10-K 1 pbf-2017123110k.htm 10-K Document


 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
 
(Mark one)
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended: December 31, 2017
Or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from            to             
Commission File Number: 001-35764
 
PBF ENERGY INC.
(Exact name of registrant as specified in its charter)
 
DELAWARE
 
45-3763855 
 
 
 
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
One Sylvan Way, Second Floor
Parsippany, New Jersey
 
07054
(Address of principal executive offices)
 
(Zip Code)
Registrants’ telephone number, including area code: (973) 455-7500
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
 
Name of Each Exchange on Which Registered
Class A Common Stock, $0.001 par value 
 
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None.
 


Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  x Yes ¨ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act¨ Yes x No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports); and (2) has been subject to such filing requirements for the past 90 days. x  Yes    ¨  No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x  Yes    o  No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated
filer
 
Accelerated filer
 
Non-accelerated filer
(Do not check if a
smaller reporting
company)
 
Smaller reporting
company
 
Emerging growth company
x
 
¨
 
¨
 
¨
 
¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨  Yes    x  No
The aggregate market value of the Common Stock of PBF Energy Inc. held by non-affiliates as of June 30, 2017 was $2,425,403,143 based upon the New York Stock Exchange Composite Transaction closing price.
As of February 20, 2018, PBF Energy Inc. had outstanding 110,672,334 shares of Class A common stock and 24 shares of Class B common stock.
DOCUMENTS INCORPORATED BY REFERENCE
PBF Energy Inc. intends to file with the Securities and Exchange Commission a definitive Proxy Statement for its Annual Meeting of Stockholders within 120 days after December 31, 2017. Portions of the Proxy Statement are incorporated by reference in Part III of this Form 10-K to the extent stated herein.
 




PBF ENERGY INC.
TABLE OF CONTENTS
PART I
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PART II
 
 
 
 
 
 
 
 
 
 
 
PART III
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PART IV
 
 
 
 
 
 
 


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Explanatory Note
This Annual Report on Form 10-K is filed by PBF Energy Inc. (“PBF Energy”) which is a holding company whose primary asset is an equity interest in PBF Energy Company LLC (“PBF LLC”). PBF Energy is the sole managing member of, and owner of an equity interest representing approximately 96.7% of the outstanding economic interests in, PBF LLC as of December 31, 2017. PBF Energy operates and controls all of the business and affairs and consolidates the financial results of PBF LLC and its subsidiaries. PBF LLC is a holding company for the companies that directly and indirectly own and operate the business.
PART I
This Annual Report on Form 10-K is filed by PBF Energy. Unless the context indicates otherwise, the terms “we,” “us,” and “our” refer to both PBF Energy and its consolidated subsidiaries, including PBF LLC, PBF Holding Company LLC (“PBF Holding”), PBF Investments LLC (“PBF Investments”), Toledo Refining Company LLC (“Toledo Refining” or “TRC”), Paulsboro Refining Company LLC (“Paulsboro Refining” or “PRC”), Delaware City Refining Company LLC (“Delaware City Refining” or “DCR”), Chalmette Refining, L.L.C. (“Chalmette Refining”), PBF Western Region LLC (“PBF Western Region”), Torrance Refining Company LLC (“Torrance Refining”), Torrance Logistics Company LLC (“Torrance Logistics”), PBF Logistics GP LLC (“PBF GP”) and PBF Logistics LP (“PBFX”).
In this Annual Report on Form 10-K, we make certain forward-looking statements, including statements regarding our plans, strategies, objectives, expectations, intentions, and resources, under the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 to the extent such statements relate to the operations of an entity that is not a limited liability company or a partnership. You should read our forward-looking statements together with our disclosures under the heading: “Cautionary Statement for the Purpose of Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995.” When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in this Annual Report on Form 10-K under “Risk Factors” in Item 1A.


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ITEM. 1 BUSINESS
Overview
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 and Canada, 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, 2017, we own and operate five domestic oil refineries and related assets, which we acquired in 2010, 2011, 2015 and 2016. Our refineries have a combined processing capacity, known as throughput, of approximately 900,000 barrels per day (“bpd”), and a weighted-average Nelson Complexity Index of 12.2. We operate in two reportable business segments: Refining and Logistics.
PBF Energy was formed on November 7, 2011 and is a holding company whose primary asset is a controlling equity interest in PBF LLC. We are the sole managing member of PBF LLC and operate and control all of the business and affairs of PBF LLC. We consolidate the financial results of PBF LLC and its subsidiaries and record a noncontrolling interest in our consolidated financial statements representing the economic interests of the members of PBF LLC other than PBF Energy. PBF LLC is a holding company for the companies that directly or indirectly own and operate our business. PBF Holding is a wholly-owned subsidiary of PBF LLC and is the parent company for our refining operations. PBF Energy, through its ownership of PBF LLC, also consolidates the financial results of PBFX and records a noncontrolling interest for the economic interests in PBFX held by the public common unit holders of PBFX.
As of December 31, 2017, we held 110,586,762 PBF LLC Series C Units and our current and former executive officers and directors and certain employees held 3,767,464 PBF LLC Series A Units (we refer to all of the holders of the PBF LLC Series A Units as “the members of PBF LLC other than PBF Energy”). As a result, the holders of our issued and outstanding shares of our Class A common stock have approximately 96.7% of the voting power in us, and the members of PBF LLC other than PBF Energy through their holdings of Class B common stock have approximately 3.3% of the voting power in us.

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The following map details the locations of our refineries and the location of PBFX’s assets (each as defined below):
graphlocationa01.jpg

5



Refining
Our five refineries are located in Delaware City, Delaware, Paulsboro, New Jersey, Toledo, Ohio, New Orleans, Louisiana and Torrance, California. Each of these refineries is briefly described in the table below:
Refinery
Region
Nelson Complexity Index
Throughput Capacity (in barrels per day)
PADD
Crude Processed (1)
Source (1)
Delaware City
East Coast
11.3

190,000

1

light sweet through heavy sour
water, rail
Paulsboro
East Coast
13.2

180,000

1

light sweet through heavy sour
water
Toledo
Mid-Continent
9.2

170,000

2

light sweet
pipeline, truck, rail
Chalmette
Gulf Coast
12.7

189,000

3

light sweet through heavy sour
water, pipeline
Torrance
West Coast
14.9

155,000

5

medium and heavy
pipeline, water, truck
________
(1) Reflects the typical crude and feedstocks and related sources utilized under normal operating conditions and prevailing market environments.
On July 1, 2016, we closed our acquisition of the Torrance refinery and related logistics assets (the “Torrance Acquisition”). The Torrance refinery is strategically positioned in Southern California with advantaged logistics connectivity that offers flexible raw material sourcing and product distribution opportunities primarily in the California, Las Vegas and Phoenix area markets.
In addition to refining assets, the Torrance 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 assets is a 189-mile crude gathering and transportation system which delivers San Joaquin Valley crude oil directly from the field to the refinery. Additionally, the transaction included several pipelines which provide access to sources of crude oil including the Ports of Long Beach and Los Angeles, as well as clean product outlets with a direct pipeline supplying jet fuel to the Los Angeles airport. The Torrance refinery also has crude and product storage facilities with approximately 8.6 million barrels of shell capacity.
Logistics
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, 2017, a substantial majority of PBFX’s revenue is derived from long-term, fee-based commercial agreements with PBF Holding, which include minimum volume commitments, for receiving, handling, storing and transferring crude oil, refined products and natural gas. PBF Energy also has agreements with PBFX that establish fees for certain general and administrative services and operational and maintenance services provided by PBF Holding to PBFX. These transactions, other than those with third parties, are eliminated by PBF Energy in consolidation.
On May 14, 2014, PBFX completed its initial public offering (the “PBFX Offering”). As of December 31, 2017, PBF LLC held a 44.1% limited partner interest (consisting of 18,459,497 common units) in PBFX, with the remaining 55.9% limited partner interest held by the public unit holders. PBF LLC also owns all of the incentive distribution rights (“IDRs”) and indirectly owns a non-economic general partner interest in PBFX through its

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wholly-owned subsidiary, PBF Logistics GP LLC (“PBF GP”), the general partner of PBFX. The IDRs entitle PBF LLC to receive increasing percentages, up to a maximum of 50.0%, of the cash PBFX distributes from operating surplus in excess of $0.345 per unit per quarter. As a result of the payment on May 31, 2017 by PBFX of its distribution for the first quarter of 2017, the financial tests required for conversion of all of PBFX’s previously outstanding subordinated units into common units were satisfied. As a result, all of PBFX’s subordinated units, which were owned by PBF LLC, converted on a one-for-one basis into common units effective June 1, 2017. The conversion of the subordinated units did not impact the amount of cash distributions paid by PBFX or the total number of its outstanding units. The subordinated units were issued by PBFX in connection with its initial public offering in May 2014.
On February 15, 2017, PBFX entered into a contribution agreement (the “PNGPC Contribution Agreement”) between PBFX and PBF LLC. Pursuant to the PNGPC Contribution Agreement, PBF LLC contributed to PBFX’s wholly owned subsidiary, PBFX Operating Company LLC (“PBFX Op Co”), all of the issued and outstanding limited liability company interests of Paulsboro Natural Gas Pipeline Company LLC (“PNGPC”). PNGPC owns and operates an existing interstate natural gas pipeline that originates in Delaware County, Pennsylvania, at an interconnection with Texas Eastern pipeline that runs under the Delaware River and terminates at the delivery point to PBF Holding’s Paulsboro refinery, and is subject to regulation by the Federal Energy Regulatory Commission (“FERC”). In connection with the PNGPC Contribution Agreement, PBFX constructed a new 24” pipeline to replace the existing pipeline, which commenced services in August 2017 (the “Paulsboro Natural Gas Pipeline”). In consideration for the PNGPC limited liability company interests, PBFX delivered to PBF LLC (i) an $11.6 million intercompany promissory note in favor of Paulsboro Refining Company LLC (the “Promissory Note”), (ii) an expansion rights and right of first refusal agreement in favor of PBF LLC with respect to the Paulsboro Natural Gas Pipeline and (iii) an assignment and assumption agreement with respect to certain outstanding litigation involving PNGPC and the existing pipeline.
Effective February 2017, PBF Holding and PBFX Op Co entered into a ten-year storage services agreement (the “Chalmette Storage Services Agreement”) under which PBFX, through PBFX Op Co, began providing storage services to PBF Holding commencing on November 1, 2017 upon the completion of the construction of a new crude tank with a shell capacity of 625,000 barrels at PBF Holding’s Chalmette Refinery (the “Chalmette Storage Tank”). PBFX Op Co and Chalmette Refining have entered into a twenty-year lease for the premises upon which the tank is located and a project management agreement pursuant to which Chalmette Refining managed the construction of the tank.
On April 17, 2017, PBFX’s wholly-owned subsidiary, PBF Logistics Products Terminals LLC, acquired the Toledo, Ohio refined products terminal assets (the “Toledo Products Terminal”) from Sunoco Logistics L.P. for an aggregate purchase price of $10.0 million, plus working capital. The Toledo Products Terminal is directly connected to, and currently supplied by, PBF Holding’s Toledo refinery.
See “Item 1A. Risk Factors” and “Item 13. Certain Relationships and Related Transactions, and Director Independence.”


    


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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 U.S. Securities and Exchange Commission (SEC) by us are available on our website (under “Investors”) free of charge, soon after we file or furnish such material. In this same location, we also post our corporate governance guidelines, code of business conduct and ethics, and the charters of the committees of our board of directors. These documents are available free of charge in print to any stockholder that makes a written request to the Secretary, PBF Energy Inc., One Sylvan Way, Second Floor, Parsippany, New Jersey 07054.

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The diagram below depicts our organizational structure as of December 31, 2017:
pbfstructchart2017.gif

9



Operating Segments
We operate in two reportable business segments: Refining and Logistics. Our five oil refineries, including certain related logistics assets that are not owned by PBFX, are engaged in the refining of crude oil and other feedstocks into petroleum products, and are aggregated into the Refining segment. PBFX operates logistics assets such as crude oil and refined products terminaling, pipeline and storage assets. Certain of PBFX’s assets were previously operated and owned by various subsidiaries of PBF Holding and were acquired by PBFX in a series of transactions since its inception. PBFX is reported in the Logistics segment. A substantial majority of PBFX’s revenue is derived from long-term, fee based commercial agreements with PBF Holding and its subsidiaries and these intersegment related revenues are eliminated in consolidation. See “Note 20 - Segment Information” of our Notes to Consolidated Financial Statements, for detailed information on our operating results by business segment.
Refining Segment
We own and operate five refineries providing 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.
Delaware City 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. Delaware City is a fully integrated operation that receives crude via rail at its crude unloading facilities, or ship or barge at its docks located on the Delaware River. The crude and other feedstocks are stored in an extensive tank farm prior to processing. In addition, there is a 15-lane, 76,000 bpd capacity truck loading rack located adjacent to the refinery and a 23-mile interstate pipeline that are used to distribute clean products, which were sold to PBFX in conjunction with its acquisition of the DCR Products Pipeline and Truck Rack (as defined in “Note 3 - PBF Logistics LP” of our Notes to the Consolidated Financial Statements) in May 2015.
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 and is one of the largest and most complex refineries on the East Coast. The Delaware City refinery is one of two heavy crude coking refineries, the other being our Paulsboro refinery, on the East Coast of the United States with coking capacity 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 cracking unit (“FCC unit”), 47,000 bpd fluid coking unit and 18,000 bpd hydrocracking unit with vacuum distillation.
The following table approximates the Delaware City refinery’s major process unit capacities. Unit capacities are shown in barrels per stream day.

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Refinery Units
 
Nameplate
Capacity
Crude Distillation Unit
 
190,000

Vacuum Distillation Unit
 
102,000

Fluid Catalytic Cracking Unit
 
82,000

Hydrotreating Units
 
160,000

Hydrocracking Unit
 
18,000

Catalytic Reforming Unit
 
43,000

Benzene / Toluene Extraction Unit
 
15,000

Butane Isomerization Unit
 
6,000

Alkylation Unit
 
11,000

Polymerization Unit
 
16,000

Fluid Coking Unit
 
47,000

Feedstocks and Supply Arrangements. We currently fully source our own crude oil needs for Delaware City primarily through short-term and spot market agreements.
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. We market and sell all of our refined products independently to a variety of customers on the spot market or through term agreements.
Inventory Intermediation Agreement. On June 26, 2013, we entered into an Inventory Intermediation Agreement (the “Inventory Intermediation Agreement”) with J. Aron & Company, a subsidiary of The Goldman Sachs Group, Inc. (“J. Aron”) to support the operations of the Delaware City refinery, which commenced upon the termination of the previous product offtake agreement. Pursuant to such Inventory Intermediation Agreement, J. Aron purchases the Products produced and delivered into the refinery’s storage tanks 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, which term may be further extended by mutual consent of the parties to July 1, 2020. At expiration, we will have to repurchase the inventories outstanding under the Amended Delaware 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.
Energy and Other Utilities. Under normal operating conditions, the Delaware City refinery consumes approximately 65,000 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 provided via the refinery’s steam methane reformer and continuous catalytic reformer.

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Paulsboro Refinery
Overview. The Paulsboro refinery is located on approximately 950 acres on the Delaware River in Paulsboro, New Jersey, just south of Philadelphia and approximately 30 miles away from Delaware City. Paulsboro receives crude and feedstocks via its marine terminal on the Delaware River. Paulsboro is one of two operating refineries on the East Coast with coking capacity, the other being our Delaware City refinery. The Paulsboro refinery primarily processes a variety of medium and heavy, sour crude oils but can run light, sweet crude oils as well.
The following table approximates the Paulsboro refinery’s major process unit capacities. Unit capacities are shown in barrels per stream day. 
Refinery Units
 
Nameplate
Capacity
Crude Distillation Units
 
168,000

Vacuum Distillation Units
 
83,000

Fluid Catalytic Cracking Unit
 
55,000

Hydrotreating Units
 
141,000

Catalytic Reforming Unit
 
32,000

Alkylation Unit
 
11,000

Lube Oil Processing Unit
 
12,000

Delayed Coking Unit
 
27,000

Propane Deasphalting Unit
 
11,000

Feedstocks and Supply Arrangements. We have a contract with Saudi Aramco pursuant to which we have been purchasing up to approximately 100,000 bpd of crude oil from Saudi Aramco that is processed at Paulsboro. The crude purchased under this contract is priced off ASCI.
Refined Product Yield and Distribution. The Paulsboro refinery predominantly produces gasoline, diesel fuels and jet fuel and also manufactures Group I base oils or lubricants and asphalt. We market and sell all of our refined products independently to a variety of customers on the spot market or through term agreements under which we sell approximately 35% of our Paulsboro refinery’s gasoline production.
Inventory Intermediation Agreement. On June 26, 2013, we entered into an Inventory Intermediation Agreement with J. Aron to support the operations of the Paulsboro refinery, which commenced upon the termination of the previous product offtake agreement. Pursuant to such Inventory Intermediation Agreement, J. Aron purchases the Products produced and delivered into the refinery’s storage tanks 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, PRC, entered into amendments to the amended and restated inventory intermediation agreement (as amended, the “Amended Paulsboro 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 December 31, 2019, which term may be further extended by mutual consent of the parties to December 31, 2020. At expiration, we will have to repurchase the inventories outstanding under the Amended Paulsboro Intermediation Agreement at that time.
Tankage Capacity. 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 Paulsboro refinery consumes approximately 30,000 MMBTU per day of natural gas supplied via pipeline from third parties. The Paulsboro refinery is virtually self-sufficient for its electrical power requirements. The refinery supplies approximately 90% of its 63 MW load through a combination of four generators with a nameplate capacity of 78 MW, in addition to

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a 30 MW gas turbine generator and two 15 MW steam turbine generators located at the Paulsboro utility plant. In the event that Paulsboro requires additional electricity to operate the refinery, supplemental power is available through a local utility. Paulsboro is connected to the grid via three separate 69 KV aerial feeders and has the ability to run entirely on imported power. Steam is primarily produced by three boilers, each with continuous rated capacity of 300,000-lb/hr at 900-psi. In addition, Paulsboro has a heat recovery steam generator and a number of waste heat boilers throughout the refinery that supplement the steam generation capacity. Paulsboro’s current hydrogen needs are met by the hydrogen supply from the reformer. In addition, the refinery employs a standalone steam methane reformer that is capable of producing 10 MMSCFD of 99% pure hydrogen. This ancillary hydrogen plant is utilized as a back-up source of hydrogen for the refinery’s process units.
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) Capline from the south 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 major process unit capacities. Unit capacities are shown in barrels per stream day.
Refinery Units
 
Nameplate
Capacity
Crude Distillation Unit
 
170,000

Fluid Catalytic Cracking Unit
 
79,000

Hydrotreating Units
 
95,000

Hydrocracking Unit
 
45,000

Catalytic Reforming Units
 
45,000

Alkylation Unit
 
10,000

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 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. 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 36 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 2017, the agreement was renewed and extended for a two 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

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and products. A portion of storage capacity dedicated to crude oil and finished products was sold to PBFX in conjunction with its acquisition of the Toledo Storage Facility (as defined in “Note 3 - PBF Logistics LP” of our Notes to Consolidated Financial Statements) in December 2014.
Energy and Other Utilities. Under normal operating conditions, the Toledo refinery consumes approximately 20,000 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.
Chalmette Refinery
Acquisition. On November 1, 2015, we acquired the ownership interests of Chalmette Refining, L.L.C. (“Chalmette Refining”), which owns the Chalmette refinery and related logistics assets (collectively, the “Chalmette Acquisition”).
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 though its 189,000 bpd crude units and downstream units. Chalmette Refining owns 100% of the MOEM Pipeline, providing access to the Empire Terminal, as well as the CAM Connection Pipeline, providing access to the Louisiana Offshore Oil Port facility through a third party pipeline. Chalmette Refining also owns 80% of each of the Collins Pipeline Company and T&M Terminal Company, both located in Collins, Mississippi, which provide a clean products outlet for the refinery to the Plantation and Colonial Pipelines. Also included in the acquisition were a marine terminal capable of importing waterborne feedstocks and loading or unloading finished products; a clean products truck rack which provides access to local markets; and a crude and product storage facility.
The following table approximates the Chalmette refinery’s major process unit capacities. Unit capacities are shown in barrels per stream day.
Refinery Units
 
Nameplate
Capacity
Crude Distillation Units
 
189,000

Fluid Catalytic Cracking Unit
 
72,000

Hydrotreating Units
 
186,000

Delayed Coker
 
29,000

Catalytic Reforming Unit
 
40,000

Alkylation Unit
 
15,000

Feedstocks and Supply Arrangements. In connection with the Chalmette Acquisition 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 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 crude and feedstocks from other sources through connections to the CAM and MOEM pipelines as well as our marine terminal.
Refined Product Yield and Distribution. The Chalmette refinery predominantly produces gasoline, 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 Pipeline and T&M Terminal provides Chalmette with strategic access to Southeast and East Coast markets through third 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.

