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As filed with the Securities and Exchange Commission on November 6, 2012

Registration No. 333-183671

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Amendment No. 4

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		¨

 

 

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.

 

 

 

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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 6, 2012.

               Common Units

Representing Limited Partner Interests

Alon USA Partners, LP

 

 

This is the initial public offering of our common units representing limited partner interests. We are offering                     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 $         and $         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

 

 

Prospectus dated                 , 2012.

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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			40
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS			44
USE OF PROCEEDS			45
CAPITALIZATION			46
DILUTION			47
CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS			49
General			49
Unaudited Pro Forma Available Cash			51
Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2013			53
Forecast Assumptions and Considerations			57
HOW WE MAKE CASH DISTRIBUTIONS			63
Distributions of Available Cash			63
SELECTED HISTORICAL COMBINED AND PRO FORMA COMBINED FINANCIAL DATA			64
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			66
Overview			66
Outlook			67
Factors Affecting Comparability of Our Historical Results			67
Factors Affecting Our Results of Operations			69
Results of Operations			70
Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011			72
Year Ended December 31, 2011 Compared to Year Ended December 31, 2010			73
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009			74
Liquidity and Capital Resources			75
Cash Flows			76
Amended and Restated Revolving Credit Facility			77
Intercompany Debt			78
New Term Loan Facility			78
Capital Spending			78
Contractual Obligations			79
Off-Balance Sheet Arrangements			79

 

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Critical Accounting Policies			79
Quantitative and Qualitative Disclosures About Market Risk			81
BUSINESS			83
Our Company			83
Competitive Strengths			84
Business Strategy			86
Refining Industry Overview			87
Our Refinery			89
Competition			95
Trade Names, Service Marks and Trademarks			96
Governmental Regulation and Legislation			96
Seasonality			99
Employees			99
Properties			99
Legal Proceedings			99
MANAGEMENT			100
Management of Alon USA Partners, LP			100
Executive Officers and Directors			101
EXECUTIVE COMPENSATION			106
Executive Compensation			106
Director Compensation			110
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			111
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			112
Distributions and Payments to Alon Energy and its Affiliates			112
Agreements with Alon Energy			113
Other Transactions with Related Parties			115
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES			116
Conflicts of Interest			116
Fiduciary Duties of Our General Partner			121
Related Party Transactions			123
DESCRIPTION OF THE COMMON UNITS			124
Our Common Units			124
Transfer Agent and Registrar			124
Transfer of Common Units			124
Listing			125
THE PARTNERSHIP AGREEMENT			126
Organization and Duration			126
Purpose			126
Capital Contributions			126
Adjustments to Capital Accounts Upon Issuance of Additional Common Units			126
Voting Rights			127
Applicable Law; Forum, Venue and Jurisdiction			128
Limited Liability			128
Issuance of Additional Partnership Interests			129
Amendment of Our Partnership Agreement			130
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets			132
Termination and Dissolution			132
Liquidation and Distribution of Proceeds			133
Withdrawal or Removal of Our General Partner			133
Transfer of General Partner Interest			134
Transfer of Ownership Interests in Our General Partner			134
Change of Management Provisions			134

 

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Call Right			134
Non-Citizen Assignees; Redemption			135
Non-Taxpaying Assignees; Redemption			135
Meetings; Voting			136
Status as Limited Partner or Assignee			136
Indemnification			136
Reimbursement of Expenses			137
Books and Reports			137
Right to Inspect Our Books and Records			137
Registration Rights			138
UNITS ELIGIBLE FOR FUTURE SALE			139
MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES			141
Taxation of the Partnership			141
Tax Consequences of Unit Ownership			143
Tax Treatment of Operations			147
Disposition of Units			148
Uniformity of Units			150
Tax-Exempt Organizations and Other Investors			151
Administrative Matters			151
State, Local and Other Tax Considerations			153
INVESTMENT IN ALON USA PARTNERS, LP BY EMPLOYEE BENEFIT PLANS			154
UNDERWRITING			155
VALIDITY OF OUR COMMON UNITS			160
EXPERTS			160
WHERE YOU CAN FIND MORE INFORMATION			160
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.

 

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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.

 

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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 and the twelve months ended September 30, 2012, 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 $         per unit for the twelve months ending September 30, 2013. In order to pay these projected distributions, we must generate approximately $329.3 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 $312.1 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 $         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:

 

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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;

 

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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;

 

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

 

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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

 

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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, and our business interruption insurance coverage does not apply unless a business interruption exceeds 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:

 

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diversion of management time and attention from our existing business;

 

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

 

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

 

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

 

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

 

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

 

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difficulties in achieving anticipated operational improvements;

 

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

 

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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 80% of the common units.

 

•

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 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

 

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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 80% 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. 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     % of our common units (or approximately     % 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. Furthermore, other than any approval required under Alon Energy’s $450.0 million term loan and new term loan facility, 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.

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;

 

•

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;

 

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•

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 $         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.

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         common units outstanding following this offering.         common units are being sold to the public in this offering (or         common units if the underwriters exercise their option to purchase additional common units in full) and         common units will be owned indirectly by Alon Energy following this offering (or         common units if the underwriters exercise their option to purchase additional common units in full). The

 

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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.

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

 

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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.

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.

 

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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 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.

 

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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. 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

 

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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 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 $     per common unit, we expect to receive net proceeds of approximately $             million from the sale of         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 $         million (assuming no exercise of the underwriters’ option to purchase additional common units). Each increase of 1.0 million common units offered by us, together with a concurrent $1.00 increase in the assumed public offering price to $             per common unit, would increase net proceeds to us from this offering by approximately $             million. Similarly, each decrease of 1.0 million common units offered by us, together with a concurrent $1.00 decrease in the assumed initial offering price to $             per common unit, would decrease the net proceeds to us from this offering by approximately $             million.

We intend to use the net proceeds of this offering to repay approximately $             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 $         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 $         million based on an assumed initial offering price of $         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         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 $         million, or approximately $         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 $         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 $         million, or $         per unit. This represents an immediate increase in net tangible book value of $         per unit to our existing unitholders and an immediate pro forma dilution of $         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				$
Pro forma net tangible book value per common unit before this offering(1)
Increase in net tangible book value per common unit attributable to purchasers in this offering and the use of proceeds
Less: Pro forma net tangible book value per common unit after this offering(2)
Immediate dilution in net tangible book value per common unit to purchasers in this offering(3)

 

(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 $         per common unit. Each increase of 1.0 million common units offered by us, together with a concurrent $1.00 increase in the assumed public offering price to $         per common unit, would increase net proceeds to us from this offering by approximately $         million. Similarly, each decrease of 1.0 million common units offered by us, together with a concurrent $1.00 decrease in the assumed initial offering price to $         per common unit, would decrease the net proceeds to us from this offering by approximately $         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					%				(1	)				%
New investors					%				(2	)				%
Total					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 $             million of subordinated debt to our partners’ equity and we will assume debt of $250.0 million before debt issuance costs of $             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         common units in full, then the pro forma increase per unit attributable to new investors would be $            , the net tangible book value per unit after this offering would be $         and the dilution per unit to new investors would be $            . In addition, new investors would purchase         common units, or approximately         % of units outstanding, and the total consideration contributed to us by new investors would increase to $         million, or     % 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 $312.1 million and $329.4 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 $         per common unit for the year ended December 31, 2011 and $         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)			(37.4	)			(40.2	)
Interest expense—related parties(c)			—				—
Income before state income tax expense		$	293.4			$	313.7
State income tax expense			(2.6	)			(3.0	)
Net income		$	290.8			$	310.7
Adjustments to reconcile net income to Adjusted EBITDA:
Interest expense(b)		$	37.4			$	40.2
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)			(35.5	)			(38.2	)
less: Cash interest expense—related parties(c)			—				—
less: State income tax expense			(2.6	)			(3.0	)
Pro forma available cash		$	312.1			$	329.4
Common units outstanding
Pro forma available cash per unit		$				$

 

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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 $329.3 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 $329.3 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			(8.0	)			(7.6	)			(7.6	)			(7.5	)			(30.7	)
Income before state income tax expense		$	107.7			$	80.9			$	84.8			$	70.9			$	344.3
State income tax expense			(0.9	)			(0.7	)			(0.7	)			(0.6	)			(3.0	)
Net income		$	106.8			$	80.2			$	84.1			$	70.3			$	341.3
Adjustments to reconcile net income to Adjusted EBITDA:
Interest expense			8.0				7.6				7.6				7.5				30.7
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			(7.5	)			(7.1	)			(7.1	)			(7.1	)			(28.7	)
Estimated cash available for distribution before special expenses		$	106.2			$	81.0			$	85.0			$	71.3			$	343.4
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		$	102.4			$	77.5			$	81.5			$	67.8			$	329.3
Estimated cash available for distribution per unit		$				$				$				$				$
Cash distributions to common unitholders after special expenses		$	102.4			$	77.5			$	81.5			$	67.8			$	329.3
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 $30.7 million, of which $2.0 million relates to our amended and restated revolving credit facility, $18.7 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 7.5%, 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 $37.4 million, of which $5.9 million related to our amended and restated revolving credit facility, $18.7 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 7.5%, respectively.

For the twelve months ended September 30, 2012, our pro forma interest expense was $40.2 million, of which $7.7 million related to our amended and restated revolving credit facility, $18.7 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 7.5%, 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              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	)			(37,427	)			(30,601	)
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				293,383				268,643
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			$	290,785			$	266,125
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 $211.9 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

 

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		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:
WTI crude oil (per barrel)		$	61.82			$	79.41			$	95.07			$	95.42			$	96.17
WTS crude oil (per barrel)		$	60.30			$	77.26			$	93.01			$	92.95			$	92.08
Crack spreads (per barrel):
Gulf Coast (WTI) 3-2-1		$	7.24			$	8.22			$	23.37			$	24.53			$	27.54
Crude oil differentials (per barrel):
Cushing WTI less Midland WTS		$	1.52			$	2.15			$	2.06			$	2.47			$	4.09
Product price (dollars per gallon):
Gulf Coast unleaded gasoline		$	1.64			$	2.05			$	2.75			$	2.80			$	2.89
Gulf Coast ultra-low sulfur diesel		$	1.66			$	2.16			$	2.97			$	2.97			$	3.06
Natural gas (per MMBtu)		$	4.16			$	4.38			$	4.03			$	4.21			$	2.58

 

(1)	Includes sales to related parties of $416,492 and $450,416 for the nine months ended September 30, 2011 and 2012, respectively, and $277,014, $361,740 and $553,253 for the years ended December 31, 2009, 2010 and 2011, respectively.

(2)	Total refinery throughput represents the total barrels per day of crude oil and blendstock inputs in the refinery production process.

(3)	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.

(4)	Refinery utilization represents average daily crude oil throughput divided by crude oil capacity (which represents the stated refining capacity of our refinery), excluding planned periods of downtime for maintenance and turnarounds.

(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.

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

Net sales. Net sales for the nine months ended September 30, 2012 were $2,651.2 million, compared to $2,351.5 million for the nine months ended September 30, 2011, an increase of $299.7 million or 12.7%. Of this increase, $247.7 million was attributable to higher volumes, primarily higher refinery throughput and $52.0 million was attributable to higher refined product prices from the prior year period. Refinery throughput for the nine months ended September 30, 2012 was 67,884 barrels per day (“bpd”) compared to 60,889 bpd for the nine months ended September 30, 2011, an increase of 11.5%. The average per gallon price of Gulf Coast gasoline for the nine months ended September 30, 2012 increased $0.09, or 3.2%, to $2.89 from $2.80 for the nine months ended September 30, 2011. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the nine months ended September 30, 2012, increased $0.09 or 3.0%, to $3.06 from $2.97 for the nine months ended September 30, 2011.

Cost of Sales. Cost of sales for the nine months ended September 30, 2012 was $2,225.7 million, compared to $1,959.7 million for the nine months ended September 30, 2011, an increase of $266.0 million or 13.6%. Of

 

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this increase, $252.0 million was due to higher volumes, primarily higher refinery throughput. Additionally, cost of sales includes $14.0 million of realized losses on commodity swaps for the nine months ended September 30, 2012.

Direct Operating Expenses. Direct operating expenses for the nine months ended September 30, 2012, were $73.2 million compared to $73.1 million for the nine months ended September 30, 2011, an increase of $0.1 million or 0.1%. The increase is primarily due to increased refinery throughput, partially offset by lower natural gas costs. Refinery direct operating expense per barrel decreased to $3.92 from $4.40 between the two periods reflecting higher throughput.

Selling, General and Administrative Expenses. SG&A expenses for the nine months ended September 30, 2012 were $18.1 million, compared to $12.2 million for the nine months ended September 30, 2011, an increase of $5.9 million or 48.4%. This is primarily due to higher employee related costs.

Depreciation and Amortization. Depreciation and amortization for the nine months ended September 30, 2012 was $35.0 million, compared to $30.2 million for the nine months ended September 30, 2011, an increase of $4.8 million or 15.9%. This increase is due to higher turnaround and catalyst amortization expenses.

Operating Income. Operating income for the nine months ended September 30, 2012, was $299.2 million, compared to $276.2 million for the nine months ended September 30, 2011, an increase of $23.0 million or 8.3%. The increase was primarily due to higher refinery throughput, partially offset by higher selling, general and administrative expenses and depreciation and amortization and slightly lower refinery operating margins. Refinery operating margin at the Big Spring refinery was $22.88 per barrel for the nine months ended September 30, 2012, which includes a negative $0.75 per barrel impact related to realized losses on commodity swaps of $14.0 million, compared to $23.57 per barrel for the nine months ended September 30, 2011. The average Gulf Coast 3/2/1 crack spread increased 12.3% to $27.54 per barrel for the nine months ended September 30, 2012, compared to $24.53 per barrel for the nine months ended September 30, 2011.

Interest Expense. Interest expense for the nine months ended September 30, 2012 was $15.1 million, compared to $12.3 million for the nine months ended September 30, 2011, an increase of $2.8 million, as a result of higher utilization of our amended and restated revolving credit facility due to higher refinery throughput.

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

Net sales. Net sales for the year ended December 31, 2011 were $3,208.0 million compared to $1,639.9 million for the year ended December 31, 2010, an increase of $1,568.1 million or 95.6%. Of this increase, $938.1 million was due to higher volumes, primarily higher refinery throughput and $630.0 million was due to higher refined product prices in 2011 as compared to 2010. Refinery throughput for the year ended December 31, 2011 was 63,614 bpd compared to 49,028 bpd for the year ended December 31, 2010, an increase of 29.8%. The average per gallon price of Gulf Coast gasoline for the year ended December 31, 2011 increased $0.70, or 34.1%, to $2.75 from $2.05 for the year ended December 31, 2010. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the year ended December 31, 2011 increased $0.81, or 37.5%, to $2.97 from $2.16 for the year ended December 31, 2010. Refinery throughput was lower for the year ended December 31, 2010 as a result of the factors discussed above under “—Factors Affecting Comparability of Our Historical Results—Decreased Utilization of Refinery due to February 2008 Fire and Other Downtime.”

Cost of sales. Cost of sales for the year ended December 31, 2011 were $2,722.9 million compared to $1,503.3 million for the year ended December 31, 2010, an increase of $1,219.6 million or 81.1%. Of this increase, $355.0 million was due to an increase in the cost of crude oil and $864.6 million was due to higher volumes, primarily higher refinery throughput in 2011 as compared to 2010. The average price of WTI increased 19.7% from $79.41 per barrel for the year ended December 31, 2010 to $95.07 per barrel for the year ended December 31, 2011. Refinery throughput was lower for the year ended December 31, 2010 as a result of the factors discussed above under “—Factors Affecting Comparability of Our Historical Results—Decreased Utilization of Refinery due to February 2008 Fire and Other Downtime.”

 

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Direct operating expenses. Direct operating expenses for the year ended December 31, 2011 were $98.2 million compared to $90.4 million for the year ended December 31, 2010, an increase of $7.8 million or 8.6%. The increase was primarily due to the increase in operating expenses of $10.3 million resulting primarily from higher refinery throughput in the year ended December 31, 2011 compared to the year ended December 31, 2010, partially offset by a decrease of $2.5 million in natural gas costs. Refinery direct operating expenses per barrel decreased to $4.23 from $5.05 between the two periods reflecting higher throughput.

Selling, general and administrative expenses. SG&A expenses for the year ended December 31, 2011 were $15.6 million compared to $14.4 million for the year ended December 31, 2010, an increase of $1.2 million or 8.3%. This increase was primarily due to higher employee related costs.

Depreciation and amortization. Depreciation and amortization for the year ended December 31, 2011 were $40.4 million compared to $39.6 million for the year ended December 31, 2010, an increase of $0.8 million or 2%.

Operating income (loss). Operating income (loss) for the year ended December 31, 2011 was $330.8 million compared to $(7.7) million for the year ended December 31, 2010, an increase of $338.5 million. The increase was primarily due to higher refinery margins and higher refinery throughput. Refinery operating margin at the Big Spring refinery was $20.89 per barrel for the year ended December 31, 2011, compared to $7.64 per barrel for the year ended December 31, 2010. The average Gulf Coast (WTI) 3-2-1 crack spread increased 184.3% to $23.37 per barrel for the year ended December 31, 2011, from $8.22 per barrel for the year ended December 31, 2010.

Interest expense. Interest expense for the year ended December 31, 2011 was $16.7 million compared to $13.3 million for the year ended December 31, 2010, an increase of $3.4 million, as a result of higher utilization of our amended and restated revolving credit facility due to higher refinery throughput.

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

Net sales. Net sales for the year ended December 31, 2010 were $1,639.9 million compared to $1,498.2 million for the year ended December 31, 2009, an increase of $141.7 million or 9.5%. Of this increase, $409.8 million was due to higher refined product prices which was partially offset by $268.1 million of lower volumes, primarily due to lower refinery throughput. The average per gallon price of Gulf Coast gasoline for year ended December 31, 2010 increased $0.41, or 25.0%, to $2.05 from $1.64 for the year ended December 31, 2009. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the year ended December 31, 2010, increased $0.50 or 30.12%, to $2.16 from $1.66 for the year ended December 31, 2009. Refinery throughput for the year ended December 31, 2010 was 49,028 bpd compared to 59,870 bpd for the year ended December 31, 2009, a decrease of 18.1%. Refinery throughput was lower for the year ended December 31, 2010 as a result of the efforts to implement new operating procedures.

Cost of sales. Cost of sales for the year ended December 31, 2010 were $1,503.3 million compared to $1,398.4 million for the year ended December 31, 2009, an increase of $104.9 million or 7.5%. Of this increase, $345.6 million was due to an increase in the cost of crude oil used by the refinery which was partially offset by $240.7 million of lower volumes, primarily due to lower refinery throughput. The average price of WTI increased 28.5% from $61.82 per barrel for the year ended December 31, 2009 to $79.41 per barrel for the year ended December 31, 2010. Refinery throughput was lower for the year ended December 31, 2010 as a result of the factors discussed above under “—Factors Affecting Comparability of Our Historical Results—Decreased Utilization of Refinery due to February 2008 Fire and Other Downtime.”

Direct operating expenses. Direct operating expenses for the year ended December 31, 2010 were $90.4 million compared to $90.0 million for the year ended December 31, 2009, an increase of $0.4 million or 0.4%. Due to lower refinery throughput in the year ended December 31, 2010, our refinery direct operating expenses per barrel increased to $5.05 in the year ended December 31, 2010 from $4.12 in the year ended December 31, 2009. Despite lower throughput in 2010 as compared to 2009, direct operating expenses increased due in part to higher natural gas costs.

 

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Selling, general and administrative expenses. SG&A expenses for the year ended December 31, 2010 were $14.4 million compared to $16.6 million for the year ended December 31, 2009, a decrease of $2.2 million or 13.3%. This decrease was primarily due to $1.3 million of bad debt expense recorded in the year ended December 31, 2009.

Depreciation and amortization. Depreciation and amortization for the year ended December 31, 2010 were $39.6 million compared to $36.7 million for the year ended December 31, 2009, an increase of $2.9 million, or 7.9%, due primarily to increased capital expenditures after the commissioning of an additional unit and reformer regeneration in 2009.

Operating loss. Operating loss for the year ended December 31, 2010 was $7.7 million compared to $41.3 million for the year ended December 31, 2009, a decrease of $33.6 million or 81.4%. The decrease was primarily due to higher refinery margins and lower SG&A costs. Refinery operating margin at the Big Spring refinery was $7.64 per barrel for the year ended December 31, 2010, compared to $4.57 per barrel for the year ended December 31, 2009. The average Gulf Coast (WTI) 3-2-1 crack spread increased 13.5% to $8.22 per barrel for the year ended December 31, 2010, from $7.24 per barrel for the year ended December 31, 2009.

Interest expense. Interest expense for the year ended December 31, 2010 was $13.3 million compared to $8.2 million for the year ended December 31, 2009, an increase of $5.1 million due to higher utilization of our credit facilities to fund working capital needs.

Liquidity and Capital Resources

Our primary sources of liquidity are cash on hand, cash generated from our operating activities, borrowings under our amended and restated revolving credit facility, our inventory supply and offtake arrangement with J. Aron and third-party credit extensions. Our primary needs for cash are working capital purposes, distributions, debt service, capital expenditures, turnaround and catalyst replacement expenses, and other general partnership purposes. Our ability to generate sufficient cash flows from operating activities will continue to be primarily dependent on our ability to produce and sell our refined products at margins sufficient to cover our fixed and variable expenses.

In February 2011, we entered into a supply and offtake agreement with 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 amended the J. Aron agreement in July 2012 to, among other things, extend the term of the agreement. The amended supply and offtake agreement has an initial term that expires in May 2018, but may be terminated by J. Aron as early as May 2015. Following expiration or termination of the supply and offtake agreement, we are obligated to purchase the crude oil and refined product inventories then owned by J. Aron and located at the Big Spring refinery. Our agreement with J. Aron substantially reduces our need to issue letters of credit to support crude oil purchases. In addition, the structure of this arrangement allows us to acquire crude oil without the constraints of a maximum facility size during periods of high crude oil prices.

We believe that these sources of funds and other sources of capital available to us will be sufficient to satisfy the anticipated cash requirements associated with our existing operations for at least the next twelve months. However, future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors. As a result, we may need to rely on external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our growth. Additionally, our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive, and other factors beyond our control. To the extent we are unable to access external financing sources or generate sufficient cash flows from operations to satisfy our anticipated cash requirements, our distribution policy could significantly impair our ability to grow and our results of operations or liquidity could be adversely affected. Please read “—Capital Spending” for a further discussion of our expected capital expenditures in 2012 and 2013.

 

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Cash Flows

The following table summarizes our net cash provided by or used in our operating activities, investing activities and financing activities for the years ended 2009, 2010 and 2011 and the nine months ended September 30, 2011 and 2012 (dollars in thousands):

 

		Year Ended December 31,												Nine Months Ended September 30,
		2009				2010				2011				2011				2012
														(unaudited)
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	)
Net increase (decrease) in cash and cash equivalents		$	(930	)		$	19,239			$	115,593			$	124,394			$	(106,531	)

Cash Flows Provided By (Used In) Operating Activities

Net cash provided by operating activities was $363.6 million for the nine months ended September 30, 2012 compared to $165.6 million for the nine months ended September 30, 2011. The increase in net cash provided by operating activities of $198.0 million is primarily a result of higher net income for the nine months ended September 30, 2012 of $19.7 million and a reduction in working capital requirements of $178.1 million.

Net cash provided by operating activities was $258.6 million for the year ended December 31, 2011 compared to $60.1 million for the year ended December 31, 2010. The increase of $198.5 million in net cash provided by operating activities was due to higher net income (loss) of $332.9 million for the year ended December 31, 2011 as compared to the year ended December 31, 2010, partially offset by an increase in cash used for working capital of $121.7 million.

Net cash provided by operating activities was $60.1 million for the year ended December 31, 2010 compared to $29.1 million used in operating activities for the year ended December 31, 2009. The increase in net cash provided by operating activities of $89.2 million was due primarily to higher cash provided by working capital of $50.6 million.

Cash Flows Used In Investing Activities

Net cash used in investing activities was $25.5 million for the nine months ended September 30, 2012 compared to $18.0 million for the nine months ended September 30, 2011. The increase of $7.5 million in net cash used in investing activities is due to higher capital expenditures for the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011.

Net cash used in investing activities was $19.5 million for the year ended December 31, 2011 compared to $25.6 million for the year ended December 31, 2010. The decrease of $6.1 million in net cash used in investing activities was due to lower capital expenditures and capital expenditures for turnarounds and catalyst replacement for the year ended December 31, 2011 as compared to the year ended December 31, 2010.

Net cash used in investing activities was $25.6 million for the year ended December 31, 2010 compared to $19.6 million for the year ended December 31, 2009. The difference is primarily attributable to proceeds of $34.1 million received in 2009 from insurance to rebuild the refinery, partially offset by a reduction in cash used for capital expenditures and capital expenditures for turnarounds and catalyst replacement of $30.3 million in the year ended December 31, 2010 as compared to the year ended December 31, 2009.

 

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Cash Flows Used In Financing Activities

Net cash used in financing activities was $444.7 million for the nine months ended September 30, 2012 compared to $23.2 million for the nine months ended September 30, 2011. The increase of $421.5 million in net cash used in financing activities is primarily due to higher net cash repayments of $191.0 million on our revolving credit facility and higher net cash payments of $228.0 million to partners in the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011.

Net cash used in financing activities was $123.4 million for the year ended December 31, 2011 compared to $15.3 million provided by financing activities for the year ended December 31, 2010. The decrease of $108.1 million in net cash used in financing activities was primarily due to higher net cash payments of $153.3 million to partners, partially offset by higher net borrowings under our amended and restated revolving credit facility of $44.0 million for the year ended December 31, 2011 as compared to the year ended December 31, 2010.

Net cash used in financing activities was $15.3 million for the year ended December 31, 2010 compared to $47.8 million provided by financing activities for the year ended December 31, 2009. The decrease of $63.1 million in net cash provided by financing activities was primarily due to a change in net payments of $127.2 million to partners, partially offset by net borrowings of $64.0 million under our amended and restated revolving credit facility in the year ended December 31, 2010 as compared to the year ended December 31, 2009.

Amended and Restated Revolving Credit Facility

We currently have a $240.0 million amended and restated revolving credit facility that will mature on March 1, 2016, with The Israel Discount Bank of New York as the administrative agent. The amended and restated revolving credit facility can be used both for borrowings and the issuance of letters of credit subject to a limit of the lesser of the facility or the amount of the borrowing base under the facility. Summarized below are the principal terms of the amended and restated revolving credit facility, which is qualified in its entirety by reference to the amended and restated revolving credit facility, and its amendments, which are exhibits to the registration statement of which this prospectus forms a part.

Borrowings under the amended and restated revolving credit facility bear interest, payable quarterly, at the Eurodollar rate plus 3.50% per annum subject to an overall minimum interest rate of 4.00%. The amended and restated revolving credit facility is secured by (i) a first lien on our cash, accounts receivables, inventories and related assets and (ii) a second lien on our fixed assets and other specified property. The amended and restated revolving credit facility contains certain restrictive covenants that may limit our ability to incur certain additional debt, pay cash dividends, 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 Consolidated EBITDA ratio, as such terms are defined in the amended and restated revolving credit facility, to be greater than 4.0 to 1.0 as of the end of any period of four fiscal quarters.

The amended and restated revolving credit facility also contains certain customary representations and warranties and events of default. Events of default include, among other things, payment defaults, breaches of covenants, certain events of bankruptcy, certain criminal indictments of our directors and a change of control.

At December 31, 2011 and September 30, 2012, we were in compliance with these covenants. Borrowings of $122.0 million, $200.0 million and $84.0 million were outstanding under the amended and restated revolving credit facility at December 31, 2010 and 2011 and at September 30, 2012, respectively. At December 31, 2010 and 2011, and at September 30, 2012, outstanding letters of credit under the amended and restated revolving credit facility were $117.0 million, $35.5 million and $84.0 million, respectively. We expect to amend and restate our amended and restated revolving credit facility to permit the refinancing of Alon Energy’s $450 million term loan and our assumption of the new term loan facility. We do not expect that this amendment and restatement will result in any material substantive changes to the terms of our amended and restated revolving credit facility.

 

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Intercompany Debt

As of September 30, 2012, we had approximately $346.6 million of 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 do not expect that we will incur any significant additional intercompany debt following the closing of this offering. For additional information, please see “Certain Relationships and Related Party Transactions—Other Transactions with Related Parties—Intercompany Debt.”

New Term Loan Facility

In connection with this offering and the transactions described under “Prospectus Summary—The IPO Transactions,” we expect to assume from Alon Energy a fully drawn $250.0 million term loan facility with Credit Suisse AG, as administrative agent, and a syndicate of financial institutions and lenders. We expect the new term loan facility will have a maturity date approximately six years from the closing of the offering.

We expect that the new term loan facility will be secured at all times by a first priority lien on all of our fixed assets and other specified property, and a second lien on our cash, accounts receivables, inventories and related assets. In connection with our assumption of this new term loan facility, we expect that Alon Energy will be released from its obligations thereunder. After entering into this new term loan facility, we expect that we will no longer be a guarantor of Alon Energy’s $450.0 million term loan facility and our assets will no longer be subject to a lien securing that term loan facility.

Borrowings under the new term loan facility are expected to bear an interest rate equal to the sum of (i) LIBOR (with a floor of 1.25% per annum) plus (ii) a margin of approximately 6.25% per annum for a per annum rate of approximately 7.50%, based on current market rates. Interest will be payable quarterly, or, at our option, at more frequent intervals.

We expect that the new term loan facility will contain customary affirmative and negative covenants for transactions of this nature, including (i) customary reporting requirements; (ii) a requirement to maintain corporate ratings from Moody’s and S&P; (iii) a restriction on our ability to (1) incur additional debt, (2) incur or permit liens to exist on our property; (3) make certain investments, acquisitions or other restricted payments; and (4) modify or terminate certain material contracts. In addition, we expect that our new term loan facility will provide that our board of directors cannot modify our cash distribution policy in a manner adverse to the lenders thereunder. If we should fail to perform our obligations under these covenants, any outstanding borrowings under the new term loan facility, together with accrued interest, could become immediately due and payable. We expect that the new term loan facility will also contain customary default provisions, including a cross default provision to our amended and restated revolving credit facility.

Capital Spending

We divide our capital spending needs into the categories: sustaining maintenance, growth/profit improvement and turnaround and catalyst replacement. Maintenance capital spending includes only non-discretionary maintenance projects and projects required to comply with environmental, health and safety regulations. We undertake discretionary capital spending based on the expected return on incremental capital employed. Discretionary capital projects generally involve an expansion of existing capacity, improvement in product yields, and/or a reduction in direct operating expenses.

 

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The following table summarizes our expected capital expenditures for 2012 and 2013 by major category:

 

		2012				2013
		(dollars in millions)
Sustaining maintenance		$	14.9			$	23.6
Growth/profit improvement/other			5.4				3.9
Rebranding expenses			9.0				—
Turnaround and catalyst replacement			8.1				11.7
Total capital expenditures		$	37.4			$	39.2

We expect to fund these capital expenditures through cash flows from operations and borrowings under our amended and restated revolving credit facility. Our estimated capital expenditures are subject to change due to unanticipated increases/decreases in the cost, scope and completion time for our capital projects. For example, we may experience increases/decreases in labor or equipment costs necessary to comply with government regulations or to complete projects that sustain or improve the profitability of our Big Spring refinery.

Contractual Obligations

We have contractual obligations that are required to be settled in cash. The amount of our contractual obligations as of December 31, 2011 were as follows:

 

		Payments Due by Period
Contractual Obligations		Less than 1 Year				1 - 3 Years				3 - 5 Years				More Than 5 Years				Total
		(dollars in thousands)
Long-term debt obligations		$	—			$	—			$	200,000			$	—			$	200,000
Subordinated debt—related parties			—				—				—				333,592				333,592
Operating lease obligations			12,278				16,452				14,285				11,538				54,553
Pipelines and terminals agreements(1)			32,842				67,945				63,687				112,367				276,841
Other commitments(2)			3,741				7,482				7,482				19,639				38,344
Total obligations		$	48,861			$	91,879			$	285,454			$	477,136			$	903,330

 

(1)	Balances represent the minimum committed volume multiplied by the tariff and terminal rates pursuant to the terms of the pipelines and terminals agreement with HEP, as well as our minimum requirements under the throughput and deficiency agreement with Sunoco Pipeline, LP.

(2)	Other commitments include refinery maintenance services costs.

As of December 31, 2011, we did not have any material capital lease obligations or any agreements to purchase goods or services, other than those included in the table above, that were binding on us.

Off-Balance Sheet Arrangements

We have no material off-balance sheet arrangements.

Critical Accounting Policies

Our accounting policies are described in the notes to our audited combined financial statements included elsewhere in this prospectus. We prepare our combined financial statements in conformity with GAAP. In order to apply these principles, we must make judgments, assumptions and estimates based on the best available information at the time. Actual results may differ based on the accuracy of the information utilized and subsequent events, some of which we may have little or no control over. Our critical accounting policies, which are discussed below, could materially affect the amounts recorded in our combined financial statements.

 

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Inventory. Crude oil, refined products and blendstocks are priced at the lower of cost or market value. Cost is determined using the LIFO valuation method. Under the LIFO valuation method, we charge the most recent acquisition costs to cost of sales, and we value inventories at the earliest acquisition costs. We selected this method because we believe it more accurately reflects the cost of our current sales. If the market value of inventory is less than the inventory cost on a LIFO basis, then the inventory is written down to market value. An inventory write-down to market value results in a non-cash accounting adjustment, decreasing the value of our crude oil and refined products inventory and increasing our cost of sales. A reduction of inventory volumes during 2011 and 2010 resulted in a liquidation of LIFO inventory layers carried at lower costs which prevailed in previous years. The liquidation decreased costs of sales by approximately $42.7 million and $24.2 million during 2011 and 2010, respectively. Market values of crude oil, refined products and blendstock inventories exceeded LIFO costs by $21.9 million and $60.8 million at December 31, 2011 and 2010, respectively.

Environmental and Other Loss Contingencies. We record liabilities for loss contingencies, including environmental remediation costs, when such losses are probable and can be reasonably estimated. Our environmental liabilities represent the estimated cost to investigate and remediate contamination at our properties. Our estimates are based upon internal and third-party assessments of contamination, available remediation technology and environmental regulations. Accruals for estimated liabilities from projected environmental remediation obligations are recognized no later than the completion of the remedial feasibility study. These accruals are adjusted as further information develops or circumstances change. We do not discount environmental liabilities to their present value unless payments are fixed and determinable. At December 31, 2011, for those payments we considered fixed and determinable, payments were discounted at a 4.00% rate. We record them without considering potential recoveries from third parties. Recoveries of environmental remediation costs from third parties are recorded as assets when receipt is deemed probable. We update our estimates to reflect changes in factual information, available technology or applicable laws and regulations.

