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EX-5.1 - OPINION OF VINSON & ELKINS L.L.P. - Alon USA Partners, LPd400066dex51.htm
EX-8.1 - OPINION OF VINSON & ELKINS L.L.P. - Alon USA Partners, LPd400066dex81.htm
EX-23.1 - CONSENT OF KPMG LLP - Alon USA Partners, LPd400066dex231.htm
Table of Contents

As filed with the Securities and Exchange Commission on November 9, 2012

Registration No. 333-183671

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Amendment No. 6

to

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Alon USA Partners, LP

(Exact Name of Registrant as Specified in Its Charter)

 

 

 

Delaware   2911   46-0810241

(State or Other Jurisdiction of

Incorporation or Organization)

 

(Primary Standard Industrial

Classification Code Number)

 

(I.R.S. Employer

Identification Number)

12700 Park Central Dr., Suite 1600

Dallas, TX 75251

(972) 367-3600

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

 

 

Shai Even

James Ranspot

12700 Park Central Dr., Suite 1600

Dallas, TX 75251

(972) 367-3600

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

 

 

Copies to:

Mike Rosenwasser

Gillian Hobson

Vinson & Elkins L.L.P.

666 Fifth Avenue, 26th Floor

New York, New York 10103

Tel: (212) 237-0000

Fax: (212) 237-0100

 

Sean T. Wheeler

Divakar Gupta

Latham & Watkins LLP

811 Main Street, Suite 3700

Houston, Texas 77002

Tel: (713) 546-5400

Fax: (713) 546-5401

 

 

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

 

 

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, 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(c) 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, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer   ¨    Accelerated filer   ¨
Non-accelerated filer   x  (Do not check if a smaller reporting company)    Smaller reporting company   ¨

 

 

CALCULATION OF REGISTRATION FEE

 

 

Title of securities to be registered

 

    Proposed maximum aggregate    

offering price (1)(2)

 

Amount of
registration

fee(3)

Common units representing limited partner interests

  $241,500,000   $27,927

 

 

(1) Includes common units issuable upon exercise of the underwriters’ option to purchase additional common units.
(2) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) of the Securities Act.
(3) The total registration fee includes $26,358 that was previously paid for the registration of $230,000,000 of proposed aggregate offering price in the filing of the Registration Statement (Registration No. 333-183671) on August 31, 2012 and $1,569 for the registration of an additional $11,500,000 of proposed maximum offering price registered hereby.

 

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant 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 of 1933 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 Contents

The information in this prospectus is not complete and may be changed. We may not sell 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 we are not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

 

Subject to Completion, Dated November 9, 2012.

10,000,000 Common Units

Representing Limited Partner Interests

 

LOGO

Alon USA Partners, LP

 

 

This is the initial public offering of our common units representing limited partner interests. We are offering 10,000,000 common units in this offering.

Prior to this offering, there has been no public market for our common units. We anticipate that the initial public offering price will be between $19.00 and $21.00 per common unit. Our common units have been approved for listing on the New York Stock Exchange under the symbol “ALDW,” subject to official notice of issuance.

 

 

Investing in our common units involves risks. See “Risk Factors” beginning on page 18. These risks include the following:

 

 

 

   

We may not have sufficient available cash to pay any quarterly distribution on our common units.

 

   

The price volatility of crude oil, other feedstocks, refined products and fuel and utility services may have a material adverse effect on our earnings, profitability and cash flows, and our ability to make distributions to unitholders.

 

   

Changes in the WTI—Brent or Cushing WTI—Midland WTS differentials or the easing of logistical and infrastructure constraints at Cushing, Oklahoma could adversely affect the crude oil cost advantage that has been in our favor, which could negatively affect our profitability.

 

   

The amount of our quarterly cash distributions, if any, will vary significantly both quarterly and annually and will be directly dependent on the performance of our business. Unlike most publicly traded partnerships, we will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time.

 

   

Our unitholders have limited voting rights and are not entitled to elect our general partner or our general partner’s directors.

 

   

You will incur immediate and substantial dilution in net tangible book value per common unit.

 

   

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.

 

   

You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

 

 

Neither the Securities and Exchange Commission nor any other regulatory body has approved or disapproved of these securities or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.

 

 

 

     Per 
Common
Unit
     Total  

Initial public offering price

   $                            $                        

Underwriting discount

   $         $     

Proceeds, before expenses, to Alon USA Partners, LP

   $         $     

To the extent that the underwriters sell more than                      common units, the underwriters have the option to purchase up to an additional                      common units at the initial public offering price less the underwriting discount.

 

 

The underwriters expect to deliver the common units against payment in New York, New York on or about                     , 2012.

 

 

 

Goldman, Sachs & Co.   Credit Suisse   Citigroup
 

Jefferies

 
Macquarie Capital     Tudor, Pickering, Holt & Co.

 

 

Prospectus dated                 , 2012.


Table of Contents

LOGO


Table of Contents

TABLE OF CONTENTS

 

PROSPECTUS SUMMARY

     1   

Alon USA Partners, LP

     1   

Competitive Strengths

     3   

Business Strategy

     4   

Refining Industry Overview

     5   

Risk Factors

     6   

Our Relationship with Alon Energy

     6   

Our Management

     6   

Conflicts of Interest and Fiduciary Duties

     7   

About Us

     7   

The IPO Transactions

     7   

Organizational Structure

     9   

The Offering

     10   

Summary Historical Combined and Pro Forma Combined Financial and Operating Data

     14   

Non-GAAP Financial Measure

     17   

RISK FACTORS

     18   

Risks Inherent in Our Business

     18   

Risks Inherent in an Investment in Us

     33   

Tax Risks

     41   

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

     45   

USE OF PROCEEDS

     46   

CAPITALIZATION

     47   

DILUTION

     48   

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

     50   

General

     50   

Unaudited Pro Forma Available Cash

     52   

Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2013

     54   

Forecast Assumptions and Considerations

     58   

HOW WE MAKE CASH DISTRIBUTIONS

     64   

Distributions of Available Cash

     64   

SELECTED HISTORICAL COMBINED AND PRO FORMA COMBINED FINANCIAL DATA

     65   

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

     67   

Overview

     67   

Outlook

     68   

Factors Affecting Comparability of Our Historical Results

     68   

Factors Affecting Our Results of Operations

     70   

Results of Operations

     71   

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

     73   

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

     74   

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

     75   

Liquidity and Capital Resources

     76   

Cash Flows

     77   

Amended and Restated Revolving Credit Facility

     78   

Intercompany Debt

     79   

New Term Loan Facility

     79   

Capital Spending

     80   

Contractual Obligations

     80   

Off-Balance Sheet Arrangements

     80   

 

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Table of Contents

Critical Accounting Policies

     81   

Quantitative and Qualitative Disclosures About Market Risk

     82   

BUSINESS

     84   

Our Company

     84   

Competitive Strengths

     85   

Business Strategy

     87   

Refining Industry Overview

     88   

Our Refinery

     90   

Competition

     96   

Trade Names, Service Marks and Trademarks

     97   

Governmental Regulation and Legislation

     97   

Seasonality

     100   

Employees

     100   

Properties and Insurance

     100   

Legal Proceedings

     100   

MANAGEMENT

     101   

Management of Alon USA Partners, LP

     101   

Executive Officers and Directors

     102   

EXECUTIVE COMPENSATION

     107   

Executive Compensation

     107   

Director Compensation

     111   

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     112   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     113   

Distributions and Payments to Alon Energy and its Affiliates

     113   

Agreements with Alon Energy

     114   

Other Transactions with Related Parties

     116   

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

     117   

Conflicts of Interest

     117   

Fiduciary Duties of Our General Partner

     122   

Related Party Transactions

     124   

DESCRIPTION OF THE COMMON UNITS

     125   

Our Common Units

     125   

Transfer Agent and Registrar

     125   

Transfer of Common Units

     125   

Listing

     126   

THE PARTNERSHIP AGREEMENT

     127   

Organization and Duration

     127   

Purpose

     127   

Capital Contributions

     127   

Adjustments to Capital Accounts Upon Issuance of Additional Common Units

     127   

Voting Rights

     128   

Applicable Law; Forum, Venue and Jurisdiction

     129   

Limited Liability

     129   

Issuance of Additional Partnership Interests

     130   

Amendment of Our Partnership Agreement

     131   

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

     133   

Termination and Dissolution

     134   

Liquidation and Distribution of Proceeds

     134   

Withdrawal or Removal of Our General Partner

     134   

Transfer of General Partner Interest

     135   

Transfer of Ownership Interests in Our General Partner

     136   

Change of Management Provisions

     136   

 

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Table of Contents

Call Right

     136   

Non-Citizen Assignees; Redemption

     137   

Non-Taxpaying Assignees; Redemption

     137   

Meetings; Voting

     137   

Status as Limited Partner or Assignee

     138   

Indemnification

     138   

Reimbursement of Expenses

     138   

Books and Reports

     139   

Right to Inspect Our Books and Records

     139   

Registration Rights

     140   

UNITS ELIGIBLE FOR FUTURE SALE

     141   

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

     143   

Taxation of the Partnership

     143   

Tax Consequences of Unit Ownership

     145   

Tax Treatment of Operations

     149   

Disposition of Units

     150   

Uniformity of Units

     152   

Tax-Exempt Organizations and Other Investors

     153   

Administrative Matters

     153   

State, Local and Other Tax Considerations

     155   

INVESTMENT IN ALON USA PARTNERS, LP BY EMPLOYEE BENEFIT PLANS

     156   

UNDERWRITING

     157   

VALIDITY OF OUR COMMON UNITS

     162   

EXPERTS

     162   

WHERE YOU CAN FIND MORE INFORMATION

     162   

ALON USA PARTNERS, LP INDEX TO COMBINED FINANCIAL STATEMENTS

     F-1   

APPENDIX A—AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF ALON USA PARTNERS, LP

     A-1   

APPENDIX B—GLOSSARY OF INDUSTRY TERMS USED IN THIS PROSPECTUS

     B-1   

 

 

You should rely only on the information contained in this prospectus, any free writing prospectus prepared by or on behalf of us or any other information to which we have referred you in connection with this offering. We have not, and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus. Neither the delivery of this prospectus nor sale of our common units means that information contained in this prospectus is correct after the date of this prospectus. This prospectus is not an offer to sell or solicitation of an offer to buy our common units in any circumstances under which the offer or solicitation is unlawful.

 

 

Through and including                 , 2012 (the 25th day after the date of this prospectus), all dealers effecting transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to a dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

 

 

We have not authorized anyone to provide any information or to make any representations other than those contained in this prospectus or in any free writing prospectuses we have prepared. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. This prospectus is an offer to sell only the common units offered hereby, but only under circumstances and in jurisdictions where it is lawful to do so. The information contained in this prospectus is current only as of its date.

 

iii


Table of Contents

Industry and Market Data

The data included in this prospectus regarding the refining industry, including trends in the market and our position and the position of our competitors within the refining industry, is based on a variety of sources, including information provided by independent industry publications, government publications and other published independent sources, information obtained from customers, distributors, suppliers, trade and business organizations and publicly available information (including the reports and other information our competitors file with the SEC, which we did not participate in preparing and as to which we make no representation), as well as our good faith estimates, which have been derived from management’s knowledge and experience in the areas in which our business operates. Estimates of market size and relative positions in a market are difficult to develop and inherently uncertain.

 

iv


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PROSPECTUS SUMMARY

This summary highlights certain information contained elsewhere in this prospectus. This summary is not complete and does not contain all of the information that you should consider before investing in our common units. You should read this entire prospectus carefully, including the historical and pro forma combined financial statements and the notes to those statements, before investing in our common units. The information presented in this prospectus assumes, unless otherwise indicated, that the underwriters’ option to purchase additional common units is not exercised. You should read “Risk Factors” beginning on page 18 for information about important risks that you should consider before buying our common units.

Unless the context otherwise requires, in this prospectus, all references to “Alon USA,” “Alon USA Partners, LP Predecessor,” the “partnership,” “we,” “us” and “our” or like terms when used in a historical context refer to the businesses of Alon USA, LP, a Texas limited partnership, and Alon USA Refining, Inc., a Delaware corporation, each of which Alon USA Energy, Inc., a Delaware corporation, is contributing to Alon USA Partners, LP in connection with this offering. Unless the context otherwise requires, when used in the present tense or prospectively, those terms refer to Alon USA Partners, LP, a Delaware limited partnership, and its subsidiaries. References in this prospectus to “our general partner” refer to Alon USA Partners GP, LLC, a Delaware limited liability company and the general partner of the partnership. Unless the context otherwise requires, references in this prospectus to Alon Energy refer to Alon USA Energy, Inc., our parent company and the owner of our general partner, and its consolidated subsidiaries other than us. We have included a glossary of industry terms in Appendix B hereto.

Alon USA Partners, LP

Overview

We are a Delaware limited partnership formed in August 2012 by Alon USA Energy, Inc. (NYSE: ALJ) to own, operate and grow our strategically located refining and petroleum products marketing business. Our integrated downstream business operates primarily in the South Central and Southwestern regions of the United States. We own and operate a crude oil refinery in Big Spring, Texas with total throughput capacity of approximately 70,000 barrels per day (“bpd”), which we refer to as our Big Spring refinery. We refine crude oil into finished products, which we market primarily in West Texas, Central Texas, Oklahoma, New Mexico and Arizona through our wholesale distribution network to both Alon Energy’s retail convenience stores and other third-party distributors.

Our Big Spring refinery has a Nelson complexity rating of 10.2. Our refinery’s complexity allows us the flexibility to process a variety of crudes into higher-value refined products. For the year ended December 31, 2011 and the nine months ended September 30, 2012, sour crude, such as West Texas Sour (“WTS”), represented approximately 80.4% and 78.6% of our throughput, respectively, and sweet crude, such as West Texas Intermediate (“WTI”), represented approximately 15.8% and 18.8% of our throughput, respectively. For the year ended December 31, 2011 and the nine months ended September 30, 2012, we produced approximately 49.1% and 49.6% gasoline, 32.3% and 32.8% diesel/jet fuel, 7.1% and 6.3% asphalt, 6.0% and 5.9% petrochemicals and 5.5% and 5.4% other refined products, in each case, respectively. Major processing units at our Big Spring refinery include fluid catalytic cracking, naphtha reforming, vacuum distillation, hydrotreating and alkylation units. During the year ended December 31, 2011 and the nine months ended September 30, 2012, our Big Spring refinery had a utilization rate of 90.8% and 97.3%, respectively.

We believe the location and sour crude processing capability of our Big Spring refinery provide us strategic cost advantages for sourcing our crude oil requirements. Our close proximity to the Midland and Cushing markets allows us to source WTS and WTI crude oils, both of which currently trade at a considerable discount to imported waterborne crude oils, such as Brent crude oil (“Brent”). Our ability to purchase these less expensive crude oils provides us a cost advantage compared to refineries located on the U.S. Gulf Coast that utilize more

 

 

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expensive waterborne crude oils to produce the refined products they sell in our market area. In addition, our Big Spring refinery’s ability to process substantial volumes of WTS provides us with a further cost advantage. WTS has historically traded at a discount to WTI due to the cost associated with eliminating sulfur content from sour crude in the refining process. Because our Big Spring refinery is able to process substantial volumes of WTS, our overall feedstock costs are generally lower than those of refineries that are not capable of processing high volumes of WTS and therefore must utilize a greater percentage of sweeter, more expensive crudes such as WTI.

In addition to cost advantages resulting from our proximity to domestic crude oil sources and our refinery’s capability to process substantial volumes of WTS, we have been able to capitalize on the oversupply of West Texas crudes in Midland, the largest origination terminal for West Texas crude oil, resulting from increased production in the Permian Basin coupled with infrastructure constraints in Cushing, Oklahoma. Although West Texas crudes are typically transported to Cushing for sale, current logistical and infrastructure constraints at Cushing are limiting the ability of Permian Basin producers to transport their production to Cushing. The resulting oversupply of West Texas crudes at Midland has depressed Midland WTI crude prices and enabled us to access an increased portion of our West Texas crude supply directly from Midland at discounted prices to Cushing. Moreover, by sourcing West Texas crude oils at Midland, we are able to eliminate the cost of transporting crude supply to and from Cushing.

The following table shows average crude oil source differentials for the periods presented, which we believe have provided us the strategic cost advantages described above.

 

Average Differential(1)

   Nine Months  Ended
September 30, 2012
    Year Ended
December 31,  2011
    Five Years Ended
December  31, 2011
 

NYMEX Cushing WTI–ICE Brent

   $ (16.04   $ (15.80   $ (3.23

Midland WTS–NYMEX Cushing WTI

     (4.13     (2.14     (2.95

Midland WTI–NYMEX Cushing WTI

     (2.86     (0.60     (0.28

 

(1) Average prices from Alon Energy.

We sell refined products from our Big Spring refinery in both the wholesale rack and bulk markets. We focus our marketing of transportation fuels produced at our Big Spring refinery on portions of Texas, Oklahoma, New Mexico and Arizona through our physically integrated refining and distribution system. We distribute fuel products through a product pipeline and terminal network of seven pipelines totaling approximately 840 miles and five terminals that we own or access through leases or long-term throughput agreements. On a historical basis, we sold 19.1% and 19.4% of the motor fuels we produced and all of the asphalt we produced to Alon Energy during the year ended December 31, 2011 and the nine months ended September 30, 2012, respectively. In addition, in connection with this offering, we will enter into a 20-year fuel supply agreement with Alon Energy under which we will supply substantially all of the motor fuel requirements of Alon Energy’s retail convenience stores. We will also enter into a 20-year asphalt supply agreement with Alon Energy. For the twelve months ending September 30, 2013, we expect to sell approximately 21% of the motor fuels and all of the asphalt we produce to Alon Energy.

Our total net sales for the year ended December 31, 2011 and the nine months ended September 30, 2012 were $3.2 billion and $2.7 billion, respectively. Our pro forma net income and Adjusted EBITDA for the year ended December 31, 2011 were $286.4 million and $371.3 million, respectively, and for the nine months ended September 30, 2012 were $262.8 million and $334.2 million, respectively. Please read “—Summary Historical Combined and Pro Forma Combined Financial and Operating Data—Non-GAAP Financial Measure” beginning on page 17 for the definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our most directly comparable financial measure calculated and presented in accordance with generally accepted accounting principles (“GAAP”). Please also read our unaudited pro forma combined financial statements included elsewhere in this prospectus.

 

 

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Competitive Strengths

We believe the following competitive strengths differentiate us from our competitors and contribute to our continued success:

Strategically Located Refinery with Advantageous Access to Crude Oil Supply. Our Big Spring refinery is located in close proximity to Midland, Texas, the largest origination terminal for West Texas crude oil. We believe this proximity provides us with cost-effective sources of WTS and WTI crude. The recent increase in the discount at which a barrel of WTI trades relative to Brent has allowed refineries, such as ours, that are capable of sourcing and utilizing WTI and WTI-linked crude oils, to realize relatively lower feedstock costs while benefiting from the higher refined product prices resulting from higher Brent prices. As of August 2012, the U.S. Energy Information Administration (“EIA”) has forecasted that WTI will continue to trade at a significant discount to Brent through 2013. Moreover, our strategic location provides us with a low relative transportation cost to source WTS and WTI crude oil in Midland, Texas versus purchasing such crude at Cushing, further increasing the discount to Brent that we realize. We believe regulatory and capital hurdles make it difficult for competitors to replicate our business.

Attractive Regional Refined Products Supply/Demand Dynamics. Because of our inland location closer to the areas in which we market our products, foreign and coastal domestic refiners seeking to access our marketing area would incur higher transportation costs than we do. For the year ended December 31, 2011 and the nine months ended September 30, 2012, the aggregate average gasoline and diesel sale prices we realized exceeded the aggregate average gasoline and diesel prices used in calculating the Gulf Coast (WTI) 3-2-1 crack spread by $2.99 and $1.08 per barrel, respectively.

Sophisticated and Flexible Refinery with Crude Oil Supply and Operating Advantages. In addition to the benefits attributable to our strategic location, our refinery’s high relative net cash margin per barrel is due primarily to:

 

   

our ability to process substantial volumes of sour crude oil which results in lower feedstock costs and provides the competitive flexibility to utilize an alternative to low sulfur, or sweet, crude oils such as WTI, allowing us to capitalize on any long-term price differentials; and

 

   

the low-cost operations and efficiencies we realize by having a sophisticated refinery and a network of pipelines and terminals that we either own or have access to through leases or long-term throughput agreements.

Physically Integrated Refining and Distribution System. Our pipeline, terminal and distribution network provides us with the flexibility to: (1) access a variety of crude oils for feedstock, thereby allowing us to optimize our refinery’s crude supply; and (2) distribute our motor fuel products efficiently to markets in the South Central and Southwestern United States through interconnections with third-party transportation systems. Our physically integrated system also allows us to achieve cost efficiencies that are not available to those competitors who are not similarly integrated. Our distribution system is enhanced through our supply arrangements with Alon Energy.

Low-Risk Wholesale Marketing Operations. Through our wholesale marketing operations, we supply refined products and provide brand support services such as payment card processing, advertising programs and loyalty and marketing programs to branded distributors as well as Alon Energy’s retail convenience stores. Because our unaffiliated customers are distributors rather than individual retailers, we make sales to a select number of large, creditworthy customers, whose credit profile may be more closely monitored. Additionally, our distributors take possession of their motor fuels directly from our inventories at fuel terminals in our distribution system, which limits our commodities risk exposure and risk associated with fuel transportation.

 

 

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Our Relationship with Alon Energy. Our sponsor is an independent refiner and marketer of petroleum products operating primarily in the South Central, Southwestern and Western regions of the United States. As of September 30, 2012, Alon Energy operated 299 convenience stores in Central and West Texas and New Mexico, substantially all of which are branded 7-Eleven and all of which we supply. In connection with this offering, we will also enter into a 20-year fuel supply agreement with Alon Energy under which we will supply substantially all of the motor fuel requirements of Alon Energy’s retail convenience stores. We believe that access to Alon Energy’s complementary retail business fosters a mutually beneficial commercial relationship that allows us to benefit from our combined economies of scale and purchasing power. We also believe that Alon Energy’s ownership of our general partner and a majority of our common units will serve to align Alon Energy’s interests with ours and promote and support the successful execution of our business strategies.

Experienced and Incentivized Leadership. Our executive officers have an average of over 20 years’ experience in the industry. A number of our executive officers and key operating personnel have spent the majority of their careers operating refineries and have successfully managed our business through multiple industry cycles. We also benefit from the management and marketing expertise provided by Alon Energy, who, following this offering, will own 100% of the voting interests in our general partner and 84.0% of our common units.

Business Strategy

The primary components of our business strategy are:

Distribute All Available Cash We Generate Each Quarter. The board of directors of our general partner will adopt a policy under which distributions for each quarter will equal the amount of available cash (as described in “Cash Distribution Policy and Restrictions on Distributions”) we generate each quarter. We do not intend to maintain excess distribution coverage in order to stabilize our quarterly distributions or to otherwise reserve cash for future distributions. In addition, our general partner has a non-economic interest and no incentive distribution rights, and, accordingly, our unitholders will receive 100% of our cash distributions. The board of directors of our general partner may change our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay distributions to our unitholders on a quarterly or other basis. See “Cash Distribution Policy and Restrictions on Distributions” beginning on page 50.