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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 30,000 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.
Torrance Refinery
Acquisition. On July 1, 2016, we acquired from ExxonMobil, Mobil Pacific Pipe Line Company, the Torrance refinery and related logistics assets (collectively, the “Torrance Acquisition”). Subsequent to the closing of the Torrance Acquisition, Torrance Refining and Torrance Logistics are indirect wholly-owned subsidiaries of PBF Holding. The aggregate purchase price for the Torrance Acquisition was approximately $521.4 million in cash after post-closing purchase price adjustments, plus final working capital of $450.6 million.
Overview. The Torrance refinery is located on 750 acres in Torrance, California. It is a high-conversion crude, delayed-coking refinery. It is capable of processing both heavy and medium crude oil though its crude unit and downstream units. In addition to refining assets, the Torrance 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 assets is a crude gathering and transportation system which delivers San Joaquin Valley crude oil directly from the field to the refinery. Additionally, included in the transaction are several pipelines which provide access to sources of crude oil including the Ports of Long Beach and Los Angeles, as well as clean product outlets with a direct pipeline supplying jet fuel to the Los Angeles airport.
The following table approximates the Torrance refinery’s major process unit capacities. Unit capacities are shown in barrels per stream day.
Refinery Units
 
Nameplate
Capacity
Crude Distillation Unit
 
155,000

Vacuum Distillation Unit
 
102,000

Fluid Catalytic Cracking Unit
 
88,000

Hydrotreating Units
 
151,000

Hydrocracking Unit
 
23,000

Alkylation Unit
 
27,000

Delayed Coker
 
53,000

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, 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. This crude supply agreement has a five year term with an automatic renewal feature unless either party gives thirty-six months prior written notice. Additionally, we obtain crude and feedstocks from other sources through connections to third party pipelines as well as ship docks and truck racks.
Refined Product Yield and Distribution. The Torrance refinery predominantly produces gasoline, jet fuel and diesel fuels. Products produced at the Torrance refinery are transferred to customers through pipelines, the marine terminal and truck rack. The majority of clean products are delivered to customers via pipelines. We have an offtake agreement with ExxonMobil pursuant to which ExxonMobil purchases approximately 50% of our gasoline production. This offtake agreement has an initial term of three years from the date of the Torrance

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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.
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 42,000 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.
Logistics Segment
We formed PBFX, a publicly traded master limited partnership, to own or lease, operate, develop and acquire crude oil and refined petroleum products terminals, pipelines, storage facilities and similar logistics assets. PBFX’s operations are aggregated into the Logistics segment. PBFX engages in the receiving, handling, storage and transferring of crude oil, refined products, natural gas and intermediates from sources located throughout the United States and Canada for PBF Energy in support of its refineries, as well as for third party customers. A substantial majority of PBFX’s revenues is derived from long-term, fee-based commercial agreements with PBF Holding, which include minimum volume commitments, for receiving, handling, storing and transferring crude oil, refined products and natural gas. PBFX’s third party revenue is primarily derived from its East Coast Terminals (as defined below). PBF Energy also has agreements with PBFX that establish fees for certain general and administrative services and operational and maintenance services provided by PBF Holding to PBFX. These transactions, other than those with third parties, are eliminated by PBF Energy in consolidation.
As of December 31, 2017, PBFX’s assets consist of the following:
The DCR Rail Terminal - A 130,000 bpd light crude oil rail unloading terminal which commenced operations in February 2013 and serves PBF Holding’s Delaware City and Paulsboro refineries.
The DCR West Rack - A 40,000 bpd heavy crude oil unloading rack which commenced operations in August 2014 and serves PBF Holding’s Delaware City refinery.
The Toledo Truck Terminal - A truck terminal comprised of six lease automatic custody transfer (“LACT”) units, with crude unloading capacity of 22,500 bpd.
The Toledo Storage Facility - A storage facility which services PBF Holding’s Toledo refinery and consists of 30 tanks for storing crude oil, refined products and intermediates with aggregate capacity of 3.9 million barrels as well as a propane storage and unloading facility consisting of 27 propane storage bullets and a truck loading facility with a throughput capacity of 11,000 bpd.
DCR Products Pipeline and Truck Rack - The DCR Products Pipeline consists of a 23.4 mile, 16-inch interstate petroleum products pipeline with an excess of 125,000 bpd of capacity located at PBF Holding’s Delaware City refinery. The DCR Truck Rack consists of a 15-lane, 76,000 bpd capacity truck loading rack utilized to distribute gasoline and distillates.
East Coast Terminals - The East Coast Terminals include a total of 57 product tanks with a total shell capacity of approximately 4.2 million barrels, pipeline connections to the Colonial Pipeline Company, Buckeye Partners, Sunoco Logistics Partners and other proprietary pipeline systems, 26 truck loading lanes and marine facilities capable of handling barges and ships.
Torrance Valley Pipeline - PBFX acquired from PBF LLC 50% of the issued and outstanding limited liability company interests of TVPC, whose assets consist of the 189-mile San Joaquin Valley Pipeline

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system, which consists of the M55, M1 and M70 pipeline systems with 110,000 bpd of capacity, including 11 pipeline stations with storage capacity and truck unloading capability at two of the stations.
Paulsboro Natural Gas Pipeline - A 24” interstate natural gas pipeline with 60,000 dekatherms/day capacity that originates in Delaware County, Pennsylvania, at an interconnection with Texas Eastern pipeline that runs under the Delaware River and terminates at the delivery point to PBF Holding’s Paulsboro refinery.
Chalmette Storage Tank - A crude oil storage tank with a shell capacity of 625,000 barrels located at PBF Holding’s Chalmette refinery (the “Chalmette Storage Tank”).
Toledo Products Terminal - The Toledo Products Terminal is located adjacent to PBF Holding’s Toledo refinery and is comprised of a ten-bay truck rack and over 110,000 barrels of chemicals, clean product and additive storage capacity.
Transactions with PBFX
Since the inception of PBFX in 2014, PBF LLC and PBFX have entered into a series of drop-down transactions. Such transactions occurring in the three years ended December 31, 2017 are discussed below.
Effective May 14, 2015, PBF LLC contributed to PBFX all of the issued and outstanding limited liability company interests of Delaware Pipeline Company LLC and Delaware City Logistics Company LLC, whose assets consist of the DCR Products Pipeline and the DCR Truck Rack (collectively referred to as the “DCR Products Pipeline and Truck Rack”), for total consideration of $143.0 million, consisting of $112.5 million of cash and $30.5 million of PBFX common units, or 1,288,420 common units.
On August 31, 2016, PBFX entered into a contribution agreement (the “TVPC Contribution Agreement”) between PBFX and PBF LLC. Pursuant to the TVPC Contribution Agreement, PBFX acquired from PBF LLC 50% of the issued and outstanding limited liability company interests of TVPC, whose assets consist of the San Joaquin Valley Pipeline system (which was acquired as a part of the Torrance Acquisition). The total consideration paid to PBF LLC was $175.0 million, which was funded by PBFX with $20.0 million of cash on hand, $76.2 million in proceeds from the sale of marketable securities, and $78.8 million in net proceeds from the PBFX equity offering in August 2016.
On February 15, 2017, PBFX entered into the PNGPC Contribution Agreement between PBFX and PBF LLC. Pursuant to the PNGPC Contribution Agreement, PBF LLC contributed to PBFX’s wholly owned subsidiary, PBFX Op Co, all of the issued and outstanding limited liability company interests of PNGPC. PNGPC owns and operates an existing interstate natural gas pipeline that originates in Delaware County, Pennsylvania, at an interconnection with Texas Eastern pipeline that runs under the Delaware River and terminates at the delivery point to PBF Holding’s Paulsboro refinery, and is subject to regulation by the FERC. In connection with the PNGPC Contribution Agreement, PBFX constructed a new 24” pipeline to replace the existing pipeline, which commenced services in August 2017. In consideration for the PNGPC limited liability company interests, PBFX delivered to PBF LLC (i) an $11.6 million intercompany promissory note in favor of Paulsboro Refining Company LLC, a wholly owned subsidiary of PBF Holding, (ii) an expansion rights and right of first refusal agreement in favor of PBF LLC with respect to the Paulsboro Natural Gas Pipeline and (iii) an assignment and assumption agreement with respect to certain outstanding litigation involving PNGPC and the existing pipeline.
Effective February 2017, PBF Holding and PBFX Op Co entered into a ten-year storage services agreement under which PBFX, through PBFX Op Co, began providing storage services to PBF Holding commencing on November 1, 2017 upon the completion of the construction of a new crude tank with a shell capacity of 625,000 barrels at PBF Holding’s Chalmette Refinery. PBFX Op Co and Chalmette Refining have entered into a twenty-year lease for the premises upon which the tank is located and a project management agreement pursuant to which Chalmette Refining managed the construction of the tank.

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In connection with the foregoing transactions, PBF Holding entered into commercial agreements with PBFX entities for the provision of services which require minimum monthly throughput volumes. Subsequent to the transactions described above, as of December 31, 2017, PBF LLC holds a 44.1% limited partner interest in PBFX consisting of 18,459,497common units. PBF LLC also owns all of the IDRs and indirectly owns a non-economic general partner interest in PBFX. The IDRs entitle PBF LLC to receive increasing percentages, up to a maximum of 50.0%, of the cash PBFX distributes from operating surplus in excess of $0.345 per unit per quarter.
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, 2016 and 2015, gasoline and distillates accounted for 84.1%, 88.0% and 88.0% 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 years ended December 31, 2017, 2016 and 2015, no single customer accounted for 10% or more of our revenues, respectively. As of December 31, 2017 and December 31, 2016, no single customer accounted for 10% or more of our total trade accounts receivable.
Seasonality
Demand for gasoline and diesel is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and construction work. Decreased demand during the winter months can lower gasoline and diesel prices. As a result, our operating results for the first and fourth calendar quarters may be lower than those for the second and third calendar quarters of each year. Refining margins remain volatile and our results of operations may not reflect these historical seasonal trends. Additionally, the degree of seasonality may differ by the geographic areas in which we operate. Most of the effects of seasonality on PBFX’s operating results are mitigated through fee-based commercial agreements with us that include minimum volume commitments.
Competition
The refining business is very competitive. We compete directly with various other refining companies on the East, Gulf and West Coasts and in the Mid-Continent, with integrated oil companies, with foreign refiners that import products into the United States and with producers and marketers in other industries supplying alternative forms of energy and fuels to satisfy the requirements of industrial, commercial and individual consumers. Some of our competitors have expanded the capacity of their refineries and internationally new refineries are coming on line which could also affect our competitive position.
Profitability in the refining industry depends largely on refined product margins, which can fluctuate significantly, as well as crude oil prices and differentials between the prices of different grades of crude oil, operating efficiency and reliability, product mix and costs of product distribution and transportation. Certain of our competitors that have larger and more complex refineries may be able to realize lower per-barrel costs or higher margins per barrel of throughput. Several of our principal competitors are integrated national or international oil companies that are larger and have substantially greater resources. Because of their integrated operations and larger capitalization, these companies may be more flexible in responding to volatile industry or market conditions, such as shortages of feedstocks or intense price fluctuations. Refining margins are frequently impacted by sharp changes in crude oil costs, which may not be immediately reflected in product prices.
The refining industry is 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

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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 58,000 square feet for our principal corporate offices in Parsippany, New Jersey. The lease for our principal corporate offices expires in 2019. Functions performed in the Parsippany office include overall corporate management, refinery and HSE 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.
We lease approximately 5,000 square feet for our regional corporate office in The Woodlands, Texas. The lease for The Woodlands office expires in 2022. Functions performed in The Woodlands include pipeline control center operations and logistics operations, engineering and regulatory support functions.
Employees
As of December 31, 2017, we had approximately 3,165 employees. At our Paulsboro refinery, 286 of our 461 employees are covered by a collective bargaining agreement. In addition, 1,331 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. 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.
Executive Officers of the Registrant
The following is a list of our executive officers as of February 22, 2018:
Name
 
Age (as of December 31, 2017)
 
Position
Thomas J. Nimbley
 
66

 
Chief Executive Officer and Chairman of the Board of Directors
Matthew C. Lucey
 
44

 
President
Erik Young
 
40

 
Senior Vice President, Chief Financial Officer
Paul Davis
 
55

 
President, Western Region
Thomas L. O’Connor
 
45

 
Senior Vice President, Commercial
Herman Seedorf
 
66

 
Senior Vice President of Refining
Trecia Canty
 
48

 
Senior Vice President, General Counsel
Thomas J. Nimbley has served as our Chief Executive Officer since June 2010 and on our Board of Directors since October 2014. He has served as the Chairman of our Board since July 2016. He was our Executive Vice President, Chief Operating Officer from March 2010 through June 2010. In his capacity as our Chief Executive Officer, Mr. Nimbley also serves as a director and the Chief Executive Officer of certain of our subsidiaries and our affiliates, including Chairman of the Board of PBF GP. Prior to joining us, Mr. Nimbley served as a Principal

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for Nimbley Consultants LLC from June 2005 to March 2010, where he provided consulting services and assisted on the acquisition of two refineries. He previously served as Senior Vice President and head of Refining for Phillips Petroleum Company (“Phillips”) and subsequently Senior Vice President and head of Refining for ConocoPhillips (“ConocoPhillips”) domestic refining system (13 locations) following the merger of Phillips and Conoco Inc. Before joining Phillips at the time of its acquisition of Tosco Corporation (“Tosco”) in September 2001, Mr. Nimbley served in various positions with Tosco and its subsidiaries starting in April 1993.
Matthew C. Lucey has served as our President since January 2015 and was our Executive Vice President from April 2014 to December 2014. Mr. Lucey served as our Senior Vice President, Chief Financial Officer from April 2010 to March 2014. Mr. Lucey joined us as our Vice President, Finance in April 2008. Mr. Lucey is also a director of certain of our subsidiaries, including PBF GP. Prior thereto, Mr. Lucey served as a Managing Director of M.E. Zukerman & Co., a New York-based private equity firm specializing in several 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.
Erik Young has served as our Senior Vice President and Chief Financial Officer since April 2014 after joining us in December 2010 as Director, Strategic Planning where he was responsible for both corporate development and capital markets initiatives. Mr. Young is also a director of certain of our subsidiaries, including PBF GP. Prior to joining the Company, Mr. Young spent eleven years in corporate finance, strategic planning and mergers and acquisitions roles across a variety of industries. He began his career in investment banking before joining J.F. Lehman & Company, a private equity investment firm, in 2001.
Paul Davis has served as our President, PBF Energy Western Region LLC since September 2017. Mr. Davis joined us in April of 2012 and served as head of 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 our Co-Head of Commercial and served 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 Senior Vice President, Commercial since September 2015. Mr. O’Connor joined us as Senior Vice President in September 2014 with responsibility for business development and growing the business of PBFX, and from January to September 2015, served as our Co-Head of commercial activities. Prior to joining us, Mr. O’Connor worked at Morgan Stanley since 2000 in various positions, most recently as a Managing Director and Global Head of Crude Oil Trading and Global Co-Head of Oil Flow Trading. Prior to joining Morgan Stanley, Mr. O’Connor worked for Tosco from 1995 to 2000 in the Atlantic Basin Fuel Oil and Feedstocks group.
Herman Seedorf serves as our Senior Vice President of Refining. Mr. Seedorf originally joined us in February of 2011 as the Delaware City Refinery Plant Manager and became Senior Vice President, Eastern Region Refining, in September of 2013. Prior to 2011, Mr. Seedorf served as the refinery manager of the Wood River Refinery in Roxana, Illinois, and also as an officer of the joint venture between ConocoPhillips and Cenovus Energy Inc. Mr. Seedorf’s oversight responsibilities included the development and execution of the multi-billion dollar upgrade project which enabled the expanded processing of Canadian crude oils. He also served as the refinery manager of the Bayway Refinery in Linden, New Jersey for four years during the time 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 Secretary since September 2015. In her role, Ms. Canty is responsible for the Legal Department and Contracts Administration. 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

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of our subsidiaries. Prior to joining us, Ms. Canty served as Associate General Counsel, Corporate and Assistant Secretary of Southwestern Energy Company, where her responsibilities included finance and mergers and acquisitions, securities and corporate compliance and corporate governance. She also provided legal support to the midstream marketing and logistics businesses. Prior to joining Southwestern Energy Company in 2004, she was an associate with Cleary, Gottlieb, Steen & Hamilton.
Environmental, Health and Safety Matters
Our refineries, pipelines and related operations are subject to extensive and frequently changing federal, state and local laws and regulations, including, but not limited to, those relating to the discharge of materials into the environment or that otherwise relate to the protection of the environment, waste management and the characteristics and the compositions of fuels. Compliance with existing and anticipated laws and regulations can increase the overall cost of operating the refineries, including remediation, operating costs and capital costs to construct, maintain and upgrade equipment and facilities. Permits are also required under these laws for the operation of our refineries, pipelines and related operations and these permits are subject to revocation, modification and renewal. Compliance with applicable environmental laws, regulations and permits will continue to have an impact on our operations, results of operations and capital requirements. We believe that our current operations are in substantial compliance with existing environmental laws, regulations and permits.
In connection with the Paulsboro refinery acquisition, we assumed certain environmental remediation obligations. The environmental liability of $10.3 million recorded as of December 31, 2017 ($10.8 million as of December 31, 2016) represents the present value of expected future costs discounted at a rate of 8.0%. The current portion of the environmental liability is recorded in Accrued expenses and the non-current portion is recorded in Other long-term liabilities. As of December 31, 2017 and December 31, 2016, this liability is self-guaranteed by us.
In connection with the acquisition of the Delaware City assets, Valero Energy Corporation (“Valero”) remains responsible for certain pre-acquisition environmental obligations up to $20.0 million and the predecessor to Valero in ownership of the refinery retains other historical obligations.
In connection with the acquisition of the Delaware City assets and the Paulsboro refinery, the Company and Valero purchased ten year, $75.0 million environmental insurance policies to insure against unknown environmental liabilities at each site. In connection with the Toledo refinery acquisition, Sunoco, Inc. (R&M) (“Sunoco”) remains responsible for environmental remediation for conditions that existed on the closing date for twenty years from March 1, 2011, subject to certain limitations.
In connection with the acquisition of the Chalmette refinery, we obtained $3.9 million in financial assurance (in the form of a surety bond) to cover estimated potential site remediation costs associated with an agreed to Administrative Order of Consent with the United States Environmental Protection Agency (“EPA”). The estimated cost assumes remedial activities will continue for a minimum of 30 years. Further, in connection with the acquisition of the Chalmette refinery, we purchased a ten year, $100.0 million environmental insurance policy to insure against unknown environmental liabilities at the refinery. At the time we acquired the Chalmette refinery it was subject to a Consolidated Compliance Order and Notice of Potential Penalty (the “Order”) issued by the Louisiana Department of Environmental Quality (“LDEQ”) covering deviations from 2009 and 2010. Chalmette Refining and LDEQ subsequently entered into a dispute resolution agreement to negotiate the resolution of deviations inside and outside the periods covered by the Order. Although a settlement agreement has not been finalized, the administrative penalty is anticipated to be approximately $41,000, including beneficial environmental projects. To the extent the administrative penalty exceeds such amount, it is not expected to be material to us.
The Delaware City refinery is appealing a Notice of Penalty Assessment and Secretary’s Order issued in March 2017, including a $150,000 fine, alleging violations of a 2013 Secretary’s Order authorizing crude oil shipment by barge. DNREC determined that the Delaware City refinery had violated the 2013 order by failing to make timely and full disclosure to DNREC about the nature and extent of those shipments and had misrepresented the number of shipments that went to other facilities. The Penalty Assessment and Secretary’s Order conclude that

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the 2013 Secretary’s Order was violated by the Delaware City refinery by shipping crude oil from the Delaware City terminal to three locations other than the Paulsboro refinery, on 15 days in 2014, making a total of 17 separate barge shipments containing approximately 35.7 million gallons of crude oil in total. On April 28, 2017, the Delaware City refinery appealed the Notice of Penalty Assessment and Secretary’s Order. The hearing of the appeal is scheduled for February 27, 2018. To the extent that the penalty and Secretary’s Order are upheld, there will not be a material adverse effect on our financial position, results of operations or cash flows.
On December 28, 2016, DNREC issued a Coastal Zone Act permit (the “Ethanol Permit”) to DCR allowing the utilization of existing tanks and existing marine loading equipment at their existing facilities to enable denatured ethanol to be loaded from storage tanks to marine vessels and shipped to offsite facilities. On January 13, 2017, the issuance of the Ethanol Permit was appealed by two environmental groups. On February 27, 2017, the Coastal Zone Industrial 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. During the hearing before the Coastal Zone Board on standing, one of the appellants’ witnesses made a reference to the flammability of ethanol, without any indication of the significance of flammability/explosivity to specific concerns. Moreover, the appellants did not introduce at hearing any evidence of the relative flammability of ethanol as compared to other materials shipped to and from the refinery. However, the sole dissenting opinion from the Coastal Zone Board focused on the flammability/explosivity issue, alleging that the appellants’ testimony raised the issue 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.
At the time we acquired the Toledo refinery, the EPA had initiated an investigation into the compliance of the refinery with EPA standards governing flaring pursuant to Section 114 of the Clean Air Act. On February 1, 2013, the EPA issued an Amended Notice of Violation, and on September 20, 2013, the EPA issued a Notice of Violation and a Finding of Violation to Toledo Refining, alleging certain violations of the Clean Air Act at its Plant 4 and Plant 9 flares since the acquisition of the refinery on March 1, 2011. Toledo Refining and EPA subsequently entered into tolling agreements pending settlement discussions. Although a resolution has not been finalized, the EPA has proposed that the Toledo refinery pay a civil administrative penalty of $741,000 including supplemental environmental projects. To the extent the administrative penalty exceeds such amount, it is not expected to be material to us.
In connection with the acquisition of the Torrance refinery and related logistics assets, we assumed certain pre-existing environmental liabilities totaling $136.5 million as of December 31, 2017 ($142.5 million as of December 31, 2016), related to certain environmental remediation obligations to address existing soil and groundwater contamination and monitoring and other clean-up activities, which reflects the current 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 the logistic assets, including specified incidents and/or notices of violations (“NOVs”) issued by regulatory agencies in various years before our ownership, including the Southern California Air Quality Management District (“SCAQMD”) and the Division of Occupational Safety and Health of the State of California (“Cal/OSHA”).
Additionally, subsequent to the acquisition, further NOVs were issued by the SCAQMD, Cal/OSHA, the City of Torrance and the City of Torrance Fire Department 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 to the acquisition, EPA and the California Department of Toxic Substance Control (“DTSC”)

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conducted inspections related to Torrance operations and issued preliminary findings related to potential operational violations. No settlement or penalty demands have been received to date with respect to any of the NOVs or preliminary findings that are in excess of $100,000. As the ultimate outcomes 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, but any such amount is not expected to have a material impact on our financial position, results of operations or cash flows, individually or in the aggregate.
In connection with the PBFX Plains Asset Purchase (as defined in “Note 4 - Acquisitions” of our Notes to Consolidated Financial Statements), PBFX is responsible for the environmental remediation costs for conditions that existed on the closing date up to a maximum of $250,000 per year for 10 years, with Plains All American Pipeline, L.P. remaining responsible for any and all additional costs above such amounts during such period. The recorded environmental liability associated with the PBFX Plains Asset Purchase as of December 31, 2017 and December 31, 2016 was $1.9 million and $2.2 million, respectively.
Applicable Federal and State Regulatory Requirements
Our operations and many of the products we manufacture are subject to certain specific requirements of the Clean Air Act (the “CAA”) and related state and local regulations. The CAA contains provisions that require capital expenditures for the installation of certain air pollution control devices at our refineries. Subsequent rule making authorized by the CAA or similar laws or new agency interpretations of existing rules, may necessitate additional expenditures in future years.
In 2010, New York State adopted a Low-Sulfur Heating Oil mandate that, beginning July 1, 2012, requires all heating oil sold in New York State to contain no more than 15 parts per million (“PPM”) sulfur. Since July 1, 2012, other states in the Northeast market began requiring heating oil sold in their state to contain no more than 15 PPM sulfur. Currently, all of the Northeastern states and Washington DC have adopted sulfur controls on heating oil. Most of the Northeastern states will now require heating oil with 15 PPM or less sulfur by July 1, 2018 (except for Pennsylvania and Maryland - where less than 500 PPM sulfur is required). All of the heating oil we currently produce meet these specifications. The mandate and other requirements do not currently have a material impact on our financial position, results of operations or cash flows.
The EPA issued the final Tier 3 Gasoline standards on March 3, 2014 under the CAA. This final rule establishes more stringent vehicle emission standards and further reduces the sulfur content of gasoline starting in January of 2017. The new standard is set at 10 PPM sulfur in gasoline on an annual average basis starting January 1, 2017, with a credit trading program to provide compliance flexibility. The EPA responded to industry comments on the proposed rule and maintained the per gallon sulfur cap on gasoline at the existing 80 PPM cap. The refineries are complying with these new requirements as planned, either directly or using flexibility provided by sulfur credits generated or purchased in advance as an economic optimization. The standards set by the new rule are not expected to have a material impact on our financial position, results of operations or cash flows.
In November 2017, the EPA issued final 2018 RFS standards that will slightly increase renewable volume standards from final 2017 levels. It is not clear that renewable fuel producers will be able to produce the volumes of these fuels required for blending in accordance with the 2018 standards. Despite decreasing 7% in comparison to 2017, the final 2018 cellulosic standard is still set at approximately 125% of the 2016 standard. It is likely that cellulosic RIN production will be lower than needed forcing obligated parties, such as us, to purchase cellulosic “waiver credits” to comply in 2018 (the waiver credit option by regulation is only available for the cellulosic standard). The advanced and total Renewable Identification Numbers (“RINs”) requirements were kept relatively flat in comparison to 2017, but remain 19% and 7% higher than final 2016 levels. Production of advanced RINs has been below what is needed for compliance in 2017 and obligated parties, such as us, will likely continue to rely on the nesting feature of the biodiesel RIN to comply with the advanced standard in 2018. Consistent with 2017, compliance in 2018 will likely rely on obligated parties drawing down the supply of excess RINs collectively known as the “RIN bank” and could tighten the RIN market potentially raising RIN prices further. While a proposal to change the point of obligation under the RFS program to the “blender” of renewable fuels was denied by the

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EPA in November of 2017, the issue continues to receive attention from lawmakers, industry groups, and the current presidential administration, which may result in necessary changes to the RFS program in the future and provide relief to us and other downstream refiners that continue to feel the burden of increased costs to comply with RFS.
In addition, on December 1, 2015 the EPA finalized revisions to an existing air regulation concerning Maximum Achievable Control Technologies (“MACT”) for Petroleum Refineries. The regulation requires additional continuous monitoring systems for eligible process safety valves relieving to atmosphere, minimum flare gas heat (Btu) content, and delayed coke drum vent controls to be installed by January 30, 2019. In addition, a program for ambient fence line monitoring for benzene was implemented prior to the deadline of January 30, 2018. We are in the process of implementing the requirements of this regulation. The regulation is not expected to have a material impact on our financial position, results of operations or cash flows.
The EPA published a Final Rule to the Clean Water Act (“CWA”) Section 316(b) in August 2014 regarding cooling water intake structures, which includes requirements for petroleum refineries. The purpose of this rule is to prevent fish from being trapped against cooling water intake screens (impingement) and to prevent fish from being drawn through cooling water systems (entrainment). Facilities will be required to implement Best Technology Available (“BTA”) as soon as possible, but state agencies have the discretion to establish implementation time lines. We continue to evaluate the impact of this regulation, and at this time do not anticipate it having a material impact on our financial position, results of operations or cash flows.
As a result of the Torrance Acquisition, we are subject to greenhouse gas emission control regulations in the state of California pursuant to Assembly Bill 32 (“AB32”). AB32 imposes a statewide cap on greenhouse gas emissions, including emissions from transportation fuels, with the aim of returning the state to 1990 emission levels by 2020. AB32 is implemented through two market mechanisms including the Low Carbon Fuel Standard (“LCFS”) and Cap and Trade, which was extended for an additional 10 years to 2030 in July 2017. We are responsible for the AB32 obligations related to the Torrance refinery beginning on July 1, 2016 and must purchase emission credits to comply with these obligations. Additionally, in September 2016, the state of California enacted Senate Bill 32 (“SB32”) which further reduces greenhouse gas emissions targets to 40 percent below 1990 levels by 2030.
However, subsequent to the acquisition, we are recovering the majority of these costs from our customers, and as such do not expect this obligation to materially impact our financial position, results of operations, or cash flows. To the degree there are unfavorable changes to AB32 or SB32 regulations or we are unable to recover such compliance costs from customers, these regulations could have a material adverse effect on our financial position, results of operations, and cash flows.
We are subject to obligations to purchase RINs required to comply with the RFS. On February 15, 2017, we received another 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.
As of January 1, 2011, we are required to comply with the EPA’s Control of Hazardous Air Pollutants From Mobile Sources, or MSAT2, regulations on gasoline that impose reductions in the benzene content of our produced gasoline. We purchase benzene credits to meet these requirements. Our planned capital projects will reduce the amount of benzene credits that we need to purchase. In addition, the renewable fuel standards mandate the blending of prescribed percentages of renewable fuels (e.g., ethanol and biofuels) into our produced gasoline and diesel. These new requirements, other requirements of the CAA and other presently existing or future environmental regulations may cause us to make substantial capital expenditures as well as the purchase of credits at significant cost, to enable our refineries to produce products that meet applicable requirements.

