S-4 1 d428663ds4.htm FORM S-4 Form S-4
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As filed with the Securities and Exchange Commission on September 8, 2017

Registration No. 333-

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM S-4

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

PBF HOLDING COMPANY LLC

PBF FINANCE CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

 

 

 

Delaware   2911   27-2198168
Delaware   2911  

45-2685067

(State or Other Jurisdiction

of Incorporation or Organization)

 

(Primary Standard Industrial

Classification Code Number)

 

(I.R.S. Employer

Identification Number)

One Sylvan Way, Second Floor

Parsippany, New Jersey 07054

Telephone: (973) 455-7500

(Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant’s Principal Executive Offices)

 

 

Trecia M. Canty

Senior Vice President, General Counsel and Secretary

PBF Holding Company LLC

One Sylvan Way, Second Floor

Parsippany, New Jersey 07054

Telephone: (973) 455-7500

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent For Service)

 

 

Copies to:

Todd E. Lenson, Esq.
Jordan M. Rosenbaum, Esq.
Stroock & Stroock & Lavan LLP
180 Maiden Lane
New York, New York 10038
Telephone: (212) 806-5400

 

 

Approximate date of commencement of proposed sale of the securities to the public: As soon as practicable after the effective date of this Registration Statement.

If the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box.  ☐

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer  ☐   Accelerated filer  ☐    Non-accelerated filer  ☑   Smaller reporting company  ☐
       Emerging growth company  ☐
     (Do not check if a smaller reporting company)

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act.  ☐

If applicable, place an X in the box to designate the appropriate rule provision relied upon in conducting this transaction:

Exchange Act Rule 13e-4(i) (Cross-Border Issue Tender Offer)  ☐

Exchange Act Rule 14d-1(d) (Cross-Border Third-Party Tender Offer)  ☐

 

 

CALCULATION OF REGISTRATION FEE

 

 

Title of Each Class
of Securities to be Registered
  Amount to
be Registered
 

Proposed Maximum

Offering Price
per Unit

 

Proposed Maximum

Aggregate Offering

Price

 

Amount of

Registration Fee(1)

7.25% Senior Notes due 2025

  $725,000,000   100%   $725,000,000   $84,028

Guarantees of the 7.25% Senior Notes due 2025(2)

  $725,000,000   N/A   N/A   (3)

 

 

(1)   Estimated solely for the purpose of calculating the registration fee under Rule 457(f) of the Securities Act of 1933, as amended (the “Securities Act”).
(2)   The entities listed on the Table of Additional Registrant Subsidiary Guarantors on the following page have guaranteed the notes being registered hereby.
(3)   Pursuant to Rule 457(n) under the Securities Act, no additional registration fee is due for the guarantees.

 


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The Registrants hereby amend this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrants shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

TABLE OF ADDITIONAL REGISTRANT SUBSIDIARY GUARANTORS

 

Exact Name of Registrant Guarantor(1)

   State or Other Jurisdiction
of Incorporation or
Formation
     IRS Employer
Identification Number
 

Chalmette Refining, L.L.C.

     Delaware        75-2717190  

Delaware City Refining Company LLC

     Delaware        27-2198373  

Paulsboro Refining Company LLC

     Delaware        74-2881064  

PBF Energy Western Region LLC

     Delaware        35-2545521  

PBF Investments LLC

     Delaware        26-2050373  

PBF Power Marketing LLC

     Delaware        27-2198489  

PBF Services Company LLC

     Delaware        30-0644379  

Toledo Refining Company LLC

     Delaware        27-4158209  

Torrance Refining Company LLC

     Delaware        37-1795646  

Torrance Logistics Company LLC

     Delaware        38-3983432  

 

(1)   The address for each Registrant Guarantor is One Sylvan Way, Second Floor, Parsippany, New Jersey 07054 and the telephone number for each registrant is (973) 455-7500.

 

 

 


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The information in this prospectus is not complete and may be changed. We may not complete the exchange offer and issue these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offering is not permitted.

 

SUBJECT TO COMPLETION, DATED SEPTEMBER 8, 2017

PROSPECTUS

 

LOGO

PBF HOLDING COMPANY LLC

PBF FINANCE CORPORATION

Offer to Exchange (the “exchange offer”)

Up To $725,000,000 of

7.25% Senior Notes due 2025

That Have Not Been Registered Under

The Securities Act of 1933

For

Up To $725,000,000 of

7.25% Senior Notes due 2025

That Have Been Registered Under

The Securities Act of 1933

 

 

Terms of the New 7.25% Senior Notes due 2025 Offered in the Exchange Offer:

The terms of the new notes are substantially identical to the terms of the old notes that were issued on May 30, 2017, except that the new notes will be registered under the Securities Act of 1933, as amended, and will not contain restrictions on transfer, registration rights or provisions for payments of additional interest included in the registration rights agreement relating to the old notes.

Terms of the Exchange Offer:

We are offering to exchange up to $725,000,000 of our old notes for new notes with substantially identical terms that have been registered under the Securities Act and are freely tradable.

We will exchange all old notes that you validly tender and do not validly withdraw before the exchange offer expires for an equal principal amount of new notes.

The exchange offer expires at 12:00 a.m. midnight, New York City time, on                  , 2017, unless extended. We do not currently intend to extend the expiration date.

Tenders of old notes may be withdrawn at any time prior to the expiration of the exchange offer.

The exchange of new notes for old notes will not be a taxable event for U.S. federal income tax purposes.

Each broker-dealer that receives new notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the expiration date, we will make this prospectus available to any broker-dealer for use in connection with any such resale. See “Plan of Distribution.”

 

 

You should carefully consider the Risk Factors beginning on page 14 of this prospectus before participating in the exchange offer.

 

 

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus is                  , 2017


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This prospectus is part of a registration statement we filed with the SEC. You should rely only on the information contained in this prospectus and in the accompanying letter of transmittal. We have not authorized anyone to provide you with different information. The prospectus may be used only for the purposes for which it has been published and no person has been authorized to give any information not contained herein. If you receive any other information, you should not rely on it. The information contained in this prospectus is current only as of its date. We are not making an offer to sell these securities or soliciting an offer to buy these securities in any jurisdiction where an offer or solicitation is not authorized or in which the person making that offer or solicitation is not qualified to do so or to anyone whom it is unlawful to make an offer or solicitation.

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In this prospectus we refer to the notes to be issued in the exchange offer as the “new notes,” and we refer to the $725.0 million aggregate principal amount of our 7.25% senior notes due 2025 issued on May 30, 2017, as the “old notes” or the “2025 Senior Notes.” We refer to the new notes and the old notes collectively as the “notes.” In this prospectus, references to “PBF Holding” or the “issuer” refer to PBF Holding Company LLC, a Delaware limited liability company, formed on March 24, 2010. In this prospectus, references to “PBF Finance” or the “co-issuer” refer to PBF Finance Corporation, a Delaware corporation, incorporated on June 14, 2011, and a wholly owned subsidiary of PBF Holding. PBF Finance Corporation was originally formed to be a co-issuer of or guarantor of certain of our indebtedness and does not have any operations. References to the “issuers” refer to the issuer and the co-issuer together.

This prospectus incorporates important business and financial information about us that is not included or delivered with this prospectus. Such information is available without charge to holders of old notes upon written or oral request made to PBF Holding Company LLC, One Sylvan Way, Second Floor, Parsippany, New Jersey 07054, Attention: General Counsel (Telephone (973) 455-7500). To obtain timely delivery of any requested information, holders of old notes must make any request no later than five business days prior to the expiration of the exchange offer.

 

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INDUSTRY AND MARKET DATA

In this prospectus, we refer to information regarding market data and other statistical information obtained from independent industry publications, government publications or other published independent sources. Some data is also based on our good faith estimates. Although we believe these third-party sources are reliable, we have not independently verified the information and cannot guarantee its accuracy and completeness. Estimates are inherently uncertain, involve risks and uncertainties and are subject to change based on various factors, including those described elsewhere in this prospectus under the headings “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.” Moreover, forecasted information is inherently uncertain and we can provide no assurance that forecasted information will materialize.

BASIS OF PRESENTATION

Unless otherwise indicated or the context otherwise requires, all financial data in this prospectus reflects the consolidated business and operations of PBF Holding Company LLC and its consolidated subsidiaries, and has been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Our indirect parent company, PBF Energy Inc. (NYSE: PBF) (“PBF Energy”), does not guarantee the notes and its financial statements and results are not included herein. PBF Energy’s financial statements and results differ from ours because PBF Energy, among other things, has ownership interest in PBF Logistics LP (NYSE: PBFX) (“PBF Logistics” or “PBFX”). We do not own any interest in PBF Logistics.

 

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains certain “forward-looking statements” of expected future developments that involve risks and uncertainties. You can identify forward-looking statements because they contain words such as “believes,” “expects,” “may,” “should,” “seeks,” “approximately,” “intends,” “plans,” “estimates,” “anticipates” or similar expressions that relate to our strategy, plans or intentions. All statements we make relating to our estimated and projected earnings, margins, costs, expenditures, cash flows, growth rates and financial results or to our 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 “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations of PBF Holding” and elsewhere in this prospectus. All forward-looking information in this prospectus and subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements. Some of the factors that we believe could affect our results include:

 

    supply, demand, prices and other market conditions for our products, including volatility in commodity prices;

 

    the effects of competition in our markets;

 

    changes in currency exchange rates, interest rates and capital costs;

 

    adverse developments in our relationship with both our key employees and unionized employees;

 

    our ability to operate our businesses efficiently, manage capital expenditures and costs (including general and administrative expenses) and generate earnings and cash flow;

 

    our substantial indebtedness;

 

    our supply and inventory intermediation arrangements expose us to counterparty credit and performance risk;

 

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

 

    restrictive covenants in our indebtedness that may adversely affect our operational flexibility, ability to make distributions, borrow additional funds, dispose of assets and make certain investments;

 

    our assumptions regarding payments arising under PBF Energy’s tax receivable agreement and other arrangements relating to PBF Energy;

 

    our expectations and timing with respect to our acquisition activity;

 

    our expectations with respect to our capital improvement and turnaround projects;

 

    the status of an air permit to transfer crude through the Delaware City refinery’s dock;

 

    the impact of disruptions to crude or feedstock supply to any of our refineries, including disruptions due to problems at PBF Logistics, or with third party logistics infrastructure or operations, including pipeline, marine and rail transportation;

 

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    the impact of current and future laws, rulings and governmental regulations, including the implementation of rules and regulations regarding transportation of crude oil by rail;

 

    the effectiveness of our crude oil sourcing strategies, including our crude by rail strategy and related commitments;

 

    adverse impacts related to legislation by the federal government lifting the restrictions on exporting U.S. crude oil;

 

    adverse impacts from changes in our regulatory environment, such as the effects of compliance with the California Global Warming Solutions Act (also referred to as “AB32”), or from actions taken by environmental interest groups;

 

    market risks related to the volatility in the price of Renewable Identification Numbers (“RINs”) required to comply with the Renewable Fuel Standards and greenhouse gas (“GHG”) emission credits required to comply with various GHG emission programs, such as AB32;

 

    our ability to successfully integrate the completed acquisition of the Torrance refinery and related logistics assets (collectively, the “Torrance Acquisition”) into our business and realize the benefits from such acquisition;

 

    liabilities arising from the Torrance Acquisition that are unforeseen or exceed our expectations; and

 

    any decisions we continue to make with respect to our energy-related logistical assets that may be transferred to PBF Logistics.

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 prospectus 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 prospectus 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.

 

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PROSPECTUS SUMMARY

This summary highlights selected information contained elsewhere in this prospectus and may not contain all of the information that may be important to you. You should read this entire prospectus carefully, including the information set forth in “Risk Factors” and our financial statements and related notes included elsewhere in this prospectus before making an investment decision.

Unless the context otherwise requires, references to the “Company,” “we,” “our,” “us” or “PBF” refer to PBF Holding Company LLC, or PBF Holding, and, in each case, unless the context otherwise requires, its consolidated subsidiaries. See “Basis of Presentation” on page ii.

Our Company

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, the Midwest, the Gulf Coast and the West Coast of the United States, as well as in other regions of the United States and Canada, and are able to ship products to other international destinations. We were formed in 2008 to pursue acquisitions of crude oil refineries and downstream assets in North America. We currently own and operate five domestic oil refineries and related assets, which we acquired in 2010, 2011, 2015 and 2016. Our refineries have a combined processing capacity, known as throughput, of approximately 900,000 barrels per day (“bpd”), and a weighted-average Nelson Complexity Index of 12.2.

Our five refineries are located in Toledo, Ohio, Delaware City, Delaware, Paulsboro, New Jersey, New Orleans, Louisiana and Torrance, California. 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 West Texas Intermediate (“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 the flexibility to receive crude and feedstock via both water and rail. We have 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. The Delaware City rail unloading facility, which was transferred to PBFX in 2014, allows our East Coast refineries the flexibility to source WTI-based crudes from Western Canada and the Mid-Continent, when doing so provides cost advantages versus traditional Brent-based international crudes. We believe this sourcing optionality can be a beneficial component to the profitability of our East Coast refining system in certain crude price environments. The Chalmette refinery, located outside of New Orleans, Louisiana, is a 189,000 bpd, dual-train coking refinery with a Nelson Complexity of 12.7 and is capable of processing both light and heavy crude oil. The facility is strategically positioned on the Gulf Coast with strong logistics connectivity that offers flexible raw material sourcing and product distribution opportunities, including the potential to export products. The Torrance refinery, located on 750 acres in Torrance, California, is a high-conversion 155,000 bpd, delayed-coking refinery with a Nelson Complexity of 14.9. The Torrance refinery provides us with a broader, more diversified asset base and increases our combined crude oil throughput capacity to approximately 900,000 bpd. The Torrance refinery also provides us with a presence in the attractive PADD 5 market.

PBF Energy

We are a wholly-owned subsidiary of PBF Energy Company LLC (“PBF LLC”) and the parent company for PBF LLC’s refinery operating subsidiaries, and are an indirect subsidiary of PBF Energy (NYSE: PBF). PBF Energy is the sole managing member of PBF LLC and operates and controls all of its business and affairs and

 



 

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consolidates the financial results of PBF LLC and its subsidiaries, including PBF Holding. As of the date of this prospectus, PBF Energy’s sole asset is a controlling economic interest of approximately 96.6% in PBF LLC, with the remaining 3.4% of the economic interests in PBF LLC held by certain of PBF Energy’s current and former executive officers and directors and certain employees and others.

PBF Logistics LP

PBF Logistics (NYSE: PBFX) is a fee-based, growth-oriented, publicly traded Delaware master limited partnership formed by PBF Energy to own or lease, operate, develop and acquire crude oil and refined petroleum products terminals, pipelines, storage facilities and similar logistics assets. PBFX engages in the receiving, handling, storage and transferring of crude oil, refined products, natural gas and intermediates from sources located throughout the United States and Canada for PBF Energy in support of certain of our refineries, as well as for third party customers. A substantial majority of PBFX’s revenues are generated from agreements it has with PBF Holding, which include minimum volume commitments, for receiving, handling, storing and transferring crude oil and refined products. PBF Holding also has agreements with PBFX that establish fees for certain general and administrative services and operational and maintenance services provided by PBF Holding to PBFX. Following PBFX’s purchase of four refined products terminals located in the greater Philadelphia region in April 2016, PBFX generates third party revenue as well.

As of the date of this prospectus, PBF LLC holds a 44.1% limited partner interest in PBFX and all of PBFX’s incentive distribution rights, with the remaining limited partner interest held by public common unit holders. PBF LLC also owns indirectly a non-economic general partner interest in PBFX through its wholly-owned subsidiary, PBF Logistics GP LLC, the general partner of PBFX. We do not own any interests in PBFX.

Any information in this prospectus regarding PBF Energy and PBF Logistics is included in this prospectus solely for informational purposes. Nothing in this prospectus should be construed as an offer to sell, or the solicitation of an offer to buy, the Class A common stock of PBF Energy or the common units of PBF Logistics.

* * * * *

We are a Delaware limited liability company. Our principal executive offices are located at One Sylvan Way, Second Floor, Parsippany, New Jersey 07054, and our telephone number is (973) 455-7500. Our website is located at http://www.pbfenergy.com. We make available our periodic reports and other information filed with or furnished to the SEC, free of charge through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on or accessible through our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

 



 

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The Exchange Offer

On May 30, 2017, we completed a private offering of $725,000,000 aggregate principal amount of the old notes. We entered into a registration rights agreement with the initial purchasers in connection with the offering in which we agreed to deliver to you this prospectus and to use commercially reasonable efforts to consummate the exchange offer not later than 365 days after the date of original issuance of the old notes.

 

Exchange Offer

We are offering to exchange new notes for old notes. The terms of the new notes are substantially identical to the terms of the old notes that were issued on May 30, 2017, except that the new notes will be registered under the Securities Act and will not contain restrictions on transfer, registration rights or provisions for payments of additional interest included in the registration rights agreement relating to the old notes.

 

  You may only exchange notes in denominations of $2,000 and integral multiples of $1,000 in excess thereof.

 

Expiration Date

The exchange offer will expire at 12:00 a.m. midnight, New York City time, on                  , 2017, unless we decide to extend it. We do not currently intend to extend the expiration date.

 

Resale

Based on an interpretation by the staff of the SEC set forth in no-action letters issued to third parties, we believe that the new notes issued pursuant to the exchange offer in exchange for old notes may be offered for resale, resold and otherwise transferred by you (unless you are our “affiliate” within the meaning of Rule 405 under the Securities Act) without compliance with the registration and prospectus delivery provisions of the Securities Act; provided that:

 

    you are acquiring the new notes in the ordinary course of your business; and

 

    you have not engaged in, do not intend to engage in, and have no arrangement or understanding with any person to participate in, a distribution of the new notes.

 

  Each broker-dealer that receives new notes for its own account in exchange for old notes, where such old notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. See “Plan of Distribution.”

 

  Any holder of old notes who:

 

    is our affiliate;

 

    does not acquire new notes in the ordinary course of its business; or

 

   

tenders its old notes in the exchange offer with the intention to participate, or for the purpose of participating, in a distribution of new notes, cannot rely on the position of the staff of the SEC enunciated in Morgan Stanley & Co. Incorporated (available

 



 

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June 5, 1991) and Exxon Capital Holdings Corporation (available May 13, 1988), as interpreted in the SEC’s letter to Shearman & Sterling (available July 2, 1993), or similar no-action letters and, in the absence of an exemption therefrom, must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale of the new notes.

 

Procedures for Tendering Old Notes

If you hold old notes that were issued in book-entry form and are represented by global certificates held for the account of The Depository Trust Company (“DTC”), in order to participate in the exchange offer, you must follow the procedures established by DTC for tendering notes held in book-entry form. These procedures, which we call “ATOP,” require that (i) the exchange agent receive, prior to the expiration date of the exchange offer, a computer generated message known as an “agent’s message” that is transmitted through DTC’s automated tender offer program, and (ii) DTC confirms that:

 

    DTC has received your instructions to exchange your old notes, and

 

    you agree to be bound by the terms of the letter of transmittal for holders of global notes.

 

  If you hold old notes that were issued in definitive, certificated form, in order to participate in the exchange offer, you must deliver the certificates representing your notes, together with a properly completed and duly executed letter of transmittal for holders of definitive notes to the exchange agent.

 

  For more information on tendering your old notes, please refer to the section in this prospectus entitled “Exchange Offer—Terms of the Exchange Offer,” “—Procedures for Tendering,” and “Description of Notes—Book Entry; Delivery and Form.”

 

Guaranteed Delivery Procedures

If you wish to tender your old notes and your old notes are not immediately available or you cannot deliver your old notes, the letter of transmittal or any other required documents, or you cannot comply with the procedures under ATOP for transfer of book-entry interests, prior to the expiration date, you must tender your old notes according to the guaranteed delivery procedures set forth in this prospectus under “Exchange Offer—Guaranteed Delivery Procedures.”

 

Withdrawal of Tenders

You may withdraw your tender of old notes at any time prior to the expiration date. To withdraw tenders of notes held in global form, you must submit a notice of withdrawal to the exchange agent using ATOP procedures before 12:00 a.m. midnight, New York City time, on the expiration date of the exchange offer. To withdraw tenders of notes held in definitive form, you must submit a written or facsimile notice of withdrawal to the exchange agent before 12:00 a.m. midnight, New York City time, on the expiration date of the exchange offer. Please refer to the section in this prospectus entitled “Exchange Offer—Withdrawal of Tenders.”

 



 

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Acceptance of Old Notes and Delivery of New Notes

If you fulfill all conditions required for proper acceptance of old notes, we will accept any and all old notes that you properly tender in the exchange offer before 12:00 a.m. midnight New York City time on the expiration date. We will return any old note that we do not accept for exchange to you without expense promptly after the expiration or termination of the exchange offer. Please refer to the section in this prospectus entitled “Exchange Offer—Terms of the Exchange Offer.”

 

Fees and Expenses

We will bear expenses related to the exchange offer. Please refer to the section in this prospectus entitled “Exchange Offer—Fees and Expenses.”

 

Use of Proceeds

The issuance of the new notes will not provide us with any new proceeds. We are making this exchange offer solely to satisfy our obligations under the registration rights agreement.

 

Consequences of Failure to Exchange Old Notes

If you do not exchange your old notes in this exchange offer, you will no longer be able to require us to register the old notes under the Securities Act except in limited circumstances provided under the registration rights agreement. In addition, you will not be able to resell, offer to resell or otherwise transfer the old notes unless we have registered the old notes under the Securities Act, or unless you resell, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act.

 

U.S. Federal Income Tax Consequences

The exchange of new notes for old notes pursuant to the exchange offer will not be a taxable event for U.S. federal income tax purposes. Please read “Material United States Federal Income Tax Consequences.”

 

Exchange Agent

We have appointed Deutsche Bank Trust Company Americas as the exchange agent for the exchange offer. You should direct questions and requests for assistance, requests for additional copies of this prospectus, the letter of transmittal or the notice of guaranteed delivery to the exchange agent as follows:

 

  Deutsche Bank Trust Company Americas

c/o DB Services Americas, Inc.

Attn: Reorg Dept

5022 Gate Parkway, Suite 200

Jacksonville, FL 32256

 

  For telephone assistance, please call (877) 843-9767.

 



 

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Terms of the New Notes

The new notes will be substantially identical to the old notes except that the new notes are registered under the Securities Act and will not have restrictions on transfer, registration rights or provisions for additional interest. The new notes will evidence the same debt as the old notes, and the same indenture will govern the new notes and the old notes.

The following summary contains basic information about the notes and is not intended to be complete. It does not contain all the information that is important to you. For a more complete understanding of the notes, please refer to the sections of this prospectus entitled “Description of Notes.”

 

Issuers

PBF Holding Company LLC and PBF Finance Corporation

 

  PBF Finance Corporation is a wholly owned subsidiary of PBF Holding Company LLC that has no material assets and was formed for the sole purpose of being a co-issuer or guarantor of certain of our indebtedness.

 

Securities

$725.0 million aggregate principal amount of 7.25% Senior Notes due 2025 (the “new notes”).

 

Maturity Date

June 15, 2025.

 

Interest Payment Dates

June 15 and December 15 of each year, commencing on December 15, 2017.

 

Guarantees

Each of our current and future domestic restricted subsidiaries will jointly, severally and unconditionally guarantee the notes. The guarantors include all of our subsidiaries that guarantee our asset based revolving credit agreement (the “Revolving Loan”) and our $500.0 million in aggregate principal amount of 7.00% senior notes due 2023 (the “2023 Notes” and, together with the notes, the “Senior Notes”). The guarantees may be released under certain circumstances. Under certain circumstances, we will be able to designate certain additional current or future restricted subsidiaries as unrestricted subsidiaries. As of the date of this prospectus, certain of our subsidiaries are unrestricted subsidiaries. Unrestricted subsidiaries are not subject to any of the restrictive covenants set forth in the indenture governing the notes and will not guarantee the notes.

 

Ranking

The new notes will be our general senior unsecured obligations. The new notes will be:

 

    pari passu in right of payment with all of our existing and future senior indebtedness (including the Revolving Loan and the 2023 Notes);

 

    effectively subordinated to any of our existing or future secured indebtedness (including the Revolving Loan) to the extent of the value of the collateral securing such indebtedness;

 

    senior in right of payment to any of our existing and future subordinated indebtedness; and

 



 

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    structurally subordinated to all existing or future indebtedness and other obligations of our non-guarantor subsidiaries (including the PBF Rail Term Loan (as defined below)).

 

  The guarantees will be general senior unsecured obligations of the guarantors. The guarantees will be:

 

    pari passu in right of payment with all of the guarantors’ existing and future senior indebtedness (including the guarantees of the Revolving Loan and the 2023 Notes);

 

    effectively subordinated to any of the guarantors’ existing or future secured indebtedness (including the guarantees of the Revolving Loan) to the extent of the value of the collateral securing such indebtedness;

 

    senior in right of payment to any of the guarantors’ existing and future subordinated indebtedness; and

 

    structurally subordinated to all existing or future indebtedness and other obligations of any of our guarantor’s non-guarantor subsidiaries.

 

  Since the new notes and guarantees are unsecured, in the event of a bankruptcy or insolvency, our secured creditors will have a prior secured claim to any collateral securing the debt owed to them.

 

  For the six months ended June 30, 2017, our non-guarantor subsidiaries did not account for any of our net revenue, and, at June 30, 2017, represented approximately $693.0 million, or 10.7%, of our total assets and approximately $234.8 million, or 5.9%, of our total liabilities. In the event of a bankruptcy, liquidation or reorganization of any of these subsidiaries, these subsidiaries will pay the holders of their debt and their trade creditors before they will be able to distribute any of their assets to us.

 

Optional Redemption

At any time prior to June 15, 2020, we may on any one or more occasions redeem up to 35% of the aggregate principal amount of the new notes in an amount not greater than the net cash proceeds of certain equity offerings at a redemption price equal to 107.250% of the principal amount of the notes, plus any accrued and unpaid interest to the date of redemption.

 

  On or after June 15, 2020, we may redeem all or part of the new notes, in each case at the redemption prices described under “Description of Notes—Optional Redemption,” together with any accrued and unpaid interest to the date of redemption.

 

  In addition, prior to June 15, 2020, we may redeem all or part of the new notes at a “make-whole” redemption price described under “Description of Notes—Optional Redemption,” together with any accrued and unpaid interest to the date of redemption.

 



 

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Change of Control

Upon a change of control that results in a ratings decline (as defined under “Description of Notes”) with respect to the new notes, we will be required to make an offer to purchase the new notes at a purchase price of 101% of the principal amount of the notes on the date of purchase plus accrued interest. We may not have sufficient funds available at that time to make any required debt repayment (including purchases of the notes), and certain provisions of our other debt agreements (including our Revolving Loan and the 2023 Notes) may further limit our ability to make these purchases. See “Risk Factors—Risks Relating to Our Indebtedness and the Notes—We may not be able to repurchase the notes upon a change of control triggering event, and a change of control triggering event could result in us facing substantial repayment obligations under our Revolving Loan, the 2023 Notes, the notes and other agreements.”

 

Asset Sale Offer

Prior to a covenant suspension event, certain asset dispositions (including as a result of destruction or condemnation) will be triggering events that may require us to use the proceeds therefrom to offer to repurchase notes at a purchase price equal to 100% of the principal amount of the notes repurchased, plus accrued and unpaid interest to the applicable repurchase date. See “Description of Notes—Repurchase at the Option of Holders—Asset Sales.”

 

Certain Covenants before an Investment Grade Rating Event

We will issue the new notes under an indenture with Wilmington Trust, National Association, as trustee. The indenture, among other things, limits our ability and the ability of our restricted subsidiaries to:

 

    incur additional indebtedness or issue certain preferred stock;

 

    make equity distributions, pay dividends on or repurchase capital stock or make other restricted payments;

 

    enter into transactions with affiliates;

 

    create liens;

 

    engage in mergers and consolidations or otherwise sell all or substantially all of our assets;

 

    designate our subsidiaries as unrestricted subsidiaries;

 

    make certain investments; and

 

    limit the ability of restricted subsidiaries to make payments to us.
  These covenants are subject to important exceptions and qualifications. See “Description of Notes—Certain Covenants.”

 



 

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Certain Covenants after an Investment Grade Event

After an investment grade rating event, certain of the covenants described in the preceding paragraph will cease to exist or will be modified. The terms of the new notes will then only restrict our ability and the ability of our restricted subsidiaries to:

 

    create liens to secure indebtedness;

 

    guarantee our 2023 Notes without guaranteeing the notes; and

 

    engage in certain mergers and consolidations.

 

  There can be no assurances that the new notes will ever achieve or maintain investment grade or a covenant termination event will occur. See “Description of Notes—Certain Covenants.”

 

Transfers; Absence of a Public Market for the New Notes

The new notes generally will be freely transferable, but will also be new securities for which there will not initially be a market. There can be no assurance as to the development or liquidity of any market for the new notes. We do not intend to apply for a listing of the new notes on any securities exchange or any automated dealer quotation system. See “Risk Factors—Risks Related to the Exchange Offer—Your ability to transfer the new notes may be limited by the absence of a trading market.”

 

Risk Factors

You should carefully consider all the information in the prospectus prior to exchanging your old notes. See “Risk Factors” for a description of some of the risks you should consider in evaluating whether or not to tender your old notes.

 



 

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Summary Historical and Pro Forma Condensed Consolidated Financial and Other Data

The following table sets forth our summary historical and pro forma consolidated financial data at the dates and for the periods indicated. The summary historical consolidated financial data as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016 have been derived from our audited financial statements, which are included elsewhere in this prospectus. The information as of June 30, 2017 and for the six months ended June 30, 2017 and 2016 was derived from the unaudited condensed consolidated financial statements, which are included elsewhere in this prospectus, and includes all adjustments, consisting of normal recurring adjustments, which management considers necessary for a fair presentation of the financial position and the results of operations for such periods. Results for the interim periods are not necessarily indicative of the results for the full year.

The summary unaudited pro forma condensed consolidated financial data have been derived by the application of pro forma adjustments to our historical consolidated financial statements, which are included elsewhere in this prospectus, that give effect to the Torrance Acquisition, borrowings incurred under our Revolving Loan to fund the Torrance Acquisition and the consummation of the offering of the 2025 Senior Notes and redemption of the 2020 Senior Secured Notes as described in “Unaudited Pro Forma Condensed Consolidated Financial Statements” in this prospectus. The unaudited pro forma condensed consolidated financial information does not purport to represent what our results of operations or financial condition would have been had the transactions to which the pro forma adjustments relate actually occurred on the dates indicated, and they do not purport to project our results of operations or financial condition for any future period or as of any future date. The estimates and assumptions used in preparation of the pro forma financial information may be materially different from our actual experience.

You should read this information in conjunction with the sections entitled “Selected Historical Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations of PBF Holding,” our consolidated financial statements and the related notes thereto, our unaudited condensed consolidated financial statements and the related notes thereto, the 2015 audited financial statements and the June 30, 2016 unaudited financial statements of Torrance Refinery & Associated Logistics Business, each included elsewhere in this prospectus, and the sections entitled “Basis of Presentation,” “Prospectus Summary” and “Unaudited Pro Forma Condensed Consolidated Financial Statements” in this prospectus. Our summary unaudited pro forma condensed consolidated financial information is presented for informational purposes only.

