10-K 1 pbfholding-2016123110k.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, 2016
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 HOLDING COMPANY LLC
PBF FINANCE CORPORATION
(Exact name of registrant as specified in its charter)
 
DELAWARE
 
27-2198168
DELAWARE
 
45-2685067
 
 
 
(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: None.
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.  ¨Yes xNo
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 xNo
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. ¨ Yes    x No (Note: As of January 1, 2017, the registrant was no longer subject to the filing requirements of Section 13 or 15(d) of the Exchange Act other than with respect to this Form 10-K; however, the registrant filed all reports required to be filed during the period it was subject to Section 13 or 15(d) of the Exchange Act.)
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
 
¨
 
¨
 
x
 
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨  Yes    x  No
There is no trading in the membership interests of PBF Holding LLC or the common stock of PBF Finance Corporation and therefore an aggregate market value based on such is not determinable.
PBF Holding Company LLC has no common stock outstanding. As of March 8, 2017 100% of the membership interests of PBF Holding Company LLC were owned by PBF Energy Company LLC, and PBF Finance Corporation had 100 shares of common stock outstanding, all of which were held by PBF Holding Company LLC.
PBF Finance Corporation meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format.
DOCUMENTS INCORPORATED BY REFERENCE
PBF Energy Inc., the managing member of our direct parent PBF Energy Company LLC, will file with the Securities and Exchange Commission a definitive Proxy Statement for its 2017 Annual Meeting of Stockholders. Portions of the Proxy Statement of PBF Energy Inc. are incorporated by reference in Part III of this Form 10-K to the extent stated herein.
 




PBF HOLDING COMPANY LLC
TABLE OF CONTENTS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

Explanatory Note

This Form 10-K is filed by PBF Holding Company LLC (“PBF Holding”) and PBF Finance Corporation (“PBF Finance”). PBF Holding is a wholly-owned subsidiary of PBF Energy Company LLC (“PBF LLC”) and is the parent company for PBF LLC's refinery operating subsidiaries. PBF Finance is a wholly-owned subsidiary of PBF Holding. PBF Holding is an indirect subsidiary of PBF Energy Inc. (“PBF Energy”), which is the sole managing member of, and owner of an equity interest representing approximately 96.5% of the outstanding economic interests in PBF LLC as of December 31, 2016. PBF Energy operates and controls all of the business and affairs and consolidates the financial results of PBF LLC and its subsidiaries. PBF Holding, together with its consolidated subsidiaries, owns and operates oil refineries and related facilities in North America.

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PART I
In this Annual Report on Form 10-K, unless the context otherwise requires, references to the “Company,” “we,” “our” or “us” refer to PBF Holding, and, in each case, unless the context otherwise requires, its consolidated subsidiaries. References to “subsidiary guarantors” refer to PBF Services Company LLC, PBF Power Marketing LLC, Paulsboro Natural Gas Pipeline Company LLC, Paulsboro Refining Company LLC (“Paulsboro Refining”), Toledo Refining Company LLC (“Toledo Refining” or “TRC”), Delaware City Refining Company LLC (“Delaware City Refining” or “DCR”), PBF Investments LLC (“PBF Investments”), Chalmette Refining, L.L.C. (“Chalmette Refining”), PBF Western Region LLC ("PBF Western Region"), Torrance Refining Company LLC ("Torrance Refining") and Torrance Logistics Company LLC ("Torrance Logistics"), which are the subsidiaries of PBF Holding that guarantee PBF Holding's 8.25% Senior Secured Notes due 2020 (the “2020 Senior Secured Notes”) and 7.0% Senior Secured Notes due 2023 (the “2023 Senior Secured Notes”, and together with the 2020 Senior Secured Notes, the “Senior Secured Notes”) on a joint and several basis.
In this Annual Report on Form 10-K, we make certain forward-looking statements, including statements regarding our plans, strategies, objectives, expectations, intentions, and resources. You should read our forward-looking statements together with our disclosures under the heading: “Cautionary Statement Regarding Forward-Looking Statements.” When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in this Annual Report on Form 10-K under “Risk Factors” in Item 1A.
ITEM. 1 BUSINESS
Overview
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, 2016, 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. The Company’s five oil refineries are aggregated into one reportable segment.
PBF Energy Inc.'s Public Offerings
We are a Delaware limited liability company and a holding company for our operating subsidiaries. PBF Finance is a wholly-owned subsidiary of PBF Holding. We are a wholly-owned subsidiary of PBF LLC, and PBF Energy is the sole managing member of, and owner of an equity interest as of December 31, 2016 representing approximately 96.5% of the outstanding economic interests in PBF LLC.
On December 18, 2012, our indirect parent, PBF Energy completed its initial public offering. As a result of PBF Energy's initial public offering and related organization transactions, PBF Energy became the sole managing member of PBF LLC and operates and controls all of its business and affairs and consolidates the financial results of PBF LLC and its subsidiaries, including PBF Holding and PBF Finance. PBF Energy completed secondary offerings of its Class A common stock in 2013, 2014, and 2015. On October 13, 2015, PBF Energy completed a public offering of an aggregate of 11,500,000 shares of Class A common stock (the “October 2015 Equity Offering”) and on December 19, 2016, PBF Energy completed a public offering of 10,000,000 shares of Class A common stock (the "December 2016 Equity Offering"). As of December 31, 2016, PBF Energy held 109,204,047 PBF LLC Series C Units and its current and former executive officers and directors and certain employees and others beneficially held 3,920,902 PBF LLC Series A Units, and the holders of PBF Energy's issued and outstanding shares of Class A common stock have 96.5% of the voting power in PBF Energy and the members of PBF LLC other than PBF Energy through their holdings of Class B common stock have the remaining 3.5% of the voting power.

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PBF Holding Refineries
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
Throughput Capacity (in barrels per day)
PADD
Crude Processed (1)
Source (1)
Delaware City
East Coast
11.3

190,000

1

medium and heavy sour crude
water, rail
Paulsboro
East Coast
13.2

180,000

1

medium and heavy sour crude
water, rail
Toledo
Mid-Continent
9.2

170,000

2

light, sweet crude
pipeline, truck, rail
Chalmette
Gulf Coast
12.7

189,000

3

light and heavy crude
water, pipeline
Torrance
West Coast
14.9

155,000

5

heavy and medium crude
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.
Public Offerings of PBFX and Subsequent Drop-Down Transactions
PBF Logistics LP ("PBFX" or the "Partnership") is an affiliate of ours. PBFX is a fee-based, growth-oriented, 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, storing and transferring of crude oil, refined products 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, 2016, a substantial majority of PBFX’s revenue is derived from long-term, fee-based commercial agreements with us, which include minimum volume commitments, for receiving, handling, storing and transferring crude oil and refined products. PBF Energy also has agreements with PBFX that establish fees for certain general and administrative services and operational and maintenance services provided by us to PBFX.
PBF Logistics GP LLC (“PBF GP”) serves as the general partner of PBFX. PBF GP is wholly-owned by PBF LLC. On May 14, 2014, PBFX completed its initial public offering (the “PBFX Offering”). In connection with the PBFX Offering, we contributed to PBFX the assets and liabilities of certain crude oil terminaling assets. In a series of additional transactions subsequent to the PBFX Offering, we distributed certain additional assets to PBF LLC, which in turn contributed those assets to PBFX. See "Agreements with PBFX" below as well as "Note

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12 - Related Party Transactions" to the consolidated financial statements for additional information.
See “Item 1A. Risk Factors” and “Item 13. Certain Relationships and Related Transactions, and Director Independence.”
Recent Developments
Contribution Agreement
On February 15, 2017, PBF LLC entered into a contribution agreement with PBFX pursuant to which PBF LLC has agreed to contribute to PBFX all of the issued and outstanding limited liability company interests of Paulsboro Natural Gas Pipeline Company LLC ("PNGPC"), a wholly-owned subsidiary of PBF Holding. PNGPC owns and operates an existing interstate natural gas pipeline that originates in Delaware County, Pennsylvania, and terminates at the delivery point to our Paulsboro Refinery. PNGPC has Federal Energy Regulatory Commission (“FERC”) approval for, and is in the process of constructing, a new 24” pipeline (the “New Pipeline”) to replace the existing pipeline, which will be abandoned. In consideration for the PNGPC limited liability company interests, at closing, PBFX delivered (i) an intercompany promissory note in an amount to be determined based on the amounts expended through the closing date with respect to the New Pipeline and the abandonment of the existing line, (ii) an expansion rights and right of first refusal agreement in favor of PBF LLC with respect to the New Pipeline and (iii) an assignment and assumption agreement with respect to certain outstanding litigation involving PNGPC and the existing pipeline. The transaction closed on February 28, 2017.
Storage Services Agreement
On February 15, 2017, we entered into a ten-year storage services agreement (the “Chalmette Storage Agreement”) with PBFX’s wholly-owned subsidiary, PBFX Operating Company ("PBFX Op Co"), under which PBFX, through PBFX Op Co, will provide storage services to us upon the earlier of November 1, 2017 and the completion of construction of a new tank at our Chalmette Refinery. PBFX Op Co and Chalmette Refining have entered into a twenty-year lease for the premises upon which the tank will be located and a project management agreement pursuant to which our subsidiary, Chalmette Refining, will manage the construction of the tank.
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.
The diagram below depicts our organizational structure as of December 31, 2016:

5



pbfholdingstructurechartat12.gif

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Refining Operations
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 and Canada, 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 transported, via pipes, to an extensive tank farm where they are stored until processing. In addition, there is a 15-lane, 50,000 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 transferred to PBFX in conjunction with its acquisition of the Delaware City Products Pipeline and Truck Rack (as defined in "Note 12 - Related Party Transactions" 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 Paulsboro, 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 ("FCU") and 18,000 bpd hydrocracking unit with vacuum distillation. Hydrogen is provided via the refinery’s steam methane reformer and continuous catalytic reformer.
The following table approximates the Delaware City refinery’s major process unit capacities. Unit capacities are shown in barrels per stream day.
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 purchase all of our crude and feedstock needs independently from a variety of suppliers on the spot market or through term agreements. Prior to 2016, we had a crude and feedstock supply agreement with Statoil pursuant to which we directed Statoil to purchase waterborne crude and other feedstocks for Delaware City and Statoil purchased these products on the spot market or through term agreements. Accordingly, Statoil entered into, on our behalf, hedging arrangements to protect against changes in prices between the time of purchase and the time of processing the feedstocks. In addition to procurement, Statoil

7



arranged transportation and insurance for these waterborne deliveries of crude and feedstock supply and we paid Statoil a per barrel fee for their procurement and logistics services.
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 with J. Aron ("Inventory Intermediation Agreement") to support the operations of the Delaware City refinery. Pursuant to the Inventory Intermediation Agreement, J. Aron purchased certain of the finished and intermediate products (collectively the “Products”) located at the refinery upon termination of a previous product offtake 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 May 29, 2015, we entered into amended and restated inventory intermediation agreements for both the Delaware City and Paulsboro refineries (the "A&R Intermediation Agreements") with J. Aron pursuant to which certain terms of the existing Inventory Intermediation Agreements were amended, including, among other things, pricing and an extension of the term for a period of two years from the original expiry date of July 1, 2015 subject to certain early termination rights. In addition, the A&R Intermediation Agreements include one-year renewal clauses upon six months' advance notice by mutual consent of both parties. The A&R Intermediation Agreements have not been renewed and are scheduled to expire July 1, 2017. If we are unable to negotiate and extension with J. Aron or enter into an alternative intermediation agreement, we will have to repurchase the inventories outstanding under the A&R 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.
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 Delaware City. 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. 

8



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, the Company 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 the 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 May 29, 2015, the Company and J. Aron amended the Inventory Intermediation Agreement pursuant to which certain terms of the existing inventory intermediation agreements were amended, including, among other things, pricing and an extension of the term for a period of two years from the original expiry date of July 1, 2015 subject to certain early termination rights. In addition, the A&R Intermediation Agreements include one-year renewal clauses upon six months' advance notice by mutual consent of both parties. The A&R Intermediation Agreements have not been renewed and are scheduled to expire July 1, 2017. If we are unable to negotiate and extension with J. Aron or enter into an alternative intermediation agreement, we will have to repurchase the inventories outstanding under the A&R 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 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.

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Toledo Refinery
Overview. Toledo 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. Previously, we had a crude oil acquisition agreement with a third party that expired on July 31, 2014.
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 another 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 and products. A portion of storage capacity dedicated to crude oil and finished products was transferred to PBFX in conjunction with its acquisition of the Toledo Storage Facility (as defined in "Note 12 - Related Party Transactions" to the 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.

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Chalmette Refinery
Acquisition. On November 1, 2015, we acquired from ExxonMobil Oil Corporation ("ExxonMobil"), Mobil Pipe Line Company and PDV Chalmette, L.L.C., the ownership interests of Chalmette Refining, L.L.C. (“Chalmette Refining”), which owns the Chalmette refinery and related logistics assets (collectively, the "Chalmette Acquisition"). The aggregate purchase price for the Chalmette Acquisition was $322.0 million in cash, plus inventory and final working capital of $246.0 million.
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 Unit
189,000

Fluid Catalytic Cracking Unit
72,000

Hydrotreating Units
158,000

Delayed Coker
29,000

Catalytic Reforming Unit
22,000

Alkylation Unit
15,000

Feedstocks and Supply Arrangements. In connection with the Chalmette Acquisition on November 1, 2015, we entered into a crude supply arrangement with 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. Additionally, we obtain crude and feedstocks from other sources through connections to the CAM and MOEM Pipelines as well as ship docks and truck racks.
Refined Product Yield and Distribution. The Chalmette refinery primarily processes a variety of light and heavy crude oils. 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 have an offtake agreement with ExxonMobil pursuant to which ExxonMobil purchases approximately 50% of the 14,000 barrel per day capacity. This agreement had an initial term of one year from the date of the Chalmette Acquisition continuing thereafter subject to the right of either party to cancel with six months' written notice. As of December 31, 2016, no notice of cancellation had been given by either party.
Tankage Capacity. Chalmette has a total tankage capacity of approximately 7.5 million barrels. Of this total, approximately 2.1 million barrels are allocated to crude oil storage with the remaining 5.4 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

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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 Oil Corporation and its subsidiary, 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
156,000

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 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.

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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.
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, 2016, 2015 and 2014, gasoline and distillates accounted for 88.1%, 88.0% and 86.0% 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, 2016, 2015 and 2014, no single customer accounted for 10% or more of our revenues, respectively. As of December 31, 2016, no single customer accounted for 10% or more of our total trade accounts receivable. ExxonMobil and its affiliates represented approximately 18% of our total trade accounts receivable as of December 31, 2015.
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.
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 cost of crude oil is 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.