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The federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances. Under CERCLA, such persons may be subject to joint and several liability for investigation and the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. As discussed more fully above, certain of our sites are subject to these laws and we may be held liable for investigation and remediation costs or claims for natural resource damages. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Analogous state laws impose similar responsibilities and liabilities on responsible parties. In our current normal operations, we have generated waste, some of which falls within the statutory definition of a “hazardous substance” and some of which may have been disposed of at sites that may require cleanup under Superfund.
As is the case with all companies engaged in industries similar to ours, we face potential exposure to future claims and lawsuits involving environmental matters. These matters include soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances which we manufactured, handled, used, released or disposed of.
Current and future environmental regulations are 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.

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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.
“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.
“Dated Brent” refers to Brent blend oil (a light, sweet North Sea crude oil, characterized by an 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.

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“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 Permit” refers to a Coastal Zone Act permit for ethanol.
“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.
“feedstocks” refers to crude oil and partially refined petroleum products that are processed and blended into refined products.
“FASB” refers to the Financial Accounting Standards Board which develops U.S. generally accepted accounting principles.
“FCC” refers to fluid catalytic cracking.
“FCU” refers to fluid coking unit.
“FERC” refers to the Federal Energy Regulatory Commission.
“GAAP” refers to U.S. generally accepted accounting principles developed by the Financial Accounting Standards Board for nongovernmental entities.
“GHG” refers to the greenhouse gas carbon dioxide.
“Group I base oils or lubricants” refers to conventionally refined products characterized by sulfur content less than 0.03% with a viscosity index between 80 and 120. Typically, these products are used in a variety of automotive and industrial applications.
“heavy crude oil” refers to a relatively inexpensive crude oil with a low API gravity characterized by high relative density and viscosity. Heavy crude oils require greater levels of processing to produce high value products such as gasoline and diesel.
“IDRs” refers to incentive distribution rights.
“IPO” refers to the initial public offering of PBF Energy’s 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.
“light crude oil” refers to a relatively expensive crude oil with a high API gravity characterized by low relative density and viscosity. Light crude oils require lower levels of processing to produce high value products such as gasoline and diesel.
“light products” refers to the group of refined products with lower boiling temperatures, including gasoline and distillates.
“light-heavy differential” refers to the price difference between light crude oil and heavy crude oil.

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“LLS” refers to Light Louisiana Sweet benchmark for crude oil reflective of Gulf coast economics for light sweet domestic and foreign crudes.
“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 master limited partnership.
“MMbbls” refers to an abbreviation for million barrels.
“MMBTU” refers to million British thermal units.
“MMSCFD” refers to million standard cubic feet per day.
“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” refers to Morgan Stanley Capital Group Inc.
“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.
“NYSE” refers to the New York Stock 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.
“RINS” refers to renewable fuel credits required for compliance with the Renewable Fuels Standard.
“refined products” refers to petroleum products, such as gasoline, diesel and jet fuel, that are produced by a refinery.
“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.
“Saudi Aramco” refers to Saudi Arabian Oil Company.

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“SEC” refers to the United States Securities and Exchange Commission.
“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.
“TCJA” refers to the U.S. government enacted comprehensive tax legislation enacted on December 22, 2017 and commonly referred to as the Tax Cuts and Jobs Act, or TCJA.
“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 inspection of such units and occurs generally on a periodic cycle.
“ULSD” refers to ultra-low-sulfur diesel.
“Valero” refers to Valero Energy Corporation.
“WCS” refers to Western Canadian Select, a heavy, sour crude oil blend typically characterized by API gravity between 20° and 22° and a sulfur content of approximately 3.5 weight percent that is used as a benchmark for heavy Western Canadian crude oil.
“WTI” refers to West Texas Intermediate crude oil, a light, sweet crude oil, typically characterized by API gravity between 38° and 40° and a sulfur content of approximately 0.3 weight percent that is used as a benchmark for other crude oils.
“WTS” refers to West Texas Sour crude oil, a sour crude oil characterized by API gravity between 30° and 33° and a sulfur content of approximately 1.28 weight percent that is used as a benchmark for other sour crude oils.
“yield” refers to the percentage of refined products that is produced from crude oil and other feedstocks.

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ITEM 1A. RISK FACTORS
Risks Relating to Our Business and Industry
You should carefully read the risks and uncertainties described below. The risks and uncertainties described below are not the only ones facing our company. Additional risks and uncertainties may also impair our business operations. If any of the following risks actually occur, our business, financial condition, results of operations or cash flows would likely suffer. In that case, the trading price of our Class A common stock could fall.
The price volatility of crude oil, other feedstocks, blendstocks, refined products and fuel and utility services may have a material adverse effect on our revenues, profitability, cash flows and liquidity.
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, our earnings, profitability and cash flows are negatively affected. Refining margins historically have been volatile, and are likely to continue to be volatile, as a result of a variety of factors, including fluctuations in the prices of crude oil, other feedstocks, refined products and fuel and utility services. An increase or decrease in the price of crude oil will likely result in a similar increase or decrease in prices for refined products; however, there may be a time lag in the realization, or no such realization, of the similar increase or decrease in prices for refined products. The effect of changes in crude oil prices on our refining margins therefore depends in part on how quickly and how fully refined product prices adjust to reflect these changes.
In addition, the nature of our business requires us to maintain substantial crude oil, feedstock and refined product inventories. Because crude oil, feedstock and refined products are commodities, we have no control over the changing market value of these inventories. Our crude oil, feedstock and refined product inventories are valued at the lower of cost or market value under the last-in-first-out (“LIFO”) inventory valuation methodology. If the market value of our crude oil, feedstock and refined product inventory declines to an amount less than our LIFO cost, we would record a write-down of inventory and a non-cash impact to cost of products and other. For example, during the year ended December 31, 2017, we recorded an adjustment to value our inventories to the lower of cost or market which increased operating income and net income by $295.5 million and $178.5 million, respectively, reflecting the net change in the lower of cost or market inventory reserve from $596.0 million at December 31, 2016 to $300.5 million at December 31, 2017.
Prices of crude oil, other feedstocks, blendstocks, and refined products depend on numerous factors beyond our control, including the supply of and demand for crude oil, other feedstocks, gasoline, diesel, ethanol, asphalt and other refined products. Such supply and demand are affected by a variety of economic, market, environmental and political conditions.
Our direct operating expense structure also impacts our profitability. Our major direct operating expenses include employee and contract labor, maintenance and energy. Our predominant variable direct operating cost is energy, which is comprised primarily of fuel and other utility services. The volatility in costs of fuel, principally natural gas, and other utility services, principally electricity, used by our refineries and other operations affect our operating costs. Fuel and utility prices have been, and will continue to be, affected by factors outside our control, such as supply and demand for fuel and utility services in both local and regional markets. Natural gas prices have historically been volatile and, typically, electricity prices fluctuate with natural gas prices. Future increases in fuel and utility prices may have a negative effect on our refining margins, profitability and cash flows.
Our profitability is affected by crude 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

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processed at our Delaware City, Paulsboro, Chalmette and Torrance refineries. For our Toledo refinery, purchased crude prices have historically been slightly above the WTI benchmark, however, such crude slate typically results in favorable refinery production yield. For all locations, these crude oil differentials can vary significantly from quarter to quarter depending on overall economic conditions and trends and conditions within the markets for crude oil and refined products. Any change in these crude oil differentials may have an impact on our earnings. Our rail investment and strategy to acquire cost advantaged Mid-Continent and Canadian crude, which are priced based on WTI, could be adversely affected when the Dated Brent/WTI or related differentials narrow. A narrowing of the WTI/Dated Brent differential may result in our Toledo refinery losing a portion of its crude oil price advantage over certain of our competitors, which negatively impacts our profitability. In addition, the narrowing of the WTI/WCS differential, which is a proxy for the difference between light U.S. and heavy Canadian crude oil, 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 recent initiatives by the Organization of the Petroleum Exporting Countries to restrict crude oil production levels and executive actions by the current U.S. presidential administration to advance certain energy infrastructure projects such as the Keystone XL pipeline, may continue to impact crude oil prices and crude oil differentials. Any increase in crude oil prices or unfavorable movements in crude oil differentials due to such actions or changing regulatory environment may negatively impact our ability to acquire crude oil at economical prices and could have a material adverse effect on our business and profitability.
A significant interruption 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 five refineries and related assets. As a result, our operations could be subject to significant interruption if any of our refineries were to experience a major accident, be damaged by severe 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 logistical assets, power outages, acts of terrorism, fires, toxic emissions and maritime hazards. Any such shutdown or disruption would reduce the production from that refinery. There is also risk of mechanical failure and equipment shutdowns both in general and following unforeseen events. Further, in such situations, undamaged refinery processing units may be dependent on or interact with damaged sections of our refineries and, accordingly, are also subject to being shut down. In the event any of our refineries is forced to shut down for a significant period of time, it would have a material adverse effect on our earnings, our other results of operations and our financial condition as a whole.
As protection against these hazards, we maintain insurance coverage against some, but not all, such potential losses and liabilities. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may increase substantially. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, coverage for hurricane damage can be limited, and coverage for terrorism risks can include broad exclusions. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position.
Our insurance program includes a number of insurance carriers. Significant disruptions in financial markets could lead to a deterioration in the financial condition of many financial institutions, including insurance companies and, therefore, we may not be able to obtain the full amount of our insurance coverage for insured events.

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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 and Torrance refineries receive a significant portion of their crude oil through pipelines. These pipelines include the Enbridge system, Capline and Mid-Valley pipelines for supplying crude to our Toledo refinery, the MOEM and CAM pipelines for supplying crude to our Chalmette refinery and the San Joaquin Pipeline, San Ardo and Coastal Pipeline systems for supplying crude to our Torrance refinery. Additionally, our Toledo, Chalmette and Torrance refineries deliver a significant portion of the refined products through pipelines. These pipelines include pipelines such as the Sunoco Logistics Partners L.P. and Buckeye Partners L.P. pipelines at Toledo, the Collins Pipeline at our Chalmette refinery and Jet Pipeline to the Los Angeles International Airport, the Product Pipeline to Vernon and the Product Pipeline to Atwood at our Torrance refinery. We could experience an interruption of supply or delivery, or an increased cost of receiving crude oil and delivering refined products to market, if the ability of these pipelines to transport crude oil or refined products is disrupted because of accidents, weather interruptions, governmental regulation, terrorism, other third party action or casualty or other events.
The Delaware City rail unloading facilities allow our East Coast refineries to source WTI-based crudes from Western Canada and the Mid-Continent, which may provide significant cost advantages versus traditional Brent-based international crudes in certain market environments. Any disruptions or restrictions to our supply of crude by rail due to problems with third party logistics infrastructure or operations or as a result of increased regulations, could increase our crude costs and negatively impact our results of operations and cash flows.
In addition, due to the common carrier regulatory obligation applicable to interstate oil pipelines, capacity allocation among shippers can become contentious in the event demand is in excess of capacity. Therefore, nominations by new shippers or increased nominations by existing shippers may reduce the capacity available to us. Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that we rely upon for transportation of crude oil and refined products could have a further material adverse effect on our business, financial condition, results of operations and cash flows.
Regulation of emissions of greenhouse gases could force us to incur increased capital and operating costs and could have a material adverse effect on our results of operations and financial condition.
Both houses of Congress have actively considered legislation to reduce emissions of greenhouse gases (“GHGs”), such as carbon dioxide and methane, including proposals to: (i) establish a cap and trade system, (ii) create a federal renewable energy or “clean” energy standard requiring electric utilities to provide a certain percentage of power from such sources, and (iii) create enhanced incentives for use of renewable energy and increased efficiency in energy supply and use. In addition, the EPA is taking steps to regulate GHGs under the existing federal Clean Air Act (the “CAA”). The EPA has already adopted regulations limiting emissions of GHGs from motor vehicles, addressing the permitting of GHG emissions from stationary sources, and requiring the reporting of GHG emissions from specified large GHG emission sources, including refineries. These and similar regulations could require us to incur costs to monitor and report GHG emissions or reduce emissions of GHGs associated with our operations. In addition, various states, individually as well as in some cases on a regional basis, have taken steps to control GHG emissions, including adoption of GHG reporting requirements, cap and trade systems and renewable portfolio standards (such as AB32 regulations in California). Efforts have also been undertaken to delay, limit or prohibit the EPA and possibly state action to regulate GHG emissions, and it is not possible at this time to predict the ultimate form, timing or extent of federal or state regulation. In addition, it is currently uncertain how the current presidential administration will address GHG emissions. In the event we do incur increased costs as a result of increased efforts to control GHG emissions, we may not be able to pass on any of these costs to our customers. Such requirements also could adversely affect demand for the refined petroleum products that we produce. Any increased costs or reduced demand could materially and adversely affect our business and results of operation.
Requirements to reduce emissions could result in increased costs to operate and maintain our facilities as well as implement and manage new emission controls and programs put in place. For example, AB32 in California requires the state to reduce its GHG emissions to 1990 levels by 2020. Additionally, in September 2016, the state

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of California enacted Senate Bill 32 which further reduces greenhouse gas emissions targets to 40 percent below 1990 levels by 2030. Two regulations implemented to achieve these goals are Cap-and-Trade and the Low Carbon Fuel Standard (“LCFS”). In 2012, the California Air Resource Board (“CARB”) implemented Cap-and-Trade. This program currently places a cap on GHGs and we are required to acquire a sufficient number of credits to cover emissions from our refineries and our in-state sales of gasoline and diesel. In 2009, CARB adopted the LCFS, which requires a 10% reduction in the carbon intensity of gasoline and diesel by 2020. Compliance is achieved through blending lower carbon intensity biofuels into gasoline and diesel or by purchasing credits. Compliance with each of these programs is facilitated through a market-based credit system. If sufficient credits are unavailable for purchase or we are unable to pass through costs to our customers, we have to pay a higher price for credits or if we are otherwise unable to meet our compliance obligations, our financial condition and results of operations could be adversely affected.
Our hedging activities may limit our potential gains, exacerbate potential losses and involve other risks.
We may enter into commodity derivatives contracts to hedge our crude price risk or crack spread risk with respect to a portion of our expected gasoline and distillate production on a rolling basis. Consistent with that policy we may hedge some percentage of future crude 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 and refined product prices. In addition, our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which:
the volumes of our actual use of crude oil or production of the applicable refined products is less than the volumes subject to the hedging arrangement;
accidents, interruptions in feedstock transportation, inclement weather or other events cause unscheduled shutdowns or otherwise adversely affect our refineries, or those of our suppliers or customers;
changes in commodity prices have a material impact on collateral and margin requirements under our hedging arrangements, resulting in us being subject to margin calls;
the counterparties to our derivative contracts fail to perform under the contracts; or
a sudden, unexpected event materially impacts the commodity or crack spread subject to the hedging arrangement.
As a result, the effectiveness of our hedging strategy could have a material impact on our financial results. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk.”
In addition, these hedging activities involve basis risk. Basis risk in a hedging arrangement occurs when the price of the commodity we hedge is more or less variable than the index upon which the hedged commodity is based, thereby making the hedge less effective. For example, a NYMEX index used for hedging certain volumes of our crude oil or refined products may have more or less variability than the actual cost or price we realize for such crude oil or refined products. We may not hedge all the basis risk inherent in our hedging arrangements and derivative contracts.
We may have capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate.
If we cannot generate sufficient cash flows or otherwise secure sufficient liquidity to support our short-term and long-term capital requirements, we may not be able to meet our payment obligations or our future debt obligations, comply with certain deadlines related to environmental regulations and standards, or pursue our business strategies, including acquisitions, in which case our operations may not perform as we currently expect. We have substantial short-term capital needs and may have substantial long term capital needs. Our short-term

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working capital needs are primarily related to financing certain of our refined products inventory not covered by our various supply and Inventory Intermediation Agreements. Pursuant to the Inventory Intermediation Agreements, J. Aron purchases and holds title to certain of the intermediate and finished products produced by the Delaware City and Paulsboro refineries and delivered into the tanks at the refineries (or at other locations outside of the refineries as agreed upon by both parties). Furthermore, J. Aron agrees to sell the intermediate and finished products back to us as they are discharged out of the refineries’ tanks (or other locations outside of the refineries as agreed upon by both parties). We market and sell the finished products independently to third parties.
If we cannot adequately handle our crude oil and feedstock requirements or if we are required to obtain our crude oil supply at our other refineries without the benefit of the existing supply arrangements or the applicable counterparty defaults in its obligations, our crude oil pricing costs may increase as the number of days between when we pay for the crude oil and when the crude oil is delivered to us increases. Termination of our A&R Intermediation Agreements with J. Aron would require us to finance our refined products inventory covered by the agreements at terms that may not be as favorable. Additionally, we are obligated to repurchase from J. Aron all volumes of products located at the refineries’ storage tanks (or at other locations outside of the refineries as agreed upon by both parties) upon termination of these agreements, which may have a material adverse impact on our working capital and financial condition. Further, if we are not able to market and sell our finished products to credit worthy customers, we may be subject to delays in the collection of our accounts receivable and exposure to additional credit risk. Such increased exposure could negatively impact our liquidity due to our increased working capital needs as a result of the increase in the amount of crude oil inventory and accounts receivable we would have to carry on our balance sheet. Our long-term needs for cash include those to support ongoing capital expenditures for equipment maintenance and upgrades during turnarounds at our refineries and to complete our routine and normally scheduled maintenance, regulatory and security expenditures.
In addition, from time to time, we are required to spend significant amounts for repairs when one or more processing units experiences temporary shutdowns. We continue to utilize significant capital to upgrade equipment, improve facilities, and reduce operational, safety and environmental risks. In connection with the Paulsboro and Torrance acquisitions, we assumed certain significant environmental obligations, and may similarly do so in future acquisitions. We will likely incur substantial compliance costs in connection with new or changing environmental, health and safety regulations. See “Item 7. Management’s Discussion and Analysis of Financial Condition.” Our liquidity condition will affect our ability to satisfy any and all of these needs or obligations.
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 the generally weak economic conditions. In addition, the fixed income markets have experienced periods of extreme volatility that have negatively impacted market liquidity conditions. As a result, the cost of raising money in the debt and equity capital markets has increased substantially at times while the availability of funds from those markets diminished significantly. In particular, as a result of concerns about the stability of financial markets generally, which may be subject to unforeseen disruptions, the cost of obtaining money from the credit markets may increase as many lenders and institutional investors increase interest rates, enact tighter lending standards, refuse to refinance existing debt on similar terms or at all and reduce or, in some cases, cease to provide funding to borrowers. Due to these factors, we cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due. Moreover, without adequate funding, we may be unable to execute our growth strategy, complete future acquisitions, take advantage of other business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.

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Competition from companies who produce their own supply of feedstocks, have extensive retail outlets, make alternative fuels or have greater financial and other resources than we do could materially and adversely affect our business and results of operations.
Our refining operations compete with domestic refiners and marketers in regions of the United States in which we operate, as well as with domestic refiners in other regions and foreign refiners that import products into the United States. In addition, we compete with other refiners, producers and marketers in other industries that supply their own renewable fuels or alternative forms of energy and fuels to satisfy the requirements of our industrial, commercial and individual consumers. Certain of our competitors have larger and more complex refineries, and may be able to realize lower per-barrel costs or higher margins per barrel of throughput. Several of our principal competitors are integrated national or international oil companies that are larger and have substantially greater resources than we do and access to proprietary sources of controlled crude oil production. Unlike these competitors, we obtain substantially all of our feedstocks from unaffiliated sources. We are not engaged in the petroleum exploration and production business and therefore do not produce any of our crude oil feedstocks. We do not have a retail business and therefore are dependent upon others for outlets for our refined products. Because of their integrated operations and larger capitalization, these companies may be more flexible in responding to volatile industry or market conditions, such as shortages of crude oil supply and other feedstocks or intense price fluctuations.
Newer or upgraded refineries will often be more efficient than our refineries, which may put us at a competitive disadvantage. We have taken significant measures to maintain our refineries including the installation of new equipment and redesigning older equipment to improve our operations. However, these actions involve significant uncertainties, since upgraded equipment may not perform at expected throughput levels, the yield and product quality of new equipment may differ from design specifications and modifications may be needed to correct equipment that does not perform as expected. Any of these risks associated with new equipment, redesigned older equipment or repaired equipment could lead to lower revenues or higher costs or otherwise have an adverse effect on future results of operations and financial condition. Over time, our refineries or certain refinery units may become obsolete, or be unable to compete, because of the construction of new, more efficient facilities by our competitors.
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.
Any political instability, military strikes, sustained military campaigns, terrorist activity, or changes in foreign policy in areas or regions of the world where we acquire crude oil and other raw materials or sell our refined petroleum products may affect our business in unpredictable ways, including forcing us to increase security measures and causing disruptions of supplies and distribution markets. We may also be subject to United States trade and economic sanctions laws, which change frequently as a result of foreign policy developments, and which may necessitate changes to our crude oil acquisition activities. Further, like other industrial companies, our facilities may be the target of terrorist activities. Any act of war or terrorism that resulted in damage to 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.
Economic turmoil in the global financial system may in the future have an adverse impact on the refining industry.
Our business and profitability are affected by the overall level of demand for our products, which in turn is affected by factors such as overall levels of economic activity and business and consumer confidence and spending. In the past, declines in global economic activity and consumer and business confidence and spending significantly reduced the level of demand for our products. Reduced demand for our products may have an adverse impact on our business, financial condition, results of operations and cash flows. In addition, downturns in the economy impact the demand for refined fuels and, in turn, result in excess refining capacity. Refining margins are impacted by changes in domestic and global refining capacity, as increases in refining capacity can adversely impact refining margins, earnings and cash flows.