 



 

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    Year Ended December 31,     Six Months Ended June 30,  
    2016     2015     2014     Pro Forma
Consolidated
2016
    2017     2016     Pro Forma
Condensed
Consolidated
2017
 

Revenue

  $ 15,908,537     $ 13,123,929     $ 19,828,155     $ 16,987,548     $ 9,763,449     $ 6,655,958     $ 9,763,449  

Cost and expenses:

             

Cost of sales, excluding depreciation

    13,765,088       11,611,599       18,514,054       14,765,933       8,914,587       5,730,731       8,914,587  

Operating expense, excluding depreciation

    1,390,582       889,368       880,701       1,721,151       835,423       568,178       835,423  

General and administrative expenses (1)

    149,643       166,904       140,150       202,421       75,399       71,360       75,399  

Equity income in investee (2)

    (5,679     —         —         (5,679     (7,419     —         (7,419

Loss (gain) on sale of assets

    11,374       (1,004     (895     11,374       912       3,222       912  

Depreciation and amortization expense

    209,840       191,110       178,996       247,015       118,683       103,212       118,683  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    15,520,848       12,857,977       19,713,006       16,942,215       9,937,585       6,476,703       9,937,585  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from operations

    387,689       265,952       115,149       45,333       (174,136     179,255       (174,136

Other income (expense)

             

Change in fair value of catalyst lease

    1,422       10,184       3,969       1,422       (1,484     (4,633     (1,484

Debt extinguishment costs

    —         —         —         —         (25,451     —         (25,451

Interest expense, net

    (129,536     (88,194     (98,001     (129,656     (63,513     (64,550     (61,216
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before income taxes

    259,575       187,942       21,117       (82,901     (264,584     110,072       (262,287

Income tax expense (benefit)

    23,689       648       —         (120,247     6,332       26,996       6,332  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

    235,886       187,294       21,117       37,346       (270,916     83,076       (268,619

Less: net income attributable to noncontrolling interests

    269       274       —         269       380       393       380  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to PBF Holding LLC

  $ 235,617     $ 187,020     $ 21,117     $ 37,077     $ (271,296   $ 82,683     $ (268,999
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance sheet data (at end of period)

             

Total assets

  $ 6,566,897     $ 5,082,722     $ 4,013,762       $ 6,473,759     $ 5,950,599    

Total long-term debt (3)

    1,601,836       1,272,937       750,349         1,654,158       1,821,200    

Total equity

    2,588,933       1,821,284       1,630,516         2,504,807       1,836,775    

Selected financial data:

             

EBITDA (excluding special items) (4)

  $ 77,603     $ 894,472     $ 988,224     $ (227,578   $ 110,197     $ 60,991     $ 110,197  

Adjusted EBITDA

    94,477       893,506       990,350       (210,704     121,815       75,623       121,815  

Capital expenditures (5)

    1,498,191       979,481       625,403       1,523,314       417,697       240,668       417,697  

 

(1) Includes acquisition related expenses consisting primarily of consulting and legal expenses related to the acquisition from ExxonMobil Oil Corporation (“ExxonMobil”), Mobil Pipe Line Company and PDV Chalmette, Inc., of 100% of the ownership interests of Chalmette Refining, L.L.C. (“Chalmette Refining”), which owns the Chalmette refinery and related logistics assets (collectively, the “Chalmette Acquisition”) and Torrance Acquisition of $13.6 million and $5.8 million in 2016 and 2015, respectively. For the six months ended June 30, 2017 and 2016, includes acquisition related expenses consisting primarily of consulting and legal expenses of $0.5 million and $7.1 million, respectively, related to the Chalmette and Torrance Acquisitions and pending and nonconsummated acquisitions.
(2) Subsequent to the closing of the contribution agreement between PBFX and PBF LLC on August 31, 2016 (the “TVPC Contribution Agreement”), the Company accounts for its 50% equity ownership of Torrance Valley Pipeline Company (“TVPC”) as an investment in an equity method investee.
(3) Total long-term debt, excluding debt issuance costs and affiliate notes payable, includes current maturities and our Delaware Economic Development Authority Loan.
(4) The special items for the periods presented relate to a lower of cost or market inventory adjustment (LCM) and debt extinguishment costs. LCM is a GAAP guideline related to inventory valuation that requires inventory to be stated at the lower of cost or market. Our inventories are stated at the lower of cost or market. Cost is determined using last-in, first-out (LIFO) inventory valuation methodology, in which the most recently incurred costs are charged to cost of sales and inventories are valued at base layer acquisition costs. Market is determined based on an assessment of the current estimated replacement cost and net realizable selling price of the inventory. In periods where the market price of our inventory declines substantially, cost values of inventory may exceed market values. In such instances, we record an adjustment to write down the value of inventory to market value in accordance with GAAP. In subsequent periods, the value of inventory is reassessed and an LCM adjustment is recorded to reflect the net change in the LCM inventory reserve between the prior period and the current period. Additionally, during the six months ended June 30, 2017, we recorded debt extinguishment costs of $25.5 million related to the redemption of the 2020 Senior Secured Notes (as defined herein). These non-recurring costs were not recorded in any other period presented. Although we believe that non-GAAP financial measures excluding the impact of special items provide useful supplemental information to investors regarding the results and performance of our business and allow for more useful period-over-period comparison, such non-GAAP measurements should only be considered as a supplement to, and not as a substitute for, or superior to, the financial measures prepared in accordance with GAAP.
(5) Includes expenditures for construction in progress, property, plant and equipment (including railcar purchases), deferred turnaround costs and other assets, excluding the proceeds from sales of assets. Pro forma capital expenditures for the year ended December 31, 2016 include historical capital expenditures of the Torrance Refinery & Associated Logistics for the periods prior to the closing of the Torrance Acquisition.

 



 

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EBITDA, EBITDA Excluding Special Items and Adjusted EBITDA

Our management uses EBITDA (earnings before interest, income taxes, depreciation and amortization), EBITDA excluding special items and Adjusted EBITDA as measures of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with our board of directors, creditors, analysts and investors concerning our financial performance. Our outstanding indebtedness for borrowed money and other contractual obligations also include similar measures as a basis for certain covenants under those agreements which may differ from the Adjusted EBITDA definition described below.

EBITDA, EBITDA excluding special items and Adjusted EBITDA are not presentations made in accordance with GAAP and our computation of EBITDA, EBITDA excluding special items and Adjusted EBITDA may vary from others in our industry. In addition, Adjusted EBITDA contains some, but not all, adjustments that are taken into account in the calculation of the components of various covenants in the agreements governing the 2025 Senior Notes and other credit facilities. EBITDA, EBITDA excluding special items and Adjusted EBITDA should not be considered as alternatives to operating income (loss) or net income (loss) as measures of operating performance. In addition, EBITDA, EBITDA excluding special items and Adjusted EBITDA are not presented as, and should not be considered, an alternative to cash flows from operations as a measure of liquidity. Adjusted EBITDA is defined as EBITDA before adjustments for items such as equity-based compensation expense, gains (losses) from certain derivative activities and contingent consideration, the non-cash change in the deferral of gross profit related to the sale of certain finished products, the write down of inventory to the LCM, and debt extinguishment costs related to refinancing activities. Other companies, including other companies in our industry, may calculate EBITDA, EBITDA excluding special items and Adjusted EBITDA differently than we do, limiting their usefulness as comparative measures. EBITDA, EBITDA excluding special items and Adjusted EBITDA also have limitations as analytical tools and should not be considered in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations include that EBITDA, EBITDA excluding special items and Adjusted EBITDA:

 

    do not reflect depreciation expense or our cash expenditures, or future requirements, for capital expenditures or contractual commitments;

 

    do not reflect changes in, or cash requirements for, our working capital needs;

 

    do not reflect our interest expense, or the cash requirements necessary to service interest or principal payments, on our debt;

 

    do not reflect realized and unrealized gains and losses from certain hedging activities, which may have a substantial impact on our cash flow;

 

    do not reflect certain other non-cash income and expenses; and

 

    exclude income taxes that may represent a reduction in available cash.

 



 

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The following tables reconcile net income as reflected in our results of operations to EBITDA, EBITDA excluding special items and Adjusted EBITDA for the periods presented:

 

     Year Ended December 31,     Six Months Ended June 30,  
     (in thousands)  
     2016     2015     2014     Pro Forma
Consolidated
2016
    2017     2016     Pro Forma
Condensed
Consolidated
2017
 

Reconciliation of net income (loss) to EBITDA:

              

Net Income (loss)

   $ 235,886     $ 187,294     $ 21,117     $ 37,346     $ (270,916   $ 83,076     $ (268,619

Depreciation and amortization

     209,840       191,110       178,996       247,015       118,683       103,212       118,683  

Interest expense, net

     129,536       88,194       98,001       129,656       63,513       64,550       61,216  

Income tax expense (benefit)

     23,689       648       —         (120,247     6,332       26,996       6,332  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA

   $ 598,951     $ 467,246     $ 298,114     $ 293,770     $ (82,388   $ 277,834     $ (82,388
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Special Items:

              

Add: Non-cash LCM inventory adjustment

     (521,348     427,226       690,110       (521,348     167,134       (216,843     167,134  

Add: Debt estinguishment costs

     —         —         —         —         25,451       —         25,451  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA (excluding special items)

   $ 77,603     $ 894,472     $ 988,224     $ (227,578   $ 110,197     $ 60,991     $ 110,197  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Reconciliation of EBITDA to Adjusted EBITDA:

              

EBITDA

   $ 598,951     $ 467,246     $ 298,114     $ 293,770     $ (82,388   $ 277,834     $ (82,388

Add: Stock based compensation

     18,296       9,218       6,095       18,296       10,134       9,999       10,134  

Add: Non-cash LCM inventory adjustment

     (521,348     427,226       690,110       (521,348     167,134       (216,843     167,134  

Add: Non-cash change in fair value of catalyst lease obligations

     (1,422     (10,184     (3,969     (1,422     1,484       4,633       1,484  

Add: Debt estinguishment costs

     —         —         —         —         25,451       —         25,451  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

   $ 94,477     $ 893,506     $ 990,350     $ (210,704     $121,815     $ 75,623     $ 121,815  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 



 

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RISK FACTORS

Investing in the notes involves a number of risks. You should carefully consider, in addition to the other information contained in this prospectus (including “Management’s Discussion and Analysis of Financial Condition and Results of Operations of PBF Holding” and our financial statements and related notes), the following risks before participating in the exchange offer. If any of these risks were to occur, our business, financial condition, results of operations or prospects could be materially adversely affected. In that case, our ability to fulfill our obligations under the notes and the trading price of the notes could be materially affected, and you could lose all or part of your investment.

You should bear in mind, in reviewing this prospectus, that past experience is no indication of future performance. You should read the section titled “Cautionary Statement Regarding Forward-Looking Statements” for a discussion of what types of statements are forward-looking statements, as well as the significance of such statements in the context of this prospectus. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of various factors, including the risks and uncertainties faced by us described below.

Risks Related to the Exchange Offer

If you choose not to exchange your old notes in the exchange offer, the transfer restrictions currently applicable to your old notes will remain in force and the market price of your old notes could decline.

If you do not exchange your old notes for new notes in the exchange offer, then you will continue to be subject to the transfer restrictions on the old notes as set forth in the prospectus distributed in connection with the private offering of the old notes. In general, the old notes may not be offered or sold unless they are registered or exempt from registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement, we do not intend to register resales of the old notes under the Securities Act.

If you do not exchange your old notes for new notes in the exchange offer and other holders of old notes tender their old notes in the exchange offer, the total principal amount of the old notes remaining after the exchange offer will be less than it was prior to the exchange offer, which may have an adverse effect upon and increase the volatility of, the market price of the old notes due to reduction in liquidity.

Your ability to transfer the new notes may be limited by the absence of a trading market.

The new notes will be new securities for which currently there is no trading market. We do not currently intend to apply for listing of the new notes on any securities exchange or stock market. Although the initial purchasers informed us that they intended to make a market in the notes, they are not obligated to do so. In addition, they may discontinue any such market making at any time without notice. The liquidity of any market for the new notes will depend on the number of holders of those notes, the interest of securities dealers in making a market in those notes and other factors. Accordingly, we cannot assure you as to the development or liquidity of any market for the new notes. Historically, the market for non-investment grade debt has been subject to disruptions that have caused substantial volatility in the prices of securities similar to the new notes. We cannot assure you that the market, if any, for the new notes will be free from similar disruptions. Any such disruption may adversely affect the note holders.

Future trading prices of the new notes will depend on many factors, including:

 

    our subsidiaries’ operating performance and financial condition;

 

    the interest of the securities dealers in making a market in the new notes; and

 

    the market for similar securities.

 

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You may not receive the new notes in the exchange offer if the exchange offer procedures are not properly followed.

We will issue the new notes in exchange for your old notes only if you properly tender the old notes before expiration of the exchange offer. Neither we nor the exchange agent are under any duty to give notification of defects or irregularities with respect to the tenders of the old notes for exchange. If you are the beneficial holder of old notes that are held through your broker, dealer, commercial bank, trust company or other nominee, and you wish to tender such notes in the exchange offer, you should promptly contact the person or entity through which your old notes are held and instruct that person or entity to tender on your behalf.

Broker-dealers may become subject to the registration and prospectus delivery requirements of the Securities Act and any profit on the resale of the new notes may be deemed to be underwriting compensation under the Securities Act.

Any broker-dealer that acquires new notes in the exchange offer for its own account in exchange for old notes which it acquired through market-making or other trading activities must acknowledge that it will comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction by that broker-dealer. Any profit on the resale of the new notes and any commission or concessions received by a broker-dealer may be deemed to be underwriting compensation under the Securities Act.

Risks Relating to Our Business and Industry

The price volatility of crude oil, other feedstocks, blendstocks, refined products and fuel and utility services may have a material adverse effect on our revenues, profitability, cash flows and liquidity.

Our revenues, profitability, cash flows and liquidity from operations depend primarily on the margin above operating expenses (including the cost of refinery feedstocks, such as crude oil, intermediate partially refined petroleum products, and natural gas liquids that are processed and blended into refined products) at which we are able to sell refined products. Refining is primarily a margin-based business and, to increase profitability, it is important to maximize the yields of high value finished products while minimizing the costs of feedstock and operating expenses. When the margin between refined product prices and crude oil and other feedstock costs contracts, our earnings, profitability and cash flows are negatively affected. Refining margins historically have been volatile, and are likely to continue to be volatile, as a result of a variety of factors, including fluctuations in the prices of crude oil, other feedstocks, refined products and fuel and utility services. An increase or decrease in the price of crude oil will likely result in a similar increase or decrease in prices for refined products; however, there may be a time lag in the realization, or no such realization, of the similar increase or decrease in prices for refined products. The effect of changes in crude oil prices on our refining margins therefore depends in part on how quickly and how fully refined product prices adjust to reflect these changes.

In addition, the nature of our business requires us to maintain substantial crude oil, feedstock and refined product inventories. Because crude oil, feedstock and refined products are commodities, we have no control over the changing market value of these inventories. Our crude oil, feedstock and refined product inventories are valued at the lower of cost or market value under the last-in-first-out (“LIFO”) inventory valuation methodology. If the market value of our crude oil, feedstock and refined product inventory declines to an amount less than our LIFO cost, we would record a write-down of inventory and a non-cash impact to cost of sales. For example, during the year ended December 31, 2016, we recorded an adjustment to value our inventories to the lower of cost or market which increased operating income and net income by $521.3 million, respectively, reflecting the net change in the lower of cost or market inventory reserve from $1,117.3 million at December 31, 2015 to $596.0 million at December 31, 2016. During the six months ended June 30, 2017, we recorded an adjustment to value our inventories to the lower of cost or market which decreased both operating income and net income by $167.1 million reflecting the net change in the lower of cost or market inventory reserve from $596.0 million at December 31, 2016 to $763.1 million at June 30, 2017.

 

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Prices of crude oil, other feedstocks, blendstocks, and refined products depend on numerous factors beyond our control, including the supply of and demand for crude oil, other feedstocks, gasoline, diesel, ethanol, asphalt and other refined products. Such supply and demand are affected by a variety of economic, market, environmental and political conditions.

Our direct operating expense structure also impacts our profitability. Our major direct operating expenses include employee and contract labor, maintenance and energy. Our predominant variable direct operating cost is energy, which is comprised primarily of fuel and other utility services. The volatility in costs of fuel, principally natural gas, and other utility services, principally electricity, used by our refineries and other operations affect our operating costs. Fuel and utility prices have been, and will continue to be, affected by factors outside our control, such as supply and demand for fuel and utility services in both local and regional markets. Natural gas prices have historically been volatile and, typically, electricity prices fluctuate with natural gas prices. Future increases in fuel and utility prices may have a negative effect on our refining margins, profitability and cash flows.

Our profitability is affected by crude oil differentials and related factors, which fluctuate substantially.

A significant portion of our profitability is derived from the ability to purchase and process crude oil feedstocks that historically have been cheaper than benchmark crude oils, such as the heavy, sour crude oils processed at our Delaware City, Paulsboro, Chalmette and Torrance refineries. For our Toledo refinery, historically crude prices have been slightly above the WTI benchmark, however, that premium to WTI typically results in favorable refinery production yield. For all locations, these crude oil differentials can vary significantly from quarter to quarter depending on overall economic conditions and trends and conditions within the markets for crude oil and refined products. Any change in these crude oil differentials may have an impact on our earnings. Our rail investment and strategy to acquire cost advantaged Mid-Continent and Canadian crude, which are priced based on WTI, could be adversely affected when the Dated Brent/WTI or related differential narrows. A narrowing of the WTI/Dated Brent differential may result in our Toledo refinery losing a portion of its crude oil price advantage over certain of our competitors, which negatively impacts our profitability. In addition, the narrowing of the WTI/WCS differential, which is a proxy for the difference between light U.S. and heavy Canadian crude oil, may reduce our refining margins and adversely affect our profitability and earnings. Divergent views have been expressed as to the expected magnitude of changes to these crude differentials in future periods. Any further or continued narrowing of these differentials could have a material adverse effect on our business and profitability.

Additionally, governmental and regulatory actions, including recent initiatives by the Organization of the Petroleum Exporting Countries to restrict crude oil production levels and executive actions by the new U.S. presidential administration to advance certain energy infrastructure projects such as the Keystone XL pipeline, may continue to impact crude oil prices and crude oil differentials. Any increase in crude oil prices or unfavorable movements in crude oil differentials due to such actions or changing regulatory environment may negatively impact our ability to acquire crude oil at economical prices and could have a material adverse effect on our business and profitability.

The repeal of the crude oil export ban in the United States may affect our profitability.

In December 2015, the United States Congress passed and the President signed the 2016 Omnibus Appropriations bill which included a repeal of the ban on the export of crude oil produced in the United States. The crude export ban was established by the Energy Policy and Conservation Act in 1975 to reduce reliance on foreign oil producing countries. While there are differing views on the magnitude of the impact of lifting the crude export ban on crude oil prices, most economists believe the export ban repeal will eventually lead to higher crude oil prices and narrowing Dated Brent/WTI differentials and in turn higher gasoline prices in the United States. Crude oil is our most significant input cost and there is no guaranty that increases in our crude oil costs will be offset by corresponding increases in the selling prices of our refined products. As a result, an increase in crude oil prices resulting from the repeal of the crude oil export ban may reduce our profitability.

 

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

Our five refineries have similar throughput capacity, however, favorable market conditions due to, among other things, geographic location, crude and refined product slates, and customer demand, may cause an individual refinery to contribute more significantly to our earnings than others for a period of time. For example, at times our Toledo, Ohio refinery in the past has produced a substantial portion of our earnings. As a result, if there were a significant disruption to operations at this refinery, our earnings could be materially adversely affected (to the extent not recoverable through insurance) disproportionately to Toledo’s portion of our consolidated throughput. The Toledo refinery, or one of our other refineries, may continue to disproportionately affect our results of operations in the future. Any prolonged disruption to the operations of such refinery, whether due to labor difficulties, destruction of or damage to such facilities, severe weather conditions, interruption of utilities service or other reasons, could have a material adverse effect on our business, results of operations or financial condition.

A significant interruption or casualty loss at any of our refineries and related assets could reduce our production, particularly if not fully covered by our insurance. Failure by one or more insurers to honor its coverage commitments for an insured event could materially and adversely affect our future cash flows, operating results and financial condition.

Our business currently consists of owning and operating five refineries and related assets. As a result, our operations could be subject to significant interruption if any of our refineries were to experience a major accident, be damaged by severe weather or other natural disaster, or otherwise be forced to shut down or curtail production due to unforeseen events, such as acts of God, nature, orders of governmental authorities, supply chain disruptions impacting our crude rail facilities or other logistical assets, power outages, acts of terrorism, fires, toxic emissions and maritime hazards. Any such shutdown or disruption would reduce the production from that refinery. There is also risk of mechanical failure and equipment shutdowns both in general and following unforeseen events. Further, in such situations, undamaged refinery processing units may be dependent on or interact with damaged sections of our refineries and, accordingly, are also subject to being shut down. In the event any of our refineries is forced to shut down for a significant period of time, it would have a material adverse effect on our earnings, our other results of operations and our financial condition as a whole.

As protection against these hazards, we maintain insurance coverage against some, but not all, such potential losses and liabilities. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may increase substantially. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, coverage for hurricane damage can be limited, and coverage for terrorism risks can include broad exclusions. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position.

Our insurance program includes a number of insurance carriers. Significant disruptions in financial markets could lead to a deterioration in the financial condition of many financial institutions, including insurance companies and, therefore, we may not be able to obtain the full amount of our insurance coverage for insured events.

Our refineries are subject to interruptions of supply and distribution as a result of our reliance on pipelines and railroads for transportation of crude oil and refined products.

Our Toledo, Chalmette and Torrance refineries receive a significant portion of their crude oil through pipelines. These pipelines include the Enbridge system, Capline and Mid-Valley pipelines for supplying crude to our Toledo refinery, the MOEM and CAM pipelines for supplying crude to our Chalmette refinery and the San Joaquin Pipeline, San Ardo and Coastal Pipeline systems for supplying crude to our Torrance refinery. Additionally, our Toledo, Chalmette and Torrance refineries deliver a significant portion of the refined products

 

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through pipelines. These pipelines include pipelines such as the Sunoco Logistics Partners L.P. and Buckeye Partners L.P. pipelines at Toledo, the Collins Pipeline at our Chalmette refinery and Jet Pipeline to the Los Angeles International Airport, the Product Pipeline to Vernon and the Product Pipeline to Atwood at our Torrance refinery. We could experience an interruption of supply or delivery, or an increased cost of receiving crude oil and delivering refined products to market, if the ability of these pipelines to transport crude oil or refined products is disrupted because of accidents, weather interruptions, governmental regulation, terrorism, other third party action or casualty or other events.

The Delaware City rail unloading facilities allow our East Coast refineries to source WTI-based crudes from Western Canada and the Mid-Continent, which may provide significant cost advantages versus traditional Brent-based international crudes in certain market environments. Any disruptions or restrictions to our supply of crude by rail due to problems with third party logistics infrastructure or operations or as a result of increased regulations, could increase our crude costs and negatively impact our results of operations and cash flows.

In addition, due to the common carrier regulatory obligation applicable to interstate oil pipelines, capacity allocation among shippers can become contentious in the event demand is in excess of capacity. Therefore, nominations by new shippers or increased nominations by existing shippers may reduce the capacity available to us. Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that we rely upon for transportation of crude oil and refined products could have a further material adverse effect on our business, financial condition, results of operations and cash flows.

We may have capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate.

If we cannot generate sufficient cash flows or otherwise secure sufficient liquidity to support our short-term and long-term capital requirements, we may not be able to meet our payment obligations or our future debt obligations, comply with certain deadlines related to environmental regulations and standards, or pursue our business strategies, including acquisitions, in which case our operations may not perform as we currently expect. We have substantial short-term capital needs and may have substantial long term capital needs. Our short-term working capital needs are primarily related to financing certain of our refined products inventory not covered by our various supply and inventory intermediation agreements. Pursuant to the inventory intermediation agreements, J. Aron & Company (J. Aron) purchases and holds title to certain of the intermediate and finished products produced by the Delaware City and Paulsboro refineries and delivered into the tanks at the refineries (or at other locations outside of the refineries as agreed upon by both parties). Furthermore, J. Aron agrees to sell the intermediate and finished products back to us as they are discharged out of the refineries’ tanks (or other locations outside of the refineries as agreed upon by both parties). We market and sell the finished products independently to third parties. On May 4, 2017, we and our subsidiaries, Delaware City Refining Company LLC (“DCR”) and Paulsboro Refining Company LLC (“PRC”), entered into amendments to the inventory intermediation agreements (as amended, together, the “A&R Intermediation Agreements”) with J. Aron, pursuant to which certain terms of the existing inventory intermediation agreements were amended, including, among other things, pricing and an extension of the terms. The A&R Intermediation Agreements were further amended on September 8, 2017. As a result of the amendments (i) the A&R Intermediation Agreement by and among J. Aron, PBF Holding and PRC relating to the Paulsboro refinery extends to December 31, 2019, which term may be further extended by mutual consent of the parties to December 31, 2020 and (ii) the A&R Intermediation Agreement by and among J. Aron, PBF Holding and DCR relating to the Delaware City refinery extends the term to July 1, 2019, which term may be further extended by mutual consent of the parties to July 1, 2020.

If we cannot adequately handle our crude oil and feedstock requirements or if we are required to obtain our crude oil supply at our other refineries without the benefit of the existing supply arrangements or the applicable counterparty defaults in its obligations, our crude oil pricing costs may increase as the number of days between when we pay for the crude oil and when the crude oil is delivered to us increases. Termination of our A&R Intermediation Agreements with J. Aron would require us to finance our refined products inventory covered by the agreements at terms that may not be as favorable. Additionally, we are obligated to repurchase from J. Aron

 

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all volumes of products located at the refineries’ storage tanks (or at other locations outside of the refineries as agreed upon by both parties) upon termination of these agreements, which may have a material adverse impact on our working capital and financial condition. Further, if we are not able to market and sell our finished products to credit worthy customers, we may be subject to delays in the collection of our accounts receivable and exposure to additional credit risk. Such increased exposure could negatively impact our liquidity due to our increased working capital needs as a result of the increase in the amount of crude oil inventory and accounts receivable we would have to carry on our balance sheet. Our long-term needs for cash include those to support ongoing capital expenditures for equipment maintenance and upgrades during turnarounds at our refineries and to complete our routine and normally scheduled maintenance, regulatory and security expenditures.

In addition, from time to time, we are required to spend significant amounts for repairs when one or more processing units experiences temporary shutdowns. We continue to utilize significant capital to upgrade equipment, improve facilities, and reduce operational, safety and environmental risks. In connection with the Paulsboro and Torrance acquisitions, we assumed certain significant environmental obligations, and may similarly do so in future acquisitions. We will likely incur substantial compliance costs in connection with new or changing environmental, health and safety regulations. See “Management’s Discussion and Analysis of Financial Condition of PBF Holding.” Our liquidity condition will affect our ability to satisfy any and all of these needs or obligations.

We may not be able to obtain funding on acceptable terms or at all because of volatility and uncertainty in the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.

In the recent past, global financial markets and economic conditions have been, and may continue to be, subject to disruption and volatile due to a variety of factors, including uncertainty in the financial services sector, low consumer confidence, falling commodity prices, geopolitical issues and the generally weak economic 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

 

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engaged in the petroleum exploration and production business and therefore do not produce any of our crude oil feedstocks. We do not have a retail business and therefore are dependent upon others for outlets for our refined products. Because of their integrated operations and larger capitalization, these companies may be more flexible in responding to volatile industry or market conditions, such as shortages of crude oil supply and other feedstocks or intense price fluctuations.

Newer or upgraded refineries will often be more efficient than our refineries, which may put us at a competitive disadvantage. We have taken significant measures to maintain our refineries including the installation of new equipment and redesigning older equipment to improve our operations. However, these actions involve significant uncertainties, since upgraded equipment may not perform at expected throughput levels, the yield and product quality of new equipment may differ from design specifications and modifications may be needed to correct equipment that does not perform as expected. Any of these risks associated with new equipment, redesigned older equipment or repaired equipment could lead to lower revenues or higher costs or otherwise have an adverse effect on future results of operations and financial condition. Over time, our refineries or certain refinery units may become obsolete, or be unable to compete, because of the construction of new, more efficient facilities by our competitors.

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

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

Economic turmoil in the global financial system has had and may in the future have an adverse impact on the refining industry.

Our business and profitability are affected by the overall level of demand for our products, which in turn is affected by factors such as overall levels of economic activity and business and consumer confidence and spending. Declines in global economic activity and consumer and business confidence and spending during the recent global downturn significantly reduced the level of demand for our products. Reduced demand for our products has had and may continue to have an adverse impact on our business, financial condition, results of operations and cash flows. In addition, downturns in the economy impact the demand for refined fuels and, in turn, result in excess refining capacity. Refining margins are impacted by changes in domestic and global refining capacity, as increases in refining capacity can adversely impact refining margins, earnings and cash flows.

Our business is indirectly exposed to risks faced by our suppliers, customers and other business partners. The impact on these constituencies of the risks posed by economic turmoil in the global financial system have included or could include interruptions or delays in the performance by counterparties to our contracts, reductions and delays in customer purchases, delays in or the inability of customers to obtain financing to purchase our products and the inability of customers to pay for our products. Any of these events may have an adverse impact on our business, financial condition, results of operations and cash flows.

 

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We must make substantial capital expenditures on our operating facilities to maintain their reliability and efficiency. If we are unable to complete capital projects at their expected costs and/or in a timely manner, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations or cash flows could be materially and adversely affected.

Delays or cost increases related to capital spending programs involving engineering, procurement and construction of new facilities (or improvements and repairs to our existing facilities and equipment, including turnarounds) could adversely affect our ability to achieve targeted internal rates of return and operating results. Such delays or cost increases may arise as a result of unpredictable factors in the marketplace, many of which are beyond our control, including:

 

    denial or delay in obtaining regulatory approvals and/or permits;

 

    unplanned increases in the cost of construction materials or labor;

 

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

 

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

 

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

 

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

 

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

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

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

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

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

 

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business and results of operations. In addition, it is likely that, when we acquire refineries, we will not have access to the type of historical financial information that we will require regarding the prior operation of the refineries. As a result, it may be difficult for investors to evaluate the probable impact of significant acquisitions on our financial performance until we have operated the acquired refineries for a substantial period of time.

Our business may suffer if any of our senior executives or other key employees discontinues employment with us. Furthermore, a shortage of skilled labor or disruptions in our labor force may make it difficult for us to maintain labor productivity.

Our future success depends to a large extent on the services of our senior executives and other key employees. Our business depends on our continuing ability to recruit, train and retain highly qualified employees in all areas of our operations, including engineering, accounting, business operations, finance and other key back-office and mid-office personnel. Furthermore, our operations require skilled and experienced employees with proficiency in multiple tasks. The competition for these employees is intense, and the loss of these executives or employees could harm our business. If any of these executives or other key personnel resigns or becomes unable to continue in his or her present role and is not adequately replaced, our business operations could be materially adversely affected.

A portion of our workforce is unionized, and we may face labor disruptions that would interfere with our operations.

At Delaware City, Toledo, Chalmette and Torrance, most hourly employees are covered by a collective bargaining agreement through the United Steel Workers (“USW”). The agreements with the USW covering Delaware City, Chalmette and Torrance are scheduled to expire in January 2019 and the agreement with the USW covering Toledo is scheduled to expire in February 2019. Similarly, at Paulsboro hourly employees are represented by the Independent Oil Workers (“IOW”) under a contract scheduled to expire in March 2019. Future negotiations after 2019 may result in labor unrest for which a strike or work stoppage is possible. Strikes and/or work stoppages could negatively affect our operational and financial results and may increase operating expenses at the refineries.

Our hedging activities may limit our potential gains, exacerbate potential losses and involve other risks.

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

 

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

 

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

 

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

 

    the counterparties to our derivative contracts fail to perform under the contracts; or

 

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    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.

In addition, these hedging activities involve basis risk. Basis risk in a hedging arrangement occurs when the price of the commodity we hedge is more or less variable than the index upon which the hedged commodity is based, thereby making the hedge less effective. For example, a NYMEX index used for hedging certain volumes of our crude oil or refined products may have more or less variability than the actual cost or price we realize for such crude oil or refined products. We may not hedge all the basis risk inherent in our hedging arrangements and derivative contracts.