Maintain Efficient Refinery Operations and Promote Operational Excellence and Reliability. For the year ended December 31, 2011 and the nine months ended September 30, 2012, our Big Spring refinery maintained a utilization rate of 90.8% and 97.3%, respectively. We intend to continue to operate our refinery as reliably and efficiently as possible to optimize utilization and further improve our operations by maintaining our costs at competitive levels. We will continue to devote significant time and resources toward improving the reliability of our operations. We will also seek to improve operating performance through commitment to our preventive maintenance program and to employee training and development programs.

Enhance Existing Operations and Invest in Organic Growth. We are focused on the profitable enhancement of our existing operations and investment in organic growth by:

 

   

continuing to make investments to enhance the operating flexibility of our refinery and increase our crude oil sourcing advantage;

 

   

evaluating ways to increase the profitability of our Big Spring refinery through cost-effective upgrades and expansions;

 

   

pursuing organic growth projects at the refinery to improve the yield of motor fuels we produce and the efficiency of our operations; and

 

 

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expanding our physically integrated system by making investments in logistics operations, including terminal and pipeline facilities.

Maintain Modest Leverage and Sufficient Levels of Liquidity. We anticipate we will remain modestly leveraged and will continue to benefit from a number of sources of liquidity that will provide us with financial flexibility during periods of volatile commodity prices, including cash on hand, our amended and restated revolving credit facility and trade credit from our crude oil suppliers. For example, in February 2011, we entered into a supply and offtake agreement with J. Aron & Company (“J. Aron”) under which (i) J. Aron agreed to sell to us, and we agreed to buy from J. Aron, at market prices, up to our daily refining capacity limit of crude oil for processing at the Big Spring refinery and (ii) we agreed to sell, and J. Aron agreed to buy, at market prices, certain refined products produced by the Big Spring refinery. On a pro forma basis for this offering, as of September 30, 2012, we estimate that we would have had approximately $101.4 million of available liquidity comprised of cash on hand and amounts available for borrowing under our amended and restated revolving credit facility. For the twelve months ending September 30, 2013, we anticipate we will have a total debt to Adjusted EBITDA ratio of 0.7 to 1.0. Our actual available liquidity may vary from our estimated amount depending on several factors, including fluctuations in inventory and accounts receivable values as well as cash reserves.

Evaluate Accretive Acquisition Opportunities. We may pursue accretive acquisitions within our refining and wholesale marketing business operations, both in our existing areas of operations as well as in new geographic regions that would diversify our operating footprint. Our acquisition strategy may include purchases from or together with Alon Energy. We believe that Alon Energy’s active participation in the refining and wholesale marketing business and its unique insights into business opportunities in our industry will help us identify, evaluate and pursue attractive commercial growth opportunities.

Refining Industry Overview

Crude oil refining is the process of separating the hydrocarbons present in crude oil for the purpose of converting them into marketable finished, or refined, petroleum products such as gasoline, diesel, jet fuel, asphalt and other products. Refining is primarily a margin-based business where both the feedstock (primarily crude oil) and the refined products are commodities with fluctuating prices. In order to increase profitability, refineries focus on maximizing the yields of high-value finished products and minimizing the costs of feedstock and operating expenses. The U.S. economy has historically been the largest consumer of petroleum-based products in the world. According to the EIA’s 2012 Refinery Capacity Report, there were 134 operating oil refineries in the United States in January 2012, with a total refining capacity of approximately 16.7 million bpd.

Crude oil supply and demand dynamics can vary by region, creating differentiated margin opportunities depending on a given refinery’s location. Our Big Spring refinery is located in the Gulf Coast region of the United States, represented in part by Petroleum Administration for Defense District III (“PADD III”). Refineries that operate in PADD III and utilize WTI and WTI-linked crudes, including our Big Spring refinery, often benchmark their performance against the Gulf Coast (WTI) 3-2-1 crack spread. The Gulf Coast (WTI) 3-2-1 crack spread averaged $8.64 per barrel for the three years ended December 31, 2010. During the year ended December 31, 2011, and for the first nine months of 2012, the Gulf Coast (WTI) 3-2-1 crack spread averaged $23.37 and $27.54 per barrel, respectively. The primary driver of the increased crack spread is the differential between WTI and Brent, which is resulting in part from the logistical and infrastructure constraints at Cushing that are leading to lower Midland WTI prices.

According to the EIA, total demand for refined products in PADD III has represented approximately 20.9% of total U.S. refined products demand from 2007 to 2011. Total refiner capacity for PADD III in May 2012 was 8.7 million bpd with total throughput at 8.2 million bpd, representing a refinery utilization rate of approximately 93.8%. Refinery capacity exceeds refined product demand with finished petroleum products consumed in the

 

 

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region totaling 3.5 million bpd, causing refiners in PADD III to supply all other PADDs. Despite this high level of refining capacity relative to the refined product demand, refiners who can access advantageous crude supplies are still able to achieve high margins.

Risk Factors

Investing in our common units involves risks that include the volatility of crude oil and other refinery feedstocks, refined product prices, competition, our partnership structure, the tax characteristics of our common units and other material factors. For a discussion of these risks and other considerations that could negatively affect us, see “Risk Factors” beginning on page 18 and “Cautionary Note Regarding Forward-Looking Statements” beginning on page 45.

Our Relationship with Alon Energy

Alon Energy is an independent refiner and marketer of petroleum products operating primarily in the South Central, Southwestern and Western regions of the United States. Following this offering, Alon Energy will own 100% of the voting interests in our general partner and 84.0% of our common units. Our ongoing relationship with Alon Energy provides us with secure fuel distribution outlets and marketing expertise, which we believe provides us with a competitive advantage. Given its significant ownership in us, we believe Alon Energy will be motivated to promote and support the successful execution of our business plan and to pursue projects and/or acquisitions that enhance the value of our business. Under the terms of the omnibus agreement that we will enter into in connection with the closing of this offering, we will have a right of first refusal if Alon Energy or any of its controlled affiliates has the opportunity to acquire a controlling interest in any refinery and related crude oil and refined product logistic assets, including non-retail transportation terminal sales, and that operate in Arizona, Arkansas, Colorado, Kansas, New Mexico, Oklahoma or Texas. In addition, pursuant to the terms of the omnibus agreement, we will have a 60-day exclusive right of negotiation if Alon Energy or any of its controlled affiliates decide to attempt to sell any refinery and related crude oil and refined product logistic assets, including non-retail transportation terminal sales, that operate in Arizona, Arkansas, Colorado, Kansas, New Mexico, Oklahoma or Texas. Additionally, in connection with this offering, we will enter into a 20-year fuel supply agreement with Alon Energy under which we will supply substantially all of the motor fuel requirements of Alon Energy’s retail convenience stores. We will also enter into a 20-year asphalt supply agreement with Alon Energy. See “Certain Relationships and Related Party Transactions—Agreements with Alon Energy” beginning on page 114.

Our Management

We are managed and operated by the board of directors and executive officers of our general partner, Alon USA Partners GP, LLC, an indirect subsidiary of Alon Energy. Following this offering, Alon Energy will own, directly or indirectly, approximately 84.0% of our outstanding common units. As a result of owning our general partner, Alon Energy will have the right to appoint all of the members of the board of directors of our general partner, including all of our general partner’s independent directors. At least one of our general partner’s independent directors will be appointed prior to the date our common units are listed for trading on the applicable stock exchange. Alon Energy will appoint our general partner’s second independent director within three months of the date our common units begin trading, and our general partner’s third independent director within one year from such date. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operations. For more information about the executive officers and directors of our general partner, please read “Management” beginning on page 101.

 

 

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Following the consummation of this offering, neither our general partner nor Alon Energy will receive any management fee or other compensation in connection with our general partner’s management of our business, but we will reimburse our general partner and its affiliates, including Alon Energy, for all expenses they incur and payments they make on our behalf pursuant to our partnership agreement, the omnibus agreement and the services agreement. Neither our partnership agreement, the omnibus agreement nor our services agreement limits the amount of expenses for which our general partner and its affiliates may be reimbursed. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. Please read “Certain Relationships and Related Party Transactions” beginning on page 113.

Conflicts of Interest and Fiduciary Duties

Our general partner has a legal duty to manage us in good faith. However, the officers and directors of our general partner also have fiduciary duties to manage our general partner in a manner beneficial to its indirect owner, Alon Energy. As a result, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and Alon Energy, on the other hand. Our partnership agreement limits the liability and replaces the duties owed by our general partner to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions that might otherwise constitute a breach of our general partner’s duties. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and each unitholder is treated as having consented to various actions and potential conflicts of interest contemplated in the partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law.

For a more detailed description of the conflicts of interest and the fiduciary duties of our general partner, see “Conflicts of Interest and Fiduciary Duties” beginning on page 117. For a description of other relationships with our affiliates, see “Certain Relationships and Related Party Transactions” beginning on page 113.

About Us

Alon USA Partners, LP was formed in Delaware in August 2012. Our principal executive offices are located at 12700 Park Central Dr., Suite 1600, Dallas, Texas 75251, and our telephone number is (972) 367-3600. Upon completion of this offering, our website address will be www.alonpartners.com. Information contained on our website or Alon Energy’s website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission (the “SEC”) available, 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.

The IPO Transactions

In connection with this offering, the following transactions will occur:

 

   

On or before the closing date of this offering, Alon Energy will conduct a series of internal restructuring transactions that will result in our ownership of the Big Spring refinery and related assets through our operating subsidiaries.

 

   

On the closing date of this offering, we will enter into the following agreements with Alon Energy:

 

   

a services agreement with Alon Energy pursuant to which (i) Alon Energy will provide certain general and administrative services to us, and (ii) we will reimburse Alon Energy for certain expenses incurred by them on our behalf;

 

 

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an omnibus agreement with Alon Energy pursuant to which (i) we will have certain rights of first refusal on refinery and related crude oil and refined product logistic assets in our areas of operations, (ii) we will have certain exclusive rights of negotiation with respect to assets to be sold by Alon Energy, (iii) Alon Energy will agree to indemnify us with respect to certain liabilities, and (iv) we will receive the rights to continue to use the “Alon” name and related marks;

 

   

a tax sharing agreement pursuant to which we will reimburse Alon Energy for our share of state and local income and other taxes borne by Alon Energy as a result of our results being included in a combined or consolidated tax return filed by Alon Energy with respect to taxable periods including or beginning on the closing date of this offering;

 

   

a 20-year fuel supply agreement with Alon Energy under which we will supply substantially all of the motor fuel requirements of Alon Energy’s retail convenience stores; and

 

   

a 20-year asphalt supply agreement with Alon Energy.

For a more detailed description of these agreements, see “Certain Relationships and Related Party Transactions—Agreements with Alon Energy” beginning on page 114.

 

   

We will issue to Alon Energy 52,500,000 common units, representing a 84.0% limited partner interest in us (assuming the underwriters do not exercise their option to acquire additional common units).

 

   

On the closing date of this offering, we will issue and sell 10,000,000 common units to the public in this offering and pay related underwriting discounts and commissions and all related transaction costs in connection with this offering.

 

   

We will use the net proceeds from the sale of 10,000,000 common units in this offering to repay approximately $183.0 million of principal and accrued interest relating to intercompany debt payable by our subsidiaries to Alon Energy and its affiliates. We expect that the remaining balance of the intercompany debt will be eliminated prior to closing.

 

   

We will assume from Alon Energy a fully drawn $250.0 million term loan facility, which we refer to as our “new term loan facility.” We expect that the new term loan facility will be guaranteed by Alon Energy and that Alon Energy will be released from all of its obligations thereunder other than with respect to its obligations as a guarantor.

See “Use of Proceeds” beginning on page 46.

We refer to the above transactions throughout this prospectus as the “IPO Transactions.”

We have granted the underwriters a 30-day option to purchase up to an aggregate of 1,500,000 additional common units. Any net proceeds received from the exercise of this option will be distributed to Alon Energy. The number of common units to be issued to Alon Energy above includes 1,500,000 common units that will be issued at the expiration of the underwriters’ option to purchase additional common units if the underwriters do not exercise their option. Any common units that would have been sold to the underwriters had they exercised the option in full will be issued to Alon Energy at the expiration of the option period. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding, but if the underwriters’ option is not exercised in full, Alon Energy’s limited partner interest in us will increase.

 

 

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Organizational Structure

The following chart illustrates our organizational structure after giving effect to the IPO Transactions (assuming the underwriters’ option to purchase additional common units is not exercised):

 

LOGO

 

 

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The Offering

 

Issuer

Alon USA Partners, LP

 

Common units offered

10,000,000 common units

 

Over-allotment option

We have granted the underwriters a 30-day option to purchase up to an aggregate of 1,500,000 additional common units. Any common units not purchased pursuant to the over-allotment option will be issued to Alon Energy.

 

Use of proceeds

We intend to use the estimated net proceeds of approximately $183.0 million from this offering (based on an assumed initial offering price of $20.00 per common unit), after deducting the estimated underwriting discount and offering expenses, to repay approximately $183.0 million of principal and accrued interest outstanding as of September 30, 2012 relating to intercompany debt payable by our subsidiaries to Alon Energy and its affiliates. We expect that the remaining balance of the intercompany debt will be eliminated prior to closing.

 

  The net proceeds from any exercise of the underwriters’ option to purchase additional common units (approximately $27.9 million based on an assumed initial offering price of $20.00 per common unit, if exercised in full) will be distributed to Alon Energy in whole or in part as reimbursement for certain pre-formation capital expenditures.

 

  Please read “Use of Proceeds” beginning on page 46.

 

Cash distributions

Within 60 days after the end of each quarter, beginning with the quarter ending December 31, 2012, we expect to make distributions to unitholders of record on the applicable record date. We expect our first distribution will include available cash (as described below) for the period from the closing of this offering through December 31, 2012.

 

  The board of directors of our general partner will adopt a policy pursuant to which distributions for each quarter will be in an amount equal to the available cash we generate in such quarter. Available cash for each quarter will be determined by the board of directors of our general partner following the end of such quarter. We expect that available cash for each quarter will generally equal our cash flow from operations for the quarter, less cash needed for maintenance capital expenditures, accrued but unpaid expenses, reimbursement of expenses incurred by our general partner and its affiliates, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, including reserves for turnarounds, catalyst replacement and related expenses.

 

 

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  We do not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution or to otherwise reserve cash for distributions, and we do not intend to incur debt to pay quarterly distributions. We expect to finance substantially all of our growth externally, either by debt issuances or additional issuances of equity. We intend to reserve amounts each quarter in order to fund capital expenditures associated with our major turnaround and catalyst replacements.

 

  Because our policy will be to distribute an amount equal to all available cash we generate each quarter, our unitholders will have direct exposure to fluctuations in the amount of cash generated by our business. We expect that the amount of our quarterly distributions, if any, will vary based on our operating cash flow during such quarter. As a result, our quarterly distributions, if any, will not be stable and will vary from quarter to quarter as a direct result of variations in, among other factors, (i) our operating performance, (ii) cash flows caused by, among other things, fluctuations in the prices of crude oil and other feedstocks and the prices we receive for finished products, working capital needs or capital expenditures and (iii) cash reserves deemed necessary or appropriate by the board of directors of our general partner. Such variations in the amount of our quarterly distributions may be significant. Unlike most publicly traded partnerships, we will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. The board of directors of our general partner may change our distribution policy at any time. Our partnership agreement does not require us to pay distributions to our unitholders on a quarterly or other basis.

 

  Based upon our forecasted results for the twelve months ending September 30, 2013, and assuming the board of directors of our general partner declares distributions in accordance with our cash distribution policy, we expect that our aggregate distributions for the twelve months ending September 30, 2013 will be approximately $325.0 million, or $5.20 per common unit, including special turnaround reserve and wholesale business rebranding expenses of approximately $14.1 million. See “Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2013” beginning on page 54.

 

 

Unanticipated events may occur which could materially adversely affect the actual results we achieve during the forecast periods. Consequently, our actual results of operations, cash flows, financial condition and our need for cash reserves during the forecast periods may vary from the forecast, and such variations may be material. Prospective investors are cautioned not to place undue reliance on our forecast and should make their own independent assessment of our future results of operations, cash flows and financial condition. In addition, the board of directors of our general partner may be required to, or elect to, reduce or eliminate our distributions at any time during

 

 

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periods of high prices for refinery feedstocks, such as crude oil, and/or reduced prices or demand for our refined products, among other reasons. See “Risk Factors” beginning on page 18.

 

Subordinated units

None.

 

Incentive Distribution Rights

None.

 

Issuance of additional units

Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our unitholders.

 

  Please read “Units Eligible for Future Sale” beginning on page 141 and “The Partnership Agreement—Issuance of Additional Partnership Interests” beginning on page 130.

 

Limited voting rights

Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 66 2/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, Alon Energy will own an aggregate of 84.0% of our common units (or 81.6% of our common units if the underwriters exercise their option to purchase additional common units in full). This will give Alon Energy the ability to prevent the removal of our general partner. Please read “The Partnership Agreement—Voting Rights” beginning on page 128.

 

Limited call right

If at any time our general partner and its affiliates (including Alon Energy) own more than 90% of the units, our general partner will have the right, but not the obligation, to purchase all, but not less than all, of the units held by unaffiliated unitholders at a price not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding units, the ownership threshold to exercise the call right will be permanently reduced to 80%. See “The Partnership Agreement—Call Right” beginning on page 136.

 

Estimated ratio of taxable income to distributions

We estimate that if you own the common units you purchase in this offering through December 31, 2015, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be approximately 50% of the cash distributed to you. Because of the nature of our business and the expected variability of our quarterly distributions, however, the ratio of our taxable income to distributions may vary significantly from one year to another. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions” beginning on page 145.

 

 

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Material federal income tax consequences

For a discussion of the material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material U.S. Federal Income Tax Consequences” beginning on page 143.

 

Exchange listing

Our common units have been approved for listing on the New York Stock Exchange (the “NYSE”) under the symbol “ALDW,” subject to official notice of issuance.

 

 

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Summary Historical Combined and Pro Forma Combined Financial and Operating Data

The summary historical combined financial and other information presented as of September 30, 2012 and December 31, 2010 and 2011 and for the nine months ended September 30, 2011 and 2012 and the years ended December 31, 2009, 2010 and 2011 have been derived from the audited and unaudited financial statements included elsewhere in this prospectus. The summary historical combined financial and other information presented as of December 31, 2009 have been derived from audited financial statements and as of September 30, 2011 have been derived from unaudited financial statements not included in this prospectus. These combined financial statements relate to the operating subsidiaries of Alon Energy that will be transferred to Alon USA Partners, LP upon the closing of this offering, which we refer to as “Alon USA Partners, LP Predecessor.”

Our combined financial statements included elsewhere in this prospectus include certain costs of Alon Energy that were incurred on our behalf. These costs, which are reflected in selling, general and administrative expenses and direct operating expenses include an allocation of costs and certain other amounts in order to account for a reasonable share of Alon Energy’s total expenses, so that the accompanying combined financial statements reflect substantially all of our costs of doing business. The amounts charged or allocated to us were determined by Alon Energy and are not necessarily indicative of the costs that we would have incurred had we operated as a stand-alone company for all periods presented.

The historical data presented below has been derived from financial statements that have been prepared using GAAP. This data should be read in conjunction with, and is qualified in its entirety by reference to, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the combined financial statements of Alon USA Partners, LP Predecessor and related notes included elsewhere in this prospectus.

Our results of operations for 2009 and 2010 were affected by decreased utilization of the refinery as a result of a February 2008 fire and other scheduled and unscheduled downtime during 2009 and 2010. For more information on the downtime of the Big Spring refinery in 2008, 2009 and 2010, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Comparability of Our Historical Results—Decreased Utilization of Refinery due to February 2008 Fire and Other Downtime.”

 

 

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The pro forma financial and operating information presented below as of and for the nine months ended September 30, 2012 and for the year ended December 31, 2011 was derived from the unaudited pro forma combined financial statements of Alon USA Partners, LP included elsewhere in this prospectus. Our unaudited pro forma combined financial information gives pro forma effect to the IPO Transactions described under “—The IPO Transactions.”

 

     Alon USA Partners, LP Predecessor Historical Combined              
     Year Ended December 31,     Nine Months Ended
September 30,
    Alon USA Partners, LP
      Pro Forma Combined      
 
     2009     2010     2011     2011     2012     Year Ended
December 31,
2011
    Nine Months
Ended
September 30,
2012
 
                       (unaudited)     (unaudited)  
     (dollars in thousands)  

Statements of Operations

Data(1):

   

           

Net sales

   $ 1,498,176      $ 1,639,935      $ 3,207,969      $ 2,351,481      $ 2,651,191      $ 3,207,969      $ 2,651,191   

Total operating costs and expenses

     1,541,574        1,647,662        2,877,177        2,075,291        2,351,958        2,877,177        2,351,958   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Gain on disposition of assets

     2,105        —          —          10        —          —          —     
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

     (41,293     (7,727     330,792        276,200        299,233        330,792        299,233   

Interest expense

     (8,171     (13,314     (16,719     (12,305     (15,070     (41,802     (33,883

Interest expense-related parties

     (17,067     (17,067     (17,067     (12,800     (12,990     —          —     

Other income (loss), net

     183        (269     18        —          11        18        11   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before state income tax expense

     (66,348     (38,377     297,024        251,095        271,184        289,008        265,361   

State income tax expense

     —          136        2,597        2,153        2,518        2,597        2,518   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ (66,348   $ (38,513   $ 294,427      $ 248,942      $ 268,666      $ 286,411      $ 262,843   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Statements of Cash Flow
Data:

  

           

Net cash provided by (used in):

              

Operating activities

   $ (29,108   $ 60,139      $ 258,575      $ 165,587      $ 363,616       

Investing activities

     (19,634     (25,562     (19,545     (17,996     (25,455    

Financing activities

     47,812        (15,338     (123,437     (23,197     (444,692    

Capital expenditures

     (46,688     (15,411     (12,460     (11,090     (17,328    

Capital expenditures for turnarounds and catalyst replacement

     (9,176     (10,151     (7,085     (6,916     (8,127    

Depreciation and amortization

     36,651        39,570        40,448        30,206        34,963        $ 34,963   

Balance Sheet Data:

              

Cash and cash equivalents

   $ 1,113      $ 20,352      $ 135,945      $ 144,746      $ 29,414        $ 29,414   

Property, plant and equipment, net

     531,307        512,169        493,970        499,882        485,115          485,115   

Total assets

     659,134        675,039        810,480        849,483        739,520          751,270   

Total debt

     387,459        438,526        533,592        526,326        430,582          334,000   

Partners’ equity

     96,315        9,664        102,689        160,444        45,235          153,567   

Other financial
information:

  

           

Adjusted EBITDA(2)

   $ (6,564   $ 31,574      $ 371,258      $ 306,396      $ 334,207      $ 371,258      $ 334,207   

 

 

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     Alon USA Partners, LP Predecessor Historical Combined  
     Year Ended December 31,     Nine Months Ended
September 30,
 
     2009     2010     2011     2011     2012  
                       (unaudited)  
     (dollars in thousands, except per unit data)  

Operating Data:

          

Refinery Throughput (bpd):

          

WTS crude

     48,340        39,349        51,202        48,882        53,297   

WTI crude

     9,238        7,288        10,023        9,845        12,790   

Blendstocks

     2,292        2,391        2,389        2,162        1,797   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total refinery throughput(3)

     59,870        49,028        63,614        60,889        67,884   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Refinery Production:

          

Gasoline

     26,826        24,625        31,105        28,969        33,653   

Diesel/jet

     19,136        15,869        20,544        19,704        22,234   

Asphalt

     5,289        2,827        4,539        4,505        4,241   

Petrochemicals

     2,928        2,939        3,837        3,664        4,005   

Other

     5,327        2,341        3,488        3,837        3,627   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total refinery production(4)

     59,506        48,601        63,513        60,679        67,760   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Key Operating Statistics:

          

Refinery utilization

     82.3     68.2     90.8     88.3     97.3

Per barrel of throughput:

          

Refinery operating margin(5)

   $ 4.57      $ 7.64      $ 20.89      $ 23.57      $ 22.88   

Refinery direct operating expense(6)

   $ 4.12      $ 5.05      $ 4.23      $ 4.40      $ 3.92   

 

(1) Net loss per unit information is not presented as such information is not required by Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) topic 260, Earnings per share.
(2) See “—Non-GAAP Financial Measure” for a definition of Adjusted EBITDA.
(3) Total refinery throughput represents the total barrels per day of crude oil and blendstock inputs in the refinery production process.
(4) Total refinery production represents the barrels per day of various refined products produced from processing crude and other refinery feedstocks through the crude units and other conversion units.
(5) Refinery operating margin is a per barrel measurement calculated by dividing the margin between net sales and cost of sales by the refinery’s throughput volumes. Industry-wide refining results are driven and measured by the margins between refined product prices and the prices for crude oil, which are referred to as crack spreads. We compare our refinery operating margin to these crack spreads to assess our operating performance relative to other participants in our industry.
(6) Refinery direct operating expense is a per barrel measurement calculated by dividing direct operating expenses by total throughput volumes.