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Our business is indirectly exposed to risks faced by our suppliers, customers and other business partners. The impact on these constituencies of the risks posed by economic turmoil in the global financial system could include interruptions or delays in the performance by counterparties to our contracts, reductions and delays in customer purchases, delays in or the inability of customers to obtain financing to purchase our products and the inability of customers to pay for our products. Any of these events may have an adverse impact on our business, financial condition, results of operations and cash flows.
We must make substantial capital expenditures on our operating facilities to maintain their reliability and efficiency. If we are unable to complete capital projects at their expected costs and/or in a timely manner, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations or cash flows could be materially and adversely affected.
Delays or cost increases related to capital spending programs involving engineering, 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, available alternative supply and customer demand. Any one or more of these factors could have a significant impact on our business. If we were unable to make up the delays associated with such factors or to recover the related costs, or if market conditions change, it could materially and adversely affect our financial position, results of operations or cash flows.
Acquisitions that we may undertake in the future involve a number of risks, any of which could cause us not to realize the anticipated benefits.
We may not be successful in acquiring additional assets, and any acquisitions that we do consummate may not produce the anticipated benefits or may have adverse effects on our business and operating results. We may selectively consider strategic acquisitions in the future within the refining and mid-stream sector based on performance through the cycle, advantageous access to crude oil supplies, attractive refined products market fundamentals and access to distribution and logistics infrastructure. Our ability to do so will be dependent upon a number of factors, including our ability to identify acceptable acquisition candidates, consummate acquisitions on acceptable terms, successfully integrate acquired assets and obtain financing to fund acquisitions and to support our growth and many other factors beyond our control. Risks associated with acquisitions include those relating to the diversion of management time and attention from our existing business, liability for known or unknown environmental conditions or other contingent liabilities and greater than anticipated expenditures required for compliance with environmental, safety or other regulatory standards or for investments to improve operating results,

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and the incurrence of additional indebtedness to finance acquisitions or capital expenditures relating to acquired assets. We may also enter into transition services agreements in the future with sellers of any additional refineries we acquire. Such services may not be performed timely and effectively, and any significant disruption in such transition services or unanticipated costs related to such services could adversely affect our business and results of operations. In addition, it is likely that, when we acquire refineries, we will not have access to the type of historical financial information that we will require regarding the prior operation of the refineries. As a result, it may be difficult for investors to evaluate the probable impact of significant acquisitions on our financial performance until we have operated the acquired refineries for a substantial period of time.
Our business may suffer if any of our senior executives or other key employees discontinues employment with us. Furthermore, a shortage of skilled labor or 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.
A portion of our workforce is unionized, and we may face labor disruptions that would interfere with our operations.
At Delaware City, Toledo, Chalmette and Torrance, most hourly employees are covered by a collective bargaining agreement through the United Steel Workers (“USW”). The agreements with the USW covering Delaware City, Chalmette and Torrance are scheduled to expire in January 2019 and 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. Future negotiations after 2019 may result in labor unrest for which a strike or work stoppage is possible. Strikes and/or work stoppages could negatively affect our operational and financial results and may increase operating expenses at the refineries.
Our commodity derivative activities could result in period-to-period earnings volatility.
We do not currently apply hedge accounting to all 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.
The adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivatives contracts to reduce the effect of commodity price, interest rate and other risks associated with our business.
The United States Congress in 2010 passed the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which, among other things, established federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. In connection with the Dodd-Frank Act, the Commodity Futures Trading Commission, or the CFTC, has proposed rules to set position limits for certain futures and option contracts, and for swaps that are their economic equivalent, in the major energy markets. The legislation and related regulations may also require us to comply with margin requirements and with certain clearing and trade-execution requirements if we are in scope and do not otherwise satisfy certain specific exceptions. The legislation and related regulations could significantly increase the cost of derivatives contracts (including through requirements to post collateral), materially alter the terms of derivatives contracts, reduce the availability of

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derivatives to protect against risks we encounter and reduce our ability to monetize or restructure our existing derivatives contracts. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.
We may incur significant liability under, or costs and capital expenditures to comply with, environmental and health and safety regulations, which are complex and change frequently.
Our operations are subject to federal, state and local laws regulating, among other things, the use and/or handling of petroleum and other regulated materials, the emission and discharge of materials into the environment, waste management, and remediation of discharges of petroleum and petroleum products, characteristics and composition of gasoline and distillates and other matters otherwise relating to the protection of the environment and the health and safety of the surrounding community. For example, the SCAQMD is currently considering further regulations on, or potentially banning the use of, modified hydrofluoric acid, also known as MHF, in California. We utilize MHF as an alkylation catalyst in the manufacturing of gasoline at our Torrance refinery. If MHF usage is limited or restricted by the SCAQMD, our current Torrance refinery operations would be adversely affected, which could have a material adverse effect on our business, financial condition, cash flows and results of operations. Our operations are also subject to extensive laws and regulations relating to occupational health and safety.
We cannot predict what additional environmental, health and safety legislation or regulations may be adopted in the future, or how existing or future laws or regulations may be administered or interpreted with respect to our operations. Many of these laws and regulations have become increasingly stringent over time, and the cost of compliance with these requirements can be expected to increase over time.
Certain environmental laws impose strict, and in certain circumstances, joint and several, liability for costs of investigation and cleanup of spills, discharges or releases on owners and operators of, as well as persons who arrange for treatment or disposal of regulated materials at, contaminated sites. Under these laws, we may incur liability or be required to pay penalties for past contamination, and third parties may assert claims against us for damages allegedly arising out of any past or future contamination. The potential penalties and clean-up costs for past or future spills, discharges or releases, the failure of prior owners of our facilities to complete their clean-up obligations, the liability to third parties for damage to their property, or the need to address newly-discovered information or conditions that may require a response could be significant, and the payment of these amounts could have a material adverse effect on our business, financial condition, cash flows and results of operations.
Environmental clean-up and remediation costs of our sites and environmental litigation could decrease our net cash flow, reduce our results of operations and impair our financial condition.
We are subject to liability for the investigation and clean-up of environmental contamination at each of the properties that we own or operate and at off-site locations where we arrange for the treatment or disposal of regulated materials. We may become involved in litigation or other proceedings related to the foregoing. If we were to be held responsible for damages in any such litigation or proceedings, such costs may not be covered by insurance and may be material. Historical soil and groundwater contamination has been identified at each of 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

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the ownership or operation of these assets by prior owners, which could materially adversely affect our business, financial condition, results of operations and cash flow. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contractual Obligations and Commitments” and “Item 1. Business—Environmental, Health and Safety Matters.”
We may also face liability arising from current or future claims alleging personal injury or property damage due to exposure to chemicals or other regulated materials, such as asbestos, benzene, silica dust and petroleum hydrocarbons, at or from our facilities. We may also face liability for personal injury, property damage, natural resource damage or clean-up costs for the alleged migration of contamination from our properties. A significant increase in the number or success of these claims could materially adversely affect our business, financial condition, results of operations and cash flow.
Our operations could be disrupted if our critical information systems are hacked or fail, causing increased expenses and loss of sales.
Our business is highly dependent on financial, accounting and other data processing systems and other communications and information systems, including our enterprise resource planning tools. We process a large number of transactions on a daily basis and rely upon the proper functioning of computer systems. If a key system was hacked or otherwise interfered with by an unauthorized access, or was to fail or experience unscheduled downtime for any reason, even if only for a short period, our operations and financial results could be affected adversely. Our systems could be damaged or interrupted by a security breach, cyber-attack, fire, flood, power loss, telecommunications failure or similar event. We have a formal disaster recovery plan in place, but this plan may not prevent delays or other complications that could arise from an information systems failure. Further, our business interruption insurance may not compensate us adequately for losses that may occur. Finally, federal legislation relating to cyber-security threats could impose additional requirements on our operations.
Product liability claims and litigation could adversely affect our business and results of operations.
Product liability is a significant commercial risk. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers based upon claims for injuries and property damage caused by the use of or exposure to various products. Failure of our products to meet required specifications or claims that a product is inherently defective could result in product liability claims from our shippers and customers, and also arise from contaminated or off-specification product in commingled pipelines and storage tanks and/or defective fuels. Product liability claims against us could have a material adverse effect on our business or results of operations.
Climate change could have a material adverse impact on our operations and adversely affect our facilities.
Some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. We believe the issue of climate change will likely continue to receive scientific and political attention, with the potential for further laws and regulations that could materially adversely affect our ongoing operations.
In addition, as many of our facilities are located near coastal areas, rising sea levels may disrupt our ability to operate those facilities or transport crude oil and refined petroleum products. Extended periods of such disruption could have an adverse effect on our results of operation. We could also incur substantial costs to protect or repair these facilities.
Renewable fuels mandates may reduce demand for the refined fuels we produce, which could have a material adverse effect on our results of operations and financial condition. The market prices for RINs have been volatile and may harm our profitability.
Pursuant to the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007, the EPA has issued Renewable Fuel Standards, or RFS, implementing mandates to blend renewable fuels into the petroleum fuels produced and sold in the United States. Under RFS, the volume of renewable fuels that obligated refineries

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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, the 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 renewable fuel credits, known as “RINS,” which may have fluctuating costs. We have seen a fluctuation in the cost of RINs required for compliance with the RFS. We incurred approximately $293.7 million in RINs costs during the year ended December 31, 2017 as compared to $347.5 million and $171.6 million during the years ended December 31, 2016 and 2015, respectively. The fluctuations in our RINs costs are due primarily to volatility in prices for ethanol-linked RINs and increases in our production of on-road transportation fuels since 2012. Our RINs purchase obligation is dependent on our actual shipment of on-road transportation fuels domestically and the amount of blending achieved which can cause variability in our profitability.
Our pipelines are subject to federal and/or state regulations, which could reduce profitability and the amount of cash we generate.
Our transportation activities are subject to regulation by multiple governmental agencies. The regulatory burden on the industry increases the cost of doing business and affects profitability. Additional proposals and proceedings that affect the oil industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission, the United States Department of Transportation, and the courts. We cannot predict when or whether any such proposals may become effective or what impact such proposals may have. Projected operating costs related to our pipelines reflect the recurring costs resulting from compliance with these regulations, and these costs may increase due to future acquisitions, changes in regulation, changes in use, or discovery of existing but unknown compliance issues.
We are subject to strict laws and regulations regarding employee and process safety, and failure to comply with these laws and regulations could have a material adverse effect on our results of operations, financial condition and profitability.
We are subject to the requirements of the Occupational Safety & Health Administration, or OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, OSHA requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees, state and local governmental authorities, and local residents. Failure to comply with OSHA requirements, including general industry standards, process safety standards and control of occupational exposure to regulated substances, could have a material adverse effect on our results of operations, financial condition and the cash flows of the business if we are subjected to significant fines or compliance costs.
Compliance with and changes in tax laws could adversely affect our performance.
We are subject to extensive tax liabilities, including federal, state, local and foreign taxes such as income, excise, sales/use, payroll, franchise, property, gross receipts, withholding and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future. These liabilities are subject to periodic audits by the respective taxing authorities, which could increase our tax liabilities. Subsequent changes to our tax liabilities as a result of these audits may also subject us to interest and penalties. There can be no certainty that our federal, state, local or foreign taxes could be passed on to our customers.
Furthermore, the Tax Cut and Jobs Act (“TCJA”) that was enacted on December 22, 2017 made significant permanent and temporary amendments to the Internal Revenue Code of 1986, including a reduction in corporate income taxes, elimination of the corporate minimum tax, the immediate expensing of certain capital investments,

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allowing for an indefinite carryforward of tax net operating losses incurred in tax years beginning after December 31, 2017 and fundamentally changing the taxation of multinational entities. Additionally, the TCJA potentially limits the amount of interest expense currently deductible, provides for a transition tax for previously unrepatriated foreign earnings, provides for current taxation of certain foreign income, a minimum tax on low-taxed foreign earnings, and new measures to deter base erosion. Certain of the amendments included in the TCJA may adversely affect our business, result of operations and financial condition. Although we are currently evaluating the impact of the TCJA on our business, significant uncertainty exists with respect to how the TCJA will ultimately affect our business. Some of the uncertainty will not be resolved until clarifying Treasury regulations are promulgated or other relevant authoritative guidance is published.
Changes in accounting standards issued by the FASB could have a material effect on our balance sheet, revenue and result of operations, and could require a significant expenditure of time, attention and resources, especially by senior management.
Our accounting and financial reporting policies conform to GAAP, which are periodically revised and/or expanded. The application of accounting principles is also subject to varying interpretations over time. Accordingly, we are required to adopt new or revised accounting standards or comply with revised interpretations that are issued from time to time by various parties, including accounting standard setters and those who interpret the standards, such as the FASB and the SEC and our independent registered public accounting firm. Such new financial accounting standards may result in significant changes that could adversely affect our business, financial condition, cash flow and results of operations.
Refer to “Note 2 - Summary of Significant Accounting Policies” of our Notes to the Consolidated Financial Statements for further discussion of new accounting standards, including the implementation status and potential impact to our consolidated financial statements.
Changes in our credit profile could adversely affect our business.

Changes in our credit profile could affect the way crude oil suppliers view our ability to make payments and induce them to shorten the payment terms for our purchases or require us to post security or letters of credit prior to payment. Due to the large dollar amounts and volume of our crude oil and other feedstock purchases, any imposition by our suppliers of more burdensome payment terms on us may have a material adverse effect on our liquidity and our ability to make payments to our suppliers. This, in turn, could cause us to be unable to operate one or more of our refineries at full capacity.
Changes in laws or standards affecting the transportation of North American crude oil by rail could significantly impact our operations, and as a result cause our costs to increase.
Investigations into past rail accidents involving the transport of crude oil have prompted government agencies and other interested parties to call for increased regulation of the transport of crude oil by rail including in the areas of crude oil constituents, rail car design, routing of trains and other matters. Regulation governing shipments of petroleum crude oil by rail requires shippers to properly test and classify petroleum crude oil and further requires shippers to treat Class 3 petroleum crude oil transported by rail in tank cars as a Packing Group I or II hazardous material only. The DOT issued additional rules and regulations that require rail carriers to provide certain notifications to State agencies along routes utilized by trains over a certain length carrying crude oil, enhance safety training standards under the Rail Safety Improvement Act of 2008, require each railroad or contractor to develop and submit a training program to perform regular oversight and annual written reviews and establish enhanced tank car standards and operational controls for high-hazard flammable trains. These rules and any further changes in law, regulations or industry standards that require us to reduce the volatile or flammable constituents in crude oil that is transported by rail, alter the design or standards for rail cars we use, change the routing or scheduling of trains carrying crude oil, or any other changes that detrimentally affect the economics of delivering North American crude oil by rail to our, or subsequently to third party, refineries, could increase our costs, which could have a material adverse effect on our financial condition, results of operations, cash flows and our ability to service our indebtedness.

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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 liability under, or costs and capital expenditures to comply with, environmental and health and safety regulations, which are complex and change frequently.
Our operations are subject to federal, state and local laws regulating, among other things, the handling of petroleum and other regulated materials, the emission and discharge of materials into the environment, waste management, and remediation of discharges of petroleum and petroleum products, characteristics and composition of gasoline and distillates and other matters otherwise relating to the protection of the environment. Our operations are also subject to extensive laws and regulations relating to occupational health and safety.
We cannot predict what additional environmental, health and safety legislation or regulations may be adopted in the future, or how existing or future laws or regulations may be administered or interpreted with respect to our operations. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time.
Certain environmental laws impose strict, and in certain circumstances joint and several liability for, costs of investigation and cleanup of such spills, discharges or releases on owners and operators of, as well as persons who arrange for treatment or disposal of regulated materials at contaminated sites. Under these laws, we may incur liability or be required to pay penalties for past contamination, and third parties may assert claims against us for damages allegedly arising out of any past or future contamination. The potential penalties and clean-up costs for past or future releases or spills, the failure of prior owners of our facilities to complete their clean-up obligations, the liability to third parties for damage to their property, or the need to address newly-discovered information or conditions that may require a response could be significant, and the payment of these amounts could have a material adverse effect on our business, financial condition and results of operations.
Our operating results are seasonal and generally lower in the first and fourth quarters of the year for our refining operations. We depend on favorable weather conditions in the spring and summer months.
Demand for gasoline products is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and construction work. Varying vapor pressure requirements between the summer and winter months also tighten summer gasoline supply. As a result, the operating results of our refining segment are generally lower for the first and fourth quarters of each year.
We may not be able to successfully integrate the Torrance Refinery or future acquisitions into our business, or realize the anticipated benefits of these acquisitions.
Following the completion of the Torrance Acquisition, the integration of this business into our operations may be a complex and time-consuming process that may not be successful. Prior to the completion of the Torrance Acquisition we did not have any operations in the West Coast. This may add complexity to effectively overseeing, integrating and operating this refinery and related assets. 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 or future acquisitions may prove to be incorrect. This acquisition involves risks, including:
unexpected losses of key employees, customers and suppliers of the acquired operations;

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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 our Torrance Acquisition and with future acquisitions, we did not and may 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 significant acquisition or future acquisitions on our financial performance until we have operated the acquired refinery for a substantial period of time.
Risks Related to Our Indebtedness
Our indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under our indebtedness.
Our indebtedness may significantly affect our financial flexibility in the future. As of December 31, 2017, we have total debt of $2,226.1 million, excluding deferred debt issuance costs of $34.5 million, and we could incur an additional $1,195.7 million under our credit facilities. We may incur additional indebtedness in the future. Our strategy includes executing future refinery and logistics acquisitions. Any significant acquisition would likely require us to incur additional indebtedness in order to finance all or a portion of such acquisition. The level of our indebtedness has several important consequences for our future operations, including that:
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 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

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is added to our currently anticipated debt levels, the leverage risks described above would increase. Also, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness.
Restrictive covenants in our debt instruments may limit our ability to undertake certain types of transactions.
Various covenants in our debt instruments and other financing arrangements may restrict our and our subsidiaries’ financial flexibility in a number of ways. Our indebtedness subjects us to financial and other restrictive covenants, including restrictions on our ability to incur additional indebtedness, place liens upon assets, pay dividends or make certain other restricted payments and investments, consummate certain asset sales or asset swaps, conduct businesses other than our current businesses, or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of our assets. Some of these debt instruments also require our subsidiaries to satisfy or maintain certain financial tests in certain circumstances. Our subsidiaries’ ability to meet these financial tests can be affected by events beyond our control and they may not meet such tests.
Provisions in our indentures could discourage an acquisition of us by a third party.
Certain provisions of our indentures could make it more difficult or more expensive for a third party to acquire us. Upon the occurrence of certain transactions constituting a “change in control” as described in the indentures governing the Senior Notes and PBFX Senior Notes (both of which are defined below), holders of our notes could require us to repurchase all outstanding notes at 101% of the principal amount thereof, plus accrued and unpaid interest, if any, at the date of repurchase.
Our future credit ratings could adversely affect our ability to obtain credit in the future.
Our Senior Notes (as defined below) are rated BB by Standard & Poor’s Rating Services and B1 by Moody’s Investors Service. Any adverse effect on our credit rating may increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which would impair our ability to grow our business and make cash distributions to our shareholders.
Risks Related to Our Organizational Structure and Our Class A Common Stock
Our only material asset is our interest in PBF LLC. Accordingly, we depend upon distributions from PBF LLC and its subsidiaries to pay our taxes, meet our other obligations and/or pay dividends in the future.
We are a holding company and all of our operations are conducted through subsidiaries of PBF LLC. We have no independent means of generating revenue and no material assets other than our ownership interest in PBF LLC. Therefore, we depend on the earnings and cash flow of our subsidiaries to meet our obligations, including our indebtedness, tax liabilities and obligations to make payments under a tax receivable agreement entered into with PBF LLC Series A and PBF LLC Series B Unit holders (the “Tax Receivable Agreement”). If we or PBF LLC do not receive such cash distributions, dividends or other payments from our subsidiaries, we and PBF LLC may be unable to meet our obligations and/or pay dividends.
We intend to cause PBF LLC to make distributions to its members in an amount sufficient to enable us to cover all applicable taxes at assumed tax rates, make payments owed by us under the Tax Receivable Agreement, and to pay other obligations and dividends, if any, declared by us. To the extent we need funds and PBF LLC or any of its subsidiaries is restricted from making such distributions under applicable law or regulation or under the terms of our financing or other contractual arrangements, or is otherwise unable to provide such funds, such restrictions could materially adversely affect our liquidity and financial condition.
Our PBF Holding asset based revolving credit agreement (the “Revolving Loan”), 7.00% senior notes due 2023 issued by PBF Holding in November 2015 (the “2023 Senior Notes”), 7.25% senior notes due 2025 issued by PBF Holding in May 2017 (the “2025 Senior Notes”, and together with the 2023 Senior Notes, the “Senior Notes”) and certain of our other outstanding debt arrangements include a restricted payment covenant, which restricts the ability of PBF Holding to make distributions to us, and we anticipate our future debt will contain a similar restriction. PBFX’s five-year, $360.0 million revolving credit facility (the “PBFX Revolving Credit

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Facility”) and PBFX’s indenture governing its PBFX 2023 Senior Notes (as defined in Item 7. Management’s Discussion and Analysis) also contain covenants that limit or restrict PBFX’s ability and the ability of its restricted subsidiaries to make distributions and other restricted payments and restrict PBFX’s ability to incur liens and enter into burdensome agreements. In addition, there may be restrictions on payments by our subsidiaries under applicable laws, including laws that require companies to maintain minimum amounts of capital and to make payments to stockholders only from profits. For example, PBF Holding is generally prohibited under Delaware law from making a distribution to a member to the extent that, at the time of the distribution, after giving effect to the distribution, liabilities of the limited liability company (with certain exceptions) exceed the fair value of its assets, and PBFX is subject to a similar prohibition. As a result, we may be unable to obtain that cash to satisfy our obligations and make payments to our stockholders, if any.
The rights of other members of PBF LLC may conflict the interests of our Class A common stockholders.
The interests of the other members of PBF LLC, which include former directors and officers, may not in all cases be aligned with our Class A common stockholders’ interests. For example, these members may have different tax positions which could influence their positions, including regarding whether and when we dispose of assets and whether and when we incur new or refinance existing indebtedness, especially in light of the existence of the Tax Receivable Agreement described below. In addition, the structuring of future transactions may take into consideration these tax or other considerations even where no similar benefit would accrue to our Class A common stockholders or us. See “Certain Relationships and Related Transactions—IPO Related Agreements” in our 2018 Proxy Statement.
We will be required to pay the former and current holders of PBF LLC Series A Units and PBF LLC Series B Units for certain tax benefits we may claim arising in connection with our prior offerings and future exchanges of PBF LLC Series A Units for shares of our Class A Common Stock and related transactions, and the amounts we may pay could be significant.
We are party to a Tax Receivable Agreement that provides for the payment from time to time by PBF Energy to the former and current holders of PBF LLC Series A Units and PBF LLC Series B Units of 85% of the benefits, if any, that PBF Energy is deemed to realize as a result of (i) the increases in tax basis resulting from its acquisitions of PBF LLC Series A Units, including such acquisitions in connection with our prior offerings or in the future and (ii) certain other tax benefits related to our entering into the Tax Receivable Agreement, including tax benefits attributable to payments under the Tax Receivable Agreement. See “Item 13. Certain Relationships and Related Transactions, and Director Independence.”
We expect that the payments that we may make under the Tax Receivable Agreement will be substantial. As of December 31, 2017, we have recognized a liability for the Tax Receivable Agreement of $362.1 million reflecting our estimate of the undiscounted amounts that we expect to pay under the agreement due to exchanges that occurred prior to that date, and to range over the next five years from approximately $30.0 million to $65.0 million per year and decline thereafter. Future payments by us in respect of subsequent exchanges of PBF LLC Series A Units would be in addition to these amounts and are expected to be material as well. If PBF Energy does not have taxable income, PBF Energy generally is not required (absent a change of control or circumstances requiring an early termination payment) to make payments under the Tax Receivable Agreement for that taxable year because no benefit will have been actually realized. However, any tax benefits that do not result in realized benefits in a given tax year will likely generate tax attributes that may be utilized to generate benefits in previous or future tax years. The utilization of such tax attributes will result in payments under the Tax Receivable Agreement. The foregoing numbers are merely estimates based on assumptions that are subject to change due to various factors, including, among other factors, the timing of exchanges of PBF LLC Series A Units for shares of PBF Energy’s Class A common stock as contemplated by the Tax Receivable Agreement, the price of PBF Energy’s Class A common stock at the time of such exchanges, the extent to which such exchanges are taxable, and the amount and timing of PBF Energy’s income. The actual payments under the Tax Receivable Agreement could differ materially. It is possible that future transactions or events could increase or decrease the actual tax benefits realized and the corresponding Tax Receivable Agreement payments. There may be a material negative effect on our liquidity if, as a result of timing discrepancies or otherwise, (i) the payments under the Tax Receivable Agreement exceed the