Our commodity derivative activities could result in period-to-period earnings volatility.

We do not apply hedge accounting to all of our commodity derivative contracts and, as a result, unrealized gains and losses will be charged to our earnings based on the increase or decrease in the market value of such unsettled positions. These gains and losses may be reflected in our income statement in periods that differ from when the settlement of the underlying hedged items are reflected in our income statement. Such derivative gains or losses in earnings may produce significant period-to-period earnings volatility that is not necessarily reflective of our underlying operational performance.

The adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivatives contracts to reduce the effect of commodity price, interest rate and other risks associated with our business.

The United States Congress in 2010 passed the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which, among other things, established federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. In connection with the Dodd-Frank Act, the Commodity Futures Trading Commission, or the CFTC, has proposed rules to set position limits for certain futures and option contracts, and for swaps that are their economic equivalent, in the major energy markets. The legislation and related regulations may also require us to comply with margin requirements and with certain clearing and trade-execution requirements if we do not satisfy certain specific exceptions. The legislation may also require the counterparties to our derivatives contracts to transfer or assign some of their derivatives contracts to a separate entity, which may not be as creditworthy as the current counterparty. The legislation and related regulations could significantly increase the cost of derivatives contracts (including through requirements to post collateral), materially alter the terms of derivatives contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivatives contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

Our operations could be disrupted if our critical information systems are hacked or fail, causing increased expenses and loss of sales.

Our business is highly dependent on financial, accounting and other data processing systems and other communications and information systems, including our enterprise resource planning tools. We process a large number of transactions on a daily basis and rely upon the proper functioning of computer systems. If a key system was hacked or otherwise interfered with by an unauthorized access, or was to fail or experience unscheduled downtime for any reason, even if only for a short period, our operations and financial results could be affected adversely. Our systems could be damaged or interrupted by a security breach, cyber-attack, fire,

 

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flood, power loss, telecommunications failure or similar event. We have a formal disaster recovery plan in place, but this plan may not prevent delays or other complications that could arise from an information systems failure. Further, our business interruption insurance may not compensate us adequately for losses that may occur. Finally, federal legislation relating to cyber-security threats could impose additional requirements on our operations.

Product liability claims and litigation could adversely affect our business and results of operations.

Product liability is a significant commercial risk. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers based upon claims for injuries and property damage caused by the use of or exposure to various products. Failure of our products to meet required specifications or claims that a product is inherently defective could result in product liability claims from our shippers and customers, and also arise from contaminated or off-specification product in commingled pipelines and storage tanks and/or defective fuels. Product liability claims against us could have a material adverse effect on our business or results of operations.

We may incur significant liability under, or costs and capital expenditures to comply with, environmental and health and safety regulations, which are complex and change frequently.

Our operations are subject to federal, state and local laws regulating, among other things, the use and/or handling of petroleum and other regulated materials, the emission and discharge of materials into the environment, waste management, and remediation of discharges of petroleum and petroleum products, characteristics and composition of gasoline and distillates and other matters otherwise relating to the protection of the environment and the health and safety of the surrounding community. For example, the SCAQMD recently announced that it will consider banning the use of modified hydrofluoric acid, also known as MHF, in California. We utilize MHF in the manufacturing of gasoline at our Torrance refinery. If MHF usage is limited or restricted by the SCAQMD, our current operations would be adversely affected, which could have a material adverse effect on our business, financial condition, cash flows and results of operations. Our operations are also subject to extensive laws and regulations relating to occupational health and safety.

We cannot predict what additional environmental, health and safety legislation or regulations may be adopted in the future, or how existing or future laws or regulations may be administered or interpreted with respect to our operations. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time.

Certain environmental laws impose strict, and in certain circumstances, joint and several, liability for costs of investigation and cleanup of such spills, discharges or releases on owners and operators of, as well as persons who arrange for treatment or disposal of regulated materials at, contaminated sites. Under these laws, we may incur liability or be required to pay penalties for past contamination, and third parties may assert claims against us for damages allegedly arising out of any past or future contamination. The potential penalties and clean-up costs for past or future releases or spills, the failure of prior owners of our facilities to complete their clean-up obligations, the liability to third parties for damage to their property, or the need to address newly-discovered information or conditions that may require a response could be significant, and the payment of these amounts could have a material adverse effect on our business, financial condition, cash flows and results of operations.

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

 

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remediation projects are underway in accordance with regulatory requirements at our refineries. In connection with the acquisitions of certain of our refineries, the prior owners have retained certain liabilities or indemnified us for certain liabilities, including those relating to pre-acquisition soil and groundwater conditions, and in some instances we have assumed certain liabilities and environmental obligations, including certain existing and potential remediation obligations. If the prior owners fail to satisfy their obligations for any reason, or if significant liabilities arise in the areas in which we assumed liability, we may become responsible for remediation expenses and other environmental liabilities, which could have a material adverse effect on our financial condition. As a result, in addition to making capital expenditures or incurring other costs to comply with environmental laws, we also may be liable for significant environmental litigation or for investigation and remediation costs and other liabilities arising from the ownership or operation of these assets by prior owners, which could materially adversely affect our financial condition, results of operations and cash flow. See “Business—Environmental, Health and Safety Matters.”

We may also face liability arising from current or future claims alleging personal injury or property damage due to exposure to chemicals or other regulated materials, such as asbestos, benzene, silica dust and petroleum hydrocarbons, at or from our facilities. We may also face liability for personal injury, property damage, natural resource damage or clean-up costs for the alleged migration of contamination from our properties. A significant increase in the number or success of these claims could materially adversely affect our financial condition, results of operations and cash flow.

Regulation of emissions of greenhouse gases could force us to incur increased capital and operating costs and could have a material adverse effect on our results of operations and financial condition.

Both houses of Congress have actively considered legislation to reduce emissions of greenhouse gases (“GHGs”), such as carbon dioxide and methane, including proposals to: (i) establish a cap and trade system, (ii) create a federal renewable energy or “clean” energy standard requiring electric utilities to provide a certain percentage of power from such sources, and (iii) create enhanced incentives for use of renewable energy and increased efficiency in energy supply and use. In addition, the EPA is taking steps to regulate GHGs under the existing federal Clean Air Act (the “CAA”). The EPA has already adopted regulations limiting emissions of GHGs from motor vehicles, addressing the permitting of GHG emissions from stationary sources, and requiring the reporting of GHG emissions from specified large GHG emission sources, including refineries. These and similar regulations could require us to incur costs to monitor and report GHG emissions or reduce emissions of GHGs associated with our operations. In addition, various states, individually as well as in some cases on a regional basis, have taken steps to control GHG emissions, including adoption of GHG reporting requirements, cap and trade systems and renewable portfolio standards (such as AB 32 regulations in California). Efforts have also been undertaken to delay, limit or prohibit the EPA and possibly state action to regulate GHG emissions, and it is not possible at this time to predict the ultimate form, timing or extent of federal or state regulation. In addition, it is currently uncertain how the new presidential administration will address GHG emissions. In the event we do incur increased costs as a result of increased efforts to control GHG emissions, we may not be able to pass on any of these costs to our customers. Such requirements also could adversely affect demand for the refined petroleum products that we produce. Any increased costs or reduced demand could materially and adversely affect our business and results of operation.

Requirements to reduce emissions could result in increased costs to operate and maintain our facilities as well as implement and manage new emission controls and programs put in place. For example, AB 32 in California requires the state to reduce its GHG emissions to 1990 levels by 2020. Additionally, in September 2016, the state of California enacted Senate Bill 32 which further reduces greenhouse gas emissions targets to 40 percent below 1990 levels by 2030. Two regulations implemented to achieve these goals are Cap-and-Trade and the Low Carbon Fuel Standard (“LCFS”). In 2012, the California Air Resource Board (“CARB”) implemented Cap-and-Trade. This program currently places a cap on GHGs and we are required to acquire a sufficient number of credits to cover emissions from our refineries and our in-state sales of gasoline and diesel. In 2009, CARB adopted the LCFS, which requires a 10% reduction in the carbon intensity of gasoline and diesel by 2020. Compliance is achieved through blending lower carbon intensity biofuels into gasoline and diesel or by

 

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purchasing credits. Compliance with each of these programs is facilitated through a market-based credit system. If sufficient credits are unavailable for purchase or we are unable to pass through costs to our customers, we have to pay a higher price for credits or if we are otherwise unable to meet our compliance obligations, our financial condition and results of operations could be adversely affected.

Climate change could have a material adverse impact on our operations and adversely affect our facilities.

Some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. We believe the issue of climate change will likely continue to receive scientific and political attention, with the potential for further laws and regulations that could materially adversely affect our ongoing operations.

In addition, as many of our facilities are located near coastal areas, rising sea levels may disrupt our ability to operate those facilities or transport crude oil and refined petroleum products. Extended periods of such disruption could have an adverse effect on our results of operation. We could also incur substantial costs to protect or repair these facilities.

Renewable fuels mandates may reduce demand for the refined fuels we produce, which could have a material adverse effect on our results of operations and financial condition. The market prices for RINs have been volatile and may harm our profitability.

Pursuant to the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007, the EPA has issued Renewable Fuel Standards, or RFS, implementing mandates to blend renewable fuels into the petroleum fuels produced and sold in the United States. Under RFS, the volume of renewable fuels that obligated refineries must blend into their finished petroleum fuels increases annually over time until 2022. In addition, certain states have passed legislation that requires minimum biodiesel blending in finished distillates. On October 13, 2010, the EPA raised the maximum amount of ethanol allowed under federal law from 10% to 15% for cars and light trucks manufactured since 2007. The maximum amount allowed under federal law currently remains at 10% ethanol for all other vehicles. Existing laws and regulations could change, and the minimum volumes of renewable fuels that must be blended with refined petroleum fuels may increase. Because we do not produce renewable fuels, increasing the volume of renewable fuels that must be blended into our products displaces an increasing volume of our refinery’s product pool, potentially resulting in lower earnings and profitability. In addition, in order to meet certain of these and future EPA requirements, we may be required to purchase renewable fuel credits, known as “RINS,” which may have fluctuating costs. We have seen a fluctuation in the cost of RINs, required for compliance with the RFS. We incurred approximately $347.5 million in RINs costs during the year ended December 31, 2016 as compared to $171.6 million and $115.7 million during the years ended December 31, 2015 and 2014, respectively. We incurred approximately $119.7 million and $157.2 million in RINs costs for the six months ended June 30, 2017 and 2016, respectively. The fluctuations in our RINs costs are due primarily to volatility in prices for ethanol-linked RINs and increases in our production of on-road transportation fuels since 2012. Our RINs purchase obligation is dependent on our actual shipment of on-road transportation fuels domestically and the amount of blending achieved which can cause variability in our profitability.

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

Our transportation activities are subject to regulation by multiple governmental agencies. The regulatory burden on the industry increases the cost of doing business and affects profitability. Additional proposals and proceedings that affect the oil industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission, the United States Department of Transportation, and the courts. We cannot predict when or whether any such proposals may become effective or what impact such proposals may have. Projected

 

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operating costs related to our pipelines reflect the recurring costs resulting from compliance with these regulations, and these costs may increase due to future acquisitions, changes in regulation, changes in use, or discovery of existing but unknown compliance issues.

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

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

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

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

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

Changes in our credit profile could adversely affect our business.

Changes in our credit profile could affect the way crude oil suppliers view our ability to make payments and induce them to shorten the payment terms for our purchases or require us to post security or letters of credit prior to payment. Due to the large dollar amounts and volume of our crude oil and other feedstock purchases, any imposition by our suppliers of more burdensome payment terms on us may have a material adverse effect on our liquidity and our ability to make payments to our suppliers. This, in turn, could cause us to be unable to operate one or more of our refineries at full capacity.

Changes in laws or standards affecting the transportation of North American crude oil by rail could significantly impact our operations, and as a result cause our costs to increase.

Investigations into past rail accidents involving the transport of crude oil have prompted government agencies and other interested parties to call for increased regulation of the transport of crude oil by rail including in the areas of crude oil constituents, rail car design, routing of trains and other matters. Recent regulation governing shipments of petroleum crude oil by rail requires shippers to properly test and classify petroleum crude oil and further requires shippers to treat Class 3 petroleum crude oil transported by rail in tank cars as a Packing Group I or II hazardous material only. The DOT recently issued additional rules and regulations that require rail carriers to provide certain notifications to State agencies along routes utilized by trains over a certain length carrying crude oil, enhance safety training standards under the Rail Safety Improvement Act of 2008, require each railroad or contractor to develop and submit a training program to perform regular oversight and annual

 

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written reviews and establish enhanced tank car standards and operational controls for high-hazard flammable trains. The new rules and any further changes in law, regulations or industry standards that require us to reduce the volatile or flammable constituents in crude oil that is transported by rail, alter the design or standards for rail cars we use, change the routing or scheduling of trains carrying crude oil, or any other changes that detrimentally affect the economics of delivering North American crude oil by rail to our, or subsequently to third party, refineries, could increase our costs, which could have a material adverse effect on our financial condition, results of operations, cash flows and our ability to service our indebtedness.

We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with health, safety, environmental and other laws and regulations.

Our operations require numerous permits and authorizations under various laws and regulations. These authorizations and permits are subject to revocation, renewal or modification and can require operational changes to limit impacts or potential impacts on the environment and/or health and safety. A violation of authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions, and/or facility shutdowns. In addition, major modifications of our operations could require modifications to our existing permits or upgrades to our existing pollution control equipment. Any or all of these matters could have a negative effect on our business, results of operations and cash flows.

We may incur significant liability under, or costs and capital expenditures to comply with, environmental and health and safety regulations, which are complex and change frequently.

Our operations are subject to federal, state and local laws regulating, among other things, the handling of petroleum and other regulated materials, the emission and discharge of materials into the environment, waste management, and remediation of discharges of petroleum and petroleum products, characteristics and composition of gasoline and distillates and other matters otherwise relating to the protection of the environment. Our operations are also subject to extensive laws and regulations relating to occupational health and safety.

We cannot predict what additional environmental, health and safety legislation or regulations may be adopted in the future, or how existing or future laws or regulations may be administered or interpreted with respect to our operations. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time.

Certain environmental laws impose strict, and in certain circumstances joint and several liability for, costs of investigation and cleanup of such spills, discharges or releases on owners and operators of, as well as persons who arrange for treatment or disposal of regulated materials at contaminated sites. Under these laws, we may incur liability or be required to pay penalties for past contamination, and third parties may assert claims against us for damages allegedly arising out of any past or future contamination. The potential penalties and clean-up costs for past or future releases or spills, the failure of prior owners of our facilities to complete their clean-up obligations, the liability to third parties for damage to their property, or the need to address newly-discovered information or conditions that may require a response could be significant, and the payment of these amounts could have a material adverse effect on our business, financial condition and results of operations.

Our operating results are seasonal and generally lower in the first and fourth quarters of the year for our refining operations. We depend on favorable weather conditions in the spring and summer months.

Demand for gasoline products is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and construction work. Varying vapor pressure requirements between the summer and winter months also tighten summer gasoline supply. As a result, our operating results are generally lower for the first and fourth quarters of each year.

 

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We may not be able to successfully integrate the Torrance Refinery into our business, or realize the anticipated benefits of these acquisitions.

Following the completion of the Torrance Acquisition, the integration of this business into our operations may be a complex and time-consuming process that may not be successful. Prior to the completion of the Torrance Acquisition we did not have any operations in the West Coast. This may add complexity to effectively overseeing, integrating and operating this refinery and related assets. Even if we successfully integrate this business into our operations, there can be no assurance that we will realize the anticipated benefits and operating synergies. Our estimates regarding the earnings, operating cash flow, capital expenditures and liabilities resulting from this acquisition may prove to be incorrect. This acquisition involves risks, including:

 

    unexpected losses of key employees, customers and suppliers of the acquired operations;

 

    challenges in managing the increased scope, geographic diversity and complexity of our operations;

 

    diversion of management time and attention from our existing business;

 

    liability for known or unknown environmental conditions or other contingent liabilities and greater than anticipated expenditures required for compliance with environmental, safety or other regulatory standards or for investments to improve operating results; and

 

    the incurrence of additional indebtedness to finance acquisitions or capital expenditures relating to acquired assets.

In connection with our recently completed Torrance Acquisition, we did not have access to the type of historical financial information that we may require regarding the prior operation of the refinery. As a result, it may be difficult for investors to evaluate the probable impact of this significant acquisition on our financial performance until we have operated the acquired refinery for a substantial period of time.

Risks Related to Our Organizational Structure

Under a tax receivable agreement, PBF Energy is required to pay the current and former holders of PBF LLC Series A Units and PBF LLC Series B Units for certain realized or assumed tax benefits it may claim arising in connection with its initial public offering and future exchanges of PBF LLC Series A Units for shares of its Class A common stock and related transactions. The indenture governing the notes allows us, under certain circumstances, to make distributions sufficient for PBF Energy to pay its obligations arising from the tax receivable agreement, and such amounts are expected to be substantial.

PBF Energy entered into a tax receivable agreement that provides for the payment from time to time (“On-Going Payments”) by PBF Energy to the current and former holders of PBF LLC Series A Units and PBF LLC Series B Units for certain tax benefits it may claim arising in connection with its prior offerings and future exchanges of PBF LLC Series A Units for shares of its Class A Common Stock and related transactions, and the amounts it may pay could be significant.

PBF Energy’s payment obligations under the tax receivable agreement are PBF Energy’s obligations and not obligations of PBF Holding, PBF Finance, or any of PBF Holding’s other subsidiaries. However, because PBF Energy is primarily a holding company with limited operations of its own, its ability to make payments under the tax receivable agreement is dependent on our ability to make future distributions to it. The indentures governing the Senior Notes allow us to make tax distributions (as defined in the indenture), and it is expected that PBF Energy’s share of these tax distributions will be in amounts sufficient to allow PBF Energy to make On-Going Payments. The indentures governing the Senior Notes also allow us to make a distribution sufficient to allow PBF Energy to make any payments required under the tax receivable agreement upon a change in control, so long as we offer to purchase all of the Senior Notes outstanding at a price in cash equal to 101% of the aggregate principal amount thereof, plus accrued and unpaid interest thereon, if any. If PBF Energy’s share of the

 

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distributions it receives under these specific provisions of the indentures is insufficient to satisfy its obligations under the tax receivable agreement, PBF Energy may cause us to make distributions in accordance with other provisions of the indentures in order to satisfy such obligations. In any case, based on our estimates of PBF Energy’s obligations under the tax receivable agreement, the amount of our distributions on account of PBF Energy’s obligations under the tax receivable agreement are expected to be substantial.

For example, with respect to On-Going Payments, assuming no material changes in the relevant tax law, and that PBF Energy earns sufficient taxable income to realize all tax benefits that are subject to the tax receivable agreement, we expect that PBF Energy On-Going Payments under the tax receivable agreement relating to exchanges that occurred prior to that date to aggregate $611.4 million and to range over the next 5 years from approximately $39.6 million to $60.0 million per year and decline thereafter. Further On-Going Payments by PBF Energy in respect of subsequent exchanges of PBF LLC Series A Units would be in addition to these amounts and are expected to be substantial as well. With respect to the Change of Control Payment, assuming that the market value of a share of our Class A common stock equals $22.26 per share (the closing price on June 30, 2017) and that LIBOR were to be 1.85%, we estimate as of June 30, 2017 that the aggregate amount of these accelerated payments would have been approximately $542.0 million if triggered immediately on such date. Our existing indebtedness may limit our ability to make distributions to PBF LLC, and in turn to PBF Energy to pay these obligations. These provisions may deter a potential sale of us to a third party and may otherwise make it less likely a third party would enter into a change of control transaction with PBF Energy or us.

The foregoing numbers are merely estimates—the actual payments could differ materially. For example, it is possible that future transactions or events could increase or decrease the actual tax benefits realized and the corresponding payments. Moreover, payments under the tax receivable agreement will be based on the tax reporting positions that PBF Energy determines in accordance with the tax receivable agreement. Neither PBF Energy nor any of its subsidiaries will be reimbursed for any payments previously made under the tax receivable agreement if the Internal Revenue Service subsequently disallows part or all of the tax benefits that gave rise to such prior payments.

Risks Related to Our Affiliation with PBFX

We depend upon PBFX for a substantial portion of our refineries’ logistics needs and have obligations for minimum volume commitments in our commercial agreements with PBFX.

We depend on PBFX to receive, handle, store and transfer crude oil and petroleum products for us from our operations and sources located throughout the United States and Canada in support of certain of our refineries under long-term, fee-based commercial agreements with us. These commercial agreements have an initial term of approximately seven to ten years and generally include minimum quarterly commitments and inflation escalators. If we fail to meet the minimum commitments during any calendar quarter, we will be required to make a shortfall payment quarterly to PBFX equal to the volume of the shortfall multiplied by the applicable fee.

PBFX’s operations are subject to all of the risks and operational hazards inherent in receiving, handling, storing and transferring crude oil and petroleum products, including: damages to its facilities, related equipment and surrounding properties caused by floods, fires, severe weather, explosions and other natural disasters and acts of terrorism; mechanical or structural failures at PBFX’s facilities or at third-party facilities on which its operations are dependent; curtailments of operations relative to severe seasonal weather; inadvertent damage to our facilities from construction, farm and utility equipment; and other hazards. Any of these events or factors could result in severe damage or destruction to PBFX’s assets or the temporary or permanent shut-down of PBFX’s facilities. If PBFX is unable to serve our logistics needs, our ability to operate our refineries and receive crude oil and distribute products could be adversely impacted, which could adversely affect our business, financial condition and results of operations.

 

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All of the executive officers and a majority of the directors of PBF GP are also current or former officers of PBF Energy. Conflicts of interest could arise as a result of this arrangement.

PBF Energy indirectly owns and controls PBF GP, and appoints all of its officers and directors. All of the executive officers and a majority of the directors of PBF GP are also current or former officers or directors of PBF Energy. These individuals will devote significant time to the business of PBFX. Although the directors and officers of PBF GP have a fiduciary duty to manage PBF GP in a manner that is beneficial to PBF Energy, as directors and officers of PBF GP they also have certain duties to PBFX and its unit holders. Conflicts of interest may arise between PBF Energy and its affiliates, including PBF GP, on the one hand, and PBFX and its unit holders, on the other hand. In resolving these conflicts of interest, PBF GP may favor its own interests and the interests of PBFX over the interests of PBF Energy and its subsidiaries. In certain circumstances, PBF GP may refer any conflicts of interest or potential conflicts of interest between PBFX, on the one hand, and PBF Energy, on the other hand, to its conflicts committee (which must consist entirely of independent directors) for resolution, which conflicts committee must act in the best interests of the public unit holders of PBFX. As a result, PBF GP may manage the business of PBFX in a way that may differ from the best interests of PBF Energy or us.

Risks Relating to Our Indebtedness and the Notes

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 June 30, 2017, we have total long-term debt of $1,654.2 million, excluding deferred debt issuance costs of $27.4 million, and we could incur an additional $780.8 million of senior indebtedness under our existing debt agreements. We may incur additional indebtedness in the future. Our strategy includes executing future refinery and logistics acquisitions. Any significant acquisition would likely require us to incur additional indebtedness in order to finance all or a portion of such acquisition. The level of our indebtedness has several important consequences for our future operations, including that:

 

    a significant portion of our cash flow from operations will be dedicated to the payment of principal of, and interest on, our indebtedness and will not be available for other purposes;

 

    covenants contained in our existing debt arrangements limit our ability to borrow additional funds, dispose of assets and make certain investments;

 

    these covenants also require us to meet or maintain certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our industry, such as being able to take advantage of acquisition opportunities when they arise;

 

    our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited; and

 

    we may be at a competitive disadvantage to those of our competitors that are less leveraged; and we may be more vulnerable to adverse economic and industry conditions.

Our substantial indebtedness increases the risk that we may default on our debt obligations, certain of which contain cross-default and/or cross-acceleration provisions. We have significant principal payments due under our debt instruments. Our and our subsidiaries’ ability to meet their principal obligations will be dependent upon our 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.

 

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Despite our level of indebtedness, we and our subsidiaries may be able to incur substantially more debt, which could exacerbate the risks described above.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future including additional secured debt. Although our debt instruments and financing arrangements contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions, and the indebtedness incurred in compliance with these restrictions could be substantial. To the extent new debt is added to our currently anticipated debt levels, the substantial leverage risks described above would increase. Also, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness.

Restrictive covenants in our debt instruments may limit our ability to undertake certain types of transactions.

Various covenants in our debt instruments and other financing arrangements may restrict our and our subsidiaries’ financial flexibility in a number of ways. Our indebtedness subjects us to significant financial and other restrictive covenants, including restrictions on our ability to incur additional indebtedness, place liens upon assets, pay dividends or make certain other restricted payments and investments, consummate certain asset sales or asset swaps, conduct businesses other than our current businesses, or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of our assets. Some of these debt instruments also require our subsidiaries to satisfy or maintain certain financial condition tests in certain circumstances. Our subsidiaries’ ability to meet these financial condition tests can be affected by events beyond our control and they may not meet such tests.

Provisions in our indentures could discourage an acquisition of us by a third party.

Certain provisions of our indentures could make it more difficult or more expensive for a third party to acquire us. Upon the occurrence of certain transactions constituting a “change in control” as described in the indentures governing the Senior Notes, holders of our Senior Notes could require us to repurchase all outstanding Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest, if any, at the date of repurchase.

Not all of our subsidiaries guarantee the notes and, under certain circumstances, the subsidiary guarantees will be released.

Certain of our subsidiaries do not guarantee the notes. Additionally, under the terms of the indenture governing the notes, under certain circumstances, some or all of the guarantors may cease to guarantee the notes. In the event of a bankruptcy, liquidation or reorganization of any of these non-guarantor subsidiaries, holders of their indebtedness and their trade creditors will generally be entitled to payment of their claims from the assets of those subsidiaries before any assets are made available for distribution to us. As a result, the notes will be structurally subordinated to the debt and other liabilities of our non-guarantor subsidiaries. For the six months ended June 30, 2017, our non-guarantor subsidiaries did not account for any of our net revenue, and, at June 30, 2017, represented approximately $693.0 million, or 10.7%, of our total assets and approximately $234.8 million, or 5.9%, of our total liabilities.

If a subsidiary does not have outstanding indebtedness or guarantee specified indebtedness at any time, the note guarantee of such subsidiary will be released. If all of the subsidiary guarantors are released from their guarantees of these notes, our subsidiaries will have no obligation to pay any amounts due on the notes. In the event of the release of any subsidiary guarantor’s guarantee, PBF Holding’s right, as an equity holder of such subsidiary, to receive any assets of such subsidiary upon its liquidation or reorganization, and therefore the right of the holders of the notes to participate in those assets, will be effectively subordinated to the claims of that subsidiary’s creditors, including trade creditors.

 

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The subsidiary guarantees could be deemed fraudulent conveyances under certain circumstances, and a court may try to subordinate or void the subsidiary guarantees.

Under U.S. bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee can be voided, or claims under a guarantee may be subordinated to all other debts of that guarantor if, among other things, the guarantor, at the time it incurred the indebtedness evidenced by its guarantee:

 

    received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee and was insolvent or rendered insolvent by reason of such incurrence;

 

    was engaged in a business or transaction for which the guarantor’s remaining assets constituted unreasonably small capital; or

 

    intended to incur, or believed that it would incur, debts beyond its ability to pay those debts as they mature.

In addition, any payment by that guarantor under a guarantee could be voided and required to be returned to the guarantor or to a fund for the benefit of the creditors of the guarantor.

The measures of insolvency for purposes of these fraudulent transfer laws will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred. Generally, however, a subsidiary guarantor would be considered insolvent if:

 

    the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all of its assets;

 

    the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability, including contingent liabilities, on its existing debts as they become absolute and mature; or

 

    it could not pay its debts as they became due.

We cannot assure you as to what standard for measuring insolvency a court would apply or that a court would agree with our conclusions.

We may not be able to repurchase the notes upon a change of control triggering event, and a change of control triggering event could result in us facing substantial repayment obligations under our Revolving Loan, the 2023 Notes, the notes and other agreements.

Upon occurrence of a change of control triggering event, the indenture provides that you will have the right to require us to repurchase all or any part of your notes with a cash payment equal to 101% of the aggregate principal amount of notes repurchased, plus accrued and unpaid interest. Additionally, our ability to repurchase the notes upon such a change of control triggering event would be limited by our access to funds at the time of the repurchase and the terms of our other debt agreements. Upon a change of control triggering event, we may be required immediately to repay the outstanding principal, any accrued and unpaid interest on and any other amounts owed by us under our Revolving Loan, the Senior Notes and any other outstanding indebtedness. Other agreements to which we are a party may also require payment upon a change of control affecting us or PBF Energy. The source of funds for these repayments would be our available cash or cash generated from other sources. However, we cannot assure you that we will have sufficient funds available or that we will be permitted by our other debt instruments to fulfill these obligations upon a change of control in the future, in which case the lenders under our Revolving Loan and the lenders under certain other outstanding indebtedness would have the right to foreclose on certain of our assets, which would have a material adverse effect on us. Furthermore, certain change of control events would constitute an event of default under the agreement governing our Revolving Loan and certain other outstanding indebtedness, and we might not be able to obtain a waiver of such defaults.

 

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We have, and are permitted to create further, unrestricted subsidiaries, which will not be subject to any of the covenants in the indenture, and we may not be able to rely on the cash flow or assets of unrestricted subsidiaries to pay our indebtedness.

The indenture permits us to designate certain of our subsidiaries as unrestricted subsidiaries, which subsidiaries would not be subject to the restrictive covenants in the indenture. We have a number of unrestricted subsidiaries and we may designate others in the future, including in connection with any future transactions with PBF Logistics. This means that these entities are or would be able to engage in many of the activities the indenture would otherwise prohibit, such as incurring substantial additional debt (secured or unsecured), making investments, selling, encumbering or disposing of substantial assets, entering into transactions with affiliates and entering into mergers or other business combinations. These actions could be detrimental to our ability to make payments when due and to comply with our other obligations under the terms of our outstanding indebtedness.

In addition, if we designate a restricted subsidiary as an unrestricted subsidiary for purposes of the indenture, any guarantees of the notes by such subsidiary or any of its subsidiaries will be released under the indenture. Accordingly, the creditors of the unrestricted subsidiary and its subsidiaries will have a senior claim on the assets of such unrestricted subsidiary and its subsidiaries. Finally, the initiation of bankruptcy or insolvency proceedings or the entering of a judgment against these entities, or their default under their other credit arrangements will not result in an event of default under the indenture or the revolving credit facility.

Many of the covenants in the indenture will be terminated if the notes are rated investment grade.

Many of the covenants in the indenture governing the notes will be terminated if the notes are rated investment grade, provided at such time no default under the indenture has occurred and is continuing. These covenants include those that restrict, among other things, our ability to pay distributions, incur debt, and to enter into certain other transactions. There can be no assurance that the notes will ever be rated investment grade, or that if they are rated investment grade, that the notes will maintain these ratings. However, termination of these covenants would allow us to engage in certain transactions that would not be permitted while these covenants were in force. See “Description of Notes—Certain Covenants.”

The trading price of the notes may be volatile and can be directly affected by many factors, including our credit rating.

The trading price of the notes could be subject to significant fluctuation in response to, among other factors, changes in our operating results, interest rates, the market for noninvestment grade securities, general economic conditions and securities analysts’ recommendations, if any, regarding our securities. Credit rating agencies continually revise their ratings for companies they follow, including us. Any ratings downgrade could adversely affect the trading price of the notes, or the trading market for the notes, to the extent a trading market for the notes develops. The condition of the financial and credit markets and prevailing interest rates have fluctuated in the past and are likely to fluctuate in the future and any fluctuation may impact the trading price of the notes.

If a bankruptcy petition were filed by or against us, holders of notes may receive a lesser amount for their claim than they would have been entitled to receive under the indenture governing the notes.