Turnarounds and Catalyst Replacement Costs. We record the cost of planned major refinery maintenance, referred to as turnarounds, and chemical catalyst used in the refinery process units, which are typically replaced in conjunction with planned turnarounds, in “Other assets” in our combined financial statements. 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. The amortization of deferred turnaround and catalyst replacement costs are presented in “Depreciation and amortization” in our combined financial statements.

Impairment of Long-Lived Assets. We account for impairment of long-lived assets in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Subtopic 360-10, Property, Plant, and Equipment. In evaluating our assets, long-lived assets and certain identifiable intangible assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of an asset to future net cash flows expected to be generated by the asset. If the carrying value of an asset exceeds its expected future cash flows, an impairment loss is recognized based on the excess of the carrying value of the impaired asset over its fair value. These future cash flows and fair values are estimates based on our judgment and assumptions. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs of disposition.

Asset Retirement Obligations. We use ASC Subtopic 410-20, Asset Retirement Obligations, which established accounting standards for recognition and measurement of a liability for an asset retirement obligation and the associated asset retirement costs. The provisions of ASC Subtopic 410-20 apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation of a long-lived asset. ASC Subtopic 410-20 also requires companies to recognize a liability for the fair value of a legal obligation to perform asset retirement activities that are conditional on a future event, if the amount can be reasonably estimated.

 

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In order to determine fair value, management must make certain estimates and assumptions including, among other things, projected cash flows, a credit-adjusted risk-free rate and an assessment of market conditions that could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are subjective.

Quantitative and Qualitative Disclosures About Market Risk

Changes in commodity prices, purchased fuel prices and interest rates are our primary sources of market risk. Our risk management committee oversees all activities associated with the identification, assessment and management of our market risk exposure.

Commodity Price Risk

We are exposed to market risks related to the volatility of crude oil and refined product prices, as well as volatility in the price of natural gas used in our refinery operations. Our financial results can be affected significantly by fluctuations in these prices, which depend on many factors, including demand for crude oil, gasoline and other refined products, changes in the economy, worldwide production levels, worldwide inventory levels and governmental regulatory initiatives. Alon Energy’s risk management strategy identifies circumstances in which we may utilize the commodity futures market to manage risk associated with these price fluctuations.

In order to manage the uncertainty relating to inventory price volatility, we have consistently applied a policy of maintaining inventories at or below a targeted operating level. In the past, circumstances have occurred, such as timing of crude oil cargo deliveries, turnaround schedules or shifts in market demand that have resulted in variances between our actual inventory level and our desired target level. Upon the review and approval of Alon Energy’s risk management committee, we may utilize the commodity futures market to manage these anticipated inventory variances.

We maintain inventories of crude oil, refined products and blendstocks, the values of which are subject to wide fluctuations in market prices driven by world economic conditions, regional and global inventory levels and seasonal conditions. As of December 31, 2011, we held approximately 0.4 million barrels of crude oil and refined product inventories valued under the LIFO valuation method. Market value exceeded carrying value of LIFO costs by $21.9 million. We refer to this excess as our LIFO reserve. If the market value of these inventories had been $1.00 per barrel lower, our LIFO reserve would have been reduced by $0.4 million.

In accordance with fair value provisions of ASC 825-10, all commodity futures contracts are recorded at fair value and any changes in fair value between periods is recorded in the profit and loss section of our combined financial statements. “Forwards” represent physical trades for which pricing and quantities have been set, but the physical product delivery has not occurred by the end of the reporting period. “Futures” represent trades which have been executed on the New York Mercantile Exchange which have not been closed or settled at the end of the reporting period. A “long” represents an obligation to purchase product and a “short” represents an obligation to sell product.

 

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The following table provides information about our derivative commodity instruments as of December 31, 2011:

 

Description of Activity		Contract Volume (in barrels)				Wtd Avg Purchase Price/BBL				Wtd Avg Sales Price/BBL				Contract Value				Market Value				Gain (Loss)
																		(in thousands)
Forwards-short (Crude)			(70,351	)		$	—			$	98.57			$	(6,935	)		$	(6,953	)		$	(18	)
Forwards-long (Gasoline)			73,340				107.88				—				7,912				8,182				270
Forwards-long (Distillate)			165,530				123.78				—				20,490				20,883				393
Forwards-long (Jet)			35,795				122.96				—				4,401				4,502				101
Forwards-short (Slurry)			(16,943	)			—				94.25				(1,597	)			(1,624	)			(27	)
Forwards-short (Catfeed)			(213	)			—				107.65				(23	)			(24	)			(1	)
Forwards-short (Slop)			(991	)			—				88.58				(88	)			(88	)			—
Forwards-short (Propane)			(50,000	)			—				55.66				(2,783	)			(2,788	)			(5	)
Futures-long (Crude)			188,000				88.93				—				16,719				16,642				(77	)
Futures-short (Gasoline)			(60,000	)			—				109.78				(6,587	)			(6,697	)			(110	)
Futures-short (Distillate)			(185,000	)			—				121.97				(22,564	)			(22,643	)			(79	)

Interest Rate Risk

We had borrowings of $84.0 million, $200.0 million and $122.0 million outstanding under the amended and restated revolving credit facility at September 30, 2012 and December 31, 2011 and 2010, respectively. 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%.

An increase of 1.00% in the Eurodollar rate on indebtedness, net of the minimum interest rate, would result in an increase in our interest expense of approximately $0.6 million per year.

Customer Credit Risk

We are subject to risk of losses resulting from nonpayment or nonperformance by our customers. We will continue to closely monitor the creditworthiness of customers to whom we grant credit and establish credit limits in accordance with our credit policy.

 

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BUSINESS

Our Company

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 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.

 

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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 also sell motor fuels that we purchase from third parties where necessary to supply certain of our customers’ operations that are relatively distant from our distribution network. 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.

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 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.

 

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The following graph illustrates our crude oil source differentials from 2006 through the third quarter of 2012:

 

Average Prices from Alon Energy.

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,

 

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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.

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 pursuant to 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     % 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.”

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;

 

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•

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

 

•

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, 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. The agreement substantially reduces our need to issue letters of credit to support crude oil purchases. In addition, the structure allows us to acquire crude oil without the constraints of a maximum facility size during periods of high crude oil prices. 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 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

 

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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 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.

The map below illustrates U.S. oil refinery capacity as of July 2012.

 

Source: EIA as of July 19, 2012

 

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Refineries, such as our Big Spring refinery, located in close proximity to Midland can source a majority of their crude from Midland and therefore benefit from any favorable price differential between Midland WTI and Cushing WTI. Recent increased production in the Permian Basin and continued over supply at Cushing is causing additional oil to enter the Midland market and drive the price of Midland WTI lower. According to the EIA, oil production in the Permian Basin increased to 1.0 million bpd in December 2011 and is expected to increase to 1.55 million bpd by January 2014.

The Midland WTI–Cushing WTI crude price differential reached just below $(9.00) per barrel on April 5, 2012, the widest since 1991. During the first nine months of 2012, the differential averaged $(2.79) per barrel. This differential is primarily driven by a lack of transportation infrastructure in Cushing and Midland that will likely be corrected in the longer-term. Infrastructure plans in the region include Magellan Midstream’s reversal of the former Longhorn Pipeline that runs from Houston to Crane, Texas and an expansion of Sunoco Logistics’ West Texas Gulf line from the Permian Basin to Longview, Texas. However, oil producers would incur additional transportation cost to transport crude through these pipelines, and we believe our Big Spring refinery should still be able to access its crude supply at a discount to Cushing WTI.

Complex refineries that can process sour crudes, such as our Big Spring refinery, often capture margin benefit due to the pricing differential between sour crudes like WTS and sweet crudes like WTI. The Midland WTS–Midland WTI differential averaged $(1.26) per barrel in 2009, $(1.78) per barrel in 2010, and $(1.49) per barrel in 2011. During the first nine months of 2012, as larger amounts of sweet crude oil from Cushing have entered the Midland market, the price of Midland WTI has experienced increased downward price pressure which has in turn compressed the Midland WTS–Midland WTI differential during the first nine months of 2012 to an average of $(1.23) per barrel. We believe that as the Midland WTI–NYMEX Cushing WTI differential declines, as a result of increased midstream capacity alleviating the bottleneck at Cushing, the Midland WTS–Midland WTI differential will return to levels more in-line with historic averages, and allow our Big Spring refinery to continue experiencing strong margins over the longer-term despite a reduction in the Midland WTI–NYMEX Cushing WTI differential.

Our Refinery

We acquired our Big Spring refinery and certain crude oil pipelines, product pipelines and product terminals from FINA in August 2000. In March 2005, we successfully completed a major turnaround at our Big Spring refinery. In connection with this turnaround, we expanded our crude oil throughput capacity from approximately 62,000 bpd to our current capacity of approximately 70,000 bpd.

Our Big Spring refinery is located on 1,306 acres in the Permian Basin in West Texas. In industry terms, our Big Spring refinery is characterized as a “cracking refinery,” which generally refers to a refinery utilizing

 

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vacuum distillation and catalytic cracking processes in addition to basic distillation, naphtha reforming and hydrotreating processes, to produce higher light product yields through the conversion of heavier fuel oils into gasoline, light distillates and intermediate products. Major processing units at our Big Spring refinery include fluid catalytic cracking, naphtha reforming, vacuum distillation, hydrotreating and alkylation units.

Raw Material Supply

Sour crude oil has typically accounted for approximately 80.0% of our crude oil input. For the year ended December 31, 2011 and the nine months ended September 30, 2012, WTS was approximately 80.4% and 78.6%, respectively, of the Big Spring refinery’s total throughput. The Big Spring refinery is the closest refinery to Midland, Texas, which is the largest origination terminal for West Texas crude oil. We believe this location provides us with the lowest transportation cost differential for West Texas crude oil of any refinery.

The following table summarizes historical throughput data for our Big Spring refinery:

 

		Year Ended December 31,																								Nine Months Ended September 30, 2012
		2009								2010								2011
		bpd				%				bpd				%				bpd				%				bpd				%
Refinery throughput:
WTS crude			48,340				80.8				39,349				80.2				51,202				80.4				53,297				78.6
WTI crude			9,238				15.4				7,288				14.9				10,023				15.8				12,790				18.8
Blendstocks			2,292				3.8				2,391				4.9				2,389				3.8				1,797				2.6
Total refinery throughput(1)			59,870				100.0				49,028				100.0				63,614				100.0				67,884				100.0
Refinery utilization(2)							82.3	%							68.2	%							90.8	%							97.3	%

 

(1)	Total refinery throughput represents the total barrels per day of crude oil and blendstock inputs in the refinery production process.

(2)	Refinery utilization represents average daily crude oil throughput divided by crude oil capacity, excluding planned periods of downtime for maintenance and turnarounds.

Prior to 2011, more than half of our crude oil input requirements was purchased through short-term contracts with several suppliers, including major oil companies. In February 2011, we entered into a supply and offtake agreement with J. Aron, pursuant to which we purchase crude oil for processing at the Big Spring refinery, and we amended our agreement with J. Aron in July 2012. For the year ended December 31, 2011, J. Aron supplied 52.9% of our crude oil feedstock through arrangements with various oil companies. The supply and offtake agreement with J. Aron has an initial term that expires in May 2018. J. Aron may elect to terminate the agreement prior to the initial term beginning in May 2015, provided we receive notice of termination at least six months prior to that date. Following expiration or termination of the supply and offtake agreement, we are obligated to purchase the crude oil and refined product inventories then owned by J. Aron and located at the Big Spring refinery.

In addition, access to the Amdel and White Oil pipelines gives us the ability to optimize our refinery crude slate by transporting foreign and domestic crude oils to our Big Spring refinery from the Gulf Coast when the economics for processing those crude oils are more favorable than processing locally sourced crude oils. Other feedstocks, including butane, isobutane and asphalt blending components, are delivered by truck and railcar, and a majority of the natural gas we use to run the refinery is delivered by a pipeline in which we own a 63.0% interest.

 

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The map below provides an overview of the crude oil pipelines, refined product pipelines and product terminals that serve and are serviced by our Big Spring refinery.

 

Crude Oil Pipelines

We receive WTS crude oil and WTI crude oil primarily from regional common carrier pipelines. We also have access to offshore domestic and foreign crude oils available on the Gulf Coast through the Amdel and White Oil pipelines. This combination of access to Permian Basin crude oil and foreign and offshore domestic crude oil from the Gulf Coast allows us to optimize our crude oil supply at any given time. The crude oil pipelines we utilize consist of the following:

 

Crude Oil Pipelines		Status		Miles		Connections
Amdel		Sunoco throughput and deficiency agreement		504		Midland and Nederland
White Oil		Sunoco throughput and deficiency agreement		25		Garden City (Amdel) and Big Spring
Mesa Interconnect		Owned		4		Mesa pipeline and Big Spring
Centurion		Centurion agreement		40		Midland and Roberts Junction
Centurion Interconnect		Owned (leased to Centurion)		3		Centurion pipeline and Big Spring

The bi-directional Amdel pipeline and the White Oil pipeline connect our refinery to Nederland, Texas, which is located on the Gulf Coast, and to Midland, Texas. Permian Basin crude oil is delivered to our Big Spring refinery through the Mesa Interconnect pipeline which is connected to the Mesa pipeline system, a common carrier, and through our owned connection pipeline which is leased to Centurion Pipeline L.P. (“Centurion”) and connected to the Centurion pipeline system from Midland, Texas to Roberts Junction Texas.

On March 1, 2006, Alon Energy sold the Amdel and White Oil crude pipelines to an affiliate of Sunoco and entered into a 10-year pipeline throughput and deficiency agreement with Sunoco. We commenced shipments of crude oil through the Amdel and White Oil pipelines under this agreement in October 2006. In October 2011, the throughput and deficiency agreement was replaced with a new throughput and deficiency agreement, which gives

 

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us the option to transport crude oil through the Amdel Pipeline either westbound from the Nederland Terminal to the Big Spring refinery, or eastbound from the Big Spring refinery to the Nederland Terminal for further barge transportation to Alon Energy’s Krotz Springs, Louisiana refinery. Our minimum throughput commitment under the new agreement is 15,645 bpd, which is being fulfilled by Alon Energy’s Krotz Springs refinery. The new agreement has a term of five years with options to extend the agreement by four additional thirty-month periods.

To further diversify our crude oil delivery sources, we entered into a 15-year arrangement with Centurion in June 2006. Pursuant to this arrangement, Centurion provides us with crude oil transportation pipeline capacity, and we ship a minimum of 21,500 bpd of crude oil from Midland, Texas to our Big Spring refinery using Centurion’s approximately 40-mile pipeline system from Midland to Roberts Junction and our owned three-mile pipeline from Roberts Junction to the Big Spring refinery, which we lease to Centurion. We commenced shipments of crude oil through these pipelines in November 2006. This agreement was amended in April 2012 to increase the minimum throughput to 25,000 bpd and to extend the initial term for one year.

Refinery Production

Our Big Spring refinery produces ultra-low sulfur gasoline, ultra-low sulfur diesel, jet fuel, petrochemicals, petrochemical feedstocks, asphalt and other petroleum products. This refinery typically converts approximately 90.0% of its feedstock into finished products such as gasoline, diesel, jet fuel and petrochemicals, with the remaining 10.0% primarily converted to asphalt and liquefied petroleum gas.

The following table summarizes historical production data for our Big Spring refinery for the periods presented:

 

		Year Ended December 31,																								Nine Months Ended September 30, 2012
		2009								2010								2011
		bpd				%				bpd				%				bpd				%				bpd				%
Refinery production:
Gasoline			26,826				45.0				24,625				50.7				31,105				49.1				33,653				49.6
Diesel/jet			19,136				32.2				15,869				32.7				20,544				32.3				22,234				32.8
Asphalt			5,289				8.9				2,827				5.8				4,539				7.1				4,241				6.3
Petrochemicals			2,928				4.9				2,939				6.0				3,837				6.0				4,005				5.9
Other			5,327				9.0				2,341				4.8				3,488				5.5				3,627				5.4
Total refinery production			59,506				100.0				48,601				100.0				63,513				100.0				67,760				100.0
Refined products sales to Alon Energy			12,785				21.5				11,462				23.6				13,816				21.8				14,390				21.2

Reduced refinery production in 2010 reflects the new operating procedures we implemented in 2010. Refinery production for 2009 reflects the effects of downtime associated with rebuilding after the fire in 2008, 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.

Gasoline. For the year ended December 31, 2011 and the nine months ended September 30, 2012, gasoline accounted for approximately 49.1% and 49.6% of our production, respectively. We produce various grades of gasoline, ranging from 84 sub-octane regular unleaded to 91 octane premium unleaded, and use a computerized component blending system to optimize gasoline blending. We completed our ultra-low sulfur gasoline project in 2009 and gasoline currently produced at the Big Spring refinery complies with the EPA’s ultra-low sulfur gasoline standard of 30 parts per million (“ppm”). We are capable of producing specially formulated fuels, such as those required in the El Paso, Dallas/Fort Worth and Arizona markets.

Diesel and Jet Fuels. For the year ended December 31, 2011 and the nine months ended September 30, 2012, diesel and jet fuel accounted for approximately 32.3% and 32.8% of production, respectively. All of the on-road specification diesel fuel we produce meets the EPA’s ultra-low sulfur diesel standard of 15 ppm. Our jet fuel production conforms to the JP-8 grade military specifications.

 

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Asphalt. Asphalt accounted for approximately 7.1% and 6.3% of production in the year ended December 31, 2011 and the nine months ended September 30, 2012, respectively. Our asphalt facilities are capable of producing up to 30 different product formulations, including both polymer modified asphalt (“PMA”) and ground tire rubber (“GTR”) asphalt. The asphalt we produced is sold at prices substantially determined by reference to the cost of crude oil, which is intended to approximate bulk wholesale market prices.

Petrochemical Feedstocks and Other. We produce propane, propylene, certain aromatics, specialty solvents and benzene for use as petrochemical feedstocks, along with other by-products such as sulfur and carbon black oil. We have sulfur processing capabilities of approximately two tons per thousand bpd of crude oil capacity, which is above the average for cracking refineries and aids in our ability to produce low sulfur motor fuels while continuing to process significant amounts of sour crude oil.

Refined Product Pipelines

The product pipelines we utilize to deliver refined products are linked to the major third-party product pipelines in the geographic area around our Big Spring refinery. These pipelines provide us flexibility to optimize product flows into multiple regional markets. This product pipeline network can also (1) receive additional transportation fuel products from the Gulf Coast through the Delek product terminal and Magellan pipelines, (2) deliver and receive products to and from the Magellan system, our connection to the Group III, or mid-continent markets, and (3) deliver products to the New Mexico and Arizona markets through third-party systems. The following table describes the product pipelines which we utilize:

 

Refined Product Pipelines		Access		Miles		Connections		Expiration Date
Plains (2)		Lease		38		Coahoma and Midland		2012
Fin-Tex		HEP pipelines and terminals agreement		137		Midland and Orla (Holly)		2035
Holly		Lease		133		Orla and El Paso		2022
Trust		HEP pipelines and terminals agreement		332		Big Spring/Abilene/Wichita Falls		2035
Dyess JP-8		HEP pipelines and terminals agreement		2		Abilene and Dyess Air Force Base		2035
River		HEP pipelines and terminals agreement		47		Wichita Falls and Duncan (Magellan)		2035
Carswell		Owned		148		Abilene and Fort Worth		N/A

 

(1)	For those pipelines accessed pursuant to the HEP pipelines and terminals agreement, we have committed to transport and store minimum volumes of refined products, as further described below.

(2)	The description of the Plains pipeline does not include a 4-mile pipeline that we own connecting Big Spring and Coahoma, Texas.

In February 2005, we completed the contribution of the Fin-Tex, Trust, River and Dyess JP-8 product pipelines and certain connected product terminals to HEP. Simultaneous with this transaction, we entered into a pipelines and terminals agreement with HEP, which has a 15-year term with three additional five-year renewal terms exercisable at our sole option. Pursuant to the pipelines and terminals agreement, we have committed to transport and store minimum volumes of refined products in these pipelines and terminals. The tariff rates applicable to the transportation of refined products on the pipelines are variable, with a base fee which is reduced for volumes exceeding defined volumetric targets. The agreement provides for the reduction of the minimum volume requirement under certain circumstances. The service fees for the storage of refined products in the terminals are initially set at rates competitive in the marketplace.

The Plains, Fin-Tex and Holly pipelines make up the Fin-Tex system. Our access to the Plains and Holly pipelines is secured by pipeline leases with Plains Pipeline, L.P. and HEP, respectively, while our access to the Fin-Tex pipeline is provided through our pipelines and terminals agreement with HEP. The Fin-Tex system transports product from the Big Spring refinery to El Paso, Texas and allows product to be placed in Tucson and Phoenix, Arizona through the third-party Kinder Morgan pipeline. The Fin-Tex system also gives us access to the Albuquerque and Bloomfield, New Mexico markets. We deliver physical barrels to El Paso and receive, through exchanges with third parties, physical barrels in Albuquerque and Bloomfield.

 

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The Trust pipeline connects our refinery to terminals in Abilene and Wichita Falls, while the River pipeline connects the terminal in Wichita Falls to our Duncan, Oklahoma terminal. At Duncan, the River pipeline connects into the Magellan pipeline system for sales into Group III, or mid-continent markets. The Trust and River pipeline system is a bi-directional pipeline system which we access through our pipelines and terminals agreement with HEP.

The Dyess JP-8 pipeline connects the Abilene terminal to Dyess Air Force Base. Our access to this pipeline is also provided through our pipelines and terminals agreement with HEP.

The Carswell pipeline system runs from Abilene to Fort Worth, Texas. The Carswell pipeline is currently inactive.

Product Terminals

We primarily utilize the following five product terminals for delivery of transportation fuels, of which two are owned and three are accessed through our pipelines and terminal agreement with HEP:

 

Terminals		Access		Working Capacity (1)				Supply Source		Mode of Delivery
Big Spring, Texas(2)		Owned			331			Pipeline/refinery		Pipeline/truck
Abilene, Texas		HEP pipelines and terminal agreement			111			Pipeline		Pipeline/truck
Wichita Falls, Texas		HEP pipelines and terminal agreement			189			Pipeline		Pipeline/truck
Duncan, Oklahoma		Owned(3)			154			Pipeline		Pipeline
Orla, Texas		HEP pipelines and terminal agreement			116			Pipeline		Pipeline
Total					901

 

(1)	Measured in thousands of barrels.

(2)	Includes the tankage located at our refinery.

(3)	The terminal is owned, but the underlying real property is leased.

All five terminals we access are physically integrated with our refinery through the product pipelines we utilize. Three of these five terminals, Big Spring, Abilene and Wichita Falls, are equipped with truck loading racks. The other two terminals, Duncan, Oklahoma and Orla, Texas, are used for delivering shipments into third-party pipeline systems. We also directly access three other terminals located in El Paso, Texas and Tucson and Phoenix, Arizona.

Supply Arrangements

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. Please read “Certain Relationships and Related Party Transactions—Agreements with Alon Energy—Supply Agreement.”

In addition, pursuant to our supply and offtake agreement with J. Aron, J. Aron purchases certain refined products we produce at the Big Spring refinery at market prices.

Marketing

Branded Transportation Fuel Marketing. We sell approximately 56.1% of the gasoline produced at our Big Spring refinery on a branded basis. We sell motor fuel under the Alon brand through various terminals to supply

 

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approximately 625 locations, including the majority of Alon Energy’s 299 retail locations and other Alon-branded independent locations. For the year ended December 31, 2011 and the nine months ended September 30, 2012, we sold 368.4 million and 290.7 million gallons, respectively, of branded motor fuel for distribution to Alon Energy’s retail convenience stores and other retail distribution outlets.

Unbranded Transportation Fuel Marketing. We presently sell a majority of the diesel fuel and approximately 22.7% of the gasoline produced at our Big Spring refinery on an unbranded basis. For the year ended December 31, 2011 and the nine months ended September 30, 2012, we sold over 17,278 bpd and 20,710 bpd, respectively, of our diesel fuel and gasoline production as unbranded fuels, which were largely sold through our physically integrated system.

Product Supply Sales. We sell transportation fuel production in excess of our branded and unbranded marketing needs through bulk sales and exchange channels. These bulk sales and exchange arrangements are entered into with various oil companies and traders and are transported through our product pipeline network or truck deliveries. Our petrochemical feedstock and other petroleum product production is sold to a wide customer base and is transported through truck and railcars.

Jet Fuel Marketing. We market substantially all the jet fuel produced at our Big Spring refinery as JP-8 grade to the Defense Energy Supply Center (“DESC”). All DESC contracts are for a one-year term and are awarded through a competitive bidding process. We have traditionally bid for contracts to supply Dyess Air Force Base in Abilene, Texas and Sheppard Air Force Base in Wichita Falls, Texas. Jet fuel production in excess of existing contracts is sold through unbranded rack sales.

Distribution Network and Distributor Arrangements. We sell motor fuel to Alon Energy’s retail locations and to approximately 20 third-party distributors, who then supply and sell to retail outlets. The supply agreements we maintain with our distributors are generally for three-year terms and usually include 10-day payment terms. All supplied distributors comply with our ratability program, which involves incentives and penalties based on the consistency of their purchases.

Alon Brand Sub-Licensing. We sub-license the Alon brand and provide payment card processing services, advertising programs and loyalty and other marketing programs to 37 distributors supplying approximately 130 additional stores. We offer sub-licensing to distributors supplying geographic areas where we choose not to supply motor fuels. This sub-licensing program allows us to expand the geographic footprint of the Alon brand, thereby increasing its recognition. Each sub-licensee pays royalties on a per gallon basis and is required to comply with the minimum standards program and utilize our payment card processing services.

Competition

The petroleum refining and marketing industry continues to be highly competitive. Our principal competitors include major independent refining and marketing companies such as Valero and Phillips 66. Our industry is also impacted by competition from integrated, multi-national oil companies, including Chevron, ExxonMobil and Shell. Because of their diversity, integration of operations and larger capitalization, these major competitors may have greater financial support and diversity with a potential better ability to bear the economic risks, operating risks and volatile market conditions associated with the petroleum industry.

Financial returns in the refining and marketing industry depend on the difference between refined product prices and the prices for crude oil and other feedstock, also referred to as refining margins. Refining margins are impacted by, among other things, levels of crude oil and refined product inventories, balance of supply and demand, utilization rates of refineries and global economic and political events.

All of our crude oil and feedstocks are purchased from third-party sources, while some of our vertically integrated competitors have their own sources of crude oil that they may use to supply their refineries. However, our Big Spring refinery is in close proximity to Midland, Texas, which is the largest origination terminal for

 

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West Texas crude oil, which we believe provides us with transportation cost advantages over many of our competitors in this region.

The market for our refined products are generally supplied by a number of refiners, including large integrated oil companies or independent refiners. These larger companies typically have greater resources and may have greater flexibility in responding to volatile market conditions or absorbing market changes.

The principal competitive factors affecting our wholesale marketing business are price and quality of products, reliability and availability of supply and location of distribution points.

Trade Names, Service Marks and Trademarks

We hold and use certain trade secret and confidential information related specifically to our refining operations. In addition, we are party to various process license agreements that allow us to use certain intellectual property rights of third parties in our refining operations pursuant to fully paid up licenses.

Governmental Regulation and Legislation

Environmental Controls and Expenditures

Our operations are subject to extensive and frequently changing federal, state, regional and local laws, regulations and ordinances relating to the protection of the environment, including those governing emissions or discharges to the air, water, and land, the handling, reclamation and/or disposal of petroleum hydrocarbons, hazardous substances and wastes and the remediation of contamination. We believe our operations are generally in substantial compliance with these requirements. Over the next several years our operations will have to meet new requirements being promulgated by the EPA and the states and jurisdictions in which we operate.

Fuels. The federal Clean Air Act and its implementing regulations require, among other things, significant reductions in the sulfur content in gasoline and diesel fuel. These regulations required most refineries to reduce the sulfur content in gasoline to 30 ppm and diesel to 15 ppm.

Gasoline and diesel produced at our Big Spring refinery currently meet the low sulfur gasoline and ultralow sulfur diesel fuel standards. The EPA is expected to publish a proposed rule to further reduce sulfur in gasoline and diesel fuel in the second half of 2012, and the rule is expected to be finalized in 2013. Depending on the final standard, our Big Spring refinery may be required to install controls to further reduce sulfur. The need for or costs of any such controls is not known at this time.

In February 2007, the EPA adopted final rules to reduce the levels of benzene in gasoline on a nationwide basis. More specifically, beginning in 2011, refiners meet an annual average gasoline benzene content standard of 0.62%, which may be achieved through the purchase of benzene credits, and that beginning on July 1, 2012, refiners meet a maximum average gasoline benzene concentration of 1.30%, by volume on all gasoline produced, both reformulated and conventional and without benzene credits. We have spent $14.2 million through 2011 and estimate an additional $21.0 million in costs through 2016 will be necessary in order for our Big Spring refinery to install controls to achieve these standards. Under the regulations, the EPA may grant extensions of time to comply with the annual average benzene standard if a refinery demonstrates that unusual circumstances exist that impose extreme hardship and significantly affect the ability of the refinery to comply.

We are subject to the renewable fuel standard which requires refiners to blend renewable fuels (e.g., ethanol, biodiesel) into their finished transportation fuels or purchase renewable energy credits, called RINs, in lieu of blending. The EPA establishes new annual renewable fuel percentage standards for each compliance year in the preceding year. Effective January 1, 2012, the EPA raised the renewable fuel percentage standard to

 

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approximately 9.2%. Our Big Spring refinery has received an extension of the deadline to comply with the renewable fuel standard. Therefore, we will not be required to blend renewable fuels or purchase RINs for compliance until January 1, 2013, unless a further extension is received.

Air Emissions. Conditions may develop that require additional capital expenditures at our Big Spring refinery, product terminals and retail gasoline stations (operating and closed locations) for compliance with the Federal Clean Air Act and other federal, state and local requirements. We cannot currently determine the amounts of such future expenditures.

The EPA has adopted regulations requiring certain new or modified sources of high-volume GHG emissions to install best achievable control technology to reduce GHG emissions. If we undertake significant improvements at our Big Spring refinery that could result in an increase in GHG emissions, we could be required under EPA’s regulations to install expensive GHG emissions control equipment. Although Congress has from time to time considered adopting legislation to reduce emissions of GHGs through establishment of a market-based “cap and trade” system that would be designed to achieve yearly reductions in GHG emissions, no such legislation has been passed. While it is possible that Congress will adopt some form of federal mandatory GHG emission reductions legislation in the future, the timing and specific requirements of any such legislation are uncertain at this time.

In October 2006, we were contacted by Region 6 of the EPA and invited to enter into discussions under the EPA’s National Petroleum Refinery Initiative. This initiative addresses what the EPA deems to be the most significant Clean Air Act compliance concerns affecting the petroleum refining industry. 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. If we enter into a global settlement, it would apply to our Big Spring refinery. Based on prior settlements that the EPA has reached with other petroleum refineries under the initiative, we anticipate that the EPA will seek relief 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 this time, we cannot estimate the cost of any such controls, civil penalties or environmentally beneficial projects. See “Risk Factors—Risks Inherent in Our Business—We may incur significant costs to comply with new or changing environmental laws and regulations.”

On July 15, 2010, the EPA disapproved Texas’ “flexible permit program” and indicated that sources operating under a flexible permit issued by the Texas Commission on Environmental Quality (“TCEQ”) are not properly permitted and are subject to enforcement. To address the EPA’s concerns, we have applied for a non-flexible permit. The Big Spring refinery is one of over one hundred regulated facilities in Texas that will be required to obtain a new, non-flexible permit. We do not anticipate that the new non-flexible permit will require new pollution control equipment or a change in our operations. 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 considerations. We are presently assessing our Big Spring refinery’s air emissions permitting alternatives as a result of this ruling.

Remediation Efforts. We are currently remediating historical soil and groundwater contamination at our Big Spring refinery. To date, we have substantially completed the remediation of the potentially contaminated areas and continue to monitor and treat groundwater at the site. The costs incurred to comply with the compliance plan were covered, with certain limitations, by an environmental indemnity provided by FINA that covered remediation costs incurred for ten years after the July 2000 closing date, with an aggregate indemnification cap of $20.0 million. We currently anticipate spending an additional $6.0 million over the next 15 years to remediate soil and groundwater contamination, including contamination at the Abilene, Southlake, and Wichita Falls terminals that we acquired from FINA at the time of the refinery acquisition, which were also covered by the FINA indemnity.

 

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In addition, we may be required by the federal Resource Conservation and Recovery Act or the Comprehensive Environmental Resources Compensation and Liability Act and the Texas Solid Waste Disposal Act to pay for remediation of hazardous substance contamination on our property or on other property were wastes from our operations have been released into the environment, regardless of fault or the legality of the original conduct, and to pay for damages to natural resources.

Environmental Insurance. We purchased two environmental insurance policies to cover expenditures not covered by the FINA indemnification agreement, the premiums for which have been paid in full. Under an environmental clean-up cost containment, or “cost cap policy,” we are insured for remediation costs for known conditions at the time of our acquisition of the Big Spring refinery. This policy has an initial retention of $20.0 million during the first ten years after the acquisition (coinciding with the FINA indemnity), which retention is increased by $1.0 million annually during the remainder of the term of the policy. Under an environmental response, compensation and liability insurance policy, or “ERCLIP,” we are insured for bodily injury, property damage, clean-up costs, legal defense expenses and civil fines and penalties relating to unknown conditions and incidents. The ERCLIP policy is subject to a $100,000 per claim/$1.0 million aggregate sublimit on liability for civil fines and penalties and a retention of $150,000 per claim in the case of civil fines or penalties. Both the cost cap policy and ERCLIP have a term of twenty years and share a maximum aggregate limit of $40.0 million. The insurer under these policies is The Kemper Insurance Companies, which has experienced significant downgrades of its credit ratings in recent years and is currently in run-off. However, we have no reason to believe at this time that Kemper will be unable to comply with its obligations under these policies.

