic response plan to deal with the COVID-19 pandemic and its East Coast Refining Reconfiguration (as defined in “Note 6 - Property, Plant and Equipment, net”), it recorded an impairment charge of approximately $91.8 million associated to the write-down of certain assets and project abandonments. Refer to “Note 6 - Property, Plant and Equipment, net” for further details.
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 the Company’s assets are impaired requiring evaluation that may result in future impairment charges to earnings.
F- 12
PBF HOLDING COMPANY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 the Company’s acquisitions may include earn-out provisions or other forms of contingent consideration. As of the acquisition date, the Company records contingent consideration, as applicable, at the estimated fair value of expected future payments associated with the earn-out. Any changes to the recorded fair value of contingent consideration, subsequent to the measurement period, will be recognized as earnings in the period in which it occurs.
Cash and Cash Equivalents
The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The carrying amount of the cash equivalents approximates fair value due to the short-term maturity of those instruments.
Concentrations of Credit Risk
For the year ended December 31, 2020, only 1 customer, Royal Dutch Shell, accounted for 10% or more of the Company’s revenues (approximately 13%). For the years ended December 31, 2017, 20162019 and 2015 no2018 0 single customer amounted to greater than or equal to 10% of the Company’s revenues.
Revenue, Deferred Revenue and Accounts Receivable
Effective January 1, 2018, the Company adopted ASC 606, Revenues from Contracts with Customers (“ASC 606”). As a result, the Company has changed its accounting policy for the recognition of revenue from contracts with customers. The Company sells various refined products primarily through its refinery subsidiaries and recognizes revenue related to the sale of products when there is persuasive evidencecontrol of an agreement, the sales prices are fixedpromised goods or determinable, collectability is reasonably assured and when products are shipped or delivered in accordance with their respective agreements. Revenue for services is recorded whentransferred to the services have been provided. Certaincustomers, in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. Refer to “Note 17 - Revenues” for further discussion of the Company’s refineries have product offtake agreements with third-parties under which these third parties purchase a portionrevenue recognition policy, including deferred revenues and the practical expedients elected as part of the refineries’ daily gasoline production. The refineries also sell their products through short-term contracts or on the spot market.transition to ASC 606.
F- 13
PBF HOLDING COMPANY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
During 2019, PBF Holding and its subsidiaries, DCR and PRC, entered into amendments to the existing inventory intermediation agreements (as amended in the secondfirst quarter of 2019 and amended and restated in the third quartersquarter of 2017,2019, the “A&R“Inventory Intermediation Agreements”) with J. Aron & Company, a subsidiary of The Goldman Sachs Group, Inc. (“J. Aron”), pursuant to which certain terms of the existing inventory intermediation agreements were amended, including, among other things, pricingthe maturity date. On March 29, 2019 the Inventory Intermediation Agreement by and an extension ofamong J. Aron, PBF Holding and DCR was amended to add the terms. AsPBFX assets acquired from Crown Point International, LLC in October 2018 (the “East Coast Storage Assets”) as a result oflocation and crude oil as a new product type to be included in the amendments (i)J. Aron Products (as defined in “Note 5 - Inventories”) sold to J. Aron by DCR. On August 29, 2019 the A&RInventory Intermediation Agreement by and among J. Aron, PBF Holding and PRC relating to the Paulsboro refinery extends the termwas extended to December 31, 2019,2021, which term may be further extended by mutual consent of the parties to December 31, 20202022 and (ii) the A&RInventory Intermediation Agreement by and among J. Aron, PBF Holding and DCR relatingwas extended to the Delaware City refinery extends the term to July 1, 2019,June 30, 2021, which term may be further extended by mutual consent of the parties to July 1, 2020.
June 30, 2022.