 

 

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Non-GAAP Financial Measure

Adjusted EBITDA represents earnings before state income tax expense, interest expense, depreciation and amortization and gain on disposition of assets. Adjusted EBITDA is not a recognized measurement under GAAP; however, the amounts included in Adjusted EBITDA are derived from amounts included in our combined financial statements. Our management believes that the presentation of Adjusted EBITDA is useful to investors because it is frequently used by securities analysts, investors and other interested parties in the evaluation of companies in our industry. In addition, our management believes that Adjusted EBITDA is useful in evaluating our operating performance compared to that of other companies in our industry because the calculation of Adjusted EBITDA generally eliminates the effects of state income tax expense, interest expense, gain on disposition of assets and the accounting effects of capital expenditures and acquisitions, items that may vary for different companies for reasons unrelated to overall operating performance.

Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations are:

 

   

Adjusted EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;

 

   

Adjusted EBITDA does not reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt;

 

   

Adjusted EBITDA does not reflect changes in or cash requirements for our working capital needs; and

 

   

Our calculation of Adjusted EBITDA may differ from Adjusted EBITDA calculations of other companies in our industry, limiting its usefulness as a comparative measure.

Because of these limitations, Adjusted EBITDA should not be considered a measure of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using Adjusted EBITDA only supplementally.

The following table reconciles net income (loss) to Adjusted EBITDA for the years ended December 31, 2009, 2010 and 2011 and the nine months ended September 30, 2011 and 2012 as well as the year ended December 31, 2011 and the nine months ended September 30, 2012 on a pro forma basis:

 

    Alon USA Partners, LP Predecessor Historical Combined              
    Year Ended December 31,     Nine Months Ended
September 30,
    Alon USA Partners, LP
      Pro Forma Combined      
 
    2009     2010     2011     2011     2012     Year Ended
December 31,
2011
    Nine Months
Ended
September 30,
2012
 
                      (unaudited)     (unaudited)  
    (in thousands)  

Net income (loss)

  $ (66,348   $ (38,513   $ 294,427        $248,942      $ 268,666      $ 286,411      $ 262,843   

State income tax expense

    —          136        2,597        2,153        2,518        2,597        2,518   

Interest expense

    25,238        30,381        33,786        25,105        28,060        41,802        33,883   

Depreciation and amortization

    36,651        39,570        40,448        30,206        34,963        40,448        34,963   

Gain on disposition of assets

    (2,105     —          —          (10)        —          —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  $ (6,564   $ 31,574      $ 371,258      $ 306,396      $ 334,207      $ 371,258      $ 334,207   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

 

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RISK FACTORS

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

If any of the following risks were to occur, our business, financial condition, results of operations and cash available for distribution could be materially adversely affected. In that case, we might not be able to make distributions on our common units, the trading price of our common units could decline, and you could lose all or part of your investment.

Risks Inherent in Our Business

We may not have sufficient available cash to pay any quarterly distribution on our common units.

We may not have sufficient available cash each quarter to enable us to pay any distributions to our unitholders. The amount we will be able to distribute on our common units principally depends on the amount of cash we generate from our operations, which is primarily dependent upon operating margins. Our operating margins, and thus, the cash we generate from operations have been volatile, and we expect that they will fluctuate from quarter to quarter based on, among other things:

 

   

the cost of refining feedstocks, such as crude oil, that are processed and blended into refined products;

 

   

the prices at which we are able to sell refined products;

 

   

the level of our direct operating expenses, including expenses such as maintenance and energy costs;

 

   

seasonality and weather conditions;

 

   

overall economic and local market conditions; and

 

   

non-payment or other non-performance by our customers and suppliers.

The actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

 

   

our operating margins;

 

   

the level of capital expenditures we make;

 

   

our debt service requirements;

 

   

the amount of any accrued but unpaid expenses;

 

   

the amount of any reimbursement of expenses incurred by our general partner and its affiliates;

 

   

fluctuations in our working capital needs;

 

   

our ability to borrow funds and access capital markets;

 

   

planned and unplanned maintenance at our facility that, based on determinations by the board of directors of our general partner to maintain reserves, may negatively impact our cash flows in the quarter in which such maintenance occurs;

 

   

restrictions on distributions and on our ability to make working capital borrowings; and

 

   

the amount of cash reserves established by our general partner, including for turnarounds, catalyst replacement and related expenses.

 

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Our partnership agreement will not require us to pay a minimum quarterly distribution. The amount of distributions that we pay, if any, and the decision to pay any distribution at all, will be determined by the board of directors of our general partner. Our quarterly distributions, if any, will be subject to significant fluctuations based on the above factors.

For a description of additional restrictions and factors that may affect our ability to pay distributions, see “Cash Distribution Policy and Restrictions on Distributions.”

The price volatility of crude oil and other feedstocks and refined products may have a material adverse effect on our earnings, profitability and cash flows, and our ability to make distributions to unitholders.

Our earnings, profitability, cash flows from operations and our ability to make distributions to unitholders depend primarily on the margin between refined product prices and the prices for crude oil and other feedstocks. When the margin between refined product prices and crude oil and other feedstock prices contracts or inverts, as has been the case in recent periods and may be the case in the future, our results of operations 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. The direction and timing of changes in prices for crude oil and refined products do not necessarily correlate with one another, and it is the relationship between such prices that has the greatest impact on our results of operations and cash flows. For example, from January 2007 to September 2012, the price for NYMEX Cushing WTI crude oil fluctuated between $31.27 and $145.31 per barrel and the price for Midland WTS crude oil fluctuated between $31.27 and $145.31 per barrel, while the price for U.S. Gulf Coast conventional gasoline fluctuated between $32.27 per barrel and $199.34 per barrel. While an increase or decrease in the price of crude oil may result in a similar increase or decrease in prices for refined products, there may be a time lag in the realization, if any, of the similar increase or decrease in prices for refined products over the long term. The effect of changes in crude oil prices on our refining margins therefore depends in part on how quickly and how significantly refined product prices adjust to reflect these changes.

Prices of crude oil and other feedstocks, and the relationships between such prices and prices for refined products, depend on numerous factors beyond our control, including the supply of and demand for crude oil, other feedstocks, gasoline, diesel, asphalt and other refined products and the relative magnitude and timing of such changes. Such supply and demand are affected by, among other things:

 

   

changes in general economic conditions;

 

   

changes in the underlying demand for our products;

 

   

the availability, costs and price volatility of crude oil, other refinery feedstocks and refined products;

 

   

worldwide political conditions, particularly in significant oil producing regions such as the Middle East, West Africa and Latin America;

 

   

the level of foreign and domestic production of crude oil and refined products and the volume of crude oil, feedstock and refined products imported in the United States;

 

   

the ability of the Organization of Petroleum Exporting Countries (“OPEC”) to affect oil prices and maintain production controls;

 

   

the actions of customers and competitors;

 

   

disruptions due to equipment interruption, pipeline disruptions or failure at our or third-party facilities and other factors affecting transportation infrastructure;

 

   

the effects of transactions involving forward contracts and derivative instruments and general commodities speculation;

 

   

the execution of planned capital projects, including the build out of additional pipeline infrastructure;

 

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the effects of and cost of compliance with current and future state and federal environmental, economic, safety and other laws, policies and regulations;

 

   

operating hazards, natural disasters, casualty losses and other matters beyond our control;

 

   

the impact of global economic conditions, including the current European financial crisis, on our business; and

 

   

the development and marketing of alternative and competing fuels.

Although we continually analyze our operating margins and seek to adjust throughput volumes and product slates to optimize our operating results based on market conditions, there are inherent limitations on our ability to offset the effects of adverse market conditions. For example, reductions in throughput volumes in a negative operating margin environment may reduce operating losses, but it would not eliminate them because we would still be incurring fixed costs and certain levels of variable costs.

The price volatility of crude oil and refined products will affect the market value of our inventories, which could have a material adverse effect on our ability to make distributions to unitholders.

The nature of our business has historically required us to maintain substantial quantities of crude oil and refined product inventories. Because crude oil and refined products are essentially commodities, we have no control over the changing market value of these inventories. Our inventory is valued at the lower of cost or market value under the last-in, first-out (“LIFO”) inventory valuation methodology. As a result, if the market value of our inventory were to decline to an amount less than our LIFO cost, we would record a write-down of inventory and a non-cash charge to cost of sales. Our investment in inventory is affected by the general level of crude oil prices, and significant increases in crude oil prices could result in substantial working capital requirements to maintain inventory volumes. Changes in the value of our inventory or increases in the amount of our working capital necessary to maintain our inventory volumes could have a material adverse effect on our ability to pay distributions to our unitholders.

The price volatility of fuel and utility services may have a material adverse effect on our earnings, profitability and cash flows, and our ability to make distributions to unitholders.

The volatility in costs of natural gas, electricity and other utility services used by our refinery and other operations affect our operating costs. Utility prices have been, and will continue to be, affected by factors outside our control, such as supply and demand for utility services in both local and regional markets. Future increases in utility prices that result in increased operating costs may have a negative effect on our earnings, profitability and cash flows, and our ability to make distributions to unitholders.

Changes in the WTI–Brent or Cushing WTI–Midland WTS differentials could adversely affect the crude oil cost advantage that has been in our favor, which could negatively affect our profitability.

Our profit margins depend primarily on the spread between the price of crude oil and the price of our refined products. Our ability to purchase and process less expensive crudes, such as WTS and WTI, which currently trade at a considerable discount to imported waterborne crude oils, such as Brent, has provided us with a significant cost advantage relative to many of our competitors. However, between October and November 2011, the WTI spot price increased $22.75 per barrel while the price of Brent crude oil increased only $8.81 per barrel. As a result, the WTI–Brent crude oil price differential narrowed to under $10.13 per barrel. The increase in the WTI spot price was due in part to a perception that that constraints on transportation of crude oil out of the U.S. Midwest were easing. For example, the Seaway Crude Pipeline System, which historically has transported crude oil to Cushing, Oklahoma from the U.S. Gulf Coast, has recently been reversed such that it currently transports crude from Cushing to the U.S. Gulf Coast. The ability to ship crude oil out of Cushing via pipeline, while not eliminating delays in moving WTI crude oil to other markets, is expected to allow WTI and similar inland U.S. crudes to compete directly with the higher-priced waterborne crude oils available on the Gulf Coast. As a result, the price of WTI may be brought more in line with prices for other crude oils trading on the global markets.

 

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Because our refinery is able to process substantial volumes of WTS, our overall feedstock costs are generally lower than those of refineries that lack this capability and therefore must utilize a greater percentage of sweeter crudes such as WTI. Any narrowing of the Cushing WTI–Midland WTS differential in the future would also result in a reduction of our crude oil source cost advantage.

Future declines in the WTI–Brent or Cushing WTI–Midland WTS differentials could adversely impact our earnings and profitability.

The easing of logistical and infrastructure constraints at Cushing, Oklahoma could adversely affect our crude oil cost advantage.

Due to logistical and infrastructure constraints at the Cushing, Oklahoma transport hub, which have resulted in an oversupply of crude oil at Midland, Texas, we have historically been able to purchase WTS and WTI at discounted prices to Cushing. Moreover, by sourcing West Texas crude oils at Midland, we are able to eliminate the cost of transporting crude supply to and from Cushing. If the constraints at Cushing begin to ease due to the building of additional pipeline capacity and logistics assets, the discount at which we source our West Texas crude supply at Midland relative to Cushing may decrease.

The easing of infrastructure constraints in Cushing and other changes in market dynamics could adversely impact our earnings and profitability.

The amount of our quarterly cash distributions, if any, will vary significantly both quarterly and annually and will be directly dependent on the performance of our business. Unlike most publicly traded partnerships, we will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time.

Investors who are looking for an investment that will pay regular and predictable quarterly distributions should not invest in our common units. We expect our business performance will be more volatile, and our cash flows will be less stable, than the business performance and cash flows of most publicly traded partnerships. As a result, our quarterly cash distributions will be volatile and are expected to vary quarterly and annually. Unlike most publicly traded partnerships, we will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. The amount of our quarterly cash distributions will be directly dependent on the performance of our business, which has been historically volatile and seasonal, and which we expect will continue to be volatile and seasonal. Because our quarterly distributions will significantly correlate to the cash we generate each quarter after payment of our fixed and variable expenses, future quarterly distributions paid to our unitholders will vary significantly from quarter to quarter and may be zero. See “Cash Distribution Policy and Restrictions on Distributions.”

The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to make any distributions at all.

The board of directors of our general partner will adopt a cash distribution policy pursuant to which we will distribute all of the available cash we generate each quarter to unitholders of record on a pro rata basis. However, the board may change such policy at any time at its discretion and could elect not to make distributions for one or more quarters. Our partnership agreement does not require us to make any distributions at all. Accordingly, investors are cautioned not to place undue reliance on the permanence of such a policy in making an investment decision. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders.

 

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The assumptions underlying the forecast of available cash that we include in “Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2013” are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

Our forecast of available cash set forth in “Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2013” includes our forecast of results of operations and available cash for the twelve months ending September 30, 2013. The forecast has been prepared by our management. Neither our independent registered public accounting firm nor any other independent accountants have examined, compiled or performed any procedures with respect to the forecast, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and they assume no responsibility for the forecast. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted. If the forecasted results are not achieved, we would not be able to pay the forecasted annual distribution, in which event the market price of the common units may decline materially. Our actual results may differ materially from the forecasted results presented in this prospectus. In addition, based on our historical results of operations, which have been volatile and seasonal, our distributions for the year ended December 31, 2011, on a pro forma basis, would have been significantly less than the distribution we forecast that we will be able to pay for the twelve months ending September 30, 2013. Investors should review the forecast of our results of operations for the twelve months ending September 30, 2013 together with the other information included elsewhere in this prospectus, including “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The pro forma available cash information for the year ended December 31, 2011 and the twelve months ended September 30, 2012 do not necessarily reflect the actual cash that would have been available over the course of those periods.

Our actual cash available for distribution may differ materially from our presentation of pro forma available cash for the year ended December 31, 2011 and the twelve months ended September 30, 2012.

We have included in this prospectus pro forma available cash information for the year ended December 31, 2011 and twelve months ended September 30, 2012 that indicates the amount of cash that we would have had available for distribution during that period on a pro forma basis. This pro forma information is based on numerous estimates and assumptions. Our financial performance, had the IPO Transactions (as set forth in “Prospectus Summary—The IPO Transactions”) occurred at the beginning of such periods, could have been materially different from the pro forma results. Accordingly, investors should review the unaudited pro forma information, including the related footnotes, together with the other information included elsewhere in this prospectus, including “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Our actual results may differ, possibly materially, from those presented in the pro forma available cash information.

For the year ended December 31, 2011, on a pro forma basis, we would not have generated sufficient available cash to have paid the aggregate distributions that we project that we will be able to pay for the twelve months ending September 30, 2013.

We project that we will be able to pay aggregate distributions of $5.20 per unit for the twelve months ending September 30, 2013. In order to pay these projected distributions, we must generate approximately $325.0 million of available cash in the twelve months ending September 30, 2013, including special turnaround reserve and wholesale business rebranding expenses of approximately $14.1 million. However, for the year ended December 31, 2011, on a pro forma basis, we would have generated $307.8 million of available cash. The increase in forecasted available cash for the twelve months ending September 30, 2013 compared to our pro forma available cash for the year ended December 31, 2011 and the twelve months ending September 30, 2012 is

 

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primarily driven by an increase in forecasted refinery utilization. There can therefore be no assurance that we will generate enough available cash to pay distributions of $5.20 per unit, or any distribution at all, with respect to the twelve months ending September 30, 2013, or any future period. For a description of the price assumptions upon which we have based our projected per unit distribution for the twelve months ending September 30, 2013, see “Cash Distribution Policy and Restrictions on Distributions—Forecast Assumptions and Considerations.”

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, comply with certain deadlines related to environmental regulations and standards or pursue our business strategies, any of which could have a material adverse effect on our results of operations or liquidity. 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 our inventory and accounts receivable. Our long-term needs for cash include those to support ongoing capital expenditures for equipment maintenance and upgrades during turnarounds at our refinery and for costs of catalyst replacement and to complete our routine and normally scheduled maintenance, regulatory and security expenditures. For example, we expect to perform our next major turnaround during the first quarter of 2014. We estimate total major turnaround expense at the Big Spring refinery of approximately $23.0 million in the aggregate over a five year turnaround cycle. The refinery is expected to be shut down for a portion of the first quarter of 2014 to complete the turnaround. 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. We may incur substantial compliance costs in connection with any new environmental, health and safety regulations. In addition, the board of directors of our general partner will adopt a distribution policy pursuant to which we will distribute an amount equal to the available cash we generate each quarter to unitholders. As a result, we will need to rely on external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our growth. Our liquidity will affect our ability to satisfy any of these needs. The board of directors of our general partner may change our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay distributions to our unitholders on a quarterly or other basis. See “Cash Distribution Policy and Restrictions on Distributions.”

The recent recession and credit crisis and related turmoil in the global financial system has had and may continue to have an adverse impact on our business, results of operations and cash flows.

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 have in the past, and may in the future, significantly reduced the level of demand for our products, including by consumers and our wholesale customers. In the past, severe reductions in the availability and increases in the cost of credit have adversely affected our ability to fund our operations and operate our refinery at full capacity, and have adversely affected our operating margins. Together, these factors have had and may in the future have an adverse impact on our business, financial condition, results of operations and cash flows.

Our business is indirectly exposed to risks faced by our suppliers, customers and other business partners. The impact on these constituencies of the risks posed by the recent recession and credit crisis and related 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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The dangers inherent in our operations could cause disruptions and could expose us to potentially significant losses, costs or liabilities. We are particularly vulnerable to disruptions in our operations because all of our refining operations are conducted at a single facility.

Our operations are subject to significant hazards and risks inherent in refining operations and in transporting and storing crude oil, intermediate products and refined products. These hazards and risks include, but are not limited to, natural disasters, fires, explosions, pipeline ruptures and spills, third party interference and mechanical failure of equipment at our or third-party facilities, any of which could result in production and distribution difficulties and disruptions, environmental pollution, personal injury or wrongful death claims and other damage to our properties and the properties of others. For example, on February 18, 2008, a fire at the Big Spring refinery destroyed the propylene recovery unit and damaged equipment in the alkylation and gas concentration units, forcing a temporary shutdown. Although the crude unit was restarted in April 2008, repairs and reconstruction continued through the first quarter of 2010. In addition, in 2010, we implemented new operating procedures at the refinery that also resulted in downtime. As a result of the fire in 2008 and subsequent activities, we had significantly lower throughput and net sales in 2009 and 2010 than in 2011. Because all of our refining operations are conducted at a single refinery, any such event at our refinery could significantly disrupt our production and distribution of refined products, and any sustained disruption could have a material adverse effect on our business, financial condition, results of operations and cash flows, and as a result, our ability to make distributions.

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

Our refinery receives a substantial percentage of its crude oil and delivers a substantial percentage of its refined products through pipelines. 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, earthquakes, hurricanes, governmental regulation, terrorism or other third party action. Our prolonged inability to use any of the pipelines that we use to transport crude oil or refined products could have a material adverse effect on our business, results of operations and cash flows.

Our operating results are seasonal and generally lower in the first and fourth quarters of the year.

Demand for gasoline and asphalt products is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and road construction work. As a result, our operating results for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year. This seasonality is most pronounced in our asphalt business.

Our indebtedness could adversely affect our financial condition or make us more vulnerable to adverse economic conditions.

Our level of indebtedness could have significant effects on our business, financial condition and results of operations and cash flows and, consequently, important consequences to your investment in our securities, such as:

 

   

we may be limited in our ability to obtain additional financing to fund our working capital needs, capital expenditures and debt service requirements or our other operational needs;

 

   

we may be limited in our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to make principal and interest payments on our debt;

 

   

we may be unable to refinance our new term loan facility at favorable rates or at all;

 

   

we may be at a competitive disadvantage compared to competitors with less leverage since we may be less capable of responding to adverse economic and industry conditions; and

 

   

we may not have sufficient flexibility to react to adverse changes in the economy, our business or the industries in which we operate.

 

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Our ability to service our indebtedness will depend on our ability to generate cash in the future.

Our ability to make payments on our indebtedness will depend on our ability to generate cash in the future. Our ability to generate cash is subject to general economic and market conditions and financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot assure you that our business will generate sufficient cash to fund our working capital requirements, capital expenditure, debt service and other liquidity needs, which could result in our inability to comply with financial and other covenants contained in our debt agreements, our being unable to repay or pay interest on our indebtedness, and our inability to fund our other liquidity needs. If we are unable to service our debt obligations, fund our other liquidity needs and maintain compliance with our financial and other covenants, we could be forced to curtail our operations, our creditors could accelerate our indebtedness and exercise other remedies and we could be required to pursue one or more alternative strategies, such as selling assets or refinancing or restructuring our indebtedness. However, we cannot assure you that any such alternatives would be feasible or prove adequate.

Covenants in the credit agreements governing our indebtedness could limit our ability to undertake certain types of transactions and adversely affect our liquidity.

The credit agreements governing our indebtedness may contain negative and financial covenants and events of default that may limit our financial flexibility and ability to undertake certain types of transactions. For example, we may be subject to negative covenants that restrict our activities, including restrictions on creating liens, engaging in mergers, consolidations and sales of assets, incurring additional indebtedness, entering into certain lease obligations, making certain capital expenditures, and making certain distributions, debt and other restricted payments, including distributions to our unitholders. Should we desire to undertake a transaction that is prohibited or limited by the credit agreements governing our indebtedness, we may need to obtain the consent of our lenders or refinance our credit facilities. Such consents or refinancings may not be possible or may not be available on commercially acceptable terms, or at all.