Environmental Indemnity to HEP. In connection with our sale of pipelines and terminals to HEP, we entered into an Environmental Agreement dated January 25, 2005 pursuant to which we agreed to indemnify HEP against certain costs and liabilities incurred by HEP to the extent resulting from the existence of environmental conditions at levels requiring remediation under applicable environmental laws at the pipelines or terminals prior to the sale or from our violation of environmental laws with respect to the pipelines and terminals occurring prior to the effective closing date of the sale but, in each case, excluding any such increased costs and liabilities to the extent caused by the actions of HEP. Our environmental indemnification obligations under the Environmental Agreement expire after February 2015. In addition, our indemnity obligations under the Environmental Agreement with respect to the sale of these pipelines and terminals (other than the Wichita Falls terminal) are subject to HEP first incurring $100,000 of damages as a result of pre-existing environmental conditions or violations. Further, our environmental indemnity obligations under the Environmental Agreement, together with any amounts paid by us to HEP with respect to indemnification for breaches of our representations and warranties under a Contribution Agreement entered into as a part of the HEP transaction, are also limited to an aggregate liability amount of $20.0 million.

With respect to remediation required for environmental conditions existing prior to the date of sale, we are performing such remediation ourselves at the Wichita Falls terminal. We will maintain this indemnification obligation following the closing of this offering.

Environmental Indemnity to Sunoco. In connection with the sale of the Amdel and White Oil crude oil pipelines, we entered into a Purchase and Sale Agreement with Sunoco pursuant to which we agreed to indemnify Sunoco against costs and liabilities incurred by Sunoco resulting from the existence of environmental conditions at the pipelines prior to March 1, 2006 or from violations of environmental laws with respect to the pipelines occurring prior to such date. To date, Sunoco has not made any claims against us under the Purchase and Sale Agreement. We will maintain this indemnification obligation following the closing of this offering.

Occupational Safety and Health Regulation. We are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers. In addition, OSHA requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees, state and local governmental authorities, and local residents. Failure to comply with OSHA requirements, including general industry standards, process safety standards and control of occupational

 

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exposure to regulated substances, could subject us to significant fines or cause us to spend significant amounts on compliance, which could have a material adverse effect on our results of operations, financial condition and the cash flows of the business and, as a result, our ability to make distributions.

Other Government Regulation

The pipelines owned or operated by us and located in Texas are regulated by Department of Transportation rules and our intrastate pipelines are regulated by the Texas Railroad Commission. Within the Texas Railroad Commission, the Pipeline Safety Section of the Gas Services Division administers and enforces the federal and state requirements on our intrastate pipelines. All of our pipelines within Texas are permitted and certified by the Texas Railroad Commission’s Gas Services Division.

The Petroleum Marketing Practices Act (“PMPA”) is a federal law that governs the relationship between a refiner and a distributor pursuant to which the refiner permits a distributor to use a trademark in connection with the sale or distribution of motor fuel. Under the PMPA, we may not terminate or fail to renew branded distributor contracts unless certain enumerated preconditions or grounds for termination or nonrenewal are met and we also comply with the prescribed notice requirements.

Seasonality

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. The effects of seasonal demand for gasoline are partially offset by seasonality in demand for diesel, which in our region is generally higher in winter months as east-west trucking traffic moves south to avoid winter conditions on northern routes.

Employees

We do not have any employees. We are managed and operated by the directors and officers of our general partner. All of our executive management personnel will be employees of our general partner or Alon Energy or an affiliate of Alon Energy and will devote the portion of their time to our business and affairs that is required to manage and conduct our operations. We will reimburse Alon Energy for the provision of various general and administrative services for our benefit, for direct expenses incurred by Alon Energy on our behalf and for expenses allocated to us as a result of our becoming a public entity. Please read “Certain Relationships and Related Party Transactions—Agreements with Alon Energy.”

As of September 30, 2012, Alon Energy had approximately 2,850 employees, approximately 190 of which will be employed at our Big Spring refinery and 27 of which will be employed in our marketing operations. Approximately 120 of the 190 employees at our Big Spring refinery are covered by collective bargaining agreements that expire in March 2015.

Properties

Our principal properties are described above under the caption “—Our Refinery.” We believe that our properties and facilities are adequate for our operations and are maintained in a good state of repair in the ordinary course of our business.

Legal Proceedings

In the ordinary course of our business, we are subject to periodic lawsuits, investigations and claims, including environmental claims and employee related matters. Although we cannot predict with certainty the ultimate resolution of lawsuits, investigations and claims asserted against us, we do not believe that any currently pending legal proceeding or proceedings to which we are a party will have a material adverse effect on our business, results of operations, cash flows or financial condition.

 

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MANAGEMENT

Management of Alon USA Partners, LP

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. Our general partner manages our operations and activities subject to the terms and conditions specified in our partnership agreement. Following this offering, Alon Energy will own, directly or indirectly, approximately         % of our outstanding common units. The operations of our general partner in its capacity as general partner are managed by its board of directors. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operations. 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 directors will serve until the earlier of their resignation or removal.

Actions by our general partner that are made in its individual capacity will be made by Alon Energy as the owner of the sole member of our general partner and not by the board of directors of our general partner. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. The officers of our general partner will manage the day-to-day affairs of our business.

Limited partners will not be entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Our partnership agreement contains various provisions which replace default fiduciary duties with contractual corporate governance standards. See “The Partnership Agreement.” Our general partner will be liable, as a general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly non-recourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are non-recourse to it.

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

 

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

 

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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

 

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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 consist 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.

Upon completion of this offering, we expect that the board of directors of our general partner will consist of eight directors.

The board of directors of our general partner will establish an audit committee consisting of members who meet the independence and experience standards established by the NYSE and the Exchange Act. The audit committee’s responsibilities are to review our accounting and auditing principles and procedures, accounting functions, financial reporting and internal controls; to oversee the qualifications, independence, appointment,

 

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retention, compensation and performance of our independent registered public accounting firm; to recommend to the board of directors the engagement of our independent registered public accounting firm; to review with the independent registered public accounting firm the plans and results of the auditing engagement; and to oversee “whistle-blowing” procedures and certain other compliance matters. The NYSE’s regulations and applicable laws require that our general partner has an audit committee consisting of at least three independent directors not later than one year following the effective date of this prospectus.

In addition, the board of directors of our general partner will establish a conflicts committee consisting entirely of independent directors. Pursuant to our partnership agreement, the board may, but is not required to, seek the approval of the conflicts committee whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any public unitholder, on the other, including any related party transactions. The board of directors will determine whether to seek approval of the conflicts committee on a case by case basis. The conflicts committee may then determine whether the resolution of the conflict of interest is in the best interests of the partnership. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, and must meet the independence standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. Any matters approved by the conflicts committee will be conclusively deemed to be in our best interests, approved by all of our partners and not a breach by the general partner of any duties it may owe us or our unitholders.

In determining whether to seek approval from the conflicts committee, the board of directors of our general partner will consider a variety of factors, including the size and dollar amount involved in the potential transaction, the type of assets involved in the potential transaction, the various parties to the transaction, the interests of the various board members (if any) in the potential transaction, the interests of Alon Energy and its affiliates (if any) in the potential transaction, and any other factors the board of directors deems relevant in determining whether it should seek approval from the conflicts committee.

Whenever our general partner makes a determination or takes or declines to take an action in its individual, rather than representative, capacity, it is entitled to make such determination or to take or decline to take such other action free of any fiduciary duty or obligation whatsoever to us, any limited partner or assignee, and it is not required to act in good faith or pursuant to any other standard imposed by our partnership agreement or under Delaware law or any other law. Examples include the exercise of its call right or its registration rights, its voting rights with respect to the units it owns and its determination whether or not to consent to any merger or consolidation of the partnership. 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. Decisions by our general partner that are made in its individual capacity will be made by Alon Energy, as the owner of the sole member of our general partner, not by the board of directors of our general partner.

Executive Officers and Directors

The executive officers of our general partner are also executive officers of Alon Energy, and are providing their services to our general partner and us pursuant to the services agreement entered into among us, Alon Energy and our general partner. The executive officers listed below will divide their working time between the management of Alon Energy and us. The approximate weighted average percentages of the amount of time the executive officers spent on management of our business in 2011 are as follows: David Wiessman (25%), Jeff D. Morris (25%), Paul Eisman (25%), Shai Even (25%), Jimmy C. Crosby (100%), Alan Moret (25%), Claire Hart (25%), Michael Oster (25%) and Kyle McKeen (25%).

 

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The table below sets forth the names, positions and ages of the executive officers and directors of our general partner.

 

Name		Age		Position With Our General Partner
David Wiessman		58		Executive Chairman of the Board of Directors
Jeff D. Morris		61		Vice Chairman of the Board of Directors Nominee
Paul Eisman		57		President, Chief Executive Officer and Director
Itzhak Bader		66		Director Nominee
Boaz Biran		49		Director Nominee
Snir Wiessman		31		Director Nominee
Eitan Raff		70		Director Nominee
Mordehay Ventura		57		Director Nominee
Shai Even		44		Senior Vice President, Chief Financial Officer and Director
Jimmy C. Crosby		53		Vice President of Refining and Chief Operating Officer
Alan Moret		58		Senior Vice President of Supply
Claire Hart		56		Senior Vice President
Michael Oster		40		Senior Vice President of Mergers and Acquisitions
Kyle McKeen		49		Vice President of Wholesale Marketing

David Wiessman—Executive Chairman. Mr. D. Wiessman was appointed Chairman of the board of directors of our general partner in August 2012. Mr. D. Wiessman has served as Executive Chairman of the Board of Directors of Alon Energy since July 2000 and served as President and Chief Executive Officer of Alon Energy from its formation in 2000 until May 2005. Mr. D. Wiessman has over 25 years of oil industry and marketing experience. Since 1994, Mr. D. Wiessman has been Chief Executive Officer, President and a director of Alon Israel, Alon Energy’s parent company. In 1987, Mr. D. Wiessman became Chief Executive Officer of, and a stockholder in, Bielsol Investments (1987) Ltd. (“Bielsol”), which acquired a 50% interest in Alon Israel in 1992. In 1976, after serving in the Israeli Air Force, Mr. D. Wiessman became Chief Executive Officer of Bielsol Ltd., a privately owned Israeli company that owns and operates gasoline stations and owns real estate in Israel. Mr. D. Wiessman has also been Executive Chairman of the Board of Directors of Alon Holdings Blue Square-Israel, Ltd., which is listed on the NYSE, and the Tel Aviv Stock Exchange (the “TASE”) since 2003, Chairman of Blue Square Real Estate Ltd., which is listed on the TASE, since 2006, and Executive Chairman of the Board and President of Dor-Alon Energy Israel (1988) Ltd., which is listed on the TASE, since 2005, all of which are subsidiaries of Alon Israel. Mr. D. Wiessman has also served as Executive Chairman of the Board of Directors of Alon Refining Krotz Springs, Inc. (“Krotz Springs”) since May 2008. Krotz Springs is a subsidiary of Alon Energy through which Alon Energy conducts its Louisiana refining business and which has publicly traded debt in the United States. We believe Mr. D. Wiessman’s vision, business expertise, industry experience, leadership skills and devotion to community service qualify him to serve as Executive Chairman of the board of directors of our general partner. David Wiessman is the father of Snir Wiessman, who has agreed to join the board of directors of our general partner prior to or upon our listing date on the NYSE.

Jeff D. Morris—Vice Chairman. Mr. Morris has agreed to serve as Vice Chairman of the board of directors of our general partner prior to or upon our listing date on the NYSE. Mr. Morris has served as Vice Chairman of the Board of Directors of Alon Energy since May 2011 and a director since May 2005. Prior to this Mr. Morris served as Alon Energy’s Chief Executive Officer from May 2005 to May 2011, as Chief Executive Officer of Alon Energy’s operating subsidiaries from July 2000 to May 2011, Alon Energy’s President from May 2005 until March 2010 and President of its operating subsidiaries from July 2000 until March 2010. Prior to joining Alon Energy, he held various positions at Fina, Inc., where he began his career in 1974. Mr. Morris served as Vice President of Fina’s SouthEastern Business Unit from 1998 to 2000 and as Vice President of its SouthWestern Business Unit from 1995 to 1998. In these capacities, he was responsible for both the Big Spring refinery and Fina’s Port Arthur refinery and the crude oil gathering assets and marketing activities for both business units. Mr. Morris has also been a director of Krotz Springs since 2008. We believe that Mr. Morris’ position as Chief Executive Officer of Alon Energy, detailed knowledge of Alon Energy’s operations and assets, expertise in oil refining and

 

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marketing, devotion to community service and management skills qualify him to serve as a member of the board of directors of our general partner.

Paul Eisman—President, Chief Executive Officer and Director. Mr. Eisman was appointed President, Chief Executive Officer and Director of our general partner in August 2012. Mr. Eisman became president of Alon Energy in March 2010. Prior to joining Alon Energy, Mr. Eisman was Executive Vice President, Refining & Marketing Operations at Frontier Oil Corporation from March 2006 to October 2009 and held various positions at KBC Advanced Technologies from June 2003 to March 2006, including Vice President of North American Operations. In 2002, Mr. Eisman was Senior Vice President of Planning for Valero Energy Corporation following Valero’s acquisition of Ultramar Diamond Shamrock. Prior to the acquisition, Mr. Eisman had a 24-year career with Ultramar Diamond Shamrock, serving in many technical and operational roles including Executive Vice President of Corporate Development and Refinery Manager at the McKee refinery. Mr. Eisman has also been a director of Alon Refining Krotz Springs, Inc. since May 2010. Mr. Eisman was selected to serve as a director of our general partner because of his position as president of Alon Energy, extensive management experience, leadership skills and knowledge of our operations.

Itzhak Bader—Director. Mr. Bader has agreed to join the board of directors of our general partner prior to or upon our listing date on the NYSE. Mr. Bader has served as a director of Alon Energy since August 2000. Mr. Bader has also served as Chairman of the Board of Directors of Alon Israel since 1993. He is Chairman of Granot Cooperative Regional Organization Corporation, a purchasing organization of the Kibbutz movement, a position he has held since 1995. In addition, he is also Chairman of Gat Givat Haim Agricultural Cooperative for Conservation of Agricultural Production Ltd., an Israeli beverage producer, a position he has held since 1999. Mr. Bader has also been the Co-Chairman of Dor-Alon Energy in Israel (1988) Ltd. since 2005, a director of Alon Holdings Blue Square-Israel, Ltd. since 2003 and a director of Blue Square Real Estate Ltd. since 2005, each a subsidiary of Alon Israel. We believe that Mr. Bader’s experience gained while serving as a director on a number of companies’ boards, including several chairman positions, qualifies him to serve as a member of the board of directors of our general partner.

Boaz Biran—Director. Mr. Biran has agreed to join the board of directors of our general partner prior to or upon our listing date on the NYSE. Mr. Biran has served as director of Alon Energy since May 2002. Mr. Biran has been a director of Bielsol since 1998 and served as Chairman of the Board of Directors of Rosebud Real Estate Ltd., an investment company in Israel listed on the TASE, since November 2003. Mr. Biran was also a partner in Shraga F. Biran & Co., a law firm in Israel, from 1999 to 2008. We believe that Mr. Biran’s broad business background and experience, legal expertise and directorship experience qualify him to serve as a member of the board of directors of our general partner.

Snir Wiessman—Director. Mr. S. Wiessman has agreed to join the board of directors of our general partner prior to or upon our listing date on the NYSE. Mr. S. Wiessman has served as a director of Alon Brands, Inc., a subsidiary of Alon Energy, since November 2008. Mr. S. Wiessman has served as a Business Development and M&A Manager of Alon Israel since August 2007. Mr. Wiessman has also served as a Director of Dor-Alon Fuel Stations Operation Ltd., an Israeli gas station and convenience store operator, from August 2003 to October 2010 and AM:PM, an Israeli convenience store operator, from January 2008 to October 2010. AM:PM and Dor-Alon Fuel Station Operation Ltd. merged in October 2010 and Mr. S. Wiessman has served as a director in the merged entity, Dor-Alon Retail Sites Management, since this time. Dor-Alon Retail Sites Management is a subsidiary of Dor-Alon Energy in Israel (1988) Ltd., which is listed on the TASE. Snir Wiessman is the son of David Wiessman, who is also a member of the board of directors of our general partner. We believe Mr. S. Wiessman’s broad business background and experience qualify him to serve as a member of the board of directors of our general partner.

Eitan Raff—Director. Mr. Raff has agreed to join the board of directors of our general partner prior to or upon our listing date on the NYSE. Mr. Raff has served as a director of Verifone Systems, Inc. since October 2007. Mr. Raff currently serves as a financial consultant to Wolfson Clore Mayer Ltd. and as a senior advisor to

 

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Morgan Stanley. Mr. Raff is also chairman of the public board of Youth Leading Change, a non-profit association, and previously served as the Accountant General (Treasurer) in the Israeli Ministry of Finance. Mr. Raff holds a B.A. and M.B.A. from the Hebrew University of Jerusalem. Mr. Raff currently serves on the boards of directors of Israel Corp. Ltd. and a number of privately-held corporations. Mr. Raff previously served as chairman of the board of directors of Bank Leumi le Israel B.M., Bank Leumi USA and Bank Leumi UK plc from 1995 until 2010. He currently serves on the investment and capital structure committee of Israel Corp. While serving on the Bank Leumi le Israel B.M. board, Mr. Raff served on a number of committees of the board of directors, including the committees on credit, finance, administration, conflicts of interest and risk management. We have concluded that Mr. Raff’s experience gained while serving as a director on a number of companies’ boards, including several chairman positions, qualifies him to serve as a member of the board of directors of our general partner.

Mordehay Ventura—Director. Mr. Ventura has agreed to join the board of directors of our general partner prior to or upon our listing date on the NYSE. Mr. Ventura has been the Chief Executive Officer of Mishkey Hadarom Aguda Haklait Shitufit Ltd. since 2004. Mr. Ventura has been a Director at Alon Holdings Blue Square—Israel Ltd since March 22, 2012. He serves as a Director in Oil Holdings (Founded by the Kibbutzim Organizations) Ltd., Alon Israel Oil Company Ltd., Dor Alon Energy in Israel (1988) Ltd., Dor Alon Retail Sites Management Ltd. Gan Smuel Mazon Ltd., Ganir (1992) Ltd., Hadarey Nitzanim Aguda Haklait Shitufit Ltd., Sivey Hadarom (S.D.) Ltd., Hanegev Aguda Haklait Shitufit Transport Company Ltd., Megadley Drom Yehuda Aguda Haklait Shitufit Ltd., Shkedey Drom Yehuda Aguda Haklait Shitufit Ltd., Zeitey Drom Yehuda Aguda Haklait Shitufit Ltd., Hazera (1939) Ltd., Megadley Zraim Ltd., the Egg and Poultry Board, Yoav Regional Council, Amal Darom Aguda Haklait Shitufit Ltd., Marbek Services and assets (2002) Ltd., Shovre Bar Import Feeding Stuff Ltd., Mishkey Dan Partnership, Dana Finance Services Ltd., Amber Machon Letaarovet Aguda Haklait Shitufit Merkazit Ltd., and Tnuva Holdings. Mr. Ventura serves as a Director in several companies, including companies within Alon Israel Oil Company Ltd. group, companies related to Miskey Hadarom and others. Mr. Ventura holds a BA degree in Economics and Business Administration from the Rupin College. We have concluded that Mr. Ventura’s experience gained while serving as a director on a number of companies’ boards and extensive experience in the financial industry qualifies him to serve as a member of the board of directors of our general partner.

Shai Even—Senior Vice President, Chief Financial Officer and Director. Mr. Even was appointed Senior Vice President, Chief Financial Officer and Director of our general partner in August 2012. Mr. Even has served as Senior Vice President of Alon Energy since August 2008, Vice President of Alon Energy from May 2005 to August 2008 and as Alon Energy’s Chief Financial Officer since December 2004. Mr. Even also served as Alon Energy’s Treasurer from August 2003 until March 2007. Prior to joining Alon Energy, Mr. Even served as Chief Financial Officer of DCL Technologies, Ltd. from 1996 to July 2003 and prior to that worked for KPMG LLP from 1993 to 1996. Mr. Even has also been a director of Alon Refining Krotz Springs, Inc. since July 2008 and Alon Brands, Inc. since November 2008. Mr. Even was selected to serve as a director of our general partner because of his financial education and expertise, financial reporting background, public accounting experience, management experience and detailed knowledge of our operations. Mr. Even has agreed to step down as a director of our general partner prior to or upon our listing date on the NYSE.

Jimmy C. Crosby—Vice President of Refining and Chief Operating Officer. Mr. Crosby was appointed Vice President of Refining of our general partner in August 2012 and has agreed to serve as the Chief Operating Officer of our general partner effective prior to or upon our listing date on the NYSE. Mr. Crosby has served as Vice President of Refining–Big Spring of Alon Energy since January 2010, with responsibility for operations at the Big Spring refinery. Prior to this, Mr. Crosby served as Vice President of Refining–California Refineries of Alon Energy from March 2009 until January 2010, as Vice President of Refining and Supply from May 2007 to March 2009, as Vice President of Supply and Planning from May 2005 to May 2007 and as General Manager of Business Development and Planning from August 2000 to May 2005. Prior to joining Alon Energy, Mr. Crosby worked with FINA from 1996 to August 2000 where he last held the position of Manager of Planning and Economics for the Big Spring refinery.

 

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Alan Moret—Senior Vice President of Supply. Mr. Moret was appointed Senior Vice President of Supply of our general partner in August 2012. Mr. Moret has served as Senior Vice President of Supply of Alon Energy since August 2008. Mr. Moret served as Alon Energy’s Senior Vice President of Asphalt Operations from August 2006 to August 2008, with responsibility for asphalt operations and marketing at Alon Energy’s refineries and asphalt terminals. Mr. Moret has also served as an officer of Alon Refining Krotz Springs, Inc. since July 2008. Prior to joining Alon Energy, Mr. Moret was President of Paramount Petroleum Corporation from November 2001 to August 2006. Prior to joining Paramount Petroleum Corporation, Mr. Moret held various positions with Atlantic Richfield Company, most recently as President of ARCO Crude Trading, Inc. from 1998 to 2000 and as President of ARCO Seaway Pipeline Company from 1997 to 1998.

Claire Hart—Senior Vice President. Mr. Hart was appointed Senior Vice President of our general partner in August 2012. Mr. Hart has served as Senior Vice President of Alon Energy since January 2004 and also served as Alon Energy’s Chief Financial Officer and Vice President from August 2000 to January 2004. In addition, Mr. Hart has been an officer of Alon Refining Krotz Springs, Inc. since July 2008. Prior to joining Alon Energy, Mr. Hart held various positions in the Finance, Accounting and Operations departments of FINA for 13 years, serving as Treasurer from 1998 to August 2000 and as General Manager of Credit Operations from 1997 to 1998.

Michael Oster—Senior Vice President of Mergers and Acquisitions. Mr. Oster was appointed Senior Vice President of Mergers and Acquisitions of our general partner in August 2012. Mr. Oster has served as Senior Vice President of Mergers and Acquisitions of Alon Energy since August 2008 and has served as an officer of Alon Refining Krotz Springs, Inc. since August 2009. Prior to joining Alon Energy, Mr. Oster was a partner in the Israeli law firm of Yehuda Raveh and Co.

Kyle McKeen—Vice President of Wholesale Marketing. Mr. McKeen was appointed Vice President of Wholesale Marketing of our general partner in August 2012. Mr. McKeen has served as President and Chief Executive Officer of Alon Brands, Inc., Alon Energy’s subsidiary that manages retail and branded marketing operations, since May 2008. From 2005 to 2008, Mr. McKeen served as President and Chief Operating Officer of Carter Energy, an independent energy marketer supporting over 600 retailers by providing fuel supply, merchandising and marketing support, and consulting services. Prior to joining Carter Energy in 2005, Mr. McKeen was a member of the Board of Managers of Alon USA Interests, LLC from September 2002 to 2005 and held numerous positions of increasing responsibilities with Alon Energy, including Vice President of Marketing.

 

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EXECUTIVE COMPENSATION

Executive Compensation

Compensation Discussion and Analysis

We and our general partner were formed in August 2012. Accordingly neither we nor our general partner have accrued any obligations with respect to management compensation or retirement benefits for directors and executive officers for any periods prior to our formation date.

Neither we nor our general partner directly employ any of the persons responsible for managing our business. All of the initial executive officers that will be responsible for managing our day to day affairs are also current officers of our parent Alon Energy, and therefore will have responsibilities for both us and Alon Energy. The individuals that are considered to be “named executive officers” at Alon Energy and which will also provide management services to us are as follows:

 

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Paul Eisman—Chief Executive Officer

 

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Jeff D. Morris—Vice Chairman of the Board of Directors

 

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Shai Even—Senior Vice President and Chief Financial Officer

 

•

David Wiessman—Executive Chairman of the Board of Directors

 

•

Alan Moret—Senior Vice President of Supply

 

•

Michael Oster—Senior Vice President of Mergers and Acquisitions

The objectives of Alon Energy’s compensation policies are to attract, motivate and retain qualified management and personnel who are highly talented while ensuring that executive officers and other employees are compensated in a manner that advances both the short- and long-term interests of unitholders. In pursuing these objectives, Alon Energy’s compensation committee believes that compensation should reward executive officers and other employees for both their personal performance and the performance of Alon Energy and its subsidiaries. For a detailed discussion of the compensation and benefits that Alon Energy provided to the officers noted above during the 2009, 2010 and 2011 fiscal years, as applicable for each officer, please see Alon Energy’s most recent proxy statement, filed with the SEC on March 31, 2012.

The officers and all other personnel necessary for our business to function will be employed and compensated by our parent Alon Energy, subject to the administrative services fee or reimbursement by us in accordance with the terms of the omnibus agreement. Under the omnibus agreement, none of Alon Energy’s long-term incentive compensation expense will be allocated to us. However, we will be responsible for paying the long-term incentive compensation expense associated with our long-term incentive plan described below. The executive officers that perform services for us who are also direct employees of Alon Energy will continue to participate in employee benefit plans and arrangements sponsored by Alon Energy, including plans that may be established in the future. Neither we nor our general partner have entered into any additional employment or benefit-related agreements with any of the individuals who provide executive officer services to us, and we do not anticipate entering into any such agreements in the near future.

We are not presenting any compensation for historical periods as we and our general partner were formed in August 2012. We are a new subsidiary formed to hold various portions of Alon Energy’s business. Compensation paid by or awarded by us in 2012 with respect to the executive officers of Alon Energy that also provide services to us will reflect only the portion of compensation paid by Alon Energy that is allocated to us pursuant to Alon Energy’s allocation methodology and subject to the terms of the omnibus agreement. The compensation expenses that we will incur pursuant to the omnibus agreement will be based upon the amount of time spent by such officers managing our business and operations during the applicable fiscal year. Please read “Certain Relationships and Related Party Transactions—Agreements with Alon Energy—Omnibus Agreement” for more information regarding the terms of the omnibus agreement. Responsibility and authority for compensation-related decisions for Alon Energy’s executive officers will reside with the board of directors of Alon Energy and

 

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its committees (other than compensation under our long-term incentive plan should we choose to issue awards directly to those individuals). Any such compensation decisions by Alon Energy will not be subject to any approvals by the board of directors of our general partner or any committees thereof.

Following the closing of this offering, the board of directors of our general partner may grant awards to individuals who support our operations, whether or not they also provide services to Alon Energy, pursuant to the long-term incentive plan described below. Our general partner intends to implement the long-term incentive plan to provide us with maximum flexibility with respect to the design of compensatory arrangements for individuals providing services to us; however, neither we nor our general partner currently have plans to make any grants under the long-term incentive plan in conjunction with this offering or in the near term.

Long-Term Incentive Plan

We, through our general partner, intend to adopt the Alon USA Partners, LP 2012 Long-Term Incentive Plan (the “LTIP”) prior to the effectiveness of this offering for the employees, consultants and the directors of us, our general partner and its affiliates who perform services for us. The description of the LTIP set forth below is a summary of the material features of the plan. This summary, however, does not purport to be a complete description of all the provisions of the LTIP. This summary is qualified in its entirety by reference to the LTIP, a copy of which has been filed as an exhibit to this registration statement. The purpose of the LTIP is to provide a means to attract and retain individuals who will provide services to us by affording such individuals a means to acquire and maintain ownership of awards, the value of which is tied to the performance of our common units.

The LTIP will provide grants of (1) unit options (“Options”), (2) unit appreciation rights (“UARs”), (3) restricted units (“Restricted Units”), (4) phantom units (“Phantom Units”), (5) unit awards (“Unit Awards”), (6) substitute awards, (7) other unit-based awards (“Unit-Based Awards”), (8) cash awards, (9) performance awards, and (10) distribution equivalent rights (“DERs”) (collectively referred to as “Awards”).

Administration

The LTIP will be administered by the board of directors of our general partner or an alternative committee appointed by the board of directors of our general partner, which we refer to together as the committee for purposes of this summary. The committee will administer the LTIP pursuant to its terms and all applicable state, federal, or other rules or laws. The committee will have the power to determine to whom and when Awards will be granted, determine the amount of Awards (measured in cash or in shares of our common units), proscribe and interpret the terms and provisions of each Award agreement (the terms of which may vary), accelerate the vesting provisions associated with an Award, delegate duties under the LTIP, and execute all other responsibilities permitted or required under the LTIP. In the event that the committee is not comprised of “nonemployee directors” within the meaning of Rule 16b-3 under the Exchange Act, a subcommittee of two or more nonemployee directors will administer all Awards granted to individuals that are subject to Section 16 of the Exchange Act.

Securities to be Offered

The maximum aggregate number of shares of common units that may be issued pursuant to any and all Awards under the LTIP shall not exceed                      units, subject to adjustment due to recapitalization or reorganization, or related to forfeitures or the expiration of Awards, as provided under the LTIP.

If a common unit subject to any Award is not issued or transferred, or ceases to be issuable or transferable for any reason, including (but not exclusively) because units are withheld or surrendered in payment of taxes or any exercise or purchase price relating to an Award or because an Award is forfeited, terminated, expires unexercised, is settled in cash in lieu of common units or is otherwise terminated without a delivery of units, those common units will again be available for issue, transfer or exercise pursuant to Awards under the LTIP to the extent allowable by law.

 

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Options. We may grant Options to eligible persons. Option Awards are options to acquire common units at a specified price. The exercise price of each option granted under the LTIP will be stated in the option agreement and may vary; provided, however, that, the exercise price for an Option must not be less than 100% of the fair market value per common unit as of the date of grant of the Option unless that Option is intended to otherwise comply with the requirements of Section 409A of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”). Options may be exercised in the manner and at such times as the committee determines for each Option, unless that Option is determined to be subject to Section 409A of the Code, where the Option will be subject to any necessary timing restrictions imposed by the Code or federal regulations. The committee will determine the methods and form of payment for the exercise price of an Option and the methods and forms in which common units will be delivered to a participant.

UARs. A UAR is the right to receive, in cash or in common units, as determined by the committee, an amount equal to the excess of the fair market value of one common unit on the date of exercise over the grant price of the UAR. The committee will be able to make grants of UARs and will determine the time or times at which a UAR may be exercised in whole or in part. The exercise price of each UAR granted under the LTIP will be stated in the UAR agreement and may vary; provided, however, that, the exercise price must not be less than 100% of the fair market value per common unit as of the date of grant of the UAR unless that UAR Award is intended to otherwise comply with the requirements of Section 409A of the Code.

Restricted Units. A Restricted Unit is a grant of a common unit subject to a risk of forfeiture, performance conditions, restrictions on transferability, and any other restrictions imposed by the committee in its discretion. Restrictions may lapse at such times and under such circumstances as determined by the committee. The committee shall provide, in the Restricted Unit agreement, whether the Restricted Unit will be forfeited upon certain terminations of employment. Unless otherwise determined by the committee, a common unit distributed in connection with a unit split or unit dividend, and other property distributed as a dividend, will generally be subject to restrictions and a risk of forfeiture to the same extent as the Restricted Unit with respect to which such common unit or other property has been distributed.

Phantom Units. Phantom Units are rights to receive common units, cash, or a combination of both at the end of a specified period. The committee may subject Phantom Units to restrictions (which may include a risk of forfeiture) to be specified in the Phantom Unit agreement that may lapse at such times determined by the committee. Phantom Units may be satisfied by delivery of common units, cash equal to the fair market value of the specified number of common units covered by the Phantom Unit, or any combination thereof determined by the committee. Except as otherwise provided by the committee in the Phantom Unit agreement or otherwise, Phantom Units subject to forfeiture restrictions may be forfeited upon termination of a Participant’s employment prior to the end of the specified period. Cash dividend equivalents may be paid during or after the vesting period with respect to a Phantom Units, as determined by the committee.

Unit Awards. The committee will be authorized to grant common units that are not subject to restrictions. The committee may grant Unit Awards to any eligible person in such amounts as the committee, in its sole discretion, may select.

Substitute Awards. The LTIP will permit the grant of Awards in substitution for similar awards held by individuals who become employees or directors as a result of a merger, consolidation or acquisition by us, an affiliate of another entity or the assets of another entity. Such substitute Awards that are Options or UARs may have exercise prices less than 100% of the fair market value per common unit on the date of the substitution if such substitution complies with Section 409A of the Code and its regulations, and other applicable laws and exchange rules.

Unit-Based Awards. The LTIP will permit the grant of other Unit-Based Awards, which are Awards that may be based, in whole or in part, on the value or performance of a common unit or are denominated or payable in common units. Upon settlement, the Unit-Based Award may be paid in common units, cash or a combination thereof, as provided in the Award agreement.

 

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Cash Awards. The LTIP will permit the grant of Awards denominated in and settled in cash. Cash Awards may be based, in whole or in part, on the value or performance of a common unit.

Performance Awards. The committee may condition the right to exercise or receive an Award under the LTIP, or may increase or decrease the amount payable with respect to an Award, based on the attainment of one or more performance conditions deemed appropriate by the committee.

DERs. The committee will be able to grant DERs in tandem with Awards under the LTIP (other than an award of Restricted Units or Unit Awards), or they may be granted alone. DERs entitle the participant to receive cash equal to the amount of any cash distributions made by us during the period the DER is outstanding. Payment of a DER issued in connection with another Award may be subject to the same vesting terms as the Award to which it relates or different vesting terms, in the discretion of the committee.

Miscellaneous

Tax Withholding. At our discretion, subject to conditions that the committee may impose, a participant’s minimum statutory tax withholding with respect to an Award may be satisfied by withholding from any payment related to an Award or by the withholding of common units issuable pursuant to the Award based on the fair market value of the common units.