Pursuant to each A&RInventory Intermediation Agreement, J. Aron will continue to purchasepurchases and holdholds title to certain of the intermediate and finished products (the “Products”)J. Aron Products produced by the Paulsboro and Delaware City refineries (the “Refineries”), respectively,refinery and delivered into tanks at the Refineries. Furthermore, J. Aron agrees to sell theStorage Tanks (as defined in “Note 5 - Inventories”). The J. Aron Products are sold back to Paulsboro refinery and Delaware City refinerythe Company as the J. Aron Products are discharged out of the Refineries’ tanks.J. Aron Storage Tanks. These purchases and sales are settled monthly at the daily market prices related to those products.J. Aron Products. These transactions are considered to be made in contemplation of each other and, accordingly, do not result in the recognition of a sale when title passes from the East Coast refineries to J. Aron. Additionally, J. Aron has the right to store the J. Aron Products purchased in tanksJ. Aron Storage Tanks under the A&RInventory Intermediation Agreements and will retain these storage rights for the term of the agreements. PBF Holding will continuecontinues to market and sell the J. Aron Products independently to third parties.
Accounts receivable are carried at invoiced amounts. An allowance for doubtful accounts is established, if required, to report such amounts at their estimated net realizable value. In estimating probable losses, management reviews accounts that are past due and determines if there are any known disputes. There was no0 allowance for doubtful accounts at December 31, 20172020 and 2016.2019.
Excise taxes on sales of refined products that are collected from customers and remitted to various governmental agencies are reported on a net basis.
Inventory
Inventories are carried at the lower of cost or market. The cost of crude oil, feedstocks, blendstocks and refined products are determined under the last-in first-out (“LIFO”) method using the dollar value LIFO method with increments valued based on average purchase prices during the year. The cost of supplies and other inventories is determined principally on the weighted average cost method.
Leases
Effective January 1, 2019, the Company adopted Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) 2016-02, Leases (“ASC 842”), using the modified retrospective approach. As of the date of implementation on January 1, 2019, the impact of the adoption of ASC 842 resulted in the recognition of a right of use asset and lease liability on the Company’s Consolidated Balance Sheets of approximately $853.9 million of which $604.4 million is attributable to leases with affiliates.
F- 14
PBF HOLDING COMPANY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company leases office space, office equipment, refinery facilities and equipment, railcars and other logistics assets primarily under non-cancelable operating leases, with terms typically ranging from one to twenty years, subject to certain renewal options as applicable. The Company considers those renewal or termination options that are reasonably certain to be exercised in the determination of the lease term and initial measurement of lease liabilities and right-of-use assets. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term. Interest expense for finance leases is incurred based on the carrying value of the lease liability. Leases with an initial term of 12 months or less are not recorded on the Company’s Consolidated Balance Sheets.
The Company determines whether a contract is or contains a lease at inception of the contract and whether that lease meets the classification criteria of a finance or operating lease. When available, the Company uses the rate implicit in the lease to discount lease payments to present value; however, most of the Company’s leases do not provide a readily determinable implicit rate. Therefore, the Company must discount lease payments based on an estimate of its incremental borrowing rate.
For substantially all classes of underlying assets, the Company has elected the practical expedient not to separate lease and non-lease components, which allows for combining the components if certain criteria are met. For certain leases of refinery support facilities, the Company accounts for the non-lease service component separately.
Property, Plant and Equipment
Property, plant and equipment additions are recorded at cost. The Company capitalizes costs associated with the preliminary, pre-acquisition and development/construction stages of a major construction project. The Company capitalizes the interest cost associated with major construction projects based on the effective interest rate of total borrowings. The Company also capitalizes costs incurred in the acquisition and development of software for internal use, including the costs of software, materials, consultants and payroll-related costs for employees incurred in the application development stage.
Depreciation is computed using the straight-line method over the following estimated useful lives:
| Process units and equipment | 5-25 years | |||||||
| Pipeline and equipment | 5-25 years | |||||||
| Buildings | 25 years | |||||||
| Computers, furniture and fixtures | 3-7 years | |||||||
| Leasehold improvements | 20 years | |||||||
| Railcars | 50 years | |||||||
Maintenance and repairs are charged to operating expenses as they are incurred. Improvements and betterments, which extend the lives of the assets, are capitalized.
Deferred Charges and Other Assets, Net
Deferred charges and other assets include refinery turnaround costs, catalyst, precious metals catalyst,metal catalysts, linefill, deferred financing costs and intangible assets. Refinery turnaround costs, which are incurred in connection with planned major maintenance activities, are capitalized when incurred and amortized on a straight-line basis over the period of time estimated to lapse until the next turnaround occurs (generallyoccurs. The amortization period generally ranges from 3 to 5 years).6 years; however, based upon the specific facts and circumstances, different periods of deferral occur.