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actual benefits we realize in respect of the tax attributes subject to the Tax Receivable Agreement, and/or (ii) distributions to PBF Energy by PBF LLC are not sufficient to permit PBF Energy, after it has paid its taxes and other obligations, to make payments under the Tax Receivable Agreement. The payments under the Tax Receivable Agreement are not conditioned upon any recipient’s continued ownership of us.
In certain cases, payments by us under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits we realize in respect of the tax attributes subject to the Tax Receivable Agreement. These provisions may deter a change in control of our Company.
The Tax Receivable Agreement provides that upon certain changes of control, or if, at any time, PBF Energy elects an early termination of the Tax Receivable Agreement, PBF Energy’s (or its successor’s) obligations with respect to exchanged or acquired PBF LLC Series A Units (whether exchanged or acquired before or after such transaction) would be based on certain assumptions, including (i) that PBF Energy would have sufficient taxable income to fully utilize the deductions arising from the increased tax deductions and tax basis and other benefits related to entering into the Tax Receivable Agreement and (ii) that the subsidiaries of PBF LLC will sell certain nonamortizable assets (and realize certain related tax benefits) no later than a specified date. Moreover, in each of these instances, we would be required to make an immediate payment equal to the present value (at a discount rate equal to LIBOR plus 100 basis points) of the anticipated future tax benefits (based on the foregoing assumptions). Accordingly, payments under the Tax Receivable Agreement may be made years in advance of the actual realization, if any, of the anticipated future tax benefits and may be significantly greater than the actual benefits we realize in respect of the tax attributes subject to the Tax Receivable Agreement. Assuming that the market value of a share of our Class A common stock equals $35.45 per share (the closing price on December 31, 2017) and that LIBOR were to be 1.85%, we estimate that, as of December 31, 2017 the aggregate amount of these accelerated payments would have been approximately $357.1 million if triggered immediately on such date. In these situations, our obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity. We may not be able to finance our obligations under the Tax Receivable Agreement and our existing indebtedness may limit our subsidiaries’ ability to make distributions to us to pay these obligations. These provisions may deter a potential sale of our Company to a third party and may otherwise make it less likely that a third party would enter into a change of control transaction with us.
Moreover, payments under the Tax Receivable Agreement will be based on the tax reporting positions that we determine in accordance with the Tax Receivable Agreement. We will not be reimbursed for any payments previously made under the Tax Receivable Agreement if the Internal Revenue Service subsequently disallows part or all of the tax benefits that gave rise to such prior payments. As a result, in certain circumstances, payments could be made under the Tax Receivable Agreement that are significantly in excess of the benefits that we actually realize in respect of (i) the increases in tax basis resulting from our purchases or exchanges of PBF LLC Series A Units and (ii) certain other tax benefits related to our entering into the Tax Receivable Agreement, including tax benefits attributable to payments under the Tax Receivable Agreement.
We cannot assure you that we will continue to declare dividends or have the available cash to make dividend payments.
Although we currently intend to continue to pay quarterly cash dividends on our Class A common stock, the declaration, amount and payment of any dividends will be at the sole discretion of our board of directors. We are not obligated under any applicable laws, our governing documents or any contractual agreements with our existing and prior owners or otherwise to declare or pay any dividends or other distributions (other than the obligations of PBF LLC to make tax distributions to its members). Our board of directors may take into account, among other things, general economic conditions, our financial condition and operating results, our available cash and current and anticipated cash needs, capital requirements, plans for expansion, including acquisitions, tax, legal, regulatory and contractual restrictions and implications, including under our subsidiaries’ outstanding debt documents, and such other factors as our board of directors may deem relevant in determining whether to declare or pay any dividend. Because PBF Energy is a holding company with no material assets (other than the equity interests of its direct subsidiary), its cash flow and ability to pay dividends is dependent upon the financial results and cash flows of its indirect subsidiaries PBF Holding and PBFX and their respective operating subsidiaries and

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the distribution or other payment of cash to it in the form of dividends or otherwise. The direct and indirect subsidiaries of PBF Energy are separate and distinct legal entities and have no obligation to make any funds available to it other than in the case of certain intercompany transactions. As a result, if we do not declare or pay dividends you may not receive any return on an investment in our Class A common stock unless you sell our Class A common stock for a price greater than that which you paid for it.
Anti-takeover and certain other provisions in our certificate of incorporation and bylaws and Delaware law may discourage or delay a change in control.
Our certificate of incorporation and bylaws contain provisions which could make it more difficult for stockholders to effect certain corporate actions. Among other things, these provisions:
authorize the issuance of undesignated preferred stock, the terms of which may be established and the shares of which may be issued without stockholder approval;
prohibit stockholder action by written consent;
restrict certain business combinations with stockholders who obtain beneficial ownership of a certain percentage of our outstanding common stock;
provide that special meetings of stockholders may be called only by the chairman of the board of directors, the chief executive officer or the board of directors, and establish advance notice procedures for the nomination of candidates for election as directors or for proposing matters that can be acted upon at stockholder meetings; and
provide that our stockholders may only amend our bylaws with the approval of 75% or more of all of the outstanding shares of our capital stock entitled to vote.
These anti-takeover provisions and other provisions of Delaware law may have the effect of delaying or deterring a change of control of our company. Certain provisions could also discourage proxy contests and make it more difficult for you and other stockholders to elect directors of your choosing and to cause us to take other corporate actions you desire. These provisions could limit the price that certain investors might be willing to pay in the future for shares of our Class A common stock.
The market price of our Class A common stock may be volatile, which could cause the value of your investment to decline.
The market price of our Class A common stock may be highly volatile and could be subject to wide fluctuations due to a number of factors including: 
variations in actual or anticipated operating results or dividends, if any, to stockholders;
changes in, or failure to meet, earnings estimates of securities analysts;
market conditions in the oil refining industry and volatility in commodity prices;
the impact of disruptions to crude or feedstock supply to any of our refineries, including disruptions due to problems with third party logistics infrastructure;
litigation and government investigations;
the timing and announcement of any potential acquisitions and subsequent impact of any future acquisitions on our capital structure, financial condition or results of operations;
changes or proposed changes in laws or regulations or differing interpretations or enforcement thereof;
general economic and stock market conditions; and
the availability for sale, or sales by us or our senior management, of a significant number of shares of our Class A common stock in the public market.
In addition, the stock markets generally may experience significant volatility, often unrelated to the operating performance of the individual companies whose securities are publicly traded. These and other factors may cause the market price of our Class A common stock to decrease significantly, which in turn would adversely affect the value of your investment.

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In the past, following periods of volatility in the market price of a company’s securities, stockholders have often instituted class action securities litigation against those companies. Such litigation, if instituted, could result in substantial costs and a diversion of management’s attention and resources, which could significantly harm our profitability and reputation.
If securities or industry analysts do not publish research or reports about our business, or if they downgrade their recommendations regarding our Class A common stock, our stock price and trading volume could decline.
The trading market for our Class A common stock is influenced by the research and reports that industry or securities analysts publish about us or our business. If any of the analysts who cover us downgrade our Class A common stock or publish inaccurate or unfavorable research about our business, our Class A common stock price may decline. If analysts cease coverage of us or fail to regularly publish reports on us, we could lose visibility in the financial markets, which in turn could cause our Class A common stock price or trading volume to decline and our Class A common stock to be less liquid.
Future sales of our shares of Class A common stock could cause our stock price to decline.
The market price of our Class A common stock could decline as a result of sales of a large number of shares of Class A common stock in the market or the perception that such sales could occur. These sales, or the possibility that these sales may occur, including sales related to financing acquisitions, also might make it more difficult for us to sell shares of Class A common stock in the future at a time and at a price that we deem appropriate. In addition, any shares of Class A common stock that we issue, including under any equity incentive plans, would dilute the percentage ownership of the holders of our Class A common stock.
We are party to a registration rights agreement with the other members of PBF LLC pursuant to which we continue to be required to register under the Securities Act and applicable state securities laws to register the resale of the shares of Class A common stock issuable to them upon exchange of all of the PBF LLC Series A Units held by them. We currently have an effective shelf registration statement covering the resale of up to 6,310,055 shares of our Class A common stock issued or issuable to existing holders of PBF LLC Series A Units, which shares may be sold from time to time in the public markets, subject to certain lock-up agreements. Our shares also may be sold under Rule 144 under the Securities Act depending on the holding period and subject to restrictions in the case of shares held by persons deemed to be our affiliates.
Risks Related to Our Ownership of PBFX
We depend upon PBFX for a substantial portion of our refineries’ logistics needs and have obligations for minimum volume commitments in our commercial agreements with PBFX.
We depend on PBFX to receive, handle, store and transfer crude oil, petroleum products and natural gas for us from our operations and sources located throughout the United States and Canada in support of certain of our refineries under long-term, fee-based commercial agreements with our subsidiaries. These commercial agreements have an initial term of approximately seven to ten 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

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and distribute products could be adversely impacted, which could adversely affect our business, financial condition and results of operations.
In addition, as of December 31, 2017, PBF LLC owns 18,459,497 common units representing an aggregate 44.1% limited partner interest in PBFX, as well as all of the incentive distribution rights and a non-economic general partner interest in PBFX. The inability of PBFX to continue operations, perform under its commercial arrangements with our subsidiaries or the occurrence of any of these risks or operational hazards, could also adversely impact the value of our investment in PBFX and, because PBFX is a consolidated entity, our business, financial condition and results of operations.
PBFX may not have sufficient available cash to pay any quarterly distribution on its units. Furthermore, PBFX is not required to make distributions to holders of units on a quarterly basis or otherwise, and may elect to distribute less than all of its available cash.
PBFX may not have sufficient available cash from operating surplus each quarter to enable it to pay the minimum quarterly distribution. The amount of cash it can distribute on its units principally depends upon the amount of cash generated from its operations, which will fluctuate from quarter to quarter based on, among other things: the volume of crude oil and refined products it throughputs; PBFX’s entitlement to payments associated with minimum volume commitments; the fees it charges for the volumes throughput; the level of its operating, maintenance and general and administrative costs; and prevailing economic conditions. In addition, the actual amount of cash PBFX will have available for distribution will depend on other factors, some of which are beyond its control, including: the level and timing of capital expenditures it makes; the amount of its operating expenses and general and administrative expenses, and payment of the administrative fees for services provided to it by PBF GP and its affiliate; the cost of acquisitions, if any; debt service requirements and other liabilities; fluctuations in working capital needs; PBFX’s ability to borrow funds and access capital markets; restrictions contained in the PBFX Revolving Credit Facility, the PBFX 2023 Senior Notes and other debt service requirements; the amount of cash reserves established by PBF GP; and other business risks affecting cash levels.
In addition, if PBFX issues additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that PBFX will be unable to maintain or increase its per unit distribution level. There are no limitations in the partnership agreement of PBFX on its ability to issue additional units, including units ranking senior to the outstanding units. The incurrence of additional borrowings or other debt to finance PBFX’s growth strategy would result in increased interest expense, which, in turn, may impact the cash that it has available to distribute to its unit holders (including us). Furthermore, the partnership agreement does not require PBFX to pay distributions on a quarterly basis or otherwise. The board of directors of PBF GP may at any time, for any reason, change its cash distribution policy or decide not to make any distributions (including to us).
Increases in interest rates could adversely impact the price of PBFX’s units, PBFX’s ability to issue equity or incur debt for acquisitions or other purposes and its ability to make cash distributions at its intended levels.
Interest rates on future credit facilities and debt offerings could be higher than current levels, causing PBFX’s financing costs to increase accordingly. As with other yield-oriented securities, PBFX’s unit price is impacted by the level of its cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in PBFX, and a rising interest rate environment could have an adverse impact on the price of the units, PBFX’s ability to issue equity or incur debt for acquisitions or other purposes and its ability to make cash distributions at intended levels, which could adversely impact the value of our investment in PBFX.

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PBF Energy will be required to pay taxes on its share of taxable income from PBF LLC and its other subsidiary flow-through entities (including PBFX), regardless of the amount of cash distributions PBF Energy receives from PBF LLC.
The holders of limited liability company interests in PBF LLC, including PBF Energy, generally have to include for purposes of calculating their U.S. federal, state and local income taxes their share of any taxable income of PBF LLC, regardless of whether such holders receive cash distributions from PBF LLC. PBF Energy ultimately may not receive cash distributions from PBF LLC equal to its share of the taxable income of PBF LLC or even equal to the actual tax due with respect to that income. For example, PBF LLC is required to include in taxable income PBF LLC’s allocable share of PBFX’s taxable income and gains (such share to be determined pursuant to the partnership agreement of PBFX), regardless of the amount of cash distributions received by PBF LLC from PBFX, and such taxable income and gains will flow-through to PBF Energy to the extent of its allocable share of the taxable income of PBF LLC. As a result, at certain times, including during the subordination period for the subordinated units, the amount of cash otherwise ultimately available to PBF Energy on account of its indirect interest in PBFX may not be sufficient for PBF Energy to pay the amount of taxes it will owe on account of its indirect interests in PBFX.
If PBFX was to be treated as a corporation, rather than as a partnership, for U.S. federal income tax purposes or if PBFX was otherwise subject to entity-level taxation, PBFX’s cash available for distribution to its unit holders, including to us, would be reduced, likely causing a substantial reduction in the value of units, including the units held by us.
The present U.S. federal income tax treatment of publicly traded partnerships, including PBFX, or an investment in its common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time the U.S. Congress considers substantive changes to the existing federal income tax laws that would affect publicly traded partnerships. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for PBFX to meet the exception to be treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in PBFX common units.
If PBFX were treated as a corporation for U.S. federal income tax purposes, it would pay U.S. federal income tax on income at the corporate tax rate, which is currently a maximum of 21% under the TCJA, and would likely be liable for state income tax at varying rates. Distributions to PBFX unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to PBFX unitholders. Because taxes would be imposed upon PBFX as a corporation, the cash available for distribution to PBFX unitholders would be substantially reduced. Therefore, PBFX’s treatment as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to PBFX unitholders, likely causing a substantial reduction in the value of the units.
All of the executive officers and a majority of the directors of PBF GP are also current or former officers 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. Conflicts of interest may arise between PBF Energy and its affiliates, including PBF GP, on the one hand, and PBFX and its unit holders, on the other hand. In resolving these conflicts of interest, PBF GP may favor its own interests and the interests of PBFX over the interests of PBF Energy. In certain circumstances, PBF GP may refer any conflicts of interest or potential conflicts of interest between PBFX, on the one hand, and PBF Energy, on the other hand, to its conflicts committee (which must consist entirely of independent directors) for resolution, which conflicts committee must act in the

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best interests of the public unit holders of PBFX. As a result, PBF GP may manage the business of PBFX in a way that may differ from the best interests of PBF Energy or its stockholders.

ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

ITEM 2. PROPERTIES
See “Item 1. Business”.

ITEM 3. LEGAL PROCEEDINGS
On July 24, 2013, the Delaware Department of Natural Resources and Environmental Control (“DNREC”) issued a Notice of Administrative Penalty Assessment and Secretary’s Order to Delaware City Refining for alleged air emission violations that occurred during the re-start of the refinery in 2011 and subsequent to the re-start. The penalty assessment seeks $460,200 in penalties and $69,030 in cost recovery for DNREC’s expenses associated with investigation of the incidents. We dispute the amount of the penalty assessment and allegations made in the order, and are in discussions with DNREC to resolve the assessment. It is possible that DNREC will assess a penalty in this matter but any such amount is not expected to be material to us.
At the time we acquired the Chalmette refinery it was subject to a Consolidated Compliance Order and Notice of Potential Penalty (the “Order”) issued by the Louisiana Department of Environmental Quality (“LDEQ”) covering deviations from 2009 and 2010. Chalmette Refining and LDEQ subsequently entered into a dispute resolution agreement to negotiate the resolution of deviations inside and outside the periods covered by the Order. Although a settlement agreement has not been finalized, the administrative penalty is anticipated to be approximately $41,000, including beneficial environmental projects. To the extent the administrative penalty exceeds such amount, it is not expected to be material to us
The Delaware City refinery is appealing a Notice of Penalty Assessment and Secretary’s Order issued in March 2017, including a $150,000 fine, alleging violation of a 2013 Secretary’s Order authorizing crude oil shipment by barge. DNREC determined that the Delaware City refinery had violated the order by failing to make timely and full disclosure to DNREC about the nature and extent of those shipments, and had misrepresented the number of shipments that went to other facilities. The Penalty Assessment and Secretary’s Order conclude that the 2013 Secretary’s Order was violated by the refinery by shipping crude oil from the Delaware City terminal to three locations other than the Paulsboro refinery, on 15 days in 2014, making a total of 17 separate barge shipments containing approximately 35.7 million gallons of crude oil in total. On April 28, 2017, the Delaware City refinery appealed the Notice of Penalty Assessment and Secretary’s Order. The hearing of the appeal is scheduled for February 2018. To the extent that the penalty and Secretary’s Order are upheld, there will not be a material adverse effect on the Company’s financial position, results of operations or cash flows.
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 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 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. During the hearing before the Coastal Zone Board on standing, one of the appellants’ witnesses made a reference to the flammability of ethanol, without any indication of the significance of flammability/explosivity to specific concerns. Moreover, the appellants did not introduce at hearing any evidence of the relative flammability of ethanol as compared to other materials shipped to and from the refinery. However, the sole dissenting opinion from the Coastal Zone Board focused on the flammability/explosivity issue, alleging that the appellants’ testimony raised the issue 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.

51



At the time we acquired the Toledo refinery, the EPA had initiated an investigation into the compliance of the refinery with EPA standards governing flaring pursuant to Section 114 of the Clean Air Act.  On February 1, 2013, the EPA issued an Amended Notice of Violation, and on September 20, 2013, the EPA issued a Notice of Violation and Finding of Violation to Toledo Refining, alleging certain violations of the Clean Air Act at its Plant 4 and Plant 9 flares since the acquisition of the refinery on March 1, 2011.  Toledo Refining and the EPA subsequently entered into tolling agreements pending settlement discussions.  Although a resolution has not been finalized, the EPA has proposed that the Toledo refinery pay a civil administrative penalty of $741,000 including supplemental environmental projects. To the extent the administrative penalty exceeds such amount, it is not expected to be material to us.
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 logistic assets, including specified incidents and/or NOVs issued by regulatory agencies in various years before our ownership, including the SCAQMD and Cal/OSHA. Following the closing of the acquisition, further NOVs were issued by the SCAQMD, Cal/OSHA, the City of Torrance, and the Torrance Fire Department. No settlement or penalty demand in excess of $100,000 has been made or received with respect to these NOVs and preliminary findings. It is reasonably possible that the SCAQMD, Cal/OSHA and/or the City of Torrance will assess penalties in the other matters in excess of $100,000 but any such amount is not expected to be material to us, individually or in the aggregate.
On September 2, 2011, prior to our ownership of the Chalmette refinery, the plaintiff in Vincent Caruso, et al. v. Chalmette Refining, L.L.C., filed an action on behalf of himself and potentially several thousand other Louisiana residents who live or own property in St. Bernard Parish and Orleans Parish and whose property was allegedly contaminated and who allegedly suffered any property damages and clean-up costs as a result of an emission of spent catalyst from the Chalmette refinery on September 6, 2010. Plaintiffs claim to have suffered injuries, symptoms, and property damage as a result of the release, although the trial court has limited recovery to property damages and clean-up expenses. Plaintiffs seek to recover unspecified damages, interest and costs. In 2016, there was a mini-trial for four plaintiffs for property damage relating to home and vehicle cleaning and the trial court rendered judgment awarding damages related to the cost for home cleaning and vehicle cleaning to the four plaintiffs. The trial court found Chalmette Refining and co-defendant Eaton Corporation (“Eaton”), to be solidarily liable for the damages. Chalmette Refining and Eaton filed an appeal in August 2016 of the judgment on the mini-trial and on June 28, 2017, the appellate court unanimously reversed the judgment awarding damages to the plaintiffs. On July 12, 2017, the plaintiffs filed for a rehearing of the appellate court judgment, which was denied on July 31, 2017. As a result of the appellate court’s judgment, the potential amount of the claims is not determinable. Depending upon the ultimate class size and the nature of the claims, the outcome may have a material adverse effect on our financial position, results of operations, or cash flows.
On December 5, 1990, prior to our ownership of the Chalmette refinery, the plaintiff in Adam Thomas, et al. v. Exxon Mobil Corporation and Chalmette Refining, L.L.C., filed an action on behalf of himself and potentially thousands of other individuals in St. Bernard Parish and Plaquemines Parish who were allegedly exposed to hydrogen sulfide and sulfur dioxide as a result of more than 100 separate flaring events that occurred between 1989 and 2007. This litigation is proceeding as a mass action with individually named plaintiffs as a result of a 2008 trial court decision, affirmed by the court of appeals, that denied class certification.  The Plaintiffs claim to have suffered physical injuries, property damage, and other damages as a result of the releases. Plaintiffs seek to recover unspecified compensatory and punitive damages, interest, and costs.  The state trial court has scheduled a mini-trial of up to 10 plaintiffs in May 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 is not determinable. It is possible that an adverse outcome may have a material adverse effect on our financial position, results of operations, or cash flows.

52



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 Corporation 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 Refinery which was then owned and operated by Exxon. The operation of the Torrance Refinery by the PBF entities subsequent to our acquisition in July 2016 is also referenced in the complaint. To the extent that plaintiffs’ claims relate to the ESP explosion, Exxon has retained responsibility for any liabilities that would arise from the lawsuit pursuant to the agreement relating to the acquisition of the Torrance Refinery. This matter is in the initial stages of discovery and we cannot currently estimate the amount or the timing of its resolution. We presently believe the outcome will not have a material impact on our financial position, results of operations or cash flows.
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.
As of January 1, 2011, we are required to comply with the EPA’s Control of Hazardous Air Pollutants From Mobile Sources, or MSAT2, regulations on gasoline that impose reductions in the benzene content of our produced gasoline. We purchase benzene credits to meet these requirements. Our planned capital projects will reduce the amount of benzene credits that we need to purchase. In addition, the renewable fuel standards mandate the blending of prescribed percentages of renewable fuels (e.g., ethanol and biofuels) into our produced gasoline and diesel. These new requirements, other requirements of the CAA and other presently existing or future environmental 25 regulations may cause us to make substantial capital expenditures as well as the purchase of credits at significant cost, to enable our refineries to produce products that meet applicable requirements.
CERCLA, also known as “Superfund,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances. Under CERCLA, such persons may be subject to joint and several liability for investigation and the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. As discussed more fully above, certain of our sites are subject to these laws and we may be held liable for investigation and remediation costs or claims for natural resource damages. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Analogous state laws impose similar responsibilities and liabilities on responsible parties. In our current normal operations, we have generated waste, some of which falls within the statutory definition of a “hazardous substance” and some of which may have been disposed of at sites that may require cleanup under Superfund.
ITEM 4. MINE SAFETY DISCLOSURE
None.