Anti-Dilution Adjustments. If any “equity restructuring” event occurs that could result in an additional compensation expense under Financial Accounting Standards Board Accounting Standards Codification Topic 718 (“FASB ASC Topic 718”) if adjustments to Awards with respect to such event were discretionary, the committee will equitably adjust the number and type of units covered by each outstanding Award and the terms and conditions of such Award to equitably reflect the restructuring event, and the committee will adjust the number and type of units with respect to which future Awards may be granted. With respect to a similar event that would not result in a FASB ASC Topic 718 accounting charge if adjustment to Awards were discretionary, the committee shall have complete discretion to adjust Awards in the manner it deems appropriate. In the event the committee makes any adjustment in accordance with the foregoing provisions, a corresponding and proportionate adjustment shall be made with respect to the maximum number of units available under the LTIP and the kind of units or other securities available for grant under the LTIP. Furthermore, in the case of (i) a subdivision or consolidation of the common units (by reclassification, split or reverse split or otherwise), (ii) a recapitalization, reclassification or other change in our capital structure or (iii) any other reorganization, merger, combination, exchange or other relevant change in capitalization of our equity, then a corresponding and proportionate adjustment shall be made in accordance with the terms of the LTIP, as appropriate, with respect to the maximum number of units available under the LTIP, the number of units that may be acquired with respect to an Award, and, if applicable, the exercise price of an Award in order to prevent dilution or enlargement of Awards as a result of such events.

Change in Control. Upon a “change of control” (as defined in the LTIP), the committee may, in its discretion, (i) remove any forfeiture restrictions applicable to an Award, (ii) accelerate the time of exercisability or vesting of an Award, (iii) require Awards to be surrendered in exchange for a cash payment, (iv) cancel unvested Awards without payment or (v) make adjustments to Awards as the committee deems appropriate to reflect the change of control.

 

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Director Compensation

Officers or employees of Alon Energy or its subsidiaries who also serve as directors of our general partner will not receive additional compensation for such service. Our general partner anticipates that its directors who are not also officers or employees of Alon Energy or its subsidiaries will receive compensation for service on the board of directors and its committees. We currently expect to pay such directors an annual retainer of $50,000 and award such directors $25,000 annually in restricted equity interests which will vest in three equal installments on each of the first, second and third anniversaries of the grant date. We currently expect to pay the audit committee chairman an annual amount of $10,000. In addition, each such director will be reimbursed for out-of-pocket expenses in connection with attending meetings of the board and committee meetings. We currently expect to pay meeting fees to such directors in the amount of $1,500 for each in-person board or committee meeting, and $900 for each telephonic board or committee meeting. Each director will be fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law pursuant to our partnership agreement.

 

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table presents information regarding beneficial ownership of our common units following this offering by:

 

•

our general partner;

 

•

each of our general partner’s directors;

 

•

each of our general partner’s named executive officers;

 

•

each unitholder known by us to beneficially hold five percent or more of our outstanding units; and

 

•

all of our general partner’s directors and executive officers as a group.

Beneficial ownership is determined under the rules of the SEC and generally includes voting or investment power with respect to securities. Unless indicated below, to our knowledge, the persons and entities named in the table have sole voting and sole investment power with respect to all units beneficially owned, subject to community property laws where applicable. Except as otherwise indicated, the business address for each of our beneficial owners is c/o Alon USA Partners, LP, 12700 Park Central Dr., Suite 1600, Dallas, TX 75251.

 

Name of Beneficial Owner		Common Units to be Beneficially Owned		Percentage of Total Common Units to be Beneficially Owned(1)
Alon USA Energy, Inc.(2)
David Wiessman
Jeff D. Morris
Paul Eisman
Itzhak Bader
Boaz Biran
Snir Wiessman
Eitan Raff
Mordehay Ventura
Shai Even
Jimmy C. Crosby
Alan Moret
Claire Hart
Michael Oster
Kyle McKeen
All directors and executive officers of our general partner as a group (14 persons)

 

*	Less than 1%

(1)	Based on         common units outstanding following this offering. This table assumes the underwriters do not exercise their option to purchase additional common units.

(2)

Alon USA Energy, Inc., a publicly held company with its common stock traded on the NYSE (NYSE: ALJ), will hold its common units through two of its subsidiaries, Alon Assets, Inc. and Alon USA GP, LLC. Alon Energy owns 100% of the Class A voting common stock in Alon Assets, Inc. and 94.63% of the Class B non-voting common stock. The remaining Class B non-voting common stock is owned by certain members of Alon Energy’s management. Alon Energy also indirectly owns Alon USA Partners GP, LLC, which is our general partner and manages and operates our business and has a non-economic general partner interest in us. Voting and investment determinations of Alon Energy are made by its board of directors, which is comprised of the following members: David Wiessman, Jeff Morris, Zalman Segal, Itzhak Bader, Boaz Biran, Yeshayahu Pery, Ron Haddock, Avraham Shochat, Avinadav Grinshpon, Oded Rubinstein and Shlomo Even. As a result of, and by virtue of the relationships described above, each of David Wiessman, Jeff Morris, Zalman Segal, Itzhak Bader, Boaz Biran, Yeshayahu Pery, Ron Haddock, Avraham Shochat, Avinadav Grinshpon, Oded Rubinstein and Shlomo Even may be deemed to exercise voting and dispositive power with respect to securities held by Alon Assets, Inc. and Alon USA GP, LLC.

 

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

After this offering, Alon Energy, will indirectly own (i)          common units, representing approximately        % of our outstanding units (approximately        % if the underwriters exercise their option to purchase additional          common units in full) and (ii) our general partner will own a non-economic general partner interest in us that does not entitle it to receive distributions.

Distributions and Payments to Alon Energy and its Affiliates

The following table summarizes the distributions and payments made or to be made by us to Alon Energy and its affiliates (including our general partner) in connection with the formation, offering of common units, ongoing operations and any liquidation of Alon USA Partners, LP. These distributions and payments were or will be determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Formation Stage

 

The consideration received by Alon Energy and its affiliates for our formation

•     non-economic general partner interest

•     100% of our limited partner interests

Offering Stage

 

The consideration received by Alon Energy and its affiliates

common units issued immediately prior to the closing of this offering.

 

Services, Omnibus and Tax Sharing Agreements

We will enter into the Services, Omnibus and Tax Sharing Agreements on the closing of this offering.

 

Option units or proceeds from option units

We will distribute to Alon Energy any net proceeds received from the underwriters’ exercise of their 30-day option to purchase up to an aggregate of         additional common units in whole or in part as reimbursement for certain pre-formation capital expenditures. If the underwriters do not exercise their option in full or at all, we will distribute the common units that would have been sold to the underwriters to Alon Energy.

Post-IPO Operational Stage

 

Distributions to Alon Energy and its affiliates

We will generally make cash distributions to the unitholders pro rata. Immediately following this offering, based on ownership of our common units at such time, Alon Energy and its subsidiaries will own approximately         % of our common units (    % if the underwriters exercise their over-allotment option in full) and would receive a pro rata percentage of the available cash that we distribute in respect thereof.

 

Payments to our general partner and its affiliates

We will reimburse our general partner and its affiliates for all expenses incurred on our behalf. In addition, we will reimburse Alon Energy for certain operating expenses and for the provision of various general and administrative services for our benefit under the Services and Omnibus

 

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Agreements. 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.

Liquidation Stage

 

Liquidation

Upon our liquidation, our unitholders will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements with Alon Energy

In connection with this offering, we will enter into certain agreements with Alon Energy, as described in more detail below.

Contribution Agreement

In connection with the closing of this offering, we will enter into a contribution agreement that will affect the transactions and the use of the net proceeds of this offering. While we believe this agreement is on terms no less favorable to any party than those that could have been negotiated with an unaffiliated third party, it will not be the result of arm’s-length negotiations. All of the transaction expenses incurred in connection with these transactions will be paid from the proceeds of this offering.

Omnibus Agreement

In connection with the closing of this offering, we will enter into an omnibus agreement with affiliates of our general partner that will address certain aspects of our relationship with them, including (i) our use of the name “Alon” and related marks, and (ii) certain indemnification obligations. In addition, under the terms of the omnibus agreement, 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.

Services Agreement

In connection with the closing of this offering, we will enter into a services agreement with Alon Energy or a wholly owned service subsidiary of Alon Energy that will address certain aspects of our relationship with them, including:

 

•

the provision by Alon Energy or its service subsidiary to us of certain general and administrative services and our agreement to reimburse Alon Energy for such services; and

 

•

the provision by Alon Energy or its service subsidiary to us of such employees as may be necessary to operate and manage our business, and our agreement to reimburse Alon Energy for the expenses associated with such employees.

We will reimburse Alon Energy or its service subsidiary for (i) all reasonable direct and indirect costs and expenses incurred by it in connection with the performance of these services and (ii) all other reasonable expenses allocable to us or our general partner or otherwise incurred by Alon Energy in connection with the operation of our business.

 

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The services agreement can be amended, modified, supplemented or restated by written agreement of all parties to the agreement. However, we may not agree to any amendment or modification that would, in the reasonable discretion of our general partner, be adverse in any material respect to the holders of our common units without prior approval of the conflicts committee.

The initial term of the services agreement will be five years from the effective date of such agreement, at which time the term of the agreement shall automatically be extended for additional successive one-year terms unless, on or before the date that is 180 days prior to the expiration of the then-existing term, Alon Energy provides written notice to our general partner of its intent to terminate its participation in the services agreement upon the expiration of such term. In addition to the foregoing, the general partner, on its own behalf and on our behalf, may terminate the services agreement at any time on 180 days’ prior written notice to Alon Energy. In the event of a “change of control” (as defined in the services agreement) of us or our general partner, the services agreement will be terminated immediately. Our general partner must provide Alon Energy notice of change of control of us or our general partner at least 90 days prior to the effective date thereof.

Fuel Supply Agreement

In connection with this offering, we will enter into a 20-year fuel supply agreement (the “Fuel Supply Agreement”) with Southwest Convenience Stores, LLC (“Southwest”), a subsidiary of Alon Energy, under which we will supply substantially all of the motor fuel requirements of Alon Energy’s retail convenience stores. The volume of motor fuels sold pursuant to the Fuel Supply Agreement will be determined monthly based upon Southwest’s estimated requirements. Southwest shall purchase such motor fuels at a price equal to the price per unit in effect at the time of delivery less applicable terminal discounts (as provided in the Fuel Supply Agreement) plus all applicable freight, taxes, pipeline tariff and delivery place differentials.

The Fuel Supply Agreement additionally provides for (i) Southwest’s mandatory participation in our credit card payment network, (ii) Southwest’s use of the “Alon” name and related marks in connection with the use of the credit card payment network and the resale of the motor fuels purchased pursuant to the Fuel Supply Agreement, and (iii) marketing services for the benefit of Southwest (at an additional cost). The Fuel Supply Agreement allows for Southwest’s resale of the motor fuels purchased thereunder to unaffiliated permitted distributors, as defined therein. All permitted distributors are required to participate in the credit card payment network pursuant to the terms of their applicable Alon payment card program dealer agreements.

The Fuel Supply Agreement shall be automatically renewed at its expiration on a month-to-month basis so long as neither party has exercised its right to terminate or not renew the agreement pursuant to its terms.

Asphalt Supply Agreement

In connection with this offering, we will enter into a 20-year asphalt supply agreement (the “Asphalt Supply Agreement”) with Paramount Petroleum Corporation (“Paramount”), a subsidiary of Alon Energy, under which Paramount will purchase all of the asphalt produced at our Big Spring refinery. The volume of asphalt sold pursuant to the Asphalt Supply Agreement will be based upon actual production, but we will provide good faith non-binding forecasts of our monthly production estimates for the upcoming contract year upon the effective date of the Asphalt Supply Agreement and on each anniversary thereafter. On or before the 20th day of each calendar month, Paramount will provide nominations by week for each product for the following month stating volumes and delivery points.

Prices for all products sold pursuant to the Asphalt Supply Agreement will be equal to the three day average price for such product, determined by reference to the value derived from the pricing formula set forth in the Asphalt Supply Agreement for such product on the day of delivery or lifting and for the two business days prior to the date of delivery or lifting. For products having a contract term exceeding one year, the parties will meet any time after the expiration of six months from the effective date of the Asphalt Supply Agreement to reexamine the price for such product.

 

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In the event of a “change of control” (as defined in the Asphalt Supply Agreement), of us or Paramount, the Asphalt Supply Agreement will be terminated immediately.

Tax Sharing Agreement

In connection with the closing of this offering, we intend to enter into a tax sharing agreement with Alon Energy 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. The amount of any such reimbursement will be limited to the tax that we (and our subsidiaries) would have paid had we not been included in a combined group with Alon Energy. Alon Energy may use its tax attributes to cause its combined or consolidated group, of which we may be a member for this purpose, to owe no tax. However, we would nevertheless reimburse Alon Energy for the tax we would have owed had the attributes not been available or used for our benefit, even though Alon Energy had no cash expense for that period.

Other Transactions with Related Parties

Intercompany Debt

We incurred the following intercompany debt with Alon Energy and certain of its affiliates to satisfy working capital requirements, fund acquisitions and for general corporate purposes. As of September 30, 2012, we had the following outstanding intercompany debt payable to Alon Energy and its affiliates:

 

		September 30, 2012
		(in thousands)
$50,000 10.0% Note due 2018		$	50,000
$112,000 6.0% Note due 2018			112,000
$12,044 10.0% Note due 2018			12,044
$8,000 10.0% Note due 2018			8,000
$33,423 10.0% Note due 2018			33,423
Total subordinated debt-related parties (less accrued interest)			215,467
Accrued interest			131,115
Total subordinated debt-related parties		$	346,582

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. We will use the net proceeds of this offering to repay approximately $211.9 million of the intercompany debt. We expect that the remaining balance of the intercompany debt will be eliminated prior to closing. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Intercompany Debt.”

 

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its owners, on the one hand, and us and our public unitholders, on the other hand. Conflicts may arise as a result of the duties of our general partner to act for the benefit of its owners, which may conflict with our interests and the interests of our public unitholders. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. The Delaware Revised Uniform Limited Partnership Act, which we refer to as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a general partner to limited partners and the partnership. Pursuant to these provisions, our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of the general partner and the methods of resolving conflicts of interest. Our partnership agreement also specifically defines the remedies available to limited partners for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law.

Whenever a conflict arises between our general partner and its owners, on the one hand, and us and our public unitholders, on the other, the resolution or course of action in respect of such conflict of interest shall be permitted and deemed approved by all our limited partners and shall not constitute a breach of our partnership agreement, of any agreement contemplated thereby or of any duty, if the resolution or course of action in respect of such conflict of interest is:

 

•

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

 

•

approved by the holders of a majority of the outstanding units, excluding any units owned by the general partner or any of its affiliates.

Our general partner may, but is not required to, seek the approval of such resolutions or courses of action from the conflicts committee of the board of our general partner or from the holders of a majority of the outstanding units as described above. If our general partner does not seek approval from the conflicts committee or from holders of units as described above and the board of directors of our general partner approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, the board of directors of our general partner or the conflicts committee of our general partner may consider any factors they determine in good faith to consider when resolving a conflict. An independent third party is not required to evaluate the resolution. Under our partnership agreement, a determination, other action or failure to act by our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) will be deemed to be “in good faith” unless our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) believed such determination, other action or failure to act was adverse to the interests of the partnership. See “Management—Management of Alon USA Partners, LP” for information about the conflicts committee of our general partner’s board of directors.

Conflicts of interest could arise in the situations described below, among others.

We rely primarily on the executive officers of our general partner, who also serve as the senior management team of Alon Energy and its affiliates, to manage most aspects of our business and affairs.

We rely primarily on the executive officers of our general partner, who also serve as the senior management team of Alon Energy and its affiliates to manage most aspects of our business and affairs.

 

 

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Although we will enter into a services agreement with Alon Energy upon the closing of this offering, under which we compensate Alon Energy for the services of its management, Alon Energy’s management is not required to devote any specific amount of time to our business and may devote a substantial majority of their time to the business of Alon Energy rather than to our business. Moreover, Alon Energy can terminate the services agreement, which following the one-year anniversary of the closing date of this offering, it may do upon 180 day’s prior written notice. In addition, the executive officers of Alon Energy, including its chief executive officer and chief financial officer, will face conflicts of interest if decisions arise in which we and Alon Energy have conflicting points of view or interests.

Subject to our rights of first refusal and negotiation under the omnibus agreement, our general partner’s affiliates may compete with us.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner, guaranteeing debt of its affiliates and those activities incidental to its ownership of interests in us. In addition, 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. However, except as provided in our partnership agreement and the omnibus agreement, affiliates of our general partner (which includes Alon Energy) are not otherwise prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. See “Certain Relationships and Related Party Transactions—Agreements with Alon Energy—Omnibus Agreement.”

Neither our partnership agreement nor any other agreement requires Alon Energy or its affiliates to pursue a business strategy that favors us or utilizes our assets or dictates what markets to pursue or grow. Alon Energy’s directors and officers must make these decisions in accordance with the fiduciary duties they owe to the stockholders of Alon Energy, which may be contrary to our interests.

The officers and certain directors of our general partner who are also officers or directors of Alon Energy have fiduciary duties to Alon Energy and to its stockholders that may cause them to pursue business strategies that disproportionately benefit Alon Energy or which otherwise are not in our best interests.

Our general partner is allowed to take into account the interests of parties other than us (such as Alon Energy) in exercising certain rights under our partnership agreement.

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 in its capacity as our 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, us, our affiliates or any limited partner. Examples include the exercise of its call right, its voting rights with respect to the units it owns, its registration rights and the determination of whether to consent to any merger or consolidation of the partnership or amendment of the 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.

 

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Our partnership agreement limits the liability of, and replaces the duties owed by, our general partner and also restricts the remedies available to our unitholders for actions that, without the limitations, might otherwise constitute breaches of fiduciary duty under applicable law.

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of fiduciary duty. For example, 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 decision was not adverse to the interests of the partnership and, except as specifically provided by our partnership agreement, 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;

 

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our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners 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 its officers or directors acted in bad faith or, in the case of a criminal matter, acted with knowledge that its conduct was unlawful; and

 

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in resolving conflicts of interest, it will be presumed that in making its decision our general partner, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

By purchasing a common unit, a common unitholder will agree to become bound by the provisions in our partnership agreement, including the provisions discussed above. See “—Fiduciary Duties of Our General Partner.”

Actions taken by our general partner may affect the amount of cash distributions to unitholders.

The amount of cash that is available for distribution to unitholders is affected by decisions of the board of directors of our general partner regarding such matters as:

 

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the expenses associated with being a public company and other general and administrative expenses;

 

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the creation of reserves for payment of cash distributions in respect of quarters in which a scheduled turnaround or catalyst replacement occurs;

 

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interest expense and other financing costs related to current and future indebtedness;

 

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repayment of principal on our indebtedness;

 

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amount and timing of asset purchases and sales;

 

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cash expenditures, including for capital expenditures;

 

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borrowings; and

 

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the issuance of additional units.

Our partnership agreement permits us to borrow funds to make a distribution on all outstanding units, and further provides that we and our subsidiaries may borrow funds from our general partner and its affiliates.

 

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Our general partner and its affiliates are not required to own any of our common units. If our general partner’s affiliates were to sell all or substantially all of their common units, this would heighten the risk that our general partner would act in ways that are more beneficial to itself than our common unitholders.

Upon the closing of this offering, affiliates of our general partner will own the majority of our outstanding units, but there is no requirement that they continue to do so. The general partner and its affiliates are permitted to sell all of their common units, subject to certain limitations contained in our partnership agreement. In addition, the current owners of our general partner may sell all or any portion of the general partner interest to an unrelated third party. If neither the general partner nor its affiliates owned any of our common units, this would heighten the risk that our general partner would act in ways that are more beneficial to itself than our common unitholders.

We will reimburse our general partner and its affiliates, including Alon Energy, for expenses.

We will reimburse our general partner and its affiliates, including Alon Energy, for costs incurred in managing and operating us, including overhead costs incurred by Alon Energy in rendering corporate staff and support services to us. Our partnership agreement provides that the board of directors of our general partner will determine in good faith the expenses that are allocable to us and that reimbursement of overhead to Alon Energy as described above is fair and reasonable to us. The services agreement will not contain any cap on the amount we may be required to pay pursuant to this agreement. See “Certain Relationships and Related Party Transactions—Agreements with Alon Energy—Services Agreement.”

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

If at any time our general partner and its affiliates own more than 80% 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. 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 manager from issuing additional common units and 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.”

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm’s-length negotiations.

Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm’s length negotiations. Our general partner will determine, in good faith, the terms of any such future transactions.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets and not against our general partner or its assets. Our partnership agreement provides that any action taken by our general partner to limit its liability or our liability is not a breach of our general partner’s duties, even if we could have obtained terms that are more favorable without the limitation on liability.

 

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Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

We may choose not to retain separate counsel for ourselves or for the holders of common units.

The attorneys, independent accountants and others who perform services for us in this offering have been retained by our general partner or its affiliates. Attorneys, independent accountants and others who perform services for us in the future will be selected by our general partner and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Except in limited circumstances, our general partner has the power and authority to conduct our business without limited partner approval.

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:

 

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the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into securities of the partnership, and the incurring of any other obligations;

 

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the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets;

 

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the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets or the merger or other combination of us with or into another person;

 

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the negotiation, execution and performance of any contracts, conveyances or other instruments;

 

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the distribution of partnership cash;

 

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the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

 

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the maintenance of insurance for our benefit and the benefit of our partners;

 

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the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other entities;

 

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the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

 

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the indemnification of any person against liabilities and contingencies to the extent permitted by law;

 

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the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities; and

 

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the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

See “The Partnership Agreement” for information regarding the voting rights of common unitholders.

 

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Fiduciary Duties of Our General Partner

The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, modify, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to limited partners and the partnership.

Pursuant to these provisions, our partnership agreement contains various provisions that replace the fiduciary duties that would otherwise be owed by our general partner. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that otherwise might be prohibited by state law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has a duty to manage our partnership in good faith and a duty to manage our general partner in a manner beneficial to its owners. Without these modifications, our general partner’s ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards benefit our general partner by enabling it to take into consideration all parties involved in the proposed action. These modifications also strengthen the ability of our general partner to attract and retain experienced and capable directors. These modifications represent a detriment to our public unitholders because they restrict the remedies available to our public unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interests.

The following is a summary of: the default fiduciary duties under the Delaware Act; the standards contained in our partnership agreement; and certain rights and remedies of limited partners contained in the Delaware Act.

 

State law fiduciary duty standards

Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally require that any action taken or transaction engaged in be entirely fair to the partnership.

 

Partnership agreement modified standards

Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These contractual standards reduce the obligations to which our general partner would otherwise be held.

 

If our general partner does not seek approval from the conflicts committee of its board of directors or the unitholders, excluding any units owned by our general partner or its affiliates, and its board of directors approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in

 

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making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.

 

Rights and remedies of limited partners

The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties or of our partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of it and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

 

Partnership agreement modified standards

The Delaware Act provides that, unless otherwise provided in a partnership agreement, a partner or other person shall not be liable to a limited partnership or to another partner or to another person that is a party to or is otherwise bound by a partnership agreement for breach of fiduciary duty for the partner’s or other person’s good faith reliance on the provisions of the partnership agreement. Under our partnership agreement, to the extent that, at law or in equity an indemnitee has duties (including fiduciary duties) and liabilities relating thereto to us or to our partners, our general partner and any other indemnitee acting in connection with our business or affairs shall not be liable to us or to any partner for its good faith reliance on the provisions of our partnership agreement.

In order to become one of our limited partners, a common unitholder is required to agree to be bound by the provisions in our partnership agreement, including the provisions discussed above. See “Description of the Common Units—Transfer of Common Units.” This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render our partnership agreement unenforceable against that person.

Under our partnership agreement, we must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith. We also must provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC such indemnification is contrary to public policy and therefore unenforceable. See “The Partnership Agreement—Indemnification.”

 

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Related Party Transactions

We have adopted policies for the review, approval and ratification of transactions with related persons. At the discretion of our general partner’s board of directors, a proposed related party transaction may generally be approved by the board in its entirety, or by a “conflicts committee” meeting the definitional requirements for such a committee under the Partnership Agreement.

 

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DESCRIPTION OF THE COMMON UNITS

Our Common Units

The common units offered hereby represent limited partner interests in us. The holders of common units are entitled to participate in partnership distributions and exercise the rights and privileges provided to limited partners under our partnership agreement. For a description of the rights and privileges of holders of our common units to partnership distributions, see “How We Make Cash Distributions” and “Cash Distribution Policy and Restrictions on Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, see “The Partnership Agreement.”

Transfer Agent and Registrar

Duties. American Stock Transfer & Trust Company, LLC will serve as registrar and transfer agent for the common units. We pay all fees charged by the transfer agent for transfers of common units, except the following, which must be paid by unitholders:

 

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surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

 

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special charges for services requested by a holder of a common unit; and

 

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other similar fees or charges.

There is no charge to unitholders for disbursements of our quarterly cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal. The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If a successor has not been appointed or has not accepted its appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Each transferee:

 

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represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

 

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automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and

 

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gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements entered into in connection with our formation and this offering.

A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records from time to time as necessary to accurately reflect the transfers.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

 

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Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Listing

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

 

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Annex A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

 

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with regard to distributions of cash, see “How We Make Cash Distributions;”

 

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with regard to the duties of our general partner, see “Conflicts of Interest and Fiduciary Duties;”

 

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with regard to the authority of our general partner to manage our business and activities, see “Management—Management of Alon USA Partners, LP;”

 

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with regard to the transfer of common units, see “Description of the Common Units—Transfer of Common Units;” and

 

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with regard to allocations of taxable income and taxable loss, see “Material U.S. Federal Income Tax Consequences.”

Organization and Duration

We were organized in August 2012 and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

Our purpose under our partnership agreement is limited to engaging in any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner shall not cause us to take any action that the general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiary to engage in activities other than those related to the petroleum refining business and activities now or hereafter customarily conducted in conjunction with this business, our general partner may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or our limited partners. In general, our general partner is authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Our partnership agreement specifies the manner in which we will make distributions to holders of our common units. For a description of these distributions, please read “How We Make Cash Distributions.”

Capital Contributions

Common unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.” For a discussion of our general partner’s right to contribute capital to maintain its and its affiliates’ percentage interest if we issue partnership interests, see “—Issuance of Additional Partnership Interests.”

Adjustments to Capital Accounts Upon Issuance of Additional Common Units

We will make adjustments to capital accounts upon the issuance of additional common units. In doing so, we will generally allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to our unitholders prior to such issuance on a pro rata basis, so that after such issuance, the capital account balances attributable to all common units are equal.

 

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Voting Rights

The following is a summary of the unitholder vote required for the matters specified below. Matters requiring the approval of a “unit majority” require the approval of a majority of the common units.

At the closing of this offering, Alon Energy will have the ability to ensure passage of, as well as the ability to ensure the defeat of, any amendment which requires a unit majority by virtue of its     % indirect ownership of our common units.

In voting their common units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. The holders of a majority of the common units (including common units deemed owned by our general partner) represented in person or by proxy shall constitute a quorum at a meeting of such common unitholders, unless any such action requires approval by holders of a greater percentage of such units in which case the quorum shall be such greater percentage.

The following is a summary of the vote requirements specified for certain matters under our partnership agreement.

 

Issuance of additional partnership interests		No approval right. See “—Issuance of Additional Partnership Interests.”
Amendment of our partnership agreement		Certain amendments may be made by our general partner without the approval of the common unitholders. Other amendments generally require the approval of a unit majority. See “—Amendment of Our Partnership Agreement.”
Merger of our partnership or the sale of all or substantially all of our assets		Unit majority for certain circumstances. See “—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”
Dissolutions of our partnership		Unit majority. See “—Termination and Dissolution.”
Continuation of our partnership upon dissolution		Unit majority. See “—Termination and Dissolution.”
Withdrawal of our general partner		Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to December 31, 2022. See “—Withdrawal or Removal of Our General Partner.”
Removal of our general partners		Not less than 66 2/3% of the outstanding common units, including common units held by our general partner and its affiliates. See “—Withdrawal or Removal of Our General Partner.”
Transfer of the general partner interest		At any time, our general partner may transfer all or any of its general partner interest to another person without the approval of our common unitholders. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters. In addition, any such transfer would require the approval of the lenders under our amended and restated revolving credit facility and new term loan facility. See “—Transfer of General Partner Interest.”
Transfer of ownership interest in our general partner		No approval required at any time. See “—Transfer of Ownership Interests in Our General Partner.”

 

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If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of such units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the specific approval of our general partner.

Applicable Law; Forum, Venue and Jurisdiction

Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:

 

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arising out of or relating in any way to the partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us);

 

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brought in a derivative manner on our behalf;

 

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asserting a claim of breach of a fiduciary duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners;

 

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asserting a claim arising pursuant to any provision of the Delaware Act; or

 

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asserting a claim governed by the internal affairs doctrine

shall be exclusively brought in the Court of Chancery of the State of Delaware or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction, regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims. The enforceability of similar choice of forum provisions in the certificate of incorporation of Delaware corporations has been challenged in legal proceedings, and it is possible that a court could find these types of analogous provisions in a partnership agreement to be inapplicable or unenforceable.

By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware in connection with any such claims, suits, actions or proceedings.

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that it otherwise acts in conformity with the provisions of our partnership agreement, its liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital it is obligated to contribute to us for its common units plus its share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:

 

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to remove or replace our general partner;

 

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to approve some amendments to our partnership agreement; or

 

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to take other action under our partnership agreement

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could 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 who reasonably believe 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. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for such a claim in Delaware case law.

 

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Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

Our subsidiaries conduct business in Texas, New Mexico, Arizona, Oklahoma, Louisiana and Arkansas. We and our current subsidiaries or any future subsidiaries may conduct business in other states in the future. Maintenance of our limited liability as a member of our operating company may require compliance with legal requirements in the jurisdictions in which our operating company conducts business, including qualifying our subsidiaries to do business there. We have attempted to limit our liability for the obligations of our operating subsidiaries by structuring each as a limited liability company.

If, by virtue of our membership interest in our operating subsidiaries or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or liability company statute, or that the right, or exercise of the right by the limited partners as a group, to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Partnership Interests

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our quarterly cash distributions. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, have special voting rights to which the common units are not entitled or are senior in right of distribution to the common units. In addition, our partnership agreement does not prohibit the issuance by our subsidiary of equity interests, which may effectively rank senior to the common units.

Our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, whenever, and on the same terms that, we issue those interests to persons other than our general partner and its affiliates, to the extent necessary to maintain its and its affiliates’ percentage

 

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interest, including such interest represented by common units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights under our partnership agreement to acquire additional common units or other partnership interests.

Amendment of Our Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or any partner, including any duty to act in good faith or in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below under “—No Unitholder Approval,” our general partner is required to seek written approval of the holders of the number of common units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

No amendment may be made that would:

(1) enlarge the obligations of any limited partner or general partner without its consent, unless approved by at least a majority of the type or class of partner interests so affected;

(2) enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld in its sole discretion;

(3) change certain of the terms under which we can be dissolved; or

(4) change the term of the Partnership.

The provision of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding common units, voting together as a single class (including common units owned by our general partner and its affiliates). Upon completion of this offering, our general partner and its affiliates will own approximately     % of the outstanding common units (approximately      % if the underwriters exercise their option to purchase additional common units in full).

No Unitholder Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any other partner to reflect:

 

•

a change in our name, the location of our principal place of business, our registered agent or our registered office;

 

•

the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

 

•

a change that our general partner determines to be necessary or appropriate for us to qualify or to continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor our subsidiary will be treated as an association taxable as a corporation or otherwise taxed as an entity for U.S. federal income tax purposes (to the extent not already so treated or taxed);

 

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•

an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents, or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisers Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974 (“ERISA”), whether or not substantially similar to plan asset regulations currently applied or proposed;

 

•

an amendment that our general partner determines to be necessary or appropriate for the creation, authorization, or issuance of additional partnership interests or rights to acquire partnership interests, as otherwise permitted by our partnership agreement;

 

•

any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

 

•

an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

 

•

any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;

 

•

a change in our fiscal year or taxable year and related changes;

 

•

conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

 

•

any other amendments substantially similar to any of the matters described above.

In addition, our general partner may make amendments to our partnership agreement without the approval of any partner if our general partner determines that those amendments:

 

•

do not adversely affect in any material respect the partners considered as a whole or any particular class of partners;

 

•

are necessary or appropriate to satisfy any requirements, conditions, or guidelines contained in any opinion, directive, order, ruling, or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

 

•

are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline, or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

 

•

are necessary or appropriate for any action taken by our general partner relating to splits or combinations of common units under the provisions of our partnership agreement; or

 

•

are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval

For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for U.S. federal income tax purposes in connection with any of the amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding common units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under Delaware law of any of our limited partners.

 

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Any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding common units in relation to other classes of units will require the approval of at least a majority of the type or class of common units so affected. Any amendment that would reduce the percentage of units required to take any action, other than to remove the general partner or call a meeting of unitholders must be approved by the affirmative vote of partners whose aggregate outstanding units constitute not less than the percentage sought to be reduced.

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

A merger or consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger or consolidation and may decline to do so free of any fiduciary duty or obligation whatsoever to us or other partners, including any duty to act in good faith or in the best interest of us or the other partners.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation, conversion or other combination. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval.

Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement (other than an amendment that the general partner could adopt without the consent of other partners), each of our common units will be an identical unit of our partnership following the transaction and the partnership securities to be issued do not exceed 20% of our outstanding partnership interests immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or our subsidiary into a new limited liability entity or merge us or our subsidiary into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, we have received an opinion of counsel regarding limited liability and tax matters and the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Termination and Dissolution

We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:

(1) the election of our general partner to dissolve us, if approved by the holders of common units representing a unit majority;

(2) there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

(3) the entry of a decree of judicial dissolution of our partnership; or

 

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(4) the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor.

Upon a dissolution under clause (4), the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of common units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

 

•

the action would not result in the loss of limited liability under Delaware law of any limited partner; and

 

•

neither our partnership nor our subsidiary would be treated as an association taxable as a corporation or otherwise be taxable as an entity for U.S. federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

Liquidation and Distribution of Proceeds

Upon our dissolution, unless our business is continued, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as set forth in our partnership agreement. The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2022 without obtaining the approval of the holders of at least a majority of the outstanding common units excluding common units held by our general partner and its affiliates (including Alon Energy), and furnishing an opinion of counsel regarding limited liability and tax matters. On or after December 31, 2022, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the unitholders if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest without the approval of the unitholders. See “—Transfer of General Partner Interest.”

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a majority of the outstanding classes of common units voting as a single class may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period of time after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. See “—Termination and Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66  ²/₃% of the outstanding common units, voting together as a single class, including common units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units. The ownership of more than 33 ¹/₃% of the outstanding common units by our general partner and its affiliates gives them the ability to prevent our general partner’s removal. At the closing of this offering, affiliates of our general partner will own approximately        % of the outstanding common units (        % if the underwriters exercise their option to purchase additional common units in full).

