Edgar Filing: PBF Energy Inc.

PBF-2013.12.31.10K

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, 2013



¨	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

Commission File Number: 333-186007

Commission File Number: 333-186007-07

PBF ENERGY INC.

PBF HOLDING COMPANY LLC

PBF FINANCE CORPORATION

(Exact name of registrant as specified in its charter)



DELAWARE DELAWARE DELAWARE		45-3763855 27-2198168 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)



Delaware		45-3763855
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

One Sylvan Way, Second Floor Parsippany, New Jersey		07054
(Address of principal executive offices)		(Zip Code)

Registrants’ telephone number, including area code: (973) 455-7500

Securities registered pursuant to Section 12(b) of the Act:



Title of Each Class		Name of Each Exchange on Which Registered
Class A Common Stock, $0.001 par value		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.



PBF Energy Inc.	x Yes o No
PBF Holding Company LLC	o Yes x No
PBF Finance Corporation	o Yes x No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.



PBF Energy Inc.	o Yes x No
PBF Holding Company LLC	o Yes x No
PBF Finance Corporation	o Yes x No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports); and (2) has been subject to such filing requirements for the past 90 days.



PBF Energy Inc.	x Yes ¨ No
PBF Holding Company LLC	x Yes ¨ No
PBF Finance Corporation	x Yes o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).



PBF Energy Inc.	x Yes o No
PBF Holding Company LLC	x Yes o No
PBF Finance Corporation	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
PBF Energy Inc.	x	¨	¨	¨
PBF Holding Company LLC	¨	¨	x	¨
PBF Finance Corporation	o	o	x	o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).



PBF Energy Inc.	¨ Yes x No
PBF Holding Company LLC	¨ Yes x No
PBF Finance Corporation	o Yes x No

The aggregate market value of the Common Stock of PBF Energy Inc. held by non-affiliates as of June 30, 2013 was $1,024,703,335 based upon the New York Stock Exchange Composite Transaction closing price.

Aggregate market value of PBF Holding Company LLC membership interests held by non-affiliates: None

Aggregate market value of PBF Finance Corporation common stock interests held by non-affiliates: None

As of February 20, 2014, PBF Energy Inc. had outstanding 54,665,473 shares of Class A common stock and 40 shares of Class B common stock. PBF Energy Inc. is the sole managing member of, and owner of an equity interest of approximately 56.4% of the outstanding economic interest in, PBF Energy Company LLC. PBF Energy Company LLC held 100% of the membership interests in PBF Holding Company LLC as of February 20, 2014. PBF Holding Company LLC has no common stock outstanding. As of February 20, 2014, PBF Finance Corporation had 100 shares of common stock outstanding, all of which were held by PBF Holding Company LLC.

DOCUMENTS INCORPORATED BY REFERENCE

PBF Energy Inc. intends to file with the Securities and Exchange Commission a definitive Proxy Statement for its Annual Meeting of Stockholders within 120 days after December 31, 2013. Portions of the Proxy Statement are incorporated by reference in Part III of this Form 10-K to the extent stated herein.

PBF ENERGY INC. AND

PBF HOLDING COMPANY LLC

TABLE OF CONTENTS



PART I

	Item 1.	Business	3
	Item 1A.	Risk Factors	19
	Item 1B.	Unresolved Staff Comments	35
	Item 2.	Properties	35
	Item 3.	Legal Proceedings	35
	Item 4.	Mine Safety Disclosures	35

PART II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	36
	Item 6.	Selected Financial Data	39
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	43
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	70
	Item 8.	Financial Statements and Supplementary Data	72
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	72
	Item 9A.	Controls and Procedures	72
	Item 9B.	Other Information	72

PART III

	Item 10.	Directors, Executive Officers and Corporate Governance	73
	Item 11.	Executive Compensation	73
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	73
	Item 13.	Certain Relationships and Related Transactions, and Director Independence	73
	Item 14.	Principal Accountant Fees and Services	73

PART IV
	Item 15.	Exhibits and Financial Statement Schedules	74
SIGNATURES

PART I

This combined Annual Report on Form 10-K is filed by PBF Energy Inc. (“PBF Energy”), PBF Holding Company LLC (“PBF Holding”) and PBF Finance Corporation ("PBF Finance"). Each Registrant hereto is filing on its own behalf all of the information contained in this report that relates to such Registrant. Each Registrant hereto is not filing any information that does not relate to such Registrant, and therefore makes no representation as to any such information. PBF Energy is the sole managing member of, and owner of an equity interest representing approximately 40.9% of the outstanding economic interests in, PBF Energy Company LLC ("PBF LLC") as of December 31, 2013. PBF Holding is a wholly-owned subsidiary of PBF LLC and PBF Finance is a wholly-owned subsidiary of PBF Holding. PBF Holding is the parent company for PBF LLC's operating subsidiaries.

PBF Holding is an indirect subsidiary of PBF Energy, representing 100% of PBF Energy’s consolidated revenue for the year ended December 31, 2013 and constituting 100% of PBF Energy’s revenue generating assets as of December 31, 2013.

Unless the context indicates otherwise, the terms “we,” “us,” and “our” refer to both PBF Energy and PBF Holding and consolidated subsidiaries, including PBF LLC, PBF Investments LLC (“PBF Investments”), PBF Services Company LLC, PBF Power Marketing LLC, Toledo Refining Company LLC (“Toledo Refining”), Paulsboro Natural Gas Pipeline Company LLC, Paulsboro Refining Company LLC (“Paulsboro Refining”), Delaware Pipeline Company LLC, Delaware City Refining Company LLC (“Delaware City Refining”), Delaware City Terminaling Company LLC, PBF Logistics GP LLC, PBF Logistics LP and PBF Rail Logistics Company LLC. Discussions or areas of this report that either apply only to PBF Energy or PBF Holding are clearly noted in such sections.

In this Annual Report on Form 10-K, we make certain forward-looking statements, including statements regarding our plans, strategies, objectives, expectations, intentions, and resources, under the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. You should read our forward-looking statements together with our disclosures under the heading: “Cautionary Statement for the Purpose of Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995.” When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in this Annual Report on Form 10-K under “Risk Factors” in Item 1A.

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 and Midwest 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. We currently own and operate three domestic oil refineries and related assets, which we acquired in 2010 and 2011. Our refineries have a combined processing capacity, known as throughput, of approximately 540,000 bpd, and a weighted-average Nelson Complexity Index of 11.3.

Our three refineries are located in Toledo, Ohio, Delaware City, Delaware and Paulsboro, New Jersey. Our Mid-Continent refinery at Toledo processes light, sweet crude, has a throughput capacity of 170,000 bpd and a Nelson Complexity Index of 9.2. The majority of Toledo’s WTI-based crude is delivered via pipelines that originate in both Canada and the United States. Since our acquisition of Toledo in 2011, we have added additional truck and rail crude unloading capabilities that provide feedstock sourcing flexibility for the refinery and enables Toledo to run a more cost-advantaged crude slate. Our East Coast refineries at Delaware City and Paulsboro have a combined refining capacity of 370,000 bpd and Nelson Complexity Indices of 11.3 and 13.2, respectively. These high-conversion refineries process primarily medium and heavy, sour crudes and have historically received the bulk of their feedstock via ships and barges on the Delaware River.

During 2012 and 2013, we expanded and upgraded existing on-site railroad infrastructure at our Delaware City refinery, including the expansion of the crude rail unloading facilities that was completed in February 2013. Currently, crude delivered to this facility is consumed at our Delaware City refinery. We also transport some of the crude delivered by rail from Delaware City via barge to our Paulsboro refinery or other third party destinations. The Delaware City rail unloading facility allows our East Coast refineries to source WTI based crudes from Western Canada and the Midcontinent, which we believe provides significant cost advantages versus traditional Brent based international crudes.

PBF Energy, a Delaware corporation formed on November 7, 2011, is a holding company that manages its consolidated subsidiary, PBF LLC. Our sole asset is a controlling equity interest as of December 31, 2013 of approximately 40.9% in PBF LLC as discussed more fully in “History” below.

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

History

PBF Energy is the sole managing member of PBF LLC. PBF Holding is a wholly-owned subsidiary of PBF LLC and PBF Finance is a wholly-owned subsidiary of PBF Holding. PBF Holding is the parent company for PBF LLC's operating subsidiaries.

On December 18, 2012, we completed the initial public offering of 23,567,686 shares of our Class A common stock at an offering price of $26.00 per share. In connection with the offering, our shares of Class A common stock began trading on the New York Stock Exchange under the symbol “PBF”. The proceeds to us from the offering, before deducting underwriting discounts, were approximately $612.8 million of which we used approximately $571.2 million to purchase 21,967,686 PBF LLC Series A Units from our financial sponsors, funds affiliated with The Blackstone Group L.P. (“Blackstone”) and First Reserve Management L.P. (“First Reserve”).

Additionally, on June 12, 2013, we completed a public offering of 15,950,000 shares of our Class A common stock at a price of $27.00 per share, less underwriting discounts and commissions, in a secondary public offering (the "June 2013 Secondary Offering"). All of the shares were sold by funds affiliated with Blackstone and First Reserve. In connection with this offering, Blackstone and First Reserve exchanged 15,950,000 Series A Units of PBF LLC for an equivalent number of shares of our Class A common stock. The holders of PBF LLC Series B Units, which include certain executive officers of PBF Energy, had the right to receive a portion of the proceeds of the sale of the PBF Energy Class A common stock by Blackstone and First Reserve.

As of December 31, 2013, Blackstone and First Reserve and our executive officers and directors and certain employees beneficially owned 57,201,674 PBF LLC Series A Units (we refer to all of the holders of the PBF LLC Series A Units as “the members of PBF LLC other than PBF Energy”) and we owned 39,665,473 PBF LLC Series C Units, and the members of PBF LLC other than PBF Energy through their holdings of Class B common stock have 59.1% of the voting power in us, and the holders of our issued and outstanding shares of Class A common stock have 40.9% of the voting power in us. As a result of the ownership of the Class B common stock and the PBF LLC Series A Units, prior to the January 2014 secondary offering discussed below under "Recent Developments", Blackstone and First Reserve controlled us as of December 31, 2013, and we in turn, as the sole managing member of PBF LLC, control PBF LLC and its subsidiaries.

PBF Energy consolidates the financial results of PBF LLC and its subsidiaries and records a noncontrolling interest in its consolidated financial statements representing the economic interests of the members of PBF LLC other than PBF Energy. PBF LLC is PBF Energy’s predecessor for accounting purposes. Our financial statements and results of operations for periods prior to the completion of our initial public offering are those of PBF LLC.

See “Item 1A. Risk Factors” and “Item 13. Certain Relationships and Related Transactions, and Director Independence.”

The diagram below depicts our organizational structure as of December 31, 2013:

Recent Developments

On January 6, 2014, we completed a public offering of 15,000,000 shares of our Class A common stock at a price of $28.00 per share, less underwriting discounts and commissions, in a secondary public offering (the "January 2014 Secondary Offering"). All of the shares were sold by funds affiliated with Blackstone and First Reserve. In connection with this offering, Blackstone and First Reserve exchanged 15,000,000 Series A Units of PBF LLC for an equivalent number of shares of our Class A common stock, which increased PBF Energy's interest in PBF LLC to approximately 56.4%. The holders of PBF LLC Series B Units, which include certain executive officers of PBF Energy, had the right to receive a portion of the proceeds of the sale of the PBF Energy Class A common stock by Blackstone and First Reserve. Completion of the January 2014 Secondary Offering is estimated to increase our tax receivable agreement liability to $439.6 million due to the tax benefit expected to be generated as a result of the exchange in connection with the secondary offering and the corresponding tax benefits expected to be generated in future years from this transaction.

Refining Operations

We own and operate three refineries, all located in regions with currently favorable market dynamics where finished product demand exceeds operating refining capacity. 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 and Midwest 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

Acquisition and Re-Start. Through our subsidiaries, Delaware City Refining and Delaware Pipeline Company LLC, we acquired the idle Delaware City refinery and its related assets, including a petroleum product terminal, a petroleum products pipeline and an electric generation facility, on June 1, 2010 from affiliates of Valero for approximately $220.0 million in cash, consisting of approximately $170.0 million for the refinery, terminal and pipeline assets and $50.0 million for the power plant complex located on the property.

At the time of acquisition, we reached an agreement with the State of Delaware that provided for a five-year operating permit and up to approximately $45.0 million of economic support to re-start the facility, and negotiated a new long-term contract with the relevant union at the refinery. As of December 31, 2013, we had received $39.4 million in economic support from the State of Delaware under this agreement. We believe that the refinery’s ability to process lower quality crudes allows us to capture a higher margin as these lower quality crudes are typically priced at discounts to benchmark crudes, and to compete effectively in a region where product demand currently significantly exceeds refining capacity.

We restarted the Delaware City Refinery in October 2011. Since our acquisition through December 31, 2013, we have invested more than $700.0 million in turnaround and re-start projects at Delaware City, as well as in the recent strategic development of crude rail unloading facilities. In May 2012, we commenced crude shipments via rail into a newly developed crude rail unloading facility at our Delaware City refinery. We have expanded and upgraded the existing on-site railroad infrastructure, including the expansion of the crude rail unloading facilities which, as of February 2013 were capable of discharging approximately 110,000 bpd, consisting of 40,000 bpd of heavy crude oil and 70,000 bpd of light crude oil. However, due to greater operating efficiency, discharge capacity for light crude oil at our dual-loop track has increased from 70,000 bpd to approximately 105,000 bpd. In conjunction with the development of our rail crude unloading facilities at Delaware City, we constructed a railcar storage yard with capacity for 330 railcars that is integral to railcar staging and storage and helps facilitate daily rail traffic at the refinery. We are also adding additional unloading spots to the dual-loop track to increase unloading capabilities at that facility to approximately 130,000 bpd. Also in 2013 we commenced a third rail crude offloading project to add an additional 40,000 bpd of heavy crude rail unloading capability at the refinery, which is expected to be completed by the second half of 2014. Completion of these additional rail projects is expected to increase our discharge capacity of heavy crude oil from 40,000 bpd to 80,000 bpd and bring the total rail crude unloading capability up to 210,000 bpd by the end of 2014, subject to the delivery of coiled and insulated railcars, the development of crude rail loading infrastructure in Canada and the use of unit trains.

We have entered into agreements to lease or purchase a total of 5,900 railcars, including 4,600 coiled and insulated rails cars, which are capable of transporting Canadian heavy crude oils, and 1,300 general purpose cars, which we intend to use to transport lighter crude oils. In addition to the construction of our rail unloading facilities at Delaware City and the execution of our railcar procurement strategy, we also created dedicated crude-by-rail acquisition and rail logistics teams. These teams, staffed by PBF employees in our corporate headquarters, at the Delaware City refinery and in our field offices in Calgary, Alberta and Oklahoma City, Oklahoma, are responsible for crude procurement, logistics via rail and monitoring crude-by-rail offloading.

Overview. The Delaware City refinery is located on a 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 the crude unloading facility, 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 17-bay, 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.

The Delaware City refinery has a throughput capacity of 190,000 bpd and a Nelson Complexity Index of 11.3. 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 processes a variety of medium to heavy, sour crude oils. The refinery has large conversion capacity with its 82,000 bpd FCC unit, 47,000 bpd FCU and 18,000 bpd hydrocracking unit with vacuum distillation. Hydrogen is provided via the refinery’s steam methane reformer and continuous catalytic reformer.

Delaware City Process Flow Diagram

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 (FCC)	82,000
Hydrotreating Units	160,000
Hydrocracking Unit	18,000
Catalytic Reforming Unit (CCR)	43,000
Benzene / Toluene Extraction Unit	15,000
Butane Isomerization Unit (ISOM)	6,000
Alkylation Unit (Alky)	11,000
Polymerization Unit (Poly)	16,000
Fluid Coking Unit (FCU/ Fluid Coker)	47,000

Feedstocks and Supply Arrangements. In April 2011, we entered into a crude and feedstock supply agreement with Statoil that expires on December 31, 2015. Pursuant to the agreement as amended in October 2012, we direct Statoil to purchase waterborne crude and other feedstocks for Delaware City and Statoil purchases these products on the spot market or through term agreements. Accordingly, Statoil enters 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 arranges transportation and insurance for these waterborne deliveries of crude and feedstock

supply and we pay Statoil a per barrel fee for their procurement and logistics services. Statoil generally holds title to the waterborne crude and feedstocks until we process the crude or feedstocks through our process units. We pay Statoil on a daily basis for the corresponding volume of crude or feedstocks that are consumed in conjunction with the refining process. This crude supply and feedstock arrangement helps us reduce the amount of investment we are required to maintain in crude inventories and, as a result, helps us manage our working capital.

Product Offtake. Prior to June 30, 2013, we sold the bulk of Delaware City’s clean products to MSCG through an offtake agreement. Under the offtake agreement, MSCG purchased 100% of our finished clean products at Delaware City, which included gasoline, heating oil and jet fuel, as well as our intermediates. During the term of the offtake agreement, we sold the remainder of our refined products directly to a variety of customers on the spot market or through term agreements. Subsequent to the termination of the offtake agreement, 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, the Company entered into an Inventory Intermediation Agreement with J. Aron ("Inventory Intermediation Agreement") to support the operations of the Delaware City refinery, which commenced upon the termination of the product offtake agreement with MSCG. Pursuant to the Inventory Intermediation Agreement, J. Aron purchased all of the finished and intermediate products (collectively the “Products”) located at the refinery upon termination of the MSCG 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.

Tankage Capacity. The Delaware City refinery has total storage capacity of approximately 10.0 million barrels. Of the total, 18 tanks with 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 55,000 MMBTU per day of natural gas. 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 and supplemented by secondary boilers at the FCC and coker.

Paulsboro Refinery

Acquisition. We acquired the entities that owned the Paulsboro refinery (including an associated natural gas pipeline) on December 17, 2010, from Valero for approximately $357.7 million, excluding working capital. The purchase price excludes inventory purchased on our behalf by MSCG and Statoil. We invested approximately $60.0 million in capital in early 2011 to complete a scheduled turnaround at the refinery.

Overview. Paulsboro has a throughput capacity of 180,000 bpd and a Nelson Complexity Index of 13.2. 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. Major units at the Paulsboro refinery include crude distillation units, vacuum distillation units, an FCC unit, a delayed coking unit, a lube oil processing unit and a propane deasphalting unit.

The Paulsboro refinery processes a variety of medium and heavy, sour crude oils. The Paulsboro refinery predominantly produces gasoline, heating oil and jet fuel and also manufactures Group I base oils or lubricants. In addition to its finished clean products slate, Paulsboro produces asphalt and petroleum coke.

Paulsboro Refinery Process Flow Diagram

The following table approximates the Paulsboro refinery’s major process unit capacities. Unit capacities are shown in barrels per stream day.



Refinery Units	Nameplate Capacity
Crude Distillation Units	168,000
Vacuum Distillation Units	83,000
Fluid Catalytic Cracking Unit (FCC)	55,000
Hydrotreating Units	141,000
Catalytic Reforming Unit (CCR)	32,000
Alkylation Unit (Alky)	11,000
Lube Oil Processing Unit	12,000
Delayed Coking Unit (Coker)	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 is priced off ASCI.

In addition, under a crude and feedstock supply agreement with Statoil that was terminated effective March 31, 2013, we directed Statoil to purchase crude and other feedstocks for Paulsboro and Statoil purchased the crude and feedstocks on the spot market. 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 generally arranged transportation and insurance for the crude and feedstock supply and we paid Statoil a per barrel fee for their procurement and logistics services. Statoil held title to the crude and feedstocks until we ran the crude or feedstocks through our process units. We paid Statoil on a daily basis for the corresponding volume of crude or feedstocks that were consumed in conjunction with the refining process.

Product Offtake. Prior to June 30, 2013, we sold the bulk of Paulsboro’s clean products to MSCG through our offtake agreement. With the exception of certain jet fuel and lubricant sales, MSCG purchased 100% of our finished

clean products and intermediates under the offtake agreement. During the term of the offtake agreement, we sold the remainder of our refined products directly to a variety of customers on the spot market or through term agreements. Subsequent to the termination of the offtake agreement, 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, 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 product offtake agreement with MSCG. Pursuant to the Inventory Intermediation Agreement, J. Aron purchased all of the Products located at Paulsboro upon termination of the 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.

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. 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.