53



PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
PBF Energy Class A common stock trades on the New York Stock Exchange under the symbol “PBF.” Our Class B common stock is not publicly traded.
As of February 20, 2018 there were 122 holders of record of our Class A common stock and 24 holders of record of our Class B common stock.
The following table sets forth, for the periods indicated, the high and low sales prices of our Class A common stock as reported by the New York Stock Exchange for the prior two fiscal years and dividends declared on such stock for the same periods.
 
 
Sales Prices of  the
Common Stock
 
Dividends
Per
Common Share
 
 
High
 
Low
 
2017
 
 
 
 
 
 
First Quarter ended March 31, 2017
 
$
28.92

 
$
20.44

 
$
0.30

Second Quarter ended June 30, 2017
 
$
23.52

 
$
18.48

 
$
0.30

Third Quarter ended September 30, 2017
 
$
28.31

 
$
19.46

 
$
0.30

Fourth Quarter ended December 31, 2017
 
$
36.07

 
$
26.24

 
$
0.30

2016
 
 
 
 
 
 
First Quarter ended March 31, 2016
 
$
38.27

 
$
25.60

 
$
0.30

Second Quarter ended June 30, 2016
 
$
35.67

 
$
21.87

 
$
0.30

Third Quarter ended September 30, 2016
 
$
24.47

 
$
20.57

 
$
0.30

Fourth Quarter ended December 31, 2016
 
$
30.98

 
$
19.47

 
$
0.30

Dividend and Distribution Policy
Subject to the following paragraphs, PBF Energy currently intends to continue to pay quarterly cash dividends of approximately $0.30 per share on its Class A common stock. The declaration, amount and payment of this and any other future dividends on shares of Class A common stock will be at the sole discretion of PBF Energy’s board of directors.
PBF Energy is a holding company and has no material assets other than its ownership interests of PBF LLC. In order for PBF Energy to pay any dividends, it needs to cause PBF LLC to make distributions to it and the holders of PBF LLC Series A Units, and PBF LLC needs to cause PBF Holding and/or PBFX to make distributions to it, in at least an amount sufficient to cover cash dividends, if any, declared by PBF Energy. Each of PBF Holding and PBFX is generally prohibited under Delaware law from making a distribution to a member to the extent that, at the time of the distribution, after giving effect to the distribution, liabilities of the limited liability company (with certain exceptions) exceed the fair value of its assets. As a result, PBF LLC may be unable to obtain cash from PBF Holding and/or PBFX to satisfy its obligations and make distributions to PBF Energy for dividends, if any, to PBF Energy’s stockholders. If PBF LLC makes such distributions to PBF Energy, the holders of PBF LLC Series A Units will also be entitled to receive pro rata distributions.
The ability of PBF Holding to pay dividends and make distributions to PBF LLC is, and in the future may be, limited by covenants in its Revolving Loan, the Senior Notes and other debt instruments. Subject to certain exceptions, the Revolving Loan and the indentures governing the Senior Notes prohibit PBF Holding from making

54



distributions to PBF LLC if certain defaults exist. In addition, both the indentures and the Revolving Loan contain additional restrictions limiting PBF Holding’s ability to make distributions to PBF LLC.
PBFX intends to make a minimum quarterly distribution to the holders of its common units, including PBF LLC, of at least $0.30 per unit, or $1.20 per unit on an annualized basis, to the extent PBFX has sufficient cash from operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to PBFX’s general partner. However, there is no guarantee that PBFX will pay the minimum quarterly distribution or any amount on the units we own in any quarter. Even if PBFX’s cash distribution policy is not modified or revoked, the amount of distributions paid under the policy and the decision to make any distribution is determined by its general partner, taking into consideration the terms of PBFX’s partnership agreement and debt facilities.
PBF Holding made $61.1 million in distributions to PBF LLC during the year ended December 31, 2017. PBF LLC used $136.4 million, which included $58.6 million distributed from PBF Holding, to make four separate non-tax distributions of $0.30 per unit ($1.20 per unit in total) to its members, of which $131.8 million was distributed to PBF Energy and the balance was distributed to PBF LLC’s other members. PBF Energy used this $131.8 million to pay four separate equivalent cash dividends of $0.30 per share of Class A common stock on March 13, 2017, May 31, 2017, August 31, 2017 and November 29, 2017. There were no tax distributions to PBF LLC members in 2017. In addition, PBFX made aggregate quarterly distributions of $86.5 million ($1.86 per unit) during the year ended December 31, 2017 to holders of its common units, of which $41.9 million was paid to PBF LLC including payments related to IDRs.
PBF LLC owns all of the IDRs of PBFX. The IDRs entitle PBF LLC to receive increasing percentages, up to a maximum of 50.0%, of the cash PBFX distributes from operating surplus in excess of $0.345 per unit per quarter. The maximum distribution of 50.0% includes distributions paid to PBF LLC on its partnership interest. The maximum distribution of 50.0% does not include any distributions that PBF LLC may receive on common units that it owns. PBFX made IDR payments of $7.6 million to PBF LLC based on its distributions for the year ended December 31, 2017.
PBF LLC expects to continue to make tax distributions to its members in accordance with its amended and restated limited liability company agreement.

55



Stock Performance Graph
In accordance with SEC rules, the information contained in the Stock Performance Graph below shall not be deemed to be “soliciting material,” or to be “filed” with the SEC, or subject to the SEC’s Regulation 14A or 14C, other than as provided under Item 201(e) of Regulation S-K, or to the liabilities of Section 18 of the Securities Exchange Act of 1934, as amended, except to the extent that we specifically request that the information be treated as soliciting material or specifically incorporate it by reference into a document filed under the Securities Act of 1933, as amended.
This performance graph and the related textual information are based on historical data and are not indicative of future performance. The following line graph compares the cumulative total return on an investment in our common stock against the cumulative total return of the S&P 500 Composite Index and an index of peer companies (that we selected) for the periods commencing December 31, 2012 through December 31, 2017. Our peer group consists of the following companies that are engaged in refining operations in the U.S.: Andeavor; CVR Energy, Inc.; Delek US Holdings, Inc.; HollyFrontier Corporation; Marathon Petroleum Corporation; Phillips 66; and Valero Energy Corporation.
pbf20175yearstockgrapha04.gif
 
12/31/2012
 
12/31/2013
 
12/31/2014
 
12/31/2015
 
12/31/2016
 
12/31/2017
PBF Energy Inc. Class A Common Stock
$
100.00

 
$
112.70

 
$
99.83

 
$
143.37

 
$
113.91

 
$
152.14

S&P 500
100.00

 
132.39

 
150.51

 
152.59

 
170.84

 
208.14

Peer Group
100.00

 
145.76

 
143.36

 
179.44

 
180.23

 
239.53


56



Recent Sales of Unregistered Securities—Exchange of PBF LLC Series A Units for Class A Common Stock
In the fourth quarter of 2017, a total of 78,758 PBF LLC Series A Units were exchanged for 78,758 shares of our Class A common stock in transactions exempt from registration under Section 4(2) of the Securities Act. We received no other consideration in connection with these exchanges. No exchanges were made by any of our directors or executive officers.
Share Repurchase Program
Our Board of Directors authorized the repurchase of up to $300.0 million of our Class A common stock (as amended from time to time, the “Repurchase Program”), which expires on September 30, 2018. These repurchases may be made from time to time through various methods, including open market transactions, block trades, accelerated share repurchases, privately negotiated transactions or otherwise, certain of which may be effected through Rule 10b5-1 and Rule 10b-18 plans. The timing and number of shares repurchased will depend on a variety of factors, including price, capital availability, legal requirements and economic and market conditions. We are not obligated to purchase any shares under the Repurchase Program, and repurchases may be suspended or discontinued at any time without prior notice.
There were no repurchases of our Class A Common Stock during the fourth quarter of 2017. For the period of time from the inception of the Repurchase Program through December 31, 2017, we purchased 6,050,717 shares for $150.8 million. As of December 31, 2017, we had $149.2 million remaining authorization under the Repurchase Program.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information about the securities authorized for issuance under our equity compensation plans as of December 31, 2017.
 
 
Equity Compensation Plan Information
 
 
 
(A)
 
(B)
 
(C)
 
 
 
Number of
securities to be
issued upon
exercise of
outstanding
options, warrants
and rights
 
Weighted-average
exercise price of
outstanding
options, warrants,
and rights
 
Number of securities
remaining available for
future issuance under
equity compensation
plans (excluding
securities reflected in
column (A))(1)
 
Approved by stockholders:
 
 
 
 
 
 
 
2012 Equity Incentive Plan (as amended)
 
6,017,775

 
$
27.08

 

(2)
2017 Equity Incentive Plan
 
865,000

 
28.62

 
3,072,125

 
Equity compensation plans not approved by security holders
 

 

 

 
Total
 
6,882,775

 
$
27.27

 
3,072,125

 

(1) Securities available for future issuance under the plan can be issued in various forms, including, without limitation, restricted stock and stock options.
(2) The Amended and Restated 2012 Plan currently has no shares remaining for future issuance; it has been superseded by the 2017 Equity Incentive Plan.


57



ITEM 6. SELECTED FINANCIAL DATA
The following table presents selected historical consolidated financial data of PBF Energy. The selected historical consolidated financial data as of December 31, 2017 and 2016 and for each of the three years in the period ended December 31, 2017, have been derived from our audited financial statements, included in “Item 8. Financial Statements and Supplementary Data.” The selected historical consolidated financial data as of December 31, 2015, 2014 and 2013 and for the years ended December 31, 2014 and 2013 have been derived from the audited financial statements of PBF Energy not included in this Annual Report on Form 10-K. As a result of the Chalmette and Torrance acquisitions, the historical consolidated financial results of PBF Energy only include the results of operations for the Chalmette and Torrance refineries from November 1, 2015 and July 1, 2016 forward, respectively.
The historical consolidated financial data and other statistical data presented below should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and the related notes thereto, included in “Item 8. Financial Statements and Supplementary Data.”
The consolidated financial information may not be indicative of our future financial condition, results of operations or cash flows.
As discussed in “Note 2 - Summary of Significant Accounting Policies” of our Notes to the Consolidated Financial Statements, during the year ended December 31, 2017, we determined that we would revise the presentation of certain line items on our consolidated statements of operations to enhance our disclosure under the requirements of Rule 5-03 of Regulation S-X. The revised presentation is comprised of the inclusion of a subtotal within costs and expenses referred to as “Cost of sales” and the reclassification of total depreciation and amortization expense between such amounts attributable to cost of sales 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. The historical comparative information has been revised to conform to the current presentation. This revised presentation does not have an effect on our historical consolidated income from operations or net income, nor does it have any impact on our consolidated balance sheets, statements of comprehensive income or statements of cash flows.


58



 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
 
2014
 
2013
 
 
(in thousands, except share and per share data)
Statement of operations data:
 
 
 
 
 
 
 
 
 
 
Revenues
 
$
21,786,637

 
$
15,920,424

 
$
13,123,929

 
$
19,828,155

 
$
19,151,455

Cost and expenses:
 
 
 
 
 
 
 
 
 
 
Cost of products and other
 
18,863,621

 
13,598,341

 
11,481,614

 
18,471,203

 
17,803,314

Operating expenses (excluding depreciation and amortization expense as reflected below)
 
1,685,611

 
1,423,198

 
904,525

 
883,140

 
812,652

Depreciation and amortization expense
 
277,992

 
216,341

 
187,729

 
166,799

 
98,622

Cost of sales
 
20,827,224

 
15,237,880

 
12,573,868

 
19,521,142

 
18,714,588

General and administrative expenses (excluding depreciation and amortization expense as reflected below) (1)
 
214,773

 
166,452

 
181,266

 
146,661

 
95,794

Depreciation and amortization expense
 
12,964

 
5,835

 
9,688

 
13,583

 
12,857

Loss (gain) on sale of asset
 
1,458

 
11,374

 
(1,004
)
 
(895
)
 
(183
)
Total cost and expenses
 
21,056,419

 
15,421,541

 
12,763,818

 
19,680,491

 
18,823,056

Income from operations
 
730,218

 
498,883

 
360,111

 
147,664

 
328,399

Other income (expense):
 
 
 
 
 
 
 
 
 
 
Change in Tax Receivable Agreement liability
 
250,922

 
12,908

 
18,150

 
2,990

 
(8,540
)
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
 
(154,427
)
 
(150,045
)
 
(106,187
)
 
(98,764
)
 
(93,784
)
Income before income taxes
 
799,015

 
363,168

 
282,258

 
55,859

 
230,766

Income tax expense (benefit)
 
315,584

 
137,650

 
86,725

 
(22,412
)
 
16,681

Net income
 
483,431

 
225,518

 
195,533

 
78,271

 
214,085

Less: net income attributable to noncontrolling interests
 
67,914

 
54,707

 
49,132

 
116,508

 
174,545

Net income (loss) attributable to PBF Energy Inc. stockholders
 
$
415,517

 
$
170,811

 
$
146,401

 
$
(38,237
)
 
$
39,540

Weighted-average shares of Class A common stock outstanding:
 
 
 
 
 
 
 
 
 
 
Basic
 
109,779,407

 
98,334,302

 
88,106,999

 
74,464,494

 
32,488,369

Diluted
 
113,898,845

 
103,606,709

 
94,138,850

 
74,464,494

 
33,061,081

Net income (loss) available to Class A common stock per share:
 
 
 
 
 
 
 
 
 
 
Basic
 
$
3.78

 
$
1.74

 
$
1.66

 
$
(0.51
)
 
$
1.22

Diluted
 
$
3.73

 
$
1.74

 
$
1.65

 
$
(0.51
)
 
$
1.20

Dividends per common share
 
$
1.20

 
$
1.20

 
$
1.20

 
$
1.20

 
$
1.20

Balance sheet data (at end of period) :
 
 
 
 
 
 
 
 
 
 
Total assets
 
$
8,117,993

 
$
7,621,927

 
$
6,105,124

 
$
5,164,008

 
$
4,413,808

Total debt (2)
 
2,226,109

 
2,180,700

 
1,881,637

 
1,260,349

 
747,576

Total equity
 
2,902,949

 
2,570,684

 
2,095,857

 
1,693,316

 
1,715,256

Other financial data :
 
 
 
 
 
 
 
 
 
 
Capital expenditures (3)
 
$
727,035

 
$
1,612,871

 
$
981,080

 
$
631,332

 
$
415,702

——————————
(1)
Includes acquisition related expenses consisting primarily of consulting and legal expenses related to the Torrance Acquisition, PBFX Plains Asset Purchase, Chalmette Acquisition and other pending and non-consummated acquisitions of $1.0 million, $17.5 million and $5.8 million in 2017, 2016 and 2015, respectively.
(2)
Total debt, excluding debt issuance costs, includes current maturities, our Note payable and our Delaware Economic Development Authority Loan (which was fully converted to a grant as of December 31, 2016).
(3)
Includes expenditures for acquisitions, construction in progress, property, plant and equipment (including railcar purchases), deferred turnaround costs and other assets, excluding the proceeds from sales of assets.

59



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, and 2, “Business, Risk Factors, and Properties,” Item 6, “Selected Financial Data,” and Item 8, “Financial Statements and Supplementary Data,” respectively, included in this Annual Report on Form 10-K.
CAUTIONARY STATEMENT FOR THE PURPOSE OF SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This Annual Report on Form 10-K contains certain “forward-looking statements,” as defined in the Private Securities Litigation Reform Act of 1995 (“PSLRA”), of expected future developments that involve risks and uncertainties. You can identify forward-looking statements because they contain words such as “believes,” “expects,” “may,” “should,” “seeks,” “approximately,” “intends,” “plans,” “estimates,” “anticipates” or similar expressions that relate to our strategy, plans or intentions. All statements we make relating to our estimated and projected earnings, margins, costs, expenditures, cash flows, growth rates and financial results or to our strategies, objectives, intentions, resources and expectations regarding future industry trends are forward-looking statements made under the safe harbor of the PSLRA except to the extent such statements relate to the operations of a partnership or limited liability company. In addition, we, through our senior management, from time to time make forward-looking public statements concerning our expected future operations and performance and other developments. These forward-looking statements are subject to risks and uncertainties that may change at any time, and, therefore, our actual results may differ materially from those that we expected. We derive many of our forward-looking statements from our operating budgets and forecasts, which are based upon many detailed assumptions. While we believe that our assumptions are reasonable, we caution that it is very difficult to predict the impact of known factors, and, of course, it is impossible for us to anticipate all factors that could affect our actual results.
Important factors that could cause actual results to differ materially from our expectations, which we refer to as “cautionary statements,” are disclosed under “Item 1A. Risk Factors,” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Annual Report on Form 10-K. All forward-looking information in this Annual Report on Form 10-K and subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements. Some of the factors that we believe could affect our results include:
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;
our supply and inventory intermediation arrangements expose us to counterparty credit and performance risk;
termination of our A&R Intermediation Agreements with J. Aron, which could have a material adverse effect on our liquidity, as we would be required to finance our intermediate and refined products inventory covered by the agreements. Additionally, we are obligated to repurchase from J. Aron certain intermediates and finished products located at the Paulsboro and Delaware City refineries’ storage tanks upon termination of these agreements;
restrictive covenants in our indebtedness that may adversely affect our operational flexibility;
payments to the current and former holders of PBF LLC Series A Units and PBF LLC Series B Units under our Tax Receivable Agreement for certain tax benefits we may claim;
our assumptions regarding payments arising under PBF Energy’s Tax Receivable Agreement and other arrangements relating to our organizational structure are subject to change due to various factors, including, among other factors, the timing of exchanges of PBF LLC Series A Units for shares of our Class A common stock as contemplated by the Tax Receivable Agreement, the price of our Class A common stock at the time of such exchanges, the extent to which such exchanges are taxable, and the amount and timing of our income;
our expectations and timing with respect to our acquisition activity and whether such acquisitions are accretive or dilutive to shareholders;

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our expectations with respect to our capital improvement and turnaround projects;
the status of an air permit to transfer crude through the Delaware City refinery’s dock;
the impact of disruptions to crude or feedstock supply to any of our refineries, including disruptions due to problems at PBFX or with third party logistics infrastructure or operations, including pipeline, marine and rail transportation;
the possibility that we might reduce or not make further dividend payments;
the inability of our subsidiaries to freely pay dividends or make distributions to us;
the impact of current and future laws, rulings and governmental regulations, including the implementation of rules and regulations regarding transportation of crude oil by rail;
the impact of the newly enacted federal income tax legislation on our business;
the effectiveness of our crude oil sourcing strategies, including our crude by rail strategy and related commitments;
adverse impacts from changes in our regulatory environment, such as the effects of compliance with the California Global Warming Solutions Act (also referred to as “AB32”), or from actions taken by environmental interest groups;
market risks related to the volatility in the price of RINs required to comply with the Renewable Fuel Standards and GHG emission credits required to comply with various GHG emission programs, such as AB32;
our ability to successfully integrate recently completed acquisitions into our business and realize the benefits from such acquisitions;
liabilities arising from recent acquisitions that are unforeseen or exceed our expectations;
risk associated with the operation of PBFX as a separate, publicly-traded entity;
potential tax consequences related to our investment in PBFX; and
any decisions we continue to make with respect to our energy-related logistical 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.
Explanatory Note
This Annual Report on Form 10-K is filed by PBF Energy which is a holding company whose primary asset is an equity interest in PBF LLC. PBF Energy is the sole managing member of, and owner of an equity interest representing approximately 96.7% of the outstanding economic interests in PBF LLC as of December 31, 2017. PBF Energy operates and controls all of the business and affairs and consolidates the financial results of PBF LLC and its subsidiaries. PBF LLC is a holding company for the companies that directly and indirectly own and operate the business.
Unless the context indicates otherwise, the terms “we,” “us,” and “our” refer to PBF Energy and its consolidated subsidiaries, including PBF LLC, PBF Holding and its subsidiaries and PBFX and its subsidiaries.


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Executive Summary
Our business operations are conducted by PBF LLC and its subsidiaries. We were formed in March 2008 to pursue the acquisitions of crude oil refineries and downstream assets in North America. We currently own and operate five domestic oil refineries and related assets located in Toledo, Ohio, Delaware City, Delaware, Paulsboro, New Jersey, New Orleans, Louisiana and Torrance, California. Our refineries have a combined processing capacity, known as throughput, of approximately 900,000 bpd, and a weighted average Nelson Complexity Index of 12.2. We operate in two reportable business segments: Refining and Logistics. Our five oil refineries are all engaged in the refining of crude oil and other feedstocks into petroleum products, and are aggregated into the Refining segment. PBFX operates certain logistical assets such as crude oil and refined petroleum products terminals, pipelines, and storage facilities, which are aggregated into the Logistics segment.
Factors Affecting Comparability
Our results over the past three years have been affected by the following events, the understanding of which will aid in assessing the comparability of our period to period financial performance and financial condition.
Torrance Acquisition
On July 1, 2016, we acquired from ExxonMobil and its subsidiary, Mobil Pacific Pipeline Company, the Torrance refinery and related logistics assets. The Torrance refinery, located on 750 acres in Torrance, California, is a high-conversion 155,000 bpd, delayed-coking refinery with a Nelson Complexity Index of 14.9. The facility is strategically positioned in Southern California with advantaged logistics connectivity that offers flexible raw material sourcing and product distribution opportunities primarily in the California, Las Vegas and Phoenix area markets. The Torrance Acquisition increased our total throughput capacity to approximately 900,000 bpd.
In addition to refining assets, the Torrance Acquisition included a number of high-quality logistics assets consisting of a sophisticated network of crude and products pipelines, product distribution terminals and refinery crude and product storage facilities. The most significant of the logistics assets is a 189-mile crude gathering and transportation system which delivers San Joaquin Valley crude oil directly from the field to the refinery. Additionally, included in the transaction were several pipelines which provide access to sources of crude oil including the Ports of Long Beach and Los Angeles, as well as clean product outlets with a direct pipeline supplying jet fuel to the Los Angeles airport. The Torrance refinery also has crude and product storage facilities with approximately 8.6 million barrels of shell capacity.
The purchase price for the assets was approximately $521.4 million in cash after post-closing purchase price adjustments, plus final working capital of $450.6 million. The final purchase price and fair value allocation were completed as of June 30, 2017. During the measurement period, which ended in June 2017, adjustments were made to our preliminary fair value estimates related primarily to Property, plant and equipment and Other long-term liabilities reflecting the finalization of our assessment of the costs and duration of certain assumed pre-existing environmental obligations. The transaction was financed through a combination of cash on hand, including proceeds from certain equity offerings, and borrowings under our Revolving Loan.
PBF Energy Inc. Public Offerings
As a result of the initial public offering and related reorganization transactions, PBF Energy became the sole managing member of PBF LLC with a controlling voting interest in PBF LLC and its subsidiaries. Effective with completion of the initial public offering, PBF Energy consolidates the financial results of PBF LLC and its subsidiaries and records a noncontrolling interest in its consolidated financial statements representing the economic interests of PBF LLC unit holders other than PBF Energy.
Additionally, a series of secondary offerings were made subsequent to our IPO whereby funds affiliated with The Blackstone Group L.P. (“Blackstone”) and First Reserve Management L.P. (“First Reserve”) sold their interests in us. The final such subsequent offering was completed on February 6, 2015, as funds affiliated with Blackstone and First Reserve exchanged 3,804,653 PBF LLC Series A units for the same number of shares of PBF Energy Class A common stock which were subsequently sold in a secondary public offering (the “February 2015 secondary offering” and collectively with the prior secondary offerings, the “secondary offerings”). As a result of these secondary offerings, Blackstone and First Reserve no longer hold any PBF LLC Series A units. The holders of PBF LLC Series B Units, which include certain current and former executive officers of PBF Energy, received a portion of the proceeds of the sales of the shares of PBF Energy Class A common stock by Blackstone and First Reserve in accordance with the amended and restated limited liability company agreement of PBF LLC. PBF Energy did not receive any proceeds from the secondary offerings.