If a bankruptcy petition were filed by or against us under the United States Bankruptcy Code, the claim by any holder of the notes for the principal amount of the notes may be limited to an amount equal to the sum of:

 

    the original issue price for the notes; and

 

    that portion of original issue discount (“OID”) that does not constitute “unmatured interest” for purposes of the United States Bankruptcy Code.

Any OID that was not amortized as of the date of the bankruptcy filing may be held to constitute unmatured interest. Accordingly, holders of the notes under these circumstances may receive a lesser amount than they

 

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would be entitled to receive under the terms of the indenture governing the notes, even if sufficient funds are available.

PBF Finance Corporation has limited assets and no operations.

PBF Finance Corporation is a wholly owned subsidiary of PBF Holding that was incorporated for the sole purpose of being a co-issuer or guarantor of certain of our indebtedness. PBF Finance Corporation is capitalized with an amount of cash required to satisfy minimum statutory capitalization requirements. Except with respect to such amount of cash, PBF Finance Corporation does not have any assets, operations or revenues. As a result, you should not expect that the co-issuer will participate in servicing any principal or interest obligations under the notes.

 

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EXCHANGE OFFER

Purpose and Effect of the Exchange Offer

At the closing of the offering of the old notes, we entered into a registration rights agreement with the initial purchasers of the notes pursuant to which we agreed, for the benefit of the holders of the old notes, at our cost, to file an exchange offer registration statement with the SEC with respect to the exchange offer for the new notes, and use commercially reasonable efforts to consummate the exchange offer not later than 365 days after the date of original issuance of the old notes.

Upon the SEC’s declaring the exchange offer registration statement effective, we agreed to offer the new notes in exchange for surrender of the old notes. We agreed to keep the exchange offer open for a period of not less than 20 business days after the date notice thereof is sent to the holders of the old notes.

For each old note surrendered to us pursuant to the exchange offer, the holder of such old note will receive a new note having a principal amount equal to that of the surrendered old note. Interest on each new note will accrue from the last interest payment date on which interest was paid on the surrendered old note or, if no interest has been paid on such old note, from May 30, 2017. The registration rights agreement also provides that we shall use commercially reasonable efforts to keep the registration statement effective and to amend and supplement this prospectus in order to permit this prospectus to be lawfully delivered by all persons subject to the prospectus delivery requirements of the Securities Act for such period of time as such persons must comply with such requirements in order to resell the new notes; provided, however, that (i) in the case where this prospectus and any amendment or supplement thereto must be delivered by a broker-dealer who holds notes that were acquired for its own account as a result of market making activities or other trading activities or an initial purchaser, such period shall be the lesser of 180 days following the consummation of the exchange offer and the date on which all broker-dealers and the initial purchasers have sold all new notes held by them (unless such period is extended), and (ii) upon request we shall make this prospectus and any amendment or supplement thereto available to any broker-dealer for use in connection with any resale of new notes for a period of not less than 90 days after the consummation of the exchange offer.

Based on interpretations by the SEC set forth in no-action letters issued to third parties, we believe that you may resell or otherwise transfer new notes issued in the exchange offer without complying with the registration and prospectus delivery provisions of the Securities Act, if:

 

    you are not our affiliate or an affiliate of any guarantor within the meaning of Rule 405 under the Securities Act;

 

    you do not have an arrangement or understanding with any person to participate in a distribution of the new notes;

 

    you are not engaged in, and do not intend to engage in, a distribution of the new notes; and

 

    you are acquiring the new notes in the ordinary course of your business.

If you are an affiliate of ours or an affiliate of any guarantor, or are engaging in, or intend to engage in, or have any arrangement or understanding with any person to participate in, a distribution of the new notes, or are not acquiring the new notes in the ordinary course of your business:

 

    you cannot rely on the position of the SEC set forth in Morgan Stanley & Co. Incorporated (available June 5, 1991) and Exxon Capital Holdings Corporation (available May 13, 1988), as interpreted in the SEC’s letter to Shearman & Sterling (available July 2, 1993), or similar no-action letters; and

 

    in the absence of an exception from the position stated immediately above, you must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale of the new notes.

 

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This prospectus may be used for an offer to resell, resale or other transfer of new notes only as specifically set forth in this prospectus. With regard to broker-dealers, only broker-dealers that acquired the old notes as a result of market-making activities or other trading activities may participate in the exchange offer.

Each broker-dealer that receives new notes for its own account in exchange for old notes, where such old notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of the new notes. See “Plan of Distribution” for more details regarding the transfer of new notes.

Under the circumstances set forth below, we will use commercially reasonable efforts to cause the SEC to declare effective (unless it becomes effective automatically) a shelf registration statement with respect to the resale of the notes within the time periods specified in the registration rights agreement and keep the statement effective for one year (unless such period is extended) from the effective date of such shelf registration statement or such shorter period that will terminate when all the notes covered by the shelf registration statement have been sold pursuant thereto or are no longer restricted securities as defined in Rule 144 under the Securities Act. These circumstances include:

 

    if any changes in law or applicable interpretations thereof by the SEC do not permit us to effect an exchange offer as contemplated by the registration rights agreement;

 

    if an exchange offer is not consummated within 365 days after the date of original issuance of the old notes;

 

    if any initial purchaser so requests with respect to the old notes not eligible to be exchanged for the new notes and held by it following the consummation of the exchange offer; or

 

    if any holder, other than a broker-dealer, is not eligible to participate in the exchange offer, or if any holder, other than a broker-dealer, that participates in the exchange offer does not receive freely tradeable new notes in exchange for tendered old notes, other than due solely to the status of such holder as an “affiliate” of the Company within the meaning of the Securities Act.

Under the registration rights agreement, subject to certain exceptions, if (i) the exchange offer has not been consummated or a shelf registration statement has not been declared effective by the SEC, in each case, on or prior to the 365th day after the date of original issuance of the old notes, or (ii) if applicable, a shelf registration statement has been declared effective but thereafter ceases to be effective at any time (other than because of the sale of all of the notes registered thereunder), then additional interest will accrue on the principal amount of the old notes at a rate of 0.25% per annum (which rate will be increased by an additional 0.25% per annum for each subsequent 90-day period that such additional interest continues to accrue), up to a maximum of 1.00% per annum of additional interest, beginning on the 366th day after the date of original issuance of the old notes, in the case of clause (i) above, or the day such shelf registration statement ceases to be effective in the case of clause (ii) above, until the exchange offer is completed or the shelf registration statement, if required, becomes effective.

Holders of the old notes will be required to make certain representations to us in order to participate in the exchange offer and will be required to deliver information to be used in connection with the shelf registration statement in order to have their old notes included in the shelf registration statement. See “—Your Representations to Us.”

This summary of certain provisions of the registration rights agreement does not purport to be complete and is subject to, and is qualified in its entirety by reference to, all the provisions of the registration rights agreement, a copy of which is filed as an exhibit to the registration statement which includes this prospectus.

Except as set forth above, after consummation of the exchange offer, holders of old notes which are the subject of the exchange offer have no registration or exchange rights and are not entitled to additional interest under the registration rights agreement. See “—Consequences of Failure to Exchange.”

 

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Terms of the Exchange Offer

Subject to the terms and conditions described in this prospectus and in the letters of transmittal, we will accept for exchange any old notes properly tendered and not withdrawn prior to 12:00 a.m. midnight New York City time on the expiration date. We will issue new notes in principal amount equal to the principal amount of old notes surrendered in the exchange offer. Old notes may be tendered only for new notes and only in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof.

The exchange offer is not conditioned upon any minimum aggregate principal amount of old notes being tendered for exchange.

As of the date of this prospectus, $725,000,000 in aggregate principal amount of the old notes is outstanding. This prospectus and the letters of transmittal are being sent to all registered holders of old notes. There will be no fixed record date for determining registered holders of old notes entitled to participate in the exchange offer.

We intend to conduct the exchange offer in accordance with the provisions of the registration rights agreement, the applicable requirements of the Securities Act and the Exchange Act, and the rules and regulations of the SEC. Old notes that the holders thereof do not tender for exchange in the exchange offer will remain outstanding and continue to accrue interest. These old notes will continue to be entitled to the rights and benefits such holders have under the indenture relating to the notes.

We will be deemed to have accepted for exchange properly tendered old notes when we have given oral or written notice of the acceptance to the exchange agent and complied with the applicable provisions of the registration rights agreement. The exchange agent will act as agent for the tendering holders for the purposes of receiving the new notes from us.

If you tender old notes in the exchange offer, you will not be required to pay brokerage commissions or fees or, subject to the instructions in the letters of transmittal, transfer taxes with respect to the exchange of old notes. We will pay all charges and expenses, other than certain applicable taxes described below, in connection with the exchange offer. It is important that you read the section labeled “—Fees and Expenses” for more details regarding fees and expenses incurred in the exchange offer.

We will return any old notes that we do not accept for exchange for any reason without expense to their tendering holder promptly after the expiration or termination of the exchange offer.

Expiration Date

The exchange offer will expire at 12:00 a.m. midnight, New York City time, on                     , 2017, unless, in our sole discretion, we extend it. If we, in our sole discretion, extend the period of time for which the exchange offer is open, the term “expiration date” will mean the latest time and date to which we shall have extended the expiration of the exchange offer.

Extensions, Delays in Acceptance, Termination or Amendment

We expressly reserve the right, at any time or various times, to extend the period of time during which the exchange offer is open. We may delay acceptance of any old notes by giving oral or written notice of such extension to their holders. During any such extensions, all old notes previously tendered will remain subject to the exchange offer, and we may accept them for exchange.

In order to extend the exchange offer, we will notify the exchange agent orally or in writing of any extension. We will notify the registered holders of old notes of the extension no later than 9:00 a.m., New York City time, on the first business day following the previously scheduled expiration date.

 

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We reserve the right, in our sole discretion:

 

    to delay accepting for exchange any old notes (only in the case that we amend or extend the exchange offer);

 

    to extend the exchange offer or to terminate the exchange offer if any of the conditions set forth below under “—Conditions to the Exchange Offer” have not been satisfied, by giving oral or written notice of such delay, extension or termination to the exchange agent; and

 

    subject to the terms of the registration rights agreement, to amend the terms of the exchange offer in any manner.

Any extension, termination or amendment will be followed promptly by oral or written notice thereof to the registered holders of old notes. If we amend the exchange offer in a manner that we determine to constitute a material change, we will promptly disclose such amendment by means of a prospectus supplement. The supplement will be distributed to the registered holders of the old notes. Depending upon the significance of the amendment and the manner of disclosure to the registered holders, we may extend the exchange offer. In the event of a material change in the exchange offer, including the waiver by us of a material condition, we will extend the exchange offer period if necessary so that at least five business days remain in the exchange offer following notice of the material change.

Conditions to the Exchange Offer

We will not be required to accept for exchange, or exchange any new notes for, any old notes and we may terminate or amend the exchange offer as provided in this prospectus prior to the expiration date if, in our reasonable judgment, (i) the exchange offer, or the making of any exchange by a holder of old notes, would violate applicable law or any applicable interpretation of the staff of the SEC, or (ii) any action or proceeding has been instituted or threatened in writing in any court or by or before any governmental agency with respect to the exchange offer that, in our judgment, would reasonably be expected to impair our ability to proceed with the exchange offer. Similarly, we may terminate the exchange offer as provided in this prospectus before accepting old notes for exchange in the event of such a potential violation.

In addition, we will not be obligated to accept for exchange the old notes of any holder that has not made to us the representations described under “—Purpose and Effect of the Exchange Offer,” “—Procedures for Tendering,” “Your Representations to Us” and “Plan of Distribution” and such other representations as may be reasonably necessary under applicable SEC rules, regulations or interpretations to allow us to use an appropriate form to register the new notes under the Securities Act.

We expressly reserve the right at any time or from time to time to extend the period of time during which the exchange offer is open. Consequently, we may delay acceptance of any old notes by giving written notice of the extension to the holders. We will return any old notes that we do not accept for exchange for any reason without expense to the tendering holder promptly after the expiration or termination of the exchange offer.

We expressly reserve the right to amend or terminate the exchange offer, and to reject for exchange any old notes not previously accepted for exchange, upon the occurrence of any of the conditions to the exchange offer specified above. We will give oral or written notice of any extension, amendment, non-acceptance or termination to the holders of the old notes as promptly as practicable. In the case of any extension, such notice will be issued no later than 9:00 a.m, New York City time, on the next business day after the previously scheduled expiration date.

These conditions are for our sole benefit, and we may assert them or waive them in our sole discretion, in whole or in part, at any time at or before the expiration of the exchange offer. If we fail at any time to exercise any of these rights, this failure will not mean that we have waived our rights. Each such right will be deemed an ongoing right that we may assert at any time or at various times.

 

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In addition, we will not accept for exchange any old notes tendered, and will not issue new notes in exchange for any such old notes, if at such time any stop order has been threatened or is in effect with respect to the registration statement of which this prospectus constitutes a part or the qualification of the indenture relating to the notes under the Trust Indenture Act of 1939.

Procedures for Tendering

In order to participate in the exchange offer, you must properly tender your old notes to the exchange agent as described below. It is your responsibility to properly tender your notes. We have the right to waive any defects. However, we are not required to waive defects and are not required to notify you of defects in your tender. If you are the beneficial holder of old notes that are held through your broker, dealer, commercial bank, trust company or other nominee, and you wish to tender such notes in the exchange offer, you should promptly contact the person or entity through which your old notes are held and instruct that person or entity to tender on your behalf. If you have any questions or need help in exchanging your notes, please call the exchange agent, whose contact information is set forth in “Prospectus Summary—The Exchange Offer—Exchange Agent.”

Procedures for Tendering Notes Represented by Global Notes Held in Book-Entry Form

All of the old notes were issued in book-entry form and are currently represented by global certificates held for the account of DTC. We have confirmed with DTC that the old notes issued in book-entry form and represented by global certificates held for the account of DTC may be tendered using the ATOP procedures. The exchange agent will establish an account with DTC for purposes of the exchange offer promptly after the commencement of the exchange offer, and DTC participants may electronically transmit their acceptance of the exchange offer by causing DTC to transfer their old notes to the exchange agent using the ATOP procedures. In connection with the transfer, DTC will send an “agent’s message” to the exchange agent. The agent’s message will state that DTC has received instructions from the participant to tender old notes and that the participant agrees to be bound by the terms of the letter of transmittal, or in the case of an agent’s message relating to guaranteed delivery, that such participant agrees to be bound by the notice of guaranteed delivery.

By using the ATOP procedures to exchange old notes, you will not be required to deliver a letter of transmittal for holders of global notes to the exchange agent. However, you will be bound by its terms just as if you had signed it.

Guaranteed delivery procedures are set forth below under “Exchange Offer—Guaranteed Delivery Procedures.”

Procedures for Tendering Notes Held in Definitive Form

If you hold your notes in definitive certificated form, you are required to physically deliver your notes to the exchange agent, together with a properly completed and duly executed copy of the letter of transmittal for holders of definitive notes, prior to 12:00 a.m. midnight, New York time, on the expiration date of the exchange offer or follow the guaranteed delivery procedures set forth below under “Exchange Offer—Guaranteed Delivery Procedures.”

Determinations Under the Exchange Offer

We will determine in our sole discretion all questions as to the validity, form, eligibility, time of receipt, acceptance of tendered old notes and withdrawal of tendered old notes. Our determination will be final and binding. We reserve the absolute right to reject any old notes not properly tendered or any old notes our acceptance of which would, in the opinion of our counsel, be unlawful. We also reserve the right to waive any defect, irregularities or conditions of tender as to particular old notes. Our interpretation of the terms and conditions of the exchange offer, including the instructions in the letters of transmittal, will be final and binding

 

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on all parties. Unless waived, all defects or irregularities in connection with tenders of old notes must be cured within such time as we shall determine. Although we intend to notify holders of defects or irregularities with respect to tenders of old notes, neither we, the exchange agent nor any other person will incur any liability for failure to give such notification. Tenders of old notes will not be deemed made until such defects or irregularities have been cured or waived. Any old notes received by the exchange agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned to the tendering holder, unless otherwise provided in the applicable letter of transmittal, promptly following the expiration date.

When We Will Issue New Notes

In all cases, we will issue new notes for old notes that we have accepted for exchange under the exchange offer only after the exchange agent timely receives:

 

    in the case of old notes issued in book-entry form and represented by global certificates held for the account of DTC, (1) a book-entry confirmation of such old notes into the exchange agent’s account at DTC and (2) a properly transmitted agent’s message; or

 

    in the case of old notes held in definitive form, (1) the certificates representing such notes and (2) a properly completed and duly executed letter of transmittal relating to such definitive notes.

Return of Old Notes Not Accepted or Exchanged

If we do not accept any tendered old notes for exchange or if old notes are submitted for a greater principal amount than the holder desires to exchange, the unaccepted or non-exchanged old notes will be returned without expense to their tendering holder. Such non-exchanged old notes will be credited to an account maintained with DTC. These actions will occur promptly after the expiration or termination of the exchange offer.

Your Representations to Us

By agreeing to be bound by the applicable letter of transmittal, you will represent to us that, among other things:

 

    any new notes that you receive will be acquired in the ordinary course of your business;

 

    you have no arrangement or understanding with any person or entity to participate in the distribution of the new notes;

 

    you are not our “affiliate” (as defined in Rule 405 of the Securities Act) or an “affiliate” of any guarantor;

 

    if you are not a broker-dealer, you are not engaged in, and do not intend to engage in, a distribution of new notes; and

 

    if you are a broker-dealer that will receive new notes for your own account in exchange for old notes, you acquired those notes as a result of market-making activities or other trading activities and you will deliver a prospectus in connection with any resale of such new notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. See “Plan of Distribution.”

Guaranteed Delivery Procedures

If you wish to tender your old notes but your old notes are not immediately available or you cannot deliver your old notes, the letter of transmittal or any other required documents to the exchange agent or comply with the procedures under DTC’s ATOP system in the case of old notes, prior to the expiration date, you may still tender if:

 

    the tender is made through an eligible guarantor institution;

 

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    prior to the expiration date, the exchange agent receives from such eligible guarantor institution either a properly completed and duly executed notice of guaranteed delivery, by facsimile transmission, mail, or hand delivery or a properly transmitted agent’s message and notice of guaranteed delivery, that (1) sets forth your name and address, the certificate number(s) of such old notes and the principal amount of old notes tendered; (2) states that the tender is being made thereby; and (3) guarantees that, within three New York Stock Exchange trading days after the expiration date, the letter of transmittal, or facsimile thereof, together with the old notes or a book-entry confirmation, and any other documents required by the letter of transmittal, will be deposited by the eligible guarantor institution with the exchange agent; and

 

    the exchange agent receives the properly completed and executed letter of transmittal or facsimile thereof, as well as certificate(s) representing all tendered old notes in proper form for transfer or a book-entry confirmation of transfer of the old notes into the exchange agent’s account at DTC and documents required by the letter of transmittal within three New York Stock Exchange trading days after the expiration date.

Upon request, the exchange agent will send to you a notice of guaranteed delivery if you wish to tender your old notes according to the guaranteed delivery procedures.

Withdrawal of Tenders

Except as otherwise provided in this prospectus, you may withdraw your tender at any time prior to 12:00 a.m. midnight, New York City time, on the expiration date. For a withdrawal to be effective with respect to notes held in book-entry form and represented by global certificates you must comply with the appropriate procedures of DTC’s ATOP system. Any notice of withdrawal must specify the name and number of the account at DTC to be credited with withdrawn old notes and otherwise comply with the procedures of DTC. To withdraw tenders of notes held in definitive form, you must submit a written or facsimile notice of withdrawal to the exchange agent before 12:00 a.m. midnight, New York City time, on the expiration date of the exchange offer.

We will determine all questions as to the validity, form, eligibility and time of receipt of notice of withdrawal. Our determination shall be final and binding on all parties. We will deem any old notes so withdrawn not to have been validly tendered for exchange for purposes of the exchange offer.

Any old notes in global form that have been tendered for exchange but are not exchanged for any reason will be credited to an account maintained with DTC for the old notes. This crediting will take place as soon as practicable after withdrawal, rejection of tender or termination of the exchange offer. You may retender properly withdrawn old notes by following the procedures described under “—Procedures for Tendering” above at any time prior to 12:00 a.m. midnight, New York City time, on the expiration date.

Fees and Expenses

We may make solicitation by mail, facsimile, telephone, electronic mail or in person by our officers and regular employees and those of our affiliates.

We have not retained any dealer-manager in connection with the exchange offer and will not make any payments to broker-dealers or others soliciting acceptances of the exchange offer. We will, however, pay the exchange agent reasonable and customary fees for its services and reimburse it for its related reasonable out-of-pocket expenses.

We will pay the cash expenses to be incurred in connection with the exchange offer. They include:

 

    all registration and filing fees and expenses;

 

    all fees and expenses of compliance with federal securities and state “blue sky” or securities laws;

 

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    accounting fees, legal fees incurred by us, disbursements and printing, messenger and delivery services, and telephone costs; and

 

    related fees and expenses.

We will pay all transfer taxes, if any, applicable to the exchange of old notes under the exchange offer. The tendering holder, however, will be required to pay any transfer taxes, whether imposed on the registered holder or any other person, if:

 

    new notes or old notes for principal amounts not tendered or accepted for exchange are to be delivered to, or are to be registered or issued in the name of, any person other than the registered holder of the old notes tendered,

 

    tendered old notes are registered in the name of any person other than the person signing the letter of transmittal, or

 

    a transfer tax is imposed for any reason other than the exchange of old notes pursuant to the exchange offer.

If satisfactory evidence of payment of such taxes or exemption therefrom is not submitted with the applicable letter of transmittal, the amount of such transfer taxes will be billed directly to such tendering holder.

Consequences of Failure to Exchange

If you do not exchange new notes for your old notes under the exchange offer, you will remain subject to the existing restrictions on transfer of the old notes. In general, you may not offer or sell the old notes unless the offer or sale is either registered under the Securities Act or exempt from the registration under the Securities Act and applicable state securities laws. No holder who was eligible to exchange such holder’s old notes at the time the exchange offer was pending and consummated and failed to validly tender such old notes for exchange pursuant to the exchange offer shall be entitled to receive any additional interest that would otherwise accrue subsequent to the date the exchange offer is consummated. Except as required by the registration rights agreement, we do not intend to register resales of the old notes under the Securities Act.

Accounting Treatment

We will record the new notes in our accounting records at the same carrying value as the old notes. This carrying value is the aggregate principal amount of the old notes less any bond discount, as reflected in our accounting records on the date of exchange. Accordingly, we will not recognize any gain or loss for accounting purposes in connection with the exchange offer.

Other

Participation in the exchange offer is voluntary, and you should carefully consider whether to accept. You are urged to consult your financial and tax advisors in making your own decision on what action to take.

We may in the future seek to acquire untendered old notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plans to acquire any old notes that are not tendered in the exchange offer or to file a registration statement to permit resales of any untendered old notes.

 

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USE OF PROCEEDS

The exchange offer is intended to satisfy our obligations under the registration rights agreement. We will not receive any proceeds from the issuance of the new notes in the exchange offer. In consideration for issuing the new notes as contemplated by this prospectus, we will receive old notes in a like principal amount. The form and terms of the new notes are substantially identical in all respects to the form and terms of the old notes, except the new notes will be registered under the Securities Act and will not contain restrictions on transfer, registration rights or provisions for additional interest. Old notes surrendered in exchange for the new notes will be retired and cancelled and will not be reissued. Accordingly, the issuance of the new notes will not result in any change in our capitalization.

 

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and total capitalization as of June 30, 2017.

This information should be read in conjunction with the sections entitled “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations of PBF Holding,” and the historical consolidated financial statements and related notes thereto included in this prospectus.

 

     As of June 30, 2017  
     (in thousands)  

Cash and cash equivalents

   $ 114,019  
  

 

 

 

Long-term debt(1)(2):

  

Senior notes due 2023

   $ 500,000  

Senior notes due 2025

     725,000  

Revolving Loan

     350,000  

PBF Rail Term Loan

     31,704  

Catalyst leases

     47,454  
  

 

 

 

Total long-term debt(3)

   $ 1,654,158  
  

 

 

 

Equity:

  

Member’s equity

     2,349,357  

Retained earnings

     167,868  

Accumulated other comprehensive loss

     (25,311
  

 

 

 

Total PBF Holding Company LLC equity

     2,491,914  

Noncontrolling interest

     12,893  
  

 

 

 

Total equity

     2,504,807  
  

 

 

 

Total capitalization

   $ 4,158,965  
  

 

 

 

 

(1) The PBF Rail Term Loan borrower, PBF Rail, is an unrestricted subsidiary and therefore does not guarantee the notes. As of June 30, 2017, the Company did not have any borrowing capacity remaining under the PBF Rail Term Loan.

 

(2) Does not include $442.6 million in outstanding letters of credit issued under the Revolving Loan.

 

(3) Total long-term debt outstanding excludes debt issuance costs.

 

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RATIO OF EARNINGS TO FIXED CHARGES

The following table sets forth information regarding our ratio of earnings to fixed charges for the periods shown. For purposes of determining the ratio of earnings to fixed charges, earnings consist of income from continuing operations before income taxes and fixed charges (excluding interest capitalized during the period). Fixed charges consist of interest expense (including interest capitalized during the period), amortization of debt discount and deferred financing costs and the portion of rental expense that is representative of the interest factor in these rentals.

 

     Six Months
ended
June 30,
2017
    

 

Year Ended December 31,

 
        2016      2015      2014      2013      2012  

Ratio of earnings to fixed charges

     *        2.3x        2.3x        1.1x        2.9x        7.2x  

 

* Earnings for the six months ended June 30, 2017 were inadequate to cover fixed charges by $268.1 million.

 

 

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SELECTED HISTORICAL FINANCIAL DATA

The following table presents the selected historical consolidated financial data of PBF Holding. The selected historical consolidated financial data as of and for the years ended December 31, 2016, 2015 and 2014 have been derived from audited financial statements of PBF Holding, included elsewhere in this prospectus. The selected historical financial data as of and for the years ended December 31, 2013 and 2012 have been derived from the audited financial statements of PBF Holding for those periods, which are not included in this prospectus. As a result of the Chalmette and Torrance acquisitions, the historical consolidated financial results of PBF Holding only include the results of operations for Chalmette and Torrance from November 1, 2015 and July 1, 2016 forward, respectively. The information as of June 30, 2017 and for the six months ended June 30, 2017 and 2016 was derived from the unaudited condensed consolidated financial statements of PBF Holding, included elsewhere in this prospectus, which include all adjustments, consisting of normal recurring adjustments, which management considers necessary for a fair presentation of the financial position and the results of operations for such periods. Results for the interim periods are not necessarily indicative of the results for the full year.

The historical consolidated financial data and other statistical data presented below should be read in conjunction with the consolidated financial statements of PBF Holding and the related notes thereto, included elsewhere in this prospectus, and the sections entitled “Unaudited Pro Forma Condensed Consolidated Financial Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations of PBF Holding.” The consolidated financial information may not be indicative of our future performance.

 

    Year Ended December 31,     Six Months
Ended June 30,
 
    (in thousands)  
    2016     2015     2014     2013     2012     2017     2016  

Revenue

  $ 15,908,537     $ 13,123,929     $ 19,828,155     $ 19,151,455     $ 20,138,687     $ 9,763,449     $ 6,655,958  

Cost and expenses:

             

Cost of sales, excluding depreciation

    13,765,088       11,611,599       18,514,054       17,803,314       18,269,078       8,914,587       5,730,731  

Operating expense, excluding depreciation

    1,390,582       889,368       880,701       812,652       738,824       835,423       568,178  

General and administrative expenses (1)

    149,643       166,904       140,150       95,794       120,443       75,399       71,360  

Equity income in investee (2)

    (5,679     —         —         —         —         (7,419     —    

Loss (gain) on sale of assets

    11,374       (1,004     (895     (183     (2,329     912       3,222  

Depreciation and amortization expense

    209,840       191,110       178,996       111,479       92,238       118,683       103,212  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    15,520,848       12,857,977       19,713,006       18,823,056       19,218,254       9,937,585       6,476,703  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from operations

    387,689       265,952       115,149       328,399       920,433       (174,136     179,255  

Other income (expense)

             

Change in fair value of contingent considerations

    —         —         —         —         (2,768     —         —    

Change in fair value of catalyst lease

    1,422       10,184       3,969       4,691       (3,724     (1,484     (4,633

Debt extinguishment costs

    —         —         —         —         —         (25,451     —    

Interest expense, net

    (129,536     (88,194     (98,001     (94,214     (108,629     (63,513     (64,550
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before income taxes

    259,575       187,942       21,117       238,876       805,312       (264,584     110,072  

Income tax expense (benefit)

    23,689       648       —         —         —         6,332       26,996  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

    235,886       187,294       21,117       238,876       805,312       (270,916     83,076  

Less: net income attributable to noncontrolling interests

    269       274       —         —         —         380       393  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to PBF Holding LLC

  $ 235,617     $ 187,020     $ 21,117     $ 238,876     $ 805,312     $ (271,296   $ 82,683  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance sheet data (at end of period)

             

Total assets

  $ 6,566,897     $ 5,082,722     $ 4,013,762     $ 4,192,504     $ 4,085,264     $ 6,473,759     $ 5,950,599  

Total long-term debt (3)

    1,601,836       1,272,937       750,349       747,576       729,980       1,654,158       1,821,200  

Total equity

    2,588,933       1,821,284       1,630,516       1,772,153       1,751,654       2,504,807       1,836,775  

Selected financial data:

             

Capital expenditures (4)

    1,498,191       979,481       625,403       415,702       222,688       417,697       240,668  

 

(1) Includes acquisition related expenses consisting primarily of consulting and legal expenses related to the Chalmette Acquisition and the Torrance Acquisition of $13.6 million and $5.8 million in 2016 and 2015, respectively. For the six months ended June 30, 2017 and 2016, includes acquisition related expenses consisting primarily of consulting and legal expenses of $0.5 million and $7.1 million, respectively, related to the Chalmette and Torrance Acquisitions and pending and nonconsummated acquisitions.

 

(2) Subsequent to the closing of the TVPC Contribution Agreement between PBFX and PBF LLC on August 31, 2016, the Company accounts for its 50% equity ownership of TVPC as an investment in an equity method investee.

 

(3) Total long-term debt, excluding debt issuance costs and affiliate notes payable, includes current maturities and our Delaware Economic Development Authority Loan.

 

(4) Includes expenditures for acquisitions, construction in progress, property, plant and equipment (including railcar purchases), deferred turnaround costs and other assets, excluding the proceeds from sales of assets.

 

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UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The unaudited pro forma condensed consolidated financial statements are presented to show how the Company might have looked if the Torrance Acquisition, borrowings incurred under our Revolving Loan to fund the Torrance Acquisition, the consummation of the 2025 Senior Notes offering and the redemption of the 2020 Senior Secured Notes as described below had occurred on the date and for the periods indicated below. We derived the following unaudited pro forma condensed consolidated financial statements by applying pro forma adjustments to our historical consolidated financial statements and the historical financial statements of the Torrance refinery and related logistics assets (collectively “Torrance Refining”). The pro forma effects of the Torrance Acquisition are based on the acquisition method of accounting in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 805, Business Combinations.

We derived the following unaudited pro forma condensed consolidated financial statements by applying pro forma adjustments to our historical condensed consolidated financial statements that give effect to the the Torrance Acquisition, borrowings incurred under our Revolving Loan to fund the Torrance Acquisition, the consummation of the 2025 Senior Notes offering and the redemption of the 2020 Senior Secured Notes. The unaudited pro forma consolidated statement of operations for the year ended December 31, 2016 and the six months ended June 30, 2017 combines the historical results of operations of the Company and Torrance Refining, as if the acquisition occurred on January 1, 2016 and gives effect to the borrowing incurred under our Revolving Loan to fund the Torrance Acquisition and the consummation of the 2025 Senior Notes offering and the redemption of the 2020 Senior Secured Notes, as if they occurred on January 1, 2016. As the Torrance Acquisition and the consummation of the 2025 Senior Notes offering and the redemption of the 2020 Senior Secured Notes occurred prior to June 30, 2017 and such transactions are included in the historical balance sheet as of that date, no pro forma balance sheet is necessary.