Changes in our credit profile could affect our relationships with our suppliers, which could have a material adverse effect on our liquidity and our ability to operate our refinery at full capacity.

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 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 our refinery at full capacity. A failure to operate our refinery at full capacity could adversely affect our profitability and cash flows. Alternatively, these more burdensome payment terms may require us to incur additional indebtedness under our amended and restated revolving credit facility, which could increase our interest expense and adversely affect our cash flows.

Our relationship with Alon Energy and its financial condition subjects us to potential risks that are beyond our control.

Due to our relationship with Alon Energy, adverse developments or announcements concerning Alon Energy could materially adversely affect our financial condition, even if we have not suffered any similar development. For example, Alon Energy will guarantee our new term loan facility. As a result, downgrades of the credit ratings of Alon Energy could increase our cost of capital and collateral requirements, and could impede our access to the capital markets.

The credit and business risk profiles of Alon Energy may be factors considered in credit evaluations of us. This is because we rely on Alon Energy for various services, including management services. Another factor that may be considered is the financial condition of Alon Energy, including the degree of its financial leverage and its dependence on cash flow from us to service its indebtedness. The credit and risk profile of Alon Energy could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability

 

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to raise capital. If we were to seek a credit rating in the future, our credit rating may be adversely affected by the leverage of Alon Energy, as credit rating agencies may consider the leverage and credit profile of Alon Energy and its affiliates because of their ownership interest in and joint control of us and the strong operational links between Alon Energy’s business and us. Any adverse effect on our credit rating would increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which would impair our ability to grow our business and make distributions to unitholders.

On a historical basis, we sold 19.1% and 19.4% of the motor fuels we produced and all of the asphalt we produced to Alon Energy during the year ended December 31, 2011 and the nine months ended September 30, 2012, respectively. In addition, in connection with this offering, we will enter into a 20-year fuel supply agreement with Alon Energy under which we will supply substantially all of the motor fuel requirements of Alon Energy’s retail convenience stores. We will also enter into a 20-year asphalt supply agreement with Alon Energy. For the twelve months ending September 30, 2013, we expect to sell approximately 21% of the motor fuels and all of the asphalt we produce to Alon Energy. Because a significant percentage of our sales are to Alon Energy, adverse developments concerning Alon Energy’s financial condition could result in adverse effects on our net sales. This would in turn adversely affect our profitability and ability to make distributions to unitholders.

Our arrangement with J. Aron exposes us to J. Aron related credit and performance risk.

We have a supply and offtake agreement with J. Aron, who is our largest supplier of crude oil and largest customer of refined products. For the year ended December 31, 2011, we purchased 52.9% of our crude oil from J. Aron and J. Aron accounted for 14.6% of our total sales of refined products. In the future, we could purchase up to 100% of our supply needs from J. Aron pursuant to this agreement. Additionally, we are obligated to repurchase all consigned inventories and certain other inventories upon termination of this agreement, which may be terminated by J. Aron as early as May 31, 2015. Relying on J. Aron’s ability to honor its fuel requirements purchase obligations exposes us to J. Aron’s credit and business risks. An adverse change in J. Aron’s business, results of operations, liquidity or financial condition could adversely affect its ability to perform its obligations, which could consequently have a material adverse effect on our business, results of operations or liquidity and, as a result, our ability to make distributions. In addition, we may be required to use substantial capital to repurchase inventories from J. Aron upon termination of the agreement, which could have a material adverse effect on our financial condition.

Competition in the refining and marketing industry is intense, and an increase in competition in the markets in which we sell our products could adversely affect our earnings and profitability.

We compete with a broad range of companies in our refining and marketing operations. Many of these competitors are integrated, multinational oil companies that are substantially larger than we are. Because of their diversity, integration of operations, larger capitalization, larger and more complex refineries and greater resources, these companies may be better able to withstand disruptions in operations and volatile market conditions, to offer more competitive pricing during times of intense price fluctuations and to obtain crude oil in times of shortage.

We are not engaged in the business of exploration and production of oil and therefore do not produce any of our crude oil or other feedstocks. Certain of our competitors, however, obtain a portion of their feedstocks from company-owned production. Competitors that have their own crude production are at times able to offset losses from refining operations with profits from oil producing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages. In addition, we compete with other industries, such as wind, solar and hydropower that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual customers. If we are unable to compete effectively with these competitors, both within and outside our industry, there could be a material adverse effect on our business, financial condition, results of operations and cash flows.

 

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We may incur significant costs to comply with new or changing environmental laws and regulations.

Our operations are subject to extensive regulatory controls on air emissions, water discharges, waste management and the clean-up of contamination that can require costly compliance measures. If we fail to comply with environmental requirements, we may be subject to administrative, civil and criminal proceedings by state and federal authorities, as well as civil proceedings by environmental groups and other individuals, which could result in substantial fines and penalties against us as well as governmental or court orders that could alter, limit or suspend our operations.

In October 2006, we were contacted by Region 6 of the U.S. Environmental Protection Agency (“EPA”) and invited to enter into discussions under the EPA’s National Petroleum Refinery Initiative (the “Initiative”). This Initiative is a coordinated, integrated compliance and enforcement strategy to address federal Clean Air Act compliance issues at the nation’s largest petroleum refineries, including compliance with New Source Review/Prevention of Significant Deterioration requirements, New Source Performance Standards, Leak Detection and Repair requirements, and National Emission Standards for Hazardous Air Pollutants for Benzene Waste Operations. Since March 2000, at least 31 refining companies (representing over 90% of the U.S. refining capacity) have entered into “global settlements” under the Initiative. In February 2007, we committed in writing to enter into discussions with the EPA regarding our Big Spring refinery and, since that time, have held negotiations with the agency with respect to entering into a global settlement under the Initiative. Based on our on-going negotiations as well as consideration of prior settlements that the EPA has reached with other petroleum refineries under the Initiative, we believe that the EPA will seek relief under any global settlement in the form of the payment of a civil penalty, the installation of air pollution controls, enhanced operations and maintenance programs, and the implementation of environmentally beneficial projects in consideration for a broad release from liability for violations that may have occurred historically at the Big Spring refinery. At this time, while we cannot estimate the cost of any such civil penalties, pollution controls or environmentally beneficial projects, these costs could be significant and could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our Big Spring refinery is one of more than 100 facilities in Texas to receive a Clean Air Act request for information from the EPA relating to the EPA’s disapproval of Texas’ “flexible permit program.” According to the EPA, the Texas flexible permit program and its implementing rule was never approved by the EPA for inclusion in the Texas state clean-air implementation plan and, therefore, emission limitations in Texas flexible permits are not federally enforceable. The EPA indicated that it would consider enforcement against holders of flexible permits that failed to comply with applicable federal requirements on a case-by-case basis. We have agreed to convert the refinery’s non-flexible permit to a federally enforceable non-flexible permit and currently are in the process of such conversion. It is unclear whether we will have any obligation to install new air pollution controls or be assessed civil penalties. On August 13, 2012, the U.S. Fifth Circuit Court of Appeals vacated the EPA’s final rule disapproving Texas’ flexible permit program and remanded the program back to the EPA for further consideration. We are presently assessing our Big Spring refinery’s air emissions permitting alternatives as a result of this ruling.

In addition, new laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement or other developments could require us to make additional unforeseen expenditures. 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. For example, on June 1, 2012, the EPA issued final amendments to the New Source Performance Standards (“NSPS”) for petroleum refineries, including standards for emissions of nitrogen oxides from process heaters and work practice standards and monitoring requirements for flares. EPA has finalized this rule and published it in the Federal Register on September 12, 2012. We are currently evaluating the effect that the NSPS rule may have on our refinery operations. In another example, the EPA has announced plans to propose new “Tier 3” motor vehicle emission and fuel standards sometime in the second half of 2012. We are not able to predict the impact of new or changed laws or regulations or changes in the ways that such laws or regulations are administered, interpreted or enforced but we may incur increased operating costs and capital expenditures to

 

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comply, which could be material. To the extent that the costs associated with meeting any of these requirements are substantial and not adequately provided for, our results of operations and cash flows could suffer.

Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and a reduced demand for our refining services.

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on its findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal Clean Air Act including one rule that requires a reduction in emissions of GHGs from motor vehicles and another rule that requires certain construction and operating permit reviews for GHG emissions from certain large stationary sources. The stationary source final rule addresses the permitting of GHG emissions from stationary sources under the Clean Air Act Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit programs, pursuant to which these permit programs have been “tailored” to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources subject to permitting first and smaller sources subject to permitting later. Facilities required to obtain PSD permits for their GHG emissions will be required to reduce those emissions according to “best available control technology” standards for GHGs. The EPA’s rule relating to emissions of GHGs from large stationary sources of emissions has been subject to a number of legal challenges, with the federal D.C. Circuit Court of Appeals dismissing the challenges to EPA’s tailoring rule on June 26, 2012. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries, on an annual basis, for emissions occurring after January 1, 2010.

In addition, the federal Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or monitoring and reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas produced by our customers, which could reduce demand for our refining services. One or more of these developments could have an adverse effect on our business, financial condition and results of operations.

Finally, it should be noted that 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 and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

We may incur significant costs and liabilities with respect to environmental lawsuits and proceedings and any investigation and remediation of existing and future environmental conditions.

We are currently investigating and remediating, in some cases pursuant to government orders, soil and groundwater contamination at our refinery and terminals arising from our or predecessor operators’ handling of petroleum hydrocarbons and wastes. We have reserved approximately $6.0 million in investigation and remediation expenses over the next 15 years in connection with historical soil and groundwater contamination at our Big Spring refinery and the Abilene, Southlake and Wichita Falls terminals that we acquired from FINA at the time of the Big Spring refinery acquisition. There can be no assurances, however, that costs will be limited to these anticipated amounts. Our handling and storage of petroleum and hazardous substances may lead to additional contamination at our facilities and facilities to which we send or sent wastes or by-products for treatment or disposal, in which case we may be subject to additional cleanup costs, governmental penalties, and third-party suits alleging personal injury and property damage. Joint and several strict liability may be incurred in

 

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connection with such releases of petroleum hydrocarbons, hazardous substances and/or wastes. Although we have sold three of our pipelines and three of our terminals to Holly Energy Partners, L.P. (“HEP”) and two of our pipelines pursuant to a transaction with an affiliate of Sunoco, Inc. (“Sunoco”), we have agreed, subject to certain limitations, to indemnify HEP and Sunoco for costs and liabilities that may be incurred by HEP or Sunoco as a result of environmental conditions existing at the time of the sale, and we will retain these indemnification obligations following the closing of this offering. If we are forced to incur costs or pay liabilities in connection with such releases and contamination or any associated third-party proceedings and investigations, or in connection with any of our indemnification obligations to HEP or Sunoco, such costs and payments could be significant and could adversely affect our business, results of operations and cash flows.

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

From time to time, we have been sued or investigated for alleged violations of worker health and safety, environmental and other laws. If a lawsuit or enforcement proceeding were commenced or resolved against us, we could incur significant costs and liabilities. In addition, our operations require numerous permits and authorizations under environmental and various other 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 worker health and safety. A violation of authorization or permit conditions or of 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 an adverse effect on our business, results of operations, cash flows or ability to make distributions to unitholders.

Renewable fuels mandates may reduce demand for the petroleum fuels we produce, which could have a material adverse effect on our results of operations and financial condition, and our ability to make distributions to our unitholders.

Pursuant to the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007, the EPA has issued Renewable Fuels Standards (“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 obligate refineries like the Big Spring refinery must blend into their finished petroleum fuels increases annually over time until 2022. Although we currently do not purchase renewable identification number credits (“RINS”) for fuel categories on the open market, in the future, we may be required to do so to comply with RFS. We cannot currently predict the future prices of RINS or waiver credits, but the costs to obtain the necessary number of RINS and waiver credits could be material. 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, and on January 21, 2011, EPA extended the maximum allowable ethanol content of 15% to apply to cars and light trucks manufactured since 2001. 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 materially adversely affecting our ability to make distributions.

Terrorist attacks, threats of war or actual war may negatively affect our operations, financial condition, results of operations and prospects.

Terrorist attacks, threats of war or actual war, as well as events occurring in response to or in connection with them, may adversely affect our operations, financial condition, results of operations and prospects. Energy-related assets (which could include refineries, terminals and pipelines such as ours) may be at greater risk of terrorist attacks than other possible targets in the United States. A direct attack on our assets or assets used by us could have

 

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a material adverse effect on our business, financial condition and results of operations. In addition, any terrorist attack, threats of war or actual war could have an adverse impact on energy prices, including prices for our crude oil and refined products, and an adverse impact on the margins from our refining and marketing operations. In addition, disruption or significant increases in energy prices could result in government-imposed price controls.

Our insurance policies do not cover all losses, costs or liabilities that we may experience.

We maintain significant insurance coverage, but it does not cover all potential losses, costs or liabilities. Our property and business interruption insurance policies that cover the Big Spring refinery have a $750 million limit, with a $10 million deductible for physical damage and a 75-day waiting period before losses resulting from business interruptions are recoverable. We are fully exposed to all losses in excess of the applicable limits and sub-limits and for losses due to business interruptions of fewer than 75 days. We could suffer losses for uninsurable or uninsured risks or in amounts in excess of our existing insurance coverage. Our ability to obtain and maintain adequate insurance may be affected by conditions in the insurance market over which we have no control. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

We are exposed to risks associated with the credit-worthiness of the insurer of our environmental policies.

The insurer under two of our environmental policies is The Kemper Insurance Companies, which has been operating under a run-off plan administered by the Illinois Department of Insurance since 2004 and has experienced significant downgrades of its credit ratings in recent years. These two policies are 20-year policies that were purchased to protect us against expenditures not covered by our indemnification agreement with Atofina Petrochemicals, Inc. (“FINA”). Our insurance brokers have advised us that environmental insurance policies with terms in excess of ten years are not currently available and that policies with shorter terms are available only at premiums equal to or in excess of the premiums paid for our policies with Kemper. Accordingly, we are currently subject to the risk that Kemper will be unable to fully comply with its obligations under these policies and that comparable insurance may not be available or, if available, at premiums equal to or in excess of our current premiums with Kemper. However, we have no reason at this time to believe that Kemper will not be able to comply with its obligations under these policies.

If we lose any of our key personnel, our ability to manage our business and continue our growth could be negatively affected.

Our future performance depends to a significant degree upon the continued contributions of our senior management team and key technical personnel. We do not currently maintain key man life insurance with respect to any member of our senior management team. The loss or unavailability to us of any member of our senior management team or a key technical employee could significantly harm us. We face competition for these professionals from our competitors, our customers and other companies operating in our industry. To the extent that the services of members of our senior management team and key technical personnel would be unavailable to us for any reason, we would be required to hire other personnel to manage and operate our company and to develop our products and technology. We cannot assure you that we would be able to locate or employ such qualified personnel on acceptable terms or at all.

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

As of September 30, 2012, Alon Energy employed approximately 190 people at our Big Spring refinery, approximately 120 of whom were covered by a collective bargaining agreement. The collective bargaining agreement expires in March 2015. The current labor agreement may not prevent a strike or work stoppage in the future, and any such work stoppage could have a material adverse effect on our results of operation and financial condition.

We may not be able to successfully execute our strategy of growth through acquisitions.

A component of our growth strategy is to selectively pursue accretive acquisitions within our refining and wholesale marketing assets, both in our existing areas of operations as well as in new geographic regions that

 

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would diversify our operating footprint. Our ability to do so will be dependent upon a number of factors, including our ability to identify acceptable acquisition candidates, consummate acquisitions on favorable 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:

 

   

diversion of management time and attention from our existing business;

 

   

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

 

   

difficulties in integrating the financial, technological and management standards, processes, procedures and controls of an acquired business with those of our existing operations;

 

   

our ability to understand and capitalize on supply/demand balances in the markets of such acquired assets;

 

   

liability for known or unknown environmental conditions or other contingent liabilities not covered by indemnification or insurance;

 

   

greater than anticipated expenditures required for compliance with environmental or other regulatory standards or for investments to improve operating results;

 

   

difficulties in achieving anticipated operational improvements;

 

   

incurrence of additional indebtedness to finance acquisitions or capital expenditures relating to acquired assets; and

 

   

issuance of additional equity, which could result in further dilution of the ownership interest of existing unitholders.

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.

The wholesale fuel distribution industry is characterized by intense competition and fragmentation and our failure to effectively compete could adversely affect our business and results of operations.

The market for distribution of wholesale motor fuel is highly competitive and fragmented. We have numerous competitors, some of which have significantly greater resources and name recognition than us. We rely on our ability to provide reliable supply and value-added services and to control our operating costs in order to maintain our margins and competitive position. If we were to fail to maintain the quality of our services, customers could choose alternative distribution sources and our competitive position could be adversely affected. Furthermore, we compete against major oil companies with integrated marketing businesses. Through their greater resources and access to crude oil, these companies may be better able to compete on the basis of price or offer lower wholesale and retail pricing which could negatively affect our fuel margins. The occurrence of any of these events could have a material adverse effect on our business and results of operations.

Our commodity derivative contracts may limit our potential gains, exacerbate potential losses, result in period-to-period earnings volatility and involve other risks.

We may enter into commodity derivatives contracts to mitigate our crack spread risk with respect to a portion of our expected gasoline and diesel production. We enter into these arrangements with the intent to secure a minimum fixed cash flow stream on the volume of products hedged during the hedge term. However, our hedging arrangements may fail to fully achieve these objectives for a variety of reasons, including our failure to have adequate hedging contracts, 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, while intended to reduce the adverse effects of fluctuations in crude oil and refined product prices, such transactions may limit our ability to benefit from favorable changes in margins. In

 

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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 refinery, or those of our suppliers or customers;

 

   

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

 

   

a sudden, unexpected event materially impacts the commodity or crack spread subject to the hedging arrangement.

As a result, the effectiveness of our risk mitigation strategy could have a material adverse impact on our financial results and our ability to make distributions. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk.”

The adoption of regulations implementing recent financial reform legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices.

The U.S. Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act in 2010 (the “Dodd-Frank Act”). This comprehensive financial reform legislation establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the Commodity Futures Trading Commission (“CFTC”), the SEC and other regulators to promulgate rules and regulations implementing the new legislation. The CFTC has adopted regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or derivative instruments would be exempt from these position limits. The Dodd-Frank Act may also require compliance with margin requirements and with certain clearing and trade-execution requirements in connection with certain derivative activities, although the application of those provisions to us is uncertain at this time. The legislation may also require certain counterparties to our commodity derivative contracts to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty, or cause the entity to comply with the capital requirements, which could result in increased costs to counterparties such as us. The final rules will be phased in over time according to a specified schedule which is dependent on finalization of certain other rules to be promulgated by the CFTC and the SEC.

The Dodd-Frank Act and any new regulations could significantly increase the cost of some commodity derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of some commodity derivative contracts, reduce the availability of some derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing commodity derivative contracts and potentially increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and any new regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to make distributions or plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd- Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. If the Dodd-Frank Act and any new regulations result in lower commodity prices, our net sales could be adversely affected. Any of these consequences could adversely affect our business, financial condition and results of operations and therefore could have an adverse effect on our ability to make distributions.

 

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Our historical financial statements may not be indicative of future performance.

The historical financial statements presented in this prospectus reflect carve-out financial statements, representing the assets and liabilities that will be transferred to us upon the closing of this offering. The historical combined financial statements reflect intercompany allocations of expenses which may not be indicative of the actual expenses that would have been incurred had we been operating as a company independent from Alon Energy for the periods presented. In addition, our results of operations for periods subsequent to the closing of this offering may not be comparable to our results of operations for periods prior to the closing of this offering as a result of certain transactions undertaken in connection with this offering described in “Prospectus Summary—The IPO Transactions.” See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Comparability of Our Historical Results” for a discussion of factors that affect comparability. As a result, it is difficult to evaluate our historical results of operations to assess our future operating results.

Risks Inherent in an Investment in Us

The board of directors of our general partner will adopt a policy to distribute an amount equal to the available cash we generate each quarter, which could limit our ability to grow and make acquisitions.

The board of directors of our general partner will adopt a policy to distribute an amount equal to the available cash we generate each quarter to our unitholders, beginning with the quarter ending December 31, 2012. As a result, we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund any acquisitions and expansion capital expenditures. As such, to the extent we are unable to finance growth externally, our distribution policy will significantly impair our ability to grow.

In addition, because of our distribution policy, our growth, if any, may not be as robust as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures or as in-kind distributions, current unitholders will experience dilution and the payment of distributions on those additional units will decrease the amount we distribute on each outstanding unit. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, would reduce the available cash that we have to distribute to our unitholders. The board of directors of our general partner may change our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay distributions to our unitholders on a quarterly or other basis. See “Cash Distribution Policy and Restrictions on Distributions.”

Our general partner, an indirect subsidiary of Alon Energy, has fiduciary duties to Alon Energy and its stockholders, and the interests of Alon Energy and its stockholders may differ significantly from, or conflict with, the interests of our public common unitholders.

Our general partner is responsible for managing us. Although our general partner has a duty to manage us in a manner that is in our best interests, its duties are specifically replaced by the express terms of our partnership agreement, and the directors and officers of our general partner also have fiduciary duties to manage our general partner in a manner beneficial to Alon Energy and its stockholders. The interests of Alon Energy and its stockholders may differ from, or conflict with, the interests of our common unitholders. In resolving these conflicts, our general partner may favor its own interests or the interests of Alon Energy and holders of Alon Energy’s common stock, including its controlling stockholder, Alon Israel Oil Company, Ltd. (“Alon Israel”), over our interests and those of our common unitholders.

The potential conflicts of interest include, among others, the following:

 

   

The affiliates of our general partner, including Alon Energy, have fiduciary duties to make decisions in their own best interests and in the best interest of holders of Alon Energy’s common stock, including

 

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Alon Israel, which may be contrary to our interests. In addition, our general partner is allowed to take into account the interests of parties other than us or our unitholders, such as its owners or Alon Energy, in resolving conflicts of interest, which has the effect of limiting its duties to our unitholders.

 

   

Our general partner has limited its liability and duties under our partnership agreement and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under applicable law. As a result of purchasing common units, unitholders consent to certain actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.

 

   

The board of directors of our general partner will determine the amount and timing of asset purchases and sales, capital expenditures, borrowings, repayment of indebtedness and issuances of additional partnership interests, each of which can affect the amount of cash that is available for distribution to our common unitholders.

 

   

Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf. There is no limitation on the amounts our general partner can cause us to pay it or its affiliates.

 

   

Our general partner may exercise its rights to call and purchase all of our common units if at any time it and its affiliates own more than 90% of the common units (if our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding common units, the ownership threshold to exercise the call right will be permanently reduced to 80%).

 

   

Our general partner will control the enforcement of obligations owed to us by it and its affiliates. In addition, our general partner will decide whether to retain separate counsel or others to perform services for us.

 

   

Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.

 

   

The executive officers of our general partner, and the directors of our general partner, also serve as directors and/or executive officers of Alon Energy. The executive officers who work for both Alon Energy and our general partner, including our chief executive officer and chief financial officer, divide their time between our business and the business of Alon Energy. These executive officers will face conflicts of interest from time to time in making decisions which may benefit either us or Alon Energy.

See “Conflicts of Interest and Fiduciary Duties.”