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Agreements with PBFX
Beginning with the completion of the PBFX Offering, we have entered into a series of agreements with PBFX, including commercial and operational agreements. Each of these agreements and their impact to our operations is outlined below.
Contribution Agreements
Immediately prior to the closing of the contribution agreements, which PBF LLC entered into with PBFX (as defined in the table below, and collectively referred to as the “Contribution Agreements”), we contributed certain assets to PBF LLC. PBF LLC in turn contributed those assets to PBFX pursuant to the Contribution Agreements. Certain proceeds received by PBF LLC from PBFX in accordance with the Contribution Agreements were subsequently contributed by PBF LLC to us. The Contribution Agreements include the following:
Contribution Agreement
Contribution Date
Assets Contributed
Contribution Agreement I
5/8/2014
DCR Rail Terminal and the Toledo Truck Terminal
Contribution Agreement II
9/30/2014
DCR West Rack
Contribution Agreement III
12/11/2014
Toledo Storage Facility
Contribution Agreement IV
5/5/2015
Delaware City Products Pipeline and Truck Rack
Contribution Agreement V
8/31/2016
Torrance Valley Pipeline

Pursuant to Contribution Agreement V on August 31, 2016, PBF Holding contributed 50% of the issued and outstanding limited liability company interests of TVPC to PBF LLC. PBFX then acquired 50% of the issued and outstanding limited liability company interests of Torrance Valley Pipeline Company LLC (“TVPC”). TVPC's assets consist of the Torrance Valley Pipeline which include the M55, M1 and M70 pipeline systems, including 11 pipeline stations with storage capacity and truck unloading capability at two of the stations.
PBFX Operating Company LP ("PBFX Op Co"), PBFX’s wholly-owned subsidiary, serves as TVPC's managing member. PBFX, through its ownership of PBFX Op Co, has the sole ability to direct the activities of TVPC that most significantly impact its economic performance. Accordingly, PBFX, and not PBF Holding, is considered to be the primary beneficiary for accounting purposes and as a result PBFX fully consolidates TVPC. Subsequent to the Contribution Agreement V, we record an investment in equity method investee on its balance sheet for the 50% of TVPC that we own. The carrying value of our equity method investment in TVPC was $179.9 million and $0 million at December 31, 2016 and 2015, respectively.
Our equity investment in TVPC is included in the Non-Guarantor financial position and results of PBF Holding disclosed in "Note 22 - Condensed Consolidating Financial Statements of PBF Holding" to the consolidated financial statements as this subsidiary is not a guarantor of the Senior Secured Notes.
Commercial Agreements
PBFX currently derives a substantial majority of its revenue from long-term, fee-based agreements with us relating to assets associated with the Contribution Agreements described above, PBF Holding entered into long-term, fee-based commercial agreements with PBFX, supported by contractual fee escalations for inflation adjustments and certain increases in operating costs. We believe the terms and conditions under these agreements, as well as the Omnibus Agreement (as defined below) and the Services Agreement (as defined below) each with PBFX, are generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services.
These commercial agreements (as defined in the table below) with PBFX relating to the Contributed Assets include:

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Service Agreements
Initiation Date
Initial Term
Renewals (a)
Minimum Volume Commitments ("MVC")
Force Majeure
Transportation and Terminaling
 
 
 
 
 
Delaware City Rail Terminaling Services Agreement
5/8/2014
7 years, 8 months
2 x 5
85,000 bpd
PBFX or PBF Holding can declare
Toledo Truck Unloading & Terminaling Services Agreement
5/8/2014
7 years, 8 months
2 x 5
5,500 bpd
Delaware West Ladder Rack Terminaling Services Agreement
10/1/2014
7 years, 3 months
2 x 5
40,000 bpd
Toledo Storage Facility Storage and Terminaling Services Agreement- Terminaling Facility (b)
12/12/2014
10 years
2 x 5
4,400 bpd
Delaware Pipeline Services Agreement
5/15/2015
10 years, 8 months
2 x 5
50,000 bpd
Delaware Pipeline Services Agreement- Magellan Connection
11/1/2016
2 years, 5 months
-
14,500 bpd
Delaware City Truck Loading Services Agreement- Gasoline (c)
5/15/2015
10 years, 8 months
2 x 5
30,000 bpd
Delaware City Truck Loading Services Agreement- Liquefied Petroleum Gases (“LPGs”) (c)
5/15/2015
10 years, 8 months
2 x 5
5,000 bpd
Torrance Valley Pipeline Transportation Services Agreement- North Pipeline
8/31/2016
10 years
2 x 5
50,000 bpd
Torrance Valley Pipeline Transportation Services Agreement- South Pipeline
8/31/2016
10 years
2 x 5
70,000 bpd
Torrance Valley Pipeline Transportation Services Agreement- Midway Storage Tank
8/31/2016
10 years
2 x 5
55,000 barrels (d)
Torrance Valley Pipeline Transportation Services Agreement- Emido Storage Tank
8/31/2016
10 years
2 x 5
900,000 barrels per month
Torrance Valley Pipeline Transportation Services Agreement- Belridge Storage Tank
8/31/2016
10 years
2 x 5
770,000 barrels per month
Storage
 
 
 
 
 
Toledo Storage Facility Storage and Terminaling Services Agreement- Storage Facility (b)
12/12/2014
10 years
2 x 5
3,849,271 barrels (d)
PBFX or PBF Holding can declare
____________________
(a)
PBF Holding has the option to extend the agreements for up to two additional five-year terms.
(b)
The Toledo Storage Facility Storage and Terminaling Services Agreement- Terminaling Facility and the Toledo Storage Facility Storage and Terminaling Services Agreement- Storage Facility are referred to herein collectively as the “Toledo Storage Facility Storage and Terminaling Services Agreement."
(c)
The Delaware City Truck Loading Services Agreement- Gasoline and the Delaware City Truck Loading Services Agreement- LPGs are referred to herein collectively as the “Delaware City Truck Loading Services Agreement."
(d)
Reflects the overall capacity of the storage facility. The storage MVC is subject to effective operating capacity of each tank which can be impacted by routine tank maintenance and other factors.


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In addition, we have commercial agreements in place with PBFX with respect to the East Coast Terminals having terms ranging from approximately three months to five years and include:
tank lease agreements, under which PBFX provides tank lease services to us at the East Coast Terminals, with MVCs of total aggregate shell capacity; and
terminaling service agreements, under which PBFX provides terminaling and other services to us at the East Coast Terminals. The terminaling service agreements have no MVCs and are billed based on actual volumes throughput, other than a terminaling services agreement between us and PBFX's East Coast Terminals' located at Paulsboro, New Jersey which has a 15,000 bpd MVC.
Omnibus Agreement
PBFX entered into an omnibus agreement with PBF GP, PBF LLC and us at the closing of the PBFX Offering for the provision of executive management services and support for accounting and finance, legal, human resources, information technology, environmental, health and safety, and other administrative functions, as well as (i) PBF LLC’s agreement not to compete with PBFX under certain circumstances, subject to certain exceptions, (ii) PBFX's right of first offer for ten years to acquire certain logistics assets retained by PBF Energy following the PBFX Offering, including certain logistics assets that PBF LLC or its subsidiaries may construct or acquire in the future, subject to certain exceptions, and (iii) a license to use the PBF Logistics trademark and name.
On August 31, 2016, we entered into the Fourth Amended and Restated Omnibus Agreement (as amended, the "Omnibus Agreement") with PBFX in connection with the TVPC Acquisition resulting in an increase to the annual administrative fee to approximately $4.0 million.
Services Agreement
In connection with the PBFX Offering, PBF Holding and certain of its subsidiaries entered into an operation and management services and secondment agreement with PBFX, pursuant to which we and our subsidiaries provide PBFX with the personnel necessary for PBFX to perform its obligations under its commercial agreements. PBFX reimburses us for the use of such employees and the provision of certain infrastructure-related services to the extent applicable to its operations, including storm water discharge and waste water treatment, steam, potable water, access to certain roads and grounds, sanitary sewer access, electrical power, emergency response, filter press, fuel gas, API solids treatment, fire water and compressed air.
On August 31, 2016, we entered into the Fourth Amended and Restated Services Agreement (as amended, the "Services Agreement") with PBFX in connection with the TVPC Acquisition resulting in an increase to the annual fee to approximately $6.4 million.
The Services Agreement will terminate upon the termination of the Omnibus Agreement, provided that PBFX may terminate any service on 30 days’ notice.
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.

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Employees
As of December 31, 2016, we had approximately 3,136 employees. At Paulsboro, 287 of our 461 employees are covered by a collective bargaining agreement. In addition, 1,267 of our 2,272 employees at Delaware City, Toledo, Chalmette and Torrance 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, Chalmette and Torrance are scheduled to expire in January 2019; 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.
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.
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 require heating oil with 15 PPM or less sulfur by July 1, 2018 (except for Pennsylvania and Maryland - where 500 PPM sulfur is required). All of the heating oil we currently produce meets 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 Clean Air Act. 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 standards set by the new rule are not expected to have a material impact on our financial position, results of operations or cash flows.
The EPA published the final 2014-2016 standards under the Renewable Fuels Standard ("RFS") late in 2015. The EPA proposed the 2017 standards in May of 2016 and issued final 2017 RFS standards in November 2016, in line with the deadline for issuing such standards. The final standards for 2017 are in fact slightly more aggressive than were originally proposed in May of 2016. It is not clear that renewable fuel producers will be able to produce the volumes of these fuels required for blending in 2017. The final 2017 cellulosic standard is at approximately 135% of the 2016 standard and the renewable fuel industry was only on pace to make approximately 75% of the

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lower 2016 standard. It is quite likely that cellulosic RIN production will be lower than needed forcing obligated parties to purchase cellulosic “waiver credits” to comply in 2017 (the waiver credit option by regulation is only available for the cellulosic standard). The advanced and total renewable RIN requirements were raised slightly (by 7% and 3% respectively) above the original proposed level in May 2016. Analysts had been expecting that the EPA might, in fact, lower these standards. Production of advanced RINs has been well below what is needed for compliance in 2016. Obligated parties will likely be relying on the nesting feature of the biodiesel RIN to comply with the advanced standard in 2017. While the total renewable RIN production was adequate for 2016 needs, the new 2017 standard will put obligated parties up against the E10 blendwall leaving little flexibility. Compliance in 2017 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. Industry organizations pointed out these issues with the May 2016 proposal to the EPA in commenting on the proposed standards. The EPA decided to ignore these arguments and raised the requirements in support of renewable fuel producers. We are currently evaluating the final standards, including any possible changes to the program following a new presidential administration, and they may have a material impact on our cost of compliance with RFS 2.
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 will need to be implemented by January 30, 2018. We are currently evaluating the final standards to evaluate the impact of this regulation, and at this time we do not anticipate it will have a material impact on the 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 ("AB 32"). AB 32 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. AB 32 is implemented through two market mechanisms including the Low Carbon Fuel Standard ("LCFS") and Cap and Trade. We are responsible for the AB 32 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 ("SB 32") which further reduces greenhouse gas emissions targets to 40 percent below 1990 levels by 2030. We expect to recover 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 AB 32 or SB 32 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 liquidity.
We are subject to obligations to purchase Renewable Identification Numbers ("RINs") required to comply with the RFS. In late 2015, the EPA initiated enforcement proceedings against companies it believes produced invalid RINs. On October 13, 2016, we and our subsidiaries Toledo Refining Company LLC and Delaware City Refining Company LLC were notified by the EPA that its records indicated that these entities used potentially invalid RINs. The EPA directed each of the subsidiaries to resubmit reports to remove the potentially invalid RINs and to replace the invalid RINs with valid RINs with the same D Code. The invalid RINs have been retired and we do not expect any settlement with the EPA to resolve this matter to be material.
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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Our operations are also subject to the federal Clean Water Act (the "CWA"), the federal Safe Drinking Water Act (the "SDWA") and comparable state and local requirements. The CWA, the SDWA and analogous laws prohibit any discharge into surface waters, ground waters, injection wells and publicly-owned treatment works except in strict conformance with permits, such as pre-treatment permits and discharge permits, issued by federal, state and local governmental agencies. Federal waste-water discharge permits and analogous state waste-water discharge permits are issued for fixed terms and must be renewed.
We generate wastes that may be subject to the federal Resource Conservation and Recovery Act (the "RCRA") and comparable state and local requirements. The EPA and various state agencies have limited the approved methods of disposal for certain hazardous and non-hazardous wastes.
The EPA published a Final Rule to the 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 gives state agencies 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.
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 below, 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.
In connection with each of our acquisitions, we assumed certain environmental remediation obligations. The more significant of these are discussed below.
In connection with the Paulsboro refinery acquisition, we assumed certain environmental remediation obligations. The environmental liability of $10.8 million recorded as of December 31, 2016 ($10.4 million as of

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December 31, 2015) represents the present value of expected future costs discounted at a rate of 8.0%. As of December 31, 2016 and December 31, 2015, 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, we 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 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.
As of November 1, 2015, we acquired Chalmette Refining, which was in discussions with the Louisiana Department of Environmental Quality ("LDEQ") to resolve self-reported deviations from refinery operations relating to certain Clean Air Act Title V permit conditions, limits and other requirements. LDEQ commenced an enforcement action against Chalmette Refining on November 14, 2014 by issuing a Consolidated Compliance Order and Notice of Potential Penalty (the "Order") covering deviations from 2009 and 2010. Chalmette Refining and LDEQ subsequently entered into a dispute resolution agreement, the enforcement of which has been suspended while negotiations are ongoing, which may include the resolution of deviations outside the periods covered by the Order. It is possible that LDEQ will assess an administrative penalty against Chalmette Refining, but any such amount is not expected to be material to us.
On January 24, 2017, in connection with a Clean Air Act inspection in May 2014 by the EPA to determine compliance with 40 CFR Subpart 68 Chemical Accident Prevention Provisions, the EPA notified the Chalmette refinery of its intent to bring an enforcement action on two (2) findings from the audit. No settlement or penalty demand has been received to date. It is possible that the EPA will assess penalties in these matters in excess of $0.1 million but any such amount is not expected to be material to us, individually or in the aggregate.
On December 23, 2016, the Delaware City refinery received a Notice of Violation (“NOV”) from DNREC concerning a potential violation of the DNREC order authorizing the shipment of crude oil by barge from the Refinery. The NOV alleges that DCR made shipments to locations other than the Paulsboro refinery in violation of the order and requests certain additional information but no penalties have been assessed at this time. 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 held a public hearing and dismissed the appeal, determining that the appellants did not have standing. The release of the Board decision is pending.
On February 3, 2011, the EPA sent a request for information pursuant to Section 114 of the Clean Air Act to the Paulsboro refinery with respect to compliance with EPA standards governing flaring. The refinery and the EPA have recently reached a settlement pursuant to which the Paulsboro refinery will pay a penalty of approximately $0.2 million.
On February 14, 2017, the New Jersey Department of Environmental Protection (“NJDEP”) submitted a proposed Administrative Consent Order (“ACO”) which covers air emission violations from 2013 through 2016

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and work practice standards that were not subject to an affirmative defense at the Paulsboro refinery (“PRC”). In settlement of the violations, the NJDEP has proposed that PRC pay a civil administrative penalty of $0.3 million, which includes $0.1 million for a supplemental environmental project. If the offer is accepted, the remaining $0.2 million shall be remitted by PRC within 30 days of receipt of the offer. This amount is not material to the Company, individually or in the aggregate.
In connection with the acquisition of the Torrance refinery and related logistics assets, we assumed certain pre-existing environmental liabilities totaling $142.5 million as of December 31, 2016, related to certain environmental remediation obligations to address existing soil and groundwater contamination and monitoring activities, which reflects 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. Specifically, we assumed responsibility for (i) a Notice of Violation ("NOV") issued on March 12, 2015 by the Southern California Air Quality Management District ("SCAQMD") relating to self-reported Title V deviations for the Torrance Refinery for compliance year 2012, (ii) a NOV issued on March 10, 2016 for self-reported Title V deviations for the Torrance Refinery for compliance year 2013, (iii) a NOV issued on March 10, 2016 for self-reported Title V deviations for the Torrance Refinery for compliance year 2014 and (iv) a NOV issued on March 10, 2016 for self-reported Title V deviations for the Torrance Refinery for compliance year 2015. Following the closing of the acquisition, the Torrance refinery has received a number of NOVs. On September 6, 2016, a NOV was issued to the Torrance refinery by the SCAQMD for the July 11, 2016 FCCU shutdown and startup. The NOV alleges that the facility operated equipment while it bypassed associated air pollution control equipment in violation of our facility permit to operate. Opacity from FCCU 2F-7 exceeded 40 percent on July 11, 2016 and July 14, 2016, aggregate over 3 minutes in one continuous hour. In addition, on October 13, 2016, a NOV was issued by the SCAQMD for an alleged nuisance created from flaring associated with the October 11, 2016 Southern California Edison power disruption. On January 4, 2017, a NOV was also issued for an alleged discharge of air contaminants from Tank 1340x113 that caused a nuisance to a considerable number of persons or to the public. On January 13, 2017, a NOV was issued by the City of Torrance for allegedly failing to report a release or threatened release of hazardous material. On January 7, 2017, the Torrance refinery allegedly experienced a third release (January 3, January 4 and January 7) in a week of untreated Naphtha gas due to the generation of higher capacity from the Coker Unit. On February 28, 2017, in review of the fire occurring at the refinery on February 18, 2017, the City of Torrance Fire Department issued a NOV to the Torrance refinery requiring the refinery to comply with California Fire Code Section 104.7.2 and provide a technical opinion and report with respect to the refinery’s process safety risk assessment plan. With the exception of the October 13th NOV, no settlement or penalty demand has been received to date with respect to these notices. The proposed penalty for the October 13th NOV is less than $0.1 million. It is possible that SCAQMD and/or the City of Torrance will assess penalties in the other matters in excess of $0.1 million but any such amount is not expected to be material to us, individually or in the aggregate.
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:
“AB 32” 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 at 1 atmosphere pressure.
“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.
“CAPP” refers to the Canadian Association of Petroleum Producers.
"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 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.