 

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In the event of removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest of the departing general partner for a cash payment equal to the fair market value of the general partner interest. Under all other circumstances where our general partner withdraws or is removed, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner for its fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due to the general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Interest

At any time, our general partner may transfer all or any of its general partner interest to another person without the approval of our common unitholders. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters. In addition, any such transfer would require the approval of the lenders under our amended and restated revolving credit facility and new term loan facility.

Transfer of Ownership Interests in Our General Partner

At any time, the owners of our general partner may sell or transfer all or part of their ownership interests in our general partner to an affiliate or a third party without the approval of our unitholders.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Alon USA Partners GP, LLC as our general partner or otherwise change management. See “—Withdrawal or Removal of Our General Partner” for a discussion of certain consequences of the removal of our general partner. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of common units, that person or group loses voting rights on all of its common units. This loss of voting rights does not apply in certain circumstances. See “—Voting Rights.”

Call Right

If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by public unitholders, as of a record date to be selected by our general partner, on at least 10 but not more than 60 days’ notice. Immediately following this offering the only class of limited partner interest outstanding will be the common units, and affiliates of our general partner will own        % of the total outstanding common units.

 

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The purchase price in the event of such an acquisition will be the greater of:

(1) the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; or

(2) the average of the daily closing prices of the limited partner interests over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed.

As a result of our general partner’s right to purchase outstanding common units, a holder of common units may have its common units purchased at an undesirable time or at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The U.S. federal income tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. See “Material U.S. Federal Income Tax Consequences—Disposition of Units.”

Non-Citizen Assignees; Redemption

If our general partner, with the advice of counsel, determines we are subject to U.S. federal, state or local laws or regulations that create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

 

•

obtain proof of the nationality, citizenship or other related status of our limited partner (and their owners, to the extent relevant); and

 

•

permit us to redeem the common units held by any person whose nationality, citizenship or other related status creates substantial risk of cancellation or forfeiture of any property or who fails to comply with the procedures instituted by the board to obtain proof of the nationality, citizenship or other related status. The redemption price in the case of such redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

Non-Taxpaying Assignees; Redemption

To avoid any adverse effect on the maximum applicable rates chargeable to customers by our subsidiary, or in order to reverse an adverse determination that has occurred regarding such maximum rate, our partnership agreement provides our general partner the power to amend the agreement. If our general partner, with the advice of counsel, determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our partners, has, or is reasonably likely to have, a material adverse effect on the maximum applicable rates chargeable to customers by our current or future subsidiaries, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

 

•

obtain proof of the U.S. federal income tax status of our partner (and their owners, to the extent relevant); and

 

•

permit us to redeem the common units held by any person whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates or who fails to comply with the procedures instituted by the general partner to obtain proof of the U.S. federal income tax status. The redemption price in the case of such redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

 

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Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, unitholders who are record holders of common units on the record date will be entitled to notice of, and to vote at, meetings of our unitholders and to act upon matters for which approvals may be solicited. Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. See “—Issuance of Additional Partnership Interests.” However, if at any time any person or group, other than our general partner and its affiliates, a direct or subsequently approved transferee of our general partner or their affiliates, or, upon the approval by the general partner, any other unitholder, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum, or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.

Any notice, demand, request, report, or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner or Assignee

Except as described above under “—Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions. By transfer of common units in accordance with our partnership agreement, each transferee of common units will be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records.

Indemnification

Under our partnership agreement we will indemnify the following persons in most circumstances, to the fullest extent permitted by law, from and against all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all threatened, pending or completed claims, demands, actions, suits or proceedings:

(1) our general partner;

(2) any departing general partner;

(3) any person who is or was a director, officer, fiduciary, trustee, manager or managing member of us or our subsidiary, our general partner or any departing general partner;

(4) any person who is or was serving as a director, officer, fiduciary, trustee, manager or managing member of another person owing a fiduciary duty to us or our subsidiary at the request of a general partner or any departing general partner;

 

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(5) any person who controls our general partner; or

(6) any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless they otherwise agree, our general partner will not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for (1) all direct and indirect expenses it incurs or payments it makes on our behalf (including salary, bonus, incentive compensation and other amounts paid to any person, including affiliates of our general partner, to perform services for us or for the general partner in the discharge of its duties to us) and (2) all other expenses reasonably allocable to us or otherwise incurred by our general partner in connection with operating our business (including expenses allocated to our general partner by its affiliates). Our general partner is entitled to determine in good faith the expenses that are allocable to us.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of our common units, within 105 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available a report containing our unaudited financial statements within 50 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website which we maintain.

We will furnish each record holder of a unit with tax information reasonably required for federal and state income tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

In addition, Alon Energy will have full and complete access to any records relating to our business, and our general partner will cause its officers and independent accountants to be available to discuss our business and affairs with Alon Energy’s officers, agents and employees.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his/her interest as a limited partner, upon reasonable demand and at his own expense, have furnished to him:

(1) a current list of the name and last known address of each record holder;

(2) information as to the amount of cash, and a description and statement of the agreed value of any other capital contribution, contributed or to be contributed by each partner and the date on which each became a partner;

 

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(3) copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed;

(4) information regarding the status of our business and financial condition (provided that obligation shall be satisfied to the extent the limited partner is furnished our most recent annual report and any subsequent quarterly or periodic reports required to be filed (or which would be required to be filed) with the SEC pursuant to Section 13 of the Exchange Act); and

(5) any other information regarding our affairs that our general partner determines is just and reasonable.

Under our partnership agreement, however, each of our limited partners and other persons who acquire interests in our partnership interests, do not have rights to receive information from us or any of the persons we indemnify as described above under “—Indemnification” for the purpose of determining whether to pursue litigation or assist in pending litigation against us or those indemnified persons relating to our affairs, except pursuant to the applicable rules of discovery relating to the litigation commenced by the person seeking information.

Our general partner may, and intends to, keep confidential from the limited partners’ trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any units sold by our general partner or any of its affiliates if an exemption from the registration requirements is not otherwise available. We will not be required to effect more than two registrations pursuant to this provision in any twelve-month period, and our general partner can defer filing a registration statement for up to six months if it determines that this would be in our best interests due to a pending transaction, investigation or other event. We have also agreed that, if we at any time propose to file a registration statement for an offering of partnership interests for cash, we will use all commercially reasonable efforts to include such number of partnership interests in such registration statement as any of our general partner or any of its affiliates shall request. We are obligated to pay all expenses incidental to these registrations, other than underwriting discounts and commissions. The registration rights in our partnership agreement are applicable with respect to our general partner and its affiliates after it ceases to be a general partner for up to two years following the effective date of such cessation. See “Units Eligible for Future Sale.”

 

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UNITS ELIGIBLE FOR FUTURE SALE

Upon the completion of this offering, there will be                 common units outstanding,                 of which will be indirectly owned by Alon Energy, assuming the underwriters do not exercise their option to purchase additional common units; if they exercise such option in full, Alon Energy will indirectly own                 common units. The sale of these common units could have an adverse impact on the price of our common units or on any trading market that may develop.

The                 common units sold in this offering (or                 common units if the underwriters exercise their option to purchase additional common units in full) will generally be freely transferable without restriction or further registration under the Securities Act. However, any common units held by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption from the registration requirements of the Securities Act pursuant to Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of ours to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

 

•

1% of the total number of the class of securities outstanding; or

 

•

the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 by our affiliates are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned common units for at least six months, would be entitled to sell those common units under Rule 144 without regard to the volume, manner of sale and notice requirements of Rule 144 so long as we comply with the current public information requirement for the next six months after the six-month holding period expires.

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders. Any issuance of additional common units or other equity interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. See “The Partnership Agreement—Issuance of Additional Partnership Interests.”

Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of the partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units to require registration of any of these units and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. Our general partner will continue to have these registration rights for two years after it ceases to be a general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Our general partner and its affiliates also may sell their units in private transactions at any time, subject to compliance with applicable laws.

We, the subsidiaries of Alon Energy that will own our common units following the closing of this offering, our general partner, and the directors and executive officers of our general partner have agreed not to sell any common units until 180 days after the date of this prospectus, subject to certain exceptions. See “Underwriting” for a description of these lock-up provisions.

 

 

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In addition, we intend to file a registration statement on Form S-8 under the Securities Act to register                      common units issuable under our long-term incentive plan. This registration statement is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Units issued under our long-term incentive plan will be eligible for resale in the public market without restriction after the effective date of the Form S-8 registration statement, subject to Rule 144 limitations applicable to affiliates.

 

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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

This section summarizes the material U.S. federal income tax consequences that may be relevant to prospective unitholders and is based upon current provisions of the U.S. Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed U.S. Treasury regulations thereunder (the “Treasury Regulations”), and current administrative rulings and court decisions, all of which are subject to change. Changes in these authorities may cause the federal income tax consequences to a prospective unitholder to vary substantially from those described below. Unless the context otherwise requires, references in this section to “we” or “us” are references to the Alon USA Partners, LP and our operating subsidiaries.

Legal conclusions contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of representations made by us to them for this purpose. However, this section does not address all federal income tax matters that affect us or our unitholders and does not describe the application of the alternative minimum tax that may be applicable to certain unitholders. Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States (for federal income tax purposes), who have the U.S. dollar as their functional currency and who hold units as capital assets (generally, property that is held for investment). This section has limited applicability to corporations, partnerships (including entities treated as partnerships for U.S. federal income tax purposes), estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, non-U.S. persons, individual retirement accounts (“IRAs”), employee benefit plans, real estate investment trusts or mutual funds. Accordingly, we encourage each unitholder to consult the unitholder’s own tax advisor in analyzing the federal, state, local and non-U.S. tax consequences particular to that unitholder resulting from ownership or disposition of units and potential changes in applicable tax laws.

We are relying on opinions and advice of Vinson & Elkins L.L.P. with respect to the matters described herein. An opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or a court. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any such contest of the matters described herein may materially and adversely impact the market for our units and the prices at which our units trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution. Furthermore, the tax consequences of an investment in us may be significantly modified by future legislative or administrative changes or court decisions, which may be retroactively applied.

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following federal income tax issues: (1) the treatment of a unitholder whose units are the subject of a securities loan (e.g., a loan to a short seller to cover a short sale of units) (please read “—Tax Consequences of Unit Ownership—Treatment of Securities Loans”); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of Units—Allocations Between Transferors and Transferees”); and (3) whether our method for taking into account Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Uniformity of Units”).

Taxation of the Partnership

Partnership Status

We expect to be treated as a partnership for U.S. federal income tax purposes and, therefore, generally will not be liable for entity-level federal income taxes. Instead, as described below, each of our unitholders will take into account its respective share of our items of income, gain, loss and deduction in computing its federal income tax liability as if the unitholder had earned such income directly, even if we make no cash distributions to the unitholder. Distributions we make to a unitholder generally will not give rise to income or gain taxable to such unitholder, unless the amount of cash distributed exceeds the unitholder’s adjusted tax basis in its units.

 

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Section 7704 of the Code generally provides that publicly traded partnerships will be treated as corporations for federal income tax purposes. However, if 90% or more of a partnership’s gross income for every taxable year it is publicly traded consists of “qualifying income,” the partnership may continue to be treated as a partnership for federal income tax purposes (the “Qualifying Income Exception”). Qualifying income includes income and gains derived from the refining, transportation and marketing of natural resources, including crude oil and products thereof; as well as other types of income such as interest (other than from a financial business) and dividends. We estimate that approximately 5% of our current gross income is not qualifying income; however, this estimate could change from time to time.

Based upon factual representations made by us and our general partner regarding the composition of our income and the other representations set forth below, Vinson & Elkins L.L.P. is of the opinion that we will be treated as a partnership for federal income tax purposes and each of our operating subsidiaries will be disregarded as an entity separate from us for federal income tax purposes. In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Vinson & Elkins L.L.P. has relied include, without limitation:

(a) Neither we nor any of our operating subsidiaries has elected to be treated as a corporation for federal income tax purposes;

(b) For each taxable year since and including the year of our initial public offering, more than 90% of our gross income has been and will be income of a character that Vinson & Elkins L.L.P. has opined is “qualifying income” within the meaning of Section 7704(d) of the Code; and

(c) Each hedging transaction that we treat as resulting in qualifying income has been and will be appropriately identified as a hedging transaction pursuant to applicable Treasury Regulations, and has been and will be associated with our refining operations, our purchases of crude oil or our sales of refinery products thereof that are held or to be held by us in activities that Vinson & Elkins L.L.P. has opined or will opine result in qualifying income.

We believe that these representations are true and will be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as transferring all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation and then as distributing that stock to our unitholders in liquidation. This deemed contribution and liquidation should not result in the recognition of taxable income by our unitholders or us so long as our liabilities do not exceed the tax basis of our assets. Thereafter, we would be treated as an association taxable as a corporation for federal income tax purposes.

The present 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 interpretation at any time. For example, from time to time, members of the U.S. 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 upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us and may be applied retroactively. Any such changes could negatively impact the value of an investment in our units.

If for any reason we are taxable as a corporation in any taxable year, our items of income, gain, loss and deduction would be taken into account by us in determining the amount of our liability for federal income tax, rather than being passed through to our unitholders. Our taxation as a corporation would materially reduce the cash available for distribution to unitholders and thus would likely substantially reduce the value of our units.

 

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Any distribution made to a unitholder at a time we are treated as a corporation would be (i) a taxable dividend to the extent of our current or accumulated earnings and profits, then (ii) a nontaxable return of capital to the extent of the unitholder’s tax basis in its units, and thereafter (iii) taxable capital gain.

The remainder of this discussion is based on the opinion of Vinson & Elkins L.L.P. that we will be treated as a partnership for federal income tax purposes.

Tax Consequences of Unit Ownership

Limited Partner Status

Unitholders who are admitted as limited partners of the partnership, as well as unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of units, will be treated as partners of the partnership for federal income tax purposes. For a discussion related to the risks of losing partner status as a result of securities loans, please read “—Treatment of Securities Loans.” Unitholders who are not treated as partners of the partnership as described above are urged to consult their own tax advisors with respect to the tax consequences applicable to them under the circumstances.

Flow-Through of Taxable Income

Subject to the discussion below under “—Entity-Level Collections of Unitholder Taxes” with respect to payments we may be required to make on behalf of our unitholders, we will not pay any federal income tax. Rather, each unitholder will be required to report on its federal income tax return each year its share of our income, gains, losses and deductions for our taxable year or years ending with or within its taxable year. Consequently, we may allocate income to a unitholder even if that unitholder has not received a cash distribution.

Basis of Units

A unitholder’s tax basis in its units initially will be the amount paid for those units plus the unitholder’s share of our liabilities. That basis generally will be (i) increased by the unitholder’s share of our income and any increases in such unitholder’s share of our liabilities, and (ii) decreased, but not below zero, by the amount of all distributions, the unitholder’s share of our losses, and any decreases in its share of our liabilities.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of units in this offering who owns those units from the date of closing through December 31, 2015, will be allocated, on a cumulative basis, an amount of federal taxable income that will be approximately 50% of the cash distributed through that date. 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. These estimates are based upon the assumption that earnings from operations will approximate the amount available to make the assumed distribution on all units and other assumptions with respect to our earnings from operations, capital expenditures, cash flow, net working capital and cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct, and our counsel has not opined on the accuracy of such estimates. The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could affect the value of units. For example, the ratio of taxable income to cash distributions to a purchaser of units in this offering would be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

 

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we distribute less cash than we have assumed in making this projection; or

 

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we make a future offering of common units and use the proceeds of the offering in a manner that does not produce additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

Treatment of Distributions

Distributions made by us to a unitholder generally will not be taxable to the unitholder, unless such distributions exceed the unitholder’s tax basis in its units, in which case the unitholder generally will recognize gain taxable in the manner described below under “—Disposition of Units.”

Any reduction in a unitholder’s share of our liabilities will be treated as a distribution by us of cash to that unitholder. A decrease in a unitholder’s percentage interest in us because of our issuance of additional units may decrease the unitholder’s share of our liabilities. For purposes of the foregoing, a unitholder’s share of our nonrecourse liabilities (liabilities for which no partner bears the economic risk of loss) generally will be based upon that unitholder’s share of the unrealized appreciation (or depreciation) in our assets, to the extent thereof, with any excess liabilities allocated based on the unitholder’s share of our profits. Please read “—Disposition of Units.”

A non-pro rata distribution of money or property (including a deemed distribution as a result of the reduction in a unitholder’s share of our liabilities as described above) may cause a unitholder to recognize ordinary income, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture and substantially appreciated “inventory items,” both as defined in Section 751 of the Code (“Section 751 Assets”). To the extent of such reduction, the unitholder would be deemed to receive its proportionate share of the Section 751 Assets and exchange such assets with us in return for a portion of the non-pro rata distribution. This deemed exchange generally will result in the unitholder’s recognition of ordinary income in an amount equal to the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis (generally zero) in the Section 751 Assets deemed to be relinquished in the exchange.

Limitations on Deductibility of Losses

A unitholder may not be entitled to deduct the full amount of loss we allocate to it because its share of our losses will be limited to the lesser of (i) the unitholder’s tax basis in its units, and (ii) in the case of a unitholder that is an individual, estate, trust or certain types of closely held corporations, the amount for which the unitholder is considered to be “at risk” with respect to our activities. In general, a unitholder will be at risk to the extent of its tax basis in its units, reduced by (1) any portion of that basis attributable to the unitholder’s share of our liabilities, (2) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or similar arrangement and (3) any amount of money the unitholder borrows to acquire or hold its units, if the lender of those borrowed funds owns an interest in us, is related to another unitholder or can look only to the units for repayment. A unitholder subject to the at risk limitation must recapture losses deducted in previous years to the extent that distributions (including distributions deemed to result from a reduction in a unitholder’s share of nonrecourse liabilities) cause the unitholder’s at risk amount to be less than zero at the end of any taxable year.

Losses disallowed to a unitholder or recaptured as a result of the basis or at risk limitations will carry forward and will be allowable as a deduction in a later year to the extent that the unitholder’s tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon a taxable disposition of units, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but not losses suspended by the basis limitation. Any loss previously suspended by the at risk limitation in excess of that gain can no longer be used, and will not be available to offset a unitholder’s salary or active business income.

 

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In addition to the basis and at risk limitations, a passive activity loss limitation generally limits the deductibility of losses incurred by individuals, estates, trusts, some closely held corporations and personal service corporations from “passive activities” (generally, trade or business activities in which the taxpayer does not materially participate). The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will be available to offset only passive income generated by us. Passive losses that exceed a unitholder’s share of passive income we generate may be deducted in full when the unitholder disposes of all of its units in a fully taxable transaction with an unrelated party. The passive loss rules generally are applied after other applicable limitations on deductions, including the at risk and basis limitations.

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” generally is limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

 

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interest on indebtedness properly allocable to property held for investment;

 

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interest expense allocated against portfolio income; and

 

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the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent allocable against portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses other than interest directly connected with the production of investment income. Net investment income generally does not include qualified dividend income (if applicable) or gains attributable to the disposition of property held for investment. A unitholder’s share of a publicly traded partnership’s portfolio income and, according to the IRS, net passive income will be treated as investment income for purposes of the investment interest expense limitation.

Entity-Level Collections of Unitholder Taxes

If we are required or elect under applicable law to pay any federal, state, local or non-U.S. tax on behalf of any current or former unitholder or our general partner, we are authorized to treat the payment as a distribution of cash to the relevant unitholder or general partner. Where the tax is payable on behalf of all the unitholders or we cannot determine the specific unitholder on whose behalf the tax is payable, we are authorized to treat the payment as a distribution to all current unitholders. Payments by us as described above could give rise to an overpayment of tax on behalf of a unitholder, in which event the unitholder may be entitled to claim a refund of the overpayment amount. Unitholders are urged to consult their tax advisors to determine the consequences to them of any tax payment we make on their behalf.

Allocation of Income, Gain, Loss and Deduction

Our items of income, gain, loss and deduction generally will be allocated amongst our unitholders in accordance with their percentage interests in us. Specified items of our income, gain, loss and deduction will be allocated under Section 704(c) of the Code (or the principles of Section 704(c) of the Code) to account for any difference between the tax basis and fair market value of our assets at the time such assets are contributed to us and at the time of any subsequent offering of our units (a “Book-Tax Disparity”). As a result, the federal income tax burden associated with any Book-Tax Disparity immediately prior to an offering generally will be borne by our partners holding interests in us prior to such offering. In addition, items of recapture income will be specially

 

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allocated to the extent possible to the unitholder who was allocated the deduction giving rise to that recapture income in order to minimize the recognition of ordinary income by other unitholders.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate a Book-Tax Disparity, will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has “substantial economic effect.” In any other case, a partner’s share of an item will be determined on the basis of the partner’s interest in us, which will be determined by taking into account all the facts and circumstances, including (i) his relative contributions to us, (ii) the interests of all the partners in profits and losses, (iii) the interest of all the partners in cash flow and (iv) the rights of all the partners to distributions of capital upon liquidation. Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “—Section 754 Election” and “—Disposition of Units—Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Treatment of Securities Loans

A unitholder whose units are loaned (for example, a loan to a “short seller” to cover a short sale of units) may be treated as having disposed of those units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period (i) any of our income, gain, loss or deduction allocated to those units would not be reportable by the lending unitholder, and (ii) any cash distributions received by the unitholder as to those units may be treated as ordinary taxable income.

Due to a lack of controlling authority, Vinson & Elkins L.L.P. has not rendered an opinion regarding the tax treatment of a unitholder that enters into a securities loan with respect to its units. Unitholders desiring to assure their status as partners and avoid the risk of income recognition from a loan of their units are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and lending their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please read “—Disposition of Units—Recognition of Gain or Loss.”

Tax Rates

Under current law, the highest marginal federal income tax rates for individuals applicable to ordinary income and long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) are 35% and 15%, respectively. However, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. These rates are subject to change by new legislation at any time.

A 3.8% Medicare tax on certain net investment income earned by individuals, estates, and trusts will apply for taxable years beginning after December 31, 2012. For these purposes, net investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income from all investments, or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if married filing separately) or $200,000 (if the unitholder is unmarried or in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

 

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Section 754 Election

We will make the election permitted by Section 754 of the Code that permits us to adjust the tax bases in our assets as to specific purchasers of our units under Section 743(b) of the Code. The Section 743(b) adjustment separately applies to each purchaser of units based upon the values and bases of our assets at the time of the relevant purchase, and the adjustment will reflect the purchase price paid. The Section 743(b) adjustment does not apply to a person who purchases units directly from us.

Under our partnership agreement, we are authorized to take a position to preserve the uniformity of units even if that position is not consistent with applicable Treasury Regulations. A literal application of Treasury Regulations governing a 743(b) adjustment attributable to properties depreciable under section 167 of the Code, may give rise to differences in the taxation of unitholders purchasing units from us and unitholders purchasing from other unitholders. If we have any such properties, we intend to adopt methods employed by other publicly traded partnerships to preserve the uniformity of units, even if inconsistent with existing Treasury Regulations, and Vinson & Elkins, L.L.P. has not opined on the validity of this approach. Please read “— Uniformity of Units.”

The IRS may challenge the positions we adopt with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of units due to lack of controlling authority. Because a unitholder’s tax basis for its units is reduced by its share of our items of deduction or loss, any position we take that understates deductions will overstate a unitholder’s basis in its units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Units—Recognition of Gain or Loss.” If a challenge to such treatment were sustained, the gain from the sale of units may be increased without the benefit of additional deductions.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our assets subject to depreciation to goodwill or nondepreciable assets. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure any unitholder that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different tax basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than it would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We will use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income its share of our income, gain, loss and deduction for each taxable year ending within or with its taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of its units following the close of our taxable year but before the close of its taxable year must include its share of our income, gain, loss and deduction in income for its taxable year, with the result that it will be required to include in income for its taxable year its share of more than one year of our income, gain, loss and deduction. Please read “—Disposition of Units—Allocations Between Transferors and Transferees.”

Tax Basis, Depreciation and Amortization

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets.

 

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If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation deductions previously taken, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of its interest in us. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction” and “—Disposition of Units—Recognition of Gain or Loss.”

The costs we incur in offering and selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. While there are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us, the underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values and the initial tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of tax basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by unitholders could change, and unitholders could be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Units

Recognition of Gain or Loss

A unitholder will be required to recognize gain or loss on a sale of units equal to the difference between the unitholder’s amount realized and tax basis in the units sold. A unitholder’s amount realized generally will equal the sum of the cash or the fair market value of other property it receives plus its share of our liabilities with respect to such units. Because the amount realized includes a unitholder’s share of our liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Except as noted below, gain or loss recognized by a unitholder on the sale or exchange of a unit held for more than one year generally will be taxable as long-term capital gain or loss. However, gain or loss recognized on the disposition of units will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to Section 751 Assets, such as depreciation recapture. Ordinary income attributable to Section 751 Assets may exceed net taxable gain realized on the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and capital gain or loss upon a sale of units. Net capital loss may offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in its entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership.

 

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Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling discussed above, a unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, it may designate specific units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or exchanges of our units. A unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult its tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” financial position, including a partnership interest with respect to which gain would be recognized if it were sold, assigned or terminated at its fair market value, in the event the taxpayer or a related person enters into:

 

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a short sale;

 

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an offsetting notional principal contract; or

 

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a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income or loss will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the “Allocation Date”). However, gain or loss realized on a sale or other disposition of our assets or, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction will be allocated among the unitholders on the Allocation Date in the month in which such income, gain, loss or deduction is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferee and transferor unitholders. If this method is not allowed under the final Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses could be reallocated among our unitholders. We are authorized to revise our method of allocation between transferee and transferor unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who disposes of units prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deduction attributable to the month of disposition but will not be entitled to receive a cash distribution for that period.

 

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Notification Requirements

A unitholder who sells or purchases any of its units is generally required to notify us in writing of that transaction within 30 days after the transaction (or, if earlier, January 15 of the year following the transaction in the case of a seller). Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale through a broker who will satisfy such requirements.

Constructive Termination

We will be considered to have “constructively” terminated as a partnership for federal income tax purposes upon the sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For such purposes, multiple sales of the same unit are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in such unitholder’s taxable income for the year of termination.

A constructive termination occurring on a date other than December 31 generally would require that we file two tax returns for one fiscal year and the cost of the preparation of these returns will be borne by all unitholders. However, pursuant to an IRS relief procedure the IRS may allow a constructively terminated partnership to provide a single Schedule K-1 for the calendar year in which a termination occurs. Following a constructive termination we would be required to make new tax elections, including a new election under Section 754 of the Code, and the termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination may either accelerate the application of, or subject us to, any tax legislation enacted before the termination that would not otherwise have been applied to us as a continuing as opposed to a terminating partnership.

Uniformity of Units

Because we cannot match transferors and transferees of units and for other reasons, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements. Any non-uniformity could have a negative impact on the value of the units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.”

Our partnership agreement permits our general partner to take positions in filing our tax returns that preserve the uniformity of our units. These positions may include reducing the depreciation, amortization or loss deductions to which a unitholder would otherwise be entitled or reporting a slower amortization of Section 743(b) adjustments for some unitholders than that to which they would otherwise be entitled. Vinson & Elkins L.L.P. is unable to opine as to validity of such filing positions.

A unitholder’s basis in units is reduced by its share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the unitholder’s basis in its units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Units—Recognition of Gain or Loss” above and “—Tax Consequences of Unit Ownership—Section 754 Election” above. The IRS may challenge one or more of any positions we take to preserve the uniformity of units. If such a challenge were sustained, the uniformity of units might be affected, and, under some circumstances, the gain from the sale of units might be increased without the benefit of additional deductions.

 

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Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, non-U.S. corporations and other non-U.S. persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. Prospective unitholders that are tax-exempt entities or non-U.S. persons should consult their tax advisors before investing in our units. Employee benefit plans and most other tax-exempt organizations, including IRAs and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income will be unrelated business taxable income and will be taxable to a tax-exempt unitholder.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of their ownership of our units. Consequently, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, distributions to non-U.S. unitholders are subject to withholding at the highest applicable effective tax rate. Each non-U.S. unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes.

In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain to the extent reflected in earnings and profits, and, as adjusted for changes in the foreign corporation’s “U.S. net equity.” That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Code.

A non-U.S. unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the non-U.S. unitholder. Under a ruling published by the IRS, interpreting the scope of “effectively connected income,” part or all of a non-U.S. unitholder’s gain may be treated as effectively connected with that unitholder’s indirect U.S. trade or business constituted by its investment in us. Moreover, under the Foreign Investment in Real Property Tax Act, a non-U.S. unitholder generally will be subject to federal income tax upon the sale or disposition of a unit if (i) it owned (directly or constructively applying certain attribution rules) more than 5% of our units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the units or the 5-year period ending on the date of disposition. More than 50% of our assets may consist of U.S. real property interests. Therefore, non-U.S. unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes its share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure our unitholders that those positions will yield a result that conforms to all of the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS.

The IRS may audit our federal income tax information returns. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully challenge the positions we adopt, and such a

 

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challenge could adversely affect the value of the units. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability and may result in an audit of the unitholder’s own return. Any audit of a unitholder’s return could result in adjustments unrelated to our returns.

Publicly traded partnerships generally are treated as entities separate from their owners for purposes of federal income tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings of the partners. The Code requires that one partner be designated as the “Tax Matters Partner” for these purposes, and our partnership agreement designates our general partner.

The Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review may go forward, and each unitholder with an interest in the outcome may participate in that action.

A unitholder must file a statement with the IRS identifying the treatment of any item on its federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

 

(1)

the name, address and taxpayer identification number of the beneficial owner and the nominee;

 

(2)

a statement regarding whether the beneficial owner is:

 

(a)

a non-U.S. person;

 

(b)

a non-U.S. government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

 

(c)

a tax-exempt entity;

 

(3)

the amount and description of units held, acquired or transferred for the beneficial owner; and

 

(4)

specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1.5 million per calendar year, is imposed by the Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for the underpayment of that portion and that the taxpayer acted in good faith regarding the underpayment of that portion.

 

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State, Local and Other Tax Considerations

In addition to federal income taxes, unitholders may be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangibles taxes that may be imposed by the various jurisdictions in which we conduct business or own property now or in the future or in which the unitholder is a resident. We currently conduct business or own property only in Texas. Although Texas does not impose an income tax on nonresident partners of partnerships doing business in Texas, we may also own property or do business in other states in the future that impose income or similar taxes on nonresident persons owning an interest in us. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on its investment in us.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of its investment in us. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local, alternative minimum tax or non-U.S. tax consequences of an investment in us. We strongly recommend that each prospective unitholder consult, and depend on, its own tax counsel or other advisor with regard to those matters. It is the responsibility of each unitholder to file all tax returns that may be required of it.

 

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INVESTMENT IN ALON USA PARTNERS, LP BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:

 

•

whether the investment is prudent under Section 404(a)(1)(B) of ERISA;

 

•

whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and

 

•

whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return.

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and also IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code with respect to the plan.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:

(a) the equity interests acquired by employee benefit plans are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;

(b) the entity is an “operating company,” meaning it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority-owned subsidiary or subsidiaries; or

(c) there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held by the employee benefit plans referred to above and IRAs.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) and (b) above.

Plan fiduciaries contemplating a purchase of common units are encouraged to consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

 

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UNDERWRITING

We and the underwriters named below have entered into an underwriting agreement with respect to the common units being offered. Subject to certain conditions, each underwriter has severally agreed to purchase the number of common units indicated in the following table. Goldman, Sachs & Co., Credit Suisse Securities (USA) LLC and Citigroup Global Markets Inc. are the representatives of the underwriters.

 

Underwriters		Number of Common Units
Goldman, Sachs & Co.
Credit Suisse Securities (USA) LLC
Citigroup Global Markets Inc.
Jefferies & Company, Inc.
Total

The underwriters are committed to take and pay for all of the common units being offered, if any are taken, other than the units covered by the option described below unless and until this option is exercised.

The underwriters have an option to buy up to an additional                      common units from us to cover sales by the underwriters of a greater number of units than the total number set forth in the table above. They may exercise that option for 30 days. If any common units are purchased pursuant to this option, the underwriters will severally purchase common units in approximately the same proportion as set forth in the table above.

The following table shows the per unit and total underwriting discount to be paid to the underwriters by us. Such amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units.

Paid by Us

 

		No Exercise				Full Exercise
Per Unit		$				$
Total		$				$

Common units sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus. Any units sold by the underwriters to securities dealers may be sold at a discount of up to $                 per unit from the initial public offering price. After the initial offering of the units, the representatives may change the offering price and the other selling terms. The offering of the common units by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.

We, our general partner, the executive officers and directors of our general partner and Alon USA have agreed with the underwriters, subject to certain exceptions, not to dispose of or hedge any of their common units or securities convertible into or exchangeable for common units during the period from the date of this prospectus continuing through the date 180 days after the date of this prospectus, except with the prior written consent of the representatives. This agreement does not apply to any existing employee benefit plans. See “Units Eligible for Future Sale” for a discussion of certain transfer restrictions.

 

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The 180-day restricted period described in the preceding paragraph will be automatically extended if: (1) during the last 17 days of the 180-day restricted period we issue an earnings release or announce material news or a material event; or (2) prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 15-day period following the last day of the 180-day period, in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release of the announcement of the material news or material event.

Prior to the offering, there has been no public market for our common units. The initial public offering price has been negotiated between us and the representatives. Among the factors to be considered in determining the initial public offering price of the common units, in addition to prevailing market conditions, will be our historical performance, estimates of our business potential and earnings prospects, an assessment of our management and the consideration of the above factors in relation to market valuation of companies in related businesses.

Our common units have been approved for listing on the NYSE under the symbol “ALDW,” subject to official notice of issuance. In order to meet one of the requirements for listing the common units on the NYSE, the underwriters have undertaken to sell lots of 100 or more units to a minimum of 400 beneficial holders.

In connection with the offering, the underwriters may purchase and sell common units in the open market. These transactions may include short sales, stabilizing transactions and purchases to cover positions created by short sales. Short sales involve the sale by the underwriters of a greater number of units than they are required to purchase in the offering, and a short position represents the amount of such sales that have not been covered by subsequent purchases. A “covered short position” is a short position that is not greater than the amount of additional units for which the underwriters’ option described above may be exercised. The underwriters may cover any covered short position by either exercising their option to purchase additional common units or purchasing units in the open market. In determining the source of units to cover the covered short position, the underwriters will consider, among other things, the price of units available for purchase in the open market as compared to the price at which they may purchase additional units pursuant to the option described above. “Naked” short sales are any short sales that create a short position greater than the amount of additional units for which the option described above may be exercised. The underwriters must cover any such naked short position by purchasing units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering. Stabilizing transactions consist of various bids for or purchases of common units made by the underwriters in the open market prior to the completion of the offering.