The unaudited pro forma consolidated statements of operations for the year ended December 31, 2016 and the six months ended June 30, 2017 do not reflect future events that may occur after the completion of the Torrance Acquisition on July 1, 2016, including but not limited to the anticipated realization of cost savings from operating synergies and certain charges expected to be incurred in connection with the transaction, including, but not limited to, costs that may be incurred in connection with integrating the operations of Torrance Refining.

The unaudited pro forma consolidated financial information is presented for informational purposes only. The unaudited pro forma consolidated financial information does not purport to represent what our results of operations or financial condition would have been had the transactions to which the pro forma adjustments relate actually occurred on the dates indicated, and they do not purport to project our results of operations or financial condition for any future period or as of any future date. In addition, they do not purport to indicate the results that would actually have been obtained had the Torrance Acquisition been completed on the assumed date or for the periods presented, or which may be realized in the future.

The pro forma adjustments for the six months ended June 30, 2017 principally give effect to:

 

    the consummation of the offering of the 2025 Senior Notes and redemption of the 2020 Senior Secured Notes; and

The pro forma adjustments for the year ended December 31, 2016 principally give effect to:

 

    the closing of the Torrance Acquisition and the associated impact on our statement of operations including the borrowings incurred under our Revolving Loan to fund the Torrance Acquisition; and

 

    the consummation of the offering of the 2025 Senior Notes and redemption of the 2020 Senior Secured Notes.

The unaudited pro forma consolidated statements of operations should be read in conjunction with the section entitled “Prospectus Summary”, “Selected Historical Financial Data”, “Management’s Discussion and Analysis of Financial Condition and Results of Operations of PBF Holding”, “Description of Notes” and “Use of Proceeds” in this prospectus and our historical consolidated financial statements and related notes thereto, and the historical 2015 audited financial statements and the June 30, 2016 unaudited financial statements of Torrance Refining, each included elsewhere in this prospectus.

 

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Unaudited Pro Forma Condensed Consolidated Statement of Operations

Six months ended June 30, 2017

(in thousands)

 

     Historical     Other
Pro Forma
Adjustments
   

 

     Pro Forma
Condensed
Consolidated
 

Revenues

   $ 9,763,449     $ —          $ 9,763,449  

Cost and expenses:

         

Cost of sales, excluding depreciation

     8,914,587       —            8,914,587  

Operating expenses, excluding depreciation

     835,423       —            835,423  

General and administrative expenses

     75,399       —            75,399  

Equity (income) loss investee

     (7,419          (7,419

Gain on sale of assets

     912       —            912  

Depreciation and amortization expense

     118,683       —            118,683  
  

 

 

   

 

 

      

 

 

 
     9,937,585       —            9,937,585  
  

 

 

   

 

 

      

 

 

 

Loss from operations

     (174,136     —            (174,136

Other income (expense)

         

Change in fair value of catalyst lease

     (1,484     —            (1,484

Debt extingushment costs

     (25,451     —            (25,451

Interest expense, net

     (63,513     2,297       (1)        (61,216
  

 

 

   

 

 

      

 

 

 

Income (loss) before income taxes

     (264,584     2,297          (262,287

Income tax expense

     6,332       —            6,332  
  

 

 

   

 

 

      

 

 

 

Net income (loss)

     (270,916     2,297          (268,619

Less: net income attributable to noncontrolling interests

     380       —            380  
  

 

 

   

 

 

      

 

 

 

Net income (loss) attributable to PBF Holding Company LLC

   $ (271,296   $ 2,297        $ (268,999
  

 

 

   

 

 

      

 

 

 

 

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Table of Contents

Unaudited Pro Forma Condensed Consolidated Statement of Operations

Year Ended December 31, 2016

(in thousands)

 

    Historical     Pro Forma
Effect of
Accounting
Changes
(Note 2)
         Adjusted
Pro Forma
Torrance
Refining
    Pro Forma
Acquisition
Adjustments
(Note 3)
        Other
Pro Forma
Adjustments
          Pro Forma
Condensed
Consolidated
 
    PBF
Holding
    Torrance
Refinery
                                              

Revenues

  $ 15,908,537     $ 1,079,011     $ —          $ 1,079,011     $ —         $ —         $ 16,987,548  

Cost and expenses:

                    

Cost of sales, excluding depreciation

    13,765,088       1,000,845       —            1,000,845       —           —           14,765,933  

Operating expenses, excluding depreciation

    1,390,582       349,460       (18,891   (2)      330,569       —           —           1,721,151  

General and administrative expenses

    149,643       52,778       —            52,778       —           —           202,421  

Equity income in investee

    (5,679            —             —           (5,679

Loss on sale of assets

    11,374       —         —            —         —           —           11,374  

Depreciation and amortization expense

    209,840       34,722       28,384     (2)      63,106       (25,931   (4)     —           247,015  
 

 

 

   

 

 

   

 

 

      

 

 

   

 

 

     

 

 

     

 

 

 
    15,520,848       1,437,805       9,493          1,447,298       (25,931       —           16,942,215  
 

 

 

   

 

 

   

 

 

      

 

 

   

 

 

     

 

 

     

 

 

 

Income (loss) from operations

    387,689       (358,794     (9,493        (368,287     25,931         —           45,333  

Other income (expense)

                    

Change in fair value of catalyst lease

    1,422       —         —            —         —           —           1,422  

Interest expense, net

    (129,536     —         —            —         (5,632   (5)     5,512       (1 )      (129,656
 

 

 

   

 

 

   

 

 

      

 

 

   

 

 

     

 

 

     

 

 

 

Income (loss) before income taxes

    259,575       (358,794     (9,493        (368,287     20,299         5,512         (82,901

Income tax (benefit) expense

    23,689       (143,936     —            (143,936     —           —           (120,247
 

 

 

   

 

 

   

 

 

      

 

 

   

 

 

     

 

 

     

 

 

 

Net income (loss)

    235,886       (214,858     (9,493        (224,351     20,299         5,512         37,346  

Less: net income attributable to noncontrolling interests

    269       —         —            —         —           —           269  
 

 

 

   

 

 

   

 

 

      

 

 

   

 

 

     

 

 

     

 

 

 

Net income (loss) attributable to PBF Holding Company LLC

  $ 235,617     $ (214,858   $ (9,493      $ (224,351   $ 20,299       $ 5,512       $ 37,077  
 

 

 

   

 

 

   

 

 

      

 

 

   

 

 

     

 

 

     

 

 

 

 

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NOTES TO THE UNAUDITED PRO FORMA CONSOLIDATED STATEMENTS OF OPERATIONS

 

1. Represents assumed reduction in interest expense incurred in connection with the offering of the old notes and redemption of the 2020 Senior Secured Notes as if such transactions had occurred at the beginning of the periods presented.

 

2. We performed certain procedures for the purpose of identifying any material differences in significant accounting policies between PBF Holding and Torrance Refining, including any accounting adjustments that would be required in connection with adopting uniform policies. Procedures performed by PBF Holding included a review of the summary of significant accounting policies disclosed in the Torrance Refining audited financial statements and discussions with Torrance Refining management regarding their significant accounting policies in order to identify material adjustments.

Adjustments include the estimated impact of reversing refinery turnaround costs expensed by Torrance Refining from January 1, 2016 through December 31, 2016 in accordance with their historical accounting policy in order to conform to PBF Holding’s accounting policy which is to capitalize refinery turnaround costs incurred in connection with planned major maintenance activities and subsequently amortize such costs on a straight line basis over the period of time estimated to lapse until the next turnaround occurs (generally 3 to 5 years).

The impact of this adjustment for Torrance Refining includes the reversal of the turnaround expense recorded in operating expenses ($18.9 million for the year ended December 31, 2016) and recording the estimated depreciation expense of $28.4 million for 2016, associated with the turnaround costs that have been capitalized on the balance sheet in accordance with our policy.

 

3. Pro forma acquisition adjustments include items that are directly attributable to the Torrance Acquisition assuming the transaction was consummated at the beginning of the fiscal year presented and are expected to have a continuing impact on the Company.

 

4. Represents a decrease when comparing the estimated depreciation and amortization expense resulting from the assumed fair value of property, plant and equipment acquired through the Torrance Acquisition, calculated on a straight line basis and based on a weighted average useful life of 25 years, in comparison to the historical depreciation and amortization expense recorded.

 

5. Represents assumed interest expense incurred in connection with the $550.0 million borrowings under our Revolving Loan, which were used in part to fund the Torrance Acquisition.

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS OF PBF HOLDING

You should read the following discussion and analysis together with “Selected Historical Financial Data” and our consolidated financial statements and related notes included elsewhere in this prospectus. Among other things, those historical financial statements include more detailed information regarding the basis of presentation for the financial data included in the following discussion. This discussion contains forward-looking statements about our business, operations and industry that involve risks and uncertainties, such as statements regarding our plans, estimates, beliefs and expected performance objectives, expectations and intentions. Our actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to these differences include those discussed below and elsewhere in this prospectus particularly in the sections entitled “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.” Unless the context indicates otherwise, the terms “we,” “us,” and “our” refer to PBF Holding and its consolidated subsidiaries.

Executive Summary

We are one of the largest independent petroleum refiners and suppliers of unbranded transportation fuels, heating oil, petrochemical feedstocks, lubricants and other petroleum products in the United States. We sell our products throughout the Northeast, Midwest, Gulf Coast and West Coast of the United States, as well as in other regions of the United States and Canada, and are able to ship products to other international destinations. As of June 30, 2017, we own and operate five domestic oil refineries and related assets, which we acquired in 2010, 2011, 2015 and 2016. As of June 30, 2017, our refineries have a combined processing capacity, known as throughput, of approximately 900,000 barrels per day (“bpd”), and a weighted-average Nelson Complexity Index of 12.2. The Company’s oil refineries are aggregated into one reportable segment.

Our five refineries are located in Delaware City, Delaware, Paulsboro, New Jersey, Toledo, Ohio, New Orleans, Louisiana and Torrance, California. Each of these refineries is briefly described in the table below:

 

Refinery

  

Region

   Nelson
Complexity
   Throughput Capacity
(in barrels per day)
   PADD    Crude Processed (1)    Source (1)

Delaware City

   East Coast    11.3    190,000    1    medium and heavy
sour crude
   water, rail

Paulsboro

   East Coast    13.2    180,000    1    medium and heavy
sour crude
   water, rail

Toledo

   Mid-Continent    9.2    170,000    2    light,

sweet crude

   pipeline,
truck, rail

Chalmette

   Gulf Coast    12.7    189,000    3    light and heavy
crude
   water,
pipeline

Torrance

   West Coast    14.9    155,000    5    heavy and medium
crude
   pipeline,
water, truck

 

(1) Reflects the typical crude and feedstocks and related sources utilized under normal operating conditions and prevailing market environments.

Factors Affecting Comparability

Our results have been affected by the following events, the understanding of which will aid in assessing the comparability of our period to period financial performance and financial condition.

Chalmette Acquisition

On November 1, 2015, we acquired from ExxonMobil, Mobil Pipe Line Company and PDV Chalmette, Inc., 100% of the ownership interests of Chalmette Refining, which owns the Chalmette refinery and related

 

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logistics assets. The Chalmette refinery, located outside of New Orleans, Louisiana, is a dual-train coking refinery and is capable of processing both light and heavy crude oil. Subsequent to the closing of the Chalmette Acquisition, Chalmette Refining is a wholly-owned subsidiary of ours.

Chalmette Refining owns 100% of the MOEM Pipeline, providing access to the Empire Terminal, as well as the CAM Connection Pipeline, providing access to the Louisiana Offshore Oil Port facility through a third party pipeline. Chalmette Refining also owns 80% of each of the Collins Pipeline Company and T&M Terminal Company, both located in Collins, Mississippi, which provide a clean products outlet for the refinery to the Plantation and Colonial Pipelines. Also included in the acquisition are a marine terminal capable of importing waterborne feedstocks and loading or unloading finished products; a clean products truck rack which provides access to local markets; and a crude and product storage facility.

The aggregate purchase price for the Chalmette Acquisition was $322.0 million in cash, plus inventory and working capital of $246.0 million, which was finalized in the first quarter of 2016. The transaction was financed through a combination of cash on hand and borrowings under our Revolving loan.

Torrance Acquisition

On July 1, 2016, we acquired from ExxonMobil and its subsidiary, Mobil Pacific Pipeline Company (together, the “Torrance Sellers”), the Torrance refinery and related logistics assets. The Torrance refinery is strategically positioned in Southern California with advantaged logistics connectivity that offers flexible raw material sourcing and product distribution opportunities primarily in the California, Las Vegas and Phoenix area markets.

In addition to refining assets, the Torrance Acquisition included a number of high-quality logistics assets consisting of a sophisticated network of crude and products pipelines, product distribution terminals and refinery crude and product storage facilities. The most significant of the logistics assets is a 189-mile crude gathering and transportation system which delivers San Joaquin Valley crude oil directly from the field to the refinery. Additionally, included in the transaction were several pipelines which provide access to sources of crude oil including the Ports of Long Beach and Los Angeles, as well as clean product outlets with a direct pipeline supplying jet fuel to the Los Angeles airport. The Torrance refinery also has crude and product storage facilities with approximately 8.6 million barrels of shell capacity.

The purchase price for the assets was approximately $521.4 million in cash after post-closing purchase price adjustments, plus final working capital of $450.6 million. The final purchase price and fair value allocation were completed as of June 30, 2017. During the measurement period, which ended in June 2017, adjustments were made to the Company’s preliminary fair value estimates related primarily to Property, plant and equipment and Other long-term liabilities reflecting the finalization of the Company’s assessment of the costs and duration of certain assumed pre-existing environmental obligations. The transaction was financed through a combination of cash on hand, including proceeds from certain PBF Energy equity offerings, and borrowings under our Revolving Loan.

Senior Notes Offerings

On May 30, 2017, we and PBF Finance issued $725.0 million in aggregate principal amount of 7.25% Senior Notes due 2025 (the “2025 Senior Notes”). We used the net proceeds to fund the cash tender offer (the “Tender Offer”) for any and all of our outstanding 8.25% senior secured notes due 2020 (the “2020 Senior Secured Notes”), to pay the related redemption price and accrued and unpaid interest for any 2020 Senior Secured Notes that remained outstanding after the completion of the Tender Offer, and for general corporate purposes. Upon the satisfaction and discharge of the 2020 Senior Secured Notes in connection with the closing of the Tender Offer and the redemption, the 2023 Senior Notes became unsecured and certain covenants were modified, as provided for in the indenture governing the 2023 Senior Notes and related documents.

 

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Inventory Intermediation Agreements

On May 4, 2017, we and our subsidiaries, DCR and PRC, entered into the A&R Intermediation Agreements with J. Aron, pursuant to which certain terms of the existing inventory intermediation agreements were amended, including, among other things, pricing and an extension of the terms. The A&R Intermediation Agreements were further amended on September 8, 2017. As a result of the amendments (i) the A&R Intermediation Agreement by and among J. Aron, us and PRC relating to the Paulsboro refinery extends to December 31, 2019, which term may be further extended by mutual consent of the parties to December 31, 2020 and (ii) the A&R Intermediation Agreement by and among J. Aron, us and DCR relating to the Delaware City refinery extends the term to July 1, 2019, which term may be further extended by mutual consent of the parties to July 1, 2020.

Crude Oil Acquisition Agreements

We currently purchase all of our crude and feedstock needs independently from a variety of suppliers on the spot market or through term agreements for our Delaware City refinery. We have a contract with Saudi Aramco pursuant to which we have been purchasing up to approximately 100,000 bpd of crude oil from Saudi Aramco that is processed at our Paulsboro refinery. Prior to December 31, 2015, we had a crude oil supply contract with a third-party for our Delaware City refinery. We currently fully source our own crude oil needs for our Toledo refinery. Prior to July 31, 2014, we had a crude oil acquisition agreement with a third party that expired on July 31, 2014. In connection with the Chalmette Acquisition we entered into a contract with PDVSA for the supply of 40,000 to 60,000 bpd of crude oil that can be processed at any of our East or Gulf Coast refineries. In connection with the closing of the Torrance Acquisition, we entered into a crude supply agreement with ExxonMobil for approximately 60,000 bpd of crude oil that can be processed at our Torrance refinery.

Renewable Fuels Standard

We have seen fluctuations in the cost of renewable fuel credits, known as RINs, required for compliance with the RFS. We incurred approximately $347.5 million in RINs costs during the year ended December 31, 2016 as compared to $171.6 million and $115.7 million during the years ended December 31, 2015 and 2014, respectively. We incurred approximately $119.7 million and $157.2 million in RINs costs for the six months ended June 30, 2017 and 2016, respectively. The fluctuations in RINs costs are due primarily to volatility in prices for ethanol-linked RINs and increases in our production of on-road transportation fuels since 2012. Our RINs purchase obligation is dependent on our actual shipment of on-road transportation fuels domestically and the amount of blending achieved.

TVPC Contribution Agreement

On August 31, 2016, PBFX entered into the TVPC Contribution Agreement. Pursuant to the TVPC Contribution Agreement, PBF Holding distributed to PBF LLC and PBFX acquired from PBF LLC 50% of the issued and outstanding limited liability company interests of TVPC, whose assets consist of the 189-mile San Joaquin Valley Pipeline system, including the M55, M1 and M70 Pipeline System, including 11 pipeline stations with storage capability and truck unloading capability at two of the stations (collectively, the “Torrance Valley Pipeline”). The total consideration paid to PBF LLC was $175.0 million, which was funded by PBFX with $20.0 million of cash on hand, $76.2 million in proceeds from the sale of marketable securities, and $78.8 million in net proceeds from the PBFX equity offering completed in August 2016.

PBFX Operating Company LP (“PBFX Op Co”), PBFX’s wholly-owned subsidiary, serves as TVPC’s managing member. PBFX, through its ownership of PBFX Op Co, has the sole ability to direct the activities of TVPC that most significantly impact its economic performance. PBFX, and not PBF Holding, is considered to be the primary beneficiary for accounting purposes, and as a result fully consolidates the net assets and results of operations of TVPC, with the 50% of TVPC it does not own recorded as noncontrolling interests and net income attributable to noncontrolling interests. Accordingly, PBF Holding deconsolidated TVPC and has recognized an equity investment in TVPC for its 50% noncontrolling interest.

 

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PNGPC Contribution Agreement

On February 15, 2017, PBFX entered into a contribution agreement (the “PNGPC Contribution Agreement”) between PBFX and PBF LLC. Pursuant to the PNGPC Contribution Agreement, we contributed to PBF LLC, which, in turn, contributed to PBFX’s wholly owned subsidiary PBFX Operating Company LLC (“PBFX Op Co”) all of the issued and outstanding limited liability company interests of Paulsboro Natural Gas Pipeline Company LLC (“PNGPC”). PNGPC owns and operates an existing interstate natural gas pipeline that runs under the Delaware River and terminates at our Paulsboro refinery. PNGPC has Federal Energy Regulatory Commission (“FERC”) approval for, and is in the process of constructing, a new 24” pipeline (the “New Pipeline”) to replace the existing pipeline, which was placed in service in August 2017. In consideration for the PNGPC limited liability company interests, PBFX delivered to PBF LLC (i) an $11.6 million intercompany promissory note in favor of Paulsboro Refining Company LLC, a wholly owned subsidiary of ours (the “Promissory Note”), (ii) an expansion rights and right of first refusal agreement in favor of PBF LLC with respect to the New Pipeline and (iii) an assignment and assumption agreement with respect to certain outstanding litigation involving PNGPC and the existing pipeline.

Chalmette Storage Tank Lease

On February 15, 2017, we entered into a ten-year storage services agreement (the “Chalmette Storage Agreement”) with PBFX Op Co under which PBFX Op Co will provide storage services to us upon the earlier of November 1, 2017 and the completion of construction of a new tank with a shell capacity of 625,000 barrels at our Chalmette refinery. PBFX Op Co and Chalmette Refining, L.L.C. (“Chalmette Refining”) have entered into a twenty-year lease for the premises upon which the tank will be located (the “Lease”) and a project management agreement pursuant to which Chalmette Refining will manage the construction of the tank. The Chalmette Storage Agreement can be extended by us for two additional five-year periods. Under the Chalmette Storage Agreement, PBFX will provide us with storage services in return for storage fees. The storage services require PBFX to accept, redeliver and store all products tendered by us in the tank and we will pay a monthly fee of $0.60 per barrel of shell capacity. The Lease can be extended by PBFX Op Co for two additional ten year periods.

Agreements with PBFX

PBFX is a fee-based, growth-oriented, publicly traded Delaware master limited partnership formed by our indirect parent company, PBF Energy, to own or lease, operate, develop and acquire crude oil, refined petroleum products and natural gas terminals, pipelines, storage facilities and similar logistics assets. PBFX engages in the receiving, handling, storage and transferring of crude oil, refined products, natural gas and intermediates from sources located throughout the United States and Canada for PBF Energy in support of certain of our refineries, as well as for third party customers.

On May 14, 2014, PBFX completed its initial public offering (the “PBFX Offering”). Beginning with the completion of the PBFX Offering, we have entered into a series of agreements with PBFX, including contribution, commercial and operational agreements. Each of these agreements and their impact to our operations is described in the related party transactions footnote to our consolidated financial statements for the year ended December 31, 2016 (Note 12) and our condensed consolidated financial statements for the six months ended June 30, 2017 (Note 8) contained elsewhere in this prospectus.

 

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A summary of revenue and expense transactions with PBFX is as follows (in millions):

 

     Year Ended December 31,      Six Months Ended
June 30,
 
         2016              2015              2014              2017              2016      

Revenues under affiliate agreements:

              

Services Agreement

   $ 5.1      $ 4.5      $ 2.3      $ 3.3      $ 2.2  

Omnibus Agreement

     4.8        5.3        3.6        3.3        2.3  

Total expenses under affiliate agreements

     175.4        142.1        59.4        114.6        74.5  

Amended and Restated Asset Based Revolving Credit Facility

The Third Amended and Restated Revolving Loan is available to be used for working capital and other general corporate purposes. As noted in “Note 2—Acquisitions”, to our condensed consolidated financial statements for the six months ended June 30, 2017 contained elsewhere in this prospectus, we took down an advance under our Revolving Loan to partially fund the Torrance Acquisition in 2016. The outstanding balance under our Revolving Loan was $350.0 million, $350.0 million and $550.0 million as of June 30, 2017, December 31, 2016 and June 30, 2016, respectively.

Rail Facility Revolving Credit Facility

Effective March 25, 2014, PBF Rail Logistics Company LLC (“PBF Rail”), an indirect wholly-owned subsidiary of ours, entered into a $250.0 million secured revolving credit agreement (the “Rail Facility”). The primary purpose of the Rail Facility was to fund the acquisition by PBF Rail of crude tank cars (the “Eligible Railcars”) before December 2015.

On December 22, 2016, the Rail Facility was terminated and replaced with the PBF Rail Term Loan (as described below).

PBF Rail Term Loan

On December 22, 2016, PBF Rail entered into a $35.0 million term loan (the “PBF Rail Term Loan”) with a bank previously party to the Rail Facility. The PBF Rail Term Loan amortizes monthly over its five year term and bears interest at the one month LIBOR plus the margin as defined in the credit agreement. As security for the PBF Rail Term Loan, PBF Rail pledged, among other things: (i) certain eligible crude tank cars; (ii) the debt service reserve account; and (iii) our membership interest in PBF Rail. Additionally, the PBF Rail Term Loan contains customary terms, events of default and covenants for a transaction of this nature. PBF Rail may at any time repay the PBF Rail Term Loan without penalty in the event that railcars collateralizing the loan are sold, scrapped or otherwise removed from the collateral pool.

The outstanding balance of the PBF Rail Term Loan was $31.7 million and $35.0 million as of June 30, 2017 and December 31, 2016, respectively.

Affiliate notes payable with PBF LLC and PBF Energy

Our long-term debt obligations may include outstanding affiliate notes payable with PBF LLC and PBF Energy. The affiliate notes have an interest rate of 2.5% and a five year term but may be prepaid in whole or in part at any time, at the option of PBF Holding, without penalty or premium. Additional borrowings may be made by PBF Holding under such affiliate notes payable from time to time. In the fourth quarter of 2016, the affiliate notes were extended to 2021. Additionally, in the fourth quarter of 2016, PBF LLC converted outstanding affiliate notes payable from PBF Holding of $379.9 million to a capital contribution. In the first quarter of 2017, PBF LLC converted the full amount of outstanding affiliate notes payable from PBF Holding of $86.3 million to a capital contribution. As of June 30, 2017, PBF Holding had no outstanding affiliate notes payable with PBF Energy and PBF LLC ($86.3 million outstanding as of December 31, 2016).

 

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Factors Affecting Operating Results

Overview

Our earnings and cash flows from operations are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks. The cost to acquire crude oil and other feedstocks and the price of refined petroleum products ultimately sold depends on numerous factors beyond our control, including the supply of, and demand for, crude oil, gasoline, diesel and other refined petroleum products, which, in turn, depend on, among other factors, changes in global and regional economies, weather conditions, global and regional political affairs, production levels, the availability of imports, the marketing of competitive fuels, pipeline capacity, prevailing exchange rates and the extent of government regulation. Our revenue and operating income fluctuate significantly with movements in industry refined petroleum product prices, our materials cost fluctuate significantly with movements in crude oil prices and our other operating expenses fluctuate with movements in the price of energy to meet the power needs of our refineries. In addition, the effect of changes in crude oil prices on our operating results is influenced by how the prices of refined products adjust to reflect such changes.

Crude oil and other feedstock costs and the prices of refined petroleum products have historically been subject to wide fluctuation. Expansion and upgrading of existing facilities and installation of additional refinery distillation or conversion capacity, price volatility, international political and economic developments and other factors beyond our control are likely to continue to play an important role in refining industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction or increase in product margins. Moreover, the industry typically experiences seasonal fluctuations in demand for refined petroleum products, such as for gasoline and diesel, during the summer driving season and for home heating oil during the winter.

Benchmark Refining Margins

In assessing our operating performance, we compare the refining margins (revenue less materials cost) of each of our refineries against a specific benchmark industry refining margin based on crack spreads. Benchmark refining margins take into account both crude and refined petroleum product prices. When these prices are combined in a formula they provide a single value—a gross margin per barrel—that, when multiplied by throughput, provides an approximation of the gross margin generated by refining activities.

The performance of our East Coast refineries generally follows the Dated Brent (NYH) 2-1-1 benchmark refining margin. Our Toledo refinery generally follows the WTI (Chicago) 4-3-1 benchmark refining margin. Our Chalmette refinery generally follows the LLS (Gulf Coast) 2-1-1 benchmark refining margin. Our Torrance refinery generally follows the ANS (West Coast) 4-3-1 benchmark refining margin.

While the benchmark refinery margins presented below under “Results of Operations—Market Indicators” are representative of the results of our refineries, each refinery’s realized gross margin on a per barrel basis will differ from the benchmark due to a variety of factors affecting the performance of the relevant refinery to its corresponding benchmark. These factors include the refinery’s actual type of crude oil throughput, product yield differentials and any other factors not reflected in the benchmark refining margins, such as transportation costs, storage costs, credit fees, fuel consumed during production and any product premiums or discounts, as well as inventory fluctuations, timing of crude oil and other feedstock purchases, a rising or declining crude and product pricing environment and commodity price management 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

 

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presented in our balance sheet. To minimize credit risk, all customers are subject to extensive credit verification procedures and extensions of credit above defined thresholds are to be approved by the senior management. Our intention is to trade only with recognized creditworthy third parties. In addition, receivable balances are monitored on an ongoing basis. We also limit the risk of bad debts by obtaining security such as guarantees or letters of credit.

Other Factors

We currently source our crude oil for the Paulsboro, Delaware City, Toledo, Chalmette and Torrance refineries on a global basis through a combination of market purchases and short-term purchase contracts, and through our crude oil supply agreements with Saudi Aramco, PDVSA and ExxonMobil. We have been purchasing up to approximately 100,000 bpd of crude oil from Saudi Aramco that is processed at Paulsboro. We have a contract with PDVSA for the supply of 40,000 to 60,000 bpd of crude oil that can be processed at any of our East or Gulf Coast refineries. Additionally, we have a supply agreement with ExxonMobil for approximately 60,000 bpd of crude oil that can be processed at our Torrance refinery. We believe purchases based on market pricing has given us flexibility in obtaining crude oil at lower prices and on a more accurate “as needed” basis. Since our Paulsboro and Delaware City refineries access their crude slates from the Delaware River via ship or barge and through our rail facilities at Delaware City, these refineries have the flexibility to purchase crude oils from the Mid-Continent and Western Canada, as well as a number of different countries.

In the past several years, we expanded and upgraded the existing on-site railroad infrastructure at the Delaware City refinery. Currently, crude oil delivered by rail to this facility is consumed at our Delaware City and Paulsboro refineries. The Delaware City rail unloading facility, which was transferred to PBFX in 2014, allows our East Coast refineries to source WTI-based crude oils from Western Canada and the Mid-Continent, which we believe, at times, may provide cost advantages versus traditional Brent-based international crude oils. In support of this rail strategy, we have at times entered into agreements to lease or purchase crude railcars. A portion of these railcars were purchased via the Rail Facility entered into during 2014, which was terminated in connection with the execution of the PBF Rail Term Loan in 2016. Certain of these railcars were subsequently sold to a third party, which has leased the railcars back to us for periods of between four and seven years. In 2016, we sold approximately 120 of these railcars to optimize our railcar portfolio. Our railcar fleet, at times, provides transportation flexibility within our crude oil sourcing strategy that allows our East Coast refineries to process cost advantaged crude from Canada and the Mid-Continent.

Our operating cost structure is also important to our profitability. Major operating costs include costs relating to employees and contract labor, energy, maintenance and environmental compliance, and emission control regulations, including the cost of RINs required for compliance with the Renewable Fuels Standard. The predominant variable cost is energy, in particular, the price of utilities, natural gas, electricity and chemicals.

Our operating results are also affected by the reliability of our refinery operations. Unplanned downtime of our refinery assets generally results in lost margin opportunity and increased maintenance expense. The financial impact of planned downtime, such as major turnaround maintenance, is managed through a planning process that considers such things as the margin environment, the availability of resources to perform the needed maintenance and feed logistics, whereas unplanned downtime does not afford us this opportunity.

During the third quarter of 2017, we determined that we will revise the presentation of certain line items on our historical Consolidated Statements of Operations to enhance our disclosure under the requirements of Rule 5-03 of Regulation S-X. The revised presentation will be comprised of the inclusion of a subtotal within operating costs and expenses referred to as “Cost of sales” and the reclassification of total depreciation and amortization expense between such amounts attributable to cost of sales and other operating costs and expenses. The amount of depreciation and amortization expense that will be presented separately within the “Cost of Sales” subtotal represents depreciation and amortization of refining and logistics assets that are integral to the refinery production process.