As a result of the East Coast Refining Reconfiguration (as defined in “Note - 6 Property, Plant and Equipment, net), certain major processing units were temporarily idled. As such, the Company accelerated the recognition of approximately $56.2 million of unamortized deferred turnaround costs associated with these idled units.
F- 1215
PBF HOLDING COMPANY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Precious metals catalystmetal catalysts, linefill and linefillcertain other intangibles are considered indefinite-lived assets as they are not expected to deteriorate in their prescribed functions. Such assets are assessed for impairment in connection with the Company’s review of its long-lived assets as indicators of impairment develop.assets.
Deferred financing costs are capitalized when incurred and amortized over the life of the loan (generally 1 to 8 years).
Intangible assets with finite lives primarily consist of emission credits and permits and are amortized over their estimated useful lives (generally 1 to 10 years).
Long-Lived Assets and Definite-Lived Intangibles
The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. Impairment is evaluated by comparing the carrying value of the long-lived assets to the estimated undiscounted future cash flows expected to result from use of the assets and their ultimate disposition. If such analysis indicates that the carrying value of the long-lived assets is not considered to be recoverable, the carrying value is reduced to the fair value.
Impairment assessments inherently involve judgment as to assumptions about expected future cash flows and the impact of market conditions on those assumptions. Although management would utilizeutilizes assumptions that it believes are reasonable, future events and changing market conditions may impact management’s assumptions, which could produce different results.
Investments in Equity Method Investments
For equity investments that are not required to be consolidated under the variable or voting interest model, the Company evaluates the level of influence it is able to exercise over an entity’s operations to determine whether to use the equity method of accounting. The Company’s judgment regarding the level of control over an equity method investment includes considering key factors such as its ownership interest, participation in policy-making and other significant decisions and material intercompany transactions. Amounts recognized for equity method investments are included in equity method investments in the consolidated balance sheet and adjusted for the Company’s share of the net earnings and losses of the investee and cash distributions, which are included in the consolidated statements of operations and the consolidated statements of cash flows. Amounts recognized for earnings in excess of distributions of the Company’s equity method investments are included in the operating section of the consolidated statements of cash flows. The Company evaluates its equity method investments for impairment whenever events or changes in circumstances indicate that the carrying amounts of such investments may be impaired. A loss is recorded in earnings in the current period to write down the carrying value of the investment to fair value if a decline in the value of an equity method investment is determined to be other than temporary.
Asset Retirement Obligations
The Company records an asset retirement obligation at fair value for the estimated cost to retire a tangible long-lived asset at the time the Company incurs that liability, which is generally when the asset is purchased, constructed, or leased. The Company records the liability when it has a legal or contractual obligation to incur costs to retire the asset and when a reasonable estimate of the fair value of the liability can be made. If a reasonable estimate cannot be made at the time the liability is incurred, the Company will record the liability when sufficient information is available to estimate the liability’s fair value. Certain of the Company’s asset retirement obligations are based on its legal obligation to perform remedial activity at its refinery sites when it permanently ceases operations of the long-lived assets. The Company therefore considers the settlement date of these obligations to be indeterminable. Accordingly, the Company cannot calculate an associated asset retirement liability for these obligations at this time. The Company will measure and recognize the fair value of these asset retirement obligations when the settlement date is determinable.
F- 1316
PBF HOLDING COMPANY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Environmental Matters
Liabilities for future remediation costs are recorded when environmental assessments and/or remedial efforts are probable and the costs can be reasonably estimated. Other than for assessments, the timing and magnitude of these accruals generally are based on the completion of investigations or other studies or a commitment to a formal plan of action. Environmental liabilities are based on best estimates of probable future costs using currently available technology and applying current regulations, as well as the Company’s own internal environmental policies. The measurement of environmental remediation liabilities may be discounted to reflect the time value of money if the aggregate amount and timing of cash payments of the liabilities are fixed or reliably determinable. The actual settlement of the Company’s liability for environmental matters could materially differ from its estimates due to a number of uncertainties such as the extent of contamination, changes in environmental laws and regulations, potential improvements in remediation technologies and the participation of other responsible parties.