The underwriters may also impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because a representative has repurchased units sold by or for the account of such underwriter in stabilizing or short covering transactions.

Purchases to cover a short position and stabilizing transactions, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of our common units, and together with the imposition of the penalty bid, may stabilize, maintain or otherwise affect the market price of the common units. As a result, the price of the common units may be higher than the price that otherwise might exist in the open market. The underwriters are not required to engage in these activities and may end any of these activities at any time. These transactions may be effected on the NYSE, in the over-the-counter market or otherwise.

Electronic Distribution

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offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of shares for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

The underwriters do not expect sales to discretionary accounts to exceed 5% of the total number of units offered.

We estimate that our share of the total expenses of the offering, excluding the underwriting discount, will be approximately $             million.

We have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act.

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include sales and trading, commercial and investment banking, advisory, investment management, investment research, principal investment, hedging, market making, brokerage and other financial and non-financial activities and services. Certain of the underwriters and their respective affiliates have provided, and may in the future provide, a variety of these services to the issuer and to persons and entities with relationships with the issuer, for which they received or will receive customary fees and expenses. Affiliates of certain of the underwriters are expected to be lenders under our new term loan facility.

In the ordinary course of their various business activities, the underwriters and their respective affiliates, officers, directors and employees may purchase, sell or hold a broad array of investments and actively trade securities, derivatives, loans, commodities, currencies, credit default swaps and other financial instruments for their own account and for the accounts of their customers, and such investment and trading activities may involve or relate to assets, securities and/or instruments of the issuer (directly, as collateral securing other obligations or otherwise) and/or persons and entities with relationships to the issuer. The underwriters and their respective affiliates may also communicate independent research views in respect of such assets, securities or instruments and may at any time hold, or recommend to clients that they should acquire, long and/or short positions in such assets, securities and instruments.

Because the Financial Industry Regulatory Authority (“FINRA”), views our common units as interests in a direct participation program, the offering is being made in compliance with Rule 2310 of the FINRA Rules. Investor suitability with respect to the common units will be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

Notice to Prospective Investors in the EEA

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), other than Germany, with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of securities described in this prospectus may not be made to the public in that relevant member state other than:

 

•

to any legal entity which is a qualified investor as defined in the Prospectus Directive;

 

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•

to fewer than 100 or, if the relevant member state has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the relevant Dealer or Dealers nominated by the Issuer for any such offer; or

 

•

in any other circumstances falling within Article 3(2) of the Prospectus Directive;

provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For purposes of this provision, the expression an “offer of securities to the public” in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe for the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the relevant member state), and includes any relevant implementing measure in each relevant member state. The expression “2010 PD Amending Directive” means Directive 2010/73/EU.

We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.

Notice to Prospective Investors in the United Kingdom

Our partnership may constitute a “collective investment scheme” as defined by section 235 of the Financial Services and Markets Act 2000 (FSMA) that is not a “recognised collective investment scheme” for the purposes of FSMA (CIS) and that has not been authorised or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except in accordance with FSMA. This prospectus is only being distributed in the United Kingdom to, and is only directed at:

 

(1)

if our partnership is a CIS and is marketed by a person who is an authorised person under FSMA, (a) investment professionals falling within Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) (Exemptions) Order 2001, as amended (the CIS Promotion Order) or (b) high net worth companies and other persons falling within Article 22(2)(a) to (d) of the CIS Promotion Order; or

 

(2)

otherwise, if marketed by a person who is not an authorised person under FSMA, (a) persons who fall within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the Financial Promotion Order) or (b) Article 49(2)(a) to (d) of the Financial Promotion Order; and

 

(3)

in both cases (1) and (2) to any other person to whom it may otherwise lawfully be made (all such persons together being referred to as “relevant persons”).

Our partnership’s common units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such common units will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this document or any of its contents.

An invitation or inducement to engage in investment activity (within the meaning of Section 21 of FSMA) in connection with the issue or sale of any common units which are the subject of the offering contemplated by this prospectus will only be communicated or caused to be communicated in circumstances in which Section 21(1) of FSMA does not apply to our partnership.

 

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Notice to Prospective Investors in Switzerland

This prospectus is being communicated in Switzerland to a small number of selected investors only. Each copy of this prospectus is addressed to a specifically named recipient and may not be copied, reproduced, distributed or passed on to third parties. Our common units are not being offered to the public in Switzerland, and neither this prospectus, nor any other offering materials relating to our common units may be distributed in connection with any such public offering. We have not been registered with the Swiss Financial Market Supervisory Authority FINMA as a foreign collective investment scheme pursuant to Article 120 of the Collective Investment Schemes Act of June 23, 2006 (CISA). Accordingly, our common units may not be offered to the public in or from Switzerland, and neither this prospectus, nor any other offering materials relating to our common units may be made available through a public offering in or from Switzerland. Our common units may only be offered and this prospectus may only be distributed in or from Switzerland by way of private placement exclusively to qualified investors (as this term is defined in the CISA and its implementing ordinance).

Notice to Prospective Investors in Germany

This document has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act (Wertpapierprospektgesetz), the German Capital Investment Act (Vermôgensanlagengesetz), or the German Investment Act (Investmentgesetz). Neither the German Federal Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht – BaFin) nor any other German authority has been notified of the intention to distribute our common units in Germany. Consequently, our common units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner and this document and any other document relating to the offering, as well as information or statements contained therein, may not be supplied to the public in Germany or used in connection with any offer for subscription of our common units to the public in Germany or any other means of public marketing. Our common units are being offered and sold in Germany only to qualified investors which are referred to in Section 3, paragraph 2 no. 1, in connection with Section 2, no. 6, of the German Securities Prospectus Act, Section 2 no. 4 of the German Capital Investment Act, and in Section 2 paragraph 11 sentence 2 no. 1 of the German Investment Act. This document is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.

The offering does not constitute an offer to sell or the solicitation of an offer to buy our common units in any circumstances in which such offer or solicitation is unlawful.

Notice to Prospective Investors in the Netherlands

Our common units may not be offered or sold, directly or indirectly, in the Netherlands, other than to qualified investors (gekwalificeerde beleggers) within the meaning of Article 1:1 of the Dutch Financial Supervision Act (Wet op het financieel toezicht).

 

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VALIDITY OF OUR COMMON UNITS

The validity of the common units and certain other legal matters will be passed upon for us by Vinson & Elkins L.L.P., New York, New York. Certain legal matters in connection with this offering will be passed upon for the underwriters by Latham & Watkins LLP, Houston, Texas.

EXPERTS

The combined financial statements of Alon USA Partners, LP Predecessor as of December 31, 2010 and 2011, and for each of the years in the three-year period ended December 31, 2011, have been included herein in reliance upon the reports of KPMG LLP, independent public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 (including the exhibits, schedules and amendments thereto) under the Securities Act with respect to the common units being offered hereunder. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules to the registration statement. For further information with respect to us and our common units, we refer you to the registration statement and the exhibits filed as a part of the registration statement. Statements contained in this prospectus concerning the contents of any contract or any other documents are not necessarily complete. If a contract or document has been filed as an exhibit to the registration statement, we refer you to the copy of the contract or document that has been filed as an exhibit and reference thereto is qualified in all respects by the terms of the filed exhibit. The registration statement, including any exhibits and schedules, may be inspected without charge at the Public Reference Room of the SEC at 100 F Street, N.E., Washington, D.C. 20549, and copies of these materials may be obtained from that office after payment of fees prescribed by the SEC. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains a web site that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC at http://www.sec.gov.

As a result of this offering, we will become subject to the full informational requirements of the Exchange Act. We will fulfill our obligations with respect to such requirements by filing period reports and other information with the SEC.

 

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ALON USA PARTNERS, LP

INDEX TO COMBINED FINANCIAL STATEMENTS

 

		Page
ALON USA PARTNERS, LP
Unaudited Pro Forma Combined Financial Statements:
Introduction			F-2
Unaudited Pro Forma Combined Balance Sheet as of September 30, 2012			F-3
Unaudited Pro Forma Combined Statement of Operations for the Year Ended December 31, 2011			F-4
Unaudited Pro Forma Combined Statement of Operations for the Nine Months Ended September 30, 2012			F-5
Notes to Unaudited Pro Forma Combined Financial Statements			F-6
Audited Balance Sheet:
Report of Independent Registered Public Accounting Firm			F-8
Balance Sheet as of August 17, 2012			F-9
Notes to the Balance Sheet			F-10
ALON USA PARTNERS, LP PREDECESSOR
Audited Combined Financial Statements:
Report of Independent Registered Public Accounting Firm			F-11
Combined Balance Sheets as of December 31, 2010 and 2011			F-12
Combined Statements of Operations for the Years Ended December 31, 2009, 2010 and 2011			F-13
Combined Statements of Partners’ Equity as of December 31, 2009, 2010 and 2011			F-14
Combined Statements of Cash Flows for the Years Ended December 31, 2009, 2010 and 2011			F-15
Notes to Combined Financial Statements			F-16
Condensed Combined Financial Statements:
Condensed Combined Balance Sheets as of December 31, 2011 and September 30, 2012 (Unaudited)			F-30
Condensed Combined Statements of Operations for the Nine Months Ended September 30, 2011 and 2012 (Unaudited)			F-31
Condensed Combined Statements of Cash Flows for the Nine Months Ended September 30, 2011 and 2012 (Unaudited)			F-32
Notes to Condensed Combined Financial Statements (Unaudited)			F-33

 

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ALON USA PARTNERS, LP

UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

INTRODUCTION

In connection with the closing of this offering, Alon USA Energy, Inc. (“Alon Energy”) will contribute all of the outstanding equity interests in Alon USA, LP and Alon USA Refining, Inc. (collectively, “Alon USA Partners, LP”) to Alon USA Partners, LP, a newly formed Delaware limited partnership (the “Partnership”).

The unaudited pro forma combined financial statements give effect to the following transactions:

 

•

the contribution by Alon Energy of its equity interests in Alon USA, LP and Alon USA Refining, Inc. to the Partnership;

 

•

the issuance (i) to our general partner of a non-economic general partner interest in the Partnership and (ii) to Alon Energy of              common units, representing an aggregate         % limited partner interest in the Partnership (assuming the underwriters do not exercise their option to purchase additional common units);

 

•

the issuance of              common units to the public in this offering;

 

•

the assumption from Alon Energy of a fully drawn $250.0 million term loan facility as described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources”;

 

•

the payment of offering expenses of $         million and debt financing fees of $             million;

 

•

the application of the net proceeds of this offering as described in “Use of Proceeds,” including to repay approximately $         million of principal and accrued interest relating to intercompany debt payable by Alon USA Partners, LP to Alon Energy and its affiliates; and

 

•

the elimination of the $             million remaining balance of the intercompany debt prior to closing.

The pro forma adjustments have been prepared as if the transactions to be effected at the closing of this offering had taken place on September 30, 2012 in the case of the pro forma combined balance sheet and as of January 1, 2011 in the case of the pro forma combined statements of operations for the year ended December 31, 2011 and for the nine months ended September 30, 2012.

The unaudited pro forma combined financial statements have been prepared on the basis that the Partnership will be treated as a partnership for federal tax purposes.

The accompanying unaudited pro forma combined financial statements of the Partnership should be read together with the historical combined financial statements of Alon USA Partners, LP Predecessor included elsewhere in this prospectus. The accompanying unaudited pro forma combined financial statements of the Partnership were derived by making certain adjustments to the historical combined financial statements of Alon USA Partners, LP Predecessor. The pro forma adjustments are based on currently available information and certain estimates and assumptions. Therefore, the actual effects of the events may differ from the pro forma adjustments. However, management believes the assumptions utilized to prepare the pro forma adjustments provide a reasonable basis for presenting the significant effects of the formation, offering, and related events as currently contemplated and that the unaudited pro forma adjustments are factually supportable and give appropriate effect to the expected impact of events that are directly attributable to the formation of the Partnership and this offering.

The unaudited pro forma combined financial statements of the Partnership are not necessarily indicative of the results that actually would have occurred if the Partnership had completed the offering on the dates indicated or which could be achieved in the future because they do not reflect all of the operating expenses that the Partnership expects to incur in the future.

 

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ALON USA PARTNERS, LP

UNAUDITED PRO FORMA COMBINED BALANCE SHEET

As of September 30, 2012

(dollars in thousands)

 

		Historical				Pro Forma Adjustments				Pro Forma
ASSETS
Current assets:
Cash and cash equivalents		$	29,414			$	—	(a)		$	29,414
Accounts and other receivables, net			115,135				—				115,135
Accounts and other receivables, net - related parties			14,718				—				14,718
Inventories			57,348				—				57,348
Prepaid expenses and other current assets			7,139				—				7,139
Total current assets			223,754				—				223,754
Property, plant and equipment, net			485,115				—				485,115
Other assets			30,651				11,750	(b)			42,401
Total assets		$	739,520			$	11,750			$	751,270
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable		$	193,829			$	—			$	193,829
Accrued liabilities			28,221				—				28,221
Total current liabilities			222,050				—				222,050
Other non-current liabilities			41,653				—				41,653
Long-term debt			84,000				250,000	(c)			334,000
Subordinated debt - related parties			346,582				(346,582	)(d)			—
Total liabilities			694,285				(96,582	)			597,703
Commitments and contingencies
Partners’ equity:
Alon Energy
Public
Total partners’ equity			45,235				108,332	(e)			153,567
Total liabilities and partners’ equity		$	739,520			$	11,750			$	751,270

The accompanying notes are an integral part of these unaudited pro forma combined financial statements.

 

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ALON USA PARTNERS, LP

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

For the Year Ended December 31, 2011

(dollars in thousands)

 

		Historical				Pro Forma Adjustments				Pro Forma
Net sales (1)		$	3,207,969			$	—			$	3,207,969
Operating costs and expenses:
Cost of sales			2,722,918				—				2,722,918
Direct operating expenses			98,178				—				98,178
Selling, general and administrative expenses			15,633				—				15,633
Depreciation and amortization			40,448				—				40,448
Total operating costs and expenses			2,877,177				—				2,877,177
Operating income			330,792				—				330,792
Interest expense			(16,719	)			(20,708	)(f)			(37,427	)
Interest expense - related parties			(17,067	)			17,067	(g)			—
Other income (loss), net			18				—				18
Income (loss) before state income tax expense			297,024				(3,641	)			293,383
State income tax expense			2,597				—				2,597
Net income (loss)		$	294,427			$	(3,641	)		$	290,785
Common unitholders’ interest in net income		$				$				$
Net income per common unit (basic and diluted)		$				$				$
Weighted-average number of limited partners’ units outstanding:
Basic and diluted (in thousands)

 

(1)	Includes sales to related parties of $553,253 for the year ended December 31, 2011.

The accompanying notes are an integral part of these unaudited pro forma combined financial statements.

 

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ALON USA PARTNERS, LP

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

For the Nine Months Ended September 30, 2012

(dollars in thousands)

 

		Historical				Pro Forma Adjustments				Pro Forma
Net sales (1)		$	2,651,191			$	—			$	2,651,191
Operating costs and expenses:
Cost of sales (2)			2,225,702				—				2,225,702
Direct operating expenses			73,223				—				73,223
Selling, general and administrative expenses			18,070				—				18,070
Depreciation and amortization			34,963				—				34,963
Total operating costs and expenses			2,351,958				—				2,351,958
Operating income			299,233				—				299,233
Interest expense			(15,070	)			(15,531	)(f)			(30,601	)
Interest expense - related parties			(12,990	)			12,990	(g)			—
Other income (loss), net			11				—				11
Income before state income tax expense			271,184				(2,541	)			268,643
State income tax expense			2,518				—				2,518
Net income		$	268,666			$	(2,541	)		$	266,125
Common unitholders’ interest in net income		$				$				$
Net income per common unit (basic and diluted)		$				$				$
Weighted-average number of limited partners’ units outstanding:
Basic and diluted (in thousands)

 

(1)	Includes sales to related parties of $450,416 for the nine months ended September 30, 2012.

(2)	Includes costs of $13,951 associated with losses on derivatives with a related party for the nine months ended September 30, 2012.

The accompanying notes are an integral part of these unaudited pro forma combined financial statements.

 

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ALON USA PARTNERS, LP

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

(dollars in thousands)

 

1.

Organization and Basis of Presentation

The unaudited pro forma combined financial statements of Alon USA Partners, LP (the “Partnership”) have been derived from the historical combined financial statements of Alon USA Partners, LP Predecessor. The historical combined financial statements are comprised of the financial statements relating to the operating subsidiaries of Alon USA Energy, Inc. (“Alon Energy”) that will be transferred to the Partnership upon the closing of this offering. The pro forma adjustments have been prepared as if the transactions to be effected at the closing of this offering had taken place on September 30, 2012 in the case of the pro forma combined balance sheet and as of January 1, 2011 in the case of the pro forma combined statements of operations for the year ended December 31, 2011 and for the nine months ended September 30, 2012. The pro forma adjustments are based on currently available information and certain estimates and assumptions, and therefore the actual effects of these transactions will differ from the pro forma adjustments.

The unaudited pro forma combined financial statements give effect to the following transactions:

 

•

the contribution by Alon Energy of its equity interests in Alon USA, LP and Alon USA Refining, Inc. to us;

 

•

the issuance (i) to our general partner of a non-economic general partner interest in us and (ii) to Alon Energy of              common units, representing an aggregate     % limited partner interest in us (assuming the underwriters do not exercise their option to purchase additional common units);

 

•

the issuance of              common units to the public in this offering;

 

•

the assumption from Alon Energy of a fully drawn $250.0 million term loan facility as described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources”;

 

•

the payment of offering expenses of $             million and debt financing fees of $             million;

 

•

the application of the net proceeds of this offering as described in “Use of Proceeds,” including to repay approximately $             million of principal and accrued interest relating to intercompany debt payable by Alon USA Partners, LP to Alon Energy and its affiliates; and

 

•

the elimination of the $             million remaining balance of the intercompany debt prior to closing.

The pro forma adjustments included herein assume no exercise of the underwriters’ option to purchase additional common units. The proceeds from any exercise of the underwriters’ option to purchase additional common units will be paid as a special distribution to Alon Energy.

Upon completion of this offering, the Partnership anticipates incurring incremental selling, general and administrative expenses of approximately $1.5 million per year as a result of being a publicly traded limited partnership, such as expenses associated with annual and quarterly reporting requirements, tax return and Schedule K-1 preparation and distribution expenses, 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. No pro forma adjustments have been made to the historical combined financial statements to reflect the additional costs and expenses described above because they are projected amounts based on judgmental estimates and would not be factually supportable.

 

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ALON USA PARTNERS, LP

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

(dollars in thousands)

 

2.

Pro Forma Adjustments

The pro forma adjustments are based upon currently available information and certain estimates and assumptions; therefore, actual adjustments will differ from the pro forma adjustments. A general description of these pro forma adjustments follows:

(a) Reflects the changes in the cash and cash equivalents balance as of September 30, 2012 giving effect to the transactions described in Note (1) as if they occurred on September 30, 2012 as follows:

 

		As of September 30, 2012
Proceeds from the offering		$	230,000
Less:
Offering fees			(19,100	)
Repayment of subordinated debt–related parties			(210,900	)
Subtotal			(230,000	)
Net change in cash and cash equivalents		$	—

(b) Reflects the pro forma adjustment for unamortized debt issuance costs of $11,750 related to the $250,000 new term loan facility.

(c) Reflects the pro forma adjustment for $250,000 of principal outstanding under the Partnership’s new term loan facility which was assumed in connection with this offering.

(d) Reflects the repayment of $210,900 of subordinated debt–related parties with the proceeds received from the offering and the conversion of the remaining $135,682 of subordinated debt–related parties to partners’ equity.

(e) Reflects the changes in the partners’ equity balance as of September 30, 2012 giving effect to the transactions described in Note (1) as if they occurred on September 30, 2012 as follows:

 

		As of September 30, 2012
Proceeds from the offering		$	230,000
Add:
Conversion of subordinated debt–related parties			135,682
Less:
Offering fees			(19,100	)
Assumption of new term loan facility, net of debt issuance costs			(238,250	)
Subtotal			(257,350	)
Net change in partners’ equity		$	108,332

(f) Reflects the pro forma adjustment for interest expense related to the new term loan facility at an assumed rate of 7.50% per annum plus the amortization of debt issuance costs of $11,750 amortized on a straight line basis over a six year period. The amortization of debt issuance costs for the year ended December 31, 2011 would be $1,958 and for the nine months ended September 30, 2012 would be $1,469.

(g) Reflects the pro forma adjustment to eliminate the related party interest expense in connection with the repayment and conversion of the subordinated debt–related parties as described in item (d).

 

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Report of Independent Registered Public Accounting Firm

Board of Directors

Alon USA Partners GP, LLC

We have audited the accompanying balance sheet of Alon USA Partners, LP (the Partnership) as of August 17, 2012. This financial statement is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit of the balance sheet includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit of the balance sheet provides a reasonable basis for our opinion.

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of Alon USA Partners, LP at August 17, 2012, in conformity with accounting principles generally accepted in the United States of America.

/s/ KPMG LLP

Dallas, Texas

August 31, 2012

 

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ALON USA PARTNERS, LP

BALANCE SHEET

(dollars in thousands)

 

		As of August 17, 2012
Assets		$	—
Total Assets		$	—
Partners’ Equity:
Limited Partner’s Equity		$	1
Receivables from Partners			(1	)
Total Partners’ Equity		$	—

 

 

The accompanying notes are an integral part of this audited financial statement.

 

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ALON USA PARTNERS, LP

NOTES TO THE BALANCE SHEET

(dollars in thousands)

 

1.	Nature of Operations

Alon USA Partners, LP (the “Partnership”) is a Delaware limited partnership formed on August 17, 2012. The Partnership was formed to own and operate the Big Spring refinery and related assets.

Alon Assets, Inc., a controlled subsidiary of Alon USA Energy, Inc., has committed to contribute $1 to the Partnership in exchange for a 100% limited partner interest in the Partnership. These contributions receivable are reflected as a reduction to equity in accordance with generally accepted accounting principles. The accompanying financial statement reflects the financial position of the Partnership immediately subsequent to this initial capitalization. There have been no other transactions involving the Partnership as of August 17, 2012. Alon USA Partners GP, LLC will serve as the general partner of the Partnership.

 

2.	Subsequent Events

Management of the Partnership evaluated subsequent events through August 31, 2012, which is the date the balance sheet was available to be issued.

 

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ALON USA PARTNERS, LP PREDECESSOR

Report of Independent Registered Public Accounting Firm

Board of Directors

Alon USA Partners GP, LLC:

We have audited the accompanying combined balance sheets of Alon USA Partners, LP Predecessor (the Partnership) as of December 31, 2010 and 2011, and the related combined statements of operations, partners’ equity and cash flows for each of the years in the three-year period ended December 31, 2011. These combined financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these combined financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the combined financial statements referred to above present fairly, in all material respects, the financial position of Alon USA Partners, LP Predecessor as of December 31, 2010 and 2011, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Dallas, Texas

August 31, 2012

 

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ALON USA PARTNERS, LP PREDECESSOR

COMBINED BALANCE SHEETS

(dollars in thousands)

 

		As of December 31,
		2010				2011
ASSETS
Current assets:
Cash and cash equivalents		$	20,352			$	135,945
Accounts and other receivables, net			73,409				100,853
Accounts and other receivables, net - related parties			11,929				12,788
Inventories			40,220				31,738
Prepaid expenses and other current assets			2,478				6,057
Total current assets			148,388				287,381
Property, plant and equipment, net			512,169				493,970
Other assets			14,482				29,129
Total assets		$	675,039			$	810,480
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable		$	175,194			$	111,319
Accrued liabilities			32,400				27,840
Total current liabilities			207,594				139,159
Other non-current liabilities			19,255				35,040
Long-term debt			122,000				200,000
Subordinated debt - related parties			316,526				333,592
Total liabilities			665,375				707,791
Commitments and contingencies (Note 14)
Partners’ equity			9,664				102,689
Total liabilities and partners’ equity		$	675,039			$	810,480

The accompanying notes are an integral part of these audited combined financial statements.

 

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ALON USA PARTNERS, LP PREDECESSOR

COMBINED STATEMENTS OF OPERATIONS

(dollars in thousands)

 

		Year Ended December 31,
		2009				2010				2011
Net sales (1)		$	1,498,176			$	1,639,935			$	3,207,969
Operating costs and expenses:
Cost of sales			1,398,365				1,503,301				2,722,918
Direct operating expenses			89,994				90,359				98,178
Selling, general and administrative expenses			16,564				14,432				15,633
Depreciation and amortization			36,651				39,570				40,448
Total operating costs and expenses			1,541,574				1,647,662				2,877,177
Gain on disposition of assets			2,105				—				—
Operating income (loss)			(41,293	)			(7,727	)			330,792
Interest expense			(8,171	)			(13,314	)			(16,719	)
Interest expense - related parties			(17,067	)			(17,067	)			(17,067	)
Other income (loss), net			183				(269	)			18
Income (loss) before state income tax expense			(66,348	)			(38,377	)			297,024
State income tax expense			—				136				2,597
Net income (loss)		$	(66,348	)		$	(38,513	)		$	294,427

 

(1)	Includes sales to related parties of $277,014, $361,740 and $553,253 for the years ended December 31, 2009, 2010 and 2011, respectively.

The accompanying notes are an integral part of these audited combined financial statements.

 

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ALON USA PARTNERS, LP PREDECESSOR

COMBINED STATEMENTS OF PARTNERS’ EQUITY

(dollars in thousands)

 

		Partners’ Equity
Balance at January 1, 2009		$	83,561
Net cash advances from partners			79,102
Net loss			(66,348	)
Balance at December 31, 2009			96,315
Net cash payments to partners			(48,138	)
Net loss			(38,513	)
Balance at December 31, 2010			9,664
Net cash payments to partners			(201,402	)
Net income			294,427
Balance at December 31, 2011		$	102,689

The accompanying notes are an integral part of these audited combined financial statements.

 

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ALON USA PARTNERS, LP PREDECESSOR

COMBINED STATEMENTS OF CASH FLOWS

(dollars in thousands)

 

		Year Ended December 31,
		2009				2010				2011
Cash flows from operating activities:
Net income (loss)		$	(66,348	)		$	(38,513	)		$	294,427
Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities:
Depreciation and amortization			36,651				39,570				40,448
Non-cash interest on subordinated debt - related parties			17,067				17,067				17,067
Gain on disposition of assets			(2,105	)			—				—
Changes in operating assets and liabilities:
Accounts and other receivables, net			14,526				(26,764	)			(27,444	)
Accounts and other receivables, net - related parties			(4,414	)			(2,198	)			(859	)
Inventories			(10,385	)			15,255				7,317
Prepaid expenses and other current assets			754				(1,492	)			(3,579	)
Other assets			3,415				5,725				(16,151	)
Accounts payable			(15,302	)			45,398				(63,875	)
Accrued liabilities			(7,050	)			(1,510	)			(4,561	)
Other non-current liabilities			4,083				7,601				15,785
Net cash provided by (used in) operating activities			(29,108	)			60,139				258,575
Cash flows from investing activities:
Capital expenditures			(46,688	)			(15,411	)			(12,460	)
Capital expenditures for turnarounds and catalyst replacement			(9,176	)			(10,151	)			(7,085	)
Proceeds from insurance to rebuild refinery			34,125				—				—
Proceeds from disposition of assets			2,105				—				—
Net cash used in investing activities			(19,634	)			(25,562	)			(19,545	)
Cash flows from financing activities:
Revolving credit facility, net			(30,000	)			34,000				78,000
Inventory supply agreement			—				—				1,165
Net (payments to) advances from partners			79,102				(48,138	)			(201,402	)
Deferred debt issuance costs			(1,290	)			(1,200	)			(1,200	)
Net cash provided by (used in) financing activities			47,812				(15,338	)			(123,437	)
Net increase (decrease) in cash and cash equivalents			(930	)			19,239				115,593
Cash and cash equivalents, beginning of period			2,043				1,113				20,352
Cash and cash equivalents, end of period		$	1,113			$	20,352			$	135,945
Supplemental cash flow information:
Cash paid for interest		$	7,185			$	9,262			$	12,717
Cash paid for income tax		$	—			$	—			$	136

The accompanying notes are an integral part of these audited combined financial statements.

 

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ALON USA PARTNERS, LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(dollars in thousands)

 

(1)

Description and Nature of Business

Alon USA Partners, LP is an indirect subsidiary of Alon USA Energy, Inc. (“Alon Energy”). Alon USA Partners, LP was formed on August 17, 2012 by Alon Energy. The purpose of this entity will be to own the assets and operations of the Big Spring refinery and associated wholesale marketing operations. Alon Energy will contribute to Alon USA Partners, LP i) its ownership interests in Alon USA, LP, excluding its equity ownership interests in the retail subsidiaries, and ii) its ownership interests in Alon USA Refining, Inc. Thus the financial statements presented represent this combination in the entity formed for this purpose, which we refer to herein as “Alon.”

Alon is a refiner and marketer of petroleum products operating primarily in the South Central and Southwestern regions of the United States. Alon owns and operates a crude oil refinery in Big Spring, Texas with crude oil throughput capacity of 70,000 barrels per day, or bpd, which Alon refers to as the Big Spring refinery. Alon refines crude oil into petroleum products, including gasoline, diesel, jet fuel, petrochemicals, petrochemical feedstocks, asphalts and other petroleum products, which Alon markets primarily in West Texas, Central Texas, Oklahoma, New Mexico and Arizona. Alon refers to its operations in this region as its physically integrated system because it supplies its branded and unbranded distributors in this region with motor fuels produced at the Big Spring refinery. Alon distributes fuel products through a product pipeline and terminal network, which Alon owns or accesses through leases or long-term throughput agreements. Alon’s physically integrated system includes Alon-branded retail sites that Alon supplies, including Alon Energy’s owned and operated retail convenience stores. Alon operates in a single reportable segment for financial reporting purposes based on how the business is managed.

 

(2)

Summary of Significant Accounting Policies

 

(a)

Basis of Presentation

The combined financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America.

The partners’ equity balance represents Alon Energy’s initial investment in Alon and subsequent adjustments resulting from the operations of Alon and various transactions between Alon and Alon Energy.

 

(b)

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

 

(c)

Revenue Recognition

Substantially all of Alon’s revenues are derived from the sale of refined products. Revenues from sales of refined products are earned and realized upon transfer of title to the customer based on the contractual terms of delivery (including payment terms and prices). Title primarily transfers at the refinery or terminal when the refined product is loaded into the common carrier pipelines, trucks or railcars (free on board origin). In some situations, title transfers at the customer’s destination (free on board destination).

 

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ALON USA PARTNERS, LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(dollars in thousands)

 

Alon occasionally enters into refined product buy/sell arrangements, which involve linked purchases and sales related to refined product sales contracts entered into to address location, quality or grade requirements. These buy/sell transactions are included on a net basis in sales in the combined statements of operations and profits are recognized when the exchanged product is sold.

In the ordinary course of business, logistical and refinery production schedules necessitate the occasional sale of crude oil to third parties. All purchases and sales of crude oil are recorded net, in cost of sales in the combined statements of operations.

 

(d)

Cost Classifications

Cost of sales includes crude oil, blending materials, other raw materials and transportation costs. Cost of sales excludes depreciation and amortization, which is presented separately in the combined statements of operations.

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. These costs also include actual costs incurred by Alon Energy and allocated to Alon. Environmental compliance costs, including monitoring and routine maintenance, are expensed as incurred. All operating costs associated with Alon’s 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 primarily include corporate overhead costs and marketing expenses. These costs also include actual costs incurred by Alon Energy and allocated to Alon.

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

 

(e)

Cash and Cash Equivalents

All highly liquid instruments with a maturity of three months or less at the time of purchase are considered to be cash equivalents. Cash equivalents are stated at cost, which approximates market value.

 

(f)

Accounts Receivable

The majority of accounts receivable are due from companies in the petroleum industry. Credit is extended based on evaluation of the customer’s financial condition and in certain circumstances, collateral, such as letters of credit or guarantees, are required. Credit losses are charged to reserve for bad debts when accounts are deemed uncollectible. Reserve for bad debts is based on a combination of current sales and specific identification methods.

 

(g)

Inventories

Crude oil, refined products and blendstocks (including inventory consigned to others) are stated at the lower of cost or market. Cost is determined under the last-in, first-out (“LIFO”) valuation method. Cost of crude oil, refined products and blendstock inventories in excess of market value are charged to cost of sales. Such charges are subject to reversal in subsequent periods, not to exceed LIFO cost, if prices recover. Materials and supplies are stated at average cost.

 

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ALON USA PARTNERS, LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(dollars in thousands)

 

Crude oil inventory consigned to others represents inventory that was sold to third parties with an obligation by Alon to repurchase the inventory at the end of the respective agreements (Note 8). As a result of this requirement to repurchase inventory, no revenue was recorded on these transactions and the inventory volumes remain valued under the LIFO method.

 

(h)

Hedging Activity

Alon participates in Alon Energy’s company-wide risk management program. All derivative instruments are recorded in the combined balance sheets as either assets or liabilities measured at their fair value. Alon considers all commodity forwards, futures, and option contracts to be part of its risk management strategy. Alon has elected not to designate these commodity contracts as cash flow hedges for financial accounting purposes. Accordingly, net unrealized gains and losses for changes in the fair value on open commodity derivative contracts are recognized in cost of sales in the combined statements of operations.

 

(i)

Property, Plant and Equipment

The carrying value of property, plant and equipment includes the fair value of the asset retirement obligation and has been reflected in the balance sheets at cost, net of accumulated depreciation.

Property, plant, and equipment, net of salvage value, are depreciated using the straight-line method at rates based on the estimated useful lives for the assets or groups of assets, beginning in the first month of operation following acquisition or completion. Alon capitalizes interest costs associated with major construction projects based on the effective interest rate on aggregate borrowings.

Expenditures for major replacements and additions are capitalized. Expenditures for routine repairs and maintenance costs are charged to direct operating expense as incurred. The applicable costs and accumulated depreciation of assets that are sold, retired, or otherwise disposed of are removed from the accounts and the resulting gain or loss is recognized.

 

(j)

Impairment of Long-Lived Assets and Assets To Be Disposed Of

Long-lived assets and certain identifiable intangible assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of an asset to future net cash flows expected to be generated by the asset. If the carrying value of an asset exceeds its expected future cash flows, an impairment loss is recognized based on the excess of the carrying value of the impaired asset over its fair value. These future cash flows and fair values are estimates based on management’s judgment and assumptions. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs of disposition.