Toledo Refinery

Acquisition. Through our subsidiary, Toledo Refining, we acquired the Toledo refinery on March 1, 2011, from Sunoco for approximately $400.0 million, excluding working capital. We also purchased refined and certain intermediate products inventory for approximately $299.6 million, and MSCG purchased the refinery’s crude oil inventory on our behalf. Additionally, included in the terms of the sale was a five-year participation payment of up to $125.0 million payable to Sunoco based upon post-acquisition earnings of the refinery, of which $103.6 million was paid in 2012 and the balance paid in 2013.

Overview. Toledo has a throughput capacity of approximately 170,000 bpd and a Nelson Complexity Index of 9.2. Toledo processes a slate of light, sweet crudes from Canada, the Midcontinent, the Bakken region and the U.S. Gulf Coast. Toledo produces finished products including gasoline and ULSD, in addition to a variety of high-value petrochemicals including nonene, xylene, tetramer and toluene.

The Toledo refinery is located on a 282-acre site near Toledo, Ohio, approximately 60 miles from Detroit. Major units at the Toledo refinery include an FCC unit, a hydrocracker, an alkylation unit and a UDEX unit. 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.

Toledo Refinery Process Flow Diagram

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 (FCC)	79,000
Hydrotreating Units	95,000
Hydrocracking Unit (HCC)	45,000
Catalytic Reforming Units	45,000
Alkylation Unit (Alky)	10,000
Polymerization Unit (Poly)	7,000
UDEX Unit (BTX)	16,300

Feedstocks and Supply Arrangements. We have a short term crude oil acquisition agreement with MSCG pursuant to which we direct MSCG to purchase crude and other feedstocks for Toledo. MSCG purchases crude and feedstocks on the spot market. Accordingly, MSCG enters 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, MSCG arranges transportation and insurance for the crude and feedstock supply and we pay MSCG a per barrel fee for their procurement and logistics services. We pay MSCG on a daily basis for the corresponding volume of crude or feedstocks two days after they are consumed in conjunction with the refining process. This arrangement helps us reduce the amount of investment we are required to maintain in crude inventories and, as a result, helps us manage our working capital.

Product Offtake. 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 28 terminals in this network.

In March 2011, we entered into 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 has a three year term, subject to certain early termination rights. 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 4.0 million barrels. The Toledo refinery receives its crude through pipeline connections and a truck rack. Of the total, approximately 0.4 million barrels are dedicated to crude oil storage with the remaining 3.6 million barrels allocated to intermediates and products.

Energy and Other Utilities. Under normal operating conditions, the Toledo refinery consumes approximately 17,000 MMBTU per day of natural gas. The Toledo refinery purchases its electricity from a local utility 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.

Principal Products

Our refineries make various grades of gasoline, diesel fuel, jet fuel, 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, 2013, 2012 and 2011, gasoline and distillates accounted for 88.6%, 88.8% and 88.1% of our revenues, respectively.

Customers

We sell a variety of refined products to a diverse customer base. We currently have product offtake agreements in place for a large portion of our clean product sales. For the year ended December 31, 2013, MSCG and Sunoco accounted for 29% and 10% of our revenues, respectively. The remainder of our refined products are primarily sold through short-term contracts or on the spot market. As of December 31, 2013, Sunoco accounted for 10% of accounts receivable.

For the year ended December 31, 2012, MSCG and Sunoco accounted for 57% and 10% of the Company’s revenues, respectively. As of December 31, 2012, Statoil and Sunoco accounted for 28% and 10% of accounts receivables, respectively.

For the year ended December 31, 2011, MSCG and Sunoco accounted for 52% and 12% of the Company’s revenues, respectively.

Seasonality

Demand for gasoline 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 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 both on the East and Gulf Coasts and in the Midcontinent, 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 substantially all of our crude oil and 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.

Corporate Offices

We lease approximately 53,000 square feet for our principal corporate offices in Parsippany, New Jersey. The lease for our principal corporate offices expires in 2016. Functions performed in the Parsipanny 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.

Employees

As of December 31, 2013, we had approximately 1,735 employees. At Paulsboro, 296 of our 460 employees are covered by a collective bargaining agreement that expires in March 2015. In addition, 678 of our 1,066 employees at Delaware City and Toledo are covered by a collective bargaining agreement that expires in February of 2015. None of our corporate employees are covered by a collective bargaining agreement. We consider our relations with the represented employees to be satisfactory.

Executive Officers of the Registrant

The following is a list of our executive officers as of February 20, 2014:



Name	Age	Position
Thomas D. O’Malley	72	Executive Chairman of the Board of Directors
Thomas J. Nimbley	62	Chief Executive Officer
Michael D. Gayda	59	President
Matthew C. Lucey	40	Senior Vice President, Chief Financial Officer
Jeffrey Dill	52	Senior Vice President, General Counsel
Paul Davis	51	Vice President, Crude Oil and Feedstock
Todd O'Malley	40	Vice President, Products

Thomas D. O’Malley has served as Executive Chairman of the Board of Directors of PBF Energy since its formation in November 2011, served as Executive Chairman of PBF LLC and its predecessors from March 2008 to February 2013 and was our Chief Executive Officer from inception until June 2010. Mr. O’Malley has more than 30 years experience in the refining industry. He served as Chairman of the Board of Petroplus Holdings A.G., listed on the Swiss Exchange, from May 2006 until February 2011, and was Chief Executive Officer from May 2006 until September 2007. Mr. O’Malley was Chairman of the Board and Chief Executive Officer of Premcor, a domestic oil refiner and Fortune 250 company listed on the NYSE, from February 2002 until December 2004, and continued as Chairman until its sale to Valero in August 2005. Before joining Premcor, Mr. O’Malley was Chairman and Chief Executive Officer of Tosco Corporation. This Fortune 100 company, listed on the NYSE, was the largest independent oil refiner and marketer of oil products in the United States, with annualized revenues of approximately $25.0 billion when it was sold to Philips Petroleum Company in September 2001.

Thomas J. Nimbley has served as our Chief Executive Officer since June 2010 and was our Executive Vice President, Chief Operating Officer from March 2010 through June 2010. Prior thereto, he served as a Principal for Nimbley Consultants LLC from June 2005 to April 2010, where he provided consulting services and assisted on the acquisition of two refineries. He previously served as Senior Vice President and head of Refining for Phillips Petroleum Company and subsequently Senior Vice President and head of Refining for ConocoPhillips domestic refining system (13 locations) following the merger of Phillips and Conoco. Before joining Phillips at the time of its acquisition of Tosco in September 2001, Mr. Nimbley served in various positions with Tosco Corporation and its subsidiaries starting in April 1993.

Michael D. Gayda joined us as our Executive Vice President, General Counsel and Secretary in April 2010 and has served as our President since June 2010, and was a director of PBF LLC from inception until October 2009. Prior thereto, from May 2006 until January 2010 Mr. Gayda served as Executive Vice President, General Counsel and Secretary of Petroplus. Prior to Petroplus, he served as an executive officer of Premcor until its sale to Valero in August 2005 and as General Counsel—Refining for Phillips 66 Company, a division of Phillips Petroleum Company, following Phillips Petroleum’s acquisition of Tosco in September 2001. Mr. Gayda previously served as a Vice President of certain of Tosco’s subsidiaries.

Matthew C. Lucey joined us as our Vice President, Finance in April 2008 and has served as our Senior Vice President, Chief Financial Officer since April 2010. Prior thereto, Mr. Lucey served as a Managing Director of M.E. Zukerman & Co., a New York-based private equity firm specializing in several sectors of the broader energy industry, from 2001 to 2008. While at M.E. Zukerman & Co., Mr. Lucey participated in all aspects of the firm’s energy investment activities and served on the Management Committee of Penreco, a manufacturer of specialty petroleum products; Cortez Pipeline Company, a 500 mile CO2 pipeline; and Venture Coke Company, a merchant petroleum coke calciner. Before joining M.E. Zukerman & Co., Mr. Lucey spent six years in the banking industry.

Jeffrey Dill has served as our Senior Vice President, General Counsel and Secretary since May 2010 and from March 2008 until September 2009. Mr. Dill served as Senior Vice President, General Counsel and Secretary for Maxum Petroleum, Inc., a national marketer and logistics company for petroleum products, from September 2009 to May 2010 and as Consulting General Counsel and Secretary for NTR Acquisition Co., a special purpose acquisition company focused on downstream energy opportunities, from April 2007 to February 2008. Previously he served as Vice President, General Counsel and Secretary at Neurogen Corporation, a drug discovery and development company, from March 2006 to December 2007. Mr. Dill has over 15 years experience providing legal support to refining, transportation and marketing organizations in the petroleum industry, including positions at Premcor, ConocoPhillips, Tosco and Unocal.

Paul Davis joined PBF Energy in April of 2012 and was named Vice President, Crude Oil and Feedstocks responsible for crude oil and refinery feedstock sourcing in May 2013. Previously, Mr. Davis was responsible for managing the U.S. clean products commercial operations for Hess Energy Trading Company from 2006 to 2012. Prior to that, Mr. Davis was responsible for Premcor’s U.S. Midwest clean products disposition group. Mr. Davis has over 29 years of experience in commercial operations in crude oil and refined products, including 16 years with the ExxonMobil Corporation in various operational and commercial positions, including sourcing refinery feedstocks and crude oil and the disposition of refined petroleum products, as well as optimization roles within refineries.

Todd O’Malley joined PBF Energy in November 2010, with over 15 years of energy industry experience, and was named Vice President, Products responsible for petroleum products and power in May 2013. Mr. O’Malley joined PBF from the Hess Energy Trading Company where he traded petroleum products in both the United States and Europe from October 2008 to November 2010. Prior to that, Mr. O’Malley established a proprietary refined petroleum products and ethanol trading platform for an international investment bank. Previously, Mr. O’Malley was Vice President of Supply and Distribution of Gulf Oil in charge of petroleum products trading and optimization of storage and terminal assets. Prior thereto, Mr. O’Malley managed the northeast clean products commercial operations for Premcor. Mr. O’Malley has held similar commercial roles in other energy-focused organizations where he traded electricity, natural gas, grains, biofuels, crude oil and petroleum products, both physically and financially.

Mr. Thomas O'Malley is the uncle of Mr. Todd O'Malley and uncle, by marriage, of Mr. Matthew Lucey.

Environmental, Health and Safety Matters

Refinery and pipeline operations are subject to federal, state and local laws regulating the discharge of matter into the environment or otherwise relating to human health and safety or the protection of the environment. These laws regulate, among other things, the generation, storage, handling, use and transportation of petroleum and other regulated

materials, the emission and discharge of materials into the environment, waste management, remediation of contaminated sites, characteristics and composition of gasoline and distillates and other matters otherwise relating to the protection of the environment. 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 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.

Additionally, as of January 1, 2011 we are required to meet an EPA regulation limiting the average sulfur content in gasoline to 30 PPM. The EPA has also announced that it plans to propose new “Tier 3” motor vehicle emission and fuel standards. It has been reported that these new Tier 3 regulations may, among other things, lower the maximum average sulfur content of gasoline from 30 PPM to 10 PPM. If the Tier 3 regulations are eventually implemented and lower the maximum allowable content of sulfur or other constituents in fuels that we produce, we may at some point in the future be required to make significant capital expenditures and/or incur materially increased operating costs to comply with the new standards.

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.

Our operations are also subject to the federal Clean Water Act, or the CWA, the federal Safe Drinking Water Act, or 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, or 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 federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, or 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. In the case of Paulsboro, a trust fund established to meet state financial assurance requirements, in the amount of approximately $12.1 million, the estimated cost of the remediation obligations assumed based on investigation undertaken as of the acquisition date, was acquired as part of the acquisition. The short term portion of the trust fund and corresponding liability are recorded as restricted cash and accrued expenses, the long term portion is recorded in other assets and other long-term liabilities. In connection with the acquisition of Delaware City, the prior owners remain responsible subject to certain limitations, for certain environmental obligations including ongoing remediation of soil and groundwater contamination at the site. Further, in connection with the Delaware City and Paulsboro acquisitions, we purchased two individual ten-year, $75.0 million environmental insurance policies to insure against unknown environmental liabilities at each refinery. In connection with the acquisition of Toledo, the seller, subject to certain limitations, initially retains remediation obligations which will transition to us over a 20-year period. However, there can be no assurance that any available indemnity, trust fund or insurance will be sufficient to cover any ultimate environmental liabilities we may incur with respect to our refineries, which could be significant.

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.

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:

“ASCI” refers to the Argus Sour Crude Index, a pricing index used to approximate market prices for sour, heavy crude oil.

“Bakken” refers to both a crude oil production region generally covering North Dakota, Montana and Western Canada, and the crude oil that is produced in that region.

“barrel” refers to a common unit of measure in the oil industry, which equates to 42 gallons.

“blendstocks” refers to various compounds that are combined with gasoline or diesel from the crude oil refining process to make finished gasoline and diesel; these may include natural gasoline, FCC unit gasoline, ethanol, reformate or butane, among others.

“bpd” refers to an abbreviation for barrels per day.

"CAA" refers to the Clean Air Act.

“CAPP” refers to the Canadian Association of Petroleum Producers.

“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 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 refinery that approximates the per barrel refining margin resulting from processing four barrels of crude oil to produce three barrels of gasoline and one-half barrel of jet fuel and one-half barrel of ULSD.

“Dated Brent” refers to Brent blend oil, a light, sweet North Sea crude oil, characterized by an API gravity of 38° and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for other crude oils.

“distillates” refers primarily to diesel, heating oil, kerosene and jet fuel.

“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.

“FCC” refers to fluid catalytic cracking.

“FCU” refers to fluid coking unit.

“GHG” refers to greenhouse gas.

“Group I base oils or lubricants” refers to conventionally refined products characterized by a 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.

“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.

“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.

“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.

“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.

“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 an 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.

“WCS” refers to Western Canadian Select, a heavy, sour crude oil blend typically characterized by an 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 an 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 an 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.

ITEM 1A. RISK FACTORS

Risks Relating to Our Business and Industry

You should carefully read the risks and uncertainties described below. The risks and uncertainties described below are not the only ones facing our company. Additional risks and uncertainties may also impair our business operations. If any of the following risks actually occur, our business, financial condition, results of operations or cash flows would likely suffer. In that case, the trading price of our Class A common stock could fall.

We have incurred losses in the past and may incur losses in the future. If we incur losses over an extended period of time, the value of our Class A common stock could decline.

We experienced losses during our time as a development company and certain periods thereafter. We may not be profitable in future periods. A lack of profitability could adversely affect the price of our Class A common stock. We may not continue to remain profitable, which could impair our ability to complete future financings and have a material adverse effect on our business.

Our limited operating history makes it difficult to evaluate our current business and future prospects. If we are unsuccessful in executing our business model, our business and operating results will be adversely affected.

We were formed in March 2008, we acquired our first oil refinery in June 2010 in an idle state and we acquired our first operating asset in December 2010. Therefore, we have a limited operating history and track record in executing our business model. Our future success depends on our ability to execute our business strategy effectively. Our limited operating history may make it difficult to evaluate our current business and future prospects. We may not be successful in operating any of our refineries or any other properties we may acquire in the future. In addition, we have encountered and will continue to encounter risks and difficulties frequently experienced by new companies, and specifically companies in the oil refining industry. If we do not manage these risks successfully, our business, results of operations and financial condition will be adversely affected.

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 inventories were to decline to an amount less than our LIFO cost, we would record a write-down of inventory and a non-cash charge to cost of sales.

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 revenues, profitability and cash flows.

Our historical financial statements may not be helpful in predicting our future performance.

We have grown rapidly since our inception and have not owned or operated our refineries for a substantial period of time. Accordingly, our historical financial information may not be useful either as a means of understanding our current financial situation or as an indicator of our future results. For the period from March 1, 2008 to December 16, 2010, we were considered to be in the development stage. Our historical financial information for that period reflects our activities principally in connection with identifying acquisition opportunities; acquiring the Delaware City refinery assets and commencing a reconfiguration of the refinery; and acquiring the Paulsboro refinery. As a result of the Paulsboro and Toledo acquisitions, our historical consolidated financial results include the results of operations for Paulsboro and Toledo from December 17, 2010 and March 1, 2011 forward, respectively. Certain information in our financial statements and certain other financial data included in this Annual Report on Form 10-K are based in part on financial data related to, and the operations of, those companies that previously owned and operated our refineries. For example, at the time of its acquisition, Paulsboro represented the major portion of our business and assets. As has been the case in our acquisitions to date, it is likely that, when we acquire refineries, we will not have access to the type of historical financial information that we will report regarding the prior operation of the refineries. As a result, it may be difficult for investors to evaluate the probable impact of major acquisitions on our financial performance until we have operated the acquired refineries for a substantial period of time.

Our profitability is affected by crude oil differentials, 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 processed at our Delaware City and Paulsboro refineries and the WTI based crude oils processed at our Toledo refinery and delivered by rail to our East Coast refineries. These crude oil differentials 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 Midcontinent and Canadian crude, which are priced based on WTI, could be adversely affected if the WTI-Brent differential narrows. For example, the WTI/WCS differential, a proxy for the difference between light U.S. and heavy Canadian crudes, has increased from $21.80 per barrel in 2012 to $24.62 per barrel for the year ended December 31, 2013, however, this increase may not be indicative of the differential going forward. Conversely, a narrowing of the light-heavy differential may reduce our refining margins and adversely affect our recent profitability and earnings. In addition, while our Toledo refinery benefits from a widening of the Dated Brent/WTI differential, a narrowing of this differential may result in our Toledo refinery losing a portion of its crude price advantage over certain of our competitors, which negatively impacts our profitability. This applies as well to our East Coast strategy of delivering crude by rail. Divergent views have been expressed as to the expected magnitude of changes to these crude differentials in future periods, including some analysts that expect these crude differentials to contract in upcoming periods. Any narrowing of these differentials could have a material adverse effect on our business and profitability.

Our recent historical earnings have been concentrated and may continue to be concentrated in the future.

Our three 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 has produced a substantial portion of our earnings over the past several quarters. 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) disproportionally to Toledo’s portion of our consolidated throughput. The Toledo refinery, or one of our other refineries, may continue to disproportionally 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 three refineries and related assets. As a result, our operations could be subject to significant interruption if any of our refineries were to experience a major accident, be damaged by severe weather or other natural disaster, or otherwise be forced to shut down or curtail production due to unforeseen events, such as acts of God, nature, orders of governmental authorities, supply chain disruptions impacting our crude rail facilities or other logistical assets, power outages, acts of terrorism, fires, toxic emissions and maritime hazards. Any such shutdown or disruption would reduce the production from that refinery. There is also risk of mechanical failure and equipment shutdowns both 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.

During 2012 and 2013, we expanded and upgraded existing on-site railroad infrastructure at our Delaware City refinery, which significantly increased our capacity to unload crude by rail. Currently, the majority of the crude delivered to this facility is consumed at our Delaware City refinery, although we also transport some of the crude delivered by rail from Delaware City via barge to our Paulsboro refinery. The Delaware City rail unloading facilities allow our East Coast refineries to source WTI based crudes from Western Canada and the Midcontinent, which can provide significant cost advantages versus traditional Brent based international crudes. 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.

Our Toledo refinery receives a substantial portion of its crude oil and delivers a portion of its refined products through pipelines. The Enbridge system is our primary supply route for crude oil from Canada, the Bakken region and Michigan, and supplies approximately 55% to 60% of the crude oil used at our Toledo refinery. In addition, we source domestic crude oil through our connections to the Capline and Mid-Valley pipelines. We also distribute a portion of our transportation fuels through pipelines owned and operated by Sunoco Logistics Partners L.P. and Buckeye Partners L.P. 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 of events.

In addition, due to the common carrier regulatory obligation applicable to interstate oil pipelines, capacity is prorated among shippers in accordance with the tariff then in effect in the event there are nominations 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.

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. We terminated our supply agreement with Statoil for our Paulsboro refinery effective March 31, 2013 and our MSCG Offtake Agreements for our Paulsboro and Delaware City refineries effective July 1, 2013. Concurrent with the termination of our MSCG Offtake Agreements, we entered into Inventory Intermediation Agreements with J. Aron at our Paulsboro and Delaware City refineries. Pursuant to the Inventory Intermediation Agreements, J. Aron purchases and holds title to all of the intermediate and finished products produced by the Delaware City and Paulsboro refineries and delivered into the tanks at the refineries (or at other locations outside of the refineries as agreed upon by both parties). Furthermore, J. Aron agrees to sell the intermediate and finished products back to us as they are discharged out of the refineries' tanks (or other locations outside of the refineries as agreed upon by both parties). We market and sell the finished products independently to third parties.