Stock-Based Compensation
Stock-based compensation includes the accounting effect of options to purchase PBF Energy Class A common stock granted by PBF Energy to certain PBF Holding employees, Series A warrants issued or granted by PBF LLC to employees in connection with their acquisition of PBF LLC Series A units, options to acquire Series A units of PBF LLC granted by PBF LLC to certain employees, Series B units of PBF LLC that were granted to certain members of management and restricted PBF LLC Series A Units and restricted PBF Energy Class A common stock granted to certain directors and officers. The estimated fair value of the options to purchase PBF Energy Class A common stock and the PBF LLC Series A warrants and options, is based on the Black-Scholes option pricing model and the fair value of the PBF LLC Series B units is estimated based on a Monte Carlo simulation model. The estimated fair value is amortized as stock-based compensation expense on a straight-line method over the vesting period and included in generalGeneral and administrationadministrative expense with forfeitures recognized in the period they occur.
PBF Energy grants performance share unit awards and performance unit awards to certain key employees. Performance awards granted to employees prior to November 1, 2020 are based on a three-year performance cycle with four measurement periods and performance awards granted to employees after November 1, 2020 are based on a three-year performance cycle having a single measurement period. The payout for each, which ranges from 0% to 200%, is based on the relative ranking of the total shareholder return (“TSR”) of PBF Energy’s common stock as compared to the TSR of a selected group of industry peer companies over an average of four measurement periods. The performance share unit awards and performance unit awards are each measured at fair value based on Monte Carlo simulation models. The performance share unit awards will be settled in PBF Energy Class A common stock and are accounted for as equity awards and the performance unit awards will be settled in cash and are accounted for as liability awards.
Income Taxes
As PBF Holding is a limited liability company treated as a “flow-through” entity for income tax purposes, there is no benefit or expense for federal or state income tax in the accompanying financial statements apart from the income taxes attributable to two2 subsidiaries acquired in connection with the acquisition of Chalmette Refining and the Company’s wholly-owned Canadian subsidiary, PBF Energy Limited (“PBF Ltd”Ltd.”). These subsidiaries are treated as C-corporations for tax purposes.
The FederalState tax returns for all years since 2014 and state tax returns for all years since 2013 or 20142015 are subject to examination by the respective tax authorities.
F- 17
PBF HOLDING COMPANY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Pension and Other Post-Retirement Benefits
The Company recognizes an asset for the overfunded status or a liability for the underfunded status of its pension and post-retirement benefit plans. The funded status is recorded within otherOther long-term liabilities or assets. Changes in the plans’ funded status are recognized in other comprehensive income in the period the change occurs.
Fair Value Measurement
A fair value hierarchy (Level 1, Level 2, or Level 3) is used to categorize fair value amounts based on the quality of inputs used to measure fair value. Accordingly, fair values derived from Level 1 inputs utilize quoted prices in active markets for identical assets or liabilities. Fair values derived from Level 2 inputs are based on quoted prices for similar assets and liabilities in active markets, and inputs other than quoted prices that are either directly or indirectly observable for the asset or liability. Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability.
The Company uses appropriate valuation techniques based on the available inputs to measure the fair values of its applicable assets and liabilities. When available, the Company measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value. In some valuations, the inputs may fall into different
levels in the hierarchy. In these cases, the asset or liability level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurements.
Financial Instruments
The estimated fair value of financial instruments has been determined based on the Company’s assessment of available market information and appropriate valuation methodologies. The Company’s non-derivative financial instruments that are included in current assets and current liabilities are recorded at cost in the consolidated balance sheets.Consolidated Balance Sheets. The estimated fair value of these financial instruments approximates their carrying value due to their short-term nature. Derivative instruments are recorded at fair value in the consolidated balance sheets.Consolidated Balance Sheets.
The Company’s commodity contracts are measured and recorded at fair value using Level 1 inputs based on quoted prices in an active market, Level 2 inputs based on quoted market prices for similar instruments, or Level 3 inputs based on third partythird-party sources and other available market based data. The Company’s catalyst lease obligationobligations and derivatives related to the Company’s crude oil and feedstocks and refined product purchase obligations are measured and recorded at fair value using Level 2 inputs on a recurring basis, based on observable market prices for similar instruments.