Our partnership agreement restricts the remedies available to us and our common unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under applicable law.

Our partnership agreement limits the liability and duties of our general partner, while also restricting the remedies available to our common unitholders for actions that, without these limitations and reductions, might constitute breaches of fiduciary duty under applicable law. Delaware partnership law permits such contractual limitations of fiduciary duty. By purchasing common units, common unitholders consent to some actions that might otherwise constitute a breach of fiduciary or other duties applicable under state law. Our partnership agreement contains provisions that replace the standards to which our general partner would otherwise be held by state fiduciary duty law. For example:

 

   

Our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to its capacity as general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, our common unitholders. Decisions made by our general partner in its individual capacity will be made by Alon Energy, which owns the sole member of our general partner, and not by the board of directors of our general partner. Examples include the exercise of the general partner’s call right, its voting rights with respect to any common units it may own, its registration rights

 

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and its determination whether or not to consent to any merger or consolidation or amendment to our partnership agreement. In addition, our general partner may decline to undertake any transaction that it believes would materially adversely affect Alon Energy’s ability to continue to comply with the covenants contained in its debt agreements.

 

   

Our partnership agreement provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning it believed that the decisions were not adverse to the interests of the partnership and, except as specifically provided by our partnership agreement, our general partner will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity.

 

   

Our partnership agreement provides that our general partner and the officers and directors of our general partner will not be liable for monetary damages to us for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those persons acted in bad faith or, in the case of a criminal matter, acted with knowledge that such person’s conduct was unlawful.

 

   

Our partnership agreement provides that our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is:

 

   

Approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or

 

   

Approved by the vote of a majority of the outstanding units, excluding any units owned by our general partner and its affiliates.

By purchasing a common unit, a unitholder will become bound by the provisions of our partnership agreement, including the provisions described above. See “Description of the Common Units—Transfer of Common Units.”

Alon Energy has the power to appoint and remove our general partner’s directors.

Upon the consummation of this offering, Alon Energy will have the power to elect all of the members of the board of directors of our general partner. Our general partner has control over all decisions related to our operations. See “Management—Management of Alon USA Partners, LP.” Our public unitholders do not have an ability to influence any operating decisions and will not be able to prevent us from entering into any transactions. Furthermore, the goals and objectives of Alon Energy, as the indirect owner of our general partner, may not be consistent with those of our public unitholders.

Common units are subject to our general partner’s call right.

If at any time our general partner and its affiliates own more than 90% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by public unitholders at a price not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding units, the ownership threshold to exercise the call right will be permanently reduced to 80%. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your common units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and then exercising its call right. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. See “The Partnership Agreement—Call Right.”

 

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Our unitholders have limited voting rights and are not entitled to elect our general partner or our general partner’s directors.

Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right to elect our general partner or our general partner’s board of directors on an annual or other continuing basis. The board of directors of our general partner, including the independent directors, will be chosen entirely by Alon Energy as the indirect owner of the general partner and not by our common unitholders. Unlike publicly traded corporations, we will not hold annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders. Furthermore, even if our unitholders are dissatisfied with the performance of our general partner, they will have no practical ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished.

Our public unitholders will not have sufficient voting power to remove our general partner without Alon Energy’s consent.

Following the closing of this offering, Alon Energy will indirectly own approximately 84.0% of our common units (or approximately 81.6% if the underwriters exercise their option to purchase additional common units in full), which means holders of common units purchased in this offering will not be able to remove the general partner, under any circumstances, unless Alon Energy sells some of the common units that it owns or we sell additional units to the public.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units (other than our general partner and its affiliates and permitted transferees).

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, may not vote on any matter. Our partnership agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the ability of our common unitholders to influence the manner or direction of management.

Cost reimbursements due to our general partner and its affiliates will reduce cash available for distribution to you.

Prior to making any distribution on our outstanding units, we will reimburse our general partner for all expenses it incurs on our behalf including, without limitation, our pro rata portion of management compensation and overhead charged by Alon Energy in accordance with our services agreement. The services agreement does not contain any cap on the amount we may be required to pay pursuant to this agreement. The payment of these amounts, including allocated overhead, to our general partner and its affiliates could adversely affect our ability to make distributions to you. See “Cash Distribution Policy and Restrictions on Distributions,” “Certain Relationships and Related Party Transactions” and “Conflicts of Interest and Fiduciary Duties—Conflicts of Interest.”

Unitholders may have liability to repay distributions and in certain circumstances may be personally liable for the obligations of the partnership.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible

 

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distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

It may be determined that the right, or the exercise of the right by the limited partners as a group, to (i) remove or replace our general partner, (ii) approve some amendments to our partnership agreement or (iii) take other action under our partnership agreement constitutes “participation in the control” of our business. A limited partner that participates in the control of our business within the meaning of the Delaware Act may be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. Please read “The Partnership Agreement—Limited Liability.”

Our general partner’s interest in us and the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest in us to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders, subject to receiving the approval of the lenders under our amended and restated revolving credit facility and new term loan facility, under which our general partner’s general partner interest in us will be pledged. Furthermore, other than any approval required under Alon Energy’s new term loan facility and our amended and restated revolving credit facility, under which the equity interests in our general partner are pledged, there is no restriction in our partnership agreement on the ability of the owners of our general partner to transfer their equity interests in our general partner to a third party. The new equity owner of our general partner would then be in a position to replace the board of directors and the officers of our general partner with its own choices and to influence the decisions taken by the board of directors and officers of our general partner. For additional information, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Liquidity and Capital Resources—Amended and Restated Revolving Credit Facility” and “—New Term Loan Facility.”

If control of our general partner were transferred to an unrelated third party, the new owner of the general partner would have no interest in Alon Energy. We rely substantially on the senior management team of Alon Energy and have entered into a number of significant agreements with Alon Energy, including a services agreement pursuant to which Alon Energy provides us with the services of its senior management team. If our general partner were no longer controlled by Alon Energy, could be more likely to terminate the services agreement which, following the one-year anniversary of the closing date of this offering, it may do upon 180 days’ prior written notice.

There is no existing market for our common units, and we do not know if one will develop to provide you with adequate liquidity. If our unit price fluctuates after this offering, you could lose a significant part of your investment.

Prior to this offering, there has not been a public market for our common units. If an active trading market does not develop, you may have difficulty selling any of our common units that you buy. The initial public offering price for the common units will be determined by negotiations between us and the underwriters and may not be indicative of prices that will prevail in the open market following this offering. Consequently, you may not be able to sell our common units at prices equal to or greater than the price paid by you in this offering. The market price of our common units may be influenced by many factors including:

 

   

our operating and financial performance;

 

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quarterly variations in our financial indicators, such as net (loss) earnings per unit, net earnings (loss) and refinery operating margin;

 

   

the amount of distributions we make and our earnings or those of other companies in our industry or other publicly traded partnerships;

 

   

strategic actions by our competitors;

 

   

changes in earnings or other estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;

 

   

speculation in the press or investment community;

 

   

sales of our common units by us or other unitholders, or the perception that such sales may occur;

 

   

changes in accounting principles;

 

   

additions or departures of key management personnel;

 

   

actions by our unitholders;

 

   

general market conditions, including fluctuations in commodity prices, in particular the differentials between WTI and Brent crude oils; and

 

   

domestic and international economic, legal and regulatory factors unrelated to our performance.

As a result of these factors, investors in our common units may not be able to resell their common units at or above the initial offering price. In addition, the stock market in general has experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of companies like us. These broad market and industry factors may materially reduce the market price of our common units, regardless of our operating performance.

You will incur immediate and substantial dilution in net tangible book value per common unit.

The initial public offering price of our common units is substantially higher than the pro forma net tangible book value of our outstanding units. As a result, if you purchase common units in this offering, you will incur immediate and substantial dilution in the amount of $17.57 per common unit. This dilution results primarily because the assets contributed by Alon Energy and its affiliates are recorded at their historical costs, and not their fair value, in accordance with GAAP. See “Dilution.”

We may issue additional common units and other equity interests without your approval, which would dilute your existing ownership interests.

Under our partnership agreement, we are authorized to issue an unlimited number of additional interests without a vote of the unitholders. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:

 

   

the proportionate ownership interest of unitholders immediately prior to the issuance will decrease;

 

   

the amount of cash distributions on each unit will decrease;

 

   

the ratio of our taxable income to distributions may increase;

 

   

the relative voting strength of each previously outstanding unit will be diminished; and

 

   

the market price of the common units may decline.

In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity interests, which may effectively rank senior to the common units.

 

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Units eligible for future sale may cause the price of our common units to decline.

Sales of substantial amounts of our common units in the public market, or the perception that these sales may occur, could cause the market price of our common units to decline. This could also impair our ability to raise additional capital through the sale of our equity interests.

There will be 62,500,000 common units outstanding following this offering. 10,000,000 common units are being sold to the public in this offering (or 11,500,000 common units if the underwriters exercise their option to purchase additional common units in full) and 52,500,000 common units will be owned indirectly by Alon Energy following this offering (or 51,000,000 common units if the underwriters exercise their option to purchase additional common units in full). The common units sold in this offering will be freely transferable without restriction or further registration under the Securities Act of 1933 (the “Securities Act”) by persons other than “affiliates,” as that term is defined in Rule 144 under the Securities Act.

In addition, under our partnership agreement, our general partner and its affiliates have the right to cause us to register their units under the Securities Act and applicable state securities laws.

In connection with this offering, we, the subsidiary of Alon Energy that will own our common units, our general partner and our general partner’s directors and executive officers will enter into lock-up agreements, pursuant to which they will agree, subject to certain exceptions, not to sell or transfer, directly or indirectly, any of our common units until 180 days from the date of this prospectus, subject to extension in certain circumstances. Following termination of these lockup agreements, all common units indirectly held by Alon Energy, our general partner and their affiliates will be freely tradable under Rule 144, subject to the volume and other limitations of Rule 144. See “Units Eligible for Future Sale.”

We will incur increased costs as a result of being a publicly traded partnership.

As a publicly traded partnership, we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. In addition, the Sarbanes-Oxley Act of 2002 and the Dodd-Frank Act of 2010, as well as rules implemented by the SEC and the NYSE, require, or will require, publicly traded entities to adopt various corporate governance practices that will further increase our costs. Before we are able to make distributions to our unitholders, we must first pay our expenses, including the costs of being a public company and other operating expenses. As a result, the amount of cash we have available for distribution to our unitholders will be affected by our expenses, including the costs associated with being a publicly traded partnership. We estimate that we will incur approximately $1.5 million of estimated incremental costs per year, some of which will be direct charges associated with being a publicly traded partnership, and some of which will be allocated to us by Alon Energy; however, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

Prior to this offering, we have not filed reports with the SEC. Following this offering, we will become subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). We expect these requirements will increase our legal and financial compliance costs and make compliance activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal control over financial reporting. In addition, we will incur additional costs associated with our publicly traded company reporting requirements.

 

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As a publicly traded partnership we qualify for, and are relying on, certain exemptions from the NYSE’s corporate governance requirements.

As a publicly traded partnership, we qualify for, and are relying on, certain exemptions from the NYSE’s corporate governance requirements, including:

 

   

the requirement that a majority of the board of directors of our general partner consist of independent directors;

 

   

the requirement that the board of directors of our general partner have a nominating/corporate governance committee that is composed entirely of independent directors; and

 

   

the requirement that the board of directors of our general partner have a compensation committee that is composed entirely of independent directors.

As a result of these exemptions, our general partner’s board of directors will not be comprised of a majority of independent directors, and our general partner’s board of directors does not currently intend to establish a compensation committee or a nominating/corporate governance committee. Accordingly, unitholders will not have the same protections afforded to equityholders of companies that are subject to all of the corporate governance requirements of the NYSE. See “Management.”

We will be exposed to risks relating to evaluations of controls required by Section 404 of the Sarbanes-Oxley Act.

We are in the process of evaluating our internal controls systems to allow management to report on, and our independent auditors to audit, our internal controls over financial reporting. We will be performing the system and process evaluation and testing (and any necessary remediation) required to comply with the management certification and auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, and under current rules will be required to comply with Section 404 in our annual report for the year ended December 31, 2013. Furthermore, upon completion of this process, we may identify control deficiencies of varying degrees of severity under applicable SEC and Public Company Accounting Oversight Board (“PCAOB”) rules and regulations that remain unremediated. Although we produce our financial statements in accordance with GAAP, our internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. As a publicly traded partnership, we will be required to report, among other things, control deficiencies that constitute a “material weakness” or changes in internal controls that, or that are reasonably likely to, materially affect internal controls over financial reporting. A “material weakness” is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

If we fail to implement the requirements of Section 404 in a timely manner, we might be subject to sanctions or investigation by regulatory authorities such as the SEC. If we do not implement improvements to our disclosure controls and procedures or to our internal controls in a timely manner, our independent registered public accounting firm may not be able to certify as to the effectiveness of our internal controls over financial reporting pursuant to an audit of our internal controls over financial reporting. This may subject us to adverse regulatory consequences or a loss of confidence in the reliability of our financial statements. We could also suffer a loss of confidence in the reliability of our financial statements if our independent registered public accounting firm reports a material weakness in our internal controls, if we do not develop and maintain effective controls and procedures or if we are otherwise unable to deliver timely and reliable financial information. Any loss of confidence in the reliability of our financial statements or other negative reaction to our failure to develop timely or adequate disclosure controls and procedures or internal controls could result in a decline in the price of our common units. In addition, if we fail to remedy any material weakness, our financial statements may be inaccurate, we may face restricted access to the capital markets and the price of our common units may be adversely affected.

 

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It may be difficult to serve process on or enforce a U.S. judgment against certain of our directors.

One of our directors, Mr. D. Wiessman, and all of our director nominees, Messrs. Bader, Biran, S. Wiessman, Raff and Ventura, reside in Israel. In addition, a substantial portion of their assets is located outside of the United States. As a result, you may have difficulty serving legal process within the United States upon such persons. You may also have difficulty enforcing, both in and outside the United States, judgments you may obtain in U.S. courts against such persons in any action, including actions based upon the civil liability provisions of U.S. federal or state securities laws. Furthermore, there is substantial doubt that the courts of the State of Israel would enter judgments in original actions brought in those courts predicated on U.S. federal or state securities laws.

Tax Risks

In addition to reading the following risk factors, please read “Material U.S. Federal Income Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes.

Despite the fact that we are organized as a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe, based upon our current operations, that we will be so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Currently, one such legislative proposal would eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more

 

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difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes.

You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, you will be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from that income.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated as a partnership for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Immediately following this offering, our sponsor will directly and indirectly own more than 50% of the total interests in our capital and profits. Therefore, a transfer by our sponsor of all or a portion of its interests in us could result in a termination of us as a partnership for federal income tax purposes. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, after our termination we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units—Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income result in a decrease in your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture of depreciation and deductions and certain other items. In addition, because the amount realized includes a unitholder’s share of our liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units—Recognition of Gain or Loss” for a further discussion of the foregoing.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investments in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (or “IRAs”), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S.

 

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persons will be reduced by withholding taxes, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their shares of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to you.

The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest by the IRS may materially and adversely impact the market for our common units and the price at which they trade. Our costs of any contest by the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we adopt.

We will prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. Nonetheless, we allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service. The use of this proration method may not be permitted under existing Treasury Regulations, and although the U.S. Treasury Department issued proposed Treasury Regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. Accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.

A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered as having disposed of those common units. If so, he would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner in us with respect to those common units during the period of the loan and the unitholder may recognize gain or loss as if it sold rather than loaned the units subject to such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the

 

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unitholder, and any cash distributions received by the unitholder as to those common units may be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

You will likely be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing in our common units.

In addition to U.S. federal income taxes, you may be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. For example, we will initially own assets and conduct business in the State of Texas, which currently imposes a franchise tax on corporations and other entities. Although Texas does not impose an income tax on nonresident partners of partnerships doing business in Texas, you may be required to file state and local income tax returns in Texas or other states in which we currently conduct business or may conduct business in the future. Further, you may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is your responsibility to file all U.S. federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements contained in this prospectus, or in other written or oral statements made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements relate to matters such as our industry, business strategy, goals and expectations concerning our market position, future operations, margins, profitability, capital expenditures, liquidity and capital resources and other financial and operating information. We have used the words “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “future,” “intend,” “may,” “plan,” “potential,” “predict,” “project” and similar terms and phrases to identify forward-looking statements.

Forward-looking statements reflect our current expectations regarding future events, results or outcomes. These expectations may or may not be realized. Some of these expectations may be based upon assumptions or judgments that prove to be incorrect. In addition, our business and operations involve numerous risks and uncertainties, many of which are beyond our control, which could result in our expectations not being realized or otherwise materially affect our financial condition, results of operations and cash flows.

Actual events, results and outcomes may differ materially from our expectations due to a variety of factors. Although it is not possible to identify all of these factors, they include, among others, the following:

 

   

changes in general economic conditions and capital markets;

 

   

changes in the underlying demand for our products;

 

   

the availability, costs and price volatility of crude oil, other refinery feedstocks and refined products;

 

   

changes in the WTI—Brent or Cushing WTI—Midland WTS differentials;

 

   

actions of customers and competitors;

 

   

changes in fuel and utility costs incurred by our facilities;

 

   

disruptions due to equipment interruption, pipeline disruptions or failure at our or third-party facilities;

 

   

the execution of planned capital projects;

 

   

adverse changes in the credit ratings assigned to our debt instruments or to Alon Energy;

 

   

the effects and cost of compliance with current and future state and federal environmental, economic, safety and other laws, policies and regulations;

 

   

operating hazards, natural disasters, casualty losses and other matters beyond our control;

 

   

the effects of transactions involving forward contracts and derivative instruments;

 

   

the effect of any national or international financial crisis on our business and financial condition; and

 

   

the other factors discussed in this prospectus under the caption “Risk Factors.”

Any one of these factors or a combination of these factors could materially affect our future results of operations and could influence whether any forward-looking statements ultimately prove to be accurate. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward-looking statements. We do not intend to update these statements unless we are required by the securities laws to do so.

 

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USE OF PROCEEDS

Based on an assumed initial offering price of $20.00 per common unit, we expect to receive net proceeds of approximately $183.0 million from the sale of 10,000,000 common units offered by this prospectus, after deducting the estimated underwriting discount and offering expenses payable by us. Each $1.00 increase (decrease) in the public offering price would increase (decrease) our net proceeds by approximately $9.3 million (assuming no exercise of the underwriters’ option to purchase additional common units). Each increase of 1,000,000 common units offered by us, together with a concurrent $1.00 increase in the assumed public offering price to $21.00 per common unit, would increase net proceeds to us from this offering by approximately $28.8 million. Similarly, each decrease of 1,000,000 common units offered by us, together with a concurrent $1.00 decrease in the assumed initial offering price to $19.00 per common unit, would decrease the net proceeds to us from this offering by approximately $27.0 million.

We intend to use the net proceeds of this offering to repay approximately $183.0 million of principal and accrued interest relating to intercompany debt payable by our subsidiaries to Alon Energy and its affiliates.

As of September 30, 2012, we had approximately $346.6 million in intercompany debt payable to Alon Energy and certain of its subsidiaries with a January 2018 maturity and a weighted-average interest rate of approximately 8.0%. It is expected that an additional $51.5 million of intercompany debt payable, which has currently been eliminated in the Alon USA Partners, LP Predecessor combined financial statements, will be transferred to Alon Energy or one of its subsidiaries prior to closing. The transfer will cause the intercompany debt payable to Alon Energy to increase from $346.6 million at September 30, 2012, to approximately $398.1 million. This intercompany debt was incurred to satisfy working capital requirements, fund acquisitions and for general corporate purposes. We expect that the remaining balance of the intercompany debt will be eliminated prior to closing, and we do not expect that we will incur any significant additional intercompany debt following the closing of this offering. In addition, we expect to have approximately $84.0 million and $250 million outstanding under our amended and restated revolving credit facility and new term loan facility following the closing of this offering, respectively. We do not currently expect to draw significant amounts under our amended and restated revolving credit facility following the closing of this offering other than in the ordinary course to fund capital expenditures and our working capital needs. For additional information, please see “Capitalization” and “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Liquidity and Capital Resources.”

The net proceeds from any exercise of the underwriters’ option to purchase additional common units (approximately $27.9 million based on an assumed initial offering price of $20.00 per common unit, if exercised in full) will be distributed to Alon Energy in whole or in part as reimbursement for certain pre-formation capital expenditures. If the underwriters do not exercise their option to purchase additional common units, we will issue 1,500,000 common units to Alon Energy at the expiration of the option period. If and to the extent the underwriters exercise their option to purchase additional common units, the number of units purchased by the underwriters pursuant to such exercise will be issued to the public and the remainder, if any, will be issued to Alon Energy. Accordingly, the exercise of the underwriters’ option will not affect the total number of units outstanding or the amount of cash available to pay distributions on our common units. Please read “Underwriting.”

Certain of the underwriters and their affiliates have engaged, and may in the future engage, in commercial banking, investment banking and advisory services for us, Alon Energy and our respective affiliates from time to time in the ordinary course of their business for which they have received customary fees and reimbursement of expenses. Affiliates of certain of the underwriters are expected to be lenders under our new term loan facility. Certain of the underwriters or their affiliates have performed or will perform commercial banking, investment banking and advisory services for Alon Energy during the 180-day period prior to, or the 90-day period following, the date of this prospectus, for which they have received or will receive customary fees and reimbursement or expenses.

 

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CAPITALIZATION

The following table sets forth our combined cash and cash equivalents and capitalization as of September 30, 2012:

 

   

on an actual basis; and

 

   

on a pro forma basis, to reflect the offering of our common units, the other transactions described under “Prospectus Summary—The IPO Transactions” and the application of the net proceeds from this offering by our general partner as described under “Use of Proceeds.”

This table is derived from, and should be read together with, the unaudited historical and pro forma combined financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Prospectus Summary—The IPO Transactions,” “Use of Proceeds” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

     As of September 30, 2012  
     Actual      Pro Forma  
     (in thousands)  

Cash and cash equivalents

   $ 29,414       $ 29,414   
  

 

 

    

 

 

 

Long-term debt, including current maturities:

     

Revolving credit facility

   $ 84,000       $ 84,000   

Intercompany debt—related parties

     346,582             —     

New term loan facility

         —           250,000   
  

 

 

    

 

 

 

Total long-term debt

     430,582         334,000   
  

 

 

    

 

 

 

Partners’ equity

     45,235         153,567   
  

 

 

    

 

 

 

Total capitalization

   $ 475,817       $ 487,567   
  

 

 

    

 

 

 

 

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DILUTION

Purchasers of common units offered by this prospectus will suffer immediate and substantial dilution in net tangible book value per unit. Our pro forma net tangible book value as of September 30, 2012, excluding the net proceeds of this offering, was approximately $(31.3) million, or approximately $(0.60) per unit. Pro forma net tangible book value per unit gives effect to the pro forma adjustments described in the notes to the unaudited pro forma combined financial statements included elsewhere in this prospectus (other than the issuance of common units in this offering and the receipt of the net proceeds from this offering as described under “Use of Proceeds”) and represents the amount of pro forma tangible assets less pro forma total liabilities (excluding the net proceeds of this offering), divided by the pro forma number of units outstanding (excluding the units issued in this offering).