 

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This revised presentation, including the effects on Management’s Discussion and Analysis of Financial Condition and Results of Operations, will be presented on a comparative basis beginning with the filing of our Quarterly Report on Form 10-Q for the three and nine-month periods ended September 30, 2017, which is expected to be filed with the SEC in November 2017. Moreover, this revised presentation will not have an effect on our historical consolidated income from operations and net income, or our Consolidated Balance Sheets, Statements of Comprehensive Income, Statements of Cash Flows, and Statements of Changes in Equity. Presented below is a summary of the effects of this revised presentation on our historical Statement of Operations for each of the three years in the periods ended December 31, 2016, 2015, and 2014 and each of the three and six-month periods ended June 30, 2017 and 2016 (in thousands):

 

     Year ended December 31, 2016  
     As Previously
Reported
    Adjustments     As Reclassified  

Cost and expenses:

      

Cost of products and other

   $ 13,765,088     $ —       $ 13,765,088  

Operating expenses

     1,390,582       —         1,390,582  

Depreciation and amortization expense

       204,005       204,005  
      

 

 

 

Cost of sales

         15,359,675  

General and administrative expenses

     149,643       —         149,643  

Equity income in investee

     (5,679     —         (5,679

Loss (gain) on sale of assets

     11,374       —         11,374  

Depreciation and amortization expense

     209,840       (204,005     5,835  
  

 

 

     

 

 

 

Total cost and expenses

   $ 15,520,848       $ 15,520,848  

 

     Year ended December 31, 2015  
     As Previously
Reported
    Adjustments     As Reclassified  

Cost and expenses:

      

Cost of products and other

   $ 11,611,599     $ —       $ 11,611,599  

Operating expenses

     889,368       —         889,368  

Depreciation and amortization expense

       181,422       181,422  
      

 

 

 

Cost of sales

         12,682,389  

General and administrative expenses

     166,904       —         166,904  

Equity income in investee

     —         —         —    

Loss (gain) on sale of assets

     (1,004     —         (1,004

Depreciation and amortization expense

     191,110       (181,422     9,688  
  

 

 

     

 

 

 

Total cost and expenses

   $ 12,857,977       $ 12,857,977  

 

     Year ended December 31, 2014  
     As Previously
Reported
    Adjustments     As Reclassified  

Cost and expenses:

      

Cost of products and other

   $ 18,514,054     $ —       $ 18,514,054  

Operating expenses

     880,701       —         880,701  

Depreciation and amortization expense

       165,413       165,413  
      

 

 

 

Cost of sales

         19,560,168  

General and administrative expenses

     140,150       —         140,150  

Equity income in investee

     —         —         —    

Loss (gain) on sale of assets

     (895     —         (895

Depreciation and amortization expense

     178,996       (165,413     13,583  
  

 

 

     

 

 

 

Total cost and expenses

   $ 19,713,006       $ 19,713,006  

 

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     Three Months ended June 30, 2017  
     As Previously
Reported
    Adjustments     As Reclassified  

Cost and expenses:

      

Cost of products and other

   $ 4,662,833     $ —       $ 4,662,833  

Operating expenses

     398,570       —         398,570  

Depreciation and amortization expense

       56,973       56,973  
      

 

 

 

Cost of sales

         5,118,376  

General and administrative expenses

     34,920       —         34,920  

Equity income in investee

     (3,820     —         (3,820

Loss (gain) on sale of assets

     29       —         29  

Depreciation and amortization expense

     62,993       (56,973     6,020  
  

 

 

     

 

 

 

Total cost and expenses

   $ 5,155,525       $ 5,155,525  

 

     Three Months ended June 30, 2016  
     As Previously
Reported
     Adjustments     As Reclassified  

Cost and expenses:

       

Cost of products and other

   $ 3,284,748      $ —       $ 3,284,748  

Operating expenses

     271,539        —         271,539  

Depreciation and amortization expense

        47,541       47,541  
       

 

 

 

Cost of sales

          3,603,828  

General and administrative expenses

     38,091        —         38,091  

Equity income in investee

     —          —         —    

Loss (gain) on sale of assets

     3,222        —         3,222  

Depreciation and amortization expense

     48,919        (47,541     1,378  
  

 

 

      

 

 

 

Total cost and expenses

   $ 3,646,519        $ 3,646,519  

 

     Six Months ended June 30, 2017  
     As Previously
Reported
    Adjustments     As Reclassified  

Cost and expenses:

      

Cost of products and other

   $ 8,914,587     $ —       $ 8,914,587  

Operating expenses

     835,423       —         835,423  

Depreciation and amortization expense

       110,900       110,900  
      

 

 

 

Cost of sales

         9,860,910  

General and administrative expenses

     75,399       —         75,399  

Equity income in investee

     (7,419     —         (7,419

Loss (gain) on sale of assets

     912       —         912  

Depreciation and amortization expense

     118,683       (110,900     7,783  
  

 

 

     

 

 

 

Total cost and expenses

   $ 9,937,585       $ 9,937,585  

 

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     Six Months ended June 30, 2016  
     As Previously
Reported
     Adjustments     As Reclassified  

Cost and expenses:

       

Cost of products and other

   $ 5,730,731      $ —       $ 5,730,731  

Operating expenses

     568,178        —         568,178  

Depreciation and amortization expense

        100,137       100,137  
       

 

 

 

Cost of sales

          6,399,046  

General and administrative expenses

     71,360        —         71,360  

Equity income in investee

     —          —         —    

Loss (gain) on sale of assets

     3,222        —         3,222  

Depreciation and amortization expense

     103,212        (100,137     3,075  
  

 

 

      

 

 

 

Total cost and expenses

   $ 6,476,703        $ 6,476,703  

Refinery-Specific Information

The following section includes refinery-specific information related to our operations, crude oil differentials, ancillary costs, and local premiums and discounts.

Delaware City Refinery. The benchmark refining margin for the Delaware City refinery is calculated by assuming that two barrels of Dated Brent crude oil are converted into one barrel of gasoline and one barrel of diesel. We calculate this benchmark using the NYH market value of reformulated blendstock for oxygenate blending (“RBOB”) and ULSD against the market value of Dated Brent and refer to the benchmark as the Dated Brent (NYH) 2-1-1 benchmark refining margin. Our Delaware City refinery has a product slate of approximately 53% gasoline, 30% distillate (consisting of jet fuel, ULSD and ultra-low sulfur heating oil), 1% high-value petrochemicals, with the remaining portion of the product slate comprised of lower-value products (6% black oil, 4% petroleum coke, 3% LPGs and 3% other). For this reason, we believe the Dated Brent (NYH) 2-1-1 is an appropriate benchmark industry refining margin. The majority of Delaware City revenues are generated off NYH-based market prices.

The Delaware City refinery’s realized gross margin on a per barrel basis has historically differed from the Dated Brent (NYH) 2-1-1 benchmark refining margin due to the following factors:

 

  the Delaware City refinery processes a slate of primarily medium and heavy sour crude oils, which has constituted approximately 65% to 70% of total throughput. The remaining throughput consists of sweet crude oil and other feedstocks and blendstocks. In addition, we have the capability to process a significant volume of light, sweet crude oil depending on market conditions. Our total throughput costs have historically priced at a discount to Dated Brent; and

 

  as a result of the heavy, sour crude slate processed at Delaware City, we produce lower value products including sulfur, carbon dioxide and petroleum coke. These products are priced at a significant discount to gasoline, ULSD and heating oil and represent approximately 5% to 7% of our total production volume.

Paulsboro Refinery. The benchmark refining margin for the Paulsboro refinery is calculated by assuming that two barrels of Dated Brent crude oil are converted into one barrel of gasoline and one barrel of diesel. We calculate this benchmark using the NYH market value of RBOB and ULSD diesel against the market value of Dated Brent and refer to the benchmark as the Dated Brent (NYH) 2-1-1 benchmark refining margin. Our Paulsboro refinery has a product slate of approximately 38% gasoline, 32% distillate (comprised of jet fuel, ULSD and ultra-low sulfur heating oil), 5% high-value Group I lubricants and 10% asphalt, with the remaining portion of the product slate comprised of lower-value products (6% black oil, 4% petroleum coke, 4% LPGs and 1% other). For this reason, we believe the Dated Brent (NYH) 2-1-1 is an appropriate benchmark industry refining margin. The majority of Paulsboro revenues are generated off NYH-based market prices.

 

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The Paulsboro refinery’s realized gross margin on a per barrel basis has historically differed from the Dated Brent (NYH) 2-1-1 benchmark refining margin due to the following factors:

 

  the Paulsboro refinery has generally processed a slate of primarily medium and heavy sour crude oils, which has historically constituted approximately 70% to 80% of total throughput. The remaining throughput consists of sweet crude oil and other feedstocks and blendstocks;

 

  as a result of the heavy, sour crude slate processed at Paulsboro, we produce lower value products including sulfur and petroleum coke. These products are priced at a significant discount to gasoline and heating oil and represent approximately 3% to 5% of our total production volume; and

 

  the Paulsboro refinery produces Group I lubricants which carry a premium sales price to gasoline and distillates.

Toledo Refinery. The benchmark refining margin for the Toledo refinery is calculated by assuming that four barrels of WTI crude oil are converted into three barrels of gasoline, one-half barrel of ULSD and one-half barrel of jet fuel. We calculate this refining margin using the Chicago market values of conventional blendstock for oxygenate blending (“CBOB”) and ULSD and the United States Gulf Coast value of jet fuel against the market value of WTI crude oil and refer to this benchmark as the WTI (Chicago) 4-3-1 benchmark refining margin. Our Toledo refinery has a product slate of approximately 54% gasoline, 35% distillate (comprised of jet fuel and ULSD), 5% high-value petrochemicals (including nonene, tetramer, benzene, xylene and toluene) with the remaining portion of the product slate comprised of lower-value products (5% LPGs and 1% other). For this reason, we believe the WTI (Chicago) 4-3-1 is an appropriate benchmark industry refining margin. The majority of Toledo revenues are generated off Chicago-based market prices.

The Toledo refinery’s realized gross margin on a per barrel basis has historically differed from the WTI (Chicago) 4-3-1 benchmark refining margin due to the following factors:

 

  the Toledo refinery processes a slate of domestic sweet and Canadian synthetic crude oil. Historically, Toledo’s blended average crude costs have been higher than the market value of WTI crude oil;

 

  the Toledo refinery configuration enables it to produce more barrels of product than throughput which generates a pricing benefit; and

 

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

Chalmette Refinery. The benchmark refining margin for the Chalmette refinery is calculated by assuming two barrels of Light Louisiana Sweet (“LLS”) crude oil are converted into one barrel of gasoline and one barrel of diesel. We calculate this benchmark using the US Gulf Coast market value of 87 conventional gasoline and ULSD against the market value of LLS and refer to this benchmark as the LLS (Gulf Coast) 2-1-1 benchmark refining margin. Our Chalmette refinery has a product slate of approximately 48% gasoline, 31% distillate (comprised of ULSD, heating oil, and light cycle oil), 5% high-value petrochemicals (including benzene and xylenes) with the remaining portion of the product slate comprised of lower-value products (10% black oil, 5% petroleum coke and 1% other). For this reason, we believe the LLS (Gulf Coast) 2-1-1 is an appropriate benchmark industry refining margin. The majority of Chalmette revenues are generated off Gulf Coast-based market prices.

The Chalmette refinery’s realized gross margin on a per barrel basis has historically differed from the LLS (USGC) 2-1-1 benchmark refining margin due to the following factors:

 

  The Chalmette refinery has generally processed a slate of primarily medium and heavy sour crude oils, which has historically constituted approximately 60% to 70% of total throughput. The remaining throughput consists of sweet crude oil and other feedstocks and blendstocks; and

 

  as a result of the heavy, sour crude slate processed at Chalmette, we produce lower-value products including sulfur and petroleum coke. These products are priced at a significant discount to gasoline and heating oil and represent approximately 4% to 6% of our total production volume.

 

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A project underway to restart an idled naphtha hydrotreater, reformer and light-ends recovery unit will increase high-octane, ultra-low sulfur reformate and chemicals production. A new crude oil tank being constructed will allow gasoline and diesel export opportunities and reduce RINs compliance costs. Both projects are expected to be completed in the third quarter of 2017.

Torrance Refinery. The benchmark refining margin for the Torrance refinery is calculated by assuming that four barrels of Alaskan North Slope (“ANS”) crude oil are converted into three barrels of gasoline, one-half barrel of diesel and one-half barrel of jet fuel. We calculate this benchmark using the West Coast Los Angeles market value of California reformulated blendstock for oxygenate blending (CARBOB), California Air Resources Board (CARB) diesel and jet fuel and refer to the benchmark as the ANS (WCLA) 4-3-1 benchmark refining margin. Our Torrance Refinery has a product slate of approximately 62% gasoline and 25% distillate (comprised of jet fuel, ULSD and marine diesel) with the remaining portion of the product slate comprised of lower-value products (8% petroleum coke, 2% LPG, 2% black oil and 1% other). For this reason, we believe the ANS (West Coast) 4-3-1 is an appropriate benchmark industry refining margin. The majority of Torrance revenues are generated off West Coast Los Angeles-based market prices.

The Torrance refinery’s realized gross margin on a per barrel basis has historically differed from the ANS (WCLA) 4-3-1 benchmark refining margin due to the following factors:

 

  The Torrance refinery has generally processed a slate of primarily heavy sour crude oils, which has historically constituted approximately 80% to 90% of total throughput. The Torrance crude slate has the lowest API gravity (typically an American Petroleum Institute (“API”) gravity of less than 20 degrees) of all of our refineries. The remaining throughput consists of other feedstocks and blendstocks; and

 

  as a result of the heavy, sour crude slate processed at Torrance, we produce lower-value products including petroleum coke and sulfur. These products are priced at a significant discount to gasoline and diesel and represent approximately 9% to 11% of our total production volume.

 

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Result of Operations

The following tables reflect our consolidated financial and operating highlights for the years ended December 2016, 2015, 2014 and for the six months ended June 30, 2017 and 2016.

 

    Year Ended December 31,     Six Months Ended June 30,
(unaudited)
 
    (in thousands)  
    2016     2015     2014     2017     2016  

Revenue

  $ 15,908,537     $ 13,123,929     $ 19,828,155     $ 9,763,449     $ 6,655,958  

Cost and expenses:

         

Cost of sales, excluding depreciation

    13,765,088       11,611,599       18,514,054       8,914,587       5,730,731  

Operating expense, excluding depreciation

    1,390,582       889,368       880,701       835,423       568,178  

General and administrative
expenses

    149,643       166,904       140,150       75,399       71,360  

Equity income in investee

    (5,679     —         —         (7,419     —    

Loss (gain) on sale of assets

    11,374       (1,004     (895     912       3,222  

Depreciation and amortization expense

    209,840       191,110       178,996       118,683       103,212  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    15,520,848       12,857,977       19,713,006       9,937,585       6,476,703  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from operations

    387,689       265,952       115,149       (174,136     179,255  

Other income (expense)

         

Change in fair value of catalyst lease

    1,422       10,184       3,969       (1,484     (4,633

Debt extinguishment costs

    —         —         —         (25,451     —    

Interest expense, net

    (129,536     (88,194     (98,001     (63,513     (64,550
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before income taxes

    259,575       187,942       21,117       (264,584     110,072  

Income tax expense (benefit)

    23,689       648       —         6,332       26,996  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

    235,886       187,294       21,117       (270,916     83,076  

Less: net income attributable to noncontrolling interests

    269       274       —         380       393  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to PBF Holding LLC

  $ 235,617     $ 187,020     $ 21,117     $ (271,296   $ 82,683  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Gross margin

  $ 548,862     $ 441,539     $ 267,987     $ (97,461   $ 256,913  

Gross refining margin (1)

    2,143,449       1,512,330       1,314,101       848,862       925,227  

 

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Operating Highlights

 

     Year Ended December 31,     Six Months Ended June 30,  
     2016     2015     2014         2017             2016      

Key Operating Information

          

Production (bpd in thousands)

     734.3       511.9       452.1       748.8       678.0  

Crude oil and feedstocks throughput (bpd in thousands)

     727.7       516.4       453.1       753.7       674.0  

Total crude oil and feedstocks throughput (millions of barrels)

     266.4       188.4       165.4       136.4       122.7  

Gross margin per barrel of throughput

   $ 2.06     $ 2.34     $ 1.60     $ (0.71   $ 2.09  

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

   $ 6.09     $ 10.29     $ 12.11     $ 7.45     $ 5.77  

Refinery operating expense, excluding depreciation, per barrel of throughput

   $ 5.22     $ 4.72     $ 5.34     $ 6.12     $ 4.63  

Crude and feedstocks (% of total throughput) (2)

          

Heavy Crude

     26     14     14     35     16

Medium Crude

     37     49     44     30     47

Light Crude

     25     26     33     20     25

Other feedstocks and blends

     12     11     9     15     12
  

 

 

   

 

 

 

Total throughput

     100     100     100     100     100

Yield (% of total throughput)

          

Gasoline and gasoline blendstocks

     50     49     47     51     48

Distillates and distillate blendstocks

     31     35     36     30     31

Lubes

     1     1     2     1     1

Chemicals

     3     3     3     2     4

Other

     15     12     12     16     16
  

 

 

   

 

 

 

Total yield

     100     100     100     100     100

 

(1) See Non-GAAP Financial measures below.
(2) We define heavy crude oil as crude oil with American Petroleum Institute (API) gravity less than 24 degrees. We define medium crude oil as crude oil with API gravity between 24 and 35 degrees. We define light crude oil as crude oil with API gravity higher than 35 degrees.

 

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

 

     Year Ended December 31,     Six Months Ended
June 30,
 
     2016     2015     2014     2017     2016  
     (dollars per barrel, except as noted)  

Dated Brent Crude

   $ 43.91     $ 52.56     $ 98.95     $ 51.61     $ 40.08  

West Texas Intermediate (WTI) crude oil

   $ 43.34     $ 48.71     $ 93.28     $ 49.89     $ 39.64  

Light Louisiana Sweet (LLS) crude oil

   $ 45.03     $ 52.36     $ 96.92     $ 51.77     $ 41.51  

Alaska North Slope (ANS) crude oil

   $ 43.67     $ 52.44     $ 97.52     $ 52.20     $ 40.00  

Crack Spreads

          

Dated Brent (NYH) 2-1-1

   $ 13.49     $ 16.35     $ 12.92     $ 13.21     $ 13.30  

WTI (Chicago) 4-3-1

   $ 12.38     $ 17.91     $ 15.92     $ 12.65     $ 12.77  

LLS (Gulf Coast) 2-1-1

   $ 10.75     $ 14.39     $ 16.95     $ 12.30     $ 9.76  

ANS (West Coast) 4-3-1

   $ 16.46     $ 26.46     $ 15.59     $ 17.85     $ 18.04  

Crude Oil Differentials

          

Dated Brent (foreign) less WTI

   $ 0.56     $ 3.85     $ 5.66     $ 1.73     $ 0.44  

Dated Brent less Maya (heavy, sour)

   $ 7.36     $ 8.45     $ 13.08     $ 7.34     $ 7.94  

Dated Brent less WTS (sour)

   $ 1.42     $ 3.59     $ 11.62     $ 2.98     $ 0.95  

Dated Brent less ASCI (sour)

   $ 3.92     $ 4.57     $ 6.49     $ 3.46     $ 3.96  

WTI less WCS (heavy, sour)

   $ 12.57     $ 11.87     $ 19.45     $ 11.23     $ 11.55  

WTI less Bakken (light, sweet)

   $ 1.32     $ 2.89     $ 5.47     $ 0.61     $ 0.98  

WTI less Syncrude (light, sweet)

   $ (2.01   $ (1.45   $ 2.25     $ (1.81   $ (3.56

WTI less LLS (light, sweet)

   $ (1.69   $ (3.66   $ (3.64   $ (1.88   $ (1.87

WTI less ANS (light, sweet)

   $ (0.33   $ (3.73   $ (4.24   $ (2.31   $ (0.37

Natural gas (dollars per MMBTU)

   $ 2.55     $ 2.63     $ 4.26     $ 3.10     $ 2.11  

Six Months Ended June 30, 2017 Compared to the Six Months Ended June 30, 2016

Overview—Net loss was $270.9 million for the six months ended June 30, 2017 compared to net income of $83.1 million for the six months ended June 30, 2016.

Our results for the six months ended June 30, 2017 were negatively impacted by special items consisting of a non-cash LCM inventory adjustment of approximately $167.1 million and debt extinguishment costs related to the early retirement of our 2020 Senior Secured Notes of $25.5 million. Our results for the six months ended June 30, 2016 were positively impacted by an LCM inventory adjustment of approximately $216.8 million. These LCM inventory adjustments were recorded due to movements in the price of crude oil and refined products in the periods presented. Excluding the impact of these special items, our results were positively impacted by generally favorable movements in crude oil differentials, higher crack spreads for our Gulf Coast refinery and lower costs to comply with the RFS. These positive impacts were partially offset by lower throughput per day at our Delaware City and Toledo refineries as discussed below and the planned turnaround at our Torrance refinery.

Revenues—Revenues totaled $9.8 billion for the six months ended June 30, 2017 compared to $6.7 billion for the six months ended June 30, 2016, an increase of approximately $3.1 billion, or 46.7%. Revenues per barrel were $61.57 and $54.25 for the six months ended June 30, 2017 and 2016, respectively, an increase of 13.5% directly related to higher hydrocarbon commodity prices. For the six months ended June 30, 2017, the total throughput rates at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 323,200 bpd, 139,300 bpd, 173,600 bpd, and 117,600 bpd, respectively. For the six months ended June 30, 2016, the total throughput rates at our East Coast, Mid-Continent and Gulf Coast refineries averaged approximately 333,900 bpd, 165,900 bpd and 174,200 bpd, respectively. The decrease in throughput rates at our East Coast refineries in 2017 compared to 2016 is primarily due to planned downtime at our Delaware City refinery in 2017. The decrease in throughput rates at our Mid-Continent and Gulf Coast refineries in the first six months of 2017 was mainly due to unplanned downtime and less favorable market conditions at our Toledo refinery and planned

 

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downtime at our Chalmette refinery during the first quarter of 2017. Our West Coast refinery was not acquired until the third quarter of 2016. For the six months ended June 30, 2017, the total barrels sold at our East Coast, Mid-Continent, Gulf Coast and West Coast refineries averaged approximately 357,100 bpd, 157,200 bpd, 215,800 bpd and 146,000 bpd, respectively. For the six months ended June 30, 2016, the total barrels sold at our East Coast, Mid-Continent and Gulf Coast refineries averaged approximately 376,200 bpd, 174,900 bpd and 208,800 bpd, respectively. Total refined product barrels sold were higher than throughput rates, reflecting sales from inventory as well as sales and purchases of refined products outside the refinery.

Gross Margin—Gross margin, including refinery operating expenses and depreciation, totaled a loss of $97.5 million, or a loss of $0.71 per barrel of throughput, for the six months ended June 30, 2017 compared to $256.9 million, or $2.09 per barrel of throughput, for the six months ended June 30, 2016, a decrease of $354.4 million. Gross refining margin (as described below in Non-GAAP Financial Measures) totaled $848.9 million, or $6.22 per barrel of throughput ($1,016.0 million or $7.45 per barrel of throughput excluding the impact of special items), for the six months ended June 30, 2017 compared to $925.2 million, or $7.54 per barrel of throughput ($708.4 million or $5.77 per barrel of throughput excluding the impact of special items) for the six months ended June 30, 2016, a decrease of approximately $76.4 million or an increase of $307.6 million excluding special items.

Excluding the impact of special items, gross margin and gross refining margin increased due to favorable movements in certain crude differentials, improved crack spreads in the Gulf Coast, reduced costs to comply with the RFS and positive margin contributions from our Torrance refinery acquired in the third quarter of 2016. Costs to comply with our obligation under the RFS totaled $104.9 million for the six months ended June 30, 2017 (excluding our West Coast refinery, whose costs to comply with RFS totaled $14.8 million for the six months ended June 30, 2017) compared to $157.2 million for the six months ended June 30, 2016. In addition, gross margin and gross refining margin were negatively impacted by a non-cash LCM inventory adjustment of approximately $167.1 million on a net basis resulting from a decrease in crude oil and refined product prices in comparison to the prices at year end. The non-cash LCM inventory adjustment increased gross margin and gross refining margin by approximately $216.8 million for the six months ended June 30, 2016.

Average industry refining margins in the Mid-Continent were weaker during the six months ended June 30, 2017 as compared to the same period in 2016. The WTI (Chicago) 4-3-1 industry crack spread was $12.65 per barrel, or 0.9% lower, in the six months ended June 30, 2017 as compared to $12.77 per barrel in the same period in 2016. Our margins were unfavorably impacted by our refinery specific crude slate in the Mid-Continent which was impacted by a declining WTI/Bakken differential partially offset by an improving WTI/Syncrude differential, which averaged a premium of $1.81 per barrel during the six months ended June 30, 2017 as compared to a premium of $3.56 per barrel in the same period of 2016.

On the East Coast, the Dated Brent (NYH) 2-1-1 industry crack spread was approximately $13.21 per barrel, or 0.7% lower in the six months ended June 30, 2017 as compared to $13.30 per barrel in the same period in 2016. The Dated Brent/Maya differentials were $0.60 lower in the six months ended June 30, 2017 as compared to the same period in 2016. The Dated Brent/WTI differentials were $1.29 higher in the six months ended June 30, 2017 as compared to the same period in 2016, partially offset by a narrowing WTI/Bakken differential, which was approximately $0.37 per barrel less favorable in the six months ended June 30, 2017 as compared to the same period in 2016.

Gulf Coast industry refining margins generally improved during the six months ended June 30, 2017 as compared to the same period in 2016. The LLS (Gulf Coast) 2-1-1 industry crack spread was $12.30 per barrel, or 26.0% higher, in the six months ended June 30, 2017 as compared to $9.76 per barrel in the same period in 2016. Crude differentials slightly decreased with the WTI/LLS averaging a premium of $1.88 per barrel during the six months ended June 30, 2017 as compared to a premium of $1.87 per barrel in the same period of 2016.

 

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Favorable movements in these benchmark crude differentials typically result in lower crude costs and positively impact our earnings while reductions in these benchmark crude differentials typically result in higher crude costs and negatively impact our earnings.

Operating Expenses—Operating expenses totaled $835.4 million, or $6.12 per barrel of throughput, for the six months ended June 30, 2017 compared to $568.2 million, or $4.63 per barrel of throughput, for the six months ended June 30, 2016, an increase of $267.2 million, or 47.0%. The increase in operating expenses was mainly attributable to costs associated with the Torrance refinery and related logistics assets which totaled approximately $242.5 million for the six months ended June 30, 2017. Total operating expenses for the six months ended June 30, 2017, excluding our Torrance refinery, increased slightly due to higher maintenance costs at our Chalmette refinery and slightly higher energy costs across all of our refineries attributable to strengthening natural gas prices. The increase in operating expenses was partially offset by a decrease in outside services costs.

General and Administrative Expenses—General and administrative expenses totaled $75.4 million for the six months ended June 30, 2017 compared to $71.4 million for the six months ended June 30, 2016, an increase of approximately $4.0 million or 5.7%. The increase in general and administrative expenses for the six months ended June 30, 2017 over the same period of 2016 primarily relates to increased employee related expenses of $6.8 million mainly due to increased headcount resulting from the Torrance Acquisition, an increase of $0.1 million in stock option expense and an increase of $2.0 million in information technology costs. These increases were partially offset by lower outside services costs in support of acquisitions and related integration activities of $5.9 million, reflecting less activity in 2017. Our general and administrative expenses are comprised of the personnel, facilities and other infrastructure costs necessary to support our refineries.

Loss on Sale of Assets—There was a loss of $0.9 million on sale of assets for the six months ended June 30, 2017 relating to non-operating refinery assets as compared to a loss of $3.2 million on the sale of assets for the six months ended June 30, 2016 relating to the sale of non-operating refinery assets in the second quarter of 2016.

Depreciation and Amortization Expense—Depreciation and amortization expense totaled $118.7 million for the six months ended June 30, 2017 compared to $103.2 million for the six months ended June 30, 2016, an increase of $15.5 million. The increase was a result of additional depreciation expense associated with the assets acquired in the Torrance Acquisition and a general increase in our fixed asset base due to capital projects and turnarounds completed since the second quarter of 2016.

Change in Fair Value of Catalyst Leases—Change in the fair value of catalyst leases represented a loss of $1.5 million for the six months ended June 30, 2017 compared to a loss of $4.6 million for the six months ended June 30, 2016. These losses relate to the change in value of the precious metals underlying the sale and leaseback of our refineries’ precious metals catalyst, which we are obligated to repurchase at fair market value on the lease termination dates.

Debt extinguishment costs—Debt extinguishment costs of $25.5 million incurred in the six months ended June 30, 2017 relate to nonrecurring charges associated with debt refinancing activity calculated based on the difference between the carrying value of the 2020 Senior Secured Notes on the date that they were reacquired and the amount for which they were reacquired. There were no such costs in the same period of 2016.

Interest Expense, net—Interest expense totaled $63.5 million for the six months ended June 30, 2017 compared to $64.6 million for the six months ended June 30, 2016, a decrease of approximately $1.0 million. This net decrease is mainly attributable to lower letter of credit fees, higher interest income and reduced amounts outstanding under our affiliate notes payable, partially offset by higher interest expense associated with higher borrowings under our Revolving Loan. Interest expense includes interest on long-term debt and notes payable, costs related to the sale and leaseback of our precious metals catalyst, financing costs associated with the A&R Inventory Intermediation Agreements with J. Aron, letter of credit fees associated with the purchase of certain crude oils, and the amortization of deferred financing costs.

 

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Income Tax Expense—As PBF Holding is a limited liability company treated as a “flow-through” entity for income tax purposes, our consolidated financial statements generally do not include a benefit or provision for income taxes for the six months ended June 30, 2017 and June 30, 2016, respectively, apart from the income tax attributable to two subsidiaries acquired in connection with the Chalmette Acquisition in the fourth quarter of 2015 and our wholly-owned Canadian subsidiary, PBF Energy Limited (“PBF Ltd.”) The two subsidiaries acquired in connection with the Chalmette Acquisition are treated as C-Corporations for income tax purposes.

Income tax expense was $6.3 million and $27.0 million for the six months ended June 30, 2017 and June 30, 2016, respectively. Income tax expense for the six months ended June 30, 2016 included a charge of $30.7 million related to a correction of prior periods.

2016 Compared to 2015

Overview—Our net income was $235.9 million for the year ended December 31, 2016 compared to $187.3 million for the year ended December 31, 2015.

Our results for the year ended December 31, 2016 were positively impacted by a non-cash special item consisting of an inventory LCM adjustment of approximately $521.3 million whereas our results for the year ended December 31, 2015 were negatively impacted by an inventory LCM adjustment of approximately $427.2 million. These LCM adjustments were recorded due to significant changes in the price of crude oil and refined products in the periods presented. Excluding the impact of the net change in LCM reserve, our results for the year ended December 31, 2016 were negatively impacted by unfavorable movements in certain crude oil differentials, lower crack spreads, increased costs to comply with the RFS, and increased interest costs, partially offset by positive earnings contributions from the Chalmette and Torrance refineries and higher throughput in the Mid-Continent. Throughput volumes for 2015 in the Mid-Continent were impacted by unplanned downtime in the second quarter of 2015.

Revenues—Revenues totaled $15.9 billion for the year ended December 31, 2016 compared to $13.1 billion for the year ended December 31, 2015, an increase of approximately $2.8 billion or 21.2%. Revenues per barrel were $59.72 and $69.66 for the years ended December 31, 2016 and 2015, respectively, a decrease of 14.3% directly related to lower hydrocarbon commodity prices. For the year ended December 31, 2016, the total throughput rates at our East Coast, Mid-Continent and Gulf Coast refineries averaged approximately 327,000 bpd, 159,100 bpd and 169,300 bpd, respectively. For the period from its acquisition on July 1, 2016 through December 31, 2016, our West Coast refinery’s throughput averaged 143,900 bpd. For the year ended December 31, 2015, the total throughput rates at our East Coast and Mid-Continent, refineries averaged approximately 330,700 bpd and 153,800 bpd, respectively. For the period from its acquisition on November 1, 2015 through December 31, 2015, our Gulf Coast refinery’s throughput averaged 190,800 bpd. The slight decrease in throughput rates at our East Coast refineries in 2016 compared to 2015 is primarily due to weather-related unplanned downtime at our Delaware City refinery in the first quarter of 2016, partially offset by downtime at our Delaware City refinery in 2015. The increase in throughput rates at our Mid-Continent refinery in 2016 is due to unplanned downtime in the second quarter of 2015. Our Gulf Coast and West Coast refineries were not acquired until the fourth quarter of 2015 and the third quarter of 2016, respectively. For the year ended December 31, 2016, the total refined product barrels sold at our East Coast, Mid-Continent, and Gulf Coast refineries averaged approximately 364,100 bpd, 171,800 bpd and 206,400 bpd, respectively. For the period from its acquisition on July 1, 2016 through December 31, 2016, refined product barrels sold at our West Coast refinery averaged approximately 179,200 bpd. For the year ended December 31, 2015, the total refined product barrels sold at our East Coast and Mid-Continent refineries averaged approximately 366,100 bpd and 162,600 bpd, respectively. For the period from its acquisition on November 1, 2015 through December 31, 2015, the total refined product barrels sold at our Gulf Coast refinery averaged 216,100 bpd. Total refined product barrels sold were higher than throughput rates, reflecting sales from inventory as well as sales and purchases of refined products outside the refineries.