 

(k)

Asset Retirement Obligations

The accounting standards established for asset retirement obligations apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation of a long-lived asset and requires companies to recognize a liability for the fair value of a legal obligation to perform asset retirement activities that are conditional on a future event, if the amount can be reasonably estimated.

 

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ALON USA PARTNERS, LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(dollars in thousands)

 

(l)

Turnarounds and Catalyst Replacement Costs

Alon records the cost of planned major refinery maintenance, referred to as turnarounds, and chemical catalyst used in the refinery process units, which are typically replaced in conjunction with planned turnarounds, in “Other assets” in the balance sheets. 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. The amortization of deferred turnaround and catalyst replacement costs are presented in “Depreciation and amortization” in the combined statements of operations.

 

(m)

Income Taxes

Alon is a partnership for U.S. federal income tax purposes and thus its income is taxed directly to its owners. As a result, Alon does not incur U.S. federal income taxes.

Alon is subject to Texas franchise tax and its operations are included in the consolidated Texas franchise tax return of Alon Energy. For financial reporting purposes, Texas franchise tax is calculated as if a separate return was filed.

 

(n)

Environmental Expenditures

Alon accrues for costs associated with environmental remediation obligations when such costs are probable and can be reasonably estimated. Environmental liabilities represent the estimated costs to investigate and remediate contamination at Alon’s properties. This estimate is based on internal and third-party assessments of the extent of the contaminations, the selected remediation technology and review of applicable environmental regulations.

Accruals for estimated costs from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are adjusted as further information develops or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value unless payments are fixed and determinable. Recoveries of environmental remediation costs from other parties are recorded as assets when the receipt is deemed probable. Estimates are updated to reflect changes in factual information, available technology or applicable laws and regulations.

 

(o)

Commitments and Contingencies

Liabilities for loss contingencies arising from claims, assessments, litigation, fines, and penalties and other sources are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred.

 

(3)

Fair Value of Financial Instruments

The carrying amounts of Alon’s cash and cash equivalents, receivables, payables and accrued liabilities approximate fair value due to the short-term maturities of these assets and liabilities. The reported amounts of long-term debt approximate fair value. Derivative financial instruments are carried at fair value, which is based on quoted market prices.

Alon must determine fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. As required, Alon utilizes valuation techniques that maximize the use of observable inputs (levels 1 and 2) and minimize the use of

 

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ALON USA PARTNERS, LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(dollars in thousands)

 

unobservable inputs (level 3) within the fair value hierarchy. Alon generally applies the “market approach” to determine fair value. This method uses pricing and other information generated by market transactions for identical or comparable assets and liabilities. Assets and liabilities are classified within the fair value hierarchy based on the lowest level (least observable) input that is significant to the measurement in its entirety.

The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, in the combined balance sheets as of December 31, 2010 and 2011:

 

		Quoted Prices in Active Markets For Identical Assets or Liabilities (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total
As of December 31, 2010
Assets:
Commodity contracts (futures and forwards)		$	380			$	—			$	—			$	380
As of December 31, 2011
Assets:
Commodity contracts (futures and forwards)		$	447			$	—			$	—			$	447

 

(4)

Derivative Financial Instruments

Commodity Derivatives — Mark to Market

Alon selectively utilizes commodity derivatives to manage its exposure to commodity price fluctuations and uses crude oil and refined product commodity derivative contracts to reduce risk associated with potential price changes on committed obligations. Alon does not speculate using derivative instruments. Credit risk on Alon’s derivative instruments is mitigated by transacting with counterparties meeting established collateral and credit criteria.

The following table presents the effect of derivative instruments on the combined statements of financial position.

 

		As of December 31, 2010
		Asset Derivatives						Liability Derivatives
		Balance Sheet Location		Fair Value				Balance Sheet Location		Fair Value
Derivatives not designated as hedging instruments:
Commodity contracts (futures and forwards)		Accounts receivable		$	438			Accrued liabilities		$	(58	)
Total derivatives				$	438					$	(58	)

 

 

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ALON USA PARTNERS, LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(dollars in thousands)

 

		As of December 31, 2011
		Asset Derivatives						Liability Derivatives
		Balance Sheet Location		Fair Value				Balance Sheet Location		Fair Value
Derivatives not designated as hedging instruments:
Commodity contracts (futures and forwards)		Accounts receivable		$	465			Accrued liabilities		$	(18	)
Total derivatives				$	465					$	(18	)

The following table presents the effect of derivative instruments on Alon’s combined statements of operations.

Derivatives not designated as hedging instruments:

 

		Gain (Loss) Recognized in Income
		Location				Amount
For the Year Ended December 31, 2009
Commodity contracts (futures & forwards)			Cost of sales			$	(4,944	)
Total derivatives						$	(4,944	)
For the Year Ended December 31, 2010
Commodity contracts (futures & forwards)			Cost of sales			$	1,071
Total derivatives						$	1,071
For the Year Ended December 31, 2011
Commodity contracts (futures & forwards)			Cost of sales			$	(1,486	)
Total derivatives						$	(1,486	)

 

(5)

Significant Customers

For the year ended December 31, 2009, Alon had a related party customer account for 14% of net sales, which include net sales to related parties.

For the year ended December 31, 2010, Alon had two customers which account for approximately 32% of net sales, which include net sales to related parties. A third party customer accounted for 13% of net sales and a related party customer accounted for 19% of net sales for the year ended December 31, 2010.

For the year ended December 31, 2011, Alon had three customers which account for approximately 41% of net sales, which include net sales to related parties. Individually, these third party customers accounted for 15% and 12% of net sales and a related party customer accounted for 14% of net sales for the year ended December 31, 2011.

At December 31, 2010 and 2011, 23% and 19%, respectively, of total third party and related party accounts and other receivables, net were from significant customers discussed above.

 

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ALON USA PARTNERS, LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(dollars in thousands)

 

(6)

Accounts and Other Receivables, Net

Financial instruments that potentially subject Alon to concentration of credit risk consist primarily of trade accounts receivables. Credit risk is minimized as a result of the ongoing credit assessment of Alon’s customer base and a lack of concentration in Alon’s customer base. Alon performs ongoing credit evaluations of its customers and requires letters of credit, prepayments or other collateral or guarantees as management deems appropriate. Alon’s allowance for doubtful accounts is reflected as a reduction of accounts receivable in the combined balance sheets.

SEMGroup, LP Bankruptcy. On July 22, 2008, SemMaterials, a customer of Alon filed a petition under Chapter 11 of the United States Bankruptcy Code. On that date, SemMaterials owed approximately $39,000 to Alon under outstanding invoices for sales of asphalt products, vacuum gas oil and vacuum tower bottoms. Alon also owed approximately $1,000 to SemMaterials at that time for purchases of asphalt products. On September 17, 2008, Alon and SemMaterials entered into a settlement agreement providing Alon with an administrative claim of approximately $16,700 less 63,425 barrels of vacuum gas oil to be delivered to Alon and a right of set-off related to the approximately $1,000 payable to SemMaterials. Alon received the payment and vacuum gas oil barrels in 2008. Alon provided for this loss in 2008 through its allowance for doubtful accounts and wrote the SemMaterials receivable off in 2011 when the bankruptcy process was complete.

The following table sets forth the allowance for doubtful accounts for the years ended:

 

		Balance at Beginning of Period				Additions Charged to Expense				Deductions				Balance at End of Period
2009		$	20,249				1,328				—			$	21,577
2010		$	21,577				489				—			$	22,066
2011		$	22,066				—				(21,789	)		$	277

 

(7)

Inventories

Alon’s inventories (including inventory consigned to others) are stated at the lower of cost or market. Cost is determined under the LIFO method for crude oil (including inventory consigned to others), refined products and blendstock inventories. Materials and supplies are stated at average cost.

Carrying value of inventories consisted of the following:

 

		As of December 31,
		2010				2011
Crude oil, refined products and blendstocks		$	28,877			$	8,674
Crude oil inventory consigned to others (Note 8)			2,799				14,000
Materials and supplies			8,544				9,064
Total inventories		$	40,220			$	31,738

Crude oil, refined products and blendstock inventories totaled 943 thousand barrels and 443 thousand barrels as of December 31, 2010 and 2011, respectively. A reduction of inventory volumes during 2010 and 2011 resulted in a liquidation of LIFO inventory layers carried at lower costs which prevailed in previous years. The liquidation decreased costs of sales by approximately $24,210 and $42,702 during 2010 and 2011, respectively.

 

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ALON USA PARTNERS, LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(dollars in thousands)

 

Market values of crude oil, refined products and blendstock inventories exceeded LIFO costs by $60,787 and $21,889 at December 31, 2010 and 2011, respectively.

Alon had 106 thousand barrels and 270 thousand barrels of crude oil consigned to others at December 31, 2010 and 2011, respectively. Alon recorded liabilities associated with this consigned inventory of $9,310 and $25,550 in other non-current liabilities at December 31, 2010 and 2011, respectively.

Additionally, Alon recorded accrued liabilities of $18 and accounts receivable of $731 at December 31, 2011, for forward commitments related to month-end consignment inventory target levels differing from projected levels and the associated pricing with these inventory level differences.

Effective January 1, 2011, Alon elected to account for all inventory financing agreements it has under the “Normal Purchase Normal Sales” exemption of Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 815, Derivatives and Hedging. This exemption applies to situations where commodities are physically delivered. In previous periods Alon recorded changes in the fair value of the estimated settlement liability of these contracts through the statement of operations. Beginning January 1, 2011 and forward, changes in fair value of the estimated settlement liability will no longer be recorded due to the Normal Purchase Normal Sale exemption. If the contracts were settled December 31, 2011, the payment would be in excess of the liabilities recorded by $1,031.

 

(8)

Inventory Financing Agreements

In October 2010, Alon entered into a lease agreement, with a third party, relating to crude oil storage tanks located at the Big Spring refinery. The crude oil inventory consigned at December 2010 represents crude oil owned by the third party and stored at the Big Spring refinery. The lease agreement was terminated in February 2011 and Alon recorded a termination fee expense of $3,189. At December 31, 2010 Alon had long-term payables of $9,310 related to consigned crude oil inventory.

In February 2011, Alon entered into a Supply and Offtake Agreement, (the “Supply and Offtake Agreement”), with J. Aron & Company (“J. Aron”). Pursuant to the Supply and Offtake Agreement, (i) J. Aron agreed to sell to Alon, and Alon agreed to buy from J. Aron, at market prices, crude oil for processing at the Big Spring refinery and (ii) Alon agreed to sell, and J. Aron agreed to buy, at market prices, certain refined products produced at the Big Spring refinery.

In connection with the execution of the Supply and Offtake Agreement, Alon also entered into agreements that provided for the sale, at market prices, of Alon’s crude oil and certain refined product inventories to J. Aron, the lease to J. Aron of crude oil and refined product storage tanks located at the Big Spring refinery, and an agreement to identify prospective purchasers of refined products on J. Aron’s behalf. The Supply and Offtake Agreement has an initial term that expires in May 2016. J. Aron may elect to terminate the agreement prior to the initial term beginning in May 2013, provided Alon receives notice of termination at least six months prior to that date. Following expiration or termination of the Supply and Offtake Agreement, Alon is obligated to purchase the crude oil and refined product inventories then owned by J. Aron and located at the Big Spring refinery. At December 31, 2011 Alon had current payables to J. Aron for purchases of $2,335, long-term payables related to the original financing of $25,550 and a consignment inventory receivable representing a deposit paid to J. Aron of $6,290 recorded in other assets.

 

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ALON USA PARTNERS, LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(dollars in thousands)

 

In July 2012, the Supply and Offtake Agreement was amended principally in order to extend the terms of the Supply and Offtake Agreement by an additional two years. After the amendment, the Supply and Offtake Agreement has an initial term that expires in May 2018. J. Aron may elect to terminate the agreement prior to the initial term in May 2015 and upon each anniversary thereof provided Alon receives notice of termination at least six months prior to that date. Alon may elect to terminate in May 2017, provided Alon provides notice of termination at least six months prior to that date.

 

(9)

Property, Plant and Equipment, Net

Property, plant and equipment, net consisted of the following:

 

		As of December 31,
		2010				2011
Property, plant and equipment, gross		$	617,664			$	630,598
Less accumulated depreciation			(105,495	)			(136,628	)
Property, plant and equipment, net		$	512,169			$	493,970

The useful lives on depreciable assets used to determine depreciation expense were 3 to 20 years, with an average life of 18 years.

 

(10)

Other Assets

Other assets consisted of the following:

 

		As of December 31,
		2010				2011
Deferred turnaround and chemical catalyst cost		$	9,558			$	12,231
Deferred debt issuance costs			1,698				1,448
Consignment inventory receivable			—				6,290
Other			3,226				9,160
Total other assets		$	14,482			$	29,129

Debt issuance costs are amortized over the term of the related debt using the effective interest method. Amortization of debt issuance costs was $612 and $1,450 for the years ended December 31, 2010 and 2011, respectively, and is recorded as interest expense in the combined statements of operations.

 

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ALON USA PARTNERS, LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(dollars in thousands)

 

(11)

Accrued Liabilities and Other Non-Current Liabilities

Accrued liabilities and other non-current liabilities consisted of the following:

 

		As of December 31,
		2010				2011
Accrued liabilities:
Taxes other than income taxes, primarily excise taxes		$	20,167			$	21,658
Accrued finance charges			4,049				1,493
Environmental accrual			933				1,066
Other			7,251				3,623
Total accrued liabilities		$	32,400			$	27,840
Other non-current liabilities:
Consignment inventory		$	9,310			$	25,550
Environmental accrual			5,431				4,901
Asset retirement obligations			1,714				1,789
Other			2,800				2,800
Total other non-current liabilities		$	19,255			$	35,040

Alon has asset retirement obligations with respect to its refinery due to various legal obligations to clean and/or dispose of these assets at the time they are retired. However, the majority of these assets can be used for extended and indeterminate periods of time provided that they are properly maintained and/or upgraded. It is Alon’s practice and intent to continue to maintain these assets and make improvements based on technological advances. When a date or range of dates can reasonably be estimated for the retirement of these assets or any component part of these assets, Alon will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using established present value techniques.

 

(12)

Revolving Credit Facility

Alon has a $240,000 revolving credit facility (the “Revolving Credit Facility”) that will mature in March 2016, as amended March 2012. The Revolving Credit Facility can be used both for borrowings and the issuance of letters of credit subject to a limit of the lesser of the facility or the amount of the borrowing base under the facility.

Borrowings under the Revolving Credit Facility bear interest at the Eurodollar rate plus 3.50% per annum subject to an overall minimum interest rate of 4.00%.

The Revolving Credit Facility is secured by (i) a first lien on Alon’s cash, accounts receivables, inventories and related assets and (ii) a second lien on Alon’s fixed assets.

The Revolving Credit Facility contains certain restrictive covenants including maintenance financial covenants. At December 31, 2011, Alon was in compliance with these covenants.

Borrowings of $122,000 and $200,000 were outstanding under the Revolving Credit Facility at December 31, 2010 and 2011, respectively. At December 31, 2010 and 2011, outstanding letters of credit under the Revolving Credit Facility were $116,956 and $35,509, respectively.

 

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ALON USA PARTNERS, LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(dollars in thousands)

 

Alon is a secured guarantor under a $450,000 term loan of Alon Energy. The term loan of Alon Energy is secured by (i) a first lien on Alon’s fixed assets and (ii) a second lien on Alon’s cash, accounts receivables, inventories and related assets.

 

		Year Ended December 31,
		2009				2010				2011
Interest expense on third party debt		$	2,209			$	5,447			$	5,889
Letters of credit and finance charges			6,280				7,437				10,093
Amortization of debt issuance costs			180				612				1,450
Capitalized interest			(498	)			(182	)			(713	)
Total interest expense		$	8,171			$	13,314			$	16,719

 

(13)

Income Taxes

Alon is a partnership for U.S. federal income tax purposes and thus its income is taxed directly to its owners. As a result, Alon does not incur U.S. federal income taxes.

Alon Energy’s tax basis is less than Alon’s reported assets and liabilities by approximately $417,000 and $412,000 at December 31, 2010 and 2011, respectively.

 

(14)

Commitments and Contingencies

 

(a)

Leases

Alon has long-term lease commitments for land, office facilities and related equipment and various equipment and facilities used in the storage and transportation of refined products. In most cases, Alon expects that in the normal course of business, Alon’s leases will be renewed or replaced by other leases. Alon has commitments under long-term operating leases for certain buildings, land, equipment, and pipelines expiring at various dates over the next fifteen years. Certain long-term operating leases relating to buildings, land and pipelines include options to renew for additional periods. At December 31, 2011, minimum lease payments on operating leases were as follows:

 

Year ending December 31:
2012		$	12,278
2013			8,865
2014			7,587
2015			7,238
2016			7,047
2017 and thereafter			11,538
Total		$	54,553

Total rental expense was $14,146, $13,308 and $12,190 for the years ended December 31, 2009, 2010 and 2011, respectively. Contingent rentals and subleases were not significant.

 

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ALON USA PARTNERS, LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(dollars in thousands)

 

(b)

Commitments

In the normal course of business, Alon has long-term commitments to purchase, at market prices, utilities such as natural gas, electricity and water for use by the refinery, terminals and pipelines. Alon is also party to various refined product and crude oil supply and exchange agreements. These agreements are typically short-term in nature or provide terms for cancellation.

Alon has a pipelines and terminals agreement with Holly Energy Partners, L.P. (“HEP”) through February 2020 with three additional five year renewal terms exercisable at Alon’s sole option. Pursuant to the pipelines and terminals agreement, Alon has committed to transport and store minimum volumes of refined products in these pipelines and terminals. The tariff rates applicable to the transportation of refined products on the pipelines are variable, with a base fee which is reduced for volumes exceeding defined volumetric targets. The agreement provides for the reduction of the minimum volume requirement under certain circumstances. The service fees for the storage of refined products in the terminals are initially set at rates competitive in the marketplace.

Alon has a throughput and deficiency agreement with Sunoco Pipeline, LP, through February 2016 with an option to extend the agreement by four additional thirty-month periods. The throughput and deficiency agreement gives Alon transportation rights to ship a minimum of 15,000 bpd of crude oil on the Amdel and White Oil pipelines from the Gulf Coast and from Midland, Texas to the Big Spring refinery. In October 2011, the throughput and deficiency agreement was replaced with a new throughput and deficiency agreement (the “New Agreement”). The New Agreement gives Alon the option to transport crude oil through the Amdel Pipeline (1) either westbound from the Nederland Terminal to the Big Spring refinery, or (2) eastbound from the Big Spring refinery to the Nederland Terminal for further barge transportation to Alon Energy’s Krotz Springs, Louisiana refinery. The minimum throughput commitment by Alon is 15,645 bpd. The agreement is for 5 years from the operational date as defined in the New Agreement with an option to extend the New Agreement by four additional thirty-month periods.

Alon has an arrangement with Centurion through June 2021. This arrangement gives Alon transportation pipeline capacity to ship a minimum of 21,500 bpd of crude oil from Midland to the Big Spring refinery using Centurion’s approximately forty-mile long pipeline system from Midland to Roberts Junction and Alon’s three-mile pipeline from Roberts Junction to the Big Spring refinery which Alon leases to Centurion. The arrangement was amended April 1, 2012 to increase the minimum to 25,000 bpd.

 

(c)

Contingencies

Alon is involved in various other claims and legal actions arising in the ordinary course of business. In August 2011, Alon received from the Federal Trade Commission a civil investigative demand to provide documents as part of an industry-wide investigation related to petroleum industry practices and pricing. Alon believes the ultimate disposition of this and all other matters will not have a material effect on Alon’s financial position, results of operations or liquidity.

 

(d)

Environmental

Alon is subject to loss contingencies pursuant to federal, state, and local environmental laws and regulations. These rules regulate the discharge of materials into the environment and may require Alon to incur future obligations to investigate the effects of the release or disposal of certain petroleum, chemical, and mineral substances at various sites; to remediate or restore these sites; to compensate others for damage to property and

 

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ALON USA PARTNERS, LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(dollars in thousands)

 

natural resources and for remediation and restoration costs. These possible obligations relate to sites owned by Alon and are associated with past or present operations. Alon is currently participating in environmental investigations, assessments and cleanups under these regulations at pipelines and terminals. Alon may in the future be involved in additional environmental investigations, assessments and cleanups. The magnitude of future costs will depend on factors such as the unknown nature and contamination at many sites, the unknown timing, extent and method of the remedial actions which may be required, and the determination of Alon’s liability in proportion to other responsible parties.

Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Substantially all amounts accrued are expected to be paid out over the next fifteen years. The level of future expenditures for environmental remediation obligations is impossible to determine with any degree of reliability.

Alon has an environmental agreement with HEP pursuant to which Alon agreed to indemnify HEP against costs and liabilities incurred by HEP to the extent resulting from the existence of environmental conditions at the pipelines or terminals prior to February 28, 2005 or from violations of environmental laws with respect to the pipelines and terminals occurring prior to February 28, 2005. Alon’s environmental indemnification obligations under the environmental agreement expire after February 28, 2015. In addition, Alon’s indemnity obligations are subject to HEP first incurring $100 of damages as a result of pre-existing environmental conditions or violations. Alon’s environmental indemnity obligations are further limited to an aggregate indemnification amount of $20,000, including any amounts paid by Alon to HEP with respect to indemnification for breaches of Alon’s representations and warranties under a contribution agreement. With respect to any remediation required for environmental conditions existing prior to February 28, 2005, Alon has the option under the environmental agreement to perform such remediation itself in lieu of indemnifying HEP for their costs of performing such remediation. Pursuant to this option, Alon is continuing to perform the ongoing remediation at the Wichita Falls terminal. Any remediation required under the terms of the environmental agreement is limited to the standards under the applicable environmental laws as in effect at February 28, 2005.

Alon has an environmental agreement with Sunoco pursuant to which Alon agreed to indemnify Sunoco against costs and liabilities incurred by Sunoco to the extent resulting from the existence of environmental conditions at the pipelines prior to March 1, 2006 or from violations of environmental laws with respect to the pipelines occurring prior to March 1, 2006. With respect to any remediation required for environmental conditions existing prior to March 1, 2006, Alon has the option to perform such remediation itself in lieu of indemnifying Sunoco for their costs of performing such remediation.

Alon has accrued environmental remediation obligations of $6,364 ($933 current liability and $5,431 non-current liability at December 31, 2010 and $5,967 ($1,066 current liability and $4,901 non-current liability) at December 31, 2011.

 

(15)

Related Party Transactions

Sales and Receivables

Sales to related parties include motor fuels and asphalt sold to other Alon Energy operations at prices substantially determined by market commodity pricing information. These sales are included in net sales in the combined statements of operations. Accounts receivable from related parties include sales of motor fuels and are shown separately on the combined balance sheets.

 

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ALON USA PARTNERS, LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(dollars in thousands)

 

Costs Allocated from Alon Energy

 

(a)

Corporate Overhead Allocations

Alon is a subsidiary of Alon Energy and is operated as a component of the integrated operations of Alon Energy and its other subsidiaries. As such, the executive officers of Alon Energy, who are employed by another subsidiary of Alon Energy, also serve as executive officers of Alon and Alon Energy’s other subsidiaries and Alon Energy performs general corporate and administrative services and functions for Alon and Alon Energy’s other subsidiaries, which include accounting, treasury, cash management, tax, information technology, insurance administration and claims processing, legal, environmental, risk management, audit, payroll and employee benefit processing, and internal audit services. Alon Energy allocates the expenses actually incurred by it in performing these services to Alon and to its other subsidiaries based primarily on the estimated amount of time the individuals performing such services devote to Alon’s business and affairs relative to the amount of time they devote to the business and affairs of Alon Energy’s other subsidiaries. The management of Alon Energy considers these allocations to be reasonable. Alon records the amount of such allocations to its combined financial statements as selling, general and administrative expenses. For the years ended December 31, 2009, 2010 and 2011, Alon recorded selling, general and administrative expenses of $9,505, $9,045 and $10,336, respectively, with respect to allocations from Alon Energy substantially associated with Alon Energy employee costs.

 

(b)

Labor Costs

Alon has no employees, and as a result, actual employee expense costs for Alon Energy employees working in Alon’s operations have been allocated and recorded as payroll expense and included in direct operating expenses and selling, general and administrative expenses within the combined statements of operations. Alon’s share of Alon Energy’s employee costs included in direct operating expenses was $19,654, $20,400 and $21,598 for the years ended December 31, 2009, 2010 and 2011, respectively.

 

(c)

Insurance Costs

Insurance costs related to the Big Spring refinery and wholesale marketing operations are allocated from Alon Energy based on estimated insurance premiums on a stand alone basis relative to the total insurance premium. Insurance costs included in direct operating expenses were $11,328, $5,980 and $8,476 for the years ended December 31, 2009, 2010 and 2011, respectively. Insurance costs included in selling, general and administrative expenses were $173, $0 and $0 for the years ended December 31, 2009, 2010 and 2011, respectively.

Subordinated Debt

Alon has subordinated debt notes payable to Alon Energy and certain of its subsidiaries. These notes mature on January 1, 2018. The notes have no prepayment penalty or any covenant requirements. The interest rates charged on these notes range from 6% to 10%. Interest expense pertaining to these notes is shown separately on the combined statements of operations.

(16) Subsequent Event

Alon has evaluated subsequent events through August 31, 2012, which was the date the combined financial statements were issued.

 

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ALON USA PARTNERS, LP PREDECESSOR

CONDENSED COMBINED BALANCE SHEETS

(dollars in thousands)

 

		December 31, 2011				September 30, 2012
						(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	135,945			$	29,414
Accounts and other receivables, net			100,853				115,135
Accounts and other receivables, net - related parties			12,788				14,718
Inventories			31,738				57,348
Prepaid expenses and other current assets			6,057				7,139
Total current assets			287,381				223,754
Property, plant and equipment, net			493,970				485,115
Other assets			29,129				30,651
Total assets		$	810,480			$	739,520
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable		$	111,319			$	193,829
Accrued liabilities			27,840				28,221
Total current liabilities			139,159				222,050
Other non-current liabilities			35,040				41,653
Long-term debt			200,000				84,000
Subordinated debt - related parties			333,592				346,582
Total liabilities			707,791				694,285
Commitments and contingencies (Note 10)
Partners’ equity			102,689				45,235
Total liabilities and partners’ equity		$	810,480			$	739,520

The accompanying notes are an integral part of these condensed combined interim financial statements.

 

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ALON USA PARTNERS, LP PREDECESSOR

CONDENSED COMBINED STATEMENTS OF OPERATIONS

(unaudited, dollars in thousands)

 

		Nine Months Ended September 30,
		2011				2012
Net sales (1)		$	2,351,481			$	2,651,191
Operating costs and expenses:
Cost of sales (2)			1,959,728				2,225,702
Direct operating expenses			73,144				73,223
Selling, general and administrative expenses			12,213				18,070
Depreciation and amortization			30,206				34,963
Total operating costs and expenses			2,075,291				2,351,958
Gain on disposition of assets			10				—
Operating income			276,200				299,233
Interest expense			(12,305	)			(15,070	)
Interest expense - related parties			(12,800	)			(12,990	)
Other income, net			—				11
Income before state income tax expense			251,095				271,184
State income tax expense			2,153				2,518
Net income		$	248,942			$	268,666

 

(1)	Includes sales to related parties of $416,492 and $450,416 for the nine months ended September 30, 2011 and 2012, respectively.

 

(2)	Includes costs of $13,951 associated with losses on derivatives with a related party for the nine months ended September 30, 2012.

The accompanying notes are an integral part of these condensed combined interim financial statements.

 

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ALON USA PARTNERS, LP PREDECESSOR

CONDENSED COMBINED STATEMENTS OF CASH FLOWS

(unaudited, dollars in thousands)

 

		Nine Months Ended September 30,
		2011				2012
Cash flows from operating activities:
Net income		$	248,942			$	268,666
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization			30,206				34,963
Non-cash interest on subordinated debt - related parties			12,800				12,990
Gain on disposition of assets			(10	)			—
Changes in operating assets and liabilities:
Accounts and other receivables, net			(33,763	)			(14,282	)
Accounts and other receivables, net - related parties			(2,098	)			(1,930	)
Inventories			(15,373	)			(25,610	)
Prepaid expenses and other current assets			(487	)			(1,082	)
Other assets			(10,494	)			397
Accounts payable			(82,767	)			82,510
Accrued liabilities			(3,630	)			381
Other non-current liabilities			22,261				6,613
Net cash provided by operating activities			165,587				363,616
Cash flows from investing activities:
Capital expenditures			(11,090	)			(17,328	)
Capital expenditures for turnarounds and catalysts			(6,916	)			(8,127	)
Proceeds from disposition of assets			10				—
Net cash used in investing activities			(17,996	)			(25,455	)
Cash flows from financing activities:
Revolving credit facility, net			75,000				(116,000	)
Inventory supply agreement			1,165				—
Net payments to partners			(98,162	)			(326,120	)
Deferred debt issuance costs			(1,200	)			(2,572	)
Net cash used in financing activities			(23,197	)			(444,692	)
Net increase (decrease) in cash and cash equivalents			124,394				(106,531	)
Cash and cash equivalents, beginning of period			20,352				135,945
Cash and cash equivalents, end of period		$	144,746			$	29,414
Supplemental cash flow information:
Cash paid for interest		$	10,707			$	14,516
Cash paid for income tax		$	136			$	2,597

The accompanying notes are an integral part of these condensed combined interim financial statements.

 

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ALON USA PARTNERS, LP PREDECESSOR

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(unaudited, dollars in thousands)

 

(1)

Basis of Presentation

These unaudited combined financial statements have been prepared in accordance with United States generally accepted accounting principles (“GAAP”) for interim financial information. Accordingly, they do not include all of the information and notes required by GAAP for complete financial statements. In the opinion of management, the information included in these condensed combined financial statements reflects all adjustments, consisting of normal and recurring adjustments, which are necessary for a fair presentation of the financial position and results of operations for the interim periods presented. The results of operations for the interim periods are not necessarily indicative of the operating results that may be obtained for the year ending December 31, 2012.

The balance sheet as of December 31, 2011, has been derived from the audited combined financial statements as of that date. These unaudited combined financial statements should be read in conjunction with the audited combined financial statements and notes thereto included in this prospectus for the year ended December 31, 2011.

 

(2)

Fair Value of Financial Instruments

The carrying amounts of Alon’s cash and cash equivalents, receivables, payables and accrued liabilities approximate fair value due to the short-term maturities of these assets and liabilities. The reported amounts of long-term debt approximate fair value. Derivative financial instruments are carried at fair value, which is based on quoted market prices.

Alon must determine fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. As required, Alon utilizes valuation techniques that maximize the use of observable inputs (levels 1 and 2) and minimize the use of unobservable inputs (level 3) within the fair value hierarchy. Alon generally applies the “market approach” to determine fair value. This method uses pricing and other information generated by market transactions for identical or comparable assets and liabilities. Assets and liabilities are classified within the fair value hierarchy based on the lowest level (least observable) input that is significant to the measurement in its entirety.

The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, in the combined balance sheets as of December 31, 2011 and September 30, 2012:

 

		Quoted Prices in Active Markets For Identical Assets or Liabilities (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total
As of December 31, 2011
Assets:
Commodity contracts (futures and forwards)		$	447			$	—			$	—			$	447
As of September 30, 2012
Assets:
Commodity contracts (futures and forwards)		$	4,751			$	—			$	—			$	4,751
Liabilities:
Commodity contracts (forwards)			—				591				—				591

 

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ALON USA PARTNERS, LP PREDECESSOR

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(unaudited, dollars in thousands)

 

(3)

Derivative Financial Instruments

Commodity Derivatives — Mark to Market

Alon selectively utilizes commodity derivatives to manage its exposure to commodity price fluctuations and uses crude oil and refined product commodity derivative contracts to reduce risk associated with potential price changes on committed obligations. Alon does not speculate using derivative instruments. Credit risk on Alon’s derivative instruments is mitigated by transacting with counterparties meeting established collateral and credit criteria.

Fair Value Hedges

Fair value hedges are used to hedge price volatility in certain refining inventories and firm commitments to purchase inventories. The level of activity for our fair value hedges is based on the level of our operating inventories. The gain or loss on a derivative instrument designated and qualifying as a fair value hedge, as well as the offsetting loss or gain on the hedged item attributable to the hedged risk, is recognized currently in income in the same period.

As of September 30, 2012, Alon has accounted for certain commodity contracts as fair value hedges with contract purchase volumes of 332,607 barrels of crude oil with remaining contract terms through May 2018.

The following table presents the effect of derivative instruments on the combined statements of financial position.

 

		As of December 31, 2011
		Asset Derivatives						Liability Derivatives
		Balance Sheet Location		Fair Value				Balance Sheet Location		Fair Value
Derivatives not designated as hedging instruments:
Commodity contracts (futures and forwards)		Accounts receivable		$	465			Accrued liabilities		$	(18	)
Total derivatives				$	465					$	(18	)

 

		As of September 30, 2012
		Asset Derivatives						Liability Derivatives
		Balance Sheet Location		Fair Value				Balance Sheet Location		Fair Value
Derivatives not designated as hedging instruments:
Commodity contracts (futures and forwards)		Accounts receivable		$	4,751					$	—
Total derivatives				$	4,751					$	—
Derivatives designated as hedging instruments:
Commodity contracts (forwards)					—			Other non-current liabilities			(591	)
Total derivatives				$	—					$	(591	)

 

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ALON USA PARTNERS, LP PREDECESSOR

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(unaudited, dollars in thousands)

 

The following table presents the effect of derivative instruments on Alon’s combined statements of operations.

Derivatives in fair value hedging relationships:

 

				Gain (Loss) Recognized in Income
				For the Nine Months Ended September 30,
		Location		2011				2012
Commodity contracts (forwards)		Cost of sales		$	—			$	(591	)
Total derivatives				$	—			$	(591	)

Derivatives not designated as hedging instruments:

 

		Gain (Loss) Recognized in Income
		Location		Amount
For the Nine Months Ended September 30, 2011
Commodity contracts (futures & forwards)		Cost of sales		$	(482	)
Total derivatives				$	(482	)
For the Nine Months Ended September 30, 2012
Commodity contracts (futures & forwards)		Cost of sales		$	12,446
Commodity contracts (swaps) (a)		Cost of sales			(13,951	)
Total derivatives				$	(1,505	)

 

(a)	Related to derivatives with a related party.

 

(4)

Inventories

Alon’s inventories (including inventory consigned to others) are stated at the lower of cost or market. Cost is determined under the LIFO method for crude oil, refined products and blendstock inventories. Materials and supplies are stated at average cost.