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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” 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 and cellulosic residues from crops or wood. 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 GAAP.
“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 greenhouse gas.
“Group I base oils or lubricants” refers to conventionally refined products characterized by sulfur content less than 0.03% with a viscosity index between 80 and 120. Typically, these products are used in a variety of automotive and industrial applications.
“heavy crude oil” refers to a relatively inexpensive crude oil with a low API gravity characterized by high relative density and viscosity. Heavy crude oils require greater levels of processing to produce high value products such as gasoline and diesel.
“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.
“LLS” refers to Light Louisiana Sweet benchmark for crude oil reflective of Gulf coast economics for light sweet domestic and foreign crudes.

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“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.
“SEC” refers to the United States Securities and Exchange Commission.
“Statoil” refers to Statoil Marketing and Trading (US) Inc.

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“Sunoco” refers to Sunoco, Inc. (R&M).
“sweet crude oil” refers to a crude oil that is relatively low in sulfur content, requiring less processing to remove the sulfur than sour crude oil. Sweet crude oil is typically more expensive than sour crude oil.
“Syncrude” refers to a blend of Canadian synthetic oil, a light, sweet crude oil, typically characterized by API gravity between 30° and 32° and a sulfur content of approximately 0.1-0.2 weight percent.
“throughput” refers to the volume processed through a unit or refinery.
“turnaround” refers to a periodically required shutdown and comprehensive maintenance event to refurbish and maintain a refinery unit or units that involves the 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.
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 sales. For example, during the year ended December 31, 2016, we recorded an adjustment to value our inventories to the lower of cost or market which increased operating income and net income by $521.3 million, respectively, reflecting the net change in the lower of cost or market inventory reserve from $1,117.3 million at December 31, 2015 to $596.0 million at December 31, 2016.
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 cheaper 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, historically crude prices have been slightly above the WTI benchmark, however, that premium to WTI 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 differential narrows. 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 further or continued 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 new 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.
The repeal of the crude oil export ban in the United States may affect our profitability.
In December 2015, the United States Congress passed and the President signed the 2016 Omnibus Appropriations bill which included a repeal of the ban on the export of crude oil produced in the United States. The crude export ban was established by the Energy Policy and Conservation Act in 1975 to reduce reliance on foreign oil producing countries. While there are differing views on the magnitude of the impact of lifting the crude export ban on crude oil prices, most economists believe the export ban repeal will eventually lead to higher crude oil prices and narrowing Dated Brent/WTI differentials and in turn higher gasoline prices in the United States. Crude oil is our most significant input cost and there is no guaranty that increases in our crude oil costs will be offset by corresponding increases in the selling prices of our refined products. As a result, an increase in crude oil prices resulting from the repeal of the crude oil export ban may reduce our profitability.
Our recent historical earnings have been concentrated and may continue to be concentrated in the future.
Our five refineries have similar throughput capacity, however, favorable market conditions due to, among other things, geographic location, crude and refined product slates, and customer demand, may cause an individual refinery to contribute more significantly to our earnings than others for a period of time. For example, our Toledo, Ohio refinery in the past has produced a substantial portion of our earnings. As a result, if there were a significant disruption to operations at this refinery, our earnings could be materially adversely affected (to the extent not recoverable through insurance) disproportionately to Toledo’s portion of our consolidated throughput. The Toledo refinery, or one of our other refineries, may continue to disproportionately affect our results of operations in the future. Any prolonged disruption to the operations of such refinery, whether due to labor difficulties, destruction of or damage to such facilities, severe weather conditions, interruption of utilities service or other reasons, could have a material adverse effect on our business, results of operations or financial condition.
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,

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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.
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.

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We may have capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate.
If we cannot generate sufficient cash flows or otherwise secure sufficient liquidity to support our short-term and long-term capital requirements, we may not be able to meet our payment obligations or our future debt obligations, comply with certain deadlines related to environmental regulations and standards, or pursue our business strategies, including acquisitions, in which case our operations may not perform as we currently expect. We have substantial short-term capital needs and may have substantial long term capital needs. Our short-term working capital needs are primarily related to financing certain of our 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). On May 29, 2015, we entered into amended and restated inventory intermediation agreements with J. Aron pursuant to which certain terms of the existing inventory intermediation agreements were amended, including, among other things, pricing and an extension of the term for a period of two years from the original expiry date of July 1, 2015, subject to certain early termination rights. In addition, the A&R Intermediation Agreements for both the Delaware City and Paulsboro refineries with J. Aron include one-year renewal clauses upon six months' advance notice by mutual consent of both parties. The A&R Intermediation Agreements have not been renewed and are scheduled to expire July 1, 2017. If we are unable to negotiate an extension with J. Aron or enter into an alternative intermediation agreement, we will have to repurchase the inventories outstanding under the A&R Intermediation Agreement at that time.
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 recent past, global financial markets and economic conditions have been, and may continue to 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

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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 and the solvency of lending counterparties specifically, the cost of obtaining money from the credit markets may increase as many lenders and institutional investors increase interest rates, enact tighter lending standards, refuse to refinance existing debt on similar terms or at all and reduce or, in some cases, cease to provide funding to borrowers. Due to these factors, we cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due. Moreover, without adequate funding, we may be unable to execute our growth strategy, complete future acquisitions, take advantage of other business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.
Competition from companies who produce their own supply of feedstocks, have extensive retail outlets, make alternative fuels or have greater financial and other resources than we do could materially and adversely affect our business and results of operations.
Our refining operations compete with domestic refiners and marketers in regions of the United States in which we operate, as well as with domestic refiners in other regions and foreign refiners that import products into the United States. In addition, we compete with other refiners, producers and marketers in other industries that supply their own renewable fuels or alternative forms of energy and fuels to satisfy the requirements of our industrial, commercial and individual consumers. Certain of our competitors have larger and more complex refineries, and may be able to realize lower per-barrel costs or higher margins per barrel of throughput. Several of our principal competitors are integrated national or international oil companies that are larger and have substantially greater resources than we do and access to proprietary sources of controlled crude oil production. Unlike these competitors, we obtain substantially all of our feedstocks from unaffiliated sources. We are not engaged in the petroleum exploration and production business and therefore do not produce any of our crude oil feedstocks. We do not have a retail business and therefore are dependent upon others for outlets for our refined products. Because of their integrated operations and larger capitalization, these companies may be more flexible in responding to volatile industry or market conditions, such as shortages of crude oil supply and other feedstocks or intense price fluctuations.
Newer or upgraded refineries will often be more efficient than our refineries, which may put us at a competitive disadvantage. We have taken significant measures to maintain our refineries including the installation of new equipment and redesigning older equipment to improve our operations. However, these actions involve significant uncertainties, since upgraded equipment may not perform at expected throughput levels, the yield and product quality of new equipment may differ from design specifications and modifications may be needed to correct equipment that does not perform as expected. Any of these risks associated with new equipment, redesigned older equipment or repaired equipment could lead to lower revenues or higher costs or otherwise have an adverse effect on future results of operations and financial condition. Over time, our refineries or certain refinery units may become obsolete, or be unable to compete, because of the construction of new, more efficient facilities by our competitors.
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

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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 has had and 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. Declines in global economic activity and consumer and business confidence and spending during the recent global downturn significantly reduced the level of demand for our products. Reduced demand for our products has had and may continue to 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.
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 have included or 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.

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Acquisitions that we may undertake in the future involve a number of risks, any of which could cause us not to realize the anticipated benefits.
We may not be successful in acquiring additional assets, and any acquisitions that we do consummate may not produce the anticipated benefits or may have adverse effects on our business and operating results. We may selectively consider strategic acquisitions in the future within the refining and mid-stream sector based on performance through the cycle, advantageous access to crude oil supplies, attractive refined products market fundamentals and access to distribution and logistics infrastructure. Our ability to do so will be dependent upon a number of factors, including our ability to identify acceptable acquisition candidates, consummate acquisitions on acceptable terms, successfully integrate acquired assets and obtain financing to fund acquisitions and to support our growth and many other factors beyond our control. Risks associated with acquisitions include those relating to the diversion of management time and attention from our existing business, liability for known or unknown environmental conditions or other contingent liabilities and greater than anticipated expenditures required for compliance with environmental, safety or other regulatory standards or for investments to improve operating results, and the incurrence of additional indebtedness to finance acquisitions or capital expenditures relating to acquired assets. We may also enter into transition services agreements in the future with sellers of any additional refineries we acquire. Such services may not be performed timely and effectively, and any significant disruption in such transition services or unanticipated costs related to such services could adversely affect our business and results of operations. In addition, it is likely that, when we acquire refineries, we will not have access to the type of historical financial information that we will require regarding the prior operation of the refineries. As a result, it may be difficult for investors to evaluate the probable impact of significant acquisitions on our financial performance until we have operated the acquired refineries for a substantial period of time.
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 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

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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.
Our commodity derivative activities could result in period-to-period earnings volatility.
We do not 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 do not satisfy certain specific exceptions. The legislation may also require the counterparties to our derivatives contracts to transfer or assign some of their derivatives contracts to a separate entity, which may not be as creditworthy as the current counterparty. 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 derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivatives contracts, and increase our exposure to less creditworthy counterparties. 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

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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.
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.
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 recently announced that it will consider banning the use of modified hydrofluoric acid, also known as MHF, in California. We utilize MHF in the manufacturing of gasoline at our Torrance refinery. If MHF usage is limited or restricted by the SCAQMD,our current operations would be adversely affected, which could have a material adverse affect 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 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, cash flows and results of operations.

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Environmental clean-up and remediation costs of our sites and environmental litigation could decrease our net cash flow, reduce our results of operations and impair our financial condition.
We are subject to liability for the investigation and clean-up of environmental contamination at each of the properties that we own or operate and at off-site locations where we arrange for the treatment or disposal of regulated materials. We may become involved in future litigation or other proceedings. If we were to be held responsible for damages in any 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 are underway in accordance with regulatory requirements at our refineries. In connection with the acquisitions of certain of our refineries, 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 financial condition. As a result, in addition to making capital expenditures or incurring other costs to comply with environmental laws, we also may be liable for significant environmental litigation or for investigation and remediation costs and other liabilities arising from the ownership or operation of these assets by prior owners, which could materially adversely affect our 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 financial condition, results of operations and cash flow.
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 AB 32 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 new 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, AB 32 in California

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requires the state to reduce its GHG emissions to 1990 levels by 2020. Additionally, in September 2016, the state of California enacted Senate Bill 32 which further reduces greenhouse gas emissions targets to 40 percent below 1990 levels by 2030. Two regulations implemented to achieve these goals are Cap-and-Trade and the 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.
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 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 $347.5 million in RINs costs during the year ended December 31, 2016 as compared to $171.6 million and $115.7 million during the years ended December 31, 2015 and 2014, 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

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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 new presidential administration has called for substantial change to fiscal and tax policies, which may include comprehensive tax reform. We cannot predict the impact, if any, of these changes to our business. However, it is possible that some of these changes could adversely affect our business. Until we know what changes are enacted, we will not know whether in total we are negatively impacted by, the changes.
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. Recent 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 recently issued additional rules and regulation 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

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tank car standards and operational controls for high-hazard flammable trains. The new rules and any further changes in law, regulations or industry standards that require us to reduce the volatile or flammable constituents in crude oil that is transported by rail, alter the design or standards for rail cars we use, change the routing or scheduling of trains carrying crude oil, or any other changes that detrimentally affect the economics of delivering North American crude oil by rail to our, or subsequently to third party, refineries, could increase our costs, which could have a material adverse effect on our financial condition, results of operations, cash flows and our ability to service our indebtedness.
We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with health, safety, environmental and other laws and regulations.
Our operations require numerous permits and authorizations under various laws and regulations. These authorizations and permits are subject to revocation, renewal or modification and can require operational changes to limit impacts or potential impacts on the environment and/or health and safety. A violation of authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions, and/or facility shutdowns. In addition, major modifications of our operations could require modifications to our existing permits or upgrades to our existing pollution control equipment. Any or all of these matters could have a negative effect on our business, results of operations and cash flows.
We may incur significant liability under, or costs and capital expenditures to comply with, environmental and health and safety regulations, which are complex and change frequently.
Our operations are subject to federal, state and local laws regulating, among other things, the handling of petroleum and other regulated materials, the emission and discharge of materials into the environment, waste management, and remediation of discharges of petroleum and petroleum products, characteristics and composition of gasoline and distillates and other matters otherwise relating to the protection of the environment. Our operations are also subject to extensive laws and regulations relating to occupational health and safety.
We cannot predict what additional environmental, health and safety legislation or regulations may be adopted in the future, or how existing or future laws or regulations may be administered or interpreted with respect to our operations. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time.
Certain environmental laws impose strict, and in certain circumstances joint and several liability for, costs of investigation and cleanup of such spills, discharges or releases on owners and operators of, as well as persons who arrange for treatment or disposal of regulated materials at contaminated sites. Under these laws, we may incur liability or be required to pay penalties for past contamination, and third parties may assert claims against us for damages allegedly arising out of any past or future contamination. The potential penalties and clean-up costs for past or future releases or spills, the failure of prior owners of our facilities to complete their clean-up obligations, the liability to third parties for damage to their property, or the need to address newly-discovered information or conditions that may require a response could be significant, and the payment of these amounts could have a material adverse effect on our business, financial condition and results of operations.
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, our operating results are generally lower for the first and fourth quarters of each year.

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We may not be able to successfully integrate the Chalmette Refinery or the Torrance Refinery into our business, or realize the anticipated benefits of these acquisitions.
Following the completion of the Chalmette and Torrance Acquisitions, the integration of these businesses into our operations may be a complex and time-consuming process that may not be successful. Prior to the completion of the Chalmette Acquisition we did not have any operations in the Gulf Coast and prior to the Torrance Acquisition we did not have any operations in the West Coast. This may add complexity to effectively overseeing, integrating and operating these refineries and related assets. Even if we successfully integrate these businesses 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 these acquisitions may prove to be incorrect. These acquisitions involve risks, including:
unexpected losses of key employees, customers and suppliers of the acquired operations;
challenges in managing the increased scope, geographic diversity and complexity of our operations;
diversion of management time and attention from our existing business;
liability for known or unknown environmental conditions or other contingent liabilities and greater than anticipated expenditures required for compliance with environmental, safety or other regulatory standards or for investments to improve operating results; and
the incurrence of additional indebtedness to finance acquisitions or capital expenditures relating to acquired assets.
In connection with our recently completed Chalmette and Torrance Acquisitions, we did not have access to the type of historical financial information that we may require regarding the prior operation of the refineries. As a result, it may be difficult for investors to evaluate the probable impact of these significant acquisitions on our financial performance until we have operated the acquired refineries for a substantial period of time.
Risks Related to Our Indebtedness
Our substantial indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under our indebtedness.
Our substantial indebtedness may significantly affect our financial flexibility in the future. As of December 31, 2016, we have total long-term debt, including affiliate notes payable, of 1,688.1 million, excluding deferred debt issuance costs of $25.3 million, substantially all of which is secured, and we could incur an additional $534.6 million of senior secured indebtedness under our existing debt agreements. 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 significant 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;
covenants contained in our existing debt arrangements limit our ability to borrow additional funds, dispose of assets and make certain investments;
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 substantial indebtedness increases the risk that we may default on our debt obligations, certain of which contain cross-default and/or cross-acceleration provisions. We have significant principal payments due under our debt instruments. Our and our subsidiaries’ ability to meet their principal obligations will be dependent upon our

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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 substantial 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 substantial additional indebtedness in the future including additional secured debt. Although our debt instruments and financing arrangements contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions, and the indebtedness incurred in compliance with these restrictions could be substantial. To the extent new debt is added to our currently anticipated debt levels, the substantial 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 significant financial and other restrictive covenants, including restrictions on our ability to incur additional indebtedness, place liens upon assets, pay dividends or make certain other restricted payments and investments, consummate certain asset sales or asset swaps, conduct businesses other than our current businesses, or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of our assets. Some of these debt instruments also require our subsidiaries to satisfy or maintain certain financial condition tests in certain circumstances. Our subsidiaries’ ability to meet these financial condition tests can be affected by events beyond our control and 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 Secured Notes (as 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 secured debt is rated BBB- 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
Under a tax receivable agreement, PBF Energy is required to pay the pre-IPO owners of PBF LLC for certain realized or assumed tax benefits it may claim arising in connection with its initial public offering and future exchanges of PBF LLC Series A Units for shares of its Class A common stock and related transactions. The indenture governing the notes allows us, under certain circumstances, to make distributions sufficient for PBF Energy to pay its obligations arising from the tax receivable agreement, and such amounts are expected to be substantial.
PBF Energy entered into a tax receivable agreement that provides for the payment from time to time (“On-Going Payments”) by PBF Energy to the holders of PBF LLC Series A Units and PBF LLC Series B Units for certain tax benefits it may claim arising in connection with its prior offerings and future exchanges of PBF LLC