 

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Gross Margin—Gross margin, including refinery operating expenses and depreciation, totaled $548.9 million, or $2.06 per barrel of throughput, for the year ended December 31, 2016, compared to $441.5 million, or $2.34 per barrel of throughput for the year ended December 31, 2015, an increase of approximately $107.3 million. Gross refining margin (as defined below in Non-GAAP Financial Measures) totaled $2,143.4 million, or $8.05 per barrel of throughput ($1,622.1 million or $6.09 per barrel of throughput excluding the impact of special items) for the year ended December 31, 2016 compared to $1,512.3 million, or $8.02 per barrel of throughput ($1,939.6 million or $10.29 per barrel of throughput excluding the impact of special items) for the year ended December 31, 2015, an increase of approximately $631.1 million or a decrease of approximately $317.5 million excluding special items. Excluding the impact of special items, gross margin and gross refining margin decreased due to unfavorable movements in certain crude differentials, lower crack spreads as persistent above-average refined product inventory levels weighed on margins, and increased costs to comply with the RFS, partially offset by higher throughput rates in the Mid-Continent and positive margin contributions from the Chalmette and Torrance refineries acquired in the fourth quarter of 2015 and third quarter of 2016, respectively. Costs to comply with our obligation under the RFS totaled $236.2 million for the year ended December 31, 2016 (excluding our Gulf Coast and West Coast refineries, whose costs to comply with RFS totaled $111.3 million for the year ended December 31, 2016) compared to $163.6 million for the year ended December 31, 2015 (excluding our Gulf Coast refinery, whose costs to comply with RFS totaled $8.0 million for the year ended December 31, 2015). In addition, gross margin and gross refining margin were positively impacted by a non-cash LCM adjustment of approximately $521.3 million resulting from the change in crude oil and refined product prices from the end of 2015 to the end of 2016 which, in addition to remaining below historical costs, increased since the prior year. The non-cash LCM adjustment decreased gross margin and gross refining margin by approximately $427.2 million in the year ended December 31, 2015.

Average industry refining margins in the Mid-Continent were weaker during the year ended December 31, 2016, as compared to the same period in 2015. The WTI (Chicago) 4-3-1 industry crack spread was $12.38 per barrel, or 30.9% lower, in the year ended December 31, 2016 as compared to $17.91 per barrel in the same period in 2015. Our margins were negatively impacted from our refinery specific crude slate in the Mid-Continent which was impacted by a declining WTI/Bakken differential and a declining WTI/Syncrude differential, which averaged a premium of $2.01 per barrel for the year ended December 31, 2016 as compared to a premium of $1.45 per barrel in the same period in 2015.

The Dated Brent (NYH) 2-1-1 industry crack spread was approximately $13.49 per barrel, or 17.5% lower in the year ended December 31, 2016 as compared to $16.35 per barrel in the same period in 2015. The Dated Brent/WTI differential and Dated Brent/Maya differential were $3.29 and $1.09 lower, respectively, in the year ended December 31, 2016, as compared to the same period in 2015. In addition, the WTI/Bakken differential was approximately $1.57 per barrel less favorable in the year December 31, 2016 as compared to the same period in 2015. Reductions in these benchmark crude differentials typically result in higher crude costs and negatively impact our earnings.

Operating Expenses—Operating expenses totaled $1,390.6 million, or $5.22 per barrel of throughput, for the year ended December 31, 2016 compared to $889.4 million, or $4.72 per barrel of throughput, for the year ended December 31, 2015, an increase of $501.2 million, or 56.4%. The increase in operating expenses was mainly attributable to the operating expenses associated with the Chalmette and Torrance refineries and related logistics assets. For the year ended December 31, 2016 and for the period from its acquisition on November 1, 2015 to December 31, 2015, the Chalmette refinery and related logistics assets incurred operating expenses of approximately $343.9 million and $52.1 million, respectively. In the period from its acquisition on July 1, 2016 to December 31, 2016, the Torrance refinery and related logistics assets incurred operating expenses of approximately $250.5 million. Total operating expenses at our refineries, excluding our Chalmette and Torrance refineries, decreased slightly for the year ended December 31, 2016, primarily due to lower energy costs and maintenance costs. The reduction in energy costs was mainly due to lower natural gas prices while the reduction in maintenance costs was mainly due to timing of repairs and certain non-recurring maintenance costs incurred in 2015. These reductions were partially offset by higher employee-related expenses, primarily attributable to merit increases in salaries.

 

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General and Administrative Expenses—General and administrative expenses totaled $149.6 million for the year ended December 31, 2016, compared to $166.9 million for the year ended December 31, 2015, a decrease of $17.3 million or 10.3%. The decrease in general and administrative expenses primarily relates to reduced employee related expenses of $39.3 million mainly due to lower incentive compensation expenses, partially offset by $12.9 million in additional outside services and other costs to support our acquisitions and related integration activities, and an increase of $9.1 million in equity compensation expense related to incremental grants in 2016 and accelerated vesting of awards due to retirements. Our general and administrative expenses are comprised of the personnel, facilities and other infrastructure costs necessary to support our refineries.

Loss (gain) on Sale of Assets—There was a loss of $11.4 million on the sale of assets for the year ended December 31, 2016 relating to the sale of non-refining assets as compared to a gain of $1.0 million for the year ended December 31, 2015 which related to the sale of railcars which were subsequently leased back.

Depreciation and Amortization Expense—Depreciation and amortization expense totaled $209.8 million for the year ended December 31, 2016, compared to $191.1 million for the year ended December 31, 2015, an increase of $18.7 million. The increase was a result of additional depreciation expense associated with the assets acquired in the Chalmette and Torrance acquisitions and a general increase in our fixed asset base due to capital projects and turnarounds completed since 2015.

Change in Fair Value of Catalyst Leases—Change in the fair value of catalyst leases represented a gain of $1.4 million for the year ended December 31, 2016, compared to a gain of $10.2 million for the year ended December 31, 2015. These gains relate to the change in value of the precious metals underlying the sale and leaseback of our refineries’ precious metals catalyst, which we are obligated to return or repurchase at fair market value on the lease termination dates.

Interest Expense, net—Interest expense totaled $129.5 million for the year ended December 31, 2016, compared to $88.2 million for the year ended December 31, 2015, an increase of $41.3 million. This increase is mainly attributable to higher interest costs associated with the issuance of the 2023 Senior Notes in November 2015, increased interest expense related to the affiliate notes payable and the drawdown on our Revolving Loan to partially fund the Torrance Acquisition in July 2016, partially offset by lower letter of credit fees. Interest expense includes interest on long-term debt and notes payable, costs related to the sale and leaseback of our precious metals catalyst, financing costs associated with the A&R Inventory Intermediation Agreements with J. Aron, letter of credit fees associated with the purchase of certain crude oils, and the amortization of deferred financing costs.

Income Tax Expense—As PBF Holding is a limited liability company treated as a “flow-through” entity for income tax purposes our consolidated financial statements generally do not include a benefit or provision for income taxes for the years ended December 31, 2016 and 2015 apart from the income tax attributable to two subsidiaries of Chalmette Refining and a wholly-owned Canadian subsidiary, PBF Ltd. that are treated as C-Corporations for income tax purposes. The two Chalmette subsidiaries incurred approximately $1.4 million of income tax expense and PBF Holding incurred income tax benefit of approximately $8.4 million attributable to PBF Ltd. for the year ended December 31, 2016. In addition, we recorded $30.7 million of incremental income tax expense in 2016 relating to a correction of prior period income taxes.

2015 Compared to 2014

Overview—Net income was $187.3 million for the year ended December 31, 2015 compared to $21.1 million for the year ended December 31, 2014.

Our results for the year ended December 31, 2015 were negatively impacted by a non-cash special item consisting of an inventory LCM adjustment of approximately $427.2 million whereas our results for the year ended December 31, 2014 were negatively impacted by an inventory LCM adjustment of approximately

 

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$690.1 million. These LCM charges were recorded due to significant declines in the price of crude oil and refined products in 2015 and 2014. Our throughput rates during the year ended December 31, 2015 compared to December 31, 2014 were higher due to the acquisition of the Chalmette refinery on November 1, 2015 as well as an approximate 40-day plant-wide planned turnaround at our Toledo refinery completed in the fourth quarter of 2014. Our results for the year ended December 31, 2015 were positively impacted by higher throughput volumes, lower non-cash special items for LCM charges and higher crack spreads for the East Coast and in the Mid-Continent partially offset by unfavorable movements in certain crude differentials.

Revenues—Revenues totaled $13.1 billion for the year ended December 31, 2015 compared to $19.8 billion for the year ended December 31, 2014, a decrease of approximately $6.7 billion, or 33.8%. Revenues per barrel were $69.66 and $119.89 for the years ended December 31, 2015 and 2014, respectively, a decrease of 41.9% directly related to lower hydrocarbon commodity prices. For the year ended December 31, 2015, the total throughput rates in the East Coast and Mid-Continent refineries averaged approximately 330,700 bpd and 153,800 bpd, respectively. For the period from its acquisition on November 1, 2015 through December 31, 2015, our Gulf Coast refinery’s throughput averaged 190,800 bpd. For the year ended December 31, 2014, the total throughput rates at our East Coast and Mid-Continent refineries averaged approximately 325,300 bpd and 127,800 bpd, respectively. The increase in throughput rates at our East Coast refineries in 2015 compared to 2014 was primarily due to higher run rates as a result of favorable market economics partially offset by unplanned downtime at our Delaware City refinery in 2015. The increase in throughput rates at our Mid-Continent refinery in 2015 compared to 2014 was primarily due to an approximate 40-day plant-wide planned turnaround completed in the fourth quarter of 2014. For the year ended December 31, 2015, the total refined product barrels sold at our East Coast and Mid-Continent refineries averaged approximately 366,100 bpd and 162,600 bpd, respectively. For the period from its acquisition on November 1, 2015 through December 31, 2015, the total refined product barrels sold at our Gulf Coast refinery averaged 216,100 bpd. For the year ended December 31, 2014, the total refined product barrels sold at our East Coast and Mid-Continent refineries averaged approximately 350,800 bpd and 144,100 bpd, respectively. Total refined product barrels sold were higher than throughput rates, reflecting sales from inventory as well as sales and purchases of refined products outside the refineries.

Gross Margin—Gross margin, including refinery operating expenses and depreciation, totaled $441.5 million, or $2.34 per barrel of throughput, for the year ended December 31, 2015, compared to $268.0 million, or $1.60 per barrel of throughput, for the year ended December 31, 2014, an increase of $173.6 million. Gross refining margin (as defined below in Non-GAAP Financial Measures) totaled $1,512.3 million, or $8.02 per barrel of throughput, ($1,939.6 million or $10.29 per barrel of throughput excluding the impact of special items) for the year ended December 31, 2015 compared to $1,314.1 million, or $7.94 per barrel of throughput ($2,004.2 million, or $12.11 per barrel of throughput excluding the impact of special items) for the year ended December 31, 2014, an increase of $198.2 million and a decrease of $64.7 million excluding special items. Excluding the impact of special items, gross refining margin decreased due to the narrowing of certain crude differentials partially offset by higher throughput rates, reflecting the impact from the Chalmette Acquisition, and favorable movements in crack spreads. Excluding the impact of special items, gross margin was relatively consistent with the prior year.

Average industry refining margins in the U.S. Mid-Continent were generally improved during the year ended December 31, 2015, as compared to the same period in 2014. The WTI (Chicago) 4-3-1 industry crack spread was approximately $17.91 per barrel or 12.5% higher in the year ended December 31, 2015, as compared to the same period in 2014. The price of WTI versus Dated Brent and other crude discounts narrowed during the year ended December 31, 2015, and our refinery specific crude slate in the Mid-Continent faced an adverse WTI/Syncrude differential, which averaged a premium of $1.45 per barrel for the year ended December 31, 2015 as compared to a discount of $2.25 per barrel in the same period in 2014.

The Dated Brent (NYH) 2-1-1 industry crack spread was approximately $16.35 per barrel, or 26.5% higher in the year ended December 31, 2015, as compared to the same period in 2014. However, the WTI/Dated Brent differential was $1.81 lower in the year ended December 31, 2015, as compared to the same period in 2014, and

 

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the WTI/Bakken differential was $2.58 per barrel less favorable for the same periods. The Dated Brent/Maya differential was approximately $4.63 per barrel less favorable in the year ended December 31, 2015 as compared to the same period in 2014. Additionally, the decrease in the Dated Brent/Maya crude differential, our proxy for the light/heavy crude differential, had a negative impact on our East Coast refineries, which can process a large slate of medium and heavy, sour crude oil that is priced at a discount to light, sweet crude oil. However, the lower flat price of crude oil during 2015 as compared to 2014 resulted in improved margins on certain lower value products we produce.

Operating Expenses—Operating expenses totaled $889.4 million, or $4.72 per barrel of throughput, for the year ended December 31, 2015 compared to $880.7 million, or $5.34 per barrel of throughput, for the year ended December 31, 2014, an increase of $8.7 million, or 1.0%. The increase in operating expenses is mainly attributable to an increase of approximately $45.8 million in maintenance costs, primarily driven by the Chalmette Acquisition in 2015 and general repairs at the Delaware City and Paulsboro refineries, an increase of $17.3 million in employee compensation primarily driven by additional headcount and $14.9 million of increased catalyst and chemicals costs partially offset by net reduced energy and utility costs of $64.4 million due to lower natural gas prices and $4.4 million lower other fixed charges. Our operating expenses principally consist of salaries and employee benefits, maintenance, energy and catalyst and chemicals costs at our refineries. Although operating expenses increased on an overall basis, refinery operating expenses per barrel decreased as a result of higher throughput volumes.

General and Administrative Expenses—General and administrative expenses totaled $166.9 million for the year ended December 31, 2015, compared to $140.2 million for the year ended December 31, 2014, an increase of $26.7 million or 19.1%. The increase in general and administrative expenses primarily relates to higher employee compensation expense of $13.3 million, mainly related to higher headcount and higher incentive compensation expenses, higher outside services fees of $3.0 million related to professional, legal and engineering consultants attributable to the Chalmette Acquisition, and higher equity compensation expense of $1.3 million. Our general and administrative expenses are comprised of the personnel, facilities and other infrastructure costs necessary to support our refineries.

Gain on Sale of Assets—Gain on sale of assets for the year ended December 31, 2015 was $1.0 million which related to the sale of railcars which were subsequently leased back to us, compared to a gain of $0.9 million for the year ended December 31, 2014, for the sale of railcars.

Depreciation and Amortization Expense—Depreciation and amortization expense totaled $191.1 million for the year ended December 31, 2015, compared to $179.0 million for the year ended December 31, 2014, an increase of $12.1 million. The increase was largely driven by our increased fixed asset base due to capital projects and turnarounds completed during 2014 and 2015 as well as the acquisition of the Chalmette refinery in 2015. These general increases were partially offset by reduction in impairment charges. In 2014, we recorded a $28.5 million impairment related to an abandoned capital project at our Delaware City refinery during that year whereas we did not record any significant impairment charges in the year ended December 31, 2015.

Change in Fair Value of Catalyst Leases—Change in the fair value of catalyst leases represented a gain of $10.2 million for the year ended December 31, 2015, compared to a gain of $4.0 million for the year ended December 31, 2014. This gain relates to the change in value of the precious metals underlying the sale and leaseback of our refineries’ precious metals catalyst, which we are obligated to return or repurchase at fair market value on the lease termination dates.

Interest Expense, net—Interest expense totaled $88.2 million for the year ended December 31, 2015, compared to $98.0 million for the year ended December 31, 2014, a decrease of $9.8 million. The decrease is mainly attributable to the termination of our crude and feeedstock supply agreement with MSCG, effective July 31, 2014. Interest expense includes interest on long-term debt including the 2020 Senior Secured Notes and 2023 Notes and credit facility, costs related to the sale and leaseback of our precious metals catalyst, interest

 

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expense incurred in connection with our crude and feedstock supply agreement with Statoil up to its expiration on December 31, 2015, financing costs associated with the Inventory Intermediation Agreements with J. Aron, letter of credit fees associated with the purchase of certain crude oils, and the amortization of deferred financing fees.

Income Tax Expense—As PBF Holding is a limited liability company treated as a “flow-through” entity for income tax purposes our consolidated financial statements do not include a benefit or provision for income taxes for the years ended December 31, 2015 and 2014 apart from the income tax attributable to two subsidiaries of Chalmette Refining that are treated as C-Corporations for income tax purposes.

Non-GAAP Financial Measures

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

Special Items

The non-GAAP measures presented include EBITDA excluding special items, and gross refining margin excluding special items. The special items for the periods presented relate to an LCM inventory adjustment and debt extinguishment costs (as further explained in “Notes to Non-GAAP Financial Measures” below). Although we believe that non-GAAP financial measures, excluding the impact of special items, provide useful supplemental information to investors regarding the results and performance of our business and allow for helpful period-over-period comparisons, such non-GAAP measures should only be considered as a supplement to, and not as a substitute for, or superior to, the financial measures prepared in accordance with GAAP.

Gross Refining Margin and Gross Refining Margin Excluding Special Items

Gross refining margin is defined as gross margin excluding depreciation and operating expenses related to the refineries. We believe both gross refining margin and gross refining margin excluding special items are important measures of operating performance and provide useful information to investors because they are helpful metric comparisons to the industry refining margin benchmarks, as the refining margin benchmarks do not include a charge for refinery operating expenses and depreciation. In order to assess our operating performance, we compare our gross refining margin (revenue less cost of products and other) to industry refining margin benchmarks and crude oil prices as defined in the table below.

 

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Neither gross refining margin nor gross refining margin excluding special items should 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 and gross refining margin excluding special items presented by other companies may not be comparable to our presentation, since each company may define these terms differently. The following table presents our GAAP calculation of gross margin and a reconciliation of gross refining margin to the most directly comparable GAAP financial measure, gross margin, on a historical basis, as applicable, for each of the periods indicated (in thousands, except per barrel amounts):

 

    Year Ended December 31,  
    2016     2015     2014  
    $     per barrel of
throughput
    $     per barrel of
throughput
    $     per barrel of
throughput
 

Calculation of gross margin:

           

Revenues

  $ 15,908,537     $ 59.72     $ 13,123,929     $ 69.66     $ 19,828,155     $ 119.88  

Less: Cost of products and other

    13,765,088       51.67       11,611,599       61.64       18,514,054       111.95  

Less: Refinery operating expenses

    1,390,582       5.22       889,368       4.72       880,701       5.33  

Less: Refinery depreciation expenses

    204,005       0.77       181,423       0.96       165,413       1.00  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Gross margin

  $ 548,862     $ 2.06     $ 441,539     $ 2.34     $ 267,987     $ 1.60  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Reconciliation of gross margin to gross refining margin:

           

Gross margin

  $ 548,862     $ 2.06     $ 441,539     $ 2.34     $ 267,987     $ 1.60  

Add: Refinery operating expenses

    1,390,582       5.22       889,368       4.72       880,701       5.34  

Add: Refinery depreciation expense

    204,005       0.77       181,423       0.96       165,413       1.00  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Gross refining margin

  $ 2,143,449     $ 8.05     $ 1,512,330     $ 8.02     $ 1,314,101     $ 7.94  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Special items:

           

Add: Non-cash LCM inventory adjustment (1)

    (521,348     (1.96     427,226       2.27       690,110       4.17  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Gross refining margin excluding special items

  $ 1,622,101     $ 6.09     $ 1,939,556     $ 10.29     $ 2,004,211     $ 12.11  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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    Six Months Ended June 30,  
    2017     2016  
    $     per barrel of
throughput
    $     per barrel of
throughput
 

Calculation of gross margin:

       

Revenues

  $ 9,763,449     $ 71.57     $ 6,655,958     $ 54.25  

Less: Cost of products and other

    8,914,587       65.35       5,730,731       46.71  

Less: Refinery operating expenses

    835,423       6.12       568,178       4.63  

Less: Refinery depreciation expenses

    110,900       0.81       100,136       0.82  
 

 

 

   

 

 

   

 

 

   

 

 

 

Gross margin

  $ (97,461   $ (0.71   $ 256,913     $ 2.09  
 

 

 

   

 

 

   

 

 

   

 

 

 

Reconciliation of gross margin to gross refining margin:

       

Gross margin

  $ (97,461   $ (0.71   $ 256,913     $ 2.09  

Add: Refinery operating expenses

    835,423       6.12       568,178       4.63  

Add: Refinery depreciation expense

    110,900       0.81       100,136       0.82  
 

 

 

   

 

 

   

 

 

   

 

 

 

Gross refining margin

  $ 848,862     $ 6.22     $ 925,227     $ 7.54  
 

 

 

   

 

 

   

 

 

   

 

 

 

Special items:

       

Add: Non-cash LCM inventory adjustment (1)

    167,134       1.23       (216,843     (1.77
 

 

 

   

 

 

   

 

 

   

 

 

 

Gross refining margin excluding special items

  $ 1,015,996     $ 7.45     $ 708,384     $ 5.77  
 

 

 

   

 

 

   

 

 

   

 

 

 

 

See notes to Non-GAAP Financial Measures.

EBITDA, EBITDA Excluding Special Items and Adjusted EBITDA

Our management uses EBITDA (earnings before interest, income taxes, depreciation and amortization), EBITDA excluding special items and Adjusted EBITDA as measures of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with our board of directors, creditors, analysts and investors concerning our financial performance. Our outstanding indebtedness for borrowed money and other contractual obligations also include similar measures as a basis for certain covenants under those agreements which may differ from the Adjusted EBITDA definition described below.

EBITDA, EBITDA excluding special items and Adjusted EBITDA are not presentations made in accordance with GAAP and our computation of EBITDA, EBITDA excluding special items and Adjusted EBITDA may vary from others in our industry. In addition, Adjusted EBITDA contains some, but not all, adjustments that are taken into account in the calculation of the components of various covenants in the agreements governing the Senior Notes and other credit facilities. EBITDA, EBITDA excluding special items and Adjusted EBITDA should not be considered as alternatives to operating income (loss) or net income (loss) as measures of operating performance. In addition, EBITDA, EBITDA excluding special items and Adjusted EBITDA are not presented as, and should not be considered, an alternative to cash flows from operations as a measure of liquidity. Adjusted EBITDA is defined as EBITDA before adjustments for items such as equity-based compensation expense, gains (losses) from certain derivative activities and contingent consideration, the non-cash change in the deferral of gross profit related to the sale of certain finished products, the write down of inventory to the LCM, and debt extinguishment costs related to refinancing activities. Other companies, including other companies in our industry, may calculate EBITDA, EBITDA excluding special items and Adjusted EBITDA differently than we do, limiting their usefulness as comparative measures. EBITDA, EBITDA excluding special items and Adjusted EBITDA also have limitations as analytical tools and should not be considered in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations include that EBITDA, EBITDA excluding special items and Adjusted EBITDA:

 

    do not reflect depreciation expense or our cash expenditures, or future requirements, for capital expenditures or contractual commitments;

 

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    do not reflect changes in, or cash requirements for, our working capital needs;

 

    do not reflect our interest expense, or the cash requirements necessary to service interest or principal payments, on our debt;

 

    do not reflect realized and unrealized gains and losses from certain hedging activities, which may have a substantial impact on our cash flow;

 

    do not reflect certain other non-cash income and expenses; and

 

    exclude income taxes that may represent a reduction in available cash.

The following tables reconcile net income as reflected in our results of operations to EBITDA, EBITDA excluding special items and Adjusted EBITDA for the periods presented (in thousands):

 

     Year Ended December 31,  
     2016     2015     2014  

Reconciliation of net income (loss) to EBITDA:

      

Net income (loss)

   $ 235,886     $ 187,294     $ 21,117  

Add: Depreciation and amortization expense

     209,840       191,110       178,996  

Add: Interest expense, net

     129,536       88,194       98,001  

Add: Income tax expense (benefit)

     23,689       648       —    
  

 

 

   

 

 

   

 

 

 

EBITDA

   $ 598,951     $ 467,246     $ 298,114  
  

 

 

   

 

 

   

 

 

 

Special Items:

      

Add: Non-cash LCM inventory adjustment (1)

     (521,348     427,226       690,110  
  

 

 

   

 

 

   

 

 

 

EBITDA excluding special items

   $ 77,603     $ 894,472     $ 988,224  
  

 

 

   

 

 

   

 

 

 

Reconciliation of EBITDA to Adjusted EBITDA:

      

EBITDA

   $ 598,951     $ 467,246     $ 298,114  

Add: Stock based compensation

     18,296       9,218       6,095  

Add: Non-cash change in fair value of catalyst leases

     (1,422     (10,184     (3,969

Add: Non-cash LCM inventory adjustment (1)

     (521,348     427,226       690,110  
  

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

   $ 94,477     $ 893,506     $ 990,350  
  

 

 

   

 

 

   

 

 

 

 

     Six Months Ended
June 30,
 
     2017     2016  

Reconciliation of net income (loss) to EBITDA:

    

Net income (loss)

   $ (270,916   $ 83,076  

Add: Depreciation and amortization expense

     118,683       103,212  

Add: Interest expense, net

     63,513       64,550  

Add: Income tax expense (benefit)

     6,332       26,996  
  

 

 

   

 

 

 

EBITDA

   $ (82,388   $ 277,834  
  

 

 

   

 

 

 

Special Items:

    

Add: Non-cash LCM inventory adjustment (1)

     167,134       (216,843

Add: Debt extinguishment costs (1)

     25,451       —    
  

 

 

   

 

 

 

EBITDA excluding special items

   $ 110,197     $ 60,991  
  

 

 

   

 

 

 

Reconciliation of EBITDA to Adjusted EBITDA:

    

EBITDA

   $ (82,388   $ 277,834  

Add: Stock based compensation

     10,134       9,999  

Add: Non-cash change in fair value of catalyst leases

     1,484       4,633  

Add: Non-cash LCM inventory adjustment (1)

     167,134       (216,843

Add: Debt extinguishment costs (1)

     25,451       —    
  

 

 

   

 

 

 

Adjusted EBITDA

   $ 121,815     $ 75,623  
  

 

 

   

 

 

 

 

See notes to Non-GAAP Financial Measures

 

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Notes to Non-GAAP Financial Measures

The following notes are applicable to the Non-GAAP Financial Measures above:

 

(1) Special items: In accordance with GAAP, we are required to state our inventories at the lower of cost or market. Our inventory cost is determined by the last-in, first-out (“LIFO”) inventory valuation methodology, in which the most recently incurred costs are charged to cost of sales and inventories are valued at base layer acquisition costs. Market is determined based on an assessment of the current estimated replacement cost and net realizable selling price of the inventory. In periods where the market price of our inventory declines substantially, cost values of inventory may exceed market values. In such instances, we record an adjustment to write down the value of inventory to market value in accordance with GAAP. In subsequent periods, the value of inventory is reassessed and an LCM inventory adjustment is recorded to reflect the net change in the LCM inventory reserve between the prior period and the current period.

The following table includes the lower of cost or market inventory reserve as of each date presented (in thousands):

 

     2016      2015      2014      2013  

December 31,

   $ 595,988      $ 1,117,336      $ 690,110      $ —    

 

     2017      2016  

January 1,

   $ 595,988      $ 1,117,336  

March 31,

     612,027        1,058,273  

June 30,

     763,122        900,493  

The following tables includes the corresponding impact of changes in the lower of cost or market inventory reserve on both operating income and net income for the periods presented (in thousands):

 

     Year Ended December 31,  
     2016      2015     2014  

Net LCM inventory adjustment benefit (charge) in both operating and net income

   $ 521,348      $ (427,226   $ (690,110

 

     Six Months Ended June 30,  
         2017              2016      

Net LCM inventory adjustment benefit (charge) in both operating and net income

   $ (167,134    $ 216,843  

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are our cash flows from operations and borrowing availability under our credit facilities, as more fully described below. We believe that our cash flows from operations and available capital resources will be sufficient to meet our and our subsidiaries’ capital expenditure, working capital, distribution payments and debt service requirements for the next twelve months. However, our ability to generate sufficient cash flow from operations depends, in part, on petroleum oil market pricing and general economic, political and other factors beyond our control. We are in compliance as of June 30, 2017 with all of the covenants, including financial covenants, in all of our debt agreements.

Cash Flow Analysis

Cash Flows from Operating Activities

Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016

Net cash used in operating activities was $205.8 million for the six months ended June 30, 2017 compared to net cash provided by operating activities of $147.8 million for the six months ended June 30, 2016. Our operating

 

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cash flows for the six months ended June 30, 2017 included our net loss of $270.9 million, plus depreciation and amortization of $122.8 million, a non-cash charge of $167.1 million relating to an LCM inventory adjustment, debt extinguishment costs related to refinancing of our 2020 Senior Secured Notes of $25.5 million, pension and other post-retirement benefits costs of $21.1 million, equity-based compensation of $10.1 million, changes in the fair value of our catalyst leases of $1.5 million, deferred income taxes of $5.1 million, loss on sale of assets of $0.9 million and net distributions in excess of earnings from our investment in TVPC of $4.8 million, offset by a change in the fair value of our inventory repurchase obligations of $3.1 million. In addition, net changes in operating assets and liabilities reflected uses of cash of $290.8 million driven by the timing of inventory purchases, payments for accrued expenses and accounts payable and collections of accounts receivable. Our operating cash flows for the six months ended June 30, 2016 included our net income of $83.1 million, plus net non-cash charges relating to depreciation and amortization of $107.9 million, the change in the fair value of our inventory repurchase obligations of $26.2 million, deferred income taxes of $27.1 million, pension and other post-retirement benefits costs of $15.4 million, changes in the fair value of our catalyst leases of $4.6 million, equity-based compensation of $10.0 million and a loss on sale of assets of $3.2 million, partially offset by a non-cash benefit of $216.8 million relating to an LCM inventory adjustment. In addition, net changes in operating assets and liabilities reflected sources of cash of $87.2 million driven by the timing of inventory purchases, payments for accrued expenses and accounts payables and collections of accounts receivables.

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

Net cash provided by operating activities was $551.6 million for the year ended December 31, 2016 compared to net cash provided by operating activities of $652.4 million for the year ended December 31, 2015. Our operating cash flows for the year ended December 31, 2016 included our net income of $235.9 million, depreciation and amortization of $218.9 million, change in the fair value of our inventory repurchase obligations of $29.5 million, pension and other post-retirement benefits costs of $38.0 million, deferred income tax expense of $19.8 million, stock-based compensation of $18.3 million and a loss on sale of assets of $11.4 million, partially offset by net non-cash benefits relating to an LCM adjustment of $521.3 million, equity income from our investment in TVPC of $5.7 million and the changes in the fair value of our catalyst lease of $1.4 million. In addition, net changes in working capital reflected sources of cash of $508.3 million driven by timing of inventory purchases and collections of accounts receivable. Our operating cash flows for the year ended December 31, 2015 included our net income of $187.3 million, plus net non-cash charges relating to an LCM adjustment of $427.2 million, depreciation and amortization of $199.4 million, change in the fair value of our inventory repurchase obligations of $63.4 million, pension and other post-retirement benefits costs of $27.0 million, and stock-based compensation of $9.2 million, partially offset by the changes in the fair value of our catalyst lease of $10.2 million, and gain on sales of assets of $1.0 million. In addition, net changes in working capital reflected uses of cash of $249.9 million driven by timing of inventory purchases and collections of accounts receivable.