Carrying value of inventories consisted of the following:

 

		December 31, 2011				September 30, 2012
Crude oil, refined products and blendstocks		$	8,674			$	23,850
Crude oil inventory consigned to others			14,000				24,498
Materials and supplies			9,064				9,000
Total inventories		$	31,738			$	57,348

Crude oil, refined products and blendstock inventories totaled 443 thousand barrels and 681 thousand barrels as of December 31, 2011 and September 30, 2012, respectively. Market values of crude oil, refined products and blendstock inventories exceeded LIFO costs by $21,889 and $18,754 at December 31, 2011 and September 30, 2012, respectively.

 

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ALON USA PARTNERS, LP PREDECESSOR

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(unaudited, dollars in thousands)

 

Alon had 270 thousand barrels and 333 thousand barrels of crude oil consigned to others at December 31, 2011 and September 30, 2012, respectively. Alon recorded liabilities associated with this consigned inventory of $25,550 and $32,107 in other non-current liabilities at December 31, 2011 and September 30, 2012, respectively.

Additionally, Alon recorded accrued liabilities of $18 and accounts receivable of $731 at December 31, 2011 and accounts receivable of $2,943 at September 30, 2012 for forward commitments related to month-end consignment inventory target levels differing from projected levels and the associated pricing with these inventory level differences.

 

(5)

Inventory Financing Agreements

In February 2011, Alon entered into a Supply and Offtake Agreement, (the “Supply and Offtake Agreement”), with J. Aron & Company (“J. Aron”). Pursuant to the Supply and Offtake Agreement, (i) J. Aron agreed to sell to Alon, and Alon agreed to buy from J. Aron, at market prices, crude oil for processing at the Big Spring refinery and (ii) Alon agreed to sell, and J. Aron agreed to buy, at market prices, certain refined products produced at the Big Spring refinery.

In connection with the execution of the Supply and Offtake Agreement, Alon also entered into agreements that provided for the sale, at market prices, of Alon’s crude oil and certain refined product inventories to J. Aron, the lease to J. Aron of crude oil and refined product storage tanks located at the Big Spring refinery, and an agreement to identify prospective purchasers of refined products on J. Aron’s behalf. The Supply and Offtake Agreement has an initial term that expires in May 2016. J. Aron may elect to terminate the agreement prior to the initial term beginning in May 2013, provided Alon receives notice of termination at least six months prior to that date. Following expiration or termination of the Supply and Offtake Agreement, Alon is obligated to purchase the crude oil and refined product inventories then owned by J. Aron and located at the Big Spring refinery.

In July 2012, the Supply and Offtake Agreement was amended principally in order to extend the terms of the Supply and Offtake Agreement by an additional two years. After the amendment, the Supply and Offtake Agreement has an initial term that expires in May 2018. J. Aron may elect to terminate the agreement prior to the initial term in May 2015 and upon each anniversary thereof provided Alon receives notice of termination at least six months prior to that date. Alon may elect to terminate in May 2017, provided Alon provides notice of termination at least six months prior to that date.

 

(6)

Property, Plant and Equipment, Net

Property, plant and equipment, net consisted of the following:

 

		December 31, 2011				September 30, 2012
Property, plant and equipment, gross		$	630,598			$	646,321
Less accumulated depreciation			(136,628	)			(161,206	)
Property, plant and equipment, net		$	493,970			$	485,115

The useful lives on depreciable assets used to determine depreciation expense were 3 to 20 years, with an average life of 18 years.

 

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ALON USA PARTNERS, LP PREDECESSOR

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(unaudited, dollars in thousands)

 

(7)

Other Assets

Other assets consisted of the following:

 

		December 31, 2011				September 30, 2012
Deferred turnaround and chemical catalyst cost		$	12,231			$	10,572
Deferred debt issuance costs			1,448				2,574
Consignment inventory receivable			6,290				6,290
Other			9,160				11,215
Total other assets		$	29,129			$	30,651

Debt issuance costs are amortized over the term of the related debt using the effective interest method. Amortization of debt issuance costs was $1,088 and $1,445 for the nine months ended September 30, 2011 and 2012, respectively, and is recorded as interest expense in the combined statements of operations.

 

(8)

Accrued Liabilities and Other Non-Current Liabilities

Accrued liabilities and other non-current liabilities consisted of the following:

 

		December 31, 2011				September 30, 2012
Accrued Liabilities:
Taxes other than income taxes, primarily excise taxes		$	21,658			$	19,609
Accrued finance charges			1,493				1,411
Environmental accrual			1,066				1,066
Other			3,623				6,135
Total accrued liabilities		$	27,840			$	28,221
Other Non-Current Liabilities:
Consignment inventory		$	25,550			$	32,107
Environmental accrual			4,901				4,901
Asset retirement obligations			1,789				1,847
Other			2,800				2,798
Total other non-current liabilities		$	35,040			$	41,653

Alon has asset retirement obligations with respect to its refinery due to various legal obligations to clean and/or dispose of these assets at the time they are retired. However, the majority of these assets can be used for extended and indeterminate periods of time provided that they are properly maintained and/or upgraded. It is Alon’s practice and intent to continue to maintain these assets and make improvements based on technological advances. When a date or range of dates can reasonably be estimated for the retirement of these assets or any component part of these assets, Alon will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using established present value techniques.

 

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ALON USA PARTNERS, LP PREDECESSOR

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(unaudited, dollars in thousands)

 

(9)

Revolving Credit Facility

Alon has a $240,000 revolving credit facility (the “Revolving Credit Facility”) that will mature on March 1, 2016, as amended March 2012. The Revolving Credit Facility can be used both for borrowings and the issuance of letters of credit subject to a limit of the lesser of the facility or the amount of the borrowing base under the facility.

Borrowings under the Revolving Credit Facility bear interest at the Eurodollar rate plus 3.50% per annum subject to an overall minimum interest rate of 4.00%.

The Revolving Credit Facility is secured by (i) a first lien on Alon’s cash, accounts receivables, inventories and related assets and (ii) a second lien on Alon’s fixed assets.

Alon’s Revolving Credit Facility contains certain restrictive covenants including maintenance financial covenants. At September 30, 2012, Alon was in compliance with these covenants.

Borrowings of $200,000 and $84,000 were outstanding under the Revolving Credit Facility at December 31, 2011 and September 30, 2012, respectively. At December 31, 2011 and September 30, 2012, outstanding letters of credit under the Revolving Credit Facility were $35,509 and $83,987, respectively.

Alon is a secured guarantor under a $450,000 term loan of Alon Energy. The term loan of Alon Energy is secured by (i) a first lien on Alon’s fixed assets and (ii) a second lien on Alon’s cash, accounts receivables, inventories and related assets.

 

(10)

Commitments and Contingencies

 

(a)

Commitments

In the normal course of business, Alon has long-term commitments to purchase, at market prices, utilities such as natural gas, electricity and water for use by the refinery, terminals and pipelines. Alon is also party to various refined product and crude oil supply and exchange agreements. These agreements are typically short-term in nature or provide terms for cancellation.

 

(b)

Contingencies

Alon is involved in various other claims and legal actions arising in the ordinary course of business. In August 2011, Alon received from the Federal Trade Commission a civil investigative demand to provide documents as part of an industry-wide investigation related to petroleum industry practices and pricing. Alon believes the ultimate disposition of this and all other matters will not have a material effect on Alon’s financial position, results of operations or liquidity.

 

(c)

Environmental

Alon is subject to loss contingencies pursuant to federal, state, and local environmental laws and regulations. These rules regulate the discharge of materials into the environment and may require Alon to incur future obligations to investigate the effects of the release or disposal of certain petroleum, chemical, and mineral substances at various sites; to remediate or restore these sites; to compensate others for damage to property and natural resources and for remediation and restoration costs. These possible obligations relate to sites owned by Alon and are associated with past or present operations. Alon is currently participating in environmental

 

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ALON USA PARTNERS, LP PREDECESSOR

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(unaudited, dollars in thousands)

 

investigations, assessments and cleanups under these regulations at pipelines and terminals. Alon may in the future be involved in additional environmental investigations, assessments and cleanups. The magnitude of future costs will depend on factors such as the unknown nature and contamination at many sites, the unknown timing, extent and method of the remedial actions which may be required, and the determination of Alon’s liability in proportion to other responsible parties.

Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Substantially all amounts accrued are expected to be paid out over the next fifteen years. The level of future expenditures for environmental remediation obligations is impossible to determine with any degree of reliability.

Alon has accrued environmental remediation obligations of $5,967 ($1,066 current liability and $4,901 non-current liability) at December 31, 2011 and September 30, 2012.

 

(11)

Related Party Transactions

Sales and Receivables

Sales to related parties include motor fuels and asphalt sold to other Alon Energy operations at prices substantially determined by market commodity pricing information. These sales are included in net sales in the combined statements of operations. Accounts receivable from related parties include sales of motor fuels and are shown separately on the combined balance sheets.

Costs Allocated from Alon Energy

 

(a)

Corporate Overhead Allocations

Alon is a subsidiary of Alon Energy and is operated as a component of the integrated operations of Alon Energy and its other subsidiaries. As such, the executive officers of Alon Energy, who are employed by another subsidiary of Alon Energy, also serve as executive officers of Alon and Alon Energy’s other subsidiaries and Alon Energy performs general corporate and administrative services and functions for Alon and Alon Energy’s other subsidiaries, which include accounting, treasury, cash management, tax, information technology, insurance administration and claims processing, legal, environmental, risk management, audit, payroll and employee benefit processing, and internal audit services. Alon Energy allocates the expenses actually incurred by it in performing these services to Alon and to its other subsidiaries based primarily on the estimated amount of time the individuals performing such services devote to Alon’s business and affairs relative to the amount of time they devote to the business and affairs of Alon Energy’s other subsidiaries. The management of Alon Energy considers these allocations to be reasonable. Alon records the amount of such allocations to its combined financial statements as selling, general and administrative expenses. For the nine months ended September 30, 2011 and 2012, Alon recorded selling, general and administrative expenses of $8,393 and $10,298, respectively, with respect to allocations from Alon Energy substantially associated with Alon Energy employee costs.

 

(b)

Labor Costs

Alon has no employees, and as a result, actual employee expense costs for Alon Energy employees working in Alon’s operations have been allocated and recorded as payroll expense and included in direct operating

 

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ALON USA PARTNERS, LP PREDECESSOR

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(unaudited, dollars in thousands)

 

expenses and selling, general and administrative expenses within the combined statements of operations. Alon’s share of Alon Energy’s employee costs included in direct operating expenses was $16,384 and $17,167 for the nine months ended September 30, 2011 and 2012, respectively.

 

(c)

Insurance Costs

Insurance costs related to the Big Spring refinery and wholesale marketing operations are allocated from Alon Energy based on the projected equipment values and estimated earnings. Insurance costs included in direct operating expenses were $5,982 and $7,804 for the nine months ended September 30, 2011 and 2012, respectively.

Subordinated Debt

Alon has subordinated debt notes payable to Alon Energy and certain of its subsidiaries. These notes mature on January 1, 2018. The notes have no prepayment penalty or any covenant requirements. The interest rates charged on these notes range from 6% to 10%. Interest expense pertaining to these notes is shown separately on the combined statements of operations.

 

(12)

Subsequent Events

Alon has evaluated subsequent events through November 5, 2012, which was the date the combined financial statements were issued.

 

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Appendix A

FORM OF

AMENDED AND RESTATED

AGREEMENT OF LIMITED PARTNERSHIP

OF

ALON USA PARTNERS, LP

 

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Appendix B

GLOSSARY OF INDUSTRY TERMS USED IN THIS PROSPECTUS

“3-2-1 crack spread” refers to the approximate refining margin resulting from processing three barrels of crude oil to produce two barrels of gasoline and one barrel of distillate;

“Barrel” refers to common unit of measurement in the oil industry, which equates to 42 gallons;

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

“Bpd” refers to an abbreviation for barrels per calendar day, which is defined by the EIA as the amount of input that a distillation facility can process under usual operating conditions reduced for regular limitations that may delay, interrupt, or slow down production such as downtime due to such conditions as mechanical problems, repairs, and slowdowns;

“Catalyst” refers to a substance that alters, accelerates, or instigates chemical changes, but is neither produced, consumed nor altered in the process;

“Complexity” refers to the number, type and capacity of processing units at a refinery, measured by the Nelson index, which is often used as a measure of a refinery’s ability to process lower cost crude oils into higher-value light refined products, including transportation fuels, such as gasoline and distillates;

“Crack spread” refers to a simplified calculation that measures the difference between the price for motor fuels and crude oil;

“Distillates” refers to primarily diesel, kerosene and jet fuel;

“Feedstocks” refers to petroleum products, such as crude oil, that are processed and blended into refined products;

“Gulf Coast (WTI) 3-2-1 crack spread” refers to the 3-2-1 crack spread calculated using the market value of Gulf Coast conventional gasoline and ultra-low sulfur diesel against the market value of NYMEX Cushing WTI;

“ICE” refers to Intercontinental Exchange;

“Nelson complexity” refers to the complexity of an oil refinery as measured by the Nelson Complexity Index, which is calculated on an annual basis by the Oil and Gas Journal. The Nelson Complexity Index assigns a complexity factor to each major piece of refinery equipment based on its complexity and cost in comparison to crude distillation, which is assigned a complexity factor of 1.0. The complexity of each piece of refinery equipment is then calculated by multiplying its complexity factor by its throughput ratio as a percentage of crude distillation capacity. Adding up the complexity values assigned to each piece of equipment, including crude distillation, determines a refinery’s complexity on the Nelson Complexity Index. A refinery with a complexity of 10.0 on the Nelson Complexity Index is considered ten times more complex than crude distillation for the same amount of throughput;

“NYMEX” refers to the New York Mercantile Exchange;

“NYMEX RBOB” refers to a wholesale non-oxygenated blendstock traded in the New York Harbor barge market that is ready for the addition of 10% ethanol at the truck rack.

“PADD III” refers to the Petroleum Administration for Defense District III region of the United States, which covers the following states: Alabama, Arkansas, Louisiana, Mississippi, New Mexico and Texas;

 

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“Refined products” refers to petroleum products, such as gasoline, diesel and jet fuel, which are produced by a refinery;

“Sour crude oil” refers to a crude oil that is relatively high in sulfur content, requiring additional processing to remove the sulfur. Sour crude oil is typically less expensive than sweet crude oil;

“Sweet crude oil” refers to a crude oil that is relatively low in sulfur content, requiring less processing to remove the sulfur. Sweet crude oil is typically more expensive than sour crude oil;

“Throughput” refers to the volume processed through a unit or a refinery;

“Turnaround” refers to a periodically required standard procedure to refurbish and maintain a refinery that involves the shutdown and inspection of major processing units and occurs every three to four years on industry average;

“Utilization” refers to average daily crude oil throughput divided by crude oil capacity (which represents the stated refining capacity of our refinery), excluding planned periods of downtime for maintenance and turnarounds.

“WTI” refers to West Texas Intermediate crude oil, a light, sweet crude oil, characterized by an American Petroleum Institute gravity, or API gravity, between 39° and 41° and a sulfur content of approximately 0.3 weight percent that is used as a benchmark for other crude oils;

“WTS” refers to West Texas Sour crude oil, a sour crude oil, characterized by an API gravity between 30° and 33° and a sulfur content of approximately 1.28 weight percent that is used as a benchmark for other sour crude oils; and

“Yield” refers to the percentage of refined products that is produced from crude oil and other feedstocks.

 

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                 Common Units

Representing Limited Partner Interests

 

 

Alon USA Partners, LP

 

 

Goldman, Sachs & Co.

Credit Suisse

Citigroup

Jefferies

 

 

Through and including                 , 2012 (25 days 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.

 

 

 

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PART II

INFORMATION REQUIRED IN THE REGISTRATION STATEMENT

 

ITEM 13.

OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.

Set forth below are the expenses (other than underwriting discounts) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the FINRA filing fee and the New York Stock Exchange listing fee the amounts set forth below are estimates.

 

SEC registration fee		$	26,358
FINRA filing fee			35,000
Printing and engraving expenses			450,000
Fees and expenses of legal counsel			1,500,000
Accounting fees and expenses			660,000
Transfer agent and registrar fees			5,500
New York Stock Exchange listing fee			250,000
Miscellaneous			133,142
Total		$	3,000,000

 

*	To be provided by amendment.

 

ITEM 14.

INDEMNIFICATION OF OFFICERS AND MEMBERS OF OUR BOARD OF DIRECTORS.

The section of the prospectus entitled “The Partnership Agreement—Indemnification” is incorporated herein by reference and discloses that we will generally indemnify the directors and officers of our general partner and Alon Energy to the fullest extent permitted by law against all losses, claims, damages or similar events. Subject to any terms, conditions or restrictions set forth in the second amended and restated partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against all claims and demands whatsoever.

Section 18-108 of the Delaware Limited Liability Company Act provides that a Delaware limited liability company may indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever. The limited liability company agreement of Alon USA Partners GP, LLC, our general partner, provides for the indemnification of its directors and officers against liabilities they incur in their capacities as such. The Registrant may enter into indemnity agreements with each of its current directors and officers to give these directors and officers additional contractual assurances regarding the scope of the indemnification set forth in the Registrant’s limited liability company agreement and to provide additional procedural protections.

The underwriting agreement that we expect to enter into with the underwriters, to be filed as Exhibit 1.1 to this registration statement, will contain indemnification and contribution provisions.

 

ITEM 15.

RECENT SALES OF UNREGISTERED SECURITIES.

On August 17, 2012, in connection with the formation of Alon USA Partners, LP, we issued (i) the non-economic general partner interest in us to Alon USA Partners GP, LLC and (ii) the 100.0% limited partner interest in us to Alon Assets, Inc. for $1,000.00. The issuance was exempt from registration under Section 4(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years.

 

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ITEM 16.

EXHIBITS.

The following documents are filed as exhibits to this registration statement:

 

Exhibit Number				Description
1.1		—		Form of Underwriting Agreement
3.1**		—		Certificate of Limited Partnership of Alon USA Partners, LP
3.2**		—		Agreement of Limited Partnership of Alon USA Partners, LP
3.3**		—		Form of Amended and Restated Limited Partnership Agreement of Alon USA Partners, LP
5.1**		—		Form of Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
8.1**		—		Form of Opinion of Vinson & Elkins L.L.P. relating to tax matters
10.1**		—		Form of Contribution Agreement
10.2**		—		Form of Omnibus Agreement
10.3**		—		Form of Services Agreement
10.4**		—		Form of Tax Sharing Agreement
10.5*		—		Form of New Term Loan Facility
10.6**		—		Credit Agreement, dated June 22, 2006, by and among Alon USA Energy, Inc., the lenders party thereto and Credit Suisse (incorporated by reference to Exhibit 10.1 to Alon USA Energy, Inc.’s Current Report on Form 8-K filed on June 26, 2006, File No. 001-32567)
10.7**		—		Amendment No. 1 to the Credit Agreement, dated as of February 28, 2007, by and among Alon USA Energy, Inc., the lenders party thereto and Credit Suisse (incorporated by reference to Exhibit 10.3 to Alon USA Energy Inc.’s Current Report on Form 8-K, filed on March 5, 2007, File No. 001-32567)
10.8**		—		Amended Revolving Credit Agreement, dated as of June 22, 2006, among Alon USA, LP, EOC Acquisition, LLC, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.2 to Alon USA Energy Inc.’s Current Report on Form 8-K, filed on June 26, 2006, File No. 001-32567)
10.9**		—		First Amendment to Amended Revolving Credit Agreement, dated as of August 4, 2006, to the Amended Revolving Credit Agreement, dated as of June 22, 2006, among Alon USA, LP, EOC Acquisition, LLC, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.25 to Alon USA Energy Inc.’s Annual Report on Form 10-K, filed on March 15, 2007, File No. 001-32567)
10.10**		—		Waiver, Consent, Partial Release and Second Amendment, dated as of February 28, 2007, to the Amended Revolving Credit Agreement, dated as of June 22, 2006, Alon USA, LP, Edgington Oil Company, LLC, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.2 to Alon USA Energy Inc.’s Current Report on Form 8-K, filed on March 5, 2007, File No. 001-32567)

 

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10.11**		—		Third Amendment to Amended Revolving Credit Agreement, dated as of June 29, 2007, to the Amended Revolving Credit Agreement, dated as of June 22, 2006, among Alon USA Energy, Inc., Alon USA, LP, the guarantor companies and financial institutions named therein, Israel Discount Bank of New York and Bank Leumi USA (incorporated by reference to Exhibit 10.1 to Alon USA Energy Inc.’s Current Report on Form 8-K, filed on July 20, 2007, File No. 001-32567)
10.12**		—		Waiver, Consent, Partial Release and Fourth Amendment, dated as of July 2, 2008, by and among Alon USA, LP, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.4 to Alon USA Energy Inc.’s Current Report on Form 8-K, filed on July 10, 2008, File No. 001-32567)
10.13**		—		Fifth Amendment to Amended Revolving Credit Agreement, dated as of July 31, 2009, by and among Alon USA, LP, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.3 to Alon USA Energy Inc.’s Quarterly Report on Form 10-Q, filed on August 6, 2009, File No. 001-32567)
10.14**		—		Sixth Amendment to Amended Revolving Credit Agreement, dated as of May 10, 2010, by and among Alon USA, LP, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.2 to Alon USA Energy Inc.’s Quarterly Report on Form 10-Q, filed on May 10, 2010, File No. 001-32567)
10.15**		—		Seventh Amendment to Amended Revolving Credit Agreement, dated as of June 1, 2010, by and among Alon USA, LP, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.1 to Alon USA Energy Inc.’s Quarterly Report on Form 10-Q, filed by the Company on August 9, 2010, File No. 001-32567)
10.16**		—		Eighth Amendment to Amended Revolving Credit Agreement, dated as of June 16, 2010, by and among Alon USA, LP, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.2 to Alon USA Energy Inc.’s Quarterly Report on Form 10-Q, filed by the Company on August 9, 2010, File No. 001-32567)
10.17**		—		Ninth Amendment to Amended Revolving Credit Agreement, dated as of February 22, 2011, by and among Alon USA, LP, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.22 to Alon USA Energy Inc.’s Annual Report on Form 10-K, filed by the Company on March 15, 2011, File No. 001-32567)
10.18**		—		Tenth Amendment to Amended Revolving Credit Agreement, dated as of March 6, 2012, by and among Alon USA, LP, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.21 to Alon USA Energy Inc.’s Annual Report on Form 10-K, filed by the Company on March 13, 2012, File No. 001-32567)
10.19**		—		Amended and Restated Supply and Offtake Agreement dated as of March 1, 2011 between J. Aron & Company and Alon USA, LP (incorporated by reference to Exhibit 10.1 to Alon USA Energy, Inc.’s Quarterly Report on Form 10-Q filed on May 10, 2011, File No. 001-32567)
10.20**		—		Amendment to Supply and Offtake Agreement dated as of July 20, 2012 between J. Aron & Company and Alon USA, LP (incorporated by reference to Exhibit 10.4 to Alon USA Energy, Inc.’s Quarterly Report on Form 10-Q filed on August 9, 2012, File No. 001-32567)

 

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10.21**†		—		Form of Alon USA Partners, LP 2012 Long-Term Incentive Plan
10.22**†		—		Directors’ Compensation Summary
10.23**		—		Pipeline and Terminals Agreement, dated February 28, 2005, between Alon USA, LP and Holly Energy Partners, L.P. (incorporated by reference to Exhibit 10.8 to Alon USA Energy, Inc.’s Registration Statement on Form S-1, filed May 11, 2005, Registration No. 333-124797)
10.24**		—		First Amendment of Pipelines and Terminals Agreement, effective as of September 1, 2008, between Holly Energy Partners, L.P. and Alon USA, LP
10.25**		—		Second Amendment to Pipelines and Terminals Agreement, dated as of March 1, 2011, between Holly Energy Partners, L.P. and Alon USA, LP
10.26**		—		Third Amendment to Pipelines and Terminals Agreement, dated as of June 6, 2011, between Holly Energy Partners, L.P. and Alon USA, LP
10.27**		—		Pipeline Lease Agreement, dated as of December 12, 2007, between Plains Pipeline, L.P. and Alon USA, L.P. (incorporated by reference to Exhibit 10.1 to Alon USA Energy, Inc.’s Current Report on Form 8-K filed on February 5, 2008, File No. 001-32567)
10.28**		—		Pipeline Lease Agreement, dated as of February 21, 1997, between Navajo Pipeline Company and American Petrofina Pipe Line Company (incorporated by reference to Exhibit 10.6 to Alon USA Energy, Inc.’s Registration Statement on Form S-1, filed May 11, 2005, Registration No. 333-124797)
10.29**		—		Connection and Shipping Agreement, dated June 14, 2006, by and between Centurion Pipeline L.P. and Alon USA, LP
10.30**		—		Amendment No. 1 to Connection and Shipping Agreement, effective as of April 1, 2012, by and between Alon USA, LP and Centurion Pipeline L.P.
10.31**		—		Form of Distributor Sales Agreement
10.32**		—		Form of Offtake Agreement
10.34**†		—		Form of Restricted Stock Award Agreement
21.1**		—		List of Subsidiaries of Alon USA Partners, LP
23.1		—		Consent of KPMG LLP
23.2**		—		Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
23.3**		—		Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)
23.4**		—		Consent of Director Nominee (Morris)
23.5**		—		Consent of Director Nominee (Bader)
23.6**		—		Consent of Director Nominee (Biran)
23.7**		—		Consent of Director Nominee (Raff)
23.8**		—		Consent of Director Nominee (Weissman)
23.9**		—		Consent of Director Nominee (Ventura)
24.1**		—		Powers of Attorney (contained on page II-4)

 

*	To be filed by amendment.

**	Previously filed.

†	Compensatory plan or arrangement.

 

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ITEM 17.

UNDERTAKINGS.

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the provisions described in Item 14 above, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that, for the purpose of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of the securities, in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

1) Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

2) Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

3) The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

4) Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

The undersigned registrant hereby further undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective; and

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at the time shall be deemed to be the initial bona fide offering thereof.

The registrant undertakes to send to each limited partner at least on an annual basis a detailed statement of any transactions with Alon USA Partners GP, LLC, our general partner, or any of its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to, Alon USA Partners GP, LLC or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the limited partners the financial statements required by Form 10-K for the first full fiscal year of operations of the registrant.

 

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the city of Dallas, State of Texas, on November 6, 2012.

 

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and the dates indicated.

 

Signature		Title		Date
/s/ Paul Eisman		President, Chief Executive Officer and Director (Principal Executive Officer)		November 6, 2012
Paul Eisman
*		Senior Vice President, Chief Financial Officer and Director (Principal Financial and Accounting Officer)		November 6, 2012
Shai Even
*		Executive Chairman		November 6, 2012
David Wiessman

 

*By:		/s/ Paul Eisman
		Paul Eisman Attorney-in-Fact

 

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INDEX TO EXHIBITS

 

Exhibit Number				Description
1.1		—		Form of Underwriting Agreement
3.1**		—		Certificate of Limited Partnership of Alon USA Partners, LP
3.2**		—		Agreement of Limited Partnership of Alon USA Partners, LP
3.3**		—		Form of Amended and Restated Limited Partnership Agreement of Alon USA Partners, LP
5.1**		—		Form of Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
8.1**		—		Form of Opinion of Vinson & Elkins L.L.P. relating to tax matters
10.1**		—		Form of Contribution Agreement
10.2**		—		Form of Omnibus Agreement
10.3**		—		Form of Services Agreement
10.4**		—		Form of Tax Sharing Agreement
10.5*		—		Form of New Term Loan Facility
10.6**		—		Credit Agreement, dated June 22, 2006, by and among Alon USA Energy, Inc., the lenders party thereto and Credit Suisse (incorporated by reference to Exhibit 10.1 to Alon USA Energy, Inc.’s Current Report on Form 8-K filed on June 26, 2006, File No. 001-32567)
10.7**		—		Amendment No. 1 to the Credit Agreement, dated as of February 28, 2007, by and among Alon USA Energy, Inc., the lenders party thereto and Credit Suisse (incorporated by reference to Exhibit 10.3 to Alon USA Energy Inc.’s Current Report on Form 8-K, filed on March 5, 2007, File No. 001-32567)
10.8**		—		Amended Revolving Credit Agreement, dated as of June 22, 2006, among Alon USA, LP, EOC Acquisition, LLC, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.2 to Alon USA Energy Inc.’s Current Report on Form 8-K, filed on June 26, 2006, File No. 001-32567)
10.9**		—		First Amendment to Amended Revolving Credit Agreement, dated as of August 4, 2006, to the Amended Revolving Credit Agreement, dated as of June 22, 2006, among Alon USA, LP, EOC Acquisition, LLC, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.25 to Alon USA Energy Inc.’s Annual Report on Form 10-K, filed on March 15, 2007, File No. 001-32567)
10.10**		—		Waiver, Consent, Partial Release and Second Amendment, dated as of February 28, 2007, to the Amended Revolving Credit Agreement, dated as of June 22, 2006, Alon USA, LP, Edgington Oil Company, LLC, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.2 to Alon USA Energy Inc.’s Current Report on Form 8-K, filed on March 5, 2007, File No. 001-32567)

 

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10.11**		—		Third Amendment to Amended Revolving Credit Agreement, dated as of June 29, 2007, to the Amended Revolving Credit Agreement, dated as of June 22, 2006, among Alon USA Energy, Inc., Alon USA, LP, the guarantor companies and financial institutions named therein, Israel Discount Bank of New York and Bank Leumi USA (incorporated by reference to Exhibit 10.1 to Alon USA Energy Inc.’s Current Report on Form 8-K, filed on July 20, 2007, File No. 001-32567)
10.12**		—		Waiver, Consent, Partial Release and Fourth Amendment, dated as of July 2, 2008, by and among Alon USA, LP, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.4 to Alon USA Energy Inc.’s Current Report on Form 8-K, filed on July 10, 2008, File No. 001-32567)
10.13**		—		Fifth Amendment to Amended Revolving Credit Agreement, dated as of July 31, 2009, by and among Alon USA, LP, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.3 to Alon USA Energy Inc.’s Quarterly Report on Form 10-Q, filed on August 6, 2009, File No. 001-32567)
10.14**		—		Sixth Amendment to Amended Revolving Credit Agreement, dated as of May 10, 2010, by and among Alon USA, LP, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.2 to Alon USA Energy Inc.’s Quarterly Report on Form 10-Q, filed on May 10, 2010, File No. 001-32567)
10.15**		—		Seventh Amendment to Amended Revolving Credit Agreement, dated as of June 1, 2010, by and among Alon USA, LP, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.1 to Alon USA Energy Inc.’s Quarterly Report on Form 10-Q, filed by the Company on August 9, 2010, File No. 001-32567)
10.16**		—		Eighth Amendment to Amended Revolving Credit Agreement, dated as of June 16, 2010, by and among Alon USA, LP, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.2 to Alon USA Energy Inc.’s Quarterly Report on Form 10-Q, filed by the Company on August 9, 2010, File No. 001-32567)
10.17**		—		Ninth Amendment to Amended Revolving Credit Agreement, dated as of February 22, 2011, by and among Alon USA, LP, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.22 to Alon USA Energy Inc.’s Annual Report on Form 10-K, filed by the Company on March 15, 2011, File No. 001-32567)
10.18**		—		Tenth Amendment to Amended Revolving Credit Agreement, dated as of March 6, 2012, by and among Alon USA, LP, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.21 to Alon USA Energy Inc.’s Annual Report on Form 10-K, filed by the Company on March 13, 2012, File No. 001-32567)
10.19**		—		Amended and Restated Supply and Offtake Agreement dated as of March 1, 2011 between J. Aron & Company and Alon USA, LP (incorporated by reference to Exhibit 10.1 to Alon USA Energy, Inc.’s Quarterly Report on Form 10-Q filed on May 10, 2011, File No. 001-32567)
10.20**		—		Amendment to Supply and Offtake Agreement dated as of July 20, 2012 between J. Aron & Company and Alon USA, LP (incorporated by reference to Exhibit 10.4 to Alon USA Energy, Inc.’s Quarterly Report on Form 10-Q filed on August 9, 2012, File No. 001-32567)

 

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Table of Contents

10.21**†		—		Form of Alon USA Partners, LP 2012 Long-Term Incentive Plan
10.22**†		—		Directors’ Compensation Summary
10.23**		—		Pipeline and Terminals Agreement, dated February 28, 2005, between Alon USA, LP and Holly Energy Partners, L.P. (incorporated by reference to Exhibit 10.8 to Alon USA Energy, Inc.’s Registration Statement on Form S-1, filed May 11, 2005, Registration No. 333-124797)
10.24**		—		First Amendment of Pipelines and Terminals Agreement, effective as of September 1, 2008, between Holly Energy Partners, L.P. and Alon USA, L.P.
10.25**		—		Second Amendment to Pipelines and Terminals Agreement, dated as of March 1, 2011, between Holly Energy Partners, L.P. and Alon USA, LP
10.26**		—		Third Amendment to Pipelines and Terminals Agreement, dated as of June 6, 2011, between Holly Energy Partners, L.P. and Alon USA, LP
10.27**		—		Pipeline Lease Agreement, dated as of December 12, 2007, between Plains Pipeline, L.P. and Alon USA, LP (incorporated by reference to Exhibit 10.1 to Alon USA Energy, Inc.’s Current Report on Form 8-K filed on February 5, 2008, File No. 001-32567)
10.28**		—		Pipeline Lease Agreement, dated as of February 21, 1997, between Navajo Pipeline Company and American Petrofina Pipe Line Company (incorporated by reference to Exhibit 10.6 to Alon USA Energy, Inc.’s Registration Statement on Form S-1, filed May 11, 2005, Registration No. 333-124797)
10.29**		—		Connection and Shipping Agreement, dated June 14, 2006, by and between Centurion Pipeline L.P. and Alon USA, LP
10.30**		—		Amendment No. 1 to Connection and Shipping Agreement, effective as of April 1, 2012, by and between Alon USA, LP and Centurion Pipeline L.P.
10.31**		—		Form of Distributor Sales Agreement
10.32**		—		Form of Offtake Agreement
10.34**†		—		Form of Restricted Stock Award Agreement
21.1**		—		List of Subsidiaries of Alon USA Partners, LP
23.1		—		Consent of KPMG LLP
23.2**		—		Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
23.3**		—		Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)
23.4**		—		Consent of Director Nominee (Morris)
23.5**		—		Consent of Director Nominee (Bader)
23.6**		—		Consent of Director Nominee (Biran)
23.7**		—		Consent of Director Nominee (Raff)
23.8**		—		Consent of Director Nominee (Weissman)
23.9**		—		Consent of Director Nominee (Ventura)
24.1**		—		Powers of Attorney (contained on page II-4)

 

*	To be filed by amendment.

**	Previously filed.

†	Compensatory plan or arrangement.

 

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