If we cannot adequately handle our crude oil and feedstock requirements without the benefit of the Statoil arrangement at Paulsboro, or if we are required to obtain our crude oil supply at our other refineries without the benefit of the existing supply arrangements or the applicable counterparty defaults in its obligations, our crude oil pricing costs may increase as the number of days between when we pay for the crude oil and when the crude oil is delivered to us increases. Termination of our Inventory Intermediation Agreements with J. Aron would require us to finance our refined products inventory covered by the agreements at terms that may not be as favorable. Additionally, we are obligated to repurchase from J. Aron all volumes of products located at the refineries’ storage tanks (or at other locations outside of the refineries as agreed upon by both parties) upon termination of these agreements, which may have a material adverse impact on our working capital and financial condition. Further, if we are not able to market and sell our finished products to credit worthy customers, we may be subject to delays in the collection of our accounts receivable and exposure to additional credit risk. Such increased exposure could negatively impact our liquidity due to our increased working capital needs as a result of the increase in the amount of crude oil inventory and accounts receivable we would have to carry on our 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 acquisition, 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 will affect our ability to satisfy any 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.

Global financial markets and economic conditions have been, and continue to be, disrupted and volatile due to a variety of factors, including uncertainty in the financial services sector, low consumer confidence, continued high unemployment, geopolitical issues and the current weak economic conditions. In addition, the fixed income markets have experienced periods of extreme volatility that have negatively impacted market liquidity conditions. As a result, the cost of raising money in the debt and equity capital markets has increased substantially at times while the availability of funds from those markets diminished significantly. In particular, as a result of concerns about the stability of financial markets generally 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 may become obsolete, or be unable to compete, because of the construction of new, more efficient facilities by our competitors.

Any political instability, military strikes, sustained military campaigns, terrorist activity, or changes in foreign policy could have a material adverse effect on our business, results of operations and financial condition.

Any political instability, military strikes, sustained military campaigns, terrorist activity, or changes in foreign policy in areas or regions of the world where we acquire crude oil and other raw materials or sell our refined petroleum products may affect our business in unpredictable ways, including forcing us to increase security measures and causing disruptions of supplies and distribution markets. We may also be subject to United States trade and economic sanctions laws, which change frequently as a result of foreign policy developments, and which may necessitate changes to our crude oil acquisition activities. Further, like other industrial companies, our facilities may be the target of terrorist activities. Any act of war or terrorism that resulted in damage to any of our refineries or third-party facilities upon which we are dependent for our business operations could have a material adverse effect on our business, results of operations and financial condition.

Continued economic turmoil in the global financial system has had and may continue to 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 have 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, continued 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 the continued 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.

The geographic concentration of our East Coast refineries creates a significant exposure to the risks of the local economy and other local adverse conditions.

Our East Coast refineries are both located in the mid-Atlantic region on the East Coast and therefore are vulnerable to economic downturns in that region. These refineries are located within a relatively limited geographic area and we primarily market our refined products in that area. As a result, we are more susceptible to regional conditions than the operations of more geographically diversified competitors and any unforeseen events or circumstances that affect the area could also materially adversely affect our revenues and profitability. These factors include, among other things, changes in the economy, damages to infrastructure, weather conditions, demographics and population.

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) 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 issuing regulatory approvals and/or permits;


•	unplanned increases in the cost of construction materials or labor;


•	disruptions in transportation of modular components and/or construction materials;


•	severe adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors and suppliers;


•	shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;


•	market-related increases in a project’s debt or equity financing costs; and/or


•	non-performance or force majeure by, or disputes with, vendors, suppliers, contractors or sub-contractors involved with a project.

Our refineries contain many processing units, a number of which have been in operation for many years. Equipment, even if properly maintained, may require significant capital expenditures and expenses to keep it operating at optimum efficiency. One or more of the units may require unscheduled downtime for unanticipated maintenance or repairs that are more frequent than our scheduled turnarounds for such units. Scheduled and unscheduled maintenance could reduce our revenues during the period of time that the units are not operating.

Our forecasted internal rates of return are also based upon our projections of future market fundamentals, which are not within our control, including changes in general economic conditions, available alternative supply and customer demand. Any one or more of these factors could have a significant impact on our business. If we were unable to make up the delays associated with such factors or to recover the related costs, or if market conditions change, it could materially and adversely affect our financial position, results of operations or cash flows.

Acquisitions that we may undertake in the future involve a number of risks, any of which could cause us not to realize the anticipated benefits.

We may not be successful in acquiring additional assets, and any acquisitions that we do consummate may not produce the anticipated benefits or may have adverse effects on our business and operating results. We may selectively consider strategic acquisitions in the future within the refining and mid-stream sector based on performance through the cycle, advantageous access to crude oil supplies, attractive refined products market fundamentals and access to distribution and logistics infrastructure. Our ability to do so will be dependent upon a number of factors, including our ability to identify acceptable acquisition candidates, consummate acquisitions on acceptable terms, successfully integrate acquired assets and obtain financing to fund acquisitions and to support our growth and many other factors beyond our control. Risks associated with acquisitions include those relating to the diversion of management time and attention from our existing business, liability for known or unknown environmental conditions or other contingent liabilities and greater than anticipated expenditures required for compliance with environmental, safety or other regulatory standards or for investments to improve operating results, 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.

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.

As of December 31, 2013, approximately 296 of our 460 employees at Paulsboro are covered by a collective bargaining agreement that expires in March of 2015. In addition, 678 of our 1,066 employees at Delaware City and Toledo are covered by a collective bargaining agreement that expires in February of 2015. We may not be able to renegotiate our collective bargaining agreements on satisfactory terms or at all when such agreements expire. A failure to do so may increase our costs. Other employees of ours, who are not presently represented by a union, may become so represented in the future. In addition, our existing labor agreements may not prevent a strike or work stoppage at any of our facilities in the future, and any work stoppage could negatively affect our results of operations and financial condition.

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, or MSCG or Statoil at our request, may hedge some percentage of future crude supply. We may enter into hedging arrangements with the intent to secure a minimum fixed cash flow stream on the volume of products hedged during the hedge term and to protect against volatility in commodity prices. Our hedging arrangements may fail to fully achieve these objectives for a variety of reasons, including our failure to have adequate hedging arrangements, if any, in effect at any particular time and the failure of our hedging arrangements to produce the anticipated results. We may not be able to procure adequate hedging arrangements due to a variety of factors. Moreover, such transactions may limit our ability to benefit from favorable changes in crude oil and refined product prices. In addition, our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which:


•	the volumes of our actual use of crude oil or production of the applicable refined products is less than the volumes subject to the hedging arrangement;


•	accidents, interruptions in feedstock transportation, inclement weather or other events cause unscheduled shutdowns or otherwise adversely affect our refineries, or those of our suppliers or customers;


•	changes in commodity prices have a material impact on collateral and margin requirements under our hedging arrangements, resulting in our being subject to margin calls;


•	the counterparties to our futures 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 crude oil or refined products may have more or less variability than the cost or price for such crude oil or refined products. We generally do not expect to hedge the basis risk inherent in our derivatives 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 the unsettled position. These gains and losses may be reflected in our income statement in periods that differ from when the underlying hedged items (i.e., gross margins) 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 adopted 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, adopted regulations to set position limits for certain futures and option contracts in the major energy markets. Although these regulations were recently vacated by the U.S. District Court for the District of Columbia, the court remanded the matter to the CFTC and the CFTC voted on November 15, 2012 to appeal the District Court’s decision. The legislation 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 any new 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 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 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, 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.

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 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.

Furthermore, our Delaware City refinery and our Delaware City Rail Terminal are located in Delaware's coastal zone where certain activities are regulated under the Delaware Coastal Zone Act and closely monitored by environmental interest groups. On June 14, 2013, two administrative appeals were filed by the Sierra Club and Delaware Audubon regarding a permit Delaware City Refining Company LLC (“DCR”) obtained to allow loading of crude oil onto barges. The appeals allege that both the loading of crude oil onto barges and the operation of the Delaware City rail unloading terminal violate Delaware’s Coastal Zone Act. The first appeal is Number 2013-1 before the State Coastal Zone Industrial Control Board (the “CZ Board”), and the second appeal is before the Environmental Appeals Board and appeals Secretary’s Order No. 2013-A-0020. The CZ Board held a hearing on the first appeal on July 16, 2013, and ruled in favor of DCR and the State of Delaware and dismissed the Appellants’ appeal for lack of standing. Sierra Club and Delaware Audubon have appealed that decision to the Delaware Superior Court, New Castle County, Case No. N13A-09-001 ALR, and Delaware City Refining

and the State have filed cross-appeals. Briefs are due to be filed in this appeal in the first quarter of 2014 but no date has been set for a decision by the Superior Court. A hearing on the second appeal before the Environmental Appeals Board, case no. 2013-06, was held on January 13, 2014, and the Board ruled in favor of Delaware City Refining and the State and dismissed the appeal for lack of jurisdiction. A written decision from the Board is pending, after which the Appellants will again have the right to appeal the decision to Superior Court. If the Appellants in one or both of these matters ultimately prevail, the outcome may have an adverse material effect on our financial condition, results of operations or cash flows.

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 the Paulsboro and Delaware City refineries. In connection with the acquisitions 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 remediation obligations at the Paulsboro refinery. 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, MTBE 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 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, or 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. Efforts have also been undertaken to delay, limit or prohibit EPA and possibly state action to regulate GHG emissions, and it is not possible at this time to predict the ultimate form, timing or extent of federal or state regulation. In 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.

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.

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 must purchase credits, known as “RINS,” which have fluctuating costs.

Our pipelines are subject to federal and/or state regulations, which could reduce the amount of cash we generate.

Our transportation activities are subject to regulation by multiple governmental agencies. The regulatory burden on the industry increases the cost of doing business and affects profitability. Additional proposals and proceedings that affect the oil industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission, the United States Department of Transportation, and the courts. We cannot predict when or whether any such proposals may become effective or what impact such proposals may have. Projected operating costs related to our pipelines reflect the recurring costs resulting from compliance with these regulations, and these costs may increase due to future acquisitions, changes in regulation, changes in use, or discovery of existing but unknown compliance issues.

We are subject to strict laws and regulations regarding employee and process safety, and failure to comply with these laws and regulations could have a material adverse effect on our results of operations, financial condition and profitability.

We are subject to the requirements of the Occupational Safety & Health Administration, or OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, OSHA requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees, state and local governmental authorities, and local residents. Failure to comply with OSHA requirements, including general industry standards, process safety standards and control of occupational exposure to regulated substances, could have a material adverse effect on our results of operations, financial condition and the cash flows of the business if we are subjected to significant fines or compliance costs.

Compliance with and changes in tax laws could adversely affect our performance.

We are subject to extensive tax liabilities, including federal, state, local and foreign taxes such as income, excise, sales/use, payroll, franchise, property, gross receipts, withholding and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future. These liabilities are subject to periodic audits by the respective taxing authorities, which could increase our tax liabilities. Subsequent changes to our tax liabilities as a result of these audits may also subject us to interest and penalties. There can be no certainty that our federal, state, local or foreign taxes could be passed on to our customers.

Our rapid growth may strain our resources and divert management’s attention.

We were a development stage enterprise prior to our acquisition of Paulsboro on December 17, 2010. With the further acquisition of Toledo, the re-start of Delaware City, our IPO and construction of our rail facilities, we have experienced rapid growth in a short period of time. Continued expansion may strain our resources and force management to focus attention from other business concerns to the development of incremental internal controls and procedures, which could harm our business and operating results. We may also need to hire more employees, which will increase our costs and expenses.

We rely on Statoil and MSCG, over whom we may have limited control, to provide us with certain volumetric and pricing data used in our inventory valuations.

We rely on Statoil and MSCG to provide us with certain volumetric and pricing data used in our inventory valuations. Our limited control over the accuracy and the timing of the receipt of this data could materially and adversely affect our ability to produce financial statements in a timely manner.

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 recent 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. If changes in law, regulations or industry standards occur that result in requirements to reduce the volatile or flammable constituents in crude oil that is transported by rail, alter the design or standards for rail cars, 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 refineries, our costs could increase, which could have a material adverse effect on our financial condition, results of operations and cash flows.

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.

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.

dismissed the appeal for lack of jurisdiction. A written decision from the Board is pending, after which the Appellants will again have the right to appeal the decision to Superior Court. If the Appellants in one or both of these matters ultimately prevail, the outcome may have an adverse material effect on our financial condition, results of operations or cash flows.

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, 2013, we have total long-term debt including the Delaware Economic Development Authority Loan, of $747.6 million, all of which is secured, and we could have incurred an additional $615.9 million of senior secured indebtedness under our existing debt agreements. We may incur additional indebtedness in the future. Our strategy includes executing future refinery 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 subsidiaries’ ability to meet their principal obligations will be dependent upon our future performance, which in turn will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our business may not continue to generate sufficient cash flow from operations to repay our 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 indenture could discourage an acquisition of us by a third party.

Certain provisions of our indenture 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 defined in the indenture, 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, to the date of repurchase.

Risks Related to Our Organizational Structure and Our Class A Common Stock

Our only material asset is our interest in PBF LLC. Accordingly, we depend upon distributions from PBF LLC and its subsidiaries to pay our taxes, meet our other obligations and/or pay dividends in the future.

We are a holding company and all of our operations are conducted through subsidiaries of PBF Holding. We have no independent means of generating revenue and no material assets other than our ownership interest in PBF LLC. Therefore, we depend on the earnings and cash flow of our subsidiaries to meet our obligations, including our indebtedness, tax liabilities and obligations to make payments under our tax receivable agreement. If we or PBF LLC do not receive such cash distributions, dividends or other payments from our subsidiaries, we and PBF LLC may be unable to meet our obligations and/or pay dividends.

We intend to cause PBF LLC to make distributions to its members in an amount sufficient to enable us to cover all applicable taxes at assumed tax rates, make payments owed by us under the tax receivable agreement, and to pay other obligations and dividends, if any, declared by us. To the extent we need funds and PBF LLC or any of its subsidiaries is restricted from making such distributions under applicable law or regulation or under the terms of our financing or other contractual arrangements, or is otherwise unable to provide such funds, such restrictions could materially adversely affect our liquidity and financial condition.

Our ABL Revolving Credit Facility, 8.25% Senior Secured Notes due 2020 issued by PBF Holding in February 2012, or Senior Secured Notes, and certain of our other outstanding debt arrangements include a restricted payment covenant, which restricts the ability of PBF Holding to make distributions to us, and we anticipate our future debt will contain a similar restriction. In addition, there may be restrictions on payments by our subsidiaries under applicable laws, including laws that require companies to maintain minimum amounts of capital and to make payments to stockholders only from profits. For example, PBF Holding is generally prohibited under Delaware law from making a distribution to a member to the extent that, at the time of the distribution, after giving effect to the distribution, liabilities of the limited liability company (with certain exceptions) exceed the fair value of its assets. As a result, we may be unable to obtain that cash to satisfy our obligations and make payments to our stockholders, if any.

Blackstone and First Reserve through their ownership of units of PBF LLC have substantial influence or control over us, and their interests may differ from those of our public stockholders.

As of February 20, 2014, Blackstone and First Reserve collectively possess in the aggregate approximately 38.0% of the combined voting power of our common stock. As a result, Blackstone and First Reserve have the ability to significantly influence or control the management and affairs of our company and potentially determine the outcome of matters submitted to our stockholders for approval, including the election and removal of our directors, the appointment of management, future issuances of securities, the incurrence of debt by us, amendments to our organizational documents, making acquisitions and significant investments and capital expenditures and the entering into of extraordinary transactions. Blackstone’s and First Reserve’s interests may not in all cases be aligned with our Class A common stockholders’ interests.

For example, Blackstone and First Reserve may have different tax positions which could influence their positions, including regarding whether and when we dispose of assets and whether and when we incur new or refinance existing indebtedness, especially in light of the existence of the tax receivable agreement described below. In addition, the structuring of future transactions may take into consideration these tax or other considerations even where no similar benefit would accrue to our Class A common stockholders or us. See “Item 13. Certain Relationships and Related Transactions, and Director Independence.”

Blackstone and First Reserve may have an interest in pursuing acquisitions, divestitures and other transactions that, in their judgment, could enhance their equity investment, even though such transactions might involve risks to our Class A common stockholders. For example, they could influence us to make acquisitions, investments and capital expenditures that increase our indebtedness, or to sell revenue-generating assets or to not make such acquisitions, investments or capital expenditures. Pursuant to the stockholders agreement we are party to with Blackstone and First Reserve, following the January 2014 Secondary Offering, Blackstone and First Reserve will each have the ability to nominate two of our directors so long as it owns between 15% and 25% of our voting stock, and one director so long as it owns between 7.5% and 15%

of our voting stock. See “Item 13. Certain Relationships and Related Transactions, and Director Independence.” This concentration of ownership may have the effect of delaying, preventing or deterring a change of control of our company. Lastly, Blackstone and First Reserve are in the business of making investments in companies and may from time to time acquire and hold interests in businesses that compete directly or indirectly with us. Our certificate of incorporation contains a provision renouncing our interest and expectancy in certain corporate opportunities identified by Blackstone or First Reserve. They may also pursue acquisition opportunities that are complementary to our business and, as a result, those acquisition opportunities may not be available to us.

Although we are no longer a “controlled company” within the meaning of the NYSE rules, we may rely on exemptions from certain corporate governance requirements during a one-year transition period.

Following our January 2014 Secondary Offering, Blackstone and First Reserve no longer control a majority of the combined voting power of all classes of our voting stock. As a result, we no longer are a “controlled company” within the meaning of the NYSE corporate governance standards. Under the NYSE rules, a majority of our directors must be independent within one year of the date we no longer qualify as a “controlled company.” The NYSE rules also require that we have at least one independent director on each of the compensation and nominating and corporate governance committees prior to the date we no longer qualify as a “controlled company,” at least a majority of independent members within 90 days of such date and that the compensation and nominating and corporate governance committees be composed entirely of independent directors within one year of such date. We might utilize certain of these exemptions during these transition periods. Accordingly, until January 2015, our stockholders may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE. See “Item 13. Certain Relationships and Related Transactions and Director Independence.”

We will be required to pay the holders of PBF LLC Series A Units and PBF LLC Series B Units for certain tax benefits we may claim arising in connection with our prior offerings and future exchanges of PBF LLC Series A Units for shares of our Class A Common Stock and related transactions, and the amounts we may pay could be significant.

We are party to a tax receivable agreement that provides for the payment from time to time by PBF Energy to the holders of PBF LLC Series A Units and PBF LLC Series B Units of 85% of the benefits, if any, that PBF Energy is deemed to realize as a result of (i) the increases in tax basis resulting from its acquisitions of PBF LLC Series A Units, including such acquisitions in connection with our prior offerings or in the future and (ii) certain other tax benefits related to our entering into the tax receivable agreement, including tax benefits attributable to payments under the tax receivable agreement. See “Item 13. Certain Relationships and Related Transactions, and Director Independence.”

We expect that the payments that we may make under the tax receivable agreement will be substantial. As of December 31, 2013, we have recognized a liability for the tax receivable agreement of $287.3 million reflecting our estimate of the undiscounted amounts that we expect to pay under the agreement due to exchanges that occurred prior to that date, and to range over the next five years from approximately $12.5 million to $34.6 million per year and decline thereafter. Assuming no material changes in the relevant tax law, and that we earn sufficient taxable income to realize all tax benefits that are subject to the tax receivable agreement, we expect that additional future payments under the tax receivable agreement relating to the exchange by the selling stockholders in connection with the January 2014 Secondary Offering to aggregate $140.5 million. Future payments by us in respect of subsequent exchanges of PBF LLC Series A Units would be in addition to these amounts and are expected to be substantial as well. For example, if 50%, with respect to the amount and timing of PBF Energy income, or more of the capital and profits interests in PBF LLC are transferred in a taxable sale or exchange within a period of 12 consecutive months, PBF LLC will undergo, for federal income tax purposes, a “technical termination” that could affect the amount of PBF LLC’s taxable income in any year and the allocation of taxable income among the members of PBF LLC, including PBF Energy. If PBF Energy does not have taxable income, PBF Energy generally is not required (absent a change of control or circumstances requiring an early termination payment) to make payments under the tax receivable agreement for that taxable year because no benefit will have been actually realized. However, any tax benefits that do not result in realized benefits in a given tax year will likely generate tax attributes that may be utilized to generate benefits in previous or future tax years. The utilization of such tax attributes will result in payments under the tax receivable agreement. The foregoing numbers are merely estimates based on assumptions that are subject to change due to various factors, including, among other factors, the timing of exchanges of PBF LLC Series A Units for shares of PBF Energy’s Class A common stock as contemplated by the tax receivable agreement, the price of PBF Energy’s Class A common stock at the time of such exchanges, the extent to which such exchanges are taxable, and the amount and timing of PBF Energy’s income. The actual payments could differ materially from the estimates above. It is possible that future transactions or events could increase or decrease the actual tax benefits realized and the corresponding tax receivable agreement payments. There may be a material negative effect on our liquidity if, as a result of timing discrepancies or otherwise, (i) the payments under the tax receivable agreement exceed the actual benefits we realize in respect of the tax attributes subject to the tax receivable

agreement, and/or (ii) distributions to PBF Energy by PBF LLC are not sufficient to permit PBF Energy, after it has paid its taxes and other obligations, to make payments under the tax receivable agreement. The payments under the tax receivable agreement are not conditioned upon any recipient’s continued ownership of us.