40



Series A Units for shares of its Class A Common Stock and related transactions, and the amounts it may pay could be significant.
PBF Energy’s payment obligations under the tax receivable agreement are PBF Energy’s obligations and not obligations of PBF Holding, PBF Finance, or any of PBF Holding’s other subsidiaries. However, because PBF Energy is primarily a holding company with limited operations of its own, its ability to make payments under the tax receivable agreement is dependent on our ability to make future distributions to it. The indentures governing the Senior Secured Notes allow us to make tax distributions (as defined in the indenture), and it is expected that PBF Energy’s share of these tax distributions will be in amounts sufficient to allow PBF Energy to make On-Going Payments. The indentures governing the Senior Secured Notes also allow us to make a distribution sufficient to allow PBF Energy to make any payments required under the tax receivable agreement upon a change in control, so long as we offer to purchase all of the Senior Secured Notes outstanding at a price in cash equal to 101% of the aggregate principal amount thereof, plus accrued and unpaid interest thereon, if any. If PBF Energy’s share of the distributions it receives under these specific provisions of the indentures is insufficient to satisfy its obligations under the tax receivable agreement, PBF Energy may cause us to make distributions in accordance with other provisions of the indentures in order to satisfy such obligations. In any case, based on our estimates of PBF Energy’s obligations under the tax receivable agreement, the amount of our distributions on account of PBF Energy’s obligations under the tax receivable agreement are expected to be substantial.
For example, with respect to On-Going Payments, assuming no material changes in the relevant tax law, and that PBF Energy earns sufficient taxable income to realize all tax benefits that are subject to the tax receivable agreement, we expect that PBF Energy On-Going Payments under the tax receivable agreement relating to exchanges that occurred prior to that date to aggregate $611.4 million and to range over the next 5 years from approximately $39.6 million to $60.0 million per year and decline thereafter. Further On-Going Payments by PBF Energy in respect of subsequent exchanges of PBF LLC Series A Units would be in addition to these amounts and are expected to be substantial as well. With respect to the Change of Control Payment, assuming that the market value of a share of PBF Energy’s Class A common stock equals $27.88 per share of Class A common stock (the closing price on December 31, 2016) and that LIBOR were to be 1.85%, we estimate as of December 31, 2016 that the aggregate amount of these accelerated payments would have been approximately $551.6 million if triggered immediately on such date. Our existing indebtedness may limit our ability to make distributions to PBF LLC, and in turn to PBF Energy to pay these obligations. These provisions may deter a potential sale of us to a third party and may otherwise make it less likely a third party would enter into a change of control transaction with PBF Energy or us.
The foregoing numbers are merely estimates—the actual payments could differ materially. For example, it is possible that future transactions or events could increase or decrease the actual tax benefits realized and the corresponding payments. Moreover, payments under the tax receivable agreement will be based on the tax reporting positions that PBF Energy determines in accordance with the tax receivable agreement. Neither PBF Energy nor any of its subsidiaries will 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.
Risks Related to Our Affiliation with PBFX
We depend upon PBFX for a substantial portion of our refineries’ logistics needs and have obligations for minimum volume commitments in our commercial agreements with PBFX.
We depend on PBFX to receive, handle, store and transfer crude oil and petroleum products for us from our operations and sources located throughout the United States and Canada in support of certain of our refineries under long-term, fee-based commercial agreements with us. These commercial agreements have an initial term of approximately 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.

41



PBFX’s operations are subject to all of the risks and operational hazards inherent in receiving, handling, storing and transferring crude oil and petroleum products, including: damages to its facilities, related equipment and surrounding properties caused by floods, fires, severe weather, explosions and other natural disasters and acts of terrorism; mechanical or structural failures at PBFX’s facilities or at third-party facilities on which its operations are dependent; curtailments of operations relative to severe seasonal weather; inadvertent damage to our facilities from construction, farm and utility equipment; and other hazards. Any of these events or factors could result in severe damage or destruction to PBFX’s assets or the temporary or permanent shut-down of PBFX’s facilities. If PBFX is unable to serve our logistics needs, our ability to operate our refineries and receive crude oil and distribute products could be adversely impacted, which could adversely affect our business, financial condition and results of operations.
All of the executive officers and a majority of the directors of PBF GP are also current or former officers 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 and its subsidiaries. In certain circumstances, PBF GP may refer any conflicts of interest or potential conflicts of interest between PBFX, on the one hand, and PBF Energy, on the other hand, to its conflicts committee (which must consist entirely of independent directors) for resolution, which conflicts committee must act in the best interests of the public unit 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 us.

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 the Company.
As of November 1, 2015, the Company acquired Chalmette Refining, which was in discussions with the Louisiana Department of Environmental Quality ("LDEQ") to resolve self-reported deviations from refinery operations relating to certain Clean Air Act Title V permit conditions, limits and other requirements. LDEQ commenced an enforcement action against Chalmette Refining on November 14, 2014 by issuing a Consolidated Compliance Order and Notice of Potential Penalty (the "Order") covering deviations from 2009 and 2010. Chalmette Refining and LDEQ subsequently entered into a dispute resolution agreement, the enforcement of which has been suspended while negotiations are ongoing, which may include the resolution of deviations outside the periods covered by the Order. In February 2017, Chalmette Refining and the LDEQ met to resolve the issues under the Order, including the assessment of an administrative penalty against Chalmette Refining. Although a resolution

42



has not been finalized, the administrative penalty is anticipated to be approximately $0.7 million, including beneficial environmental projects. To the extent the administrative penalty exceeds such amount, it is not expected to be material to the Company.
On January 24, 2017, in connection with a Clean Air Act inspection in May 2014 by the EPA to determine compliance with 40 CFR Subpart 68 Chemical Accident Prevention Provisions, the EPA notified the Chalmette refinery of its intent to bring an enforcement action on two (2) findings from the audit. No settlement or penalty demand has been received to date. It is possible that the EPA will assess penalties in these matters in excess of $0.1 million but any such amount is not expected to be material to the Company, individually or in the aggregate.
On December 23, 2016, the Delaware City Refinery received a Notice of Violation (“NOV”) from DNREC concerning a potential violation of the DNREC order authorizing the shipment of crude oil by barge from the refinery. The NOV alleges that DCR made shipments to locations other than the Paulsboro refinery in violation of the order and requests certain additional information. The Delaware City refinery responded to the NOV on February 7, 2017, maintaining that no violations occurred. Although no penalties have been assessed at this time, DNREC has reserved the right to assess penalties. 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 held a public hearing and dismissed the appeal, determining that the appellants did not have standing. The release of the Board decision is pending.
On February 3, 2011, the EPA sent a request for information pursuant to Section 114 of the Clean Air Act to the Paulsboro refinery with respect to compliance with EPA standards governing flaring. The refinery and the EPA have recently reached a settlement pursuant to which the Paulsboro refinery will pay a penalty of approximately $0.2 million.
On February 14, 2017, the New Jersey Department of Environmental Protection (“NJDEP”) submitted a proposed Administrative Consent Order (“ACO”) which covers air emission violations from 2013 through 2016 and work practice standards that were not subject to an affirmative defense at the Paulsboro refinery (“PRC”). In settlement of the violations, the NJDEP has proposed that PRC pay a civil administrative penalty of $0.3 million, which includes $0.1 million for a supplemental environmental project. If the offer is accepted, the remaining $0.2 million shall be remitted by PRC within 30 days of receipt of the offer. This amount is not material to the Company, individually or in the aggregate.
In connection with the acquisition of the Torrance refinery and related logistics assets, we assumed certain pre-existing environmental liabilities totaling $142.5 million as of December 31, 2016, related to certain environmental remediation obligations to address existing soil and groundwater contamination and monitoring activities, which reflects 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. Specifically, we assumed responsibility for (i) a Notice of Violation ("NOV") issued on March 12, 2015 by the Southern California Air Quality Management District ("SCAQMD") relating to self-reported Title V deviations for the Torrance Refinery for compliance year 2012, (ii) a NOV issued on March 10, 2016 for self-reported Title V deviations for the Torrance Refinery for compliance year 2013, (iii) a NOV issued on March 10, 2016 for self-reported Title V deviations for the Torrance Refinery for compliance year 2014 and (iv) a NOV issued on March 10, 2016 for self-reported Title V deviations for the Torrance Refinery for compliance year 2015. Following the closing of the acquisition, the Torrance refinery has received a number of NOVs. On September 6, 2016, a NOV was issued to the Torrance refinery by the SCAQMD for the July 11, 2016 FCCU shutdown and startup. The NOV alleges that the facility operated equipment while it bypassed associated air pollution control equipment in violation of our facility permit to operate. Opacity from FCCU 2F-7 exceeded 40 percent on July 11, 2016 and July 14, 2016, aggregate over 3 minutes in one continuous hour. In addition, on

43



October 13, 2016, a NOV was issued by the SCAQMD for an alleged nuisance created from flaring associated with the October 11, 2016 Southern California Edison power disruption. On January 4, 2017, a NOV was also issued for an alleged discharge of air contaminants from Tank 1340x113 that caused a nuisance to a considerable number of persons or to the public. On January 13, 2017, a NOV was issued by the City of Torrance for allegedly failing to report a release or threatened release of hazardous material. On January 7, 2017, the Torrance refinery allegedly experienced a third release (January 3, January 4 and January 7) in a week of untreated Naphtha gas due to the generation of higher capacity from the Coker Unit. On February 28, 2017, in review of the fire occurring at the refinery on February 18, 2017, the City of Torrance Fire Department issued a NOV to the Torrance refinery requiring the refinery to comply with California Fire Code Section 104.7.2 and provide a technical opinion and report with respect to the refinery’s process safety risk assessment plan. With the exception of the October 13th NOV, no settlement or penalty demand has been received to date with respect to these notices. The proposed penalty for the October 13th NOV is less than $0.1 million. It is possible that SCAQMD and/or the City of Torrance will assess penalties in the other matters in excess of $0.1 million but any such amount is not expected to be material to us, individually or in the aggregate.
On September 2, 2011, prior to the Company’s 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 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 personal or property damages as a result of an emission of spent catalyst, sulfur dioxide and hydrogen sulfide from the Chalmette refinery on September 6, 2010. Plaintiffs claim to have suffered injuries, symptoms, and property damage as a result of the release. Plaintiffs seek to recover unspecified damages, interest and costs. In August 2015, there was a mini-trial for four plaintiffs for property damage relating to home and vehicle cleaning. On April 12, 2016, the trial court rendered judgment limiting damages ranging from $100 to $500 for home cleaning and $25 to $75 for vehicle cleaning to the four plaintiffs. The trial court found Chalmette Refining and co-defendant Eaton Corporation (“Eaton”), to be solitarily liable for the damages. Chalmette Refining and Eaton filed an appeal in August 2016 of the judgment on the mini-trial, which appeal is pending. There is no stay pending appeal. The potential class members have not been identified as the parties are negotiating a claims process for claims such as home cleaning, vehicle cleaning, and alleged personal injury. The claims process would also include a class notice to identify potential class members. Depending upon the ultimate class size and the nature of the claims, the outcome may have a material adverse effect on the Company's financial condition, or cash flows.
The Company is subject to obligations to purchase RINs required to comply with the RFS. In late 2015, the EPA initiated enforcement proceedings against companies it believes produced invalid RINs. On October 13, 2016, PBF Holding and its subsidiaries Toledo Refining Company LLC and Delaware City Refining Company LLC were notified by the EPA that its records indicated that these entities used potentially invalid RINs. The EPA directed each of the subsidiaries to resubmit reports to remove the potentially invalid RINs and to replace the invalid RINs with valid RINs with the same D Code. The invalid RINs have been retired and the Company does not expect any settlement with the EPA to resolve this matter to be material.
On February 14, 2017, the plaintiff in Adam Trotter v. ExxonMobil Corp., ExxonMobil Oil Corp., ExxonMobil Refining and Supply Company, et. al., filed a civil action against the Company in the Superior Court of the State of California, County of Los Angeles, Southwest District, claiming public nuisance, battery, a violation of civil rights under 42 U.S.C. §1983, intentional infliction of emotional distress, negligence and strict liability in tort and injuries and symptoms resulting from the February 18, 2015 electrostatic precipitator ("ESP") explosion at the Torrance Refinery which was then owned and operated by Exxon. The City of Torrance and the SCAQMD are also named as defendants in the lawsuit. The Company was served with the lawsuit on February 22, 2017 and has not had an opportunity to evaluate the merits of plaintiff’s claims. To the extent that plaintiff’s claims relate to the ESP explosion, Exxon has retained responsibility for any liabilities that would arise from the lawsuit.
On February 17, 2017, in Arnold Goldstein, et al. v. Exxon Mobil Corporation, et al., the Company’s parents, PBF Energy Inc. and PBF Energy Company LLC, the Company and the Company’s subsidiaries, PBF Energy Western Region LLC and Torrance Refining Company LLC and the manager of the Company’s Torrance refinery along with Exxon Mobil Corporation were named as defendants in a class action and representative action complaint

44



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 the Company’s acquisition in July 2016 is also referenced in the complaint. The Company was served with the lawsuit on March 1, 2017 and has not had an opportunity to evaluate the merits of the plaintiffs’ claims. 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. The Company cannot currently estimate the amount of its potential liability.
ITEM 4. MINE SAFETY DISCLOSURE
None.


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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
We are a privately-owned company with no established public trading market for our membership units.
Holders
At December 31, 2016, 100% of our outstanding membership interests was held by PBF LLC. PBF Finance had 100 shares of common stock outstanding, all of which were held by us. None of the membership interests are publicly traded, and none were issued or sold in 2016.
Dividend and Distribution Policy
We made cash distributions to PBF LLC in the amount of $139.4 million during 2016, which in turn made cash distributions (including tax distributions) of an equivalent amount to its members including PBF Energy.
We currently intend to make quarterly cash distributions in amounts sufficient for PBF LLC to make tax distributions to its members and may make additional distributions to the extent necessary for PBF Energy to declare and pay a quarterly cash dividend of approximately $0.30 per share on its Class A common stock. The declaration, amount and payment of this and any other future distributions by us will be at the sole discretion of our board of directors and the board of directors of PBF Energy, which is the sole managing member of our sole member (PBF LLC), and we are not obligated under any applicable laws, governing documents or any contractual agreements with PBF LLC's existing owners or otherwise to declare or pay any dividends or other distributions (other than the obligations of PBF LLC to make tax distributions to its members).
We are a holding company and all of our operations are conducted through our subsidiaries. We have no independent means of generating revenue other than through assets owned by our subsidiaries. In order for us to make any distributions, we will need to cause our subsidiaries to make distributions to us. We and our subsidiaries are generally prohibited under Delaware law from making a distribution to a member to the extent that, at the time of the distribution, after giving effect to the distribution, liabilities of the limited liability company (with certain exceptions) exceed the fair value of its assets. As a result, we may be unable to obtain cash from our subsidiaries to satisfy our obligations and make distributions to PBF LLC.
Our ability to pay dividends and make distributions to PBF LLC is, and in the future may be, limited by covenants in our Revolving Loan, our Senior Secured Notes and other debt instruments. Subject to certain exceptions, the Revolving Loan and the indentures governing the Senior Secured Notes prohibit us from making distributions to PBF LLC if certain defaults exist. In addition, both the indentures and the Revolving Loan contain additional restrictions limiting our ability to make distributions to PBF LLC.
Based upon our operating results for the year ended December 31, 2016, we were permitted, under our Revolving Loan, Senior Secured Notes and other debt instruments, to make distributions to PBF LLC so that PBF LLC could make tax distributions to its members and make quarterly distributions to its members in an amount sufficient for PBF Energy to declare and pay a quarterly dividend of $0.30 per share on its Class A common stock. Our ability to comply with the foregoing limitations and restrictions is, to a significant degree, subject to our operating results, which are dependent on a number of factors outside of our control. As a result, we cannot assure you that we will be able to continue to make distributions. See “Item 1A. Risk Factors”
PBF Holding paid $139.4 million in distributions to PBF LLC during the year ended December 31, 2016. PBF LLC used $123.4 million of this amount in total to make four separate non-tax distributions of $0.30 per unit ($1.20 per unit in total) to its members, of which $117.5 million was distributed to PBF Energy and the balance was distributed to PBF LLC’s other members. PBF Energy used this $117.5 million to pay four separate equivalent

46



cash dividends of $0.30 per share of Class A common stock on November 22, 2016, August 23, 2016, May 31, 2016, and March 8, 2016. PBF LLC used the remaining $16.0 million distributions from PBF Holding to make tax distributions to its members, including to PBF Energy.
ITEM 6. SELECTED FINANCIAL DATA
The following table presents selected historical consolidated financial and other data of PBF Holding. The selected historical consolidated financial data for each of the fiscal years ended as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016 have been derived from our audited consolidated financial statements, included in this Annual Report on Form 10-K. The selected historical consolidated financial data as of December 31, 2014, 2013 and 2012 and for the years ended December 31, 2013 and 2012 have been derived from the audited financial statements of PBF Holding 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 Holding only include the results of operations for Chalmette and Torrance 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 this Annual Report on Form 10-K.