Dilution in net tangible book value per unit represents the difference between the amount per unit paid by purchasers of our common units in this offering and the pro forma net tangible book value per unit immediately after this offering. After giving effect to the sale of common units in this offering at an initial public offering price of $20.00 per common unit, and after deduction of the estimated underwriting discounts and commissions and estimated offering expenses payable by us, our pro forma net tangible book value as of September 30, 2012 would have been approximately $151.7 million, or $2.43 per unit. This represents an immediate increase in net tangible book value of $3.03 per unit to our existing unitholders and an immediate pro forma dilution of $17.57 per unit to purchasers of common units in this offering. The following table illustrates this dilution on a per unit basis:

 

                 

Assumed initial public offering price per common unit

     $ 20.00   

Pro forma net tangible book value per common unit before this offering(1)

   $ (0.60  

Increase in net tangible book value per common unit attributable to purchasers in this offering and the use of proceeds

     3.03     
  

 

 

   

 

 

 

Less: Pro forma net tangible book value per common unit after this offering(2)

       2.43   
  

 

 

   

 

 

 

Immediate dilution in net tangible book value per common unit to purchasers in this offering(3)

     $ 17.57   
    

 

 

 

 

(1) Determined by dividing the net tangible book value of the contributed assets less total liabilities by the number of common units to be issued to subsidiaries of Alon Energy and its affiliates.
(2) Determined by dividing our pro forma net tangible book value, after giving effect to the use of the net proceeds of the offering by the total number of common units outstanding after this offering.
(3) For each increase (decrease) in the initial public offering price of $1.00 per common unit, dilution in net tangible book value per common unit would increase (decrease) by $1.00 per common unit. Each increase of 1,000,000 common units offered by us, together with a concurrent $1.00 increase in the assumed public offering price to $21.00 per common unit, would increase net proceeds to us from this offering by approximately $28.8 million. Similarly, each decrease of 1,000,000 common units offered by us, together with a concurrent $1.00 decrease in the assumed initial offering price to $19.00 per common unit, would decrease the net proceeds to us from this offering by approximately $27.0 million.

 

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The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner and its affiliates and by the purchasers of our common units in this offering upon consummation of the transactions contemplated by this prospectus:

 

     Units     Total Consideration  
     Number      Percent     Amount     Percent  

Alon Energy

     52,500,000         84.0     (29,400,000 )(1)      (19.2 )% 

New investors

     10,000,000         16.0     183,000,000 (2)      119.2
  

 

 

    

 

 

   

 

 

   

 

 

 

Total

     62,500,000         100   $ 153,600,000        100
  

 

 

    

 

 

   

 

 

   

 

 

 

 

(1) The net assets contributed by Alon Energy were recorded at historical cost in accordance with GAAP. Our partners’ equity, which is the result of contributions by Alon Energy, as of September 30, 2012, was $45.2 million. In addition, Alon Energy will convert $163.6 million of subordinated debt to our partners’ equity and we will assume debt of $250.0 million before debt issuance costs of $11.8 million.
(2) Reflects the net proceeds of this offering after deducting the underwriting discounts and estimated offering expenses payable by us.

If the underwriters exercise their option to purchase 1,500,000 common units in full, then the pro forma increase per unit attributable to new investors would be $0.04, the net tangible book value per unit after this offering would be $151.7 and the dilution per unit to new investors would be $15.91. In addition, new investors would purchase 11,500,000 common units, or approximately 18.4% of units outstanding, and the total consideration contributed to us by new investors would increase to $210.9 million, or 137.3% of the total consideration contributed.

 

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CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy and restrictions on distributions in conjunction with the specific assumptions upon which our cash distribution policy is based. See “—Forecast Assumptions and Considerations” below. For additional information regarding our historical and pro forma operating results, you should refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” our audited historical combined financial statements, our unaudited historical combined financial statements and our unaudited pro forma combined financial statements included elsewhere in this prospectus. In addition, you should read “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

General

Our Cash Distribution Policy

The board of directors of our general partner will adopt a policy pursuant to which we will distribute all of the available cash we generate each quarter, beginning with the quarter ending December 31, 2012. Available cash for each quarter will be determined by the board of directors of our general partner following the end of such quarter. We expect that available cash for each quarter will generally equal our cash flow from operations for the quarter, less cash needed for maintenance capital expenditures, debt service and other contractual obligations, and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, including reserves for our expenses in the quarters in which our planned turnarounds and catalyst replacement occur. We expect to fund scheduled turnarounds and catalyst replacement capital expenditures with cash reserves and borrowings under our credit facilities. In order to fund our major turnaround and catalyst replacement capital expenditures, following the closing of this offering, we expect to reserve approximately $1.2 million per quarter. In addition, we expect to reserve an additional $3.5 million in each of the five quarters beginning with the fourth quarter of 2012 in order to fund our next scheduled major turnaround and catalyst replacement, which is scheduled for the first quarter of 2014. We do not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution or otherwise to reserve cash for distributions, nor do we intend to incur debt to pay quarterly distributions. We expect to finance substantially all of our growth externally, either by debt issuances or additional issuances of equity. We intend to reserve amounts each quarter in order to fund capital expenditures associated with our major turnaround and catalyst replacements.

Because our policy will be to distribute all available cash we generate each quarter, without reserving cash for future distributions or borrowing to pay distributions during periods of low cash flow from operations, our unitholders will have direct exposure to fluctuations in the amount of cash generated by our business. We expect that the amount of our quarterly distributions, if any, will vary based on our operating cash flow during each quarter. Our quarterly cash distributions, if any, will not be stable and will vary from quarter to quarter as a direct result of variations in our operating performance and cash flow caused by fluctuations in our refining margins, which will be affected by prices of feedstock and refined products as well as our working capital requirements and capital expenditures. Such variations may be significant. The board of directors of our general partner may change the foregoing distribution policy at any time and from time to time. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis.

Limitations on Cash Distributions; Our Ability to Change Our Cash Distribution Policy

There is no guarantee that unitholders will receive quarterly cash distributions from us. Our distribution policy may be changed at any time and is subject to certain restrictions, including:

 

   

Our unitholders have no contractual or other legal right to receive cash distributions from us on a quarterly or other basis. The board of directors of our general partner will adopt a policy pursuant to

 

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which we will distribute to our unitholders each quarter all of the available cash we generate each quarter, as determined quarterly by the board of directors, but it may change this policy at any time.

 

   

Our ability to make cash distributions pursuant to our cash distribution policy will be subject to our compliance with our amended and restated revolving credit facility and our new term loan facility, which will contain financial tests and covenants that we must satisfy. Should we be unable to satisfy these financial covenants or if we are otherwise in default under our amended and restated revolving credit facility and our new term loan facility, we will be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy.

 

   

Our business performance is expected to be volatile, and our cash flows are expected to be less stable than the business performance and cash flows of most publicly traded partnerships. As a result, our quarterly cash distributions are expected to vary quarterly and annually. Unlike most publicly traded partnerships, we will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. Furthermore, none of our limited partnership interests, including those indirectly held by Alon Energy, will be subordinate in right of distribution payment to the common units sold in this offering.

 

   

Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.

 

   

We may lack sufficient cash to make distributions to our unitholders due to a number of factors that would adversely affect us, including but not limited to decreases in net sales or increases in operating expenses, principal and interest payments on debt, working capital requirements, capital expenditures or anticipated cash needs. See “Risk Factors” for information regarding these factors.

We do not have any operating history as an independent company upon which to rely in evaluating whether we will have sufficient cash to allow us to pay distributions on our common units. While we believe, based on our financial forecast and related assumptions, that we should have sufficient cash to enable us to pay the forecasted aggregate distribution on all of our common units for the twelve months ending September 30, 2013, we may be unable to pay the forecasted distribution or any amount on our common units.

We expect to pay our distributions within sixty days of the end of each quarter. Our first distribution will include available cash for the period from the closing of this offering through the quarter ending December 31, 2012.

In the sections that follow, we present the following two tables:

 

   

“Alon USA Partners, LP Unaudited Pro Forma Available Cash for Distribution,” in which we present our unaudited estimate of the amount of pro forma available cash we would have had for the year ended December 31, 2011 and the twelve months ended September 30, 2012 had the IPO Transactions described under “Prospectus Summary—The IPO Transactions” been consummated on January 1, 2011, in each case, based on our historical and pro forma combined financial statements included elsewhere in this prospectus; and

 

   

“Alon USA Partners, LP Estimated Cash Available for Distribution,” in which we present our unaudited forecast of cash available for distribution for the twelve months ending September 30, 2013.

We do not as a matter of course make or intend to make projections as to future sales, earnings, or other results. However, our management has prepared the prospective financial information set forth under “—Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2013” below to supplement the historical and pro forma combined financial statements included elsewhere in this prospectus. To management’s knowledge and belief, the accompanying prospective financial information was prepared on a reasonable basis, reflects currently available estimates and judgments, and presents our expected course of action and our expected future financial performance. However, this information is not fact and should not be relied upon as being indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information. Neither our independent registered public accounting firm, nor any other registered public accounting firm, has compiled, examined, or performed any procedures with respect to the

 

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prospective financial information contained in this section, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the prospective financial information. See “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors.”

Unaudited Pro Forma Available Cash

We believe that we would have generated pro forma available cash during the year ended December 31, 2011 and the twelve months ended September 30, 2012 of $307.8 million and $325.1 million, respectively. Based on the cash distribution policy we expect our board of directors to adopt, this amount would have resulted in an aggregate annual distribution equal to $4.92 per common unit for the year ended December 31, 2011 and $5.20 per common unit for the twelve months ended September 30, 2012.

Pro forma available cash reflects the payment of incremental general and administrative expenses we expect that we will incur as a publicly traded limited partnership, such as costs associated with SEC reporting requirements, including annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, Sarbanes-Oxley compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director compensation expenses. We estimate that these incremental general and administrative expenses will be approximately $1.5 million per year. The estimated incremental general and administrative expenses are reflected in our pro forma available cash but are not reflected in our unaudited pro forma combined financial statements.

The unaudited pro forma combined financial statements, from which pro forma available cash is derived, do not purport to present our results of operations had the transactions contemplated below actually been completed as of the date indicated. Furthermore, available cash is a cash accounting concept, while our unaudited pro forma combined financial statements have been prepared on an accrual basis. We derived the amounts of pro forma available cash stated above in the manner described in the table below. As a result, the amount of pro forma available cash should only be viewed as a general indication of the amount of available cash that we might have generated had we been formed and completed the transactions contemplated below in earlier periods.

 

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The following table illustrates, on a pro forma basis for the year ended December 31, 2011, and for the twelve months ended September 30, 2012, the amount of cash that would have been available for distribution to our unitholders, assuming that the IPO Transactions had occurred on January 1, 2011:

Alon USA Partners, LP Unaudited Pro Forma Available Cash for Distribution

 

     Year Ended
December 31,
2011
    Twelve Months
Ended September 30,
2012
 
     (in millions except per unit data)  

Net sales

   $ 3,208.0      $ 3,507.7   

Operating costs and expenses:

    

Cost of sales

   $ 2,722.9      $ 2,988.9   

Direct operating expenses

     98.2        98.3   

Selling, general and administrative expenses

     15.6        21.5   

Depreciation and amortization(a)

     40.4        45.2   
  

 

 

   

 

 

 

Operating income

   $ 330.8      $ 353.8   

Interest expense(b)

     (41.8     (44.5

Interest expense—related parties(c)

     —          —     
  

 

 

   

 

 

 

Income before state income tax expense

   $ 289.0      $ 309.4   

State income tax expense

     (2.6     (3.0
  

 

 

   

 

 

 

Net income

   $ 286.4      $ 306.4   

Adjustments to reconcile net income to Adjusted EBITDA:

    

Interest expense(b)

   $ 41.8      $ 44.5   

Interest expense—related parties(c)

     —          —     

State income tax expense

     2.6        3.0   

Depreciation and amortization(a)

     40.4        45.2   

(Gain) loss on disposition of assets

     —          —     
  

 

 

   

 

 

 

Adjusted EBITDA

   $ 371.3      $ 399.1   
  

 

 

   

 

 

 

Adjusted EBITDA(d)

   $ 371.3      $ 399.1   

Adjustments to reconcile Adjusted EBITDA to pro forma available cash:

    

less: Incremental general and administrative expense(e)

     (1.5     (1.5

less: Capital expenditures

     (12.5     (18.7

less: Turnaround and catalyst replacement capital expenditures(f)

     (7.1     (8.3

less: Turnaround reserve(f)

     —          —     

less: Principal payments(g)

     —          —     

less: Cash interest expense(b)

     (39.8     (42.5

less: Cash interest expense—related parties(c)

     —          —     

less: State income tax expense

     (2.6     (3.0
  

 

 

   

 

 

 

Pro forma available cash

   $ 307.8      $ 325.1   
  

 

 

   

 

 

 

Common units outstanding

     62,500,000        62,500,000   

Pro forma available cash per unit

   $ 4.92      $ 5.20   

 

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(a) Includes amortization expense related to turnarounds and catalyst replacements.
(b) Reflects:
  (i) cash interest expense related to borrowings under our amended and restated revolving credit facility and new term loan facility, costs associated with our letters of credit as well as financing costs associated with crude oil purchases as part of our supply and offtake agreement with J. Aron; and
  (ii) non-cash amortization of $2.0 million associated with debt issuance costs.
(c) Reflects change in interest expense related to the repayment and elimination of intercompany debt. See “—Forecast Assumptions and Considerations—Interest Expense.”
(d) For a description of Adjusted EBITDA, see “Prospectus Summary—Summary Historical Combined and Pro Forma Combined Financial and Operating Data—Non-GAAP Financial Measure.”
(e) Reflects an adjustment to our Adjusted EBITDA for approximately $1.5 million of incremental general and administrative expenses that we expect to incur as a result of operating as a publicly traded partnership, which are not reflected in our unaudited pro forma combined financial statements included elsewhere in this prospectus.
(f) Includes capital expenditures related to annual turnaround and catalyst replacement costs. We expect to maintain quarterly reserves for major turnaround and catalyst replacement capital expenditures. See “—Forecast Assumptions and Considerations—Turnaround and Catalyst Replacement Capital Expenditures and “—Forecast Assumptions and Considerations—Major Turnaround Reserve.”
(g) Reflects amortization payments relating to our new term loan facility.

Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2013

During the twelve months ending September 30, 2013, we estimate that we will generate approximately $325.0 million of cash available for distribution, including special turnaround reserve and wholesale business rebranding expenses of approximately $14.1 million. In “—Forecast Assumptions and Considerations” below, we discuss the major assumptions underlying this estimate. The available cash discussed in the forecast should not be viewed as management’s projection of the actual available cash that we will generate during the twelve months ending September 30, 2013. We can give you no assurance that our assumptions will be realized or that we will generate any available cash, in which event we will not be able to pay quarterly cash distributions on our common units.

When considering our ability to generate available cash and how we calculate forecasted available cash, please keep in mind all the risk factors and other cautionary statements under the headings “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” which discuss factors that could cause our results of operations and available cash to vary significantly from our estimates.

We do not, as a matter of course, make public projections as to future sales, earnings or other results. However, our management has prepared the prospective financial information set forth below in the table entitled “Alon USA Partners, LP Estimated Available Cash for Distribution” to present our expectations regarding our ability to generate approximately $325.0 million of cash available for distribution for the twelve months ending September 30, 2013, including special turnaround reserve and wholesale business rebranding expenses of approximately $14.1 million. The accompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the expected course of action and our expected future financial performance. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on this prospective financial information.

Although the assumptions and estimates underlying the prospective financial information included herein are considered reasonable by the management team of our general partner (all of whom are employed by Alon

 

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Energy), such assumptions and estimates are inherently uncertain and are subject to a wide variety of significant business, economic, and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the prospective financial information. Such risks and uncertainties include risks relating to the volatility of prices of crude oil and other refinery feedstocks, refined product prices and competition within our industry. Accordingly, there can be no assurance that the prospective results are indicative of our future performance or that actual results will not differ materially from those presented in the prospective financial information. Inclusion of the prospective financial information in this prospectus should not be regarded as a representation by any person that the results contained in the prospective financial information will be achieved.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. In light of the above, the statement that we believe that we will have sufficient available cash to allow us to pay the forecasted quarterly distributions on all of our outstanding common units for the twelve months ending September 30, 2013, should not be regarded as a representation by us or the underwriters or any other person that we will make such distributions. Therefore, you are cautioned not to place undue reliance on this information.

The following table shows how we calculate estimated available cash for the twelve months ending September 30, 2013. The assumptions that we believe are relevant to particular line items in the table below are explained in the corresponding footnotes and in “—Forecast Assumptions and Considerations.”

Neither our independent registered public accounting firm, nor any other independent registered public accounting firm, has compiled, examined or performed any procedures with respect to the forecasted financial information contained herein, nor has it expressed any opinion or given any other form of assurance on such information or its achievability, and it assumes no responsibility for such forecasted financial information. Our independent registered public accounting firm’s reports included elsewhere in this prospectus relate to our audited historical combined financial information. These reports do not extend to the tables and the related forecasted information contained in this section and should not be read to do so.

 

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The following table illustrates the amount of cash that we estimate we will generate for the twelve months ending September 30, 2013 and for each quarter during that twelve-month period that would be available for distribution to our unitholders. All of the amounts in the table below are estimates. Refinery operating margin per barrel, refinery direct operating expense per barrel, forecasted Gulf Coast (WTI) 3-2-1 crack spread, forecasted Cushing WTI prices and forecasted Midland WTS—Cushing WTI differentials represent weighted averages estimated over the stated period.

Alon USA Partners, LP Estimated Cash Available for Distribution

 

    Three Months Ending     Twelve  Months
Ending

September 30, 2013
 
    December 31,
2012
    March 31,
2013
    June 30,
2013
    September 30,
2013
   
    (Dollars in millions except per unit and per bbl data)  

Operating data:

         

Refinery feedstocks (bpd):

         

Sour crude oil

    55,204        56,200        56,200        53,652        55,307   

Sweet crude oil

    13,342        10,800        10,800        10,957        11,480   

Other feedstocks/blendstocks

    3,129        2,024        655        728        1,634   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total throughput

    71,675        69,024        67,655        65,337        68,421   

Refinery product yields (bpd):

         

Gasoline

    36,718        34,860        33,210        30,608        33,845   

Diesel/jet fuel

    23,867        22,808        22,842        22,190        22,928   

Asphalt

    4,358        4,815        4,815        4,619        4,651   

Other

    6,789        6,173        6,430        7,686        6,774   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total production

    71,733        68,657        67,297        65,103        68,198   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Refinery operating margin per bbl of throughput(a)

  $ 23.97      $ 20.85      $ 21.83      $ 20.00      $ 21.71   

Refinery direct operating expense per bbl of throughput(a)

  $ 3.98      $ 3.93      $ 4.01      $ 4.15      $ 4.02   

Forecasted Gulf Coast (WTI) 3-2-1 crack spread (per bbl)

  $ 27.91      $ 19.76      $ 22.09      $ 20.46      $ 22.57   

Forecasted Cushing WTI (per bbl)

  $ 89.93      $ 93.44      $ 93.35      $ 92.55      $ 92.31   

Forecasted Cushing WTI—Midland WTS differential (per bbl)

  $ 3.87      $ 4.50      $ 4.50      $ 4.50      $ 4.34   

Statement of operations data:

         

Net sales

  $ 873.1      $ 812.8      $ 815.5      $ 785.1      $ 3,286.5   

Operating costs and expenses:

         

Cost of sales

    715.0        683.2        681.1        664.9        2,744.3   

Direct operating expenses

    26.2        24.4        24.7        24.9        100.3   

Selling, general and administrative expenses

    4.4        4.8        5.4        4.7        19.3   

Depreciation and amortization

    11.7        11.8        12.0        12.1        47.6   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

  $ 115.7      $ 88.5      $ 92.4      $ 78.4      $ 375.0   

Interest expense

    (9.1     (8.7     (8.6     (8.6     (35.0
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income before state income tax expense

  $ 106.6      $ 79.8      $ 83.8      $ 69.8      $ 340.0   

State income tax expense

    (0.9     (0.7     (0.7     (0.6     (3.0
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

  $ 105.7      $ 79.1      $ 83.1      $ 69.2      $ 337.0   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjustments to reconcile net income to Adjusted EBITDA:

         

Interest expense

    9.1        8.7        8.6        8.6        35.0   

State income tax expense

    0.9        0.7        0.7        0.6        3.0   

Depreciation and amortization

    11.7        11.8        12.0        12.1        47.6   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA(b)

  $ 127.4      $ 100.3      $ 104.4      $ 90.5      $ 422.6   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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    Three Months Ending     Twelve  Months
Ending

September 30, 2013
 
    December 31,
2012
    March 31,
2013
    June 30,
2013
    September 30,
2013
   
    (Dollars in millions except per unit and per bbl data)  

Adjustments to reconcile Adjusted EBITDA to estimated cash available for distribution:

         

less: Maintenance/growth capital expenditures

  $ (11.7   $ (6.9   $ (6.9   $ (6.9   $ (32.3

less: Turnaround and catalyst replacement capital expenditures

    —          (2.9     (2.9     (2.9     (8.8

less: Major turnaround reserve

    (1.2     (1.2     (1.2     (1.2     (4.6

less: Principal payments

    —          (0.6     (0.6     (0.6     (1.9

less: State income tax expense

    (0.9     (0.7     (0.7     (0.6     (3.0

less: Interest paid in cash

    (8.6     (8.2     (8.1     (8.2     (33.0
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Estimated cash available for distribution before special expenses

  $ 105.1      $ 79.9      $ 84.0      $ 70.2      $ 339.1   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

less: Special turnaround reserve

    (3.5    
(3.5

    (3.5 )       (3.5 )       (13.8

less: Special wholesale rebranding expenses

    (0.3     —          —          —          (0.3
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Estimated cash available for distribution after giving effect to special expenses

  $ 101.3      $ 76.4      $ 80.5      $ 66.7      $ 325.0   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Estimated cash available for distribution per unit

  $ 1.62      $ 1.22      $ 1.29      $ 1.07      $ 5.20   

Cash distributions to common unitholders after special expenses

  $ 101.3      $ 76.4      $ 80.5      $ 66.7      $ 325.0   

Sensitivity analysis:

         

Changes in estimated cash available for distribution if:

         

$1/bbl increase in Gulf Coast (WTI) 3-2-1 crack spread

  $ 5.6      $ 5.2      $ 5.1      $ 4.9      $ 20.7   

$1/bbl increase in realized crude oil price—Cushing WTI differential

  $ 6.3      $ 6.0      $ 6.1      $ 5.8      $ 24.3   

1,000 bpd increase in throughput

  $ 2.1      $ 1.7      $ 1.8      $ 1.7      $ 7.3   

 

(a) For definitions of refining operating margin per bbl of throughput and refinery direct operating expenses per bbl of throughput, see “Prospectus Summary—Summary Historical Combined and Pro Forma Combined Financial and Operating Data.”
(b) For a description of Adjusted EBITDA, see “Prospectus Summary—Summary Historical Combined and Pro Forma Combined Financial and Operating Data—Non-GAAP Financial Measure.”

 

* Total amounts in the table above may not foot due to rounding.

 

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Forecast Assumptions and Considerations

General

The accompanying financial forecast and specific significant forecast assumptions assume that the IPO Transactions had occurred as of October 1, 2012.