In certain cases, payments by us under the tax receivable agreement may be accelerated and/or significantly exceed the actual benefits we realize in respect of the tax attributes subject to the tax receivable agreement. These provisions may deter a change in control of our Company.

The tax receivable agreement provides that upon certain changes of control, or if, at any time, PBF Energy elects an early termination of the tax receivable agreement, PBF Energy’s (or its successor’s) obligations with respect to exchanged or acquired PBF LLC Series A Units (whether exchanged or acquired before or after such transaction) would be based on certain assumptions, including (i) that PBF Energy would have sufficient taxable income to fully utilize the deductions arising from the increased tax deductions and tax basis and other benefits related to entering into the tax receivable agreement and (ii) that the subsidiaries of PBF LLC will sell certain nonamortizable assets (and realize certain related tax benefits) no later than a specified date. Moreover, in each of these instances, we would be required to make an immediate payment equal to the present value (at a discount rate equal to LIBOR plus 100 basis points) of the anticipated future tax benefits (based on the foregoing assumptions). Accordingly, payments under the tax receivable agreement may be made years in advance of the actual realization, if any, of the anticipated future tax benefits and may be significantly greater than the actual benefits we realize in respect of the tax attributes subject to the tax receivable agreement. Assuming that the market value of a share of our Class A common stock equals $31.46 per share (the closing price on December 31, 2013) and that LIBOR were to be 1.85%, we estimate that, as of December 31, 2013 the aggregate amount of these accelerated payments would have been approximately $789.4 million if triggered immediately on such date. In these situations, our obligations under the tax receivable agreement could have a substantial negative impact on our liquidity. We may not be able to finance our obligations under the tax receivable agreement and our existing indebtedness may limit our subsidiaries’ ability to make distributions to us to pay these obligations. These provisions may deter a potential sale of our Company to a third party and may otherwise make it less likely that a third party would enter into a change of control transaction with us.

Moreover, payments under the tax receivable agreement will be based on the tax reporting positions that we determine in accordance with the tax receivable agreement. We will not be reimbursed for any payments previously made under the tax receivable agreement if the Internal Revenue Service subsequently disallows part or all of the tax benefits that gave rise to such prior payments. As a result, in certain circumstances, payments could be made under the tax receivable agreement that are significantly in excess of the benefits that we actually realize in respect of (i) the increases in tax basis resulting from our purchases or exchanges of PBF LLC Series A Units and (ii) certain other tax benefits related to our entering into the tax receivable agreement, including tax benefits attributable to payments under the tax receivable agreement.

The requirements of being a public company may strain our resources and distract our management.

As a public company, we are subject to the reporting requirements of the Securities Exchange Act of 1934, as amended, and requirements of the Sarbanes-Oxley Act of 2002. These requirements may place a strain on our systems and resources. The Exchange Act requires that we file annual, quarterly and current reports with respect to our business and financial condition. The Sarbanes-Oxley Act requires that we maintain effective disclosure controls and procedures and internal controls over financial reporting. We have implemented additional procedures and processes for the purpose of addressing the standards and requirements applicable to public companies. In addition, sustaining our growth also will require us to commit additional management, operational and financial resources to identify new professionals to join our firm and to maintain appropriate operational and financial systems to adequately support expansion. These activities may divert management’s attention from other business concerns, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. We expect to incur significant additional annual expenses related to these steps and other public company expenses.

We cannot assure you that we will continue to declare dividends or have the available cash to make dividend payments.

Although we currently intend to pay quarterly cash dividends on our Class A common stock, the declaration, amount and payment of any dividends will be at the sole discretion of our board of directors. We are not obligated under any applicable laws, our governing documents or any contractual agreements with our existing owners or otherwise to declare or pay any dividends or other distributions (other than the obligations of PBF LLC to make tax distributions to its members). Our board of directors may take into account, among other things, general economic conditions, our financial condition and operating results, our available cash and current and anticipated cash needs, capital requirements, plans for expansion, tax, legal, regulatory and contractual restrictions and implications, including under our outstanding debt documents, and such other factors as our board of directors may deem relevant in determining whether to declare or pay any dividend. Because PBF Energy is a holding company with no material assets (other than the equity interests of its direct subsidiary), its cash flow

and ability to pay dividends is dependent upon the financial results and cash flows of its direct subsidiary PBF Holding and its operating subsidiaries and the distribution or other payment of cash to it in the form of dividends or otherwise. The direct and indirect subsidiaries of PBF Energy are separate and distinct legal entities and have no obligation to make any funds available to it. As a result, if we do not declare or pay dividends you may not receive any return on an investment in our Class A common stock unless you sell our Class A common stock for a price greater than that which you paid for it.

Anti-takeover and certain other provisions in our certificate of incorporation and bylaws and Delaware law may discourage or delay a change in control.

Our certificate of incorporation and bylaws contain provisions which could make it more difficult for stockholders to effect certain corporate actions. Among other things, these provisions:


•	authorize the issuance of undesignated preferred stock, the terms of which may be established and the shares of which may be issued without stockholder approval;


•	prohibit stockholder action by written consent now that Blackstone and First Reserve collectively cease to beneficially own at least a majority of all of the outstanding shares of our capital stock entitled to vote;


•	restrict certain business combinations with stockholders who obtain beneficial ownership of a certain percentage of our outstanding common stock after the date Blackstone and First Reserve and their affiliates collectively cease to beneficially own at least 5% of all of the outstanding shares of our capital stock entitled to vote;


•	provide that special meetings of stockholders may be called only by the chairman of the board of directors, the chief executive officer or the board of directors, and establish advance notice procedures for the nomination of candidates for election as directors or for proposing matters that can be acted upon at stockholder meetings; and


•	provide now that Blackstone and First Reserve collectively cease to beneficially own a majority of all of the outstanding shares of our capital stock entitled to vote, our stockholders may only amend our bylaws with the approval of 75% or more of all of the outstanding shares of our capital stock entitled to vote.

These anti-takeover provisions and other provisions of Delaware law may have the effect of delaying or deterring a change of control of our company. Certain provisions could also discourage proxy contests and make it more difficult for you and other stockholders to elect directors of your choosing and to cause us to take other corporate actions you desire. These provisions could limit the price that certain investors might be willing to pay in the future for shares of our Class A common stock.

In addition, in connection with our initial public offering, we entered into a stockholders agreement with Blackstone and First Reserve pursuant to which they will each be entitled to nominate a number of directors so long as certain ownership thresholds are maintained.

The market price of our Class A common stock may be volatile, which could cause the value of your investment to decline.

The market price of our Class A common stock may be highly volatile and could be subject to wide fluctuations due to a number of factors including:


•	variations in actual or anticipated operating results or dividends, if any, to stockholders;


•	changes in, or failure to meet, earnings estimates of securities analysts;


•	market conditions in the oil refining industry;


•	the impact of disruptions to crude or feedstock supply to any of our refineries, including disruptions due to problems with third party logistics infrastructure;


•	litigation and government investigations;


•	the timing and announcement of any potential acquisitions and subsequent impact of any future acquisitions on our capital structure, financial condition or results of operations;


•	changes or proposed changes in laws or regulations or differing interpretations or enforcement thereof affecting our business or industry, including any lifting by the federal government of the restrictions on exporting U.S. crude oil;


•	general economic and stock market conditions; and


•	the availability for sale, or sales, of a significant number of shares of our Class A common stock in the public market.

In addition, the stock markets generally may experience significant volatility, often unrelated to the operating performance of the individual companies whose securities are publicly traded. These and other factors may cause the market price of our Class A common stock to decrease significantly, which in turn would adversely affect the value of your investment.

In the past, following periods of volatility in the market price of a company’s securities, stockholders have often instituted class action securities litigation against those companies. Such litigation, if instituted, could result in substantial costs and a diversion of management’s attention and resources, which could significantly harm our profitability and reputation.

If securities or industry analysts do not publish research or reports about our business, or if they downgrade their recommendations regarding our Class A common stock, our stock price and trading volume could decline.

The trading market for our Class A common stock is influenced by the research and reports that industry or securities analysts publish about us or our business. If any of the analysts who cover us downgrade our Class A common stock or publish inaccurate or unfavorable research about our business, our Class A common stock price may decline. If analysts cease coverage of us or fail to regularly publish reports on us, we could lose visibility in the financial markets, which in turn could cause our Class A common stock price or trading volume to decline and our Class A common stock to be less liquid.

Future sales of our shares of Class A common stock could cause our stock price to decline.

The market price of our Class A common stock could decline as a result of sales of a large number of shares of Class A common stock in the market or the perception that such sales could occur. These sales, or the possibility that these sales may occur, including sales related to financing acquisitions, also might make it more difficult for us to sell shares of Class A common stock in the future at a time and at a price that we deem appropriate. In addition, any shares of Class A common stock that we issue, including under any equity incentive plans, would dilute the percentage ownership of the holders of our Class A common stock.

We are party to a registration rights agreement with the other members of PBF LLC pursuant to which we continue to be required to register under the Securities Act and applicable state securities laws the resale of the shares of Class A common stock issuable to them upon exchange of all of the PBF LLC Series A Units held by them. We currently have an effective shelf registration statement covering the resale of up to 6,310,055 shares of our Class A common stock issued or issuable to certain holders of PBF LLC Series A Units (other than Blackstone and First Reserve), which shares may be sold from time to time in the public markets, subject to the lock-up agreements described below. Our shares also may be sold under Rule 144 under the Securities Act depending on the holding period and subject to restrictions in the case of shares held by persons deemed to be our affiliates.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

See “Item 1. Business”.

ITEM 3. LEGAL PROCEEDINGS

On June 14, 2013, two administrative appeals were filed by the Sierra Club and Delaware Audubon regarding a permit Delaware City Refining Company LLC (“DCR”) obtained to allow loading of crude oil onto barges. The appeals allege that both the loading of crude oil onto barges and the operation of the Delaware City rail unloading terminal violate Delaware’s Coastal Zone Act. The first appeal is Number 2013-1 before the State Coastal Zone Industrial Control Board (the “CZ Board”), and the second appeal is before the Environmental Appeals Board and appeals Secretary’s Order No. 2013-A-0020. The CZ Board held a hearing on the first appeal on July 16, 2013, and ruled in favor of DCR and the State of Delaware and dismissed the Appellants’ appeal for lack of standing. Sierra Club and Delaware Audubon have appealed that decision to the Delaware Superior Court, New Castle County, Case No. N13A-09-001 ALR, and DCR and the State have filed cross-appeals. Briefs are due to be filed in this appeal in the first quarter of 2014 but no date has been set for a decision by the Superior Court. A hearing on the second appeal before the Environmental Appeals Board, case no. 2013-06, was held on January 13, 2014, and the Board ruled in favor of DCR and the State and dismissed the appeal for lack of jurisdiction. A written decision from the Board is pending, after which the Appellants will again have the right to appeal the decision to Superior Court. If the Appellants in one or both of these matters ultimately prevail, the outcome may have an adverse material effect on our financial condition, results of operations or cash flows.

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 Company LLC 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.

ITEM 4. MINE SAFETY DISCLOSURE

None.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

PBF Energy Class A common stock trades on the New York Stock Exchange under the symbol “PBF.” Our Class B common stock is not publicly traded.

As of February 20, 2014 there were 8 holders of record of our Class A common stock and 40 holders of record of our Class B common stock, 100% of PBF Holding's outstanding membership interests were held by PBF LLC.

The following table sets forth, for the period indicated, the high and low sales prices of our Class A common stock as reported by the New York Stock Exchange from December 13, 2012, the first day of trading following our initial public offering, through December 31, 2013. The initial public offering price of our Class A common stock was $26.00 per share.



	Sales Prices of the Common Stock				Dividends Per Common Share
	High		Low		Dividends Per Common Share
2013:
First Quarter ended March 31, 2013	$	42.50	$	27.10	$	0.30
Second Quarter ended June 30, 2013	$	39.00	$	23.54	$	0.30
Third Quarter ended September 30, 2013	$	26.66	$	20.15	$	0.30
Fourth Quarter ended December 31, 2013	$	31.52	$	21.20	$	0.30
2012:
December 13 to December 31, 2012	$	29.05	$	26.00	$	—

There is no established public trading market for membership interests of PBF Holding.

Dividend Policy

Subject to the following paragraphs, PBF Energy currently intends to continue to pay quarterly cash dividends of approximately $0.30 per share on its Class A common stock.

The declaration, amount and payment of this and any other future dividends on shares of Class A common stock will be at the sole discretion of PBF Energy's board of directors, 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). PBF Energy's board of directors may take into account, among other things, general economic conditions, our financial condition and operating results, our available cash and current and anticipated cash needs, capital requirements, plans for expansion, tax, legal, regulatory and contractual restrictions and implications, including under PBF Energy's tax receivable agreement and our subsidiaries’ outstanding debt documents, and such other factors as PBF Energy's board of directors may deem relevant in determining whether to declare or pay any dividend. In addition, we expect that to the extent we declare a dividend for a particular quarter, our cash flow from operations for that quarter will substantially exceed any dividend payment for such period. Because any future declaration or payment of dividends will be at the sole discretion of PBF Energy's board of directors, we do not expect that any such dividend payments will have a material adverse impact on our liquidity or otherwise limit our ability to fund capital expenditures or otherwise pursue our business strategy over the long-term. Although we have the ability to borrow funds and sell assets to pay future dividends (subject to certain limitations in our ABL Revolving Credit Facility and the Senior Secured Notes), we intend to fund any future dividends out of our cash flow from operations and, as a result, we do not expect to incur any indebtedness or to use the proceeds from equity offerings to fund such payments.

PBF Energy is a holding company and has no material assets other than its ownership interests of PBF LLC. In order for PBF Energy to pay any dividends, they will need to cause PBF LLC to make distributions to it and the holders of PBF LLC Series A Units, and PBF LLC will need to cause PBF Holding to make distributions to it, in an amount sufficient to cover cash dividends, if any, declared by PBF Energy. PBF Holding is generally prohibited under Delaware law from making a distribution to a member to the extent that, at the time of the distribution, after giving effect to the distribution, liabilities of the limited liability company (with certain exceptions) exceed the fair value of its assets. As a result, PBF LLC may be unable to obtain cash from PBF Holding to satisfy its obligations and make distributions to PBF Energy for dividends, if any, to PBF Energy's stockholders. If PBF LLC makes such distributions to PBF Energy, the holders of PBF LLC Series A Units will also be entitled to receive pro rata distributions.

The ability of PBF Holding to pay dividends and make distributions to PBF LLC is, and in the future may be, limited by covenants in its ABL Revolving Credit Facility, the Senior Secured Notes and other debt instruments. Subject to certain exceptions, the ABL Revolving Credit Facility and the indenture governing the Senior Secured Notes prohibit PBF Holding from making distributions to PBF LLC if certain defaults exist. In addition, both the indenture and the ABL Revolving Credit Facility contain additional restrictions limiting PBF Holding’s ability to make distributions to PBF LLC. Subject to certain exceptions, the restricted payment covenant under the indenture restricts PBF Holding from making cash distributions unless its fixed charge coverage ratio, as defined in the indenture, is at least 2.0 to 1.0 after giving pro forma effect to such distributions and such cash distributions do not exceed an amount equal to the aggregate net equity proceeds received by it (either as a result of certain capital contributions or from the sale of certain equity or debt securities) plus 50% of its consolidated net income (or less 100% of consolidated net loss) which is defined to exclude certain non-cash charges, such as impairment charges, plus certain other items. Two important exceptions to the foregoing are (i) a permission to pay up to the greater of $100.0 million and 1% of PBF Holding’s total assets and (ii) a permission to pay an additional $200.0 million subject to compliance with a total debt ratio of 2.0 to 1.0. The ABL Revolving Credit Facility generally restricts PBF Holding’s ability to make cash distributions if (x) the aggregate amount of such distributions exceeds the then existing available amount basket (as defined by the ABL Revolving Credit Facility) and (y) before and after giving effect to any such distribution (a) it fails to have pro forma excess availability under the facility greater than an amount equal to 17.5% of the lesser of (1) the then existing borrowing base and (2) the then current aggregate revolving commitment amount, which as of December 31, 2013 was $1.610 billion or (b) it fails to maintain on a pro forma basis a fixed charge coverage ratio, as defined by the ABL Revolving Credit Facility, of at least 1.1 to 1.0. As a result, we cannot assure you that PBF Holding will be able to make distributions to PBF LLC in order for PBF LLC to make distributions to PBF Energy. If that is the case, it is unlikely that PBF Energy will be able to declare dividends as contemplated herein.

Based upon our operating results for the year ended December 31, 2013, PBF Holding was permitted under its ABL Revolving Credit Facility and indenture to pay distributions to PBF LLC so that PBF LLC could make distributions to its members, including us, in amounts sufficient to enable us to pay a quarterly dividend at the rate specified above. The ability of PBF Holding to comply with the foregoing limitations and restrictions is, to a significant degree, subject to its operating results, which is dependent on a number of factors outside of our control. As a result, we cannot assure you that we will be able to declare dividends as contemplated herein. See “Item 1A. Risk Factors - Risks Related to Our Organizational Structure and Class A Common Stock - We cannot assure you that we will continue to declare dividends or have the available cash to make dividend payments.”

PBF LLC made pre-IPO cash distributions to its members in the amount of $161.0 million during 2012. PBF Holding paid $215.8 million in distributions to PBF LLC during the year ended December 31, 2013. PBF LLC used $116.0 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 $37.9 million was distributed to PBF Energy and the balance was distributed to PBF LLC’s other members. PBF Energy used this $37.9 million to pay four separate equivalent cash dividends of $0.30 per share of Class A common stock on November 21, 2013, August 21, 2013, June 7, 2013 and March 15, 2013. PBF LLC used the remaining $99.8 million from PBF Holding’s distribution to make tax distributions to its members, with $20.2 million distributed to PBF Energy, of which $1.1 million was paid by PBF LLC directly to the applicable taxing authorities on behalf of PBF Energy, and $79.6 million to its other members.

PBF LLC will continue to make tax distributions to its members in accordance with its amended and restated limited liability company agreement.

Assuming approximately 96,867,147 PBF LLC Series A Units and PBF LLC Series C Units outstanding, the aggregate annual distributions which are anticipated to be required to be made by PBF Holding to PBF LLC, such that

PBF LLC may make an equivalent distribution to its members (including PBF Energy) in order for PBF Energy to pay the anticipated $0.30 per quarter cash dividend on its Class A common stock, would be approximately $116.2 million. As of December 31, 2013, PBF Holding had cash and cash equivalents of $77.0 million and approximately $615.9 million of unused borrowing availability under its ABL Revolving Credit Facility to fund its operations, if necessary. We believe our and our subsidiaries’ available cash and cash equivalents, other sources of liquidity to operate our business and operating performance provide us with a reasonable basis for our assessment that we can continue to support our intended dividend policy.

Stock Performance Graph

In accordance with SEC rules, the information contained in the Stock Performance Graph below shall not be deemed to be “soliciting material,” or to be “filed” with the SEC, or subject to the SEC’s Regulation 14A or 14C, other than as provided under Item 201(e) of Regulation S-K, or to the liabilities of Section 18 of the Securities Exchange Act of 1934, as amended, except to the extent that we specifically request that the information be treated as soliciting material or specifically incorporate it by reference into a document filed under the Securities Act of 1933, as amended.

This performance graph and the related textual information are based on historical data and are not indicative of future performance. The following line graph compares the cumulative total return on an investment in our common stock against the cumulative total return of the S&P 500 Composite Index and an index of peer companies (that we selected) for the period commencing December 13, 2012 and ending December 31, 2013. Our peer group consists of the following companies that are engaged in refining operations in the U.S.: Alon USA Energy, Inc.; CVR Energy Inc.; Delek US Holdings, Inc.; HollyFrontier Corporation; Marathon Petroleum Corporation; Phillips 66; Tesoro Corporation; Valero Energy Corporation; and Western Refining, Inc.



	12/13/2012		12/31/2012		12/31/2013
PBF Energy Inc. Class A Common Stock	$	100.00	$	110.67	$	124.73
S&P 500	100.00		100.91		133.59
Peer Group	100.00		103.11		149.73

Recent Sales of Unregistered Securities—Exchange of PBF LLC Series A Units to Class A Common Stock

In the fourth quarter of 2013, a total of 83,860 PBF LLC Series A Units were exchanged for 83,860 shares of our Class A common stock in transactions exempt from registration under Section 4(2) of the Securities Act. We received no other consideration in connection with these exchanges. No exchanges were made by any of our directors, executive officers or entities affiliated with Blackstone or First Reserve.

Additionally, on January 6, 2014, Blackstone and First Reserve completed a public offering of 15,000,000 shares of our Class A common stock at a price of $28.00 per share, less underwriting discounts and commissions, in a secondary public offering. All of the shares were sold by funds affiliated with Blackstone and First Reserve. In connection with

this offering, Blackstone and First Reserve exchanged 15,000,000 Series A Units of PBF LLC for an equivalent number of shares of our Class A common stock in a transaction exempt from registration under Section 4(2) of the Securities Act.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information about the securities authorized for issuance under our equity compensation plans as of December 31, 2013. The information regarding equity compensation plans approved by security holders represents our 2012 Equity Incentive Plan.



	Equity Compensation Plan Information
	(A)	(B)		(C)
	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants, and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (A))
Plan Category
Equity compensation plans approved by security holders	1,380,392	$	27.26	3,619,608
Equity compensation plans not approved by security holders	—	—		—
Total	1,380,392	$	27.26	3,619,608

(1) Securities available for future issuance under the plan can be issued in various forms, including, without limitation, restricted stock and stock options.

ITEM 6. SELECTED FINANCIAL DATA

The following table presents selected historical consolidated financial and other data of PBF Energy and PBF Holding. The data presented is PBF Energy's data, unless otherwise noted. The selected historical consolidated financial data as of December 31, 2013 and 2012 and for each of the three years in the period ended December 31, 2013 have been derived from our audited financial statements, included in “Item 8. Financial Statements and Supplementary Data.” The selected historical consolidated financial data as of December 31, 2011, 2010, and 2009 for the years ended December 31, 2010 and 2009 have been derived from the audited financials of PBF LLC and PBF Holding not included in this Annual Report on Form 10-K. As a result of the Paulsboro and Toledo acquisitions, the historical consolidated financial results of PBF LLC and PBF Holding only include the results of operations for Paulsboro and Toledo from December 17, 2010 and March 1, 2011 forward, respectively.

The historical consolidated financial data and other statistical data presented below should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” and our consolidated financial statements and the related notes thereto, included in “Item 8. Financial Statements and Supplementary Data.”

The historical financial information for all periods prior to PBF Energy's initial public offering included in this report were derived from the consolidated financial statements of PBF LLC and does not reflect what our financial position, results of operations, and cash flows would have been had we been a public company during those periods. We were not operated as a public company for historical periods presented prior to our initial public offering. The consolidated financial information may not be indicative of our future financial condition, results of operations or cash flows.

The following tables reflect our financial and operating highlights (amounts in thousands, except per share data) except for income taxes, net income attributable to noncontrolling interest and earnings per share for the years ended December 2013 and 2012, each of which apply only to the financial results of PBF Energy. In addition, general and administrative expenses for PBF Energy for the year ended December 31, 2013 include a charge of $8.5 million associated with a change in the tax receivable agreement liability. Total assets for PBF Energy include deferred tax

assets which do not apply to PBF Holding. PBF Holding's interest expense also includes interest related to an intercompany note with PBF Energy, which is eliminated in consolidation.



	Year Ended December 31,
	2013			2012			2011			2010			2009 (3)
Statement of operations data:
Revenues (1)	$	19,151,455		$	20,138,687		$	14,960,338		$	210,671		$	228
Costs and expenses:
Cost of sales, excluding depreciation	17,803,314			18,269,078			13,855,163			203,971			—
Operating expenses, excluding depreciation	812,652			738,824			658,831			25,140			—
General and administrative expenses	104,334			120,443			86,183			15,859			6,294
Gain on sale of asset	(183		)	(2,329		)	—			—			—
Acquisition-related expenses (2)	—			—			728			6,051			—
Depreciation and amortization expense	111,479			92,238			53,743			1,402			44
Income (loss) from operations	319,859			920,433			305,690			(41,752		)	(6,110		)
Other (expense) income:
Change in fair value of catalyst lease obligation	—			(2,768		)	(5,215		)	(1,217		)	—
Change in fair value of contingent consideration	4,691			(3,724		)	7,316			—			—
Interest income (expense), net	(93,784		)	(108,629		)	(65,120		)	(1,388		)	10
Income before income taxes	230,766			805,312			242,671			(44,357		)	(6,100		)
Income tax expense	16,681			1,275			—			—			—
Net income (loss)	214,085			804,037			$	242,671		$	(44,357	)	$	(6,100	)
Less: net income attributable to noncontrolling interest	174,545			802,081
Net income attributable to PBF Energy Inc.	$	39,540		$	1,956
Weighted-average shares of Class A common stock outstanding:
Basic	32,488,369			23,570,240
Diluted	33,061,081			97,230,904
Net income available to Class A common stock per share:
Basic	$	1.22		$	0.08
Diluted	$	1.20		$	0.08
Balance sheet data (at end of period) :
Total assets	$	4,413,808		$	4,253,702		$	3,621,109		$	1,274,393		$	19,150
Total long-term debt (4)	747,576			729,980			804,865			325,064			—
Total equity	1,715,256			1,723,545			1,110,918			458,661			18,694
Other financial data :
Capital expenditures (5)	$	415,702		$	222,688		$	574,883		$	72,118		$	70


(1)	Consulting services income provided to a related party was $10 and $221 for the years ended December 31, 2010 and 2009, respectively. No consulting services income was earned subsequent to 2010.


(2)	Acquisition related expenses consist of consulting and legal expenses related to the Paulsboro and Toledo acquisition as well as non-consummated acquisitions.


(3)	December 31, 2009 financial statement data is that of PBF Investments LLC, which was converted to a limited liability company and renamed PBF Energy Company LLC in 2010.


(4)	Total long-term debt includes current maturities and our Delaware Economic Development Authority Loan.


(5)	Includes expenditures for construction in progress, property, plant and equipment, deferred turnaround costs and other assets.

Selected Historical Financial Data of Paulsboro, PBF LLC’s Predecessor

The following table presents Paulsboro’s selected historical financial data. We refer to Paulsboro as PBF LLC’s “Predecessor” or “Predecessor Paulsboro,” as prior to its acquisition PBF LLC generated substantially no revenues and prior to the acquisition of Paulsboro and the Delaware City assets, was a new company formed to pursue acquisitions of crude oil refineries and downstream assets in North America. At the time of its acquisition, Paulsboro represented the major portion of PBF LLC’s business and assets.

The financial information of Predecessor Paulsboro, are presented as of, and for the years ended, December 31, 2009 and for the period from January 1, 2010 through December 16, 2010 and as of December 16, 2010, periods prior to PBF LLC’s acquisition. These financial statements were prepared by the former management of Predecessor Paulsboro and audited by Predecessor Paulsboro’s independent registered public accounting firm. The financial information of Predecessor Paulsboro presented herein may not be representative of the operations of PBF going forward for the following reasons, among others:


•	Both PBF LLC’s financial statements and Paulsboro’s financial statements contain items which require management to make considerable judgments and estimates. There can be no assurance that the judgments and estimates made by PBF LLC’s management will be identical or even similar to the historical judgments and estimates made by Paulsboro’s former management.


•	The financial statements of Paulsboro contain allocations of certain general and administrative expenses and income taxes specific to Valero.


•	The financial statements of Paulsboro reflect depreciation and amortization expense and asset impairment losses based on Valero’s historical cost basis for the applicable assets. PBF LLC’s cost basis in such assets is different.

The historical financial data and other statistical data presented below should be read in conjunction with the section entitled “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations.” The historical financial data for Paulsboro for the period from January 1, 2010 through December 16, 2010 and as of December 16, 2010 and for the year ended December 31, 2009 has been derived from audited financial statements not included in this Annual Report on Form 10-K.

PAULSBORO REFINING BUSINESS—PBF LLC’S PREDECESSOR



	Period from January 1, 2010 through December 16, 2010			Year Ended December 31,
	Period from January 1, 2010 through December 16, 2010			2009
	(in thousands)
Statement of operations data:
Operating revenues (1)	$	4,708,989		$	3,549,517
Cost and expenses:
Cost of sales (2)	4,487,825			3,419,460
Operating expenses	259,768			266,319
General and administrative expenses (3)	14,606			15,594
Asset impairment loss	895,642			8,478
Depreciation and amortization expense	66,361			65,103
Total costs and expenses	5,724,202			3,774,954
Operating income (loss)	(1,015,213		)	(225,437		)
Interest and other income and expense, net	500			1,249
Income (loss) before income tax expense (benefit)	(1,014,713		)	(224,188		)
Income tax expense (benefit) (4)	(322,962		)	(86,586		)
Net income (loss)	$	(691,751	)	$	(137,602	)
Balance sheet data (at end of period):
Total assets	$	510,205		$	1,440,557
Total liabilities	42,582			357,289
Net parent investment	467,623			1,083,268
Selected financial data:
Capital expenditures	$	20,122		$	96,754


(1)	Operating revenues consist of refined products sold from Paulsboro to Valero that were recorded at intercompany transfer prices, which were market prices adjusted by quality, location, and other differentials on the date of the sale.


(2)	Cost of sales consist of the cost of feedstock acquired for processing, including transportation costs to deliver the feedstock to Paulsboro. Purchases of feedstock by Paulsboro from Valero were recorded at the cost paid to independent third parties by Valero.


(3)	General and administrative expenses include allocations and estimates of general and administrative costs of Valero that were attributable to the operations of Paulsboro.

(4)

The income tax provision represented the current and deferred income taxes that would have resulted if Paulsboro were a stand-alone taxable entity filing its own income tax returns. Accordingly, the calculations of current and deferred income tax provision require certain assumptions, allocations, and estimates that Paulsboro management believed were reasonable to reflect the tax reporting for Paulsboro as a stand-alone taxpayer.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following review of our results of operations and financial condition should be read in conjunction with Items 1, 1A, and 2, “Business, Risk Factors, and Properties,” Item 6, “Selected Financial Data,” and Item 8, “Financial Statements and Supplementary Data,” respectively, included in this Annual Report on Form 10-K.

CAUTIONARY STATEMENT FOR THE PURPOSE OF SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This Annual Report on Form 10-K contains certain “forward-looking statements”, as defined in the Private Securities Litigation Reform Act of 1995, 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;

• 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 Inventory Intermediation Agreements with J. Aron could have a material adverse effect on our liquidity, as we would be required to finance our refined products inventory covered by the agreements. Additionally, we are obligated to repurchase from J. Aron all volumes of products located at the Paulsboro and Delaware City refineries’ storage tanks upon termination of these agreements;

•restrictive covenants in our indebtedness that may adversely affect our operational flexibility;

•payments to the holders of PBF LLC Series A Units and PBF LLC Series B Units under our tax receivable agreement for certain tax benefits we may claim;

•our assumptions regarding payments arising under the tax receivable agreement and other arrangements relating to our organizational structure are subject to change due to various factors, including, among other factors, the timing of exchanges of PBF LLC Series A Units for shares of our Class A common stock as contemplated by the tax receivable agreement, the price of our Class A common stock at the time of such exchanges, the extent to which such exchanges are taxable, and the amount and timing of our income;

•our expectations and timing with respect to our acquisition activity and whether any acquisitions are accretive or dilutive to shareholders;

•our expectations with respect to our capital improvement projects including the development and expansion of our Delaware City crude unloading facilities and status of an air permit to transfer crude to Paulsboro;

•the impact of disruptions to crude or feedstock supply to any of our refineries, including disruptions due

to problems with third party logistics infrastructure or operations, including pipeline and rail transportation;

•the possibility that we might reduce or not make further dividend payments;

•the impact of current and future laws, rulings and governmental regulations, including any change by the federal government in the restrictions on exporting U.S. crude oil;

•adverse impacts from changes in our regulatory environment or actions taken by environmental interest groups;

•the costs of being a public company, including Sarbanes-Oxley Act compliance;

•any decisions we make with respect to our energy-related logistical assets that could qualify for an MLP structure, including future opportunities that we may determine present greater potential value to stockholders than the planned MLP initial public offering;

•the timing and structure of the planned MLP initial public offering may change;

•unanticipated developments may delay or negatively impact the planned MLP initial public offering;

•receipt of regulatory approvals and compliance with contractual obligations required in connection with the planned MLP initial public offering;

•the impact of the planned MLP initial public offering on our relationships with our employees, customers and vendors and our credit rating and cost of funds; and

•although we are no longer a “controlled company” following our January 2014 Secondary Offering, Blackstone and First Reserve continue to be able to significantly influence our decisions, and it is possible that their interests will conflict with ours.

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 or as of the date which they are made. 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 consolidated Form 10-K is filed by PBF Energy Inc., PBF Holding Company LLC and PBF Finance Corporation. Each Registrant hereto is filing on its own behalf all of the information contained in this report that relates to such Registrant. Each Registrant hereto is not filing any information that does not relate to such Registrant, and therefore makes no representation as to any such information as of December 31, 2013. PBF Energy is the sole managing member of, and owner, as of December 31, 2013, of an equity interest representing approximately 40.9% of the outstanding economic interests in, PBF LLC. PBF Holding is a wholly-owned subsidiary of PBF LLC and PBF Finance is a wholly-owned subsidiary of PBF Holding. PBF Holding is the parent company for PBF LLC's operating subsidiaries.

Unless the context indicates otherwise, the terms “we,” “us,” and “our” refer to both PBF Energy and PBF Holding and subsidiaries. Discussions or areas of this report that either apply only to PBF Energy or PBF Holding are clearly noted in such sections.

Executive Summary

Our business operations are conducted by PBF LLC and its subsidiaries. We were formed in March 2008 to pursue the acquisitions of crude oil refineries and downstream assets in North America. We currently own and operate three domestic oil refineries and related assets located in Delaware City, Delaware, Paulsboro, New Jersey, and Toledo, Ohio, which we

acquired in 2010 and 2011. Our refineries have a combined processing capacity, known as throughput, of approximately 540,000 bpd, and a weighted average Nelson Complexity Index of 11.3.

The following table summarizes our history and key events:




March 1, 2008		PBF was formed.

June 1, 2010		The idle Delaware City refinery and its related assets were acquired from affiliates of Valero Energy Corporation (“Valero”) for approximately $220.0 million.

December 17, 2010		The Paulsboro refinery and its related assets were acquired from affiliates of Valero for approximately $357.7 million, excluding working capital.

March 1, 2011		The Toledo refinery and its related assets were acquired from Sunoco for approximately $400.0 million, excluding working capital.

October 2011		Delaware City became fully operational.

February 2012		Our subsidiary, PBF Holding, issued $675.5 million aggregate principal amount of 8.25% Senior Secured Notes due 2020.

December 2012		PBF Energy completed the initial public offering of its common equity selling a total of 23,567,686 Class A common shares. In connection with the initial public offering, PBF Energy became the sole managing member of PBF LLC.

June 2013		Blackstone and First Reserve completed a secondary public offering selling a total of 15,950,000 Class A common shares.

January 2014		Blackstone and First Reserve completed a secondary public offering selling a total of 15,000,000 Class A common shares.

Factors Affecting Comparability

Our results over the past three years have been affected by the following events, which must be understood in order to assess the comparability of our period to period financial performance and financial condition.

Acquisition of Toledo Refinery

Through our subsidiary, Toledo Refining, we acquired the Toledo refinery on March 1, 2011, from Sunoco for approximately $400.0 million, excluding working capital. We paid the purchase price with cash funded from equity and a $200.0 million seller note (the “Toledo Promissory Note”), which we repaid in February 2012 with proceeds received through the issuance of the Senior Secured Notes. We also purchased refined and certain intermediate products in inventory for approximately $299.6 million with the proceeds from a note provided by Sunoco that we subsequently repaid on May 31, 2011 with proceeds from our ABL Revolving Credit Facility, and MSCG purchased the refinery’s crude oil inventory on our behalf. Additionally, included in the terms of the sale was a five-year participation payment of up to $125.0 million payable to Sunoco based upon post-acquisition earnings of the refinery, of which the maximum aggregate amount of $125.0 million was paid as of April 2013.

The acquisition was accounted for using the acquisition method of accounting with the preliminary purchase price allocated to the assets acquired and liabilities assumed based on their estimated fair values. The results of operations of the Toledo refinery have been included in our consolidated financial statements as of March 1, 2011.

Toledo has a throughput capacity of 170,000 bpd and a Nelson Complexity Index of 9.2. Toledo processes a slate of light, sweet crudes from Canada, the Midcontinent, 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.

Amended and Restated ABL Revolving Credit Facility

On May 31, 2011, we amended the terms of our ABL Revolving Credit Facility to increase its size to $500.0 million and included certain inventory and accounts receivable of the Toledo refinery in the borrowing base. In addition, the interest rate was changed to the Adjusted LIBOR Rate plus 2.00% to 2.50%, depending on the excess availability, as defined, and

the maturity date was extended to May 31, 2016. On an ongoing basis, the ABL Revolving Credit Facility is available to be used for working capital and other general corporate purposes. In March, August, and September 2012, we amended the ABL Revolving Credit Facility again to increase the aggregate size from $500.0 million to $750.0 million, $950.0 million, and $965.0 million, respectively. In addition, the ABL Revolving Credit Facility was amended and restated on October 26, 2012 to increase the maximum availability to $1.375 billion, extend the maturity date to October 26, 2017 and amend the borrowing base to include non-U.S. inventory, and was further amended on December 28, 2012 to increase the maximum availability to $1.575 billion. The amended and restated ABL Revolving Credit facility includes an accordion feature which allows for commitments of up to $1.8 billion. The agreement was expanded again in November 2013 to increase the maximum availability to $1.610 billion.

Letter of Credit Facility

On January 25, 2011, we entered into a short-term letter of credit facility, which was subsequently amended on April 26, 2011 and April 24, 2012, under which we could obtain letters of credit up to $750.0 million composed of a committed maximum amount of $500.0 million and an uncommitted maximum amount of $250.0 million to support certain of our crude oil purchases. As a result of the increased size of the amended and restated ABL Revolving Credit Facility, we terminated the letter of credit facility in December 2012.

Senior Secured Notes Offering

On February 9, 2012, PBF Holding and PBF Finance Corporation issued $675.5 million aggregate principal amount of 8.25% Senior Secured Notes, due 2020 (which we refer to as the “senior secured notes offering”). The net proceeds from the offering of approximately $665.8 million were used to repay our Paulsboro Promissory Note in the amount of $160.0 million, our Term Loan in the amount of $123.8 million, our Toledo Promissory Note in the amount of $181.7 million, and to reduce indebtedness under the ABL Revolving Credit Facility.

PBF Energy Inc. Public Offerings

On December 12, 2012, PBF Energy completed an initial public offering of 23,567,686 shares of its Class A common stock at a public offering price of $26.00 per share. The initial public offering subsequently closed on December 18, 2012. PBF Energy used the net proceeds of the offering to acquire approximately 24.4% of the membership interests in PBF LLC from certain of its existing members. As a result of the initial public offering and related reorganization transactions, PBF Energy became the sole managing member of PBF LLC with a controlling voting interest in PBF LLC and its subsidiaries. Effective with completion of the initial public offering, PBF Energy consolidates the financial results of PBF LLC and its subsidiaries and records a noncontrolling interest in its consolidated financial statements representing the economic interests of noncontrolling PBF LLC units holders. PBF LLC is PBF Energy’s predecessor for accounting purposes. The financial statements and results of operations for periods prior to the completion of PBF Energy’s initial public offering and the related reorganization transactions are those of PBF LLC.

Additionally, on June 12, 2013, Blackstone and First Reserve completed a public offering of 15,950,000 shares of our Class A common stock at a price of $27.00 per share, less underwriting discounts and commissions, in a secondary public offering, which we refer to as the June 2013 Secondary Offering. All of the shares were sold by funds affiliated with Blackstone and First Reserve and we did not receive any of the proceeds from the sale of these shares. In connection with this offering, Blackstone and First Reserve exchanged 15,950,000 Series A Units of PBF LLC for an equivalent number of shares of our Class A common stock. The holders of PBF LLC Series B Units, which include certain executive officers of PBF Energy, had the right to receive a portion of the proceeds of the sale of the PBF Energy Class A common stock by Blackstone and First Reserve.

Tax Receivable Agreement

In connection with our initial public offering, we entered into a tax receivable agreement pursuant to which we are required to pay the members of PBF LLC, who exchange their units for PBF Energy Class A common stock or whose units we purchase, approximately 85% of the cash savings in income taxes that we realize as a result of the increase in the tax basis of our interest in PBF LLC, including tax benefits attributable to payments made under the tax receivable agreement. We have recognized, as of December 31, 2013, a liability for the tax receivable agreement of $287.3 million reflecting our

estimate of the undiscounted amounts that we expect to pay under the agreement due to exchanges in connection with our public offerings. Our estimate of the tax agreement liability is based on forecasts of future taxable income over the anticipated life of our future business operations, assuming no material changes in the relevant tax law. Periodically, we may adjust the liability based on an updated estimate of the amounts that we expect to pay, using assumptions consistent with those used in our concurrent estimate of the deferred tax asset valuation allowance. For example, we must adjust the estimated tax receivable agreement liability each time we purchase PBF LLC Series A Units or upon an exchange of PBF LLC Series A Units for our Class A common stock. These periodic adjustments to the tax receivable liability, if any, are recorded in general and administrative expense and may result in adjustments to our income tax expense and deferred tax assets and liabilities.

Renewable Fuels Standard

We have seen an escalation in the cost of renewable fuel credits, known as RINs, required for compliance with the Renewable Fuels Standard. We incurred approximately $126.4 million in RINs costs during the year ended December 31, 2013 as compared to $43.7 million and $25.9 million during the years ended December 31, 2012 and 2011, an increase due primarily to higher prices for ethanol-linked RINs and increases in our production of on-road transportation fuels since 2011. Our RINs purchase obligation is dependent on our actual shipment of on-road transportation fuels domestically and the amount of blending achieved.

Factors Affecting Operating Results

Overview

Our earnings and cash flows from operations are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks. The cost to acquire crude oil and other feedstocks and the price of refined petroleum products ultimately sold depends on numerous factors beyond our control, including the supply of, and demand for, crude oil, gasoline, diesel and other refined petroleum products, which, in turn, depend on, among other factors, changes in global and regional economies, weather conditions, global and regional political affairs, production levels, the availability of imports, the marketing of competitive fuels, pipeline capacity, prevailing exchange rates and the extent of government regulation. Our revenue and 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 a crack spread. 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 a throughput number, provides an approximation of the gross margin generated by refining activities.

The performance of our East Coast refineries generally follows the currently published Dated Brent (NYH) 2-1-1 benchmark refining margins. For our Toledo refinery, we utilize a composite benchmark refining margin, the WTI (Chicago) 4-3-1 that is based on publicly available pricing information for products trading in the Chicago and United States Gulf Coast markets.

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 Paulsboro and Delaware City on a global basis through a combination of market purchases and short-term purchase contracts, and through our crude supply agreements with Statoil and Saudi Aramco. Our crude supply agreement with Statoil for Paulsboro was terminated effective March 31, 2013, at which time we began to source Paulsboro’s crude oil and feedstocks internally. Our crude supply agreement with Statoil for Delaware City has been extended by Statoil through December 31, 2015 and we have recently entered into certain amendments to that agreement that are effective through the extended term. In addition, we have a contract with the Saudi Arabian Oil Company (“Saudi Aramco”) to purchase crude oil, and also purchase on the spot market from Saudi Aramco when strategic opportunities arise. We have been purchasing up to approximately 100,000 bpd of crude oil from Saudi Aramco that is processed at Paulsboro. Our Toledo refinery sources domestic and Canadian crude oil through similar market purchases through our crude supply contract with MSCG. 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 Midcontinent and Western Canada, as well as a number of different countries.

During 2012, we expanded and upgraded the existing on-site railroad infrastructure at the Delaware City refinery, including the expansion of the crude rail unloading facilities that was completed in February 2013 and is capable of discharging approximately 110,000 bpd, consisting of 40,000 bpd of heavy crude oil and 70,000 bpd of light crude oil. However, due to greater operating efficiency, discharge capacity for light crude oil at our dual-loop track at the Delaware City refinery has increased from 70,000 bpd to approximately 105,000 bpd. In conjunction with the development of our rail crude unloading facilities at Delaware City, we constructed a railcar storage yard with capacity for 330 railcars that is integral to railcar staging and storage and helps facilitate daily rail traffic at the refinery. Also in 2013 we commenced a third rail crude offloading project to add an additional 40,000 bpd of heavy crude rail unloading capability at the refinery, which is expected to be completed by the second half of 2014. Completion of this third rail project will increase our discharge capacity of heavy crude oil from 40,000 bpd to 80,000 bpd and bring the total rail crude unloading capability up to 185,000 bpd. As a result of our crude rail unloading facility expansion, the delivery of coiled and insulated railcars, the development of crude rail loading infrastructure in Canada and the use of unit trains, we expect to be capable of taking delivery of approximately 80,000 bpd of Canadian heavy crude oil at the Delaware City refinery by the end of 2014. We are also adding additional unloading spots to the dual-loop track to increase unloading capabilities at that facility to approximately 130,000 bpd. Completion of these additional rail projects will increase our discharge capacity of heavy crude oil from 40,000 bpd to 80,000 bpd and bring the total rail crude unloading capability up to 210,000 bpd by the end of 2014, subject to the delivery of coiled and insulated railcars, the development of crude rail loading infrastructure in Canada and the use of unit trains.

During 2012 and January 2013, we have entered into agreements to lease or purchase 5,900 crude railcars which will enable us to transport this crude to each of our refineries. Of the 5,900 crude railcars, we recently purchased 717 railcars, and subsequently sold them to a third party, which has leased the railcars back to us for periods of between four and six years. This transportation flexibility allows our East Coast refineries to process the most cost advantaged crude available.

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 renewable fuel credits, known as RINs, required for compliance with the Renewable Fuels Standard. The predominant variable cost is energy, in particular, the price of utilities, natural gas 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 feedstock logistics, whereas unplanned downtime does not afford us this opportunity.

Refinery-Specific Information

The following section includes refinery-specific information related to crude 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 the benchmark Dated Brent crude oil are converted into one barrel of gasoline and one barrel of heating oil. We calculate this refining margin using the New York Harbor market value of gasoline and heating oil against the market value of Dated Brent crude oil 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 53.5% gasoline, 32.5% distillate (consisting of ULSD, marketed as ULSD or low sulfur heating oil, and conventional heating oil), 1% high-value petrochemicals, with the remaining portion of the product slate comprised of lower-value products (5% petroleum coke, 5% 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, and sour crude oil, 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 are currently processing a significant volume of price-advantaged crude. 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 low value products including sulfur and petroleum coke. These products are priced at a significant discount to gasoline, ULSD and heating oil and represent approximately 5.5% of our total production volume.

Paulsboro Refinery. The benchmark refining margin for the Paulsboro refinery is calculated by assuming that two barrels of the benchmark Dated Brent crude oil are converted into one barrel of gasoline and one barrel of heating oil. We calculate this refining margin using the New York Harbor market value of gasoline and heating oil against the market value of Dated Brent crude oil 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 37% gasoline, 41% distillate (comprised of jet fuel, ULSD and heating oil), 5.5% high-value Group I lubricants, with the remaining portion of the product slate comprised of lower-value products (3% petroleum coke, 4% LPGs, 3% fuel oil, 6% asphalt and 0.5% 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, and sour crude oil, which has historically constituted approximately 65% to 70% of total throughput. The remaining throughput consists of sweet crude oil and other feedstocks and blendstocks. We are now also running a significant volume of price advantaged domestic crudes. These feedstocks historically have priced at a discount to Dated Brent;


•	as a result of the heavy, sour crude slate processed at Paulsboro, we produce low value products including sulfur, petroleum coke and fuel oil. These products are priced at a significant discount to gasoline and heating oil and represent approximately 6% to 7.5% of our total production volume; and


•	the Paulsboro refinery produces Group I lubricants which, through an extensive production process, have a low volume yield which limits the volume expansion on crude inputs.

Toledo Refinery. The benchmark refining margin for the Toledo refinery is calculated by assuming that four barrels of benchmark 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 gasoline 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 50% gasoline, 36.5% distillate (comprised of approximately 49.5% jet fuel and 50.5% 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 (6% LPGs, 2% fuel oil and 0.5% 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 is connected to its distribution network through a variety of third party product pipelines. While lower in cost when compared to barge or rail transportation, the inclusion of transportation costs increases our overall cost relative to the 4-3-1 benchmark refining margin; and


•	the Toledo refinery generates a pricing benefit on some of its products, primarily its petrochemicals.

Results of Operations

The following tables reflect our financial and operating highlights for the years ended December 31, 2013, 2012 and 2011 (amounts in thousands, except per share data) except for income taxes, net income attributable to noncontrolling interest and earnings per share, each of which apply only to the financial results of PBF Energy. In addition, general and administrative expenses for PBF Energy for the year ended December 31, 2013 include a charge of $8.5 million associated with a change in the tax receivable agreement liability. PBF Holding's interest expense also includes interest related to an intercompany note with PBF Energy, which is eliminated in consolidation.



	Year Ended December 31,
	2013			2012			2011
Revenue	$	19,151,455		$	20,138,687		$	14,960,338
Cost of sales, excluding depreciation	17,803,314			18,269,078			13,855,163
Gross refining margin (1)	1,348,141			1,869,609			1,105,175
Operating expenses, excluding depreciation	812,652			738,824			658,831
General and administrative expenses	104,334			120,443			86,183
Gain on sale of asset	(183		)	(2,329		)	—
Acquisition-related expenses	—			—			728
Depreciation and amortization expense	111,479			92,238			53,743
Income from operations	319,859			920,433			305,690
Change in fair value of contingent consideration	—			(2,768		)	(5,215		)
Change in fair value of catalyst leases	4,691			(3,724		)	7,316
Interest income (expense), net	(93,784		)	(108,629		)	(65,120		)
Income before income taxes	230,766			805,312			242,671
Income tax expense	16,681			1,275			—
Net income	214,085			804,037			$	242,671
Less: net income attributable to noncontrolling interest	174,545			802,081
Net income attributable to PBF Energy Inc.	$	39,540		$	1,956
Gross margin	$	436,867		$	1,046,598		$	417,962
Net income available to Class A common stock per share:
Basic	$	1.22		$	0.08
Diluted	$	1.20		$	0.08

——————————


(1)	See Gross Refining Margin below.

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



	Year Ended December 31,
	2013		2012		2011
(dollars per barrel, except as noted)
Dated Brent Crude	$	108.66	$	111.67	$	111.26
West Texas Intermediate (WTI) crude oil	$	97.99	$	94.13	$	95.04
Crack Spreads
Dated Brent (NYH) 2-1-1	$	12.34	$	14.29	$	9.93
WTI (Chicago) 4-3-1	$	20.09	$	27.13	$	24.14
Crude Oil Differentials
Dated Brent (foreign) less WTI	$	10.67	$	17.54	$	16.22
Dated Brent less Maya (heavy, sour)	$	11.38	$	12.04	$	12.63
Dated Brent less WTS (sour)	$	13.31	$	22.95	$	18.28
Dated Brent less ASCI (sour)	$	6.67	$	4.97	$	3.82
WTI less WCS (heavy, sour)	$	24.62	$	21.80	$	15.63
WTI less Bakken (light, sweet)	$	5.12	$	5.77	$	(3.31	)
WTI less Syncrude (light, sweet)	$	0.63	$	0.96	$	(9.79	)
Natural gas (dollars per MMBTU)	$	3.73	$	2.83	$	4.00
Key Operating Information
Production (barrels per day in thousands)	451.0		464.4		427.9
Crude oil and feedstocks throughput (barrels per day in thousands)	452.8		463.2		429.4
Total crude oil and feedstocks throughput (millions of barrels)	165.3		169.5		128.7

2013 Compared to 2012

Overview— Net income for PBF Energy was $214.1 million for the year ended December 31, 2013 compared to $804.0 million for the year ended December 31, 2012. Net income attributable to PBF Energy was $39.5 million, or $1.20 per diluted share ($1.48 per share on a fully exchanged, fully diluted basis based on adjusted pro forma net income as described below in Non-GAAP Financial Measures), for the year ended December 31, 2013. The net income attributable to PBF Energy represents PBF Energy’s equity interest in PBF LLC’s pre-tax income, less applicable income taxes, of approximately 24.4% prior to the June 2013 Secondary Offering and approximately 40.9% subsequent to the June 2013 Secondary Offering. Net income for PBF Holding, which does not include income tax benefits or the expense associated with the change in our tax receivable agreement liability, was $238.9 million for the year ended December 31, 2013 compared to $805.3 million for the year ended December 31, 2012.

Our throughput rates during the year ended December 31, 2013 and 2012, were impacted by unplanned downtime at our Toledo refinery and planned downtime at our Delaware City refinery. On January 31, 2013 there was a brief fire within the fluid catalytic cracking complex at the Toledo refinery that resulted in that unit being temporarily shutdown. The refinery resumed running at planned rates on February 18, 2013. During the fourth quarter of 2013, our Delaware City Refinery was impacted by a 40-day planned turnaround of the coker unit. In the first quarter of 2012, the Toledo refinery was impacted by a 30-day turnaround of its hydrocracker, reformer and UDEX units which commenced on March 9, 2012. Our results for the year ended December 31, 2013 were unfavorably impacted by lower crack spreads and the result of unfavorable crude differentials, higher operating expenses due to increased energy costs, repair and restart costs related to the Toledo fire, turnaround at the Delaware City refinery, as well as higher costs of compliance with the Renewable Fuels Standard.

Revenues— Revenues totaled $19.2 billion for the year ended December 31, 2013 compared to $20.1 billion for the year ended December 31, 2012, a decrease of $1.0 billion, or 4.9%. For the year ended December 31, 2013, the total throughput rates in the East Coast and Mid-Continent refineries averaged approximately 310,300 bpd and 142,500 bpd, respectively. For the year ended December 31, 2012, the total throughput rates at our East Coast and Mid-Continent refineries averaged approximately 316,000 bpd, and 147,200 bpd, respectively. The decrease in throughput rates at our East Coast refineries in 2013 compared to 2012 was primarily driven by market factors including narrower crude differentials for rail-delivered crude as well as the Delaware City coker unit turnaround which reduced crude run rates during the period. The

decrease in throughput rates at our Mid-Continent refinery in 2013 compared to 2012 was primarily due to the refinery's 18-day unplanned down time in the first quarter of 2013, attributable to the fire at the Toledo refinery as described above, as well as refinery maintenance. For the year ended December 31, 2013, the total barrels sold at our East Coast and Mid-Continent refineries averaged approximately 307,600 bpd and 153,700 bpd, respectively. For the year ended December 31, 2012, the total barrels sold at our East Coast and Mid-Continent refineries averaged approximately 311,900 bpd and 159,000 bpd, respectively. Total barrels sold at our Mid-Continent refinery are typically higher than throughput rates, reflecting sales and purchases of refined products outside the refinery. Total barrels sold at our East Coast refineries typically reflect inventory movements in addition to throughput rates.

Gross Margin— Gross refining margin (as defined below in Non-GAAP Financial Measures) totaled $1,348.1 million, or $8.16 per barrel of throughput, for the year ended December 31, 2013 compared to $1,869.6 million, or $11.03 per barrel of throughput during the year ended December 31, 2012, a decrease of $521.5 million. Gross margin, including refinery operating expenses and depreciation, totaled $436.9 million, or $2.64 per barrel of throughput, for the year ended December 31, 2013, compared to $1,046.6 million, or $6.17 per barrel of throughput, for the year ended December 31, 2012, a decrease of $609.7 million. The decrease in gross refining margin was primarily due to reduced throughput rates, unfavorable movement in crude differentials, and higher costs of compliance with the Renewable Fuels Standard.

Average industry refining margins in the U.S. Mid-Continent were generally weaker during the year ended December 31, 2013, as compared to the same period in 2012. The WTI (Chicago) 4-3-1 industry crack spread was approximately $20.09 per barrel or 25.9% lower in the year ended December 31, 2013, as compared to the same period in 2012. Additionally, the price of WTI versus Syncrude and Bakken decreased in 2013, which negatively impacted our overall cost of crude.

The Dated Brent (NYH) 2-1-1 industry crack spread was approximately $12.34 per barrel, or 13.6%, lower in the year ended December 31, 2013, as compared to the same period in 2012. Furthermore, the WTI/Dated Brent differential was $6.87 lower in the year ended December 31, 2013, as compared to the same period in 2012 and the Dated Brent/Maya differential was approximately $0.66 per barrel lower in the year ended December 31, 2013 as compared to the same period in 2012. A decrease in the WTI/Dated Brent crude differential unfavorably impacts our East Coast refineries which have increased shipments of WTI based crudes from the Bakken and Western Canada. A reduction in the Dated Brent/Maya crude differential, our proxy for the light/heavy crude differential, has 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.

Operating Expenses— Operating expenses totaled $812.7 million, or $4.92 per barrel of throughput, for the year ended December 31, 2013 compared to $738.8 million, or $4.36 per barrel of throughput, for the year ended December 31, 2012, an increase of $73.9 million, or 10.0%. The increase in operating expenses is mainly attributable to an increase of approximately $41.3 million in energy and utilities costs, primarily driven by higher natural gas prices, $11.0 million in increased personnel cost associated with higher headcount attributable to the Delaware rail facility expansion, $8.0 million in repair and restart costs related to the Toledo fire described above, $14.3 million in increased outside engineering and consulting fees related to refinery capital and maintenance projects, and $2.2 million in higher regulatory costs and taxes. Our operating expenses principally consist of salaries and employee benefits, maintenance, energy and catalyst and chemicals costs at our refineries.

General and Administrative Expenses— General and administrative expenses totaled $104.3 million for the year ended December 31, 2013, compared to $120.4 million for the year ended December 31, 2012, an decrease of $16.1 million or 13.4%. The decrease in general and administrative expenses primarily relates to lower employee compensation expense of $30.1 million, which is partially offset by $8.5 million of expense associated with the change in our tax receivable agreement liability and $7.6 million in costs associated with being a public company. Our general and administrative expenses are comprised of the personnel, facilities and other infrastructure costs necessary to support our refineries.

General and administrative expenses for PBF Holding, which do not include the $8.5 million expense associated with PBF Energy's tax receivable agreement liability, totaled $95.8 million for the year ended December 31, 2013, compared to $120.4 million for the year ended December 31, 2012.

Gain on Sale of Assets— Gain on sale of assets for the year ended December 31, 2013 was $183.0 thousand which related to the sale of railcars which were subsequently leased back, compared to a gain of $2.3 million for the year ended December 31, 2012, for the sale of certain equipment at Paulsboro and Delaware City.

Depreciation and Amortization Expense— Depreciation and amortization expense totaled $111.5 million for the year ended December 31, 2013, compared to $92.2 million for the year ended December 31, 2012, an increase of $19.3 million.

The increase was principally due to capital projects including the expansion of the crude rail unloading facility completed in the first quarter of 2013 as well as new system implementations at the corporate level during 2012.

Change in Fair Value of Catalyst Leases— Change in the fair value of catalyst leases represented a gain of $4.7 million for the year ended December 31, 2013, compared to a loss of $3.7 million for the year ended December 31, 2012. 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.

Change in Fair Value of Contingent Consideration— In 2013, there was no change in the fair value of contingent consideration related to the Toledo refinery acquisition and the liability was paid in full in April 2013.

Interest Expense, net— Interest expense totaled $93.8 million for the year ended December 31, 2013, compared to $108.6 million for the year ended December 31, 2012, a decrease of $14.8 million. Interest expense includes interest on long-term debt, costs related to the sale and leaseback of our precious metals catalyst, interest expense incurred in connection with our crude and feedstock supply agreements with Statoil and MSCG, financing cost associated with the Inventory Intermediation Agreements, letter of credit fees associated with the purchase of certain crude oils, and the amortization of deferred financing fees. The decrease in interest expense primarily relates to lower interest costs associated with our credit facilities reflecting lower average outstanding borrowings, reduced financing costs related to the termination of the Paulsboro Statoil supply agreement, and the $4.4 million write-off of deferred financing costs in the first quarter of 2012 on debt that was repaid from the proceeds of our 2012 senior secured notes offering.

Income Tax Expense— As PBF LLC is a limited liability company treated as a "flow-through" entity for income tax purposes, the members of PBF LLC are required to include their proportionate share of PBF LLC’s taxable income or loss on their respective tax returns. Accordingly, PBF Energy’s consolidated financial statements do not include a benefit or provision for income taxes for periods prior to the closing of our initial public offering on December 18, 2012. However, PBF LLC generally made distributions to its members, per the terms of the PBF LLC limited liability agreement, related to such taxes. Effective with the completion of the initial public offering of PBF Energy, we recognize an income tax expense or benefit in our consolidated financial statements based on PBF Energy's allocable share of PBF LLC’s pre-tax income (loss), which was approximately 24.4% prior to the June 2013 Secondary Offering and 40.9% subsequent to the June 2013 Secondary Offering. We do not recognize any income tax expense or benefit related to the noncontrolling interest of the other members in PBF LLC (although, as described elsewhere, we make tax distributions to all members of PBF LLC under the terms of its amended and restated limited liability company agreement). PBF Energy's effective tax rate for the year ended December 31, 2013 was 29.7% reflecting tax benefit adjustments for discrete items related to changes in income tax provision estimates based on our income tax returns and changes in our effective state tax rates.

PBF Holding, as a limited liability company treated as a "flow-through" entity for income tax purposes, did not recognize a benefit or provision for income tax expense for the years ended December 31, 2013 and 2012.

Noncontrolling Interest— As a result of our initial public offering and the related reorganization transactions, PBF Energy became the sole managing member of, and has a controlling interest in, PBF LLC. As the sole managing member of PBF LLC, PBF Energy operates and controls all of the business and affairs of PBF LLC and its subsidiaries. PBF Energy consolidates the financial results of PBF LLC and its subsidiaries, and records a noncontrolling interest for the economic interest in PBF LLC held by members other than PBF Energy. Noncontrolling interest on the consolidated statement of operations represents the portion of earnings or loss attributable to the economic interest in PBF LLC held by members other than PBF Energy. Noncontrolling interest on the balance sheet represents the portion of net assets of PBF Energy attributable to the members of PBF LLC other than PBF Energy, based on the relative equity interest held by such members. The noncontrolling interest ownership percentage as of December 31, 2013 and December 31, 2012 was approximately 59.1% and 75.6%, respectively. The carrying amount of the noncontrolling interest on our consolidated balance sheet attributable to the noncontrolling interest is not equal to the noncontrolling interest ownership percentage due to the effect of income taxes and related agreements that pertain solely to PBF Energy.

2012 Compared to 2011

Overview—Net income was $804.0 million for the year ended December 31, 2012 compared to $242.7 for the year ended December 31, 2011. Net income attributable to PBF Energy shareholders was $2.0 million, or $0.08 per share, for the year ended December 31, 2012. The net income attributable to PBF Energy shareholders represents PBF Energy’s approximately 24.4% equity interest in PBF LLC’s pre-tax income, less applicable income taxes, for the period from December 18, 2012, the date of the closing of its initial public offering, through December 31, 2012. During the 2011 period, our results reflect twelve months of operations of our Paulsboro refinery, ten months of operations of our Toledo refinery,

which was acquired on March 1, 2011, and three months of operations of our Delaware City refinery as it was fully operational in October 2011. Prior to October 2011, we performed activities to turnaround, reconfigure and re-start our Delaware City Refinery. We began restarting our Delaware City refinery in June 2011 and it was fully operational in October 2011.

During the year ended December 31, 2012, all three of our refineries were operating, although the Toledo refinery was impacted by a thirty day turnaround of its hydrocracker, reformer and UDEX units which commenced on March 9, 2012. Our results for the year ended December 31, 2012 were favorably impacted by improved crack spreads despite the narrowing of the light/heavy crude differential which impacted our Paulsboro and Delaware City refineries.

Revenues—Revenues totaled $20.1 billion for the year ended December 31, 2012 compared to $15.0 billion for the year ended December 31, 2011, an increase of $5.2 billion, or 34.6%. The revenue increase primarily relates to year of operations of the Toledo refinery in 2012 compared to ten months in 2011 as a result of its acquisition on March 1, 2011, and twelve months of operations of our Delaware City refinery in 2012, which was being reconfigured and prepared for restart in 2011. For the year ended December 31, 2012, the total throughput rates at our Paulsboro, Toledo, and Delaware City refineries averaged approximately 152,000 bpd, 147,200 bpd, and 164,000 bpd, respectively. For the year ended December 31, 2011, the total throughput rates at our Paulsboro, Toledo and Delaware City refineries averaged approximately 151,400 bpd, 151,400 bpd, and 126,600 bpd, respectively. For the year ended December 31, 2012, the total barrels sold at our Paulsboro, Toledo, and Delaware City refineries averaged approximately 149,800 bpd, 159,000 bpd, and 162,100 bpd, respectively. For the year ended December 31, 2011, the total barrels sold at our Paulsboro, Toledo, and Delaware City refineries averaged approximately 151,700 bpd, 160,800 bpd, and 116,200 bpd, respectively.

The throughput rate and barrels sold for our Toledo and Delaware City refineries for the year ended December 31, 2011 reflect the period from March 1 to December 31 and June 1 to December 31, respectively. Total barrels sold during the year ended December 31, 2012 were approximately 172.3 million barrels at an average price of $116.83 per barrel, compared to 129.4 million barrels at an average price of $115.83 per barrel during the 2011 period.

Gross Margin—Gross refining margin totaled $1,869.6 million, or $11.03 per barrel of throughput, for the year ended December 31, 2012 compared to $1,105.2 million, or $8.59 per barrel of throughput during the year ended December 31, 2011, an increase of $764.4 million. Gross margin totaled $1,046.6 million, or $6.17 per barrel of throughput, for the year ended December 31, 2012 compared to $418.0 million, or $3.25 per barrel of throughput, for the year ended December 31, 2011, an increase of $628.6 million. The increase in both gross refining margin and gross margin was primarily due to a full twelve months of operations at the Toledo and Delaware City refineries in 2012 and higher crack spreads.

Average industry refining margins in the U.S. Mid-Continent were generally stronger during the year ended December 31, 2012 as compared to the same period in 2011. The WTI (Chicago) 4-3-1 industry crack spread was approximately $2.99 per barrel or 12.0% higher in the year ended December 31, 2012 as compared to the same period in 2011. During the year ended December 31, 2012, we believe the strong industry refining margins and crude oil price differentials reflect limitations on takeaway capacity of WTI crude stored at Cushing, Oklahoma and the increase in domestically available supply which decreased the price of WTI versus Dated Brent and other crudes. The WTI-Syncrude differential improved by $10.75 per barrel during the year ended December 31, 2012 compared to the same period in 2011. As the WTI-Syncrude premium increases, it has a positive impact on our Toledo refinery’s gross margin because Syncrude represents a significant portion of its crude slate.

While the Dated Brent (NYH) 2-1-1 industry crack spread was approximately $4.36 per barrel, or 43.9%, higher in the year ended December 31, 2012 as compared to the same period in 2011, the Dated Brent/Maya differential was approximately $0.59 per barrel, or approximately 4.7%, lower in 2012 than in 2011. A reduction in the Dated Brent/Maya crude differential, our proxy for the light/heavy crude differential, has a negative impact on Paulsboro and Delaware City as both refineries process a large slate of medium and heavy, sour crude oil that is priced at a discount to light, sweet crude oil.

The increase in our gross refining margin per barrel to $11.03 per barrel for the year ended December 31, 2012 from $8.59 per barrel during the same period in 2011 was primarily driven by improved crack spreads and lower cost of crude at our Toledo refinery, partially offset by an unfavorable increase in the landed cost of crude at our East Coast refineries due to the narrowing of the light/heavy crude differential. In addition, the results of our Paulsboro and Delaware City refineries is compounded by their significant production of low value products such as sulfur, petroleum coke and fuel oils as these products price at a substantial discount to light products. As a result, we were not able to fully benefit from the increase in gasoline and distillates prices during the twelve month period.

Operating Expenses—Operating expenses totaled $738.8 million, or $4.36 per barrel of throughput, for the year ended December 31, 2012 compared to $658.8 million, or $5.12 per barrel of throughput, for the year ended December 31, 2011, an increase of $80.0 million, or 12.1%. The increase in operating expenses primarily relates to having Toledo for a full twelve

months in the 2012 period versus ten months in 2011, and the restart of the Delaware City refinery. During the first nine months of the 2011 period, our Delaware City refinery was undergoing a turnaround and reconfiguration. It was fully operational during the full year ended December 31, 2012. The decrease in operating expenses per barrel of throughput is mainly attributable to a reduction in energy and utilities costs, primarily driven by lower natural gas prices, and the increase in throughput barrels. Our operating expenses principally consist of salaries and employee benefits, maintenance, energy and catalyst and chemicals costs.

General and Administrative Expenses—General and administrative expenses totaled $120.4 million for the year ended December 31, 2012 compared to $86.2 million for the year ended December 31, 2011, an increase of $34.3 million or 40.0%. The increase in general and administrative expenses primarily relates to higher information technology expenses for the implementation of accounting and commercial software in 2012 and higher compensation expense related to headcount increases in 2012. Our general and administrative expenses are comprised of the personnel, facilities and other infrastructure costs necessary to support our refineries.

Acquisition-related Expenses—Acquisition-related expenses for the year ended December 31, 2011 were $0.7 million and related to our acquisition of Toledo.

Gain on Sale of Assets—Gain on sale of assets for the year ended December 31, 2012 was $2.3 million and related to sales of certain equipment at Paulsboro and Delaware City.

Depreciation and Amortization Expense—Depreciation and amortization expense totaled $92.2 million for the year ended December 31, 2012 compared to $53.7 million for the year ended December 31, 2011, an increase of $38.5 million. The increase was principally due to the acquisition of Toledo in March 2011, commencement of depreciation in July 2011 related to the restart of Delaware City, and capital expenditure and turnaround activity.

Change in Fair Value of Catalyst Leases—Change in the fair value of catalyst leases represented a loss of $3.7 million for the year ended December 31, 2012 compared to a gain of $7.3 million for the year ended December 31, 2011. This gain or loss 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 repurchase at fair market value lease termination dates.

Change in Fair Value of Contingent Consideration—Change in the fair value of contingent consideration was an expense of $2.8 million for the year ended December 31, 2012, compared to $5.2 million for the 2011 period. This change represents the increase in the estimated fair value of the total contingent consideration we expect to pay in connection with our acquisition of the Toledo refinery.

Interest (Expense) Income—Interest expense totaled $108.6 million for the year ended December 31, 2012 compared to $65.1 million for the year ended December 31, 2011, an increase of $43.5 million. Interest expense includes interest on long-term debt, costs related to the sale and leaseback of our precious metals catalyst, interest expense incurred in connection with our crude and feedstock supply agreements with Statoil and MSCG, letter of credit fees associated with the purchase of certain crude oils, and the amortization of deferred financing fees. The increase in interest expense primarily relates to an increase in letter of credit fees attributable to all refineries operating for the full year in 2012, financing costs associated with the expanded capacity under the ABL Revolver, interest expense associated with the Statoil agreement related to the Delaware City restart and the write off of $4.4 million in deferred financing costs on debt that was repaid from the proceeds of our senior secured notes offering.

Noncontrolling Interest—As a result of our initial public offering and the related reorganization transactions, PBF Energy is the sole managing member of, and has a controlling interest in, PBF LLC. As the sole managing member of PBF LLC, PBF Energy operates and controls all of the business and affairs of PBF LLC and its subsidiaries. PBF Energy consolidates the financial results of PBF LLC and its subsidiaries, and records a noncontrolling interest for the economic interest in PBF Energy held by the noncontrolling PBF LLC Series A Unit holders. Noncontrolling interest on the consolidated statement of operations represents the portion of earnings or loss attributable to the economic interest in PBF LLC held by

the members of PBF LLC other than PBF Energy, which was approximately 75.6% for the period from the completion of our initial public offering, or December 18, 2012, to December 31, 2012 and all earnings prior to the IPO. Noncontrolling interest on the balance sheet represents the portion of net assets of PBF Energy attributable to the the members of PBF LLC other than PBF Energy, based on the number of PBF LLC Series A units held by such holders. The noncontrolling interest ownership percentage as of December 18, 2012 and December 31, 2012 was approximately 75.6%. The carrying amount of the noncontrolling interest on our consolidated balance sheet attributable to the noncontrolling interest is not equal to 75.6% due to the effect of income taxes and related agreements that pertain solely to PBF Energy.

Non-GAAP Financial Measures

Management uses certain financial measures to evaluate our operating performance that are calculated and presented on the basis of methodologies other than in accordance with U.S. GAAP. These measures should not be considered a substitute for, or superior to, measures of financial performance prepared in accordance with U.S. GAAP, and our calculations thereof may not be comparable to similarly entitled measures reported by other companies.

Adjusted Pro forma Net Income (Loss)

We utilize results presented on an Adjusted Pro Forma basis that exclude certain items relating to our initial public offering and also reflects an assumed exchange of all PBF LLC Series A Units for shares of Class A common stock of PBF Energy. We believe that these Adjusted Pro Forma measures, when presented in conjunction with comparable U.S. GAAP measures, are useful to investors to compare our results across different periods and to facilitate an understanding of our operating results. The differences between Adjusted Pro Forma and U.S. GAAP results are as follows:



1	Assumed Exchange of PBF LLC Series A Units for shares of PBF Energy Class A common stock. As a result of the assumed exchange of PBF LLC Series A Units, the noncontrolling interest related to these units is converted to controlling interest. Management believes that it is useful to provide the per-share effect associated with the assumed exchange of all PBF LLC Series A Units.



2	Income Taxes. Prior to the initial public offering, we were organized as a limited liability company treated as a “flow-through” entity for income tax purposes, and even after our IPO, not all of our earnings are subject to corporate-level income taxes. Adjustments have been made to the Adjusted Pro Forma tax provisions and earnings to assume that we had adopted our post-IPO corporate tax structure for all periods presented and are taxed as a C corporation in the U.S. at the prevailing corporate rates. These assumptions are consistent with the assumption in clause 1 above that all PBF LLC Series A Units are exchanged for shares of PBF Energy Class A common stock, as the assumed exchange would change the amount of our earnings that is subject to corporate income tax.



3	Elimination of Certain Initial Public Offering-Related Expenses. Adjusted Pro Forma results for 2012 also exclude one-time charges relating to our initial public offering. Management believes that this adjustment results in a more meaningful comparison with prior and succeeding period results.

The following table reconciles our Adjusted Pro Forma results with our results presented in accordance with U.S. GAAP for the years ended December 31, 2013, 2012 and 2011:



	Year Ended December 31,
	2013			2012			2011
Net income attributable to PBF Energy Inc.	$	39,540		$	1,956		$	—
Add: IPO-related expenses⁽¹⁾	—			8,187			—
Add: Net income attributable to the noncontrolling interest⁽²⁾	174,545			802,081			242,671
Less: Income tax expense⁽³⁾	(70,167		)	(319,732		)	(95,758		)
Adjusted pro forma net income	$	143,918		$	492,492		$	146,913

Diluted weighted-average shares outstanding of PBF Energy Inc. ⁽⁴⁾	33,061,081			97,230,904
Conversion of PBF LLC Series A Units ⁽⁵⁾	64,164,045			—			97,230,904
Pro forma shares outstanding—diluted⁽⁶⁾	97,225,126			97,230,904			97,230,904
Adjusted pro forma net income (loss) per fully exchanged, fully diluted shares outstanding	$	1.48		$	5.07		$	1.51



(1)		Represents the elimination of one-time charges associated with our initial public offering.
(2)		Represents the elimination of the noncontrolling interest associated with the ownership by the members of PBF LLC other than PBF Energy as if such members had fully exchanged their PBF LLC Series A Units for shares of PBF Energy's Class A common stock.
(3)		Represents an adjustment to apply PBF Energy's statutory tax rate of approximately 40.2% for the year ended December 31, 2013 and 39.5% for the years ended December 31, 2012 and 2011 to the noncontrolling interest. The adjustment assumes the full exchange of existing PBF LLC Series A Units as described in (2) above.
(4)		Represents weighted-average diluted shares outstanding assuming the conversion of all common stock equivalents, including options and warrants for units of PBF LLC Series A Units and options for shares of PBF Energy Class A common stock as calculated under the treasury stock method for the year ended December 31, 2013. Common stock equivalents exclude the effects of options to purchase 1,320,000 and 682,500 shares of PBF Energy's Class A common stock because they are anti-dilutive for the years ended December 31, 2013 and 2012, respectively.
(5)		Represents an adjustment to weighted-average diluted shares to assume the full exchange of existing PBF LLC Series A Units as described in (2) above.
(6)		Diluted pro forma shares outstanding for 2011 reflect the same number of diluted shares outstanding for 2012 in order to present such pre-IPO period on a comparable basis.

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 better metric comparison for the industry refining margin benchmarks, as the refining margin benchmarks do not include a charge for 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 margin to the most directly comparable GAAP financial measure, gross margin, on a historical basis, as applicable, for each of the periods indicated:



	Year Ended December 31,
	2013				2012				2011
	$		per barrel of throughput		$		per barrel of throughput		$		per barrel of throughput
Reconciliation of gross margin to gross refining margin:
Gross margin	$	436,867	$	2.64	$	1,046,598	$	6.17	$	417,962	$	3.07
Add:
Refinery operating expense	812,652		4.92		738,824		4.36		635,517		5.12
Refinery depreciation expense	98,622		0.60		84,187		0.50		51,696		0.40
Gross refining margin	$	1,348,141	$	8.16	$	1,869,609	$	11.03	$	1,105,175	$	8.59

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. The Senior Secured Notes, revolving credit facility 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 the ABL Revolving Credit Facility. EBITDA and Adjusted EBITDA should not be considered as alternatives to operating income 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 equity-based compensation expense, gains (losses) from certain derivative activities and contingent consideration and the non-cash change in the deferral of gross profit related to the sale of certain finished products. Other companies, including other companies in our industry, may calculate Adjusted EBITDA differently than we do, limiting its usefulness as a comparative measure. Adjusted EBITDA also has limitations as an analytical tool and should not be considered in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations include that 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 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 (loss) income as reflected in our results of operations to EBITDA and Adjusted EBITDA for the periods presented:



	Year Ended December 31,
	2013			2012		2011

Reconciliation of net (loss) income to EBITDA:
Net income ⁽¹⁾	$	214,085		$	804,037	$	242,671
Add:Depreciation and amortization expense	111,479			92,238		53,743
Add: Interest expense, net	93,784			108,629		65,120
Add: Income tax expense⁽¹⁾	16,681			1,275		—
EBITDA	$	436,029		$	1,006,179	$	361,534

Reconciliation of EBITDA to Adjusted EBITDA:
EBITDA	$	436,029		$	1,006,179	$	361,534
Stock based compensation	3,753			2,954		2,516
Change in tax receivable agreement liability	8,540			—		—
Non-cash change in fair value of catalyst lease obligations	(4,691		)	3,724		(7,316		)
Non-cash change in fair value of contingent consideration	—			2,768		5,215
Non-cash change in fair value of inventory repurchase obligations	(12,985		)	9,271		(1,396		)
Non-cash deferral of gross profit on finished product sales	(31,329		)	19,177		(6,771		)
Adjusted EBITDA	$	399,317		$	1,044,073	$	353,782

——————————

⁽¹⁾ Net income for PBF Holding for the years ended December 31, 2013, 2012 and 2011 was $238,876, $805,312 and $242,671 respectively, which excludes $16,681 and $1,275 and $0 of income tax expense of PBF Energy, respectively, and $8,540 of expense associated with the change in the tax receivable agreement liability for the year ended December 31, 2013 and

includes $423 of interest expense related to the intercompany notes payable between PBF Holding and PBF Energy for the year ended December 31, 2013.