Derivative Instruments
The Company is exposed to market risk, primarily related to changes in commodity prices for the crude oil and feedstocks used in the refining process as well as the prices of the refined products sold.sold and the risk associated with the price of credits needed to comply with various governmental and regulatory environmental compliance programs. The accounting treatment for commodity and environmental compliance contracts depends on the intended use of the particular contract and on whether or not the contract meets the definition of a derivative.
All derivative instruments, not designated as normal purchases or sales, are recorded in the balance sheetConsolidated 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 currently in earnings. Contracts qualifying for the normal purchase and sales exemption are accounted for upon settlement. Cash flows related to derivative instruments that are not designated or do not qualify for hedge accounting treatment are included in operating activities.
F- 18
PBF HOLDING COMPANY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company designates certain derivative instruments as fair value hedges of a particular risk associated with a recognized asset or liability. At the inception of the hedge designation, the Company documents the relationship between the hedging instrument and the hedged item, as well as its risk management objective and strategy for undertaking various hedge transactions. Derivative gains and losses related to these fair value hedges, including hedge ineffectiveness, are recorded in cost of sales along with the change in fair value of the hedged asset or liability attributable to the hedged risk. Cash flows related to derivative instruments that are designated as fair value hedges are included in operating activities.
Economic hedges are hedges not designated as fair value or cash flow hedges for accounting purposes that are used to (i) manage price volatility in certain refinery feedstock and refined product inventories, and (ii) manage price volatility in certain forecasted refinery feedstock purchases and refined product sales. These instruments are recorded at fair value and changes in the fair value of the derivative instruments are recognized currently in cost of sales.
Derivative accounting is complex and requires management judgment in the following respects: identification of derivatives and embedded derivatives, determination of the fair value of derivatives, documentation of hedge relationships, assessment and measurement of hedge ineffectiveness and election and designation of the normal purchases and sales exception. All of these judgments, depending upon their timing and effect, can have a significant impact on the Company’s earnings.
Recently Adopted Accounting GuidancePronouncements
In January 2017,June 2016, the FASB issued ASU No. 2017-01, “Business Combinations2016-13, “Financial Instruments-Credit Losses (Topic 805)326): Clarifying the DefinitionMeasurement of a Business”Credit Losses on Financial Instruments” (“ASU 2017-01”2016-13”), which provides. This guidance to assist entities with evaluating when a setamends the guidance on measuring credit losses on financial assets held at amortized cost. ASU 2016-13 requires the measurement of transferredall expected credit losses for financial assets held at the reporting date based on historical experience, current conditions, and activities is a business. Under ASU 2017-01, it is expected that the definition of a business will be narrowedreasonable and more consistently applied. ASU 2017-01supportable forecasts. This guidance is effective for annual periodsfiscal years beginning after December 15, 2017,2019, including interim periods within those periods.fiscal years. The amendments inCompany adopted this ASU should be applied prospectively on or after the effective date. Early adoption of ASU 2017-01 is permitted and the Company early adopted the new standard in its consolidated financial statements and related disclosures effective January 1, 2017. The Company’s2020, which did not have a material impact on its Consolidated Financial Statements. Refer to “Note 4 - Current Expected Credit Losses” for further disclosure related to our adoption of this guidance did not materially impact its consolidated financial statements.pronouncement.
Recently Issued Accounting Pronouncements
In May 2014,March 2020, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers2020-04, “Reference Rate Reform (Topic 606)” requiring revenue848): Facilitation of the effects of reference rate reform on financial reporting”. The amendments in this ASU provide optional guidance to be recognized when promised goods or services are transferredalleviate the burden in accounting for reference rate reform, by allowing certain expedients and exceptions in applying GAAP to customers in an amount that reflectscontracts, hedging relationship and other transactions affected by the expected consideration for these goods or services. The new guidance supersedes the revenue recognition requirements in FASB ASC Topic 605, “Revenue Recognition”, and most industry-specific guidance. The Company has adopted this new standard effective January 1, 2018, using the modified retrospective application, whereby a cumulative effect adjustment will be recognized upon adoption, if applicable, and the guidance will be applied prospectively.
F- 1819