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On October 13, 2015, we completed a public offering of an aggregate of 11,500,000 shares of Class A common stock, including 1,500,000 shares of Class A common stock that were sold pursuant to the exercise of an over-allotment option, for net proceeds of $344.0 million, after deducting underwriting discounts and commissions and other offering expenses (the “October 2015 Equity Offering”).
On December 19, 2016, we completed a public offering of an aggregate of 10,000,000 shares of Class A common stock for net proceeds of $274.3 million, after deducting underwriting discounts and commissions and other offering expenses (the “December 2016 Equity Offering”).
As of December 31, 2017, including the offerings described above, we own 110,586,762 PBF LLC Series C Units and our current and former executive officers and directors and certain employees and others beneficially own 3,767,464 PBF LLC Series A Units, and the holders of our issued and outstanding shares of Class A common stock have 96.7% of the voting power in us and the members of PBF LLC other than PBF Energy through their holdings of Class B common stock have the remaining 3.3% of the voting power in us.
PBFX Equity Offerings
On April 5, 2016, PBFX completed a public offering of an aggregate of 2,875,000 common units, including 375,000 common units that were sold pursuant to the full exercise by the underwriter of its option to purchase additional common units, for net proceeds of $51.6 million, after deducting underwriting discounts and commissions and other offering expenses. In addition, on August 17, 2016, PBFX completed a public offering of an aggregate of 4,000,000 common units, and granted the underwriter an option to purchase an additional 600,000 common units, of which 375,000 units were subsequently purchased on September 14, 2016, for total net proceeds of $86.8 million, after deducting underwriting discounts and commissions and other offering expenses. As a result of the PBFX equity offerings, as of December 31, 2017, PBF LLC holds a 44.1% limited partner interest in PBFX and owns all of PBFX’s IDRs, with the remaining 55.9% limited partner interest owned by public common unit holders.
Chalmette Acquisition
On November 1, 2015, we acquired from ExxonMobil Oil Corporation, Mobil Pipe Line Company and PDV Chalmette, Inc., 100% of the ownership interests of Chalmette Refining, which owns the Chalmette refinery and related logistics assets. The Chalmette refinery, located outside of New Orleans, Louisiana, is a dual-train coking refinery and is capable of processing both light and heavy crude oil. Subsequent to the closing of the Chalmette Acquisition, Chalmette Refining is a wholly-owned subsidiary of PBF Holding.
Chalmette Refining owns 100% of the MOEM Pipeline, providing access to the Empire Terminal, as well as the CAM Connection Pipeline, providing access to the Louisiana Offshore Oil Port facility through a third party pipeline. Chalmette Refining also owns 80% of each of the Collins Pipeline Company and T&M Terminal Company, both located in Collins, Mississippi, which provide a clean products outlet for the refinery to the Plantation and Colonial Pipelines. Also included in the acquisition are a marine terminal capable of importing waterborne feedstocks and loading or unloading finished products; a clean products truck rack which provides access to local markets; and a crude and product storage facility.
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 finalized in the first quarter of 2016. The transaction was financed through a combination of cash on hand and borrowings under our Revolving Loan.
PBFX Assets and Drop-Down Transactions
PBFX’s assets consist of the DCR Rail Terminal, the Toledo Truck Terminal, the DCR West Rack, the Toledo Storage Facility, the DCR Products Pipeline and Truck Rack, the East Coast Terminals (as defined below), the Torrance Valley Pipeline, PNGPC, the Toledo Products Terminal and the Chalmette Storage Tank. Apart from the East Coast Terminals, PBFX’s revenue is derived from long-term, fee-based commercial agreements with subsidiaries of PBF Energy, which include minimum volume commitments, for receiving, handling, transferring and storing crude oil, refined products and natural gas. These transactions are eliminated by PBF Energy in consolidation.
Since the inception of PBFX in 2014, PBF LLC and PBFX have entered into a series of drop-down transactions. Such transactions and third party acquisitions made by PBFX occurring in the three years ended December 31, 2017 are discussed below.

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On May 14, 2015, PBFX acquired from PBF LLC all of the issued and outstanding limited liability company interests of Delaware Pipeline Company LLC and Delaware City Logistics Company LLC, whose assets consist of the DCR Products Pipeline and Truck Rack.
On April 29, 2016, PBFX’s wholly-owned subsidiary, PBF Logistics Products Terminals LLC, completed the purchase of the four refined products terminals in the greater Philadelphia region (the “East Coast Terminals”) from an affiliate of Plains All American Pipeline, L.P.
On August 31, 2016, PBFX acquired from PBF LLC 50% of the issued and outstanding limited liability company interests of TVPC, whose assets consist of the Torrance Valley Pipeline.
On February 15, 2017, PBFX entered into the PNGPC Contribution Agreement between PBFX and PBF LLC, pursuant to which PBFX Op Co acquired from PBF LLC all of the issued and outstanding limited liability company interests of PNGPC. PNGPC owns and operates an existing interstate natural gas pipeline. In August 2017, PBFX Op Co completed the construction of a new pipeline which replaced the existing pipeline and commenced services.
On February 15, 2017, we entered into the Chalmette Storage Services Agreement under which PBFX, through PBFX Op Co, assumed construction of the Chalmette Storage Tank. The Chalmette Storage Tank commenced operations in November 2017 upon completion of construction.
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 million in RINs costs during the year ended December 31, 2017 as compared to $347.5 million and $171.6 million during the years ended December 31, 2016 and 2015, 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.
Amended and Restated Asset Based Revolving Credit Facility
On an ongoing basis, the Revolving Loan is available to be used for working capital and other general corporate purposes. On August 15, 2014, the agreement was amended and restated to, among other things, increase the maximum availability to $2.50 billion and extend its maturity to August 2019. The commitment fee on the unused portion, the interest rate on advances and the fees for letters of credit were reduced as part of the amendment. The amended and restated Revolving Loan includes an accordion feature which allows for aggregate commitments of up to $2.75 billion. In November and December 2015, PBF Holding increased the maximum availability under the Revolving Loan to $2.60 billion and $2.64 billion, respectively, in accordance with its accordion feature.
As noted in “Note 4 - Acquisitions” of our Notes to the Consolidated Financial Statements, we drew down under our Revolving Loan to partially fund the Torrance Acquisition. The outstanding balance under our Revolving Loan was $350.0 million as of December 31, 2017 and December 31, 2016, respectively.
2023 Senior Notes Offering
On November 24, 2015, PBF Holding and PBF Finance Corporation issued $500.0 million in aggregate principal amount of the 2023 Senior Notes. The net proceeds were approximately $490.0 million after deducting the initial purchasers’ discount and offering expenses. We used the proceeds to fund general corporate purposes, including a portion of the purchase price for the Torrance Acquisition.
2025 Senior Notes Offering
On May 30, 2017, PBF Holding and PBF Finance issued $725.0 million, in aggregate, principal amount of the 2025 Senior Notes. The Company used the net proceeds of $711.6 million to fund the cash tender offer (the “Tender Offer”) for any and all of its outstanding 8.25% senior secured notes due 2020 (the “2020 Senior Secured Notes”), to pay the related redemption price and accrued and unpaid interest for any 2020 Senior Secured Notes that remained outstanding after the completion of the Tender Offer, and for general corporate purposes. As described in “Note 9 - Credit Facility and Debt”

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of our Notes to the Consolidated Financial Statements, upon the satisfaction and discharge of the 2020 Senior Secured Notes in connection with the closing of the Tender Offer and the redemption, the 2023 Senior Notes became unsecured and certain covenants were modified, as provided for in the indenture governing the 2023 Senior Notes and related documents.
PBF Rail Revolving Credit Facility
Effective March 25, 2014, PBF Rail Logistics Company LLC (“PBF Rail”), an indirect wholly-owned subsidiary of PBF Holding, entered into a $250.0 million secured revolving credit agreement (the “Rail Facility”), the primary purpose of which was to fund the acquisition by PBF Rail of crude tank cars (the “Eligible Railcars”) before December 2015.
As noted in “Note 9 - Credit Facility and Debt” of our Notes to the Consolidated Financial Statements, the Rail Facility was amended on two occasions in 2015 and 2016. On December 22, 2016, the Rail Facility was terminated and replaced with the PBF Rail Term Loan (as described below).
PBF Rail Term Loan
On December 22, 2016, PBF Rail entered into a $35.0 million term loan (the “PBF Rail Term Loan”) with a bank previously party to the Rail Facility. The PBF Rail Term Loan amortizes monthly over its five year term and bears interest at the one month LIBOR plus the margin as defined in the credit agreement. As security for the PBF Rail Term Loan, PBF Rail pledged, among other things: (i) certain Eligible Railcars; (ii) the Debt Service Reserve Account (as defined in the credit agreement); and (iii) PBF Holding’s member interest in PBF Rail. Additionally, the PBF Rail Term Loan contains customary terms, events of default and covenants for transactions of this nature. PBF Rail may at any time repay the PBF Rail Term Loan without penalty in the event that railcars collateralizing the loan are sold, scrapped or otherwise removed from the collateral pool.
The outstanding balance of the PBF Rail Term Loan was $28.4 million and $35.0 million as of December 31, 2017 and December 31, 2016, respectively.
PBFX Debt and Credit Facilities
On May 14, 2014, in connection with the closing of the PBFX Offering, PBFX entered into the PBFX Revolving Credit Facility and a three-year, $300.0 million term loan facility (the “PBFX Term Loan”). The PBFX Revolving Credit Facility was increased from $275.0 million to $325.0 million in December 2014 and from $325.0 million to $360.0 million in May 2016. The PBFX Revolving Credit Facility is available to fund working capital, acquisitions, distributions and capital expenditures and for other general partnership purposes and is guaranteed by a guaranty of collection from PBF LLC. PBFX also has the ability to increase the maximum amount of the PBFX Revolving Credit Facility by an aggregate amount of up to $240.0 million, to a total facility size of $600.0 million, subject to receiving increased commitments from lenders or other financial institutions and satisfaction of certain conditions. The PBFX Revolving Credit Facility includes a $25.0 million sublimit for standby letters of credit and a $25.0 million sublimit for swingline loans. The PBFX Term Loan was used to fund distributions to PBF LLC and was guaranteed by a guaranty of collection from PBF LLC and secured at all times by cash, U.S. Treasury or other investment grade securities in an amount equal to or greater than the outstanding principal amount of the PBFX Term Loan.
Certain subsequent acquisitions made by PBFX were funded partially by proceeds from the sale of marketable securities. PBFX used borrowings under the PBFX Revolving Credit Facility to repay the outstanding PBFX Term Loan balance, and thereby release the marketable securities that had collateralized the PBFX Term Loan. The PBFX Term Loan was repaid in 2017.
On May 12, 2015, PBFX entered into an indenture among the Partnership, PBF Logistics Finance Corporation, a Delaware corporation and wholly-owned subsidiary of PBFX (“PBF Logistics Finance,” and together with PBFX, the “Issuers”), the Guarantors named therein (certain subsidiaries of PBFX) and Deutsche Bank Trust Company Americas, as Trustee, under which the Issuers issued $350.0 million in aggregate principal amount of the 6.875% senior notes due 2023 (the “initial PBFX 2023 Senior Notes”). PBF LLC provided a limited guarantee of collection of the principal amount of the PBFX 2023 Senior Notes (as defined below), but is not otherwise subject to the covenants of the indenture. After deducting offering expenses, PBFX received net proceeds of approximately $343.0 million from the initial PBFX 2023 Senior Notes offering.
On October 6, 2017, PBFX issued $175.0 million in aggregate principal amount of 6.875% Senior Notes due 2023 (the “new PBFX 2023 Senior Notes” and, together with the initial PBFX 2023 Senior Notes, the “PBFX 2023 Senior Notes”). The new PBFX 2023 Senior Notes were issued at 102% of face value with an effective rate of 6.442% and were

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issued under the indenture governing the initial PBFX 2023 Senior Notes dated on May 12, 2015. The new PBFX 2023 Senior Notes are expected to be treated as a single series with the initial PBFX 2023 Senior Notes and have the same terms as those initial notes except that (i) the new PBFX 2023 Senior Notes are subject to a separate registration rights agreement and (ii) the new PBFX 2023 Senior Notes were issued initially under CUSIP numbers different from the initial PBFX 2023 Senior Notes. PBFX used the net proceeds from the offering of the new PBFX 2023 Senior Notes to repay a portion of the PBFX Revolving Credit Facility and for general capital purposes.
As of December 31, 2017 and December 31, 2016, there were $528.4 million and $350.0 million outstanding under the PBFX 2023 Senior Notes, respectively.
Inventory Intermediation Agreements
On certain dates subsequent to the inception of the Inventory Intermediation Agreements, we and our subsidiaries, DCR and PRC, entered into amendments to the amended and restated inventory intermediation agreement (as amended, the “A&R Intermediation Agreements”) 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 was on September 8, 2017 which extends the term of the A&R Intermediation Agreement relating to DCR and PRC to July 1, 2019 and December 31, 2019, respectively, which terms may be further extended by mutual consent of the parties to July 1, 2020 and December 31, 2020, respectively.
Pursuant to each A&R Intermediation Agreement, J. Aron continues to purchase and hold title to certain of the intermediate and finished products produced by the Paulsboro and Delaware City refineries, respectively, and delivered into tanks at the Refineries. Furthermore, J. Aron agrees to sell the Products back to Paulsboro refinery and Delaware City refinery as the Products are discharged out of the refineries’ tanks. J. Aron has the right to store the products purchased in tanks under the A&R Intermediation Agreements and will retain these storage rights for the term of the agreements. PBF Holding continues to market and sell the products independently to third parties.
Crude Oil Acquisition Agreements
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 refinery. We have a contract with Saudi Aramco pursuant to which we have been purchasing up to approximately 100,000 bpd of crude oil from Saudi Aramco that is processed at our Paulsboro refinery. Prior to December 31, 2015, we had a crude oil supply contract with a third-party for our Delaware City refinery. We currently fully source our own crude oil needs for our Toledo refinery. Prior to July 31, 2014, we had a crude oil acquisition agreement with a third party that expired on July 31, 2014. In connection with the Chalmette Acquisition we entered into a contract with PDVSA for the supply of 40,000 to 60,000 bpd of crude oil that can be processed at any of our East or Gulf Coast refineries. We have not sourced crude oil under this agreement since the third quarter of 2017 as PDVSA has suspended deliveries due to the parties’ inability to agree to mutually acceptable payment terms. In connection with the closing of the Torrance Acquisition, we entered into a crude supply agreement with ExxonMobil for approximately 60,000 bpd of crude oil that can be processed at our Torrance refinery.
Tax Receivable Agreement
In connection with our initial public offering, we entered into a Tax Receivable Agreement pursuant to which we are required to pay the members of PBF LLC, who exchange their units for PBF Energy Class A common stock or whose units we purchase, approximately 85% of the cash savings in income taxes that we realize as a result of the increase in the tax basis of our interest in PBF LLC, including tax benefits attributable to payments made under the Tax Receivable Agreement. We have recognized, as of December 31, 2017, a liability for the Tax Receivable Agreement of $362.1 million, reflecting our estimate of the undiscounted amounts that we expect to pay under the agreement due to exchanges including those in connection with our IPO and our secondary offerings. Our estimate of the Tax Receivable Agreement liability is based, in part, on forecasts of future taxable income over the anticipated life of our future business operations, assuming no material changes in the relevant tax law. Periodically, we may adjust the liability based, in part, on an updated estimate of the amounts that we expect to pay, using assumptions consistent with those used in our concurrent estimate of the deferred tax asset valuation allowance. For example, we must adjust the estimated Tax Receivable Agreement liability each time we purchase PBF LLC Series A Units or upon an exchange of PBF LLC Series A Units for our Class A common stock. These periodic adjustments to the tax receivable liability, if any, are recorded in general and administrative expense and may result in adjustments to our income tax expense and deferred tax assets and liabilities. As a result of the reduction of the corporate tax rate to 21% as part of the TCJA, the liability associated with the Tax Receivable Agreement was reduced. Accordingly, the deferred tax assets associated with the payments made or expected to be made were also reduced.

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Share Repurchase Program
Our Board of Directors authorized the repurchase of up to $300.0 million of our Class A common stock. On September 26, 2016, our Board of Directors approved a two year extension to the existing Repurchase Program. As a result of the extension, the Repurchase Program will expire on September 30, 2018. No repurchases of our Class A common stock were made during the year ended December 31, 2017. As of December 31, 2017 we have purchased approximately 6.05 million shares of our Class A common stock under the Repurchase Program for $150.8 million through open market transactions. We currently have the ability to purchase approximately an additional $149.2 million in common stock under the approved Repurchase Program.
These repurchases may be made from time to time through various methods, including open market transactions, block trades, accelerated share repurchases, privately negotiated transactions or otherwise, certain of which may be effected through Rule 10b5-1 and Rule 10b-18 plans. The timing and number of shares repurchased will depend on a variety of factors, including price, capital availability, legal requirements and economic and market conditions. We are not obligated to purchase any shares under the Repurchase Program, and repurchases may be suspended or discontinued at any time without prior notice.
Factors Affecting Operating Results
Overview
Our earnings and cash flows from operations are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks. The cost to acquire crude oil and other feedstocks and the price of refined petroleum products ultimately sold depends on numerous factors beyond our control, including the supply of, and demand for, crude oil, gasoline, diesel and other refined petroleum products, which, in turn, depend on, among other factors, changes in global and regional economies, weather conditions, global and regional political affairs, production levels, the availability of imports, the marketing of competitive fuels, pipeline capacity, prevailing exchange rates and the extent of government regulation. Our revenue and operating income 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, international political and economic developments and other factors beyond our control are likely to continue to play an important role in refining industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction or increase in product margins. Moreover, the industry typically experiences seasonal fluctuations in demand for refined petroleum products, such as for gasoline and diesel, during the summer driving season and for home heating oil during the winter.
Benchmark Refining Margins
In assessing our operating performance, we compare the refining margins (revenue less materials cost) of each of our refineries against a specific benchmark industry refining margin based on crack spreads. Benchmark refining margins take into account both crude and refined petroleum product prices. When these prices are combined in a formula they provide a single value—a gross margin per barrel—that, when multiplied by throughput, provides an approximation of the gross margin generated by refining activities.
The performance of our East Coast refineries generally follows the Dated Brent (NYH) 2-1-1 benchmark refining margin. Our Toledo refinery generally follows the WTI (Chicago) 4-3-1 benchmark refining margin. Our Chalmette refinery generally follows the LLS (Gulf Coast) 2-1-1 benchmark refining margin. Our Torrance refinery generally follows the ANS (West Coast) 4-3-1 benchmark refining margin.
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

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activities. As discussed in more detail below, each of our refineries, depending on market conditions, has certain feedstock-cost and product-value advantages and disadvantages as compared to the refinery’s relevant benchmark.
Credit Risk Management
Credit risk refers to the risk that a counterparty will default on its contractual obligations resulting in financial loss to us. Our exposure to credit risk is reflected in the carrying amount of the receivables that are presented in our balance sheet. 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.
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. 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 City 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.
In the past several years, we expanded and upgraded the existing on-site railroad infrastructure at the Delaware City refinery. Currently, crude oil delivered by rail to this facility is consumed at our Delaware City and Paulsboro refineries. The Delaware City rail unloading facility, which was sold to PBFX in 2014, allows 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, which has leased the railcars back to us for periods of between four and seven years. In 2016, we sold approximately 120 of these 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.
Refinery-Specific Information
The following section includes refinery-specific information related to our operations, crude oil differentials, ancillary costs, and local premiums and discounts.
Delaware City Refinery. The benchmark refining margin for the Delaware City refinery is calculated by assuming that two barrels of Dated Brent crude oil are converted into one barrel of gasoline and one barrel of diesel. We calculate this benchmark using the NYH market value of reformulated blendstock for oxygenate blending (“RBOB”) and ultra-low sulfur diesel (“ULSD”) against the market value of Dated Brent and refer to the benchmark as the Dated Brent (NYH) 2-1-1 benchmark refining margin. Our Delaware City refinery has a product slate of approximately 53% gasoline, 30% distillate, 2% high-value petrochemicals, with the remaining portion of the product slate comprised of lower-value products (6% black oil, 4% petroleum coke, 3% LPGs and 2% other). For this reason, we believe the Dated Brent (NYH) 2-1-1 is an appropriate benchmark industry refining margin. The majority of Delaware City revenues are generated off NYH-based market prices.

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The Delaware City refinery’s realized gross margin on a per barrel basis has historically differed from the Dated Brent (NYH) 2-1-1 benchmark refining margin due to the following factors:
the Delaware City refinery processes a slate of primarily medium and heavy sour crude oils, which has constituted approximately 55% to 65% 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, 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.
Paulsboro Refinery. The benchmark refining margin for the Paulsboro refinery is calculated by assuming that two barrels of Dated Brent crude oil are converted into one barrel of gasoline and one barrel of diesel. We calculate this benchmark using the NYH market value of RBOB and ULSD diesel against the market value of Dated Brent and refer to the benchmark as the Dated Brent (NYH) 2-1-1 benchmark refining margin. Our Paulsboro refinery has a product slate of approximately 39% gasoline, 33% distillate, 5% high-value Group I lubricants and 10% asphalt, with the remaining portion of the product slate comprised of lower-value products (5% black oil, 3% petroleum coke, 4% LPGs and 1% other). For this reason, we believe the Dated Brent (NYH) 2-1-1 is an appropriate benchmark industry refining margin. The majority of Paulsboro revenues are generated off NYH-based market prices.
The Paulsboro refinery’s realized gross margin on a per barrel basis has historically differed from the Dated Brent (NYH) 2-1-1 benchmark refining margin due to the following factors:
the Paulsboro refinery processes a slate of primarily medium and heavy sour crude oils, which has historically constituted approximately 75% to 85% of total throughput. The remaining throughput consists of sweet crude oil and other feedstocks and blendstocks;
as a result of the heavy, sour crude slate processed at Paulsboro, we produce lower value products including sulfur and petroleum coke. These products are priced at a significant discount to RBOB and ULSD and represent approximately 3% to 5% of our total production volume; and
the Paulsboro refinery produces Group I lubricants which carry a premium sales price to RBOB and ULSD.
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”) and ULSD and the United States Gulf Coast value of jet fuel against the market value of WTI and refer to this benchmark as the WTI (Chicago) 4-3-1 benchmark refining margin. Our Toledo refinery has a product slate of approximately 54% gasoline, 34% distillate, 6% high-value petrochemicals (including nonene, tetramer, benzene, xylene and toluene) with the remaining portion of the product slate comprised of lower-value products (5% LPGs and 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 than the market value of WTI crude oil;
the Toledo refinery configuration enables it to produce more barrels of product than throughput which generates a pricing benefit; and
the Toledo refinery generates a pricing benefit on some of its refined products, primarily its petrochemicals.
Chalmette Refinery. The benchmark refining margin for the Chalmette refinery is calculated by assuming two barrels of Light Louisiana Sweet (“LLS”) 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% gasoline, 32% distillate, 3% high-value petrochemicals (including benzene and xylenes) with the remaining portion of the product slate comprised of lower-value products (10% black oil, 5% petroleum

69



coke and 3% other). For this reason, we believe the LLS (Gulf Coast) 2-1-1 is an appropriate benchmark industry refining margin. The majority of Chalmette revenues are generated off Gulf Coast-based market prices.
The Chalmette refinery’s realized gross margin on a per barrel basis has historically differed from the LLS (USGC) 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% to 65% 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.
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.
Torrance Refinery. The benchmark refining margin for the Torrance refinery is calculated by assuming that four barrels of Alaskan North Slope (“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), California Air Resources Board (CARB) diesel and jet fuel and refer to the benchmark as the ANS (WCLA) 4-3-1 benchmark refining margin. Our Torrance refinery has a product slate of approximately 64% gasoline and 22% distillate with the remaining portion of the product slate comprised of lower-value products (9% petroleum coke, 2% LPG, 1% black oil and 2% 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) 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”) 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 and represent approximately 9% to 11% of our total production volume.
Change in Presentation
During 2017, we determined that we will revise the presentation of certain line items on our historical consolidated statements of operations to enhance our disclosure under the requirements of Rule 5-03 of Regulation S-X. The revised presentation is comprised of the inclusion of a subtotal within operating costs and expenses referred to as “Cost of sales” and the reclassification of total depreciation and amortization expense between such amounts attributable to cost of sales 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.
As described in “Note 2 - Summary of Significant Accounting Policies” of our Notes to the Consolidated Financial Statements, the historical comparative information has been revised to conform to the current presentation. This revised presentation does not have an effect on our historical consolidated income from operations or net income, nor does it have any impact on our consolidated balance sheets, statements of comprehensive income, statements of changes in equity and statements of cash flows.