Liquidity and Capital Resources

Overview

Our primary source of liquidity is 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 capital expenditure, working capital, dividend payments and debt service requirements for the next twelve months. However, our ability to generate sufficient cash flow from operations depends, in part, on oil market pricing and general economic, political and other factors beyond our control. We believe we could, during periods of economic downturn, access the capital markets and/or other available financial resources or reduce our capital and discretionary expenditure plans to strengthen our financial position.

Cash Flow Analysis

Cash Flows from Operating Activities

Net cash provided by operating activities was $291.3 million for the year ended December 31, 2013 compared to net cash provided by operating activities of $812.4 million for the year ended December 31, 2012. Our operating cash flows for the year ended December 31, 2013 included our net income of $214.1 million, plus net non-cash charges relating to depreciation and amortization of $118.0 million, change in deferred income taxes of $16.7 million, pension and other post retirement benefits costs of $16.7 million, change in the tax receivable agreement liability of $8.5 million and stock-based compensation of $3.8 million, partially offset by the change in the fair value of our inventory repurchase obligations of $20.5 million, changes in the fair value of our catalyst lease of $4.7 million, and gain on sale of assets of $183 thousand. In addition, net changes in working capital reflected uses of cash of $61.1 million driven by the timing of inventory purchases and collections of accounts receivables as well as payments associated with the terminations of the MSCG offtake and Statoil supply agreements. Our operating cash flows for the year ended December 31, 2012 included our net income of $804.0 million, plus net non-cash charges relating to depreciation and amortization of $97.7 million, pension and other post retirement benefits of $12.7 million, changes in the fair value of our catalyst lease and Toledo contingent consideration obligations of $6.4 million, change in the fair value of our inventory repurchase obligations of $4.6 million, the write-off of unamortized deferred financing fees related to retired debt of $4.4 million and stock-based compensation of $2.9 million, partially offset by a gain on sales of assets of $2.3 million. In addition, net changes in working capital used $118.0 million in cash driven by increases in hydrocarbon purchases and sales volumes and their associated impact on inventory, accounts receivable, and hydrocarbon-related liabilities.

Net cash provided by operating activities was $812.4 million for the year ended December 31, 2012 compared to net cash provided by operating activities of $249.3 million for the year ended December 31, 2011. During the 2011 period, our cash flows reflect only ten months of operations of our Toledo refinery, which was acquired on March 1, 2011, and limited operations at our Delaware City refinery, which was not fully operational until October 2011. Our operating cash flows for the year ended December 31, 2011 included our net income of $242.7 million, plus net non-cash charges relating to depreciation and amortization of $56.9 million, pension and other post retirement benefits of $9.8 million, change in the fair value of the Toledo contingent consideration of $5.2 million and stock-based compensation of $2.5 million, change in the fair value of our inventory repurchase obligations of $25.3 million, partially offset by changes in the fair value of our catalyst lease obligations of $7.3 million, and net cash used in working capital of $85.8 million.

Cash Flows from Investing Activities

Net cash used in investing activities was $313.3 million for the year ended December 31, 2013 compared to net cash used in investing activities of $219.3 million for the year ended December 31, 2012. The net cash flows used in investing activities for the year ended December 31, 2013 was comprised of capital expenditures totaling $318.4 million, expenditures for turnarounds of $64.6 million, primarily at our Delaware City refinery, and expenditures for other assets of $32.7 million, partially offset by $102.4 million in proceeds from the sale of railcars. Net cash used in investing activities for the year ended December 31, 2012 consisted primarily of the capital expenditures totaling $175.9 million, expenditures for turnarounds of $38.6 million, primarily at our Toledo refinery and expenditures for other assets of $8.2 million, slightly offset by $3.4 million in proceeds from the sale of assets.

Net cash used in investing activities was $219.3 million for the year ended December 31, 2012 compared to net cash used in investing activities of $739.2 million for the year ended December 31, 2011. Net cash used in investing activities for the year ended December 31, 2011 consisted primarily of the acquisition of the Toledo refinery of $168.2 million, capital expenditures totaling $488.7 million, primarily related to the reconfiguration and re-start of our Delaware City refinery,

expenditures for a turnaround at our Paulsboro refinery of $62.8 million and expenditures for other assets of $23.3 million slightly offset by $4.7 million in proceeds from the sale of assets.

Cash Flows from Financing Activities

Net cash used in financing activities was $187.0 million for the year ended December 31, 2013 compared to $357.4 million for the year ended December 31, 2012. For the year ended December 31, 2013, net cash used in financing activities consisted primarily of distributions and dividends of $195.7 million, payments of contingent consideration related to the Toledo acquisition of $21.4 million and $1.0 million for deferred financing costs offset by $15.0 million of net proceeds from revolver borrowings, $14.3 million in proceeds from sale of catalyst and $1.8 million exercise of Series A options and warrants of PBF Energy Company LLC. For the year ended December 31, 2012, net cash used in financing activities consisted primarily of purchases of PBF LLC Series A units from existing unit holders of $571.2 million, repayments of $484.6 million of long-term debt, net repayments on the ABL credit facility of $270.0 million, a contingent consideration payment related to the Toledo acquisition of $103.6 million, cash distributions to PBF LLC’s members of $161.0 million, $26.1 million for deferred financing costs, and $8.4 million for payments related to initial public offering costs, partially offset by net proceeds from the senior secured notes offering of $665.8 million, net proceeds from the sale of shares of Class A common stock in our initial public offering of $579.1 million, proceeds of $9.5 million from the Paulsboro catalyst lease and proceeds of $13.1 million from the exercise of PBF LLC warrants and options.

Net cash used in financing activities was $357.4 million for the year ended December 31, 2012 compared to net cash provided by financing activities of $384.6 million for the year ended December 31, 2011. For the year ended December 31, 2011, cash provided by financing activities consisted primarily of capital contributions from members of PBF LLC of $408.4 million, proceeds from the issuance of long-term debt of $488.9 million and proceeds from catalyst leases of $18.6 million, partially offset by principal repayments of $299.6 million on a seller note for inventory, repayments of long-term debt of $220.4 million and $11.2 million for deferred financing and other costs.

The cash flow activity of PBF Holding is materially consistent with that discussed above, other than the PBF Holding change in due to/due from related party of $14.7 million included in cash flows from operating activities, as well as proceeds from intercompany notes payable of $31.8 million and distributions of $20.2 million related to tax distributions paid to, or on behalf of, PBF Energy included in cash flows from financing activities.

Senior Secured Notes

On February 9, 2012, PBF Holding and its wholly-owned subsidiary, PBF Finance Corp., issued $675.5 million aggregate principal amount of 8.25% Senior Secured Notes due 2020. The net proceeds from the offering of approximately $665.8 million were used to repay our Paulsboro Promissory Note in the amount of $150.6 million, our Term Loan Facility in the amount of $123.8 million, our Toledo Promissory Note in the amount of $181.7 million, and to reduce indebtedness under the ABL Revolving Credit Facility.

The Senior Secured Notes are secured on a first-priority basis by substantially all of the present and future assets of PBF Holding and its subsidiaries (other than assets securing the ABL Revolving Credit Facility). As of December 31, 2013, payment of the Senior Secured Notes is jointly and severally guaranteed by all of PBF Holding’s subsidiaries. PBF Holding has optional redemption rights to repurchase all, or a portion, of the Senior Secured Notes at varying prices equal to no less than 100% of the principal amounts of the notes plus accrued and unpaid interest. The holders of the Senior Secured Notes have repurchase options exercisable only upon a change in control, certain asset sale transactions, or in event of a default as defined in the indenture agreement. In addition, the Senior Secured Notes contain covenant restrictions limiting certain types of additional debt, equity issuances, and payments. PBF Holding is in compliance with the covenants as of December 31, 2013.

Credit Facilities

ABL Revolving Credit Facility

On May 31, 2011, PBF Holding amended its ABL Revolving Credit Facility with UBS AG, Stamford Branch, as administrative agent and co-collateral agent and certain other lenders to increase its size to $500.0 million by including certain inventory and accounts receivable of the Toledo refinery in the borrowing base. A portion of the proceeds of the ABL Revolving Credit Facility was used on the closing date thereof to repay in full all amounts then outstanding under and to terminate the Products and Intermediates Inventory Promissory Note, dated as of March 1, 2011, in an aggregate principal amount equal to $299.6 million, issued by Toledo Refining in favor of Sunoco. In March, August, and September 2012, we amended the ABL Revolving Credit Facility again to increase the aggregate size to $965.0 million. The ABL Revolving Credit Facility was amended and restated on October 26, 2012 to increase the maximum availability to $1.375 billion, extend the maturity date to October 26, 2017, and amend the borrowing base to include non-U.S. inventory, and was further amended

on December 28, 2012 to increase the maximum availability to $1.575 billion. The amended and restated ABL Revolving Credit facility includes an accordion feature which allows for commitments of up to $1.8 billion. The Revolving Loan was further expanded to a maximum availability of $1.610 billion in November 2013. On an ongoing basis, the ABL Revolving Credit Facility is available to PBF Holding and its subsidiaries for working capital and other general corporate purposes.

The ABL Revolving Credit Facility contains customary covenants and restrictions on the activities of PBF Holding and its subsidiaries, including, but not limited to, limitations on the incurrence of additional indebtedness; liens, negative pledges, guarantees, investments, loans, asset sales, mergers, acquisitions and prepayment of other debt; distributions, dividends and the repurchase of capital stock; transactions with affiliates; the ability to change the nature of our business or our fiscal year; the ability to amend the terms of the Senior Secured Notes facility documents; and sale and leaseback transactions. As of December 31, 2013, we were in compliance with these covenants.

As of December 31, 2013, the ABL Revolving Credit Facility provided for revolving loans of up to an aggregate of $1.610 billion, a portion of which was available in the form of letters of credit. The amount available for borrowings and letters of credit under the ABL Revolving Credit Facility is calculated according to a “borrowing base” formula based on (1) 90% of the book value of eligible accounts receivable with respect to investment grade obligors plus (2) 85% of the book value of eligible accounts receivable with respect to non-investment grade obligors plus (3) 80% of the cost of eligible hydrocarbon inventory plus (4) 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 $1.610 billion. As of December 31, 2013, there were $15.0 million outstanding borrowings under the ABL Revolving Credit Facility. Additionally, we had $441.4 million in standby letters of credit issued and outstanding as of that date.

All obligations under the ABL Revolving Credit Facility are guaranteed (solely on a limited recourse basis) to the extent required to support the lien described in clause (y) below by PBF LLC, PBF Finance, and each of our domestic operating subsidiaries and secured by a lien on (y) PBF LLC’s equity interests in PBF Holding and (z) substantially all of the assets of the borrowers and the subsidiary guarantors (subject to certain exceptions). The lien of the ABL Revolving Credit Facility is secured by: all deposit accounts (other than zero balance accounts, cash collateral accounts, trust accounts and/or payroll accounts, all of which are excluded from the collateral); all accounts receivables; all hydrocarbon inventory (other than the Saudi crude oil pledged under the letter of credit facility); to the extent evidencing, governing, securing or otherwise related to the foregoing, all general intangibles, chattel paper, instruments, documents, letter of credit rights and supporting obligations; and all products and proceeds of the foregoing.

Letter of Credit Facility

PBF Holding, Paulsboro Refining and Delaware City Refining were party to a letter of credit facility with BNP Paribas (Suisse) SA, or BNP. The letter of credit facility was terminated in December 2012.

Cash Balances

As of December 31, 2013, our cash and cash equivalents totaled $77.0 million. We also had $12.1 million in restricted cash, which was included within deferred charges and other assets, net on our balance sheet. The restricted cash represents a trust fund we acquired in connection with the Paulsboro refinery acquisition and represents the estimated cost of environmental remediation obligations assumed.

Liquidity

As of December 31, 2013, our total liquidity was approximately $615.9 million, compared to total liquidity of approximately $599.2 million as of December 31, 2012. Total liquidity is the sum of our cash and cash equivalents plus the amount of availability under the ABL Revolving Credit Facility.

Working Capital

Working capital for PBF Energy at December 31, 2013 was $556.0 million, consisting of $2,200.5 million in total current assets and $1,644.5 million in total current liabilities. Working capital at December 31, 2012 was $704.8 million, consisting of $2,307.9 million in total current assets and $1,603.1 million in total current liabilities.

Working capital for PBF Holding at December 31, 2013 was $541.9 million, consisting of $2,175.0 million in total current assets and $1,633.0 million in total current liabilities. Working capital at December 31, 2012 was $686.8 million, consisting of $2,283.3 million in total current assets and $1,596.5 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 purchases the crude oil requirements for each refinery on our behalf and under our direction. Our agreement with Statoil for Paulsboro was terminated effective March 31, 2013, at which time we began to source Paulsboro’s crude oil and feedstocks internally. We amended our agreement with Statoil for Delaware City in 2012 and the term was extended by Statoil through December 31, 2015. Statoil generally provides transportation and logistics services, risk management services and holds title to the crude oil until we purchase it as it enters the refinery process units. For our purchases of Saudi crude oil, similar to our purchases of other foreign waterborne crudes, we post letters of credit and arrange for shipment. We pay for the crude when we are invoiced and the letter of credit is lifted. Under the Statoil agreements, the amount of crude oil we own and the time we are exposed to market fluctuations is substantially reduced. Under generally accepted accounting principles we record the inventory owned by Statoil on our behalf as inventory with a corresponding accrued liability on our balance sheet because we have risk of loss while the Statoil inventory is in our storage tanks and because we have an obligation to repurchase Statoil’s inventory upon termination of the agreements at the then market value.

We have a similar agreement with MSCG to supply the crude oil requirements for our Toledo refinery, under which we take title to MSCG’s crude oil at certain interstate pipeline delivery locations. Payment for the crude oil under the Toledo agreement is due three days after it is processed by us or sold to third parties. We do not have to post letters of credit for these purchases and the Toledo agreement allows us to price and pay for our crude oil as it is processed, which reduces the time we are exposed to market fluctuations. We record an accrued liability at each period-end for the amount we owe MSCG for the crude oil that we own but have not processed. The accrued liability is based on the period-end market value, as it represents our best estimate of what we will pay for the crude oil.

In connection with the crude and feedstock supply agreements for our Delaware City refinery and formerly for the Paulsboro refinery, Statoil also purchases the refineries production of certain feedstocks or purchases feedstocks from third parties on the refineries' behalf. Legal title to the feedstocks is held by Statoil and stored in the refineries’ storage tanks until they are needed for further use in the refining process. At that time, the feedstocks are drawn out of the storage tanks and purchased by the refineries. These purchases and sales are netted at cost and reported within cost of sales. The feedstock inventory owned by Statoil remains on our balance sheet with a corresponding accrued liability.

At December 31, 2013, the LIFO value of crude oil and feedstocks owned by Statoil included within inventory on our balance sheet was $89.8 million. The corresponding accrued liability for such crude oil and feedstocks was $89.8 million at that date.

Product Offtake Agreements

Prior to the termination of our product offtake agreements on July 1, 2013, our Paulsboro and Delaware City refineries sold their light finished products, certain intermediates and lube base oils to MSCG. Legal title transferred to MSCG as the products left the process units and entered the refinery storage facilities. On a daily basis MSCG, under a payment direction agreement, paid the purchase price of certain finished products directly to Statoil, the counterparty to our crude oil and feedstocks supply agreements, effectively netting our liability for crude and feedstock purchases. The payment direction agreement for Paulsboro was terminated effective March 31, 2013. Any shortfall or overage in the netting process was trued up between us and Statoil. Under generally accepted accounting principles, we deferred the revenue on finished product sales and retain the inventory owned by MSCG on our balance sheet until MSCG shipped the products out of our refinery storage facilities, which typically occurred within an average of six days.

In addition, MSCG purchased the daily production of certain intermediates and lube products. When needed for additional blending or sales to third parties, the Paulsboro and Delaware City refineries repurchased the intermediates or lubes from MSCG. These purchases and sales occurred at the daily market price for the related products and were netted in cost of sales at cost. The inventory of intermediates and lubes owned by MSCG remained in inventory on our balance sheet and the net cash receipts result in a liability that was recorded at market price for the volumes held in storage with any change in the market price being recorded in cost of sales.

At December 31, 2012, the LIFO value of light finished products, intermediates and lubes owned by MSCG included within inventory on our balance sheet was $417.9 million. The corresponding deferred revenue for light finished products and accrued liability for intermediates and lubes was $210.5 million and $270.4 million, respectively.

Inventory Intermediation Agreements

We entered into two separate Inventory Intermediation Agreements with J. Aron on June 26, 2013 which commenced upon the termination of the product offtake agreements with MSCG. Pursuant to the Inventory Intermediation Agreements,

J. Aron purchases and holds title to all of the intermediate and finished products produced by the Delaware City and Paulsboro refineries and delivered into our tanks at the refineries. Inventory held outside the refineries may be purchased and owned by J. Aron under the Inventory Intermediation Agreements upon the agreement of 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 the refineries as agreed upon by both parties). We currently market and sell the finished products independently to third parties. We entered into the Inventory Intermediation Agreements for the purpose of managing the Products inventory at the Delaware City and Paulsboro refineries. They provide us with financial flexibility and improve our liquidity by allowing us to monetize Products inventory in our tanks as they are produced prior to being sold to third parties.

Our accounts receivable increased from $503.8 million at December 31, 2012 to $596.6 million at December 31, 2013 and our deferred revenue decreased from $210.5 million at December 31, 2012 to $7.8 million at December 31, 2013 as a result of the termination of the MSCG offtake agreements and commencement of the J. Aron Inventory Intermediation Agreements. Previously, under the MSCG offtake agreements, we sold substantially all of our East Coast finished products to MSCG and received payment on the day of sale. We deferred the revenue on these finished product sales until MSCG shipped the products out of our refinery storage facilities. Under the J. Aron agreements no revenue is deferred as we sell finished products directly to third parties with varying payment terms and recognize revenue as the products are shipped and title transfers to the customer. Similarly, accounts payable increased from $360.1 million at December 31, 2012 to $402.3 million at December 31, 2013, primarily as a result of the termination of the Statoil supply agreement at Paulsboro and our increased purchases of crude by rail delivered to the East Coast.

At December 31, 2013, the LIFO value of intermediates and finished products owned by J. Aron included within inventory on our balance sheet was $378.3 million. The corresponding accrued liability for such intermediates and finished products was $378.3 million at that date.

Capital Spending

Capital spending was $415.7 million for the year ended December 31, 2013, which primarily included safety related enhancements and facility improvements at the refinery and the continued expansion of the rail unloading facilities at our Delaware City refinery.

We are pursuing capital project opportunities designed to increase the profitability of our Toledo refinery. These projects are expected to improve crude sourcing and flexibility, further diversify our product sales into higher margin chemicals and improve the ULSD and total liquid yield from the Toledo refinery. We spent approximately $30.7 million through December 31, 2013 related to these capital projects and estimate aggregate total capital expenditures of approximately $85.0 million through the end of 2015.

Contractual Obligations and Commitments

The following table summarizes our material contractual payment obligations as of December 31, 2013:



	Payments due by period
	Total		Less than 1 year		1-3 Years		3-5 Years		More than 5 years
Long-term debt (a)	$	743,589	$	26,887	$	41,202	$	—	$	675,500
Interest payments on debt facilities (a)	423,417		72,466		143,312		124,046		83,593
Delaware Economic Development Authority Loan (b)	—		—		—		—		—
Operating Leases (c)	311,323		59,410		101,721		81,877		68,315
Purchase obligations (d):
Crude Supply and Offtake Agreements	454,893		454,893		—		—		—
Other Supply and Capacity Agreements	483,351		60,023		98,207		91,544		233,577
Construction obligations	13,088		13,088		—		—		—
Environmental obligations (e)	14,874		2,907		1,492		1,439		9,036
Pension and post-retirement obligations (f)	96,023		6,669		9,287		17,257		62,810
Tax receivable agreement obligations (g)	287,316		12,541		53,604		32,821		188,350
Total contractual cash obligations	$	2,827,874	$	708,884	$	448,825	$	348,984	$	1,321,181


(a)	Long-term Debt and Interest Pay