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The following tables reflect our financial and operating highlights (amounts in thousands) for the years ended December 31, 2016, 2015, 2014, 2013 and 2012.
 
 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
 
2013
 
2012
Statement of operations data:
 
 
 
 
 
 
 
 
 
 
Revenues
 
$
15,908,537

 
$
13,123,929

 
$
19,828,155

 
$
19,151,455

 
$
20,138,687

Costs, expenses and other:
 
 
 
 
 
 
 
 
 
 
Cost of sales, excluding depreciation
 
13,765,088

 
11,611,599

 
18,514,054

 
17,803,314

 
18,269,078

Operating expenses, excluding depreciation
 
1,390,582

 
889,368

 
880,701

 
812,652

 
738,824

General and administrative expenses (1)
 
149,643

 
166,904

 
140,150

 
95,794

 
120,443

Equity (income) loss in investee
 
(5,679
)
 

 

 

 

Loss (gain) on sale of asset
 
11,374

 
(1,004
)
 
(895
)
 
(183
)
 
(2,329
)
Depreciation and amortization expense
 
209,840

 
191,110

 
178,996

 
111,479

 
92,238

Income (loss) from operations
 
387,689

 
265,952

 
115,149

 
328,399

 
920,433

Other income (expense):
 
 
 
 
 
 
 
 
 
 
Change in fair value of contingent consideration
 

 

 

 

 
(2,768
)
Change in fair value of catalyst lease
 
1,422

 
10,184

 
3,969

 
4,691

 
(3,724
)
Interest expense, net
 
(129,536
)
 
(88,194
)
 
(98,001
)
 
(94,214
)
 
(108,629
)
Income before income taxes
 
259,575

 
187,942

 
21,117

 
238,876

 
805,312

Income tax expense
 
23,689

 
648

 

 

 

Net Income
 
235,886

 
187,294

 
21,117

 
238,876

 
805,312

Less income attributable to noncontrolling interest
 
269

 
274

 

 

 

Net income attributable to PBF Holding LLC
 
$
235,617

 
$
187,020

 
$
21,117

 
$
238,876

 
$
805,312

 
 
 
 
 
 
 
 
 
 
 
Balance sheet data (at end of period) :
 
 
 
 
 
 
 
 
 
 
Total assets
 
$
6,566,897

 
$
5,082,722

 
$
4,013,762

 
$
4,192,504

 
$
4,085,264

Total debt (2)
 
1,601,836

 
1,272,937

 
750,349

 
747,576

 
729,980

Total equity
 
2,588,933

 
1,821,284

 
1,630,516

 
1,772,153

 
1,751,654

Other financial data :
 
 
 
 
 
 
 
 
 
 
Capital expenditures (3)
 
$
1,498,191

 
$
979,481

 
$
625,403

 
$
415,702

 
$
222,688

 
(1)
Includes acquisition related expenses consisting primarily of consulting and legal expenses related to the Torrance Acquisition and other pending and non-consummated acquisitions of $13.6 million in 2016, as well as the Chalmette Acquisition and other pending and non-consummated acquisitions of $5.8 million in 2015.
(2)
Total debt, excluding debt issuance costs and affiliate notes payable, includes current maturities and our Delaware Economic Development Authority Loan (which was fully converted to a grant as of December 31, 2016).
(3)
Includes expenditures for construction in progress, property, plant and equipment (including railcar purchases), deferred turnaround costs and other assets, excluding the proceeds from sales of assets.

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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 REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains certain “forward-looking statements” of expected future developments that involve risk and uncertainties. You can identify forward-looking statements because they contain words such as “believes,” “expects,” “may,” “should,” “seeks,” “approximately,” “intends,” “plans,” “estimates,” or “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 expectations regarding future industry trends are forward-looking statements. In addition, we, through our senior management, from time to time make forward-looking public statements concerning our expected future operations and performance and other developments. These forward-looking statements are subject to risks and uncertainties that may change at any time, and, therefore, our actual results may differ materially from those that we expected. We derive many of our forward-looking statements from our operating budgets and forecasts, which are based upon many detailed assumptions. While we believe that our assumptions are reasonable, we caution that it is very difficult to predict the impact of known factors, and, of course, it is impossible for us to anticipate all factors that could affect our actual results.
Important factors that could cause actual results to differ materially from our expectations, which we refer to as “cautionary statements,” are disclosed under “Item 1A. Risk Factors,” and “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Annual Report on Form 10-K. All forward-looking information in this Annual Report on Form 10-K and subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements. Some of the factors that we believe could affect our results include:
supply, demand, prices and other market conditions for our products, including volatility in commodity prices;
 the effects of competition in our markets;
changes in currency exchange rates, interest rates and capital costs;
 adverse developments in our relationship with both our key employees and unionized employees;
our ability to operate our businesses efficiently, manage capital expenditures and costs (including general and administrative expenses) and generate earnings and cash flow;
our substantial indebtedness;
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 or ability to make distributions;
our assumptions regarding payments arising under PBF Energy's tax receivable agreement and other arrangements relating to PBF Energy;
our expectations and timing with respect to our acquisition activity;

49



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 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 effectiveness of our crude oil sourcing strategies, including our crude by rail strategy and related commitments;
adverse impacts related to recent legislation by the federal government lifting the restrictions on exporting U.S. crude oil;
adverse impacts from changes in our regulatory environment, such as the effects of compliance with the California Global Warming Solutions Act (also referred to as "AB32"), 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 the completed acquisitions of Chalmette Refining and related logistics assets and the Torrance refinery and related logistics assets into our business and realize the benefits from such acquisitions;
liabilities arising from the Chalmette Acquisition and/or Torrance Acquisition that are unforeseen or exceed our expectations; 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 Holding and PBF Finance. PBF Finance is a wholly-owned subsidiary of PBF Holding. PBF Holding is a wholly-owned subsidiary of PBF LLC and is the parent company for PBF LLC's refinery operating subsidiaries. PBF Holding is an indirect subsidiary of PBF Energy, which is the sole managing member of, and owner of an equity interest representing approximately 96.5% of the outstanding economic interests in PBF LLC as of December 31, 2016. PBF Energy operates and controls all of the business and affairs and consolidates the financial results of PBF LLC and its subsidiaries. PBF Holding, together with its consolidated subsidiaries, owns and operates oil refineries and related facilities in North America.
Unless the context indicates otherwise, the terms “we,” “us,” and “our” refer to PBF Holding and its consolidated subsidiaries.

50



Executive Summary
We were formed in March 2008 to pursue the acquisitions of crude oil refineries and downstream assets in North America. We currently own and operate 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. Our five oil refineries are all engaged in the refining of crude oil and other feedstocks into petroleum products, and are aggregated into one reportable segment.
Factors Affecting Comparability
Our results over the past three years have been affected by the following events, the understanding of which will aid in assessing the comparability of our period to period financial performance and financial condition.
Torrance Acquisition
On July 1, 2016, we acquired from ExxonMobil and its subsidiary, Mobil Pacific Pipeline Company (together, the “Torrance Sellers”), the Torrance refinery and related logistics assets. The Torrance refinery, located on 750 acres in Torrance, California, is a high-conversion 155,000 barrel per day, delayed-coking refinery with a Nelson Complexity 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 purchase price and fair value allocation may be subject to adjustment pending completion of the final valuation which was in process as of December 31, 2016. In addition, we assumed certain pre-existing environmental and regulatory emission credit obligations in connection with the Torrance Acquisition. The transaction was financed through a combination of cash on hand, including proceeds from PBF Energy's October 2015 Equity Offering and the 2023 Senior Secured Notes offering, and borrowings under our Revolving Loan.
TVPC Contribution Agreement
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, PBF Holding distributed to PBF LLC and PBFX acquired from PBF LLC 50% of the issued and outstanding limited liability company interests of Torrance Valley Pipeline Company LLC (“TVPC”), whose assets consist of the 189 mile San Joaquin Valley Pipeline system, including the M55, M1 and M70 Pipeline System, including 11 pipeline stations with storage capability and truck unloading capability at two of the stations (collectively, the “Torrance Valley Pipeline”). 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 completed in August 2016.

PBFX Operating Company LP ("PBFX Op Co"), PBFX’s wholly-owned subsidiary, serves as TVPC's managing member. PBFX, through its ownership of PBFX Op Co, has the sole ability to direct the activities of

51



TVPC that most significantly impact its economic performance. PBFX, and not PBF Holding, is considered to be the primary beneficiary for accounting purposes, and as a result fully consolidates the net assets and results of operations of TVPC, with the 50% of TVPC it does not own recorded as noncontrolling interests and net income attributable to noncontrolling interests. Accordingly, PBF Holding deconsolidated TVPC and has recognized an equity investment in TVPC for its 50% noncontrolling interest.

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 ours.
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.
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 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. The commitment fees on the unused portions, the interest rate on advances and the fees for letters of credit have also been reduced in the amended and restated Revolving Loan.
As noted in "Note 3 - Acquisitions" to the consolidated financial statements, we drew down under our Revolving Loan to partially fund the Torrance Acquisition and $350.0 million remains outstanding as of December 31, 2016.
Senior Secured Notes Offering
On November 24, 2015, we and PBF Finance Corporation issued $500.0 million in aggregate principal amount of the 2023 Senior Secured Notes. The net proceeds were approximately $490.0 million after deducting the initial purchasers’ discount and offering expenses. We used the proceeds for general corporate purposes, including to fund a portion of the purchase price for the Torrance Acquisition.
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 the Rail Facility was to fund the acquisition by PBF Rail of coiled and insulated crude tank cars and non-coiled and non-insulated general purpose crude tank cars before December 2015.

52



As noted in "Note 9 - Credit Facility and Long-term Debt" to the consolidated financial statements, the Rail Facility was amended on two occasions in 2015 and 2016 and 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 DVB Bank SE (“DVB”). The PBF Rail Term Loan amortizes monthly over its five year term and bears interest at the one month LIBOR plus 2.0%. As security for the PBF Rail Term Loan, PBF Rail pledged, among other things, (i) certain eligible railcars; (ii) the Debt Service Reserve Account; and (iii) our 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.
J. Aron Intermediation Agreements
On May 29, 2015, we entered into amended and restated inventory intermediation agreements with J. Aron pursuant to which certain terms of the existing inventory intermediation agreements were amended, including, among other things, pricing and an extension of the term for a period of two years from the original expiry date of July 1, 2015, subject to certain early termination rights. In addition, the A&R Intermediation Agreements include one-year renewal clauses by mutual consent of both parties. The A&R Intermediation Agreements have not been renewed and are scheduled to expire on July 1, 2017. If we are unable to negotiate an extension with J. Aron or enter into an alternative intermediation agreement, we will have to repurchase the inventories outstanding under the A&R Intermediation Agreement at that time.
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. 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.
Renewable Fuels Standard
We have seen fluctuations in the cost of renewable fuel credits, known as RINs, required for compliance with the RFS. We incurred approximately $347.5 million in RINs costs during the year ended December 31, 2016 as compared to $171.6 million and $115.7 million during the years ended December 31, 2015 and 2014, 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.

53



Agreements with PBFX
PBFX is a fee-based, growth-oriented, publicly traded Delaware master limited partnership formed by our indirect parent company, PBF Energy, to own or lease, operate, develop and acquire crude oil and refined petroleum products terminals, pipelines, storage facilities and similar logistics assets. PBFX engages in the receiving, handling, storing and transferring of crude oil, refined products and intermediates from sources located throughout the United States and Canada for PBF Energy in support of certain of its refineries.
Beginning with the completion of the PBFX Offering, we have entered into a series of agreements with PBFX, including contribution, commercial and operational agreements. Each of these agreements and their impact to our operations is described in "Item 1. Business" and "Note 12 - Related Party Transactions" in our consolidated financial statements.
A summary of revenue and expense transactions with PBFX is as follows (in millions):
 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
Revenues under affiliate agreements:
 
 
 
 
 
 
Services Agreement
 
$
5.1

 
$
4.5

 
$
2.3

Omnibus Agreement
 
4.8

 
5.3

 
3.6

Total expenses under commercial agreements
 
175.4

 
142.1

 
59.4

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.

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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 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 the Paulsboro, Delaware City, Toledo, Chalmette and Torrance 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 and ExxonMobil. We have been purchasing up to approximately 100,000 bpd of crude oil from Saudi Aramco that is processed at Paulsboro. We have 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. Additionally, we have a supply agreement with ExxonMobil for approximately 60,000 bpd of crude oil that can be processed at our Torrance refinery. 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.
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 transferred 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

55



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, electricity and chemicals.
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 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 (consisting of jet fuel, ULSD and ultra-low sulfur heating oil), 1% 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 3% other). For this reason, we believe the Dated Brent (NYH) 2-1-1 is an appropriate benchmark industry refining margin. The majority of Delaware City revenues are generated off NYH-based market prices.
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 65% to 70% of total throughput. The remaining throughput consists of sweet crude oil and other feedstocks and blendstocks. In addition, we have the capability to process a significant volume of light, sweet crude oil depending on market conditions. Our total throughput costs have historically priced at a discount to Dated Brent; and
as a result of the heavy, sour crude slate processed at Delaware City, we produce lower value products including sulfur, carbon dioxide and petroleum coke. These products are priced at a significant discount to gasoline, ULSD and heating oil 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 38% gasoline, 32% distillate (comprised of jet fuel, ULSD and ultra-low sulfur heating oil), 5% high-value Group I lubricants and 10% asphalt, with the remaining portion of the product slate comprised of lower-value products (6% black oil, 4% 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 has generally processed a slate of primarily medium and heavy sour crude oils, which has historically constituted approximately 70% to 80% of total throughput. The remaining throughput consists of sweet crude oil and other feedstocks and blendstocks;

56



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 gasoline and heating oil 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 gasoline and distillates.
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 crude oil and refer to this benchmark as the WTI (Chicago) 4-3-1 benchmark refining margin. Our Toledo refinery has a product slate of approximately 54% gasoline, 35% distillate (comprised of jet fuel and ULSD), 5% high-value petrochemicals (including nonene, tetramer, benzene, xylene and toluene) with the remaining portion of the product slate comprised of lower-value products (5% LPGs and 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 48% gasoline, 31% distillate (comprised of ULSD, heating oil, and light cycle oil), 5% 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 coke and 1% 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 60% to 70% 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 gasoline and heating oil and represent approximately 4% to 6% of our total production volume.
A project underway to restart an idled naphtha hydrotreater, reformer and light-ends recovery unit will increase high-octane, ultra-low sulfur reformate and chemicals production. A new crude oil tank being constructed will allow gasoline and diesel export opportunities and reduce Renewable Identification Numbers (“RINs”) compliance costs. Both projects are expected to be completed in the third quarter of 2017.

57



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 62% gasoline and 25% distillate (comprised of jet fuel, ULSD and marine diesel) with the remaining portion of the product slate comprised of lower-value products (8% petroleum coke, 2% LPG, 2% black oil and 1% 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.

58



Results of Operations
The following tables reflect our consolidated financial and operating highlights for the years ended December 31, 2016, 2015 and 2014 (amounts in thousands).  
 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
Revenue
 
$
15,908,537

 
$
13,123,929

 
$
19,828,155

Cost of sales, excluding depreciation
 
13,765,088

 
11,611,599

 
18,514,054

 
 
2,143,449

 
1,512,330

 
1,314,101

Operating expenses, excluding depreciation
 
1,390,582

 
889,368

 
880,701

General and administrative expenses
 
149,643

 
166,904

 
140,150

Equity (income) loss in investee
 
(5,679
)
 

 

Loss (gain) on sale of assets
 
11,374

 
(1,004
)
 
(895
)
Depreciation and amortization expense
 
209,840

 
191,110

 
178,996

Income from operations
 
387,689

 
265,952

 
115,149

Change in fair value of catalyst leases
 
1,422

 
10,184

 
3,969

Interest expense, net
 
(129,536
)
 
(88,194
)
 
(98,001
)
Income before income taxes
 
259,575

 
187,942

 
21,117

Income tax expense
 
23,689

 
648

 

Net Income
 
235,886

 
187,294

 
21,117

Less: net income attributable to noncontrolling interest
 
269

 
274

 

Net income attributable to PBF Holding LLC
 
$
235,617

 
$
187,020

 
$
21,117

 
 
 
 
 
 
 
Gross margin
 
$
548,862

 
$
441,539

 
$
267,987

Gross refining margin (1)
 
2,143,449

 
1,512,330

 
1,314,101

 ——————————

(1) 
See Non-GAAP financial measures below.

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Operating Highlights
 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
 
 
 
 
 
 
 
Key Operating Information
 
 
 
 
 
 
Production (bpd in thousands)
 
734.3

 
511.9

 
452.1

Crude oil and feedstocks throughput (bpd in thousands)
 
727.7

 
516.4

 
453.1

Total crude oil and feedstocks throughput (millions of barrels)
 
266.4

 
188.4

 
165.4

Gross margin per barrel of throughput
 
$
2.06

 
$
2.34

 
$
1.60

Gross refining margin, excluding special items, per barrel of throughput (1)
 
$
6.09

 
$
10.29

 
$
12.11

Refinery operating expense, excluding depreciation, per barrel of throughput
 
$
5.22

 
$
4.72

 
$
5.34

 
 
 
 
 
 
 
Crude and feedstocks (% of total throughput) (2)
 
 
 
 
 
 
Heavy Crude
 
26
%
 
14
%
 
14
%
Medium Crude
 
37
%
 
49
%
 
44
%
Light Crude
 
25
%
 
26
%
 
33
%
Other feedstocks and blends
 
12
%
 
11
%
 
9
%
Total throughput
 
100
%
 
100
%
 
100
%
 
 
 
 
 
 
 
Yield (% of total throughput)
 
 
 
 
 
 
Gasoline and gasoline blendstocks
 
50
%
 
49
%
 
47
%
Distillates and distillate blendstocks
 
31
%
 
35
%
 
36
%
Lubes
 
1
%
 
1
%
 
2
%
Chemicals
 
3
%
 
3
%
 
3
%
Other
 
15
%
 
12
%
 
12
%
Total yield
 
100
%
 
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,
 
 
2016
 
2015
 
2014
 
 
(dollars per barrel, except as noted)
Dated Brent Crude
 
$
43.91

 
$
52.56

 
$
98.95

West Texas Intermediate (WTI) crude oil
 
$
43.34

 
$
48.71

 
$
93.28

Light Louisiana Sweet (LLS) crude oil
 
$
45.03

 
$
52.36

 
$
96.92

Alaska North Slope (ANS) crude oil
 
$
43.67

 
$
52.44

 
$
97.52

Crack Spreads
 
 
 
 
 
 
Dated Brent (NYH) 2-1-1
 
$
13.49

 
$
16.35

 
$
12.92

WTI (Chicago) 4-3-1
 
$
12.38

 
$
17.91

 
$
15.92

LLS (Gulf Coast) 2-1-1
 
$
10.75

 
$
14.39

 
$
16.95

ANS (West Coast) 4-3-1
 
$
16.46

 
$
26.46

 
$
15.59

Crude Oil Differentials
 
 
 
 
 
 
Dated Brent (foreign) less WTI
 
$
0.56

 
$
3.85

 
$
5.66

Dated Brent less Maya (heavy, sour)
 
$
7.36

 
$
8.45

 
$
13.08

Dated Brent less WTS (sour)
 
$
1.42

 
$
3.59

 
$
11.62

Dated Brent less ASCI (sour)
 
$
3.92

 
$
4.57

 
$
6.49

WTI less WCS (heavy, sour)
 
$
12.57

 
$
11.87

 
$
19.45

WTI less Bakken (light, sweet)
 
$
1.32

 
$
2.89

 
$
5.47

WTI less Syncrude (light, sweet)
 
$
(2.01
)
 
$
(1.45
)
 
$
2.25

WTI less ANS (light, sweet)
 
$
(0.33
)
 
$
(3.73
)
 
$
(4.24
)
Natural gas (dollars per MMBTU)
 
$
2.55

 
$
2.63

 
$
4.26

2016 Compared to 2015
Overview— Our net income was $235.9 million for the year ended December 31, 2016 compared to $187.3 million for the year ended December 31, 2015.
Our results for the year ended December 31, 2016 were positively impacted by a non-cash special item consisting of an inventory LCM adjustment of approximately $521.3 million whereas our results for the year ended December 31, 2015 were negatively impacted by an inventory LCM adjustment of approximately $427.2 million. These LCM 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 reserve, our results for the year ended December 31, 2016 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 21.2%. Revenues per barrel were $59.72 and $69.66 for the years ended December 31, 2016 and 2015, respectively, a decrease of 14.3% 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

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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 throughput 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 the 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 refineries.
Gross Margin— Gross margin, including refinery operating expenses and depreciation, totaled $548.9 million, or $2.06 per barrel of throughput, for the year ended December 31, 2016, compared to $441.5 million, or $2.34 per barrel of throughput for the year ended December 31, 2015, an increase of approximately $107.3 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, 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 adjustment of approximately $521.3 million resulting from the change in crude oil and refined product prices from the end of 2015 to the end of 2016 which, in addition to remaining below historical costs, increased since the prior year. The non-cash LCM 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 December 31, 2016 as compared to the same period in 2015. Reductions in these benchmark crude differentials typically result in higher crude costs and negatively impact our earnings.

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Operating Expenses— Operating expenses totaled $1,390.6 million, or $5.22 per barrel of throughput, for the year ended December 31, 2016 compared to $889.4 million, or $4.72 per barrel of throughput, for the year ended December 31, 2015, an increase of $501.2 million, or 56.4%. The increase in operating expenses was mainly attributable to the operating expenses associated with the Chalmette and Torrance refineries and related logistics assets. For the year ended December 31, 2016 and for the period from its acquisition on November 1, 2015 to December 31, 2015, the Chalmette refinery and related logistics assets incurred operating expenses of approximately $343.9 million and $52.1 million, respectively. In the period from its acquisition on July 1, 2016 to December 31, 2016, the Torrance refinery and related logistics assets incurred operating expenses of approximately $250.5 million. Total operating expenses at our refineries, excluding our Chalmette and Torrance refineries, decreased slightly for the year ended December 31, 2016, primarily due to lower energy costs and maintenance costs. The reduction in energy costs was mainly due to lower natural gas prices while the reduction in maintenance costs was mainly due to timing of repairs and certain non-recurring maintenance costs incurred in 2015. These reductions were partially offset by higher employee-related expenses, primarily attributable to merit increases in salaries.
General and Administrative Expenses— General and administrative expenses totaled $149.6 million for the year ended December 31, 2016, compared to $166.9 million for the year ended December 31, 2015, a decrease of $17.3 million or 10.3%. The decrease in general and administrative expenses primarily relates to reduced employee related expenses of $39.3 million mainly due to lower incentive compensation expenses, partially offset by $12.9 million in additional outside services and other costs to support our acquisitions and related integration activities, and an increase of $9.1 million in equity compensation expense related to incremental grants in 2016 and accelerated vesting of awards due to retirements. Our general and administrative expenses are comprised of the personnel, facilities and other infrastructure costs necessary to support our refineries.
Loss (gain) on Sale of Assets— There was a loss of $11.4 million on the sale of assets for the year ended December 31, 2016 relating to the sale of non-refining assets as compared to a gain of $1.0 million for the year ended December 31, 2015 which related to the sale of railcars which were subsequently leased back.
Depreciation and Amortization Expense— Depreciation and amortization expense totaled $209.8 million for the year ended December 31, 2016, compared to $191.1 million for the year ended December 31, 2015, an increase of $18.7 million. The increase was a result of additional depreciation expense associated with the assets acquired in the Chalmette and Torrance Acquisitions and a general increase in our fixed asset base due to capital projects and turnarounds completed since 2015.
Change in Fair Value of Catalyst Leases— Change in the fair value of catalyst leases represented a gain of $1.4 million for the year ended December 31, 2016, compared to a gain of $10.2 million for the year ended December 31, 2015. These gains 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.
Interest Expense, net— Interest expense totaled $129.5 million for the year ended December 31, 2016, compared to $88.2 million for the year ended December 31, 2015, an increase of $41.3 million. This increase is mainly attributable to higher interest costs associated with the issuance of the 2023 Senior Secured Notes in November 2015, increased interest expense related to the affiliate notes payable and the drawdown on our Revolving Loan to partially fund the Torrance Acquisition in July 2016, partially offset by lower letter of credit fees. Interest expense includes interest on long-term debt and notes payable, costs related to the sale and leaseback of our precious metals catalyst, financing costs associated with the A&R Inventory Intermediation Agreements with J. Aron, letter of credit fees associated with the purchase of certain crude oils, and the amortization of deferred financing costs.
Income Tax Expense— As PBF Holding is a limited liability company treated as a “flow-through” entity for income tax purposes our consolidated financial statements generally do not include a benefit or provision for income taxes for the years ended December 31, 2016 and 2015 apart from the income tax attributable to two subsidiaries of Chalmette Refining and a wholly-owned Canadian subsidiary, PBF Energy Limited ("PBF Ltd.") that are treated as C-Corporations for income tax purposes. The two Chalmette subsidiaries incurred approximately

63



$1.4 million of income tax expense and PBF Holding incurred income tax benefit of approximately $8.4 million attributable to PBF Ltd for the year ended December 31, 2016. In addition, we recorded $30.7 million of incremental income tax expense in 2016 relating to a correction of prior period income taxes.
2015 Compared to 2014
Overview—Net income was $187.3 million for the year ended December 31, 2015 compared to $21.1 million for the year ended December 31, 2014.
Our results for the year ended December 31, 2015 were negatively impacted by a non-cash special item consisting of an inventory LCM adjustment of approximately $427.2 million whereas our results for the year ended December 31, 2014 were negatively impacted by an inventory LCM adjustment of approximately $690.1 million. These LCM charges were recorded due to significant declines in the price of crude oil and refined products in 2015 and 2014. Our throughput rates during the year ended December 31, 2015 compared to December 31, 2014 were higher due to the acquisition of the Chalmette refinery on November 1, 2015 as well as an approximate 40-day plant-wide planned turnaround at our Toledo Refinery completed in the fourth quarter of 2014. Our results for the year ended December 31, 2015 were positively impacted by higher throughput volumes, lower non-cash special items for LCM charges and higher crack spreads for the East Coast and in the Mid-Continent partially offset by unfavorable movements in certain crude differentials.
Revenues—Revenues totaled $13.1 billion for the year ended December 31, 2015 compared to $19.8 billion for the year ended December 31, 2014, a decrease of approximately $6.7 billion, or 33.8%. Revenues per barrel were $69.66 and $119.89 for the years ended December 31, 2015 and 2014, respectively, a decrease of 41.9% directly related to lower hydrocarbon commodity prices. For the year ended December 31, 2015, the total throughput rates in the 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. For the year ended December 31, 2014, the total throughput rates at our East Coast and Mid-Continent refineries averaged approximately 325,300 bpd, and 127,800 bpd, respectively. The increase in throughput rates at our East Coast refineries in 2015 compared to 2014 was primarily due to higher run rates as a result of favorable market economics partially offset by unplanned downtime at our Delaware City refinery in 2015. The increase in throughput rates at our Mid-Continent refinery in 2015 compared to 2014 was primarily due to an approximate 40-day plant-wide planned turnaround completed in the fourth quarter of 2014. 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. For the year ended December 31, 2014, the total refined product barrels sold at our East Coast and Mid-Continent refineries averaged approximately 350,800 bpd and 144,100 bpd, respectively. Total refined product barrels sold were higher than throughput rates, reflecting sales from inventory as well as sales and purchases of refined products outside the refineries.
Gross Margin— Gross margin, including refinery operating expenses and depreciation, totaled $441.5 million, or $2.34 per barrel of throughput, for the year ended December 31, 2015, compared to $268.0 million, or $1.60 per barrel of throughput, for the year ended December 31, 2014, an increase of $173.6 million. Gross refining margin (as defined below in Non-GAAP Financial Measures) totaled $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 compared to $1,314.1 million, or $7.94 per barrel of throughput ($2,004.2 million, or $12.11 per barrel of throughput excluding the impact of special items) for the year ended December 31, 2014, an increase of $198.2 million and a decrease of $64.7 million excluding special items. Excluding the impact of special items, gross refining margin decreased due to the narrowing of certain crude differentials partially offset by higher throughput rates, reflecting the impact from the Chalmette Acquisition, and favorable movements in crack spreads. Excluding the impact of special items, gross margin was relatively consistent with the prior year.
Average industry refining margins in the U.S. Mid-Continent were generally improved during the year ended December 31, 2015, as compared to the same period in 2014. The WTI (Chicago) 4-3-1 industry crack spread was

64



approximately $17.91 per barrel or 12.5% higher in the year ended December 31, 2015, as compared to the same period in 2014. The price of WTI versus Dated Brent and other crude discounts narrowed during the year ended December 31, 2015, and our refinery specific crude slate in the Mid-Continent faced an adverse WTI/Syncrude differential, which averaged a premium of $1.45 per barrel for the year ended December 31, 2015 as compared to a discount of $2.25 per barrel in the same period in 2014.
The Dated Brent (NYH) 2-1-1 industry crack spread was approximately $16.35 per barrel, or 26.5% higher in the year ended December 31, 2015, as compared to the same period in 2014. However, the WTI/Dated Brent differential was $1.81 lower in the year ended December 31, 2015, as compared to the same period in 2014, and the WTI/Bakken differential was $2.58 per barrel less favorable for the same periods. The Dated Brent/Maya differential was approximately $4.63 per barrel less favorable in the year ended December 31, 2015 as compared to the same period in 2014. Additionally, the decrease in the Dated Brent/Maya crude differential, our proxy for the light/heavy crude differential, had a negative impact on our East Coast refineries, which can process a large slate of medium and heavy, sour crude oil that is priced at a discount to light, sweet crude oil. However, the lower flat price of crude oil during 2015 as compared to 2014 resulted in improved margins on certain lower value products we produce.
Operating Expenses—Operating expenses totaled $889.4 million, or $4.72 per barrel of throughput, for the year ended December 31, 2015 compared to $880.7 million, or $5.34 per barrel of throughput, for the year ended December 31, 2014, an increase of $8.7 million, or 1.0%. The increase in operating expenses is mainly attributable to an increase of approximately $45.8 million in maintenance costs, primarily driven by the Chalmette Acquisition in 2015 and general repairs at the Delaware City and Paulsboro refineries, an increase of $17.3 million in employee compensation primarily driven by additional headcount and $14.9 million of increased catalyst and chemicals costs partially offset by net reduced energy and utility costs of $64.4 million due to lower natural gas prices and $4.4 million lower other fixed charges. Our operating expenses principally consist of salaries and employee benefits, maintenance, energy and catalyst and chemicals costs at our refineries. Although operating expenses increased on an overall basis, refinery operating expenses per barrel decreased as a result of higher throughput volumes.
General and Administrative Expenses—General and administrative expenses totaled $166.9 million for the year ended December 31, 2015, compared to $140.2 million for the year ended December 31, 2014, an increase of $26.7 million or 19.1%. The increase in general and administrative expenses primarily relates to higher employee compensation expense of $13.3 million, mainly related to higher headcount and higher incentive compensation expenses, higher outside services fees of $3.0 million related to professional, legal and engineering consultants attributable to the Chalmette Acquisition, and higher equity compensation expense of $1.3 million. Our general and administrative expenses are comprised of the personnel, facilities and other infrastructure costs necessary to support our refineries.
Gain on Sale of Assets—Gain on sale of assets for the year ended December 31, 2015 was $1.0 million which related to the sale of railcars which were subsequently leased back to us, compared to a gain of $0.9 million for the year ended December 31, 2014, for the sale of railcars.
Depreciation and Amortization Expense—Depreciation and amortization expense totaled $191.1 million for the year ended December 31, 2015, compared to $179.0 million for the year ended December 31, 2014, an increase of $12.1 million. The increase was largely driven by our increased fixed asset base due to capital projects and turnarounds completed during 2014 and 2015 as well as the acquisition of the Chalmette refinery in 2015. These general increases were partially offset by reduction in impairment charges. In 2014, we recorded a $28.5 million impairment related to an abandoned capital project at our Delaware City refinery during that year whereas we did not record any significant impairment charges in the year ended December 31, 2015.
Change in Fair Value of Catalyst Leases— Change in the fair value of catalyst leases represented a gain of $10.2 million for the year ended December 31, 2015, compared to a gain of $4.0 million for the year ended December 31, 2014. This gain relates 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.