70



Results of Operations
The tables below reflect our consolidated financial and operating highlights for the years ended December 31, 2017, 2016 and 2015 (amounts in thousands, except per share data). We operate in two reportable business segments: Refining and Logistics. Our oil refineries, excluding the assets owned by PBFX, are all engaged in the refining of crude oil and other feedstocks into petroleum products, and are aggregated into the Refining segment. PBFX is a publicly traded master limited partnership that operates certain logistical assets such as crude oil and refined petroleum products terminals, pipelines and storage facilities. PBFX’s operations are aggregated into the Logistics segment. We do not separately discuss our results by individual segments as, apart from the East Coast Terminals, our Logistics segment did not have any significant third party revenue and a significant portion of its operating results eliminate in consolidation.
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Revenue
 
$
21,786,637

 
$
15,920,424

 
$
13,123,929

 
 
 
 
 
 
 
Cost and expenses:
 
 
 
 
 
 
Cost of products and other
 
18,863,621

 
13,598,341

 
11,481,614

Operating expenses (excluding depreciation and amortization expense as reflected below)
 
1,685,611

 
1,423,198

 
904,525

Depreciation and amortization expense
 
277,992

 
216,341

 
187,729

Cost of sales
 
20,827,224

 
15,237,880

 
12,573,868

General and administrative expenses (excluding depreciation and amortization expense as reflected below)
 
214,773

 
166,452

 
181,266

Depreciation and amortization expense
 
12,964

 
5,835

 
9,688

Loss (gain) on sale of assets
 
1,458

 
11,374

 
(1,004
)
Total cost and expenses
 
21,056,419

 
15,421,541

 
12,763,818

Income from operations
 
730,218

 
498,883

 
360,111

Other income (expense):
 
 
 
 
 
 
Change in Tax Receivable Agreement liability
 
250,922

 
12,908

 
18,150

Change in fair value of catalyst leases
 
(2,247
)
 
1,422

 
10,184

Debt extinguishment costs
 
(25,451
)
 

 

Interest expense, net
 
(154,427
)
 
(150,045
)
 
(106,187
)
Income before income taxes
 
799,015

 
363,168

 
282,258

Income tax expense
 
315,584

 
137,650

 
86,725

Net income
 
483,431

 
225,518

 
195,533

Less: net income attributable to noncontrolling interest
 
67,914

 
54,707

 
49,132

Net income attributable to PBF Energy Inc. stockholders
 
$
415,517

 
$
170,811

 
$
146,401

 
 
 
 
 
 
 
Gross margin
 
$
1,041,129

 
$
727,496

 
$
571,524

 
 
 
 
 
 
 
Gross refining margin (1)
 
2,676,651

 
2,143,449

 
1,512,330

 
 
 
 
 
 
 
Net income available to Class A common stock per share:
 
 
 
 
 
 
Basic
 
$
3.78

 
$
1.74

 
$
1.66

Diluted
 
$
3.73

 
$
1.74

 
$
1.65

——————————
(1) See Non-GAAP Financial Measures below.

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Operating Highlights
 
 
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
 
$
3.53

 
$
2.73

 
$
3.03

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.

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The table below summarizes certain market indicators relating to our operating results as reported by Platts.
 
 
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

 
2017 Compared to 2016
Overview— Net income was $483.4 million for the year ended December 31, 2017 compared to $225.5 million for the year ended December 31, 2016. Net income attributable to PBF Energy stockholders was $415.5 million, or $3.73 per diluted share, for the year ended December 31, 2017 ($3.73 per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income, or net income of $1.14 per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income excluding special items, as described below in Non-GAAP Financial Measures) compared to net income attributable to PBF Energy stockholders of $170.8 million, or $1.74 per diluted share, for the year ended December 31, 2016 ($1.74 per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income, or a net loss of $1.41 per share on a fully exchanged, fully-diluted basis based on adjusted fully-converted net loss excluding special items, as described below in Non-GAAP Financial Measures). The net income or loss attributable to PBF Energy represents PBF Energy’s equity interest in PBF LLC’s pre-tax income (loss), less applicable income tax expense. PBF Energy’s weighted-average equity interest in PBF LLC was 96.6% and 95.3% for the years ended December 31, 2017 and 2016, respectively.
Our results for the year ended December 31, 2017 were positively impacted by special items including a pre-tax non-cash LCM inventory adjustment of approximately $295.5 million, or $178.5 million net of tax, and a pre-tax benefit of $250.9 million, or $151.5 million net of tax, related to the change in our Tax Receivable Agreement liability. Our results for the year ended December 31, 2016 were positively impacted by special items consisting of a pre-tax LCM inventory adjustment of approximately $521.3 million, or $317.7 million net of tax, and a pre-tax benefit of $12.9 million, or $7.9 million net of tax related to the change in our Tax Receivable Agreement liability. Our results for the year ended December 31, 2017 were also impacted by special items related to pre-tax debt extinguishment costs of $25.5 million, or $15.4 million net of tax related to the redemption of the 2020 Senior Secured Notes and the enactment of the Tax Cuts and Jobs Act (the “TCJA”) resulting in a net tax expense of $193.5 million associated with the remeasurement of Tax Receivable Agreement associated deferred tax assets and a net tax benefit of $173.3 million for the reduction of our deferred tax liabilities.

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Excluding the impact of these special items, our results were positively impacted by higher throughput volumes at the majority of our refineries and higher crack spreads realized at each of our refineries, which 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 lower costs to comply with the RFS. Notably, we benefited from the improved operating performance of our Chalmette and Torrance refineries.
Revenues— Revenues totaled $21.8 billion for the year ended December 31, 2017 compared to $15.9 billion for the year ended December 31, 2016, an increase of approximately $5.9 billion or 36.8%. Revenues per barrel were $64.90 and $59.77 for the years ended December 31, 2017 and 2016, respectively, an increase of 8.6% directly related to higher hydrocarbon commodity prices. For the year ended December 31, 2017, the total throughput rates at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 338,200 bpd, 145,200 bpd, 184,500 bpd and 139,500 bpd, respectively. For the year ended December 31, 2016, the total throughput rates at our 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. The throughput rates at our East Coast and Gulf Coast refineries were higher in 2017 compared to 2016. Our West Coast refinery was not acquired until the beginning of the third quarter of 2016. The decrease in throughput rates at our West Coast refinery in 2017 compared to 2016 is primarily due to planned downtime at our Torrance refinery for its first significant turnaround under our ownership, which was completed early in the third quarter of 2017. However, our West Coast refinery throughput averaged 164,000 bpd for the last six months of the year upon completion of the turnaround. For the year ended December 31, 2017, the total refined product barrels sold at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 363,800 bpd, 160,400 bpd, 227,200 bpd and 168,300 bpd, respectively. For the year ended December 31, 2016, the total refined product barrels sold at our East Coast, Mid-Continent and Gulf Coast refineries averaged approximately 364,100 bpd, 171,800 bpd and 206,400 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 179,200 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.
Gross Margin— Gross margin, including refinery operating expenses and depreciation, totaled $1,041.1 million, or $3.53 per barrel of throughput, for the year ended December 31, 2017, compared to $727.5 million, or $2.73 per barrel of throughput, for the year ended December 31, 2016, an increase of $313.6 million. Gross refining margin (as defined below in Non-GAAP Financial Measures) totaled $2,676.7 million, or $9.08 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, 2017 compared to $2,143.4 million, or $8.05 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 increase of approximately $533.2 million or an increase of $759.0 million excluding special items.
Excluding the impact of special items, gross margin and gross refining margin increased due to improved crack spreads across each of our refineries, reduced costs to comply with the RFS and positive margin contributions from our Torrance refinery following its first significant turnaround under our ownership, which was completed early in the third quarter of 2017. Costs to comply with our obligation under the RFS totaled $255.2 million for the year ended December 31, 2017 (excluding our West Coast refinery, whose cost to comply with RFS totaled $38.5 million for the year ended December 31, 2017) compared to $325.3 million for the year ended December 31, 2016 (excluding our West Coast refinery, whose costs to comply with RFS totaled $22.2 million for the year ended December 31, 2016). In addition, gross margin and gross refining margin were positively impacted by a non-cash LCM inventory adjustment of approximately $295.5 million on a net basis resulting from an increase in crude oil and refined product prices in comparison to the prices at the end of 2016. The non-cash LCM inventory adjustment increased gross margin and gross refining margin by approximately $521.3 million in the year ended December 31, 2016.
Average industry refining margins in the Mid-Continent were stronger during the year ended December 31, 2017, as compared to the same period in 2016. The WTI (Chicago) 4-3-1 industry crack spread was $15.88 per barrel, or 28.3% higher, in the year ended December 31, 2017, as compared to $12.38 per barrel in the same period in 2016. Our margins were unfavorably impacted by our refinery specific crude slate in the Mid-Continent which was impacted by a declining WTI/Bakken differential partially offset by an improving WTI/Syncrude differential, which averaged a 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.
On the East Coast, the Dated Brent (NYH) 2-1-1 industry crack spread was approximately $14.74 per barrel, or 9.3% higher, in the year ended December 31, 2017 as compared to $13.49 per barrel in the same period in 2016. The Dated Brent/WTI differential was $2.83 higher in the year ended December 31, 2017, as compared to the same period in 2016, partially offset by year over year decreases in the Dated Brent/Maya differential and WTI/Bakken differential of $0.20 and $1.58, respectively.

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Gulf Coast industry refining margins improved during the year ended December 31, 2017 as compared to the same period in 2016. The LLS (Gulf Coast) 2-1-1 industry crack spread was $13.57 per barrel, or 26.2% higher, in the year ended December 31, 2017 as compared to $10.75 per barrel in the same period in 2016. Crude differentials weakened with the WTI/LLS differential averaging a premium of $3.23 per barrel during the year ended December 31, 2017 as compared to a premium of $1.69 per barrel in the same period of 2016.
Additionally, we benefited from improvements in the West Coast industry refining margins during the year ended December 31, 2017 as compared to the same period in 2016. The ANS (West Coast) 4-3-1 industry crack spread was $17.43 per barrel, or 5.9% higher, in the year ended December 31, 2017 as compared to $16.46 per barrel in the same period in 2016. Partially offsetting the improved crack spreads, crude differentials weakened with the WTI/ANS differential averaging a premium of $3.63 per barrel during the year ended December 31, 2017 as compared to a premium of $0.33 per barrel in the same period of 2016. As the Torrance refinery was not acquired until the beginning of the third quarter of 2016, we did not benefit from the contribution of this refinery for the full twelve months of the prior year.
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 $1,685.6 million for the year ended December 31, 2017 compared to $1,423.2 million for the year ended December 31, 2016, an increase of $262.4 million, or 18.4%. Of the total $1,685.6 million of operating expenses, approximately $1,627.6 million, or $5.52 per barrel of throughput, related to expenses incurred by the Refining segment, while the remaining $58.0 million related to expenses incurred by the Logistics segment ($1,390.6 million or $5.22 per barrel, and $32.6 million of operating expenses for the year ended December 31, 2016 related to the Refining and Logistics segment, respectively). The increase in operating expenses was mainly attributable to the operating expenses associated with our Torrance refinery and related logistics 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 of approximately $475.9 million in comparison to $250.5 million for the period from its acquisition on July 1, 2016 to December 31, 2016. Total operating expenses at our refineries, excluding our Torrance refinery, increased slightly for the year ended December 31, 2017, primarily due to higher energy costs and maintenance costs. The increase in energy costs was mainly due to higher natural gas prices while the increase in maintenance costs was mainly due to timing of repairs. The operating expenses related to the Logistics segment consists of costs related to the operation and maintenance of PBFX’s assets, which were higher primarily as a result of current period expenses related to certain assets including the Toledo Products Terminal and Torrance Valley Pipeline, which were not in service for the full comparable period in 2016, and higher operating expenses associated with the East Coast Terminals.
General and Administrative Expenses— General and administrative expenses totaled $214.8 million for the year ended December 31, 2017, compared to $166.5 million for the year ended December 31, 2016, an increase of $48.3 million or 29.0%. The increase in general and administrative expenses primarily relates to increased employee related expenses of $58.2 million driven by higher incentive compensation costs in the year ended December 31, 2017 as compared to the same period in 2016, attributable to higher average employee headcount and better operating performance. These increases were partially offset by lower costs associated with acquisition and integration related activities which were approximately $8.6 million lower in the year ended December 31, 2017 as compared to the same period in 2016. Our general and administrative expenses are comprised of the personnel, facilities and other infrastructure costs necessary to support our refineries and related logistical assets.
Loss (gain) on Sale of Assets— There was a loss of $1.5 million on sale of assets for the year ended December 31, 2017 relating to non-operating refinery assets. There was a loss of $11.4 million for the year ended December 31, 2016 relating to the sale of non-operating refining assets.
Depreciation and Amortization Expense— Depreciation and amortization expense totaled $291.0 million for the year ended December 31, 2017 (including $278.0 million recorded within Cost of sales) compared to $222.2 million for the year ended December 31, 2016 (including $216.3 million recorded within Cost of sales), an increase of $68.8 million. The increase was a result of additional depreciation expense associated with the assets acquired in the Torrance Acquisition and a general increase in our fixed asset base due to capital projects and turnarounds completed during 2017 and 2016.
Change in Tax Receivable Agreement LiabilityChange in the Tax Receivable Agreement liability for the year ended December 31, 2017 represented a gain of $250.9 million as compared to a gain of $12.9 million for the year ended December 31, 2016. This gain was primarily a result of the TCJA enacted in December 2017 and related remeasurement of the liability based on the decrease in the federal tax rate from 35% to 21%.

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Change in Fair Value of Catalyst Leases— Change in the fair value of catalyst leases represented a loss of $2.2 million for the year ended December 31, 2017, compared to a gain of $1.4 million for the year ended December 31, 2016. 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, which we are obligated to return or repurchase at fair market value on the lease termination dates.
Debt extinguishment costs— Debt extinguishment costs of $25.5 million incurred in the year ended December 31, 2017 relate to nonrecurring charges associated with debt refinancing activity calculated based on the difference between the carrying value of the 2020 Senior Secured Notes on the date that they were reacquired and the amount for which they were reacquired. There were no such costs in the same period of 2016.
Interest Expense, net— Interest expense totaled $154.4 million for the year ended December 31, 2017, compared to $150.0 million for the year ended December 31, 2016, an increase of $4.4 million. This net increase is attributable to higher average borrowings under our Revolving Loan partially offset by lower interest expense on a portion of our senior notes that were refinanced in May 2017 (see “Note 9 - Credit Facility and Debt” of our Notes to the Consolidated Financial Statements, for additional details). Interest expense includes interest on long-term debt including the PBFX credit facilities, costs related to the sale and leaseback of our precious metals catalyst, financing costs associated with the A&R 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— PBF LLC is organized as a limited liability company and PBFX is a master limited partnership, both of which are treated as “flow-through” entities for federal income tax purposes and therefore are not subject to income tax. However, two subsidiaries of Chalmette Refining and one subsidiary of PBF Holding that are treated as C-Corporations for income tax purposes may incur income taxes with respect to their earnings, as applicable. The members of PBF LLC are required to include their proportionate share of PBF LLC’s taxable income or loss, which includes PBF LLC’s allocable share of PBFX’s pre-tax income or loss, on their respective tax returns. PBF LLC generally makes distributions to its members, per the terms of PBF LLC’s amended and restated limited liability company agreement, related to such taxes on a pro-rata basis. PBF Energy recognizes an income tax expense or benefit in our consolidated financial statements based on PBF Energy’s allocable share of PBF LLC’s pre-tax income or loss, which was approximately 96.6% and 95.3%, on a weighted-average basis for the years ended December 31, 2017 and 2016, respectively. PBF Energy’s consolidated financial statements do not reflect any benefit or provision for income taxes on the pre-tax income or loss attributable to the noncontrolling interests in PBF LLC or PBFX (although, as described above, PBF LLC must make tax distributions to all its members on a pro-rata basis). PBF Energy’s effective tax rate, including the impact of noncontrolling interest, for the years ended December 31, 2017 and 2016 was 39.5% and 37.9%, respectively, reflecting tax adjustments for discrete items and the impact of the TCJA which, among other things, reduced the U.S. federal corporate tax rate from 35% percent to 21% percent.
Noncontrolling Interests— PBF Energy is the sole managing member of, and has a controlling interest in, PBF LLC. As the sole managing member of PBF LLC, PBF Energy operates and controls all of the business and affairs of PBF LLC and its subsidiaries. PBF Energy consolidates the financial results of PBF LLC and its subsidiaries, including PBFX. With respect to the consolidation of PBF LLC, the Company records a noncontrolling interest for the economic interest in PBF LLC held by members other than PBF Energy, and with respect to the consolidation of PBFX, the Company records a noncontrolling interest for the economic interests in PBFX held by the public unit holders of PBFX, and with respect to the consolidation of PBF Holding, the Company records a 20% noncontrolling interest for the ownership interests in two subsidiaries of Chalmette Refining held by a third party. The total noncontrolling interest on the consolidated statement of operations represents the portion of the Company’s earnings or loss attributable to the economic interests held by members of PBF LLC other than PBF Energy and by the public common unit holders of PBFX and by the third party holder of certain of Chalmette Refining’s subsidiaries. The total noncontrolling interest on the balance sheet represents the portion of the Company’s net assets attributable to the economic interests held by the members of PBF LLC other than PBF Energy, by the public common unit holders of PBFX and by the third party stockholder of T&M Terminal Company and Collins Pipeline Company. PBF Energy’s weighted-average equity noncontrolling interest ownership percentage in PBF LLC for the years ended December 31, 2017 and 2016 was approximately 3.4% and 4.7%, respectively. The carrying amount of the noncontrolling interest on our consolidated balance sheet attributable to the noncontrolling interest is not equal to the noncontrolling interest ownership percentage due to the effect of income taxes and related agreements that pertain solely to PBF Energy.
2016 Compared to 2015
Overview—Net income for PBF Energy was $225.5 million for the year ended December 31, 2016 compared to $195.5 million for the year ended December 31, 2015. Net income attributable to PBF Energy stockholders was $170.8 million, or $1.74 per diluted share, for the year ended December 31, 2016 ($1.74 per share on a fully-exchanged, fully-

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diluted basis based on adjusted fully-converted net income, or a net loss of $1.41 per share on a fully-exchanged, fully- diluted basis based on adjusted fully-converted net loss excluding special items, as described below in Non-GAAP Financial Measures) compared to net income attributable to PBF Energy stockholders of $146.4 million, or $1.65 per diluted share, for the year ended December 31, 2015 ($1.65 per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income, or $4.27 net income per share on a fully-exchanged, fully-diluted basis based on adjusted fully-converted net income excluding special items, as described below in Non-GAAP Financial Measures). The net income or loss attributable to PBF Energy represents PBF Energy’s equity interest in PBF LLC’s pre-tax income (loss), less applicable income tax expense. PBF Energy’s weighted-average equity interest in PBF LLC was 95.3% and 94.0% for the years ended December 31, 2016 and 2015, respectively.
Our results for the year ended December 31, 2016 were positively impacted by a non-cash special item consisting of a pre-tax LCM inventory adjustment of approximately $521.3 million or $317.7 million net of tax, whereas our results for the year ended December 31, 2015 were negatively impacted by a pre-tax LCM inventory adjustment of approximately $427.2 million, or $258.0 million net of tax. These LCM inventory adjustments were recorded due to significant changes in the price of crude oil and refined products in the periods presented. Excluding the impact of the net change in LCM inventory reserve, our results were negatively impacted by unfavorable movements in certain crude oil differentials, lower crack spreads, increased costs to comply with the RFS, 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.
Revenues— Revenues totaled $15.9 billion for the year ended December 31, 2016 compared to $13.1 billion for the year ended December 31, 2015, an increase of approximately $2.8 billion, or 21.3%. Revenues per barrel were $59.77 and $69.66 for the years ended December 31, 2016 and 2015, respectively, a decrease of 14.2% directly related to lower hydrocarbon commodity prices. For the year ended December 31, 2016, the total throughput rates at our 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, the total throughput rates at our East Coast and Mid-Continent refineries averaged approximately 330,700 bpd and 153,800 bpd, respectively. For the period from its acquisition on November 1, 2015 through December 31, 2015, our Gulf Coast refinery’s throughput averaged 190,800 bpd. The slight decrease in throughput rates at our East Coast refineries in 2016 compared to 2015 is primarily due to weather-related 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 throughout rates at our Mid-Continent refinery in 2016 is due to unplanned downtime in the second quarter of 2015. Our Gulf Coast and West Coast refineries were not acquired until the fourth quarter of 2015 and third quarter of 2016, respectively. For the year ended December 31, 2016, the total refined product barrels sold at our East Coast, Mid-Continent and Gulf Coast refineries averaged approximately 364,100 bpd, 171,800 bpd and 206,400 bpd, respectively. For the period from its acquisition on July 1, 2016 through December 31, 2016, 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 refinery.
Gross Margin— Gross margin, including refinery operating expenses and depreciation, totaled $727.5 million, or $2.73 per barrel of throughput, for the year ended December 31, 2016, compared to $571.5 million, or $3.03 per barrel of throughput, for the year ended December 31, 2015, an increase of $156.0 million. Gross refining margin (as defined below in Non-GAAP Financial Measures) totaled $2,143.4 million, or $8.05 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 compared to $1,512.3 million, or $8.02 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 approximately $631.1 million or a decrease of approximately $317.5 million excluding special items.
Excluding the impact of special items, gross margin and gross refining margin decreased due to unfavorable movements in certain crude differentials, lower crack spreads as persistent above-average refined product inventory levels weighed on margins, and increased costs to comply with the RFS, partially offset by higher throughput rates in the Mid-Continent and positive margin contributions from the Chalmette and Torrance refineries acquired in the fourth quarter of 2015 and third quarter of 2016, respectively. Costs to comply with our obligation under the RFS totaled $236.2 million for the year ended December 31, 2016 (excluding our Gulf Coast and West Coast refineries, whose costs to comply with RFS totaled $111.3 million for the year ended December 31, 2016) compared to $163.6 million for the year ended December 31, 2015 (excluding our Gulf Coast refinery, 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

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inventory adjustment of approximately $521.3 million resulting from the change in crude oil and refined product prices from the year ended 2015 to the year ended 2016 which, while remaining below historical costs, increased since the prior year end. 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.
Average industry refining margins in the Mid-Continent were weaker during the year ended December 31, 2016, as compared to the same period in 2015. The WTI (Chicago) 4-3-1 industry crack spread was $12.38 per barrel or 30.9% lower, in the year ended December 31, 2016, as compared to $17.91 per barrel in the same period in 2015. Our margins were negatively impacted from our refinery specific crude slate in the Mid-Continent which was impacted by a declining WTI/Bakken differential and a declining WTI/Syncrude differential, which averaged a premium of $2.01 per barrel for the year ended December 31, 2016 as compared to a premium of $1.45 per barrel in the same period in 2015.
The Dated Brent (NYH) 2-1-1 industry crack spread was approximately $13.49 per barrel, or 17.5% lower, in the year ended December 31, 2016, as compared to $16.35 per barrel in the same period in 2015. The Dated Brent/WTI differential and Dated Brent/Maya differential were $3.29 and $1.09 lower, respectively, in the year ended December 31, 2016, as compared to the same period in 2015. In addition, the WTI/Bakken differential was approximately $1.57 per barrel less favorable in the year ended Dece