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

Net cash provided by operating activities was $652.4 million for the year ended December 31, 2015 compared to net cash provided by operating activities of $495.7 million for the year ended December 31, 2014. Our operating cash flows for the year ended December 31, 2014 included our net income of $21.1 million, plus net non-cash charges relating to an LCM adjustment of $690.1 million, depreciation and amortization of $186.4 million, pension and other post-retirement benefits costs of $22.6 million, and stock-based compensation of $6.1 million, partially offset by the change in the fair value of our inventory repurchase obligations of $93.2 million, change in the fair value of our catalyst lease of $4.0 million, and gain on sales of assets of $0.9 million. In addition, net changes in working capital reflected uses of cash of $332.5 million driven by timing of inventory purchases and collections of accounts receivable as well as payments associated with the terminations of the MSCG offtake and Statoil supply agreement.

 

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Cash Flows from Investing Activities

Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016

Net cash used in investing activities was $417.7 million for the six months ended June 30, 2017 compared to net cash used in investing activities of $233.8 million for the six months ended June 30, 2016. The net cash flows used in investing activities for the six months ended June 30, 2017 was comprised of capital expenditures totaling $179.6 million, expenditures for refinery turnarounds of $214.4 million and expenditures for other assets of $23.7 million. Net cash used in investing activities for the six months ended June 30, 2016 was comprised of capital expenditures totaling $110.0 million, expenditures for refinery turnarounds of $106.6 million, expenditures for other assets of $21.3 million and a final net working capital settlement of $2.7 million associated with the acquisition of the Chalmette refinery, partially offset by $6.9 million of proceeds from the sale of assets.

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

Net cash used in investing activities was $1,473.5 million for the year ended December 31, 2016 compared to net cash used in investing activities of $811.2 million for the year ended December 31, 2015. The net cash flows used in investing activities for the year ended December 31, 2016 was comprised of cash outflows of $971.9 million used to fund the Torrance Acquisition, capital expenditures totaling $282.4 million, expenditures for turnarounds of $198.7 million, expenditures for other assets of $42.5 million and the final working capital settlement related to the acquisition of the Chalmette refinery of $2.7 million, partially offset by $24.7 million in proceeds from the sale of assets. The net cash flows used in investing activities for the year ended December 31, 2015 was comprised of $565.3 million used in the acquisition of the Chalmette refinery, capital expenditures totaling $352.4 million, expenditures for turnarounds of $53.6 million, and expenditures for other assets of $8.2 million, partially offset by $168.3 million in proceeds from the sale of assets.

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

Net cash used in investing activities was $811.2 million for the year ended December 31, 2015 compared to net cash used in investing activities of $422.7 million for the year ended December 31, 2014. The net cash used in investing activities for the year ended December 31, 2014 was comprised of capital expenditures totaling $470.5 million, expenditures for turnarounds of $137.7 million, and expenditures for other assets of $17.3 million, partially offset by $202.7 million in proceeds from the sale of assets.

Cash Flows from Financing Activities

Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016

Net cash provided by financing activities was $110.8 million for the six months ended June 30, 2017 compared to net cash provided by financing activities of $481.5 million for the six months ended June 30, 2016. For the six months ended June 30, 2017, net cash provided by financing activities consisted of a contribution from PBF LLC of $97.0 million and net cash proceeds of $22.4 million from the issuance of the 2025 Senior Notes net of cash paid to redeem the 2020 Senior Secured Notes and related issuance costs. Additionally, during the six months ended June 30, 2017, we made distributions to members of $5.3 million and principal amortization payments of the PBF Rail Term Loan of $3.3 million. Further, during the six months ended June 30, 2017, we borrowed and repaid $290.0 million under our Revolving Loan resulting in no net change to amounts outstanding for the six months ended June 30, 2017. For the six months ended June 30, 2016, net cash provided by financing activities consisted primarily of proceeds from the Revolving Loan of $550.0 million and a net increase of $0.1 million in proceeds from affiliate notes payable partially offset by $61.7 million of distribution to members and repayments of the PBF Rail revolving credit facility of $7.0 million.

 

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Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

Net cash provided by financing activities was $633.8 million for the year ended December 31, 2016 compared to net cash provided by financial activities of $855.2 million for the year ended December 31, 2015. For the year ended December 31, 2016, net cash provided by financing activities consisted primarily of net proceeds from the Revolving Loan of $350.0 million, a contribution from our parent of $450.3 million, proceeds from the PBF Rail Term Loan of $35.0 million and proceeds from catalyst leases of $15.6 million, partially offset by distributions to members of $139.4 million, repayments of the Rail Facility of $67.5 million and net repayments of the affiliate note payable of $10.1 million. For the year ended December 31, 2015, net cash provided by financing activities consisted primarily of $500.0 million in proceeds from the 2023 Senior Notes, capital contributions of $345.0 million, proceeds from affiliate notes payable of $347.8 million, and net proceeds from the PBF Rail Facility of $30.1 million, partially offset by distribution to members of $350.7 million and deferred financing costs and other of $17.1 million.

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

Net cash provided by financing activities was $855.2 million for the year ended December 31, 2015 compared to net cash provided by financing activities of $68.5 million for the year ended December 31, 2014. For the year ended December 31, 2014, net cash provided by financing activities consisted primarily of capital contributions of $328.7 million, proceeds from affiliate notes payable of $90.6 million, net proceeds from the Rail Facility of $37.3 million, partially offset by distributions to members of $361.4 million, net repayments of the Revolving Loan of $15.0 million and $11.7 million for deferred financing costs and other.

Capitalization

Our capital structure was comprised of the following as of December 31, 2016 (in millions):

 

     December 31, 2016  

Debt, including current maturities:

  

8.25% Senior Secured Notes due 2020

   $ 670.9  

7.00% Senior Secured Notes due 2023 (1)

     500.0  

Revolving Loan

     350.0  

PBF Rail Term Loan

     35.0  

Catalyst leases

     46.0  
  

 

 

 

Total debt

     1,601.9  
  

 

 

 

Unamortized deferred financing costs

     (25.3
  

 

 

 

Total debt, net of unamortized deferred financing costs

     1,576.6  

Affiliate notes payable

     86.3  

Total Equity

     2,588.9  
  

 

 

 

Total Capitalization

   $ 4,251.8  
  

 

 

 

Total Debt to Capitalization Ratio

     39
  

 

 

 

Our total debt, net of unamortized deferred financing costs to capitalization ratio was 39% and 48% at December 31, 2016 and 2015, respectively.

 

(1) These notes became unsecured following the “Collateral Fall-Away Event” defined under the indenture governing the 2025 Notes which occurred on May 30, 2017.

 

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2016 Debt Transactions

As noted in “Note 9—Credit Facility and Long-term Debt” to our consolidated financial statements for the year ended December 31, 2016 included elsewhere herein, on December 22, 2016, the PBF Rail Facility was repaid in full and terminated in connection with the execution of The PBF Term Loan (as defined below).

On December 22, 2016, PBF Rail entered into a $35.0 million term loan (the “PBF Rail Term Loan”) with DVB Bank SE (“DVB”). The PBF Rail Term Loan amortizes monthly over its five year term and bears interest at the one month LIBOR plus 2.0%. As security for the PBF Rail Term Loan, PBF Rail pledged, among other things: (i) certain eligible railcars; (ii) the Debt Service Reserve Account; and (iii) our membership interest in PBF Rail. Additionally, the PBF Rail Term Loan contains customary terms, events of default and covenants for transactions of this nature. PBF Rail may at any time repay the PBF Rail Term Loan without penalty in the event that railcars collateralizing the loan are sold, scrapped or otherwise removed from the collateral pool.

The 7.00% 2023 Senior Notes were issued on November 24, 2015 and included a registration payment arrangement whereby we agreed to use commercially reasonable efforts to consummate an offer to exchange the 2023 Senior Notes for an issue of registered notes with terms substantially identical to the notes not later than 365 days after the date of the original issuance of the notes. The registration statement was declared effective on December 1, 2016 and the exchange was consummated on January 19, 2017. Because the exchange offer was not consummated by November 24, 2016, additional interest was added at a rate of 0.25% per annum for the period from November 24, 2016 through the consummation of the exchange. As a result, we recognized approximately $0.1 million of additional interest expense in 2016.

During 2016, we borrowed under our Revolving Loan to partially fund the Torrance Acquisition (as discussed in “Note 3—Acquisitions” to our consolidated financial statements for the year ended December 31, 2016 included elsewhere herein).

Revolving Credit Facilities Overview

Our primary sources of liquidity are cash flows from operations with additional sources available under borrowing capacity from our revolving line of credit. As of December 31, 2016, we had $626.7 million of cash and cash equivalents and $350.0 million outstanding under our Revolving Loan. We believe available capital resources will be adequate to meet our capital expenditure, working capital and debt service requirements. We had available capacity under our revolving credit facility as follows at December 31, 2016 (in millions):

 

     Total
Capacity
     Amount Borrowed as
of December 31, 2016
     Outstanding
Letters of Credit
     Available
Capacity
     Expiration
date
 

PBF Holding Revolving Loan (a)

   $ 2,635.0      $ 350.0      $ 412.0      $ 534.6        August 2019  

 

(a) The amount available for borrowings and letters of credit under the Revolving Loan is calculated according to a “borrowing base” formula based on (i) 90% of the book value of eligible accounts receivable with respect to investment grade obligors plus (ii) 85% of the book value of eligible accounts receivable with respect to non-investment grade obligors plus (iii) 80% of the cost of eligible hydrocarbon inventory plus (iv) 100% of cash and cash equivalents in deposit accounts subject to a control agreement. The borrowing base is subject to customary reserves and eligibility criteria and in any event cannot exceed $2.635 billion.

Additional Information on Indebtedness

Our debt, including our revolving credit facility, term loan and senior notes, include certain typical financial covenants and restrictions on our subsidiaries’ ability to, among other things, incur or guarantee new debt, engage in certain business activities including transactions with affiliates and asset sales, make investments or distributions, engage in mergers or pay dividends in certain circumstances. These covenants are subject to a number of important exceptions and qualifications. For further discussion of our indebtedness and these covenants and restrictions, see “Note 9—Credit Facilities and Long-term Debt” to our consolidated financial statements for the year ended December 31, 2016 included elsewhere herein.

 

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We were in compliance with our covenants as of June 30, 2017.

Cash Balances

As of December 31, 2016 and June 30, 2017, our cash and cash equivalents totaled $626.7 million and $114.0 million, respectively.

Liquidity

As of June 30, 2017, our total liquidity was approximately $894.8 million, compared to total liquidity of approximately $1,161.3 million as of December 31, 2016. Total liquidity is the sum of our cash and cash equivalents plus the estimated amount available under the Revolving Loan.

Working Capital

Our working capital at June 30, 2017 was $627.1 million, consisting of $2,695.4 million in total current assets and $2,068.3 million in total current liabilities. Our working capital at December 31, 2016 was $1,111.0 million, consisting of $3,154.3 million in total current assets and $2,043.3 million in total current liabilities. Working capital has decreased primarily as a result of capital expenditures, including turnaround costs, during the six months ended June 30, 2017.

Capital Spending

Net capital spending was $417.7 million for the six months ended June 30, 2017, which primarily included turnaround costs, safety related enhancements and facility improvements at the refineries. We currently expect to spend an aggregate of approximately between $575.0 million to $600.0 million in net capital expenditures during the full year 2017 for facility improvements and refinery maintenance and turnarounds. Significant capital spending plans for the full year 2017 include turnarounds for the FCC at our Delaware City refinery, several units at our Torrance refinery and several units at our Chalmette refinery, as well as expenditures to meet Tier 3 requirements.

Crude and Feedstock Supply Agreements

Certain of our purchases of crude oil under our agreements with foreign national oil companies require that we post letters of credit and arrange for shipment. We pay for the crude when invoiced, at which time the letters of credit are lifted. Our crude and feedstock supply agreements with PDVSA provide that the crude oil can be processed at any of our East and Gulf Coast refineries. In connection with the Torrance Acquisition, we entered into a crude supply agreement with ExxonMobil to deliver crude oil to our Torrance refinery.

Inventory Intermediation Agreements

On May 4, 2017, we and our subsidiaries, DCR and PRC, entered into amendments to the inventory intermediation agreements (as amended in the second quarter of 2017, the “A&R Intermediation Agreements”) with J. Aron, pursuant to which certain terms of the existing inventory intermediation agreements were amended, including, among other things, pricing and an extension of the terms. The A&R Intermediation Agreements were further amended on September 8, 2017. As a result the amendments (i) the A&R Intermediation Agreement by and among J. Aron, us and PRC relating to the Paulsboro refinery extends to December 31, 2019, which term may be further extended by mutual consent of the parties to December 31, 2020 and (ii) the A&R Intermediation Agreement by and among J. Aron, us and DCR relating to the Delaware City refinery extends the term to July 1, 2019, which term may be further extended by mutual consent of the parties to July 1, 2020.

Pursuant to each A&R Intermediation Agreement, J. Aron continues to purchase and hold title to certain of the intermediate and finished products (the “Products”) produced by the Paulsboro and Delaware City refineries

 

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(the “Refineries”), respectively, and delivered into tanks at the Refineries. Furthermore, J. Aron agrees to sell the Products back to the Refineries as the Products are discharged out of the Refineries’ tanks. J. Aron has the right to store the Products purchased in tanks under the A&R Intermediation Agreements and will retain these storage rights for the term of the agreements. We continue to market and sell independently to third parties.

At June 30, 2017, the LIFO value of intermediates and finished products owned by J. Aron included within inventory on our balance sheet was $300.9 million. We accrue a corresponding liability for such intermediates and finished products.

Contractual Obligations and Commitments

The following table summarizes our material contractual payment obligations as of December 31, 2016 (in thousands):

 

    Payments due by period  
    Total     Less than
1 year
    1-3 Years     3-5 Years     More than
5 years
 

Long-term debt (a)

  $ 1,692,767     $ 9,798     $ 472,469     $ 710,500     $ 500,000  

Interest payments on debt facilities (a)

    472,490       101,893       200,808       99,789       70,000  

Operating Leases (b)

    436,667       111,184       187,740       105,322       32,421  

Purchase obligations (c):

         

Crude Supply and Inventory Intermediation Agreements

    8,137,912       2,268,826       3,560,062       2,309,024       —    

Other Supply and Capacity Agreements

    1,269,562       187,443       328,399       195,324       558,396  

Minimum volume commitments with PBFX (d)

    1,469,766       208,319       411,344       409,116       440,987  

Construction obligations

    33,927       33,927       —         —         —    

Environmental obligations (e)

    159,111       9,981       22,037       10,250       116,843  

Pension and post-retirement obligations (f)

    263,723       13,413       17,648       19,012       213,650  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total contractual cash obligations

  $ 13,935,925     $ 2,944,784     $ 5,200,507     $ 3,858,337     $ 1,932,297  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

(a) Long-term Debt and Interest Payments on Debt Facilities

Long-term debt obligations in the table above as of December 31, 2016 represent (i) the repayment of the outstanding borrowings under the Revolving Loan; (ii) the repayment of indebtedness incurred in connection with the 2020 Senior Secured Notes; (iii) the repayment of our catalyst lease obligations on their maturity dates; (iv) the repayment of outstanding amounts under the PBF Rail Term Loan; and (v) the repayment of outstanding affiliate notes payable with PBF LLC and PBF Energy.

Interest payments on debt facilities include cash interest payments on the 2020 Senior Secured Notes, catalyst lease obligations, PBF Rail Term Loan, our affiliate notes payable with PBF Energy and PBF LLC, plus cash payments for the commitment fee on the unused Revolving Loan and letter of credit fees on the letters of credit outstanding at December 31, 2016. With the exception of our catalyst leases, we have no long-term debt maturing before 2019 as of December 31, 2016.

On May 30, 2017, the Company consummated the offering of the 2025 Senior Notes and used the funds for the redemption of the 2020 Senior Secured Notes and general corporate purposes.

(b) Operating Leases

We enter into operating leases in the normal course of business, some of these leases provide us with the option to renew the lease or purchase the leased item. Future operating lease obligations would change if we chose to exercise renewal options and if we enter into additional operating lease agreements. Certain of our lease obligations contain a fixed and variable component. The table above reflects the fixed component of our lease

 

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obligations. The variable component could be significant. Our operating lease obligations are further explained in the Commitments and Contingencies footnote to our financial statements for the year ended December 31, 2016 included elsewhere herein. In support of our rail strategy, we have at times entered into agreements to lease or purchase crude railcars. A portion of these railcars were purchased via the Rail Facility entered into during 2014, which was repaid in full and terminated in connection with the execution of the PBF Rail Term Loan in 2016. Certain of these railcars were subsequently sold to third parties, which have leased the railcars back to us for periods of between four and seven years.

(c) Purchase Obligations

We have obligations to repurchase certain intermediates and refined products under separate inventory intermediation agreements with J. Aron as further explained in the Summary of Significant Accounting Policies, Inventories and Accrued Expenses footnotes to our financial statements for the year ended December 31, 2016 included elsewhere herein. Additionally, purchase obligations under “Crude Supply and Inventory Intermediation Agreements” include commitments to purchase crude oil from certain counterparties under supply agreements entered into to ensure adequate supplies of crude oil for our refineries. These obligations are based on aggregate minimum volume commitments at 2016 year end market prices.

As of June 30, 2017, a liability of $233.5 million was recorded for the inventory and supply intermediation arrangements and is recorded at market price for the J. Aron owned inventory held in the Company’s storage tanks under the A&R Inventory Intermediation Agreements.

Payments under “Other Supply and Capacity Agreements” include contracts for the transportation of crude oil and supply of hydrogen, steam, or natural gas to certain of our refineries, contracts for the treatment of wastewater, and contracts for pipeline capacity. We enter into these contracts to facilitate crude oil deliveries and to ensure an adequate supply of energy or essential services to support our refinery operations. Substantially all of these obligations are based on fixed prices. Certain agreements include fixed or minimum volume requirements, while others are based on our actual usage. The amounts included in this table are based on fixed or minimum quantities to be purchased and the fixed or estimated costs based on market conditions as of December 31, 2016.

(d) Minimum commitments with PBFX

We have minimum obligations under our commercial agreements entered into with PBFX. PBFX receives, handles and transfers crude oil and receives, stores and delivers crude oil, refined products and intermediates from sources located throughout the United States and Canada in support of certain of our refineries. Refer to “Note 12—Related Party Transactions” to our consolidated financial statements for the year ended December 31, 2016 included elsewhere herein for a detailed explanation of each of these agreements.

Included in the table above are our obligations related to the minimum commitments required under these commercial agreements. Any incremental volumes above any minimums throughput under these agreements would increase our obligations. Our obligation with respect to the Toledo Tank Farm Storage and Terminaling Agreement is based on the estimated shell capacity of the storage tanks to be utilized.

(e) Environmental Obligations

In connection with the Paulsboro acquisition, we assumed certain environmental remediation obligations to address existing soil and groundwater contamination at the site and recorded as a liability in the amount of $10.8 million which reflects the present value of the current estimated cost of the remediation obligations assumed based on investigative work to-date. The undiscounted estimated costs related to these environmental remediation obligations were $16.7 million as of December 31, 2016.

 

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In connection with the acquisition of the Delaware City assets, the prior owners remain responsible, subject to certain limitations, for certain pre-acquisition environmental obligations, including ongoing soil and groundwater remediation at the site.

In connection with the Delaware City assets and Paulsboro refinery acquisitions, we, along with the seller, purchased two individual ten-year, $75.0 million environmental insurance policies to insure against unknown environmental liabilities at each site.

In connection with the acquisition of Toledo, the seller initially retains, subject to certain limitations, remediation obligations which will transition to us over a 20-year period.

In connection with the acquisition of the Chalmette refinery, the sellers provided $3.9 million financial assurance in the form of a surety bond to cover estimated potential site remediation costs associated with an agreed to Administrative Order of Consent with the EPA. Additionally, we purchased a ten year $100.0 million environmental insurance policy to insure against unknown environmental liabilities at the site.

In connection with the Torrance Acquisition, we assumed certain environmental remediation obligations to address existing soil and groundwater contamination at the site and recorded a liability of $142.5 million as of December 31, 2016, which reflects the current estimated cost of the remediation obligations, expected to be paid out over an average period of approximately 20 years. Additionally, we purchased a ten year $100.0 million environmental insurance policy to insure against unknown environmental liabilities.

In connection with the acquisition of all of our refineries, we assumed certain environmental obligations under regulatory orders unique to each site, including orders regulating air emissions from each facility.

(f) Pension and Post-retirement Obligations

Pension and post-retirement obligations include only those amounts we expect to pay out in benefit payments and are further explained at the Employee Benefit Plans footnote to our financial statements for the year ended December 31, 2016 included elsewhere herein.

(g) Tax Receivable Agreement Obligations

The Contractual Obligations and Commitments Table above does not include tax distributions or other distributions that we expect to make on account of PBF Energy’s obligations under the tax receivable agreement that PBF Energy entered into with the members of PBF LLC other than PBF Energy in connection with PBF Energy’s initial public offering.

PBF Energy used a portion of the proceeds from its IPO to purchase PBF LLC Series A Units from the members of PBF LLC other than PBF Energy. In addition, the members of PBF LLC other than PBF Energy may (subject to the terms of the exchange agreement) exchange their PBF LLC Series A Units for shares of Class A common stock of PBF Energy on a one-for-one basis. As a result of both the purchase of PBF LLC Series A Units and subsequent secondary offerings and exchanges, PBF Energy is entitled to a proportionate share of the existing tax basis of the assets of PBF LLC. Such transactions have resulted in increases in the tax basis of the assets of PBF LLC that otherwise would not have been available. Both this proportionate share and these increases in tax basis may reduce the amount of tax that PBF Energy would otherwise be required to pay in the future. These increases in tax basis have reduced the amount of the tax that PBF Energy would have otherwise been required to pay and may also decrease gains (or increase losses) on the future disposition of certain capital assets to the extent tax basis is allocated to those capital assets. PBF Energy entered into a tax receivable agreement with the current and former members of PBF LLC other than PBF Energy that provides for the payment by PBF Energy to such members of 85% of the amount of the benefits, if any, that PBF Energy is deemed to realize as a result of (i) these increases in tax basis and (ii) certain other tax benefits related to entering

 

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into the tax receivable agreement, including tax benefits attributable to payments under the tax receivable agreement. These payment obligations are obligations of PBF Energy and not of PBF Holding or any of its subsidiaries.

PBF Energy expects to obtain funding for these payments by causing its subsidiaries to make cash distributions to PBF LLC, which, in turn, will distribute such amounts, generally as tax distributions, on a pro-rata basis to its owners, which as of December 31, 2016 include the members of PBF LLC other than PBF Energy holding a 3.5% interest and PBF Energy holding a 96.5% interest. The members of PBF LLC other than PBF Energy may continue to reduce their ownership in PBF LLC by exchanging their PBF LLC Series A Units for shares of PBF Energy Class A common stock. Such exchanges may result in additional increases in the tax basis of PBF Energy’s investment in PBF LLC and require PBF Energy to make increased payments under the tax receivable agreement. Required payments under the tax receivable agreement also may increase or become accelerated in certain circumstances, including certain changes of control.

Off-Balance Sheet Arrangements and Contractual Obligations and Commitments

We have no off-balance sheet arrangements as of June 30, 2017, other than outstanding letters of credit in the amount of approximately $442.6 million and operating leases.

Distribution Policy

On August 3, 2017 PBF Energy, PBF Holding’s indirect parent, announced a dividend of $0.30 per share on outstanding Class A common stock. The dividend was paid on August 31, 2017 to Class A common stockholders of record at the close of business on August 15, 2017. PBF Holding made a distribution of $34.1 million to PBF LLC, which in turn made pro-rata distributions to its members, including PBF Energy. PBF Energy used this distribution to fund the dividend payments to the stockholders of PBF Energy.

As of June 30, 2017, we had $894.8 million of unused borrowing availability, which includes our cash and cash equivalents of $114.0 million, under the Revolving Loan to fund our operations, if necessary. Accordingly, as of June 30, 2017, there was sufficient cash and cash equivalents and borrowing capacity under our credit facilities available to make distributions to PBF LLC, in order for PBF LLC, if necessary, to make pro rata distributions to its members, including PBF Energy, necessary to fund in excess of one year’s cash dividend payments by PBF Energy.

Since, as described above, there was sufficient cash and cash equivalents and borrowing capacity as of June 30, 2017, we would have been permitted under our debt agreements to make these distributions; however, our ability to continue to comply with our debt covenants is, to a significant degree, subject to our operating results, which are dependent on a number of factors outside of our control. We believe our and our subsidiaries’ available cash and cash equivalents, other sources of liquidity to operate our business and operating performance provides us with a reasonable basis for our assessment that we can support PBF Energy’s intended distribution policy.

Critical Accounting Policies

The following summary provides further information about our critical accounting policies that involve critical accounting estimates and should be read in conjunction with “Note 2—Summary of Significant Accounting Policies” to our consolidated financial statements, “Item 8. Financial Statements and Supplementary Data.” The following accounting policies involve estimates that are considered critical due to the level of subjectivity and judgment involved, as well as the impact on our financial position and results of operations. We believe that all of our estimates are reasonable. Unless otherwise noted, estimates of the sensitivity to earnings that would result from changes in the assumptions used in determining our estimates is not practicable due to the number of assumptions and contingencies involved, and the wide range of possible outcomes.

 

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Inventory

Inventories are carried at the lower of cost or market. The cost of crude oil, feedstocks, blendstocks and refined products is determined under the LIFO method using the dollar value LIFO method with increments valued based on average cost during the year. The cost of supplies and other inventories is determined principally on the weighted average cost method. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years that inventory volumes decline as the result of charging cost of sales with LIFO inventory costs generated in prior periods. At December 31, 2016 and 2015, market values had fallen below historical LIFO inventory costs and, as a result, we recorded lower of cost or market inventory valuation reserves of $596.0 million and $1,117.3 million, respectively. The $596.0 million as of December 31, 2016, or a portion thereof, is subject to reversal as a reduction to cost of products sold in subsequent periods as inventories giving rise to the reserve are sold, and a new reserve is established. Such a reduction to cost of products sold could be significant if inventory values return to historical cost price levels. Additionally, further decreases in overall inventory values could result in additional charges to cost of products sold should the lower of cost or market inventory valuation reserve be increased.

Our Delaware City refinery acquired a portion of its crude oil from Statoil under our crude supply agreement whereby we took title to the crude oil as it was delivered to our processing units. We had risk of loss while the Statoil inventory was in our storage tanks. We were obligated to purchase all of the crude oil held by Statoil on our behalf upon termination of the agreements. As a result of the purchase obligations, we recorded the inventory of crude oil and feedstocks in the refinery’s storage facilities. The purchase obligations contained derivatives that changed in value based on changes in commodity prices. Such changes were included in our cost of sales. Our agreement with Statoil for our Delaware City refinery terminated effective December 31, 2015, at which time we began to source crude oil and feedstocks internally. Our agreement with Statoil for Paulsboro terminated effective March 31, 2013, at which time we began to source crude oil and feedstocks independently.

Prior to July 31, 2014, our Toledo refinery acquired substantially all of its crude oil from MSCG under a crude oil acquisition agreement whereby we took legal title to the crude oil at certain interstate pipeline delivery locations. We recorded an accrued liability at each period-end for the amount we owed MSCG for the crude oil that we owned but had not processed. The accrued liability was based on the period-end market value, as it represented our best estimate of what we would pay for the crude oil. We terminated this crude oil acquisition agreement effective July 31, 2014 and began to source our crude oil needs independently.

Environmental Matters

Liabilities for future clean-up costs are recorded when environmental assessments and/or clean-up efforts are probable and the costs can be reasonably estimated. Other than for assessments, the timing and magnitude of these accruals generally are based on the completion of investigations or other studies or a commitment to a formal plan of action. Environmental liabilities are based on best estimates of probable future costs using currently available technology and applying current regulations, as well as our own internal environmental policies. The actual settlement of our liability for environmental matters could materially differ from our estimates due to a number of uncertainties such as the extent of contamination, changes in environmental laws and regulations, potential improvements in remediation technologies and the participation of other responsible parties. Additionally, in connection with the Torrance Acquisition on July 1, 2016, we assumed certain pre-existing environmental liabilities. While we believe that our current estimates of the amounts and timing of the costs related to the remediation of these liabilities are reasonable, we have had limited experience with these environmental obligations due to our short operating history. It is possible that our estimates of the costs and duration of the environmental remediation activities related to these liabilities could materially change.

Business Combinations

We use the acquisition method of accounting for the recognition of assets acquired and liabilities assumed in business combinations at their estimated fair values as of the date of acquisition. Any excess consideration

 

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transferred over the estimated fair values of the identifiable net assets acquired is recorded as goodwill. Significant judgment is required in estimating the fair value of assets acquired. As a result, in the case of significant acquisitions, we obtain the assistance of third-party valuation specialists in estimating fair values of tangible and intangible assets based on available historical information and on expectations and assumptions about the future, considering the perspective of marketplace participants. While management believes those expectations and assumptions are reasonable, they are inherently uncertain. Unanticipated market or macroeconomic events and circumstances may occur, which could affect the accuracy or validity of the estimates and assumptions.

Deferred Turnaround Costs

Refinery turnaround costs, which are incurred in connection with planned major maintenance activities at our refineries, are capitalized when incurred and amortized on a straight-line basis over the period of time estimated until the next turnaround occurs (generally three to five years). While we believe that the estimates of time until the next turnaround are reasonable, it should be noted that factors such as competition, regulation or environmental matters could cause us to change our estimates thus impacting amortization expense in the future.

Derivative Instruments

We are exposed to market risk, primarily related to changes in commodity prices for the crude oil and feedstocks we use in the refining process as well as the prices of the refined products we sell. The accounting treatment for commodity contracts depends on the intended use of the particular contract and on whether or not the contract meets the definition of a derivative. Non-derivative contracts are recorded at the time of delivery.

All derivative instruments that are not designated as normal purchases or sales are recorded in our balance sheet as either assets or liabilities measured at their fair values. Changes in the fair value of derivative instruments that either are not designated or do not qualify for hedge accounting treatment or normal purchase or normal sale accounting are recognized in income. Contracts qualifying for the normal purchases and sales exemption are accounted for upon settlement. We elect fair value hedge accounting for certain derivatives associated with our inventory repurchase obligations.

Derivative accounting is complex and requires management judgment in the following respects: identification of derivatives and embedded derivatives; determination of the fair value of derivatives; identification of hedge relationships; assessment and measurement of hedge ineffectiveness; and election and designation of the normal purchases and sales exception. All of these judgments, depending upon their timing and effect, can have a significant impact on earnings.

Recent Accounting Pronouncements

In August 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (“ASU 2015-14”), which defers the effective date of ASU 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”) for all entities by one year. Additional ASUs have been issued in 2016 that provide certain implementation guidance related to ASU 2014-09 (collectively, we refer to ASU 2014-09 and these additional ASUs as the “Updated Revenue Recognition Guidance”). The Updated Revenue Recognition Guidance will replace most existing revenue recognition guidance in GAAP when it becomes effective. Under ASU 2015-14, this guidance becomes effective for interim and annual periods beginning after December 15, 2017 and permits the use of either the retrospective or modified retrospective transition method. Under ASU 2015-14, early adoption is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We have established a working group to assess the Updated Revenue Recognition Guidance, including its impact on our business processes, accounting systems, controls and financial statement disclosures. Our preliminary expectation is that we will adopt this guidance using the

 

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modified retrospective method whereby a cumulative effect adjustment is recognized upon adoption and the Updated Revenue