Utilization

Our refinery has a throughput capacity of approximately 70,000 bpd. We have assumed that the refinery will operate at an average total throughput of approximately 68,400 bpd during the twelve months ending September 30, 2013 and have assumed no significant downtime during such period. For the year ended December 31, 2011 and the twelve months ended September 30, 2012, the Big Spring refinery operated at an average total throughput of 63,614 bpd and 68,843 bpd, respectively.

The Big Spring refinery completed a reformer regeneration in April 2012, and the next reformer regeneration is scheduled in the third quarter of 2013. During a reformer regeneration (which typically lasts nine to ten days), the refinery runs at a lower throughput versus its normal capacity. During 2011, the Big Spring refinery ran at lower average throughput due to reformer regeneration and fluid catalytic converter unit work during June and July 2011. Average total throughput from August through December 2011 was 70,300 bpd.

Net Sales

We project net sales of $3.3 billion over the twelve months ending September 30, 2013. During the twelve months ended September 30, 2012 and the year ended December 31, 2011, we generated net sales of $3.5 billion and $3.2 billion, respectively.

Gasoline. We estimate net gasoline sales based on forecast future product prices multiplied by the number of barrels of gasoline we estimate that we will sell during the twelve months ending September 30, 2013. We forecast that we will sell approximately 12.4 million barrels of gasoline at a weighted average price of $110.81 per barrel during the twelve months ending September 30, 2013. We forecast the weighted average selling price of gasoline based on a differential between Gulf Coast gasoline pricing and the realized pricing by our Big Spring refinery. Gulf Coast gasoline pricing is based on a differential between Platts Gulf Coast gasoline and NYMEX RBOB futures. The forecasted differentials are based on historical pricing differentials between NYMEX RBOB, Platts Gulf Coast gasoline and realized pricing by our Big Spring refinery.

For the year ended December 31, 2011, we sold approximately 11.7 million barrels of gasoline at a weighted average price of $115.61 per barrel and realized net gasoline sales of approximately $1.4 billion. For the twelve months ended September 30, 2012, we sold approximately 12.7 million barrels of gasoline at a weighted average price of $119.19 per barrel and realized net gasoline sales of approximately $1.5 billion. Changes in forecasted gasoline sales volumes for the twelve months ending September 30, 2013 are due primarily to changes in forecasted throughput at the refinery period compared to prior periods as described above under “—Utilization.”

Diesel/Jet Fuel. We estimate net diesel/jet fuel sales based on forecast future product prices multiplied by the number of barrels of diesel/jet fuel we estimate that we will produce and sell during the twelve months ending September 30, 2013. We forecast that we will sell approximately 8.4 million barrels of diesel/jet fuel at a weighted average price of $126.35 per barrel during the twelve months ending September 30, 2013. We forecast the weighted average selling price of diesel based on a differential between Gulf Coast ultra-low-sulfur diesel (“ULSD”) and the realized pricing by our Big Spring refinery. The Gulf Coast ULSD pricing is based on a differential between Platts Gulf Coast ULSD and NYMEX Heating Oil futures. The forecast differentials are based on historical pricing differentials between NYMEX Heating Oil, Platts Gulf Coast ULSD and realized pricing by our Big Spring refinery. The forecast weighted average selling price of jet fuel is based on the historical differential to ULSD.

 

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For the year ended December 31, 2011, we sold approximately 7.7 million barrels of diesel/jet fuel at a weighted average price of $124.88 per barrel and realized net diesel/jet fuel sales of approximately $1.1 billion. For the twelve months ended September 30, 2012, we sold approximately 8.2 million barrels of diesel/jet fuel at a weighted average price of $128.16 per barrel and realized net diesel/jet fuel sales of approximately $1.1 billion. Increases in forecasted diesel/jet fuel sales volumes for the twelve months ending September 30, 2013 are due primarily to increases in forecasted throughput at the refinery compared to prior periods as described above under “—Utilization.”

Asphalt. We estimate net asphalt sales based on forecast future product prices multiplied by the number of barrels of asphalt we estimate that we will produce and sell during the twelve months ending September 30, 2013. Forecast future product prices are estimated assuming that the purchaser will pay all shipping costs. We forecast that we will sell approximately 1.7 million barrels of asphalt at a weighted average price of $67.00 per barrel during the twelve months ending September 30, 2013. We have assumed asphalt sales at a weighted average discount of $25.31 per barrel to the applicable Cushing WTI price over the twelve months ending September 30, 2013. The $25.31 per barrel discount to Cushing WTI is calculated from a regression formula derived from monthly Cushing WTI oil prices and Big Spring refinery realized asphalt prices based on historical data going back further than five years. The Cushing WTI benchmark price per barrel is forecast based on our view of future prices. Based on these assumptions, we forecast our net asphalt sales for the twelve months ending September 30, 2013 to be approximately $113.7 million.

For the year ended December 31, 2011, we sold approximately 1.7 million barrels of asphalt at a weighted average price of $64.69 per barrel and realized net asphalt sales of approximately $107.2 million. For the twelve months ended September 30, 2012, we sold approximately 1.6 million barrels of asphalt at a weighted average price of $66.90 per barrel and realized net asphalt sales of approximately $106.3 million.

Petrochemicals and Other Products. In addition to gasoline, diesel, jet fuel and asphalt, the Big Spring refinery produces and sells other refined products, including benzene, propane, refinery grade propylene, carbon black oil and butane. We forecast that we will sell approximately 2.5 million barrels of these products at a weighted average price of $97.51 per barrel during the twelve months ending September 30, 2013. Based on these forecasted prices and the volumes, we forecast net sales of other products to be approximately $241.0 million during the twelve months ending September 30, 2013.

For the year ended December 31, 2011, we sold approximately 2.7 million barrels of other products at a weighted average price of $94.78 per barrel and realized net sales of approximately $259.0 million. For the twelve months ended September 30, 2012, we sold approximately 2.3 million barrels of other products at a weighted average price of $86.92 per barrel and realized net sales of approximately $200.0 million.

Cost of Sales

We estimate that our cost of sales for the twelve months ending September 30, 2013 will be approximately $2.7 billion. Cost of sales for the year ended December 31, 2011 was approximately $2.7 billion. Cost of sales for the twelve months ended September 30, 2012 was approximately $3.0 billion.

Cost of sales includes the purchased raw material costs for crude oil, isobutane, normal butane, and other costs. Our feedstock and raw material costs consist of blending components for the finished products production process, which are driven primarily by commodity prices and volumes. We assume that our product yield will be approximately 99.7% over the twelve months ending September 30, 2013. For the year ended December 31, 2011, our product yield was 99.8%. For the twelve months ended September 30, 2012, our product yield was 99.9%.

Crude Oil. We estimate that we will purchase approximately 24.4 million barrels of crude oil for the twelve months ending September 30, 2013. We estimate crude oil costs of approximately $2.2 billion and that our realized crude oil cost will be $88.74 per barrel for the twelve months ending September 30, 2013. We forecast

 

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that the Big Spring refinery will realize an average crude oil price discount of $3.57 per barrel to the benchmark Cushing WTI price. We believe the Big Spring refinery will continue to realize favorable crude differentials to Cushing WTI because we expect to continue to process significant amounts of WTS and as a result of the oversupply of crude oil in Midland due to increased Permian Basin production. Our average crude oil price discount relative to Cushing WTI realized for the six years ended December 31, 2011 was $4.28 per barrel. For the year ended December 31, 2011, we purchased approximately 22.3 million barrels of crude oil at a weighted average price of $93.08 per barrel for a total crude oil cost of approximately $2.1 billion. For the twelve months ended September 30, 2012, we purchased approximately 24.4 million barrels of crude oil at a weighted average price of $92.68 per barrel for a total crude oil cost of approximately $2.3 billion.

Feedstocks and Blendstocks. Cost of sales also includes the cost of isobutane, normal butane, and other costs, among others, that we blend into our gasoline and diesel/jet fuel finished products. We forecast these elements of cost of sales to be approximately $46.0 million over the twelve months ending September 30, 2013. For the year ended December 31, 2011, these elements of cost of sales were approximately $80.7 million. For the twelve months ended September 30, 2012, these elements of cost of sales were approximately $69.2 million.

Direct Operating Expenses

Direct operating expenses include all direct and indirect labor at the facility, materials, supplies, and other expenses associated with the operation and maintenance of the refinery. We estimate that our direct operating expenses for the twelve months ending September 30, 2013 will be approximately $100.3 million, or $4.02 per barrel of throughput. Our direct operating expenses for the year ended December 31, 2011 were $98.2 million, or $4.25 per barrel of throughput. Direct operating expenses for the twelve months ended September 30, 2012 were $98.3 million, or $3.90 per barrel of throughput. Our direct operating expenses are generally fixed in nature, and increases in refinery utilization generally result in a lower direct operating cost per barrel.

Selling, General and Administrative Expenses

Selling, general and administrative expenses include salary and benefits costs for executive management, stock based compensation, accounting and information technology personnel, legal, audit, tax and other professional service costs. We estimate that our selling, general and administrative expense will be approximately $19.3 million for the twelve months ending September 30, 2013, of which approximately $8.4 million is attributed to our wholesale business and approximately $10.9 million is related to our Big Spring refinery. Of these expenses, approximately $1.5 million is related to increased expenses that we expect we will incur as a publicly traded partnership. Selling, general and administrative expenses for the year ended December 31, 2011 were approximately $15.6 million. Selling, general and administrative expenses for the twelve months ended September 30, 2012 were approximately $21.5 million.

Depreciation and Amortization Expense

We estimate the depreciation and amortization expense for the twelve months ending September 30, 2013 to be approximately $47.6 million. Depreciation and amortization expense for the year ended December 31, 2011 was approximately $40.4 million. Depreciation and amortization expense for the twelve months ended September 30, 2012 was approximately $45.2 million. The increase in expected depreciation and amortization expense is related to increased expected capital expenditures as described below under “—Maintenance/Growth Capital Expenditures.”

Interest Expense

Interest expense includes interest incurred under our amended and restated revolving credit facility and new term loan facility, fees relating to our letters of credit and financing costs associated with crude oil purchases as part of our supply and offtake agreement with J. Aron. For the twelve months ending September 30, 2013, our

 

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forecasted interest expense is $35.0 million, of which $2.0 million relates to our amended and restated revolving credit facility, $23.0 million relates to our new term loan facility, $4.0 million relates to our letters of credit and $4.0 million relates to the J. Aron supply and offtake agreement. We have assumed average borrowings under our amended and restated revolving credit facility of $40.0 million and borrowings under our new term loan facility of $250.0 million (the fully drawn amount), and we have assumed weighted average interest rates on our amended and restated revolving credit facility and new term loan facility of 4.0% and 9.25%, respectively, based on current market rates. Our forecasted interest expense for the twelve months ending September 30, 2013 does not include any interest expense on related party borrowings, as we have assumed the repayment of such borrowings with a portion of the net proceeds of this offering or the conversion of such borrowings into equity. We do not expect to have significant additional borrowings under our amended and restated revolving credit facility during the twelve months ending September 30, 2013. In addition, we do not expect to incur any significant additional intercompany debt following the completion of this offering.

For the year ended December 31, 2011, our pro forma interest expense was $41.8 million, of which $5.9 million related to our amended and restated revolving credit facility, $23.0 million related to our new term loan facility, $6.6 million related to our letters of credit, $4.2 million related to the J. Aron supply and offtake agreement and $2.0 million was associated with debt issuance costs. Our historical interest expense for the year ended December 31, 2011 included $17.0 million of interest expense to related parties. As of December 31, 2011, on a pro forma basis, we had $200.0 million outstanding under our amended and restated revolving credit facility and $250.0 million outstanding under our new term loan facility. The assumed weighted average interest rates on our amended and restated revolving credit facility and new term loan facility during the year ended December 31, 2011 were 4.0% and 9.25%, respectively.

For the twelve months ended September 30, 2012, our pro forma interest expense was $44.5 million, of which $7.7 million related to our amended and restated revolving credit facility, $23.0 million related to our new term loan facility, $5.5 million related to our letters of credit, $6.3 million related to the J. Aron supply and offtake agreement and $2.0 million was associated with debt issuance costs. Our historical interest expense for the twelve months ended September 30, 2012 included $17.3 million of interest expense to related parties. As of September 30, 2012, on a pro forma basis, we had $84.0 million outstanding under our amended and restated revolving credit facility and $250.0 million outstanding under our new term loan facility. The assumed weighted average interest rates on our amended and restated revolving credit facility and new term loan facility during the twelve months ended September 30, 2012 were 4.0% and 9.25%, respectively.

State Income Tax Expense

We estimate that we will pay a minimal state income tax in the form of a Texas franchise tax for our refining business during the twelve months ending September 30, 2013 amounting to $3.0 million. For the year ended December 31, 2011 and the twelve months ended September 30, 2012, we paid state income taxes of $2.6 million and $3.0 million, respectively.

Maintenance/Growth Capital Expenditures

We estimate maintenance/growth capital expenditures during the twelve months ending September 30, 2013 of approximately $32.3 million, of which approximately $8.0 million is attributed to the wholesale business. Maintenance/growth capital expenditures for the year ended December 31, 2011 were approximately $12.5 million, of which approximately $1.4 million is attributed to the wholesale business. Maintenance/growth capital expenditures for the twelve months ended September 30, 2012 were approximately $18.7 million, of which approximately $9.7 million is attributed to the wholesale business.

The increase in forecasted maintenance/growth capital expenditures for the twelve months ending September 30, 2013 relative to prior periods includes increased expected maintenance/growth capital expenditures in the fourth quarter of 2012 relating to increasing liquid recovery for the refinery, a new cooling tower and certain regulatory projects. Increased expected maintenance/growth capital expenditures during the first three quarters of 2013 relate to regulatory projects, increasing liquid recovery for the refinery and tank replacement and cleaning.

 

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Rebranding Expenses

Forecasted cash available for distribution for the twelve months ending September 30, 2013 also gives effect to approximately $0.3 million of one-time additional capital expenditures relating to the rebranding of our wholesale business from FINA to ALON that we expect to incur in the fourth quarter of 2012.

Turnaround and Catalyst Replacement Capital Expenditures

Turnaround and catalyst replacement capital expenditures represent the costs of required annual and major maintenance projects on the refinery processing units. We incur two types of turnaround catalyst replacement expenses: (i) expenses relating to our annual reformer regeneration and catalyst replacement activities and (ii) expenses relating to major turnarounds, which occur every five years. Our annual turnaround expenses relating to reformer regeneration activities are capitalized and included in our capital expenditures in the tables above.

Forecasted turnaround and catalyst replacement capital expenditures relating to our annual reformer regeneration and catalyst replacement activities for the twelve months ending September 30, 2013 are $8.8 million. Capital expenditures relating to annual reformer regeneration and catalyst replacement activities for the year ended December 31, 2011 and the twelve months ended September 30, 2012 were $7.1 million and $8.3 million, respectively.

Major Turnaround Reserve

In advance of scheduled major turnarounds at our refinery, the board of directors of our general partner intends to elect to reserve amounts to fund actual capital expenditures associated with such turnarounds. Such a decision by the board of directors may have an adverse impact on our cash available for distribution in the quarter(s) in which the reserves are withheld and a corresponding mitigating impact on the future quarter(s) in which the reserves are utilized. We currently estimate total major turnaround expense at the Big Spring refinery of approximately $23.0 million in the aggregate over a five-year turnaround cycle. We expect to perform our next major turnaround during the first quarter of 2014.

We estimate reserving approximately $4.6 million of cash available for distribution per year, or approximately $1.2 million per quarter, for capital expenditures relating to the major turnarounds of our refinery that occur every five years.

Special Turnaround Reserve

In order to fund our capital expenditures relating to the major turnaround in the first quarter of 2014, we estimate reserving an additional $3.5 million per quarter for five quarters beginning with the fourth quarter of 2012. Accordingly, our forecasted special turnaround reserve for the twelve months ending September 30, 2013 is $13.8 million and the total forecasted turnaround reserve for the twelve months ending September 30, 2013 is $18.4 million. This assumption is subject to change as we complete our turnaround planning. We intend to use cash reserves or borrowings under our amended and restated revolving credit facility to fund other turnaround and catalyst replacement expenses.

Regulatory, Industry and Economic Factors

Our forecast for the twelve months ending September 30, 2013, is based on the following assumptions related to regulatory, industry and economic factors:

 

   

No material nonperformance or credit-related defaults by suppliers, customer or vendors;

 

   

No new regulation or interpretation of existing regulations that, in either case, would be materially adverse to our business;

 

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No material accidents, weather-related incidents, floods, unplanned turnarounds or other downtime or similar unanticipated events that would reduce our capacity utilization below what we are currently forecasting;

 

   

No material adverse change in the market in which we operate resulting from reduced demand for gasoline, diesel/jet fuel, asphalt or our other products;

 

   

No material decreases in the prices we receive for our products; and

 

   

No material changes to market or overall economic conditions.

Actual conditions may differ materially from those anticipated in this section as a result of a number of factors, including, but not limited to, those set forth under “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”

Compliance with Debt Covenants

Our ability to make distributions could be affected if we do not remain in compliance with the covenants in our new term loan facility and our amended and restated revolving credit facility. We have assumed we will remain in compliance with such covenants. The new term loan facility is expected to contain restrictive covenants, such as restrictions on liens, mergers, consolidations, sales of assets, additional indebtedness, different businesses, certain lease obligations, and certain restricted payments. The amended and restated revolving credit facility contains certain restrictive covenants that limit our ability to incur certain additional debt, pay cash distributions, grant liens, make certain investments, enter into certain mergers or consolidations, sell assets and engage in certain other transactions. Additionally, the amended and restated revolving credit facility requires us to maintain certain financial ratios, including requiring our Funded Debt to Adjusted EBITDA ratio, as such terms are defined therein.

Sensitivity Analysis

Our cash available for distribution is significantly impacted by volatility in prevailing crack spreads, crude oil prices and throughput at our refinery. In the paragraphs below, we discuss the impact of changes in these variables, while holding all other variables constant, on our ability to generate our estimated available cash for the twelve months ending September 30, 2013.

Crack Spread Volatility

Crack spreads measure the difference between the price received from the sale of motor fuels and the price paid for crude oil. Holding all other variables constant, we expect that a $1.00 change in the Gulf Coast (WTI) 3-2-1 crack spread per barrel would change our forecasted available cash by $20.7 million for the twelve months ending September 30, 2013.

Crude Oil Price Volatility

We are exposed to significant fluctuations in the price of crude oil. Holding all other variables constant, we expect a $1.00 increase (decrease) in our realized crude price differential to Cushing WTI would increase (decrease) our forecasted available cash by $24.3 million for the twelve months ending September 30, 2013.

Refinery Throughput

Holding all other variables constant, we expect a 1,000 bpd change in our total refinery throughput would change our forecasted available cash by $7.3 million for the twelve months ending September 30, 2013.

 

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HOW WE MAKE CASH DISTRIBUTIONS

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of Available Cash

General

Within 60 days after the end of each quarter, beginning with the quarter ending December 31, 2012, we expect to make distributions, as determined by the board of directors of our general partner, to unitholders of record on the applicable record date.

Common Units Eligible for Distributions

Upon closing of this offering, we will have 62,500,000 common units outstanding. Each common unit will be allocated a portion of our income, gain, loss deduction and credit on a pro forma basis and each common unit will be entitled to receive distributions (including upon liquidation) in the same manner as each other unit.

Method of Distributions

We will distribute available cash to our unitholders, pro rata; provided, however, that our partnership agreement allows us to issue an unlimited number of additional equity interests of equal or senior rank. Our partnership agreement permits us to borrow to make distributions, but we are not required and do not intend to borrow to pay quarterly distributions. Accordingly, there is no guarantee that we will pay any distribution on the units in any quarter.

We do not have a legal obligation to pay distributions, and the amount of distributions paid under our policy and the decision to make any distribution is determined by the board of directors of our general partner. Moreover, we may be restricted from paying distributions of available cash by the instruments governing our indebtedness. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

General Partner Interest

Upon the closing of this offering, our general partner will own a non-economic general partner interest and therefore will not be entitled to receive cash distributions. However, it may acquire common units and other equity interests in the future and will be entitled to receive pro rata distributions therefrom.

 

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SELECTED HISTORICAL COMBINED AND PRO FORMA COMBINED FINANCIAL DATA

The selected historical combined financial information presented below as of September 30, 2012 and December 31, 2010 and 2011 and for the nine months ended September 30, 2012 and 2011 and the years ended December 31, 2009, 2010 and 2011 have been derived from the audited and unaudited financial statements included elsewhere in this prospectus. The selected historical combined financial information as of December 31, 2009 have been derived from audited financial statements that are not included in this prospectus. The selected historical combined financial information for the years ended December 31, 2007 and 2008 and as of December 31, 2007 and 2008 have been derived from our unaudited combined financial statements and as of September 30, 2011 have been derived from our unaudited combined financial statements that are not included in this prospectus. These combined financial statements relate to the operating subsidiaries of Alon Energy that will be transferred to Alon USA Partners, LP Predecessor upon the closing of this offering, which we refer to as “Alon USA Partners, LP.”

Our combined financial statements included elsewhere in this prospectus include certain costs of Alon Energy that were incurred on our behalf. These costs, which are reflected in selling, general and administrative expenses and direct operating expenses include an allocation of costs and certain other amounts in order to account for a reasonable share of Alon Energy’s total expenses, so that the accompanying combined financial statements reflect substantially all of our costs of doing business. The amounts charged or allocated to us were determined by Alon Energy and are not necessarily indicative of the costs that we would have incurred had we operated as a stand-alone company for all periods presented.

This data should be read in conjunction with, and is qualified in its entirety by reference to, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the combined financial statements of Alon USA Partners, LP Predecessor and related notes included elsewhere in this prospectus.

Our results of operations for 2009 and 2010 were affected by decreased utilization of the refinery as a result of a February 2008 fire and other scheduled and unscheduled downtime during 2009 and 2010. For more information on the downtime of the Big Spring refinery in 2008, 2009 and 2010, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Comparability of Our Historical Results—Decreased Utilization of Refinery due to February 2008 Fire and Other Downtime.”

The pro forma financial and other information presented below was derived from the unaudited pro forma combined financial statements of Alon USA Partners, LP included elsewhere in this prospectus. Our unaudited pro forma combined financial information gives pro forma effect to the IPO Transactions discussed under “Prospectus Summary—The IPO Transactions.”