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Interest Expense, net— Interest expense totaled $88.2 million for the year ended December 31, 2015, compared to $98.0 million for the year ended December 31, 2014, a decrease of $9.8 million. The decrease is mainly attributable to the termination of our crude and feeedstock supply agreement with MSCG, effective July 31, 2014. Interest expense includes interest on long-term debt including the Senior Secured Notes and credit facility, costs related to the sale and leaseback of our precious metals catalyst, interest expense incurred in connection with our crude and feedstock supply agreement with Statoil up to its expiration on December 31, 2015, financing costs associated with the Inventory Intermediation Agreements with J. Aron, letter of credit fees associated with the purchase of certain crude oils, and the amortization of deferred financing fees.
Income Tax Expense— As PBF Holding is a limited liability company treated as a “flow-through” entity for income tax purposes our consolidated financial statements do not include a benefit or provision for income taxes for the years ended December 31, 2015 and 2014 apart from the income tax attributable to two subsidiaries of Chalmette Refining that are treated as C-Corporations for income tax purposes.
Non-GAAP Financial Measures
Management uses certain financial measures to evaluate our operating performance that are calculated and presented on the basis of methodologies other than in accordance with GAAP (“Non-GAAP”). These measures should not be considered a substitute for, or superior to, measures of financial performance prepared in accordance with GAAP, and our calculations thereof may not be comparable to similarly entitled measures reported by other companies.
Special Items
The non-GAAP measures presented include EBITDA excluding special items, and gross refining margin excluding special items. The special items for the periods presented relate to an LCM adjustment. LCM is a GAAP guideline related to inventory valuation that requires inventory to be stated at the lower of cost or market. Our inventories are stated at the lower of cost or market. Cost is determined by the last-in, first-out (“LIFO”) inventory valuation methodology, in which the most recently incurred costs are charged to cost of sales and inventories are valued at base layer acquisition costs. Market is determined based on an assessment of the current estimated replacement cost and net realizable selling price of the inventory. In periods where the market price of our inventory declines substantially, cost values of inventory may exceed market values. In such instances, we record an adjustment to write down the value of inventory to market value in accordance with GAAP. In subsequent periods, the value of inventory is reassessed and a LCM adjustment is recorded to reflect the net change in the LCM inventory reserve between the prior period and the current period. Although we believe that non-GAAP financial measures, excluding the impact of special items, provide useful supplemental information to investors regarding the results and performance of our business and allow for helpful period-over-period comparisons, such non-GAAP measures should only be considered as a supplement to, and not as a substitute for, or superior to, the financial measures prepared in accordance with GAAP.
Gross Refining Margin
Gross refining margin is defined as gross margin excluding depreciation and operating expense related to the refineries. We believe gross refining margin is an important measure of operating performance and provides useful information to investors because it is a helpful metric comparison to the industry refining margin benchmarks, as the refining margin benchmarks do not include a charge for refinery operating expenses and depreciation expense. In order to assess our operating performance, we compare our gross refining margin (revenue less cost of sales) to industry refining margin benchmarks and crude oil prices as defined in the table below.
Gross refining margin should not be considered an alternative to gross margin, operating income, net cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Gross refining margin presented by other companies may not be comparable to our presentation, since each company may define this term differently. The following table presents a reconciliation of gross refining

66



margin to the most directly comparable GAAP financial measure, gross margin, on a historical basis, as applicable, for each of the periods indicated (in thousands except per barrel amounts):
 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
 
 
$
per barrel of throughput
 
$
per barrel of throughput
 
$
per barrel of throughput
Reconciliation of gross margin to gross refining margin:
 
 
 
 
 
 
 
 
 
Gross margin
 
$
548,862

$
2.06

 
$
441,539

$
2.34

 
$
267,987

$
1.60

Add: Refinery operating expense
 
1,390,582

5.22

 
889,368

4.72

 
880,701

5.34

Add: Refinery depreciation expense
 
204,005

0.77

 
181,423

0.96

 
165,413

1.00

Gross refining margin
 
$
2,143,449

$
8.05

 
$
1,512,330

$
8.02

 
$
1,314,101

$
7.94

Special items:
 
 
 
 
 
 
 
 
 
Add: Non-cash LCM inventory adjustment (1)
 
(521,348
)
(1.96
)
 
427,226

2.27

 
690,110

4.17

Gross refining margin excluding special items
 
$
1,622,101

$
6.09

 
$
1,939,556

$
10.29

 
$
2,004,211

$
12.11

(1) During the year ended December 31, 2016, we recorded an adjustment to value our inventories to the lower of cost or market which resulted in a net pre-tax benefit of $521.3 million reflecting the change in the lower of cost or market inventory reserve from $1,117.3 million at December 31, 2015 to $596.0 million at December 31, 2016. During the year ended December 31, 2015, we recorded an adjustment to value our inventories to the lower of cost or market which resulted in a net pre-tax charge of $427.2 million reflecting the change in the lower of cost or market inventory reserve from $690.1 million at December 31, 2014 to $1,117.3 million at December 31, 2015. During the year ended December 31, 2014, we recorded an adjustment to value our inventory to the lower of cost or market which resulted in a net pre-tax charge of $690.1 million. The net impact of these LCM inventory adjustments are included in operating income, but are excluded from the operating results presented in the table in order to make such information comparable between periods.
EBITDA and Adjusted EBITDA
Our management uses EBITDA (earnings before interest, income taxes, depreciation and amortization) and Adjusted EBITDA as measures of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with our board of directors, creditors, analysts and investors concerning our financial performance. Our outstanding indebtedness for borrowed money and other contractual obligations also include similar measures as a basis for certain covenants under those agreements which may differ from the Adjusted EBITDA definition described below.
EBITDA and Adjusted EBITDA are not presentations made in accordance with GAAP and our computation of EBITDA and Adjusted EBITDA may vary from others in our industry. In addition, Adjusted EBITDA contains some, but not all, adjustments that are taken into account in the calculation of the components of various covenants in the agreements governing the Senior Secured Notes and other credit facilities. EBITDA and Adjusted EBITDA should not be considered as alternatives to operating income (loss) or net income (loss) as measures of operating performance. In addition, EBITDA and Adjusted EBITDA are not presented as, and should not be considered, an alternative to cash flows from operations as a measure of liquidity. Adjusted EBITDA is defined as EBITDA before adjustments for items such as equity-based compensation expense, gains (losses) from certain derivative activities and contingent consideration, the non-cash change in the deferral of gross profit related to the sale of certain finished products and the write down of inventory to the LCM. Other companies, including other companies in our industry, may calculate EBITDA and Adjusted EBITDA differently than we do, limiting their usefulness as a comparative measure. EBITDA and Adjusted EBITDA also have limitations as analytical tools and should not be

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considered in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations include that EBITDA and Adjusted EBITDA:
does not reflect depreciation expense or our cash expenditures, or future requirements, for capital expenditures or contractual commitments;
does not reflect changes in, or cash requirements for, our working capital needs;
does not reflect our interest expense, or the cash requirements necessary to service interest or principal payments, on our debt;
does not reflect realized and unrealized gains and losses from certain hedging activities, which may have a substantial impact on our cash flow;
does not reflect certain other non-cash income and expenses; and
excludes income taxes that may represent a reduction in available cash.
The following tables reconcile net income as reflected in our results of operations to EBITDA and Adjusted EBITDA for the periods presented (in thousands): 
 
 
 
Year Ended December 31,
 
 
 
2016
 
2015
 
2014
Reconciliation of net income to EBITDA:
 
 
 
 
 
Net income
$
235,886

 
$
187,294

 
$
21,117

Add: Depreciation and amortization expense
209,840

 
191,110

 
178,996

Add: Interest expense, net
129,536

 
88,194

 
98,001

Add: Income tax expense (benefit)
23,689

 
648

 

EBITDA
$
598,951

 
$
467,246

 
$
298,114

  Special Items:
 
 
 
 
 
Add: Non-cash LCM inventory adjustment (1)
(521,348
)
 
427,226

 
690,110

EBITDA excluding special items
$
77,603

 
$
894,472

 
$
988,224

 
 
 
 
 
 
 
 
Reconciliation of EBITDA to Adjusted EBITDA:
 
 
 
 
 
EBITDA
$
598,951

 
$
467,246

 
$
298,114

Add: Stock based compensation
18,296

 
9,218

 
6,095

Add: Non-cash LCM inventory adjustment
(521,348
)
 
427,226

 
690,110

Add: Non-cash change in fair value of catalyst lease obligations
(1,422
)
 
(10,184
)
 
(3,969
)
Adjusted EBITDA
$
94,477

 
$
893,506

 
$
990,350

(1) During the year ended December 31, 2016, we recorded an adjustment to value our inventories to the lower of cost or market which resulted in a net pre-tax benefit of $521.3 million reflecting the change in the lower of cost or market inventory reserve from $1,117.3 million at December 31, 2015 to $596.0 million at December 31, 2016. During the year ended December 31, 2015, we recorded an adjustment to value our inventories to the lower of cost or market which resulted in a net pre-tax charge of $427.2 million reflecting the change in the lower of cost or market inventory reserve from $690.1 million at December 31, 2014 to $1,117.3 million at December 31, 2015. During the year ended December 31, 2014, we recorded an adjustment to value our inventory to the lower of cost or market which resulted in a net pre-tax charge of $690.1 million. The net impact of these LCM inventory adjustments are included in operating income, but are excluded from the operating results presented in the table in order to make such information comparable between periods.
 

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Liquidity and Capital Resources
Overview
Our primary sources of liquidity are our cash flows from operations and borrowing availability under our credit facilities, as more fully described below. We believe that our cash flows from operations and available capital resources will be sufficient to meet our and our subsidiaries' capital expenditure, working capital, distribution payments and debt service requirements for the next twelve months. On July 1, 2016, we closed the Torrance Acquisition with a combination of cash on hand, including proceeds from a capital contribution made in connection with PBF Energy's October 2015 Equity Offering and our 2023 Senior Secured Notes Offering, and borrowings under our Revolving Loan. However, our ability to generate sufficient cash flow from operations depends, in part, on petroleum oil market pricing and general economic, political and other factors beyond our control. We are in compliance as of December 31, 2016 with all of the covenants, including financial covenants, in all of our debt agreements.
Cash Flow Analysis
Cash Flows from Operating Activities
Net cash provided by operating activities was $551.6 million for the year ended December 31, 2016 compared to net cash provided by operating activities of $652.4 million for the year ended December 31, 2015. Our operating cash flows for the year ended December 31, 2016 included our net income of $235.9 million, depreciation and amortization of $218.9 million, change in the fair value of our inventory repurchase obligations of $29.5 million, pension and other post retirement benefits costs of $38.0 million, deferred income tax expense of $19.8 million, stock-based compensation of $18.3 million and a loss on sale of assets of $11.4 million, partially offset by net non-cash benefits relating to an LCM adjustment of $521.3 million, equity income from our investment in TVPC of $5.7 million and the changes in the fair value of our catalyst lease of $1.4 million. In addition, net changes in working capital reflected sources of cash of $508.3 million driven by timing of inventory purchases and collections of accounts receivable. Our operating cash flows for the year ended December 31, 2015 included our net income of $187.3 million, plus net non-cash charges relating to an LCM adjustment of $427.2 million, depreciation and amortization of $199.4 million, change in the fair value of our inventory repurchase obligations of $63.4 million, pension and other post retirement benefits costs of $27.0 million, and stock-based compensation of $9.2 million, partially offset by the changes in the fair value of our catalyst lease of $10.2 million, and gain on sales of assets of $1.0 million. In addition, net changes in working capital reflected uses of cash of $249.9 million driven by timing of inventory purchases and collections of accounts receivable.
Net cash provided by operating activities was $652.4 million for the year ended December 31, 2015 compared to net cash provided by operating activities of $495.7 million for the year ended December 31, 2014. Our operating cash flows for the year ended December 31, 2014 included our net income of $21.1 million, plus net non-cash charges relating to an LCM adjustment of $690.1 million, depreciation and amortization of $186.4 million, pension and other post retirement benefits costs of $22.6 million, and stock-based compensation of $6.1 million, partially offset by the change in the fair value of our inventory repurchase obligations of $93.2 million, change in the fair value of our catalyst lease of $4.0 million, and gain on sales of assets of $0.9 million. In addition, net changes in working capital reflected uses of cash of $332.5 million driven by timing of inventory purchases and collections of accounts receivable as well as payments associated with the terminations of the MSCG offtake and Statoil supply agreement.
Cash Flows from Investing Activities
Net cash used in investing activities was $1,473.5 million for the year ended December 31, 2016 compared to net cash used in investing activities of $811.2 million for the year ended December 31, 2015. The net cash flows used in investing activities for the year ended December 31, 2016 was comprised of cash outflows of $971.9 million used to fund the Torrance Acquisition, capital expenditures totaling $282.4 million, expenditures for turnarounds of $198.7 million, expenditures for other assets of $42.5 million and the final working capital settlement related

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to the acquisition of the Chalmette refinery of $2.7 million, partially offset by $24.7 million in proceeds from the sale of assets. The net cash flows used in investing activities for the year ended December 31, 2015 was comprised of $565.3 million used in the acquisition of the Chalmette refinery, capital expenditures totaling $352.4 million, expenditures for turnarounds of $53.6 million, and expenditures for other assets of $8.2 million, partially offset by $168.3 million in proceeds from the sale of assets.
Net cash used in investing activities was $811.2 million for the year ended December 31, 2015 compared to net cash used in investing activities of $422.7 million for the year ended December 31, 2014. The net cash used in investing activities for the year ended December 31, 2014 was comprised of capital expenditures totaling $470.5 million, expenditures for turnarounds of $137.7 million, and expenditures for other assets of $17.3 million, partially offset by $202.7 million in proceeds from the sale of assets.
Cash Flows from Financing Activities
Net cash provided by financing activities was $633.8 million for the year ended December 31, 2016 compared to net cash provided by financial activities of $855.2 million for the year ended December 31, 2015. For the year ended December 31, 2016, net cash provided by financing activities consisted primarily of net proceeds from the Revolving Loan of $350.0 million, a contribution from our parent of $450.3 million, proceeds from the PBF Rail Term Loan of $35.0 million and proceeds from catalyst leases of $15.6 million, partially offset by distributions to members of $139.4 million, repayments of the Rail Facility of $67.5 million and net repayments of the affiliate note payable of $10.1 million. For the year ended December 31, 2015, net cash provided by financing activities consisted primarily of $500.0 million in proceeds from the 2023 Senior Secured Notes, capital contributions of $345.0 million, proceeds from affiliate notes payable of $347.8 million, and net proceeds from the Rail Facility of $30.1 million, partially offset by distribution to members of $350.7 million and deferred financing costs and other of $17.1 million .
Net cash provided by financing activities was $855.2 million for the year ended December 31, 2015 compared to net cash provided by financing activities of $68.5 million for the year ended December 31, 2014. For the year ended December 31, 2014, net cash provided by financing activities consisted primarily of capital contributions of $328.7 million, proceeds from affiliate notes payable of $90.6 million, net proceeds from the Rail Facility of $37.3 million, partially offset by distributions to members of $361.4 million, net repayments of the Revolving Loan of $15.0 million and $11.7 million for deferred financing costs and other.

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Capitalization
Our capital structure was comprised of the following as of December 31, 2016 (in millions):
 
December 31, 2016
Debt, including current maturities:
 
8.25% Senior Secured Notes due 2020
$
670.9

7.00% Senior Secured Notes due 2023
500.0

Revolving Loan
350.0

PBF Rail Term Loan
35.0

Catalyst leases
46.0

Total debt
1,601.9

Unamortized deferred financing costs
(25.3
)
Total debt, net of unamortized deferred financing costs
1,576.6

Affiliate notes payable
86.3

Total Equity
2,588.9

Total Capitalization
$
4,251.8

Total Debt to Capitalization Ratio
39
%

Our total debt, net of unamortized deferred financing costs to capitalization ratio was 39% and 48% at December 31, 2016 and 2015, respectively.
2016 Debt Transactions
As noted in "Note 9 - Credit Facility and Long-term Debt" to the consolidated financial statements, on December 22, 2016, the PBF Rail Facility was repaid in full and terminated in connection with the execution of a term loan (as described below).
On December 22, 2016, PBF Rail entered into a $35.0 million term loan (the “PBF Rail Term Loan”) with DVB Bank SE (“DVB”). The PBF Rail Term Loan amortizes monthly over its five year term and bears interest at the one month LIBOR plus 2.0%. As security for the PBF Rail Term Loan, PBF Rail pledged, among other things: (i) certain eligible railcars; (ii) the Debt Service Reserve Account; and (iii) our 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 7.00% Senior Secured Notes due 2023 (the "2023 Senior Secured Notes") were issued on November 24, 2015 and included a registration payment arrangement whereby we agreed to use commercially reasonable efforts to consummate an offer to exchange the 2023 Senior Secured Notes for an issue of registered notes with terms substantially identical to the notes not later than 365 days after the date of the original issuance of the notes. This registration statement was declared effective on December 1, 2016 and the exchange was consummated on January 19, 2017. Because the exchange offer was not consummated by November 24, 2016, additional interest was added at a rate of 0.25% per annum for the period from November 24, 2016 through the consummation of the exchange. As a result, we recognized approximately $0.1 million of additional interest expense in 2016.
During 2016, we borrowed under our Revolving Loan to partially fund the Torrance Acquisition (as discussed in "Note 3 - Acquisitions" to the consolidated financial statements).

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Revolving Credit Facilities Overview
Our primary sources of liquidity are cash flows from operations with additional sources available under borrowing capacity from our revolving line of credit. As of December 31, 2016, we had $626.7 million of cash and cash equivalents and $350.0 million outstanding under our Revolving Loan. We believe available capital resources will be adequate to meet our capital expenditure, working capital and debt service requirements. We had available capacity under our revolving credit facility as follows at December 31, 2016 (in millions):
 
 
Total Capacity
 
Amount Borrowed as of December 31, 2016
 
Outstanding Letters of Credit
 
Available Capacity
 
Expiration date
PBF Holding Revolving Loan (a)
 
$
2,635.0

 
$
350.0

 
$
412.0

 
$
534.6

 
August 2019
(a)
The amount available for borrowings and letters of credit under the Revolving Loan is calculated according to a “borrowing base” formula based on (i) 90% of the book value of eligible accounts receivable with respect to investment grade obligors plus (ii) 85% of the book value of eligible accounts receivable with respect to non-investment grade obligors plus (iii) 80% of the cost of eligible hydrocarbon inventory plus (iv) 100% of cash and cash equivalents in deposit accounts subject to a control agreement. The borrowing base is subject to customary reserves and eligibility criteria and in any event cannot exceed $2.635 billion.
Additional Information on Indebtedness
Our debt, including our revolving credit facility, term loan and senior secured notes, include certain typical financial covenants and restrictions on our subsidiaries' ability to, among other things, incur or guarantee new debt, engage in certain business activities including transactions with affiliates and asset sales, make investments or distributions, engage in mergers or pay dividends in certain circumstances. These covenants are subject to a number of important exceptions and qualifications. For further discussion of our indebtedness and these covenants and restrictions, see "Note 9 - Credit Facilities and Long-term Debt" to Consolidated Financial Statements included in this annual report.
We are in compliance with our covenants as of December 31, 2016.
Cash Balances
As of December 31, 2016, our cash and cash equivalents totaled $626.7 million.
Liquidity
As of December 31, 2016, our total liquidity was approximately $1,161.3 million, compared to total liquidity of approximately $1,514.5 million as of December 31, 2015. Total liquidity is the sum of our cash and cash equivalents plus the amount of availability under the Revolving Loan.
Working Capital
Working capital at December 31, 2016 was $1,111.0 million, consisting of $3,154.3 million in total current assets and $2,043.3 million in total current liabilities. Working capital at December 31, 2015 was $1,120.6 million, consisting of $2,580.9 million in total current assets and $1,460.3 million in total current liabilities.
Crude and Feedstock Supply Agreements
We have acquired crude oil for our Paulsboro and Delaware City refineries under supply agreements whereby Statoil generally purchased the crude oil requirements for each refinery on our behalf and under our direction. Our agreements with Statoil for Paulsboro and Delaware City were terminated effective March 31, 2013 and December 31, 2015, respectively, at which time we began to source Paulsboro’s and Delaware City's crude oil and feedstocks independently. Additionally, for our purchases of crude oil under our agreement with Saudi Aramco, similar to our purchases of other foreign waterborne crudes, we posted letters of credit and arranged for shipment. We paid for the crude when we were invoiced and the letters of credit were lifted.

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We had a similar supply agreement with MSCG, which was terminated effective July 31, 2014, to supply the crude oil requirements for our Toledo refinery, under which we took title to MSCG’s crude oil at certain interstate pipeline delivery locations. Payment for the crude oil under the Toledo supply agreement was due three days after it was processed by us or sold to third parties. We did not have to post letters of credit for these purchases and the Toledo supply agreement allowed us to price and pay for our crude oil as it was processed, which reduced the time we were exposed to market fluctuations. We recorded an accrued liability at each period-end for the amount we owed MSCG for the crude oil that we owned but had not processed. Subsequent to the term of the MSCG supply agreement, we have sourced all of our Toledo crude oil needs independently, which has increased the volumes of crude oil we own.
We have crude and feedstock supply agreements with PDVSA to supply 40,000 to 60,000 bpd of crude oil that can be processed at any of our East and Gulf Coast refineries.
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.
Inventory Intermediation Agreements
We entered into two separate Inventory Intermediation Agreements with J. Aron, which were amended and restated on May 29, 2015, expiring two years from the original expiry date of July 1, 2015, subject to certain early termination rights. In addition, the A&R Intermediation Agreements include one-year renewal clauses by mutual consent of both parties.
Pursuant to each A&R Intermediation Agreement, J. Aron will continue 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 will continue to market and sell independently to third parties. The A&R Intermediation Agreements for both the Delaware City and Paulsboro refineries with J. Aron include one-year renewal clauses upon six months' advance notice by mutual consent of both parties. The A&R Intermediation Agreements have not been renewed and are scheduled to expire July 1, 2017. If we are unable to negotiate an extension with J. Aron or enter into an alternative intermediation agreement, we will have to repurchase the inventories outstanding under the A&R Intermediation Agreement at that time.
At December 31, 2016, the LIFO value of intermediates and finished products owned by J. Aron included within inventory on our balance sheet was $352.5 million. We accrue a corresponding liability for such intermediates and finished products.
Capital Spending
Net capital spending was $1,473.5 million for the year ended December 31, 2016, which primarily included turnaround costs, safety related enhancements, facility improvements at the refineries, the Torrance Acquisition and the final working capital settlement associated with the Chalmette Acquisition. We currently expect to spend an aggregate of approximately between $575.0 to $600.0 million in net capital expenditures during 2017 for facility improvements and refinery maintenance and turnarounds. Significant capital spending plans for 2017 include turnarounds for the FCC at our Delaware City refinery, several units at our Torrance refinery and several units at our Chalmette refinery, as well as expenditures to meet Tier 3 requirements.
On July 1, 2016 we acquired the Torrance refinery and related logistic assets. The 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. The purchase price and fair value allocation may be subject to adjustment pending completion of the final valuation which was still in process as of December 31, 2016. The transaction was financed through a combination of cash on hand, including proceeds from a capital contribution made in connection

73



with PBF Energy's October 2015 Equity Offering and the 2023 Senior Secured Notes Offering, and borrowings under our Revolving Loan.

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Contractual Obligations and Commitments
The following table summarizes our material contractual payment obligations as of December 31, 2016:
 
 
Payments due by period
  
 
Total
 
Less than
1 year
 
1-3 Years
 
3-5 Years
 
More than
5 years
Long-term debt (a)
 
$
1,692,767

 
$
9,798

 
$
472,469

 
$
710,500

 
$
500,000

Interest payments on debt facilities (a)
 
472,490

 
101,893

 
200,808

 
99,789

 
70,000

Operating Leases (b)
 
436,667

 
111,184

 
187,740

 
105,322

 
32,421

Purchase obligations (c):
 
 
 
 
 
 
 
 
 
 
Crude Supply and Inventory Intermediation Agreements
 
8,137,912

 
2,268,826

 
3,560,062

 
2,309,024

 

Other Supply and Capacity Agreements
 
1,269,562

 
187,443

 
328,399

 
195,324

 
558,396

Minimum volume commitments with PBFX (d)
 
1,469,766

 
208,319

 
411,344

 
409,116

 
440,987

Construction obligations
 
33,927

 
33,927

 

 

 

Environmental obligations (e)
 
159,111

 
9,981

 
22,037

 
10,250

 
116,843

Pension and post-retirement obligations (f)
 
263,723

 
13,413

 
17,648

 
19,012

 
213,650

Total contractual cash obligations
 
$
13,935,925

 
$
2,944,784

 
$
5,200,507

 
$
3,858,337

 
$
1,932,297


(a) Long-term Debt and Interest Payments on Debt Facilities
Long-term obligations represent (i) the repayment of the outstanding borrowings under the Revolving Loan; (ii) the repayment of indebtedness incurred in connection with the Senior Secured Notes; (iii) the repayment of our catalyst lease obligations on their maturity dates; (iv) the repayment of outstanding amounts under the PBF Rail Term Loan; and (v) the repayment of outstanding affiliate notes payable with PBF LLC and PBF Energy.
Interest payments on debt facilities include cash interest payments on the Senior Secured Notes, catalyst lease obligations, PBF Rail Term Loan, our affiliate notes payable with PBF Energy and PBF LLC, plus cash payments for the commitment fee on the unused Revolving Loan and letter of credit fees on the letters of credit outstanding at December 31, 2016. With the exception of our catalyst leases, we have no long-term debt maturing before 2019 as of December 31, 2016.
(b) Operating Leases
We enter into operating leases in the normal course of business, some of these leases provide us with the option to renew the lease or purchase the leased item. Future operating lease obligations would change if we chose to exercise renewal options and if we enter into additional operating lease agreements. Certain of our lease obligations contain a fixed and variable component. The table above reflects the fixed component of our lease obligations. The variable component could be significant. Our operating lease obligations are further explained in the Commitments and Contingencies footnote to our financial statements, “Item 8. Financial Statements and Supplementary Data.” In support of our 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 repaid in full and terminated in connection with the execution of the PBF Rail Term Loan in 2016. Certain of these railcars were subsequently sold to third parties, which have leased the railcars back to us for periods of between four and seven years.

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(c) Purchase Obligations
We have obligations to repurchase certain intermediates and refined products under separate inventory intermediation agreements with J. Aron as further explained in the Summary of Significant Accounting Policies, Inventories and Accrued Expenses footnotes to our financial statements, “Item 8. Financial Statements and Supplementary Data.” Additionally, purchase obligations under "Crude Supply and Inventory Intermediation Agreements" include commitments to purchase crude oil from certain counterparties under supply agreements entered into to ensure adequate supplies of crude oil for our refineries. These obligations are based on aggregate minimum volume commitments at 2016 year end market prices.
Payments under "Other Supply and Capacity Agreements" include contracts for the transportation of crude oil and supply of hydrogen, steam, or natural gas to certain of our refineries, contracts for the treatment of wastewater, and contracts for pipeline capacity. We enter into these contracts to facilitate crude oil deliveries and to ensure an adequate supply of energy or essential services to support our refinery operations. Substantially all of these obligations are based on fixed prices. Certain agreements include fixed or minimum volume requirements, while others are based on our actual usage. The amounts included in this table are based on fixed or minimum quantities to be purchased and the fixed or estimated costs based on market conditions as of December 31, 2016.
(d) Minimum commitments with PBFX
 We have minimum obligations under our commercial agreements entered into with PBFX. PBFX receives, handles and transfers crude oil and receives, stores and delivers crude oil, refined products and intermediates from sources located throughout the United States and Canada in support of certain of our refineries. Refer to "Note 12 - Related Party Transactions” to our Consolidated Financial Statements for a detailed explanation of each of these agreements.
Included in the table above are our obligations related to the minimum commitments required under these commercial agreements. Any incremental volumes above any minimums throughput under these agreements would increase our obligations. Our obligation with respect to the Toledo Tank Farm Storage and Terminaling Agreement is based on the estimated shell capacity of the storage tanks to be utilized.
(e) Environmental Obligations
In connection with the Paulsboro acquisition, we assumed certain environmental remediation obligations to address existing soil and groundwater contamination at the site and recorded as a liability in the amount of $10.8 million which reflects the present value of the current estimated cost of the remediation obligations assumed based on investigative work to-date. The undiscounted estimated costs related to these environmental remediation obligations were $16.7 million as of December 31, 2016.
In connection with the acquisition of the Delaware City assets, the prior owners remain responsible, subject to certain limitations, for certain pre-acquisition environmental obligations, including ongoing soil and groundwater remediation at the site.
In connection with the Delaware City assets and Paulsboro refinery acquisitions, we, along with the seller, purchased two individual ten-year, $75.0 million environmental insurance policies to insure against unknown environmental liabilities at each site.
In connection with the acquisition of Toledo, the seller initially retains, subject to certain limitations, remediation obligations which will transition to us over a 20-year period.
In connection with the acquisition of the Chalmette refinery, the sellers provided $3.9 million 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 EPA. Additionally, we purchased a ten year $100.0 million environmental insurance policy to insure against unknown environmental liabilities at the site.

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In connection with the Torrance Acquisition, we assumed certain environmental remediation obligations to address existing soil and groundwater contamination at the site and recorded a liability of $142.5 million as of December 31, 2016, which reflects the current estimated cost of the remediation obligations, expected to be paid out over an average period of approximately 20 years. Additionally, we purchased a ten year $100.0 million environmental insurance policy to insure against unknown environmental liabilities.
In connection with the acquisition of all of our refineries, we assumed certain environmental obligations under regulatory orders unique to each site, including orders regulating air emissions from each facility.
(f) Pension and Post-retirement Obligations
Pension and post-retirement obligations include only those amounts we expect to pay out in benefit payments and are further explained at the Employee Benefit Plans footnote to our financial statements, “Item 8. Financial Statements and Supplementary Data.”
(g) Tax Receivable Agreement Obligations
The Contractual Obligations and Commitments Table above does not include tax distributions or other distributions that we expect to make on account of PBF Energy’s obligations under the tax receivable agreement that PBF Energy entered into with the members of PBF LLC other than PBF Energy in connection with PBF Energy’s initial public offering.
PBF Energy used a portion of the proceeds from its IPO to purchase PBF LLC Series A Units from the members of PBF LLC other than PBF Energy. In addition, the members of PBF LLC other than PBF Energy may (subject to the terms of the exchange agreement) exchange their PBF LLC Series A Units for shares of Class A common stock of PBF Energy on a one-for-one basis. As a result of both the purchase of PBF LLC Series A Units and subsequent secondary offerings and exchanges, PBF Energy is entitled to a proportionate share of the existing tax basis of the assets of PBF LLC. Such transactions have resulted in increases in the tax basis of the assets of PBF LLC that otherwise would not have been available. Both this proportionate share and these increases in tax basis may reduce the amount of tax that PBF Energy would otherwise be required to pay in the future. These increases in tax basis have reduced the amount of the tax that PBF Energy would have otherwise been required to pay and may also decrease gains (or increase losses) on the future disposition of certain capital assets to the extent tax basis is allocated to those capital assets. PBF Energy entered into a tax receivable agreement with the current and former members of PBF LLC other than PBF Energy that provides for the payment by PBF Energy to such members of 85% of the amount of the benefits, if any, that PBF Energy is deemed to realize as a result of (i) these increases in tax basis and (ii) certain other tax benefits related to entering into the tax receivable agreement, including tax benefits attributable to payments under the tax receivable agreement. These payment obligations are obligations of PBF Energy and not of PBF Holding or any of its subsidiaries.
PBF Energy expects to obtain funding for these payments by causing its subsidiaries to make cash distributions to PBF LLC, which, in turn, will distribute such amounts, generally as tax distributions, on a pro-rata basis to its owners, which as of December 31, 2016 include the members of PBF LLC other than PBF Energy holding a 3.5% interest and PBF Energy holding a 96.5% interest. The members of PBF LLC other than PBF Energy may continue to reduce their ownership in PBF LLC by exchanging their PBF LLC Series A Units for shares of PBF Energy Class A common stock. Such exchanges may result in additional increases in the tax basis of PBF Energy’s investment in PBF LLC and require PBF Energy to make increased payments under the tax receivable agreement. Required payments under the tax receivable agreement also may increase or become accelerated in certain circumstances, including certain changes of control.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements as of December 31, 2016, other than outstanding letters of credit in the amount of approximately $412.0 million and operating leases.
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