 

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    Alon USA Partners, LP Predecessor Historical Combined     Alon USA Partners, LP
Pro Forma Combined
 
    Year Ended December 31,     Nine Months Ended
September 30,
    Year Ended
December 31,
2011
    Nine Months
Ended
September 30,
2012
 
    2007     2008(2)     2009     2010     2011     2011     2012      
    (unaudited)                       (unaudited)     (unaudited)  
    (in thousands)  

Statements of Operations Data(1):

  

               

Net sales

  $ 2,426,138      $ 2,202,403      $ 1,498,176      $ 1,639,935      $ 3,207,969      $ 2,351,481      $ 2,651,191      $ 3,207,969      $ 2,651,191   

Total operating costs and expenses

    2,221,561        2,360,839        1,541,574        1,647,662        2,877,177        2,075,291        2,351,958        2,877,177        2,351,958   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Gain on involuntary conversion of assets

    —          279,680        —          —          —          —          —          —          —     

Gain on disposition of assets

    —          3,352        2,105        —          —          10        —          —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

    204,577        124,596        (41,293     (7,727     330,792        276,200        299,233        330,792        299,233   

Interest expense

    (19,263     (26,697     (25,238     (30,381     (33,786     (25,105     (28,060     (41,802     (33,883

Other income (loss), net

    4,432        667        183        (269     18        —          11        18        11   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before state income tax expense

    189,746        98,566        (66,348     (38,377     297,024        251,095        271,184        289,008        265,361   

State income tax expense

    1,599        —          —          136        2,597        2,153        2,518        2,597        2,518   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

  $ 188,147      $ 98,566      $ (66,348   $ (38,513   $ 294,427      $ 248,942      $ 268,666      $ 286,411      $ 262,843   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Statements of Cash Flow Data:

  

               

Net cash provided by (used in):

                 

Operating activities

  $ 208,447      $ (159,084   $ (29,108   $ 60,139      $ 258,575      $ 165,587      $ 363,616       

Investing activities

    (20,014     (64,571     (19,634     (25,562     (19,545     (17,996     (25,455    

Financing activities

    (153,589     186,107        47,812        (15,338     (123,437     (23,197     (444,692    

Capital expenditures

    (10,173     (374,966     (46,688     (15,411     (12,460     (11,090     (17,328    

Capital expenditures for turnarounds and catalyst replacement

    (9,841     (1,615     (9,176     (10,151     (7,085     (6,916     (8,127    

Depreciation and amortization

    20,752        19,115        36,651        39,570        40,448        30,206        34,963        $ 34,963   

Balance Sheet Data:

  

               

Cash and cash equivalents

  $ 39,591      $ 2,043      $ 1,113      $ 20,352      $ 135,945      $ 144,746      $ 29,414        $ 29,414   

Property, plant and equipment, net

    123,355        512,744        531,307        512,169        493,970        499,882        485,115          485,115   

Total assets

    414,057        677,582        659,134        675,039        810,480        849,483        739,520          751,270   

Total debt

    265,325        400,392        387,459        438,526        533,592        526,326        430,582          334,000   

Partners’ equity

    (63,445     83,561        96,315        9,664        102,689        160,444        45,235          153,567   

 

(1) Net loss per unit information is not presented as such information is not required by Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) topic 260, Earnings per share.

 

(2) On February 18, 2008, a fire at our Big Spring refinery destroyed the propylene recovery unit and damaged equipment in the alkylation and gas concentration units. For the year ended December 31, 2008, we recorded pre-tax costs of $56.9 million associated with the fire. These costs included: $51.1 million for expenses incurred from pipeline commitment deficiencies, crude sale losses and other incremental costs; $5.0 million for our third party liability insurance deductible; and $0.8 million of depreciation for the temporarily idled facilities.

As a result of the fire in 2008, Alon Energy received $330.0 million of insurance proceeds and $55.0 million for business interruption recovery. With the $330.0 million of insurance proceeds received, we recognized an involuntary gain on conversion of assets of $279.7 million, which reflects (i) the proceeds received in excess of the $25.3 million book value of the assets impaired and (ii) demolition and repair expenses of $25.0 million incurred through December 31, 2008. Pre-tax income of $55.0 million was also recorded in 2008 for business interruption recovery. For more information on the downtime of the Big Spring refinery in 2008, 2009 and 2010, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Comparability of Our Historical Results—Decreased Utilization of Refinery due to February 2008 Fire and Other Downtime.”

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion and analysis of our financial condition, results of operations and cash flows in conjunction with our combined financial statements and related notes included elsewhere in this prospectus. This discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions. Among other things, those combined financial statements include more detailed information regarding the basis of presentation for the following information. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including, but not limited to, those set forth under “Risk Factors,” “Cautionary Note Regarding Forward-Looking Statements” and elsewhere in this prospectus.

The following discussion assumes that our business was operated as a separate entity prior to its inception. The historical combined financial statements of Alon USA Partners, LP Predecessor, whose results are discussed below, have been carved out of the consolidated financial statements of our sponsor, which operated the Big Spring refinery during the periods presented. Our sponsor’s facilities and other assets, liabilities, net sales and expenses that do not relate to the Big Spring refinery acquired or to be acquired by us are not included in our combined financial statements. Our financial position, results of operations and cash flows reflected in our combined financial statements include all expenses allocable to our business, but may not be indicative of those that would have been achieved had we operated as a separate public entity for all periods presented or of future results. The following financial information has been derived from the historical combined financial statements and accounting records of Alon USA Partners, LP Predecessor and reflects significant assumptions and allocations. All significant intercompany accounts and transactions have been eliminated in the combined financial statements of Alon USA Partners, LP Predecessor.

Overview

We are a Delaware limited partnership formed in August 2012 by Alon USA Energy, Inc. (NYSE: ALJ) (“Alon Energy”) to own, operate and grow our strategically located refining and petroleum products marketing business. Our integrated downstream business operates primarily in the South Central and Southwestern regions of the United States. We own and operate a crude oil refinery in Big Spring, Texas with total throughput capacity of approximately 70,000 barrels per day (“bpd”), which we refer to as our Big Spring refinery. We refine crude oil into finished products, which we market primarily in West Texas, Central Texas, Oklahoma, New Mexico and Arizona through our wholesale distribution network to both Alon Energy’s retail convenience stores and other third-party distributors.

Our Big Spring refinery has a Nelson complexity rating of 10.2. Our refinery’s complexity allows us the flexibility to process a variety of crudes into higher-value refined products. For the year ended December 31, 2011 and the nine months ended September 30, 2012, sour crude, such as West Texas Sour (“WTS”), represented approximately 80.4% and 78.6% of our throughput, respectively, and sweet crude, such as West Texas Intermediate (“WTI”), represented approximately 15.8% and 18.8% of our throughput, respectively. For the year ended December 31, 2011 and the nine months ended September 30, 2012, we produced approximately 49.1% and 49.6% gasoline, 32.3% and 32.8% diesel/jet fuel, 7.1% and 6.3% asphalt, 6.0% and 5.9% petrochemicals and 5.5% and 5.4% other refined products, in each case, respectively. Major processing units at our Big Spring refinery include fluid catalytic cracking, naphtha reforming, vacuum distillation, hydrotreating and alkylation units. During the year ended December 31, 2011 and the nine months ended September 30, 2012, our Big Spring refinery had a utilization rate of 90.8% and 97.3%, respectively.

We sell refined products from our Big Spring refinery in both the wholesale rack and bulk markets. We focus our marketing of transportation fuels produced at our Big Spring refinery on portions of Texas, Oklahoma, New Mexico and Arizona through our physically integrated refining and distribution system. We distribute fuel products through a product pipeline and terminal network of seven pipelines totaling approximately 840 miles and five terminals that we own or access through leases or long-term throughput agreements.

 

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Outlook

Refining is primarily a margin-based business in which both the feedstock (primarily crude oil) and the refined products are commodities with fluctuating prices. In order to increase profitability, refineries focus on maximizing the yields of high-value finished products and minimizing the costs of feedstock and operating expenses. Supply and demand dynamics can vary by region, creating differentiated margin opportunities depending on a refinery’s location and refining capabilities. Our Big Spring refinery is located in the Gulf Coast region of the United States, which is included in the Petroleum Administration for Defense District III, or “PADD III.” Refineries like ours that operate in PADD III and utilize WTI and WTI-linked crudes often benchmark their performance against the Gulf Coast (WTI) 3-2-1 crack spread, which has significantly increased over the last few years due primarily to the differential between WTI and imported waterborne crude oils, such as Brent crude oil (“Brent”). As of August 2012, the U.S. Energy Information Administration (“EIA”) has forecasted that WTI will continue to trade at a significant discount to Brent through 2013. WTS has also historically traded at a discount to WTI due to the additional cost associated with eliminating sulfur content from sour crude in the refining process.

Moreover, the strategic location of our refinery near Midland, Texas provides us with a low relative transportation cost to source WTS and WTI crude oil versus purchasing such crude at Cushing, Oklahoma, further increasing the discount to Brent that we realize. Our ability to source a majority of our crude oil supply from Midland also allows us to benefit from favorable price differentials between Midland WTI and Cushing WTI. Recent increased production in the Permian Basin and continued oversupply at Cushing, together with a lack of transportation infrastructure at Cushing, is causing additional crude oil to enter the Midland market and drive the price of Midland WTI lower. Although we believe that current infrastructure plans will likely ease transportation constraints around Cushing in the longer term, we believe that producers transporting their crude oil through Cushing will likely incur additional transportation costs, and we believe our Big Spring refinery should still be able to access its crude oil supply at a discount to Cushing prices.

According to the EIA, total demand for refined products in PADD III has represented approximately 20.9% of total U.S. refined products demand from 2007 to 2011. Refinery capacity exceeds refined product demand with finished petroleum products consumed in the region totaling 3.5 million bpd. Despite this high level of refining capacity relative to the refined product demand, refiners who can access advantageous crude supplies, such as we do at our Big Spring refinery, are still able to achieve high margins.

Factors Affecting Comparability of Our Historical Results

Our historical results of operations for the periods presented may not be comparable with prior periods or to our results of operations in the future for the reasons discussed below.

Decreased Utilization of Refinery due to February 2008 Fire and Other Downtime. In February 2008, a fire at the Big Spring refinery destroyed the propylene recovery unit and damaged equipment in the alkylation and gas concentration units. The re-start of the crude unit in a hydroskimming mode began in April 2008, and the fluid catalytic cracking unit resumed operations in September 2008. However, repairs to the alkylation unit damaged in the fire were not substantially completed until the first quarter of 2010. Refinery throughput for 2009 also reflects the effects of downtime associated with a scheduled reformer regeneration in May 2009, an unscheduled reformer regeneration in November 2009 and a scheduled shutdown of the ultra-low sulfur gas unit for completion of our ultra-low sulfur gas project. In addition, in 2010, we implemented new operating procedures at the refinery, which reduced throughput rates. Accordingly, the Big Spring refinery did not resume operating at its full throughput capacity until the fourth quarter of 2010. As a result of these downtime periods, our results of operations presented below for 2009 and 2010 do not reflect full utilization of the Big Spring refinery, were not indicative of our operations in 2011 and will not be indicative of our expected results of operations for periods subsequent to the closing of this offering.

 

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Loan Agreements and Interest Expense. We had approximately $200.0 million and $84.0 million of borrowings outstanding under our amended and restated revolving credit facility as of December 31, 2011 and September 30, 2012, respectively. We also had approximately $35.5 million and $84.0 million of letters of credit outstanding under our amended and restated revolving credit facility at such respective dates. Borrowings under the amended and restated revolving credit facility bear interest at the Eurodollar rate plus 3.50% per annum subject to an overall minimum interest rate of 4.00%. We also had $333.6 million and $346.6 million of intercompany debt payable to Alon Energy and certain of its subsidiaries at December 31, 2011 and September 30, 2012, respectively. This intercompany debt bears interest at a weighted average rate of approximately 8.0% and was based on prevailing market rates at the time of issue. In connection with this offering and the transactions described under “Prospectus Summary—The IPO Transactions,” we intend to repay approximately $183.0 million of principal and accrued interest relating to intercompany debt with the proceeds of this offering and will assume from Alon Energy a $250.0 million term loan facility, which will be fully drawn at the closing of this offering. We expect that the remaining balance of the intercompany debt will be eliminated prior to closing and we do not expect to incur any significant additional intercompany debt following this offering.

Product Inventory Valuation. Because crude oil and refined products are essentially commodities, we have no control over the changing market value of our inventories. Therefore, the lower the target inventory we are able to maintain, the lesser the impact of commodity price volatility on our petroleum product inventory position. Our inventory of crude oil and refined products is valued at the lower of cost or market value under the last-in-first-out (“LIFO”) cost flow assumption. For periods in which the market price is volatile and the quantity of inventory on hand changes, we are subject to significant fluctuations in the recorded value of our inventory and related cost of products sold. If the market value of our inventory were to decline to an amount less than our LIFO cost, we would record a write-down of inventory and a non-cash charge to cost of sales. Our investment in inventory is affected by the general level of crude oil prices, and significant increases in crude oil prices could result in substantial working capital requirements to maintain inventory volumes. In February 2011, we entered into a supply and offtake agreement with J. Aron and Company (“J. Aron”) under which (i) J. Aron agreed to sell to us, and we agreed to buy from J. Aron, at market prices, crude oil for processing at the Big Spring refinery and (ii) we agreed to sell, and J. Aron agreed to buy, at market prices, certain refined products produced by the Big Spring refinery. We believe that this supply and offtake agreement significantly reduces our crude inventories and reduces the time we are exposed to market fluctuations before the finished product output is sold.

IPO Transactions. In connection with this offering, in addition to entering into the new term loan facility as described above, we will enter into the agreements and complete the reorganization transactions described in “Prospectus Summary—The IPO Transactions,” which we expect will affect the comparability of our results of operations in the following ways:

 

   

Our general and administrative expenses will increase due to the costs of operating as a publicly traded company, including costs associated with SEC reporting requirements, including annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, Sarbanes-Oxley compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director compensation expenses. We estimate that these incremental general and administrative expenses, which also include increased personnel costs, will be approximately $1.5 million per year, excluding the costs associated with the initial implementation of our Sarbanes-Oxley Section 404 internal controls review and testing.

 

   

Historically, our operating expenses have included allocations of certain general and administrative costs from our sponsor for services provided to us by our sponsor. Upon completion of the offering, we will reimburse our general partner and its affiliates for all expenses they incur and payments they make on our behalf in accordance with the services agreement into which we will enter in connection with this offering. The services agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed, and the amount of such charges could vary from historical amounts.

 

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Factors Affecting Our Results of Operations

We expect the following factors to continue to affect our results of operations for periods following the closing of this offering.

Feedstock and Refined Product Prices. Our earnings and cash flows from our petroleum operations are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks. Refining is primarily a margin-based business, and in order to increase profitability, it is important for the refinery to maximize the yields of high-value finished products and to minimize the costs of feedstock and operating expenses. The cost to acquire feedstocks and the price for which refined products are ultimately sold depend on factors beyond our control, including the supply of and demand for crude oil, as well as gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and the extent of government regulation. The effect of changes in crude oil prices on our results of operations is influenced by the rate at which the prices of refined products adjust to reflect these changes.

Feedstock and refined product prices are also affected by other factors, such as product pipeline capacity, transportation infrastructure, local market conditions and the operating levels of competing refineries. Crude oil costs and the prices of refined products have historically been subject to wide fluctuations. An expansion or upgrade of our competitors’ facilities, 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 and affect demand for feedstocks and refined products. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction in product margins.

The refining industry typically experiences seasonal fluctuations in demand for refined products, such as increases in the demand for gasoline during the summer driving season and for home heating oil during the winter. In addition to current market conditions, there are long-term factors that may impact the demand for refined products. These factors include mandated renewable fuels standards, proposed climate change laws and regulations, and increased mileage standards for vehicles.

Refining Margins as Compared with Industry Benchmarks. In order to measure our operating performance, we compare our per barrel refinery operating margins to certain industry benchmarks. We compare our per barrel operating margin to the Gulf Coast (WTI) 3-2-1 crack spread. The Gulf Coast (WTI) 3-2-1 crack spread is determined using the market values of Gulf Coast conventional gasoline and ultra-low sulfur diesel and the market value of Cushing WTI. We calculate the per barrel operating margin by dividing the difference between net sales and cost of sales by throughput.

Our ability to purchase WTI and WTS crude oil feedstocks provides us a cost advantage compared to refineries located on the U.S. Gulf Coast that utilize more expensive waterborne crude oil feedstocks to produce the refined products they sell in our market area. Our refinery is capable of processing substantial volumes of sour crude oil, which has historically cost less than intermediate and sweet crude oils. We measure the cost advantage of refining sour crude oil at our refinery by calculating the difference between the value of WTI crude oil less the value of WTS. In addition to cost advantages resulting from our proximity to domestic crude oil sources and our refinery’s capability to process substantial volumes of WTS, we have been able to capitalize on the oversupply of West Texas crudes in Midland, the largest origination terminal for West Texas crude oil, resulting from increased production in the Permian Basin coupled with infrastructure constraints in Cushing, Oklahoma. Although West Texas crudes are typically transported to Cushing for sale, current logistical and infrastructure constraints at Cushing are limiting the ability of Permian Basin producers to transport their production to Cushing. The resulting oversupply of West Texas crudes at Midland has depressed Midland WTI crude prices and enabled us to access an increased portion of our West Texas crude supply directly from Midland at discounted prices to Cushing. Moreover, by sourcing West Texas crude oils at Midland, we are able to eliminate the cost of transporting crude supply to and from Cushing.

 

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A widening of the Brent—WTI differential, the Cushing WTI—Midland WTS differential or the Cushing WTI—Midland WTI differential can favorably influence the operating margin for our refinery. Conversely, the narrowing of any of these differentials can reduce our operating margins.

Direct Operating Expenses. Our direct operating expense structure is also important to our profitability. Major direct operating expenses include energy, employee labor, maintenance, contract labor, and environmental compliance. Our predominant variable cost is energy, which is comprised primarily of electrical cost and natural gas. We are therefore sensitive to the movements of natural gas prices. Assuming the same rate of consumption of natural gas for the year ended December 31, 2011, a $1.00 change in natural gas prices would have increased or decreased our natural gas costs by approximately $4.5 million.

Scheduled and Unscheduled Downtime. Consistent, safe, and reliable operation at our refinery is key to our financial performance and results of operations. Unscheduled downtime at our refinery may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. We seek to mitigate the financial impact of scheduled downtime, such as major turnaround maintenance, through a diligent planning process that takes into account the margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors, and we intend to maintain quarterly reserves for turnaround expenses. Our refinery generally requires a facility turnaround every four to five years. The length of the turnaround is contingent upon the scope of work to be completed. We expect to perform our next major turnaround during 2014. We estimate total major turnaround expense at the Big Spring refinery of approximately $23.0 million in the aggregate over a five year turnaround cycle.

Results of Operations

The period to period comparisons of our results of operations have been prepared using the historical periods included in our combined financial statements. This “Results of Operations” section compares the nine months ended September 30, 2012 with the nine months ended September 30, 2011 as well as compares the year ended December 31, 2011 with the year ended December 31, 2010 and the year ended December 31, 2010 with the year ended December 31, 2009.

We refer to our financial statement line items in the explanation of our period-to-period changes in results of operations. Below are general definitions of what those line items include and represent.

Net sales. Net sales consist principally of sales of refined petroleum products, and are mainly affected by refined product prices, changes to the product mix and volume changes caused by operations. Product mix refers to the percentage of production represented by higher value motor fuels, such as gasoline, rather than lower value finished products.

Cost of sales. Cost of sales primarily includes crude oil, blending materials, other raw materials and transportation cost.

Direct operating expenses. Direct operating expenses include costs associated with the actual operations of the refinery and terminals, such as energy and utility costs, routine maintenance, labor, insurance and environmental compliance costs. Environmental compliance costs, including monitoring and routine maintenance, are expensed as incurred. Substantially all of the operating costs associated with our crude oil and product pipelines are considered to be transportation costs and are reflected in cost of sales in the combined statements of operations.

Selling, general and administrative expenses. Selling, general and administrative expenses primarily include corporate overhead costs and marketing expenses.

 

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Depreciation and amortization. Depreciation and amortization represents an allocation to expense within the combined statements of operations of the carrying value of capital and intangible assets. The value is allocated based on the straight-line method over the estimated useful life of the related asset. Depreciation and amortization also includes deferred turnaround and catalyst replacement costs. Turnaround and catalyst replacement costs are currently deferred and amortized on a straight-line basis beginning the month after the completion of the turnaround and ending immediately prior to the next scheduled turnaround.

Operating income (loss). Operating income (loss) represents our net sales less our total operating costs and expenses.

Interest expense. Interest expense includes interest expense, letters of credit, financing costs associated with crude oil purchases, fees, and amortization of deferred debt issuance costs but excludes capitalized interest.

Industry-wide petroleum results are driven and measured by the relationship, or margin, between refined products and the prices for crude oil referred to as crack spreads. See “—Factors Affecting Our Results of Operations.” We discuss our results of refinery operations in the context of per barrel consumed crack spreads and the relationship between net sales and cost of product sold.

 

     Year Ended December 31,     Nine Months Ended
September 30,
 
     2009     2010     2011     2011     2012  
                      

(unaudited)

 
    

(Dollars in thousands, other than per barrel and average pricing  statistics)

 

Statement of Operations Data:

          

Net sales(1)

   $ 1,498,176      $ 1,639,935      $ 3,207,969      $ 2,351,481      $ 2,651,191   

Operating costs and expenses:

          

Cost of sales

     1,398,365        1,503,301        2,722,918        1,959,728        2,225,702   

Direct operating expenses

     89,994        90,359        98,178        73,144        73,223   

Selling, general and administrative expenses

     16,564        14,432        15,633        12,213        18,070   

Depreciation and amortization

     36,651        39,570        40,448        30,206        34,963   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total operating costs and expenses

     1,541,574        1,647,662        2,877,177        2,075,291        2,351,958   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Gain on disposition of assets

     2,105        —          —          10        —     
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

     (41,293     (7,727     330,792        276,200        299,233   

Interest expense

     (8,171     (13,314     (16,719     (12,305     (15,070

Interest expense—related parties

     (17,067     (17,067     (17,067     (12,800     (12,990

Other income (loss), net

     183        (269     18        —          11   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before state income tax expense

     (66,348     (38,377     297,024        251,095        271,184   

State income tax expense

     —          136        2,597        2,153        2,518   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ (66,348   $ (38,513   $ 294,427      $ 248,942      $ 268,666   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating Data:

          

Refinery Throughput (bpd):

          

WTS crude

     48,340        39,349        51,202        48,882        53,297   

WTI crude

     9,238        7,288        10,023        9,845        12,790   

Blendstocks

     2,292        2,391        2,389        2,162        1,797   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total refinery throughput(2)

     59,870        49,028        63,614        60,889        67,884   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Refinery Production (bpd):

          

Gasoline

     26,826        24,625        31,105        28,969        33,653   

Diesel/jet

     19,136        15,869        20,544        19,704        22,234   

Asphalt

     5,289        2,827        4,539        4,505        4,241   

Petrochemicals

     2,928        2,939        3,837        3,664        4,005   

Other

     5,327        2,341        3,488        3,837        3,627   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total refinery production(3)

     59,506        48,601        63,513        60,679        67,760   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

72


Table of Contents
     Year Ended December 31,     Nine Months Ended
September 30,
 
     2009     2010     2011     2011     2012  
                      

(Unaudited)

 
    

(Dollars in thousands, other than per barrel and average pricing  statistics)

 

Key Operating Statistics:

          

Refinery utilization(4)

     82.3     68.2     90.8     88.3     97.3

Per barrel of throughput:

          

Refinery operating margin(5)

   $ 4.57      $ 7.64      $ 20.89      $ 23.57      $ 22.88   

Refinery direct operating expense(6)

   $ 4.12      $ 5.05      $ 4.23      $ 4.40      $ 3.92   

Capital expenditures

   $ (46,688   $ (15,411   $ (12,460   $ (11,090   $ (17,328

Capital expenditures for turnaround and catalyst replacement

   $ (9,176   $ (10,151   $ (7,085   $ (6,916   $ (8,127

Average Pricing Statistics: