10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	FOR THE FISCAL YEAR ENDED DECEMBER 31, 2013

OR

o	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	FOR THE TRANSITION PERIOD FROM __________TO __________

Commission file number: 333-163942

ALON REFINING KROTZ SPRINGS, INC.

(Exact name of Registrant as specified in its charter)

Delaware (State of incorporation)	74-2849682 (I.R.S. Employer Identification No.)
12700 Park Central Dr., Suite 1600, Dallas, Texas (Address of principal executive offices)	75251 (Zip Code)

Registrant’s telephone number, including area code: (972) 367-3600

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

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes þ No o

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

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

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

Indicate by check whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

The registrant is a subsidiary of Alon USA Energy, Inc., a Delaware corporation, and there is no market for the registrant’s common stock. As of March 1, 2014, 50,111 shares of the registrant’s Class A common stock, par value $0.01, and 90 shares of the registrant’s Class B common stock, par value $0.01, were outstanding.

The aggregate market value for the registrant’s common stock held by non-affiliates as of June 30, 2013, the last day of the registrant’s most recently completed second fiscal quarter was $0.

The registrant meets the conditions set forth in General Instruction I(1) (a) and (b) of Form 10-K and is therefore filing this Form with the reduced disclosure format permitted by General Instruction I(2).

Documents incorporated by reference: None.

TABLE OF CONTENTS

PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES	1
ITEM 1A. RISK FACTORS	5
ITEM 1B. UNRESOLVED STAFF COMMENTS	11
ITEM 3. LEGAL PROCEEDINGS	11
ITEM 4. MINE SAFETY DISCLOSURES	11
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	12
ITEM 6. SELECTED FINANCIAL DATA	12
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	12
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	13
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	14
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	14
ITEM 9A. CONTROLS AND PROCEDURES	14
ITEM 9B. OTHER INFORMATION	14
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	15
ITEM 11. EXECUTIVE COMPENSATION	17
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	18
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	18
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES	19
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	20

PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES.

Statements in this Annual Report on Form 10-K, including those in Items 1 and2, “Business and Properties,” and Item 3, “Legal Proceedings,” that are nothistorical in nature should be deemed forward-looking statements that areinherently uncertain. See “Forward-Looking Statements” in “Management’sDiscussion and Analysis of Financial Condition and Results of Operations” inItem 7 for a discussion of forward-looking statements and of factors that couldcause actual outcomes and results to differ materially from those projected.

This Annual Report on Form 10-K and other Securities and Exchange Commission filings of Alon Refining Krotz Springs, Inc. occasionally make references to our parent company, Alon USA Energy, Inc., when describing actions, rights or obligations. These references reflect the fact that Alon Refining Krotz Springs, Inc. is consolidated with its respective parent company for financial reporting purposes. However, these references should not be interpreted to imply that the parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company or that the subsidiary company is undertaking an action or has the rights or obligations of its parent company or any other affiliate.

Company Overview

In this Annual Report, the words “the Company,” “we,” “our” and “us” refer to Alon Refining Krotz Springs, Inc., and not to any other person. Unless the context otherwise requires, references in this Annual Report to “Alon Energy” refer to Alon USA Energy, Inc., our parent company, and its consolidated subsidiaries other than us.

We are a Delaware corporation formed in May 2008 in connection with the acquisition of Valero Refining Company-Louisiana by Alon Energy. We own and operate a high conversion crude oil refinery with a crude oil throughput capacity of approximately 74,000 barrels per day (“bpd”) in Krotz Springs, Louisiana. Our principal executive offices are located at 12700 Park Central Drive, Suite 1600, Dallas, Texas 75251, and our telephone number is (972) 367-3600.

We file annual, quarterly and current reports, and file or furnish other information, with the Securities Exchange Commission (“SEC”). Our SEC filings are available to the public at the SEC’s website at www.sec.gov. In addition, we make our SEC filings available free of charge through our parent company’s website at www.alonusa.com as soon as reasonably practicable after we file or furnish such material with the SEC. We will provide copies of our filings free of charge to our bondholders upon request to Alon Refining Krotz Springs, Inc., Attention: Investor Relations, 12700 Park Central Drive, Suite 1600, Dallas, Texas 75251.

Business

Our Refinery

Our crude oil refinery is located in Krotz Springs, Louisiana and has a throughput capacity of approximately 74,000 bpd. Our refinery is strategically located on approximately 381 acres on the Atchafalaya River in central Louisiana at the intersection of two crude oil pipeline systems and has direct access to the Colonial products pipeline system (“Colonial Pipeline”), providing us with diversified access to both locally sourced and foreign crude oils, as well as distribution of our products to markets throughout the Southern and Eastern United States and along the Mississippi and Ohio Rivers. In industry terms, our refinery is characterized as a “mild residual cracking refinery,” which generally refers to a refinery utilizing vacuum distillation and catalytic cracking processes in addition to basic distillation and naphtha reforming processes to minimize low quality black oil production and to produce higher light product yields such as gasoline, light distillates and intermediate products.

The refinery’s main processing units include a crude unit and an associated vacuum unit, a fluid catalytic cracking unit, a catalytic reformer unit, a polymerization unit and an isomerization unit. Our refinery has the capability to process substantial volumes of low sulfur, or sweet, crude oils to produce a high percentage of light, high-value refined products. Typically, sweet crude oil has accounted for all of our refinery’s crude oil input.

Raw Material Supply.

In 2012, our refinery began receiving crude oil sourced from West Texas. This crude oil is transported through the Amdel pipeline to the Nederland terminal located near the Gulf Coast and from there is transported to our refinery by barge via the Intracoastal Canal and the Atchafalaya River. Our refinery also has access to various types of domestic and foreign crude oils via an ExxonMobil pipeline (“EMPCo”), railcar or truck rack delivery. We are capable of receiving Light Louisiana Sweet (“LLS”) and foreign crude oils from the EMPCo “Northline System.” The Northline System delivers LLS and foreign crude oils from the St. James, Louisiana crude oil terminalling complex.

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In 2013, sweet crude oil accounted for all of the crude oil inputs at our refinery, of which 52.9% was Gulf Coast sweet crude oils and 47.1% was West Texas Intermediate (“WTI”) priced crude oil.

J. Aron & Company (“J. Aron”), through arrangements with various oil companies, supplies the majority of our refinery’s crude oil input requirements. Other feedstocks, including butane and secondary feedstocks, are delivered by truck and marine transportation.

Production

Gasoline. In 2013, gasoline accounted for approximately 44.6% of our refinery’s production.

Distillates. In 2013, diesel, light cycle oil and jet fuel accounted for approximately 40.2% of our refinery’s production.

Heavy Oils and Other. In 2013, slurry oil, LPG and petrochemical feedstocks accounted for approximately 15.2% of our refinery’s production.

Sales

Transportation Fuel Marketing. Substantially all of the refined products produced by our refinery are sold to J. Aron as they are produced. We market transportation fuel production through bulk sales and exchange channels. These bulk sales and exchange arrangements are entered into with various oil companies and traders and are transported to markets on the Mississippi River and the Atchafalaya River as well as to the Colonial Pipeline.

Product Pipelines. Our refinery connects to and distributes refined products into the Colonial Pipeline for distribution by our customers to the Southern and Eastern U.S. markets. The Colonial Pipeline has over 5,500 miles of pipelines and transports products to more than 260 marketing terminals located near major population centers. The connection to the Colonial Pipeline provides flexibility to optimize product flows into multiple regional markets.

Barge, Railcar and Truck. Products not shipped through the Colonial Pipeline, such as high sulfur diesel, are transported via barge for sale. Barges originating at our refinery have access to both the Mississippi and Ohio Rivers.

Propylene/propane mix is sold via railcar and truck, to consumers at Mont Belvieu, Texas or in adjacent Louisiana markets. Mixed LPGs are shipped to an LPG fractionator at Napoleonsville, Louisiana. We pay a fractionation fee and sell the ethane and propane to a regional chemical company under contract, transport the normal butane back to our refinery via truck for blending, and sell the isobutane and natural gasoline on a spot basis.

Parent Company

Alon USA Energy, Inc. (NYSE: ALJ), headquartered in Dallas, Texas, is an independent refiner and marketer of petroleum products operating primarily in the South Central, Southwestern and Western regions of the United States. Alon Energy had a market capitalization of $1,135.3 million as of December 31, 2013. Alon Energy owns 100% of the general partner and 81.6% of the limited partner interests in Alon USA Partners, LP (NYSE: ALDW), which owns a crude oil refinery in Texas with an aggregate crude oil throughput capacity of approximately 70,000 barrels per day. In addition, Alon Energy directly owns our refinery as well as crude oil refineries in California with an aggregate crude oil throughput capacity of approximately 144,000 barrels per day. Alon Energy is a leading marketer of asphalt, which it distributes through its asphalt terminals predominately in the Western United States. Alon Energy is the largest 7-Eleven licensee in the United States and operates approximately 300 convenience stores in Texas and New Mexico.

Competition

The petroleum refining industry continues to be highly competitive. Many of our principal competitors are integrated, multi-national oil companies (e.g., ExxonMobil, Chevron and Royal Dutch Shell) and other major independent refining and marketing entities (e.g., Phillips 66, Marathon Petroleum and Valero) that operate in our market areas. Because of their diversity, integration of operations and larger capitalization, these major competitors may have greater financial support and diversity with a potential greater ability to bear the economic risks, operating risks and volatile market conditions associated with the petroleum refining industry.

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.

Substantially all of the refined products produced by our refinery are sold to J. Aron as they are produced. The majority of the remaining refined fuel products produced at our refinery are sold on the spot market and shipped through the Colonial Pipeline to major demand centers throughout the Southern and Eastern United States. The market for refined products in these regions is also supplied by a number of refiners, including large integrated oil companies or independent refiners, that either have refineries located in the region or have pipeline access to these regions. These larger companies typically have greater resources and may have greater flexibility in responding to volatile market conditions or absorbing market changes.

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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.

Government 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, land and water, the handling and disposal of solid and hazardous waste 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 United States Environmental Protection Agency (“EPA”) and the states and jurisdictions in which we operate.

The federal Clean Air Act and its implementing regulations require 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 produced at our refinery currently meets the low sulfur gasoline standard. We do not manufacture low sulfur diesel fuel. In March 2014, the EPA announced final new “Tier 3” motor vehicle emission and fuel standards. Under the final rule, gasoline must contain no more than 10 ppm sulfur on an annual average basis beginning on January 1, 2017; however, approved small refineries have until January 1, 2020 to meet the standard. We believe that our refinery satisfies the definition of a small refinery. We estimate that the capital investment associated with upgrades necessary to meet these new required sulfur levels will be less than $20 million.

In 2007, the EPA adopted final rules to reduce the levels of benzene in gasoline on a nationwide basis. More specifically, beginning in 2011, refiners were required to 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 were required to meet a maximum average gasoline benzene concentration of 1.30%, by volume on all gasoline produced, both reformulated and conventional and without benzene credits. Gasoline produced at our refinery currently meets the standards established by the EPA.

We are subject to the Renewable Fuel Standards 2 (“RFS2”) which requires refiners to blend renewable fuels (e.g., ethanol, biodiesel) into finished transportation fuels or purchase renewable identification number credits (“RINs”) in lieu of blending. The EPA establishes new annual renewable fuel percentage standards for each compliance year in the preceding year. In August 2013, the EPA announced the final 2013 renewable fuel percentage standard, which raised the mandate from 9.6% to 9.74%. Our refinery received an exemption from the RFS2 requirements for 2013 and as a result recorded no costs associated with RINs. The EPA has published the proposed volume mandates for 2014, which are generally lower than the volumes for 2013 and lower than statutory mandates.

Regulation

Conditions may develop that require additional capital expenditures at our refinery 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.

Compliance

The EPA has adopted regulations requiring certain new or modified sources of high-volume greenhouse gases (“GHG”) emissions to install best achievable control technology to reduce GHG emissions. If we undertake significant improvements at our 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 the federal government 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 the federal government 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.

Our refinery was subject to a “global settlement” with the EPA under the National Petroleum Refining Initiative at the time it was acquired. In return for agreeing to the consent decree and implementing the reductions in emissions that it specifies, the refineries secured broad releases of liability that provide immunity from enforcement actions for alleged past non-compliance under each of the Clean Air Act programs covered by the consent decree. If we are unable to meet the agreed upon reductions without add-on controls, our capital costs could increase. Because our refinery remains subject to the Valero consent decree, we entered into an agreement with Valero at the time of the acquisition allocating responsibilities under the consent d

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ecree. We are responsible for implementing only those portions of the consent decree that are specifically and uniquely applicable to our refinery.

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 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 business, financial position, results of operations and the cash flows.

Known Environmental Liabilities

At December 31, 2013, our refinery had an environmental reserve of $0.3 million. This reserve relates to the remediation of groundwater.

Employees

Approximately 190 people, including operations personnel and general and administrative personnel, are currently utilized to conduct and support our refinery’s operations. To facilitate and lower the costs of the provision and administration of employee payroll and benefits, the personnel utilized in our operations are employed through Alon Energy with our company paying the costs of such payroll and benefits. None of our personnel are covered by collective bargaining agreements. We consider our relations with our personnel to be satisfactory.

Properties

Our principal real property consists of approximately 260 acres of owned real property, which includes the land upon which our main refinery facilities are located and land adjacent thereto. In addition, we lease approximately 160 acres of land near and adjoining our refinery, which are used for activities ancillary to and in support of our refinery. The leased property is primarily held under five main leases, with current terms ranging from three to 15 years and options to permit the renewal of the leases for the majority of such leased property. The shortest term of any such lease without a renewal right runs through December 31, 2017. We believe that our facility is sufficient for our operations and is maintained in a good state of repair in the ordinary course of business.

Insurance

We are insured under our own insurance policies which cover physical damage (all risk property damage, business interruption and flood), third party liability and other miscellaneous items. The property insurance policy has a combined loss limit for a property loss and business interruption at our refinery of $850 million per occurrence. A deductible of $2 million applies to physical damage claims, with a 45-day wait period deductible for business interruption.

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ITEM 1A. RISK FACTORS.

The occurrence of any of the events described in this Risk Factors section and elsewhere in this Annual Report on Form 10-K or in any other of our filings with the SEC could have a material adverse effect on our business, financial position, results of operations and cash flows. In evaluating an investment in any of our securities, you should consider carefully, among other things, the factors and the specific risks set forth below. This Annual Report on Form 10-K contains forward-looking statements that involve risks and uncertainties. See “Forward-Looking Statements” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 for a discussion of the factors that could cause actual results to differ materially from those projected.

Risk Factors Relating to Our Business

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.

Our refining earnings, profitability and cash flows from operations 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 continue to 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, rather than the nominal amounts of such prices, that has the greatest impact on our results of operations and cash flows.

Prices of crude oil, other feedstocks and refined products, 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 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 into and exported from the United States;

• refinery utilization rates;

• the development and marketing of alternative and competing fuels;

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

• infrastructure limitations;

• accidents, interruptions in transportation, inclement weather or other events that can cause unscheduled shutdowns or otherwise adversely affect refineries;

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

• local factors, including market conditions, weather conditions and the level of operations of other refineries and pipelines in our market.

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 other variable costs.

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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 earnings, profitability and cash flows.

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.

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

The volatility in costs of natural gas, electricity and other utility services used by our refinery 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 may have a negative effect on our earnings, profitability and cash flows.

A recession and credit crisis and related turmoil in the global financial system could 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 reduce 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 a 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.

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 property of others.

There is also risk of mechanical failure and equipment shutdowns both in general and following unforeseen events. In such situations, undamaged refinery processing units may be dependent on or interact with damaged process units and, accordingly, are also subject to being shutdown.

Because all of our refining operations are conducted at a single refinery, any of such events 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.

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

Our refinery receives a substantial percentage of crude oil and delivers a substantial percentage of refined products through pipelines and barges. 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 and barges to transport crude oil or refined products is disrupted because of accidents, earthquakes, hurricanes, flooding, governmental regulation, terrorism, other third party action or any of the types of events described in the preceding risk factor. Our prolonged inability to use any of the pipelines and

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barges 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.

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 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 business, results of operations and cash flows. 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.

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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.

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. 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 2016. 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. 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 and to obtain crude oil in times of shortage.

We are not engaged in the exploration and production business and therefore do not produce any of our crude oil 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 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, which 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.

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 meet 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 stop our operations.

We are subject to the RFS2 which requires refiners to blend renewable fuels (e.g., ethanol, biodiesel) into their finished transportation fuels or purchase RINs in lieu of blending. Our refinery received an exemption from the RFS2 requirements for 2013 and was not required to purchase RINs or waiver credits for compliance. During 2013, the price of RINs was extremely volatile. The EPA has published the proposed volume mandates for 2014, which are generally lower than the volumes for 2013 and lower than statutory mandates. We cannot predict the future prices of RINs or waiver credits (for cellulosic biofuels from the EPA), but the costs to obtain the necessary number of RINs and waiver credits could be material.

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, in March 2014, the EPA announced final new “Tier 3” motor vehicle emission and fuel standards. Under the final rule, gasoline must contain no more than 10 ppm sulfur on an annual average basis beginning on January 1, 2017; however, approved small refineries have until January 1, 2020 to meet the standard. We believe that our refinery satisfies the definition of a small refinery. Although we estimate that the capital investment associated with upgrades

8

necessary to meet these new required sulfur levels will be less than $20 million, we are not able to predict the impact of other 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 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 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 in June 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 could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with health, safety, environmental and other laws and regulations.

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

We are located in an area that has a history of hurricanes and flooding, the occurrence of which could materially affect our operations.

From mid-May to mid-June 2011, our refinery was shutdown in anticipation of potential flooding from the opening of the Morganza Spillway, which diverted water from the Mississippi River to the Atchafalaya Basin and the Atchafalaya River. Our refinery did not incur any damage; however, this flooding did impact crude supply to our refinery.

In August 2008, our refinery sustained minor physical damage from Hurricane Gustav; however, the regional utilities were affected and, as a result, our refinery was without electric power for one week. Offshore crude oil production and gathering

9

facilities were impacted by Gustav and a subsequent storm, which temporarily limited the availability of crude oil to our refinery. In the event hurricanes or floods cause damage to our refinery, or the infrastructure necessary for the operation of the refinery, such as the availability of usable roads, electricity, water, or natural gas, we may experience a significant interruption in our refining operations. Such an interruption could have a material adverse effect on our business, results of operations and cash flows.

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 (such as our refinery) 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 a material adverse effect on our operations, financial condition, results of operations and prospects. 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 refining margins. 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 a period of 45 days. We could suffer losses for uninsurable or uninsured risks or insurable events 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.

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, most of who are employed by an affiliate of our corporate parent, Alon Energy. 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 need to hire other personnel to manage and operate our refinery and to develop our products and technology. We cannot assure you that we would be able to locate or employ qualified personnel on acceptable terms or at all. To the extent members of our senior management team are performing services for Alon Energy, this may divert their time and attention away from our business and may therefore adversely affect our business. In addition, we cannot assure you that the interests of our parent company will always be aligned with the interests of our company or the holders of our senior secured notes.

Risk Factors Relating to Outstanding Indebtedness and Debt Agreements

Our substantial level of indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under our senior secured notes.

Subject to restrictions in the Indenture governing our Senior Secured Notes, we may incur additional indebtedness. Our indebtedness could have important consequences to you and significant effects on our business, including the following:

• it may be more difficult for us to satisfy our financial obligations, including with respect to our Senior Secured Notes;

• our ability to obtain additional financing for working capital, capital expenditures or general corporate purposes may be impaired;

• we must use a substantial portion of our cash flow from operations to pay interest on our Senior Secured Notes as well as to fund excess cash flow;

• offers on our Senior Secured Notes, which will reduce the funds available to use for operations and other purposes;

• our ability to fund a change of control offer may be limited;

• our ability to borrow additional funds may be limited;

10

• our indebtedness could place us at a competitive disadvantage compared to those of our competitors that may have proportionately less debt;

• our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate may be limited;

• we may be restricted from making strategic acquisitions or exploiting other business opportunities; and

• our level of indebtedness makes us more vulnerable to economic downturns and adverse developments in our business.

We expect to use cash flow from operations to pay our expenses and scheduled interest and principal payments due under our Senior Secured Notes. Our ability to make these payments thus depends on our future performance, which is affected by financial, business, economic and other factors, many of which we cannot control. A recession and credit crisis and related turmoil in the global financial system has had and may continue to have an adverse effect on our business, financial condition, results of operations and cash flows. Consequently, our business may not generate sufficient cash flow from operations in the future and our anticipated growth in revenue and cash flow may not be realized, either or both of which could result in our being unable to repay or pay interest on our Senior Secured Notes, or to fund other liquidity needs. If we do not have enough money, we may be required to refinance all or part of our Senior Secured Notes, sell assets or borrow more money. We cannot make any assurances that we will be able to accomplish any of these alternatives on terms acceptable to us, or at all. In addition, the terms of the Indenture governing our Senior Secured Notes, may restrict us from adopting any of these alternatives. The failure to generate sufficient cash flow or to achieve any of these alternatives could significantly adversely affect the value of our Senior Secured Notes and our ability to pay the amounts due under our Senior Secured Notes. In addition, if we default in the payment of amounts due on our Senior Secured Notes, it would give rise to an event of default under the Indenture governing our Senior Secured Notes. In the event of any acceleration, there can be no assurance that we will have enough cash to repay our outstanding Senior Secured Notes.

Despite our current indebtedness level, we may still be able to incur substantially more debt, which could exacerbate the risks associated with our substantial leverage.

We may be able to incur substantial additional indebtedness in the future. The terms of the Indenture governing our Senior Secured Notes do not fully prohibit us from doing so. If new debt is added to our current debt levels, the related risks that we now face could intensify.

Our Indenture governing our Senior Secured Notes imposes significant operating and financial restrictions, which may prevent us from pursuing certain business opportunities and taking certain actions.

Our Indenture governing our Senior Secured Notes imposes, and future debt agreements may impose, significant operating and financial restrictions on us.

These restrictions limit or prohibit, among other things, our ability to:

• incur additional indebtedness;

• repay our Senior Secured Notes prior to stated maturities;

• make acquisitions or investments;

• create or incur liens;

• transfer or sell certain assets or merge or consolidate with or into other companies;

• enter into certain transactions with affiliates; and

• otherwise conduct certain corporate activities.

These restrictions could adversely affect our ability to finance our future operations or capital needs and pursue available business opportunities. A breach of any of these restrictions could result in a default in respect to our Senior Secured Notes.

ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

ITEM 3. LEGAL PROCEEDINGS.

In the ordinary conduct 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.

ITEM 4. MINE SAFETY DISCLOSURES.

None.

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PART II

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

As of March 1, 2014, Alon Energy is the only holder of all of our outstanding voting capital stock. There is no established public trading market for our common stock. We did not declare or pay dividends on our capital stock in 2013 or 2012. Our debt agreement contains provisions that limit our ability to pay dividends.

ITEM 6. SELECTED FINANCIAL DATA.

Omitted under the reduced disclosure format permitted by General Instruction I(2)(a) of Form 10-K.

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

The following discussion of our financial condition and results ofoperations is provided as a supplement to, and should be read in conjunctionwith, our financial statements and the notes thereto includedelsewhere in this Annual Report on Form 10-K and the other sections of thisAnnual Report on Form 10-K, including Items 1 and 2 “Business and Properties.”

For additional information, including information regarding outlook, liquidity, capital resources, contractual obligations, and critical accounting policies, see the Annual Report on Form 10-K of our parent, Alon USA Energy, Inc., for the year ended December 31, 2013.

Forward-Looking Statements

Certain statements contained in this report and other materials we file with the SEC, 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,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “will,” “future” 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. See Item 1A “Risk Factors.”

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 spread between West Texas Intermediate (“WTI”) Cushing crude oil and Light Louisiana Sweet (“LLS”) crude oil;

• changes in the spread between WTI Cushing crude oil and WTI Midland crude oil;

• changes in the spread between Brent crude oil and WTI Cushing crude oil;

• changes in the spread between Brent crude oil and LLS crude oil;

• the effects of transactions involving forward contracts and derivative instruments;

• actions of customers and competitors;

• termination of our Supply and Offtake Agreement with J. Aron & Company (“J. Aron”), under which J. Aron is our largest supplier of crude oil and our largest customer of refined products. Additionally, we are obligated to repurchase all consigned inventories and certain other inventories upon termination of the Supply and Offtake Agreement;

• changes in fuel and utility costs incurred by our facility;

• 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;

• the effects of and cost of compliance with the Renewable Fuel Standard 2, including the availability, cost and price volatility of Renewable Identification Numbers;

• 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 such as flooding, casualty losses and other matters beyond our control;

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

• the other factors discussed in this Annual Report on Form 10-K 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.

Major Influences on Results of Operations

Our earnings and cash flows are primarily affected by the difference between refined product prices and the prices for crude oil and other feedstocks. These prices depend on numerous factors beyond our control, including the supply of, and demand for, crude oil, 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 government regulation. While our sales and operating revenues fluctuate significantly with movements in crude oil and refined product prices, it is the spread between crude oil and refined product prices, and not necessarily fluctuations in those prices, that affect our earnings.

In order to measure our operating performance, we compare our per barrel refinery operating margins to certain industry benchmarks. We compare our refinery’s per barrel operating margin to the Gulf Coast 2/1/1 crack spread. A Gulf Coast 2/1/1 crack spread is calculated assuming that two barrels of Light Louisiana Sweet (“LLS”) crude oil are converted into one barrel of Gulf Coast conventional gasoline and one barrel of Gulf Coast high sulfur diesel.

Our refinery has the capability to process substantial volumes of low-sulfur, or sweet, crude oils to produce a high percentage of light, high-value refined products. Sweet crude oil typically comprises 100% of our refinery’s crude oil input. This input is primarily comprised of LLS crude oil and WTI Midland priced crude oil.

In addition, 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 crude oil prices and enabled us to access an increased portion of our crude supply at discounted prices to Cushing. Moreover, by sourcing West Texas crude oils at Midland, we are able to eliminate the cost of transporting crude to and from Cushing. The WTI Cushing less WTI Midland spread represents the differential between the average value per barrel of WTI Cushing crude oil and the average value per barrel of WTI Midland crude oil. A widening of the WTI Cushing less WTI Midland spread can favorably influence the operating margin for our refinery.

Global product prices are influenced by the price of Brent crude which is a global benchmark crude. Global product prices set product prices in the U.S. As a result, our refinery is influenced by the spread between Brent crude and WTI Cushing. The Brent less WTI Cushing spread represents the differential between the average value per barrel of Brent crude oil and the average value per barrel of WTI Cushing crude oil. A widening of the spread between Brent and WTI Cushing can favorably influence our refinery operating margin.

Our refinery is also influenced by the spread between Brent crude and LLS. The Brent less LLS spread represents the differential between the average value per barrel of Brent crude oil and the average value per barrel of LLS crude oil. A widening of the spread between Brent and LLS can favorably influence our refinery operating margin.

Our results of operations are also significantly affected by our refinery’s operating costs, particularly the cost of natural gas used for fuel and the cost of electricity. Natural gas prices have historically been volatile. Typically, electricity prices fluctuate with natural gas prices.

Safety, reliability and the environmental performance of our refinery are critical to our financial performance. The financial impact of planned downtime, such as a turnaround or major maintenance project, is mitigated through a diligent planning process that considers expectations for product availability, margin environment and the availability of resources to perform the required maintenance.

Factors Affecting Comparability

Our financial condition and operating results over the three-year period ended December 31, 2013 have been influenced by the following factors, which are fundamental to understanding comparisons of our period-to-period financial performance.

Maintenance and Reduced Crude Oil Throughput

During the year ended December 31, 2013, crude oil throughput at our refinery was impacted by the unplanned shut down and repair of the reformer unit for approximately one month. Crude oil throughput was reduced at our refinery during the second quarter of 2011 due to flooding in Louisiana and its impact on crude oil supply to the refinery.

Certain Derivative Impacts

Included in cost of goods sold for the years ended December 31, 2013, 2012 and 2011 are gains of $23.9 million, losses of $116.0 million and gains of $30.0 million on commodity swaps, respectively.

Included in other income (loss), net in the statements of operations, are losses on heating oil call option crack spread contracts of $7.3 million and $36.3 million for the years ended December 31, 2012 and 2011, respectively.

Debt Related Transactions

In October 2013, Alon Energy made a $144.7 million capital contribution to us, which we used to redeem $140.0 million of the outstanding principal balance on the 13.50% senior secured notes, due October 2014.

Interest expense for the year ended December 31, 2013 includes $8.5 million for a prepayment premium and write-offs of unamortized original issuance discount and debt issuance costs related to this prepayment of a portion of our senior secured notes.

ALON REFINING KROTZ SPRINGS, INC.

Summary Financial Tables. The following table provides summary financial data and selected key operating statistics for the years endedDecember 31, 2013, 2012 and 2011. The following data should be read in conjunction with our financial statements and the notes thereto included elsewhere in this Annual Report on Form 10-K.

	Year Ended December 31,
	2013			2012			2011
	(dollars in thousands)
STATEMENT OF OPERATIONS DATA:
Net sales	$	2,680,112		$	2,881,242		$	2,533,092
Operating costs and expenses:
Cost of sales	2,510,720			2,790,998			2,433,910
Direct operating expenses	96,570			95,713			79,972
Selling, general and administrative expenses	8,870			7,828			6,827
Depreciation and amortization	26,565			23,882			22,645
Total operating costs and expenses	2,642,725			2,918,421			2,543,354
Loss on disposition of assets	—			(2,504		)	—
Operating income (loss)	37,387			(39,683		)	(10,262		)
Interest expense	(48,535		)	(44,417		)	(40,977		)
Other income (loss), net (1)	10			(7,289		)	(36,232		)
Loss before income tax benefit	(11,138		)	(91,389		)	(87,471		)
Income tax benefit	—			—			—
Net loss	$	(11,138	)	$	(91,389	)	$	(87,471	)
KEY OPERATING STATISTICS:
Per barrel of throughput:
Refinery operating margin (2)	$	6.16		$	8.30		$	3.05
Refinery direct operating expense (3)	4.09			3.85			3.67
OTHER DATA:
Capital expenditures	$	11,687		$	17,023		$	18,909
Capital expenditures for turnaround and chemical catalyst	3,513			1,163			2,649
PRICING STATISTICS:
Crack spreads (2/1/1) (per barrel):
Gulf Coast high sulfur diesel	$	7.89		$	11.29		$	7.00
WTI Cushing crude oil (per barrel)	$	97.97		$	94.14		$	95.07
Crude oil differentials (per barrel):
WTI Cushing less WTI Midland	$	2.59		$	2.88		$	0.53
LLS less WTI Cushing	11.06			16.46			16.76
Brent less LLS	2.22			0.79			(0.12		)
Brent less WTI Cushing	11.63			18.35			17.10
Product price (dollars per gallon):
Gulf Coast unleaded gasoline	$	2.70		$	2.82		$	2.75
Gulf Coast high sulfur diesel	2.87			2.99			2.91
Natural gas (per MMBtu)	3.73			2.83			4.03

	Year Ended December 31,
	2013			2012			2011
THROUGHPUT AND PRODUCTION DATA:	bpd	%		bpd	%		bpd	%
Refinery throughput:
WTI crude	29,580	45.7		20,111	29.6		—	—
Gulf Coast sweet crude	33,233	51.4		46,924	69.2		58,979	98.8
Blendstocks	1,892	2.9		842	1.2		741	1.2
Total refinery throughput (4)	64,705	100.0		67,877	100.0		59,720	100.0
Refinery production:
Gasoline	29,432	44.6		29,081	42.4		24,852	41.4
Diesel/jet	26,508	40.2		28,466	41.4		27,436	45.6
Heavy Oils	1,175	1.8		2,709	3.9		2,904	4.8
Other	8,857	13.4		8,464	12.3		4,914	8.2
Total refinery production (5)	65,972	100.0		68,720	100.0		60,106	100.0
Refinery utilization (6)		85.9	%		90.6	%		84.8	%

(1) Other income (loss), net for the years ended December 31, 2012 and 2011 is substantially the loss on heating oil call option crack spread contracts.

(2) Refinery operating margin is a per barrel measurement calculated by dividing the margin between net sales and cost of sales (exclusive of substantial hedge positions and certain inventory adjustments) by the refinery’s throughput volumes. Industry-wide refining results are driven 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.

The refinery operating margin for the years ended December 31, 2013, 2012 and 2011 excludes gains on commodity swaps of $23,900, losses on commodity swaps of $116,020 and gains on commodity swaps of $32,742, respectively.

(3) Refinery direct operating expense is a per barrel measurement calculated by dividing direct operating expenses at the refinery by the refinery’s total throughput volume.

(4) Total refinery throughput represents the total barrels per day of crude oil and blendstock inputs in the refinery production process. During the year ended December 31, 2013, crude oil throughput at the refinery was impacted by the unplanned shut down and repair of the reformer unit for approximately one month. Crude oil throughput was reduced during the second quarter of 2011 due to flooding in Louisiana and its impact on crude oil supply to the refinery.

(5) Total refinery production represents the barrels per day of various products produced from processing crude and other refinery feedstocks through the crude unit and other conversion units at the refinery.

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

Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012

Net Sales. Net sales were $2,680.1 million for the year ended December 31, 2013, compared to $2,881.2 million for the year ended December 31, 2012, a decrease of $201.1 million. This decrease was primarily due to lower refined product prices and reduced refinery throughput for the year ended December 31, 2013 compared to the year ended December 31, 2012. Refinery average throughput for the year ended December 31, 2013 was 64,705 bpd, compared to 67,877 bpd for the year ended December 31, 2012. The reduced refinery throughput reflects the impact of the unplanned shut down and repair of the reformer unit for approximately one month during 2013. The average per gallon price of Gulf Coast gasoline for the year ended December 31, 2013 decreased $0.12, or 4.3%, to $2.70, compared to $2.82 for the year ended December 31, 2012. The average per gallon price for Gulf Coast high sulfur diesel for the year ended December 31, 2013 decreased $0.12, or 4.0%, to $2.87, compared to $2.99 for the year ended December 31, 2012.

Cost of Sales. Cost of sales for the year ended December 31, 2013 were $2,510.7 million, compared to $2,791.0 million for the year ended December 31, 2012, a decrease of $280.3 million. This decrease was primarily due to commodity swaps and lower refinery throughput, partially offset by higher crude oil prices for the year ended December 31, 2013 compared to the year ended December 31, 2012. Gains on commodity swaps for the year ended December 31, 2013 were $23.9 million compared to losses on commodity swaps of $116.0 million for the year ended December 31, 2012. The average price per barrel of WTI Cushing for the year ended December 31, 2013 increased $3.83 per barrel to an average of $97.97 per barrel, or 4.1%, compared to an average of $94.14 for the year ended December 31, 2012.

Direct Operating Expenses. Direct operating expenses were $96.6 million for the year ended December 31, 2013, compared to $95.7 million for the year ended December 31, 2012, an increase of $0.9 million, or 0.9%. The increase was primarily due to higher natural gas costs.

Operating Income (Loss). Operating income was $37.4 million for the year ended December 31, 2013, compared to an operating loss of $39.7 million for the year ended December 31, 2012, an increase of $77.1 million. The increase was primarily due to gains on commodity swaps of $23.9 million for the year ended December 31, 2013 compared to losses on commodity swaps of $116.0 million for the year ended December 31, 2012, partially offset by reduced refinery operating margin.

The refinery operating margin was $6.16 per barrel for the year ended December 31, 2013, compared to $8.30 per barrel for the year ended December 31, 2012. This decrease was primarily due to lower Gulf Coast 2/1/1 high sulfur diesel crack spreads, a narrowing LLS to WTI Cushing spread as well as an unfavorable reduction in the location differential between WTI Cushing and WTI Midland during the year ended December 31, 2013. The average Gulf Coast 2/1/1 high sulfur diesel crack spread for the year ended December 31, 2013 was $7.89 per barrel, compared to $11.29 per barrel for the year ended December 31, 2012. The LLS to WTI Cushing spread decreased $5.40 per barrel to $11.06 per barrel for the year ended December 31, 2013, compared to $16.46 for the year ended December 31, 2012. The WTI Cushing to WTI Midland spread narrowed 10.1% to $2.59 per barrel for the year ended December 31, 2013, compared to $2.88 per barrel for the year ended December 31, 2012. Additionally, operating income and refinery operating margin were impacted by $4.4 million of costs related to environmental compliance obligations for the year ended December 31, 2013, which did not impact our refinery during 2012.

Interest Expense. Interest expense was $48.5 million for the year ended December 31, 2013, compared to $44.4 million for the year ended December 31, 2012, an increase of $4.1 million, or 9.2%. This increase was primarily due to a charge of $8.5 million for a prepayment premium and write-offs of unamortized original issuance discount and debt issuance costs recognized for the prepayment of a portion of our senior secured notes during the year ended December 31, 2013, partially offset by lower interest costs on the reduced balance of our outstanding debt obligations.

Other Income (Loss), Net. Other income (loss), net for the year ended December 31, 2012 was primarily attributable to the loss on heating oil call option crack spread contracts, which expired during 2012.

Net Loss. Net loss was $11.1 million for the year ended December 31, 2013, compared to $91.4 million for the year ended December 31, 2012, a decrease in loss of $80.3 million, or 87.9%. This decrease in loss was attributable to the factors discussed above.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from our operating activities, inventory supply and offtake arrangements, credit lines and additional funding from Alon Energy. Accounts payable to Alon Energy and its subsidiaries of $290.8 million at December 31, 2013, while due on demand, are expected to be paid as funds are available.

We have an agreement with J. Aron for the supply of crude oil that will support the operations our refinery, which substantially reduces our physical inventories and our associated 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.

Future operating results will depend on market factors, primarily the difference between the prices we receive from customers for produced products compared to the prices we pay to suppliers for crude oil. We plan to continue to operate the refinery at current or higher utilization rates as long as the refinery is able to generate cash operating margin. Management believes its current liquidity from the above described sources is adequate to operate the refinery.

We have senior secured notes due October 2014 with an outstanding balance (net of unamortized discount) of $75.7 million at December 31, 2013. We plan to repay this outstanding balance using cash from operating activities and funding from Alon Energy. As an alternative, we would consider the issuance of new debt to allow for the repayment of the outstanding senior secured notes balance.

Critical Accounting Policies

Our accounting policies are described in the notes to our audited financial statements included elsewhere in this Annual Report on Form 10-K. We prepare our 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 financial statements.

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. Market values of crude oil, refined products and blendstocks exceeded LIFO costs by $13.6 million and $14.0 million at December 31, 2013 and 2012, respectively.

Turnarounds and Chemical Catalyst 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 financial statements. Turnaround and catalyst costs are 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 chemical catalysts costs are presented in depreciation and amortization in our statements of operations.

Impairment of Long-Lived Assets. Our 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.

Deferred Income Taxes. Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Our results of operations are included in the consolidated U.S. Federal income tax return of Alon Energy. For financial reporting purposes, federal tax expense is allocated to us as if a separate return was filed.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Changes in commodity prices and purchased fuel prices are our primary sources of market risk. Alon Energy’s 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. In addition, we have entered into and regularly evaluate opportunities to provide us with a minimum fixed cash flow stream on the volume of products hedged during the hedge term and to protect against volatility on commodity prices.

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, 2013, we held approximately 0.5 million barrels of crude oil and product inventories valued under the LIFO valuation method. Market value exceeded carrying value of LIFO costs by $13.6 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 $0.5 million.

In accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 815, Derivatives and Hedging, we record all commodity futures contracts as assets or liabilities at fair value and any changes in fair value between periods is recorded in the profit and loss section of our 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 a commodity and a “short” represents an obligation to sell a commodity.

The following table provides information about our derivative commodity instruments as of December 31, 2013:

Description of Activity	Contract Volume (in barrels)		Wtd Avg Purchase Price/BBL		Wtd Avg Sales Price/BBL		Contract Value			Fair Value			Gain (Loss)
							(in thousands)
Forwards-long (Crude)	202,874		98.41		—		$	19,965		$	20,067		$	102
Forwards-short (Distillate)	(164,938	)	—		120.60		(19,892		)	(20,182		)	(290		)
Forwards-short (Gasoline)	(188,793	)	—		109.28		(20,631		)	(21,139		)	(508		)
Forwards-short (Jet)	(65,866	)	—		124.07		(8,172		)	(8,315		)	(143		)
Forwards-long (Slurry)	36,779		85.89		—		3,159			3,154			(5		)
Forwards-short (Catfeed)	(33,061	)	—		112.21		(3,710		)	(3,789		)	(79		)
Forwards-long (Slop)	11,876		87.89		—		1,044			1,050			6
Futures-short (Crude)	(58,000	)	—		97.87		(5,676		)	(5,708		)	(32		)
Futures-long (Gasoline)	206,000		114.94		—		23,677			24,104			427
Futures-long (Diesel)	199,000		127.67		—		25,406			25,618			212
Description of Activity	Contract Volume (in barrels)		Wtd Avg Contract Spread		Wtd Avg Market Spread		Contract Value			Fair Value			Gain (Loss)
							(in thousands)
Futures-swaps	5,760,000		$	21.20	$	25.87	$	(122,116	)	$	(149,013	)	$	(26,897	)

Interest Rate Risk

As of December 31, 2013, all of our outstanding debt was at fixed rates.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

The Financial Statements and Schedule are included as an annex of this Annual Report on Form 10-K. See the Index to Financial Statements and Schedule on page F-1.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING ANDFINANCIAL DISCLOSURE.

None.

ITEM 9A. CONTROLS AND PROCEDURES.

Disclosure Controls and Procedures

Our management has evaluated, with the participation of our principal executive and principal financial officers, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 as amended (the “Exchange Act”)) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or furnish under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms including, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or furnish under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosures.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate “internal control over financial reporting” (as defined in Rule 13a-15(f) under the Exchange Act) for Alon Refining Krotz Springs, Inc. Our management evaluated the effectiveness of our internal control over financial reporting as of December 31, 2013. In management’s evaluation, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (1992). Management believes that as of December 31, 2013, our internal control over financial reporting was effective based on those criteria.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the year ended December 31, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION.

None.

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PART III

Certain portions of Items 10, 11 and 12 of this Part III of Form 10-K have been omitted under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K.

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

Management

Our current directors and executive officers, their ages as of March 1, 2014, and their business experience during the past five years are set forth below:

Name	Age	Position
David Wiessman	59	Executive Chairman of the Board of Directors
Jeff D. Morris	62	Vice Chairman of the Board of Directors
Paul Eisman	58	Director, Chief Executive Officer and President
Shai Even	45	Director, Senior Vice President and Chief Financial Officer
Joseph A. Concienne, III	63	Director
Claire A. Hart	58	Senior Vice President
Alan Moret	59	Vice President of Supply
Michael Oster	42	Vice President of Mergers and Acquisitions
Gregg Byers	59	Vice President of Refining
Kyle McKeen	50	Vice President of Wholesale Marketing (Alon USA Partners, LP)

David Wiessman has served as Executive Chairman of our Board of Directors since July 2008. Mr. Wiessman has also 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. Wiessman has over 35 years of oil industry and marketing experience. Since 1994, Mr. Wiessman has been Chief Executive Officer, President and a director of Alon Israel Oil Company, Ltd., or Alon Israel, Alon Energy’s parent company. In 1992, Bielsol Investments (1987) Ltd. acquired a 50% interest in Alon Israel. In 1987, Mr. Wiessman became Chief Executive Officer of, and a stockholder in, Bielsol Investments (1987) Ltd. In 1976, after serving in the Israeli Air Force, he 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. Wiessman is also Executive Chairman of the Board of Directors of Blue Square-Israel, Ltd., which is listed on the New York Stock Exchange, or NYSE, and the Tel Aviv Stock Exchange, or TASE; Chairman of Blue Square Real Estate Ltd., which is listed on the TASE, and Executive Chairman of the Board and President of Dor-Alon Energy in Israel (1988) Ltd., which is listed on the TASE, and all of which are subsidiaries of Alon Israel.

Jeff D. Morris has served as our Vice Chairman of the Board of Directors since May 2011 and a director since July 2008. Mr. Morris also served as our Chief Executive Officer from July 2008 to May 2011 and as President from July 2008 until March 2010.  Mr. Morris has served as the Vice Chairman of the Board of Directors of Alon Energy since May 2011 and director since May 2005.  He also served as Alon Energy’s Chief Executive Officer from May 2005 to May 2011, Alon Energy’s Chief Executive Officer of its 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 South Eastern Business Unit from 1998 to 2000 and as Vice President of its South Western 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.

Paul Eisman was appointed to serve as our Chief Executive Officer in May 2011 and our President in March 2010 in connection with his appointments as Chief Executive Officer and President of Alon Energy. Prior to joining Alon Energy, Mr. Eisman was Executive Vice President, Refining & Marketing Operations at Frontier Oil Corporation from 2006 to 2009 and held various positions at KBC Advanced Technologies from 2003 to 2006, including Vice President of North American Operations. During 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.

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Shai Even is our Senior Vice President and Chief Financial Officer and has served as an officer since July 2008 and a director since May 2008. Mr. Even has also served as a Senior Vice President of Alon Energy since August 2008 and as Alon Energy’s Chief Financial Officer since December 2004. Mr. Even served as a Vice President of Alon Energy from May 2005 to August 2008 and Treasurer from August 2003 until March 2007.

Joseph A. Concienne, III has served as a director since July 2008 and served as our Vice President from July 2008 until his retirement in February 2011. Mr. Concienne also served as Senior Vice President of Refining of Alon Energy from August 2008 to February 2011and served as Senior Vice President of Refining and Transportation of Alon Energy from May 2007 to August 2008 and Vice President of Refining and Transportation of Alon Energy from March 2001 to May 2007. Prior to joining Alon Energy, Mr. Concienne served as Director of Operations/General Manager for PolyOne Corporation in Seabrook, Texas from 1998 to 2001. He served as Vice President/General Manager for Valero Refining and Marketing, Inc. in 1998, and as Manager of Refinery Operations and Refinery Manager for Phibro Energy Refining (now known as Valero Refining and Marketing, Inc.) from 1985 to 1998.

Claire A. Hart is our Senior Vice President and has served as an officer since July 2008. Mr. Hart has also served as Senior Vice President of Alon Energy since January 2004 and served as Alon Energy’s Chief Financial Officer and Vice President from August 2000 to January 2004. Prior to joining Alon Energy, he 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.

Alan Moret is our Vice President of Supply and has served as an officer since July 2008. Mr. Moret has also 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. 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.

Michael Oster is our Vice President of Mergers and Acquisitions and has served as an officer since August 2009. Mr. Oster has also served as Senior Vice President of Mergers and Acquisitions of Alon Energy since August 2008 and General Manager of Commercial Transactions of Alon Energy from January 2003 to August 2008. Prior to joining Alon Energy, Mr. Oster was a partner in the Israeli law firm, Yehuda Raveh and Co.

Gregg Byers has served as our Vice President of Refining since February 2012, with responsibility for operations at our refinery. Mr. Byers rejoined Alon Energy in September 2011 as Senior Director of Engineering Services.  Mr. Byers has been employed in the refining industry for over 35 years, most recently with Sinclair Oil Corporation as Operations Manager of Sinclair’s Wyoming refinery from 2008 to 2011. Prior to this, Mr. Byers served as Engineering & Project Development Director at our refinery under Alon Energy’s ownership in 2008 and Valero Energy Corporation’s ownership from 2001 to 2008.

Kyle McKeen is the Vice President of Wholesale Marketing of Alon USA Partners GP, LLC, the general partner of Alon USA Partners, LP, in August 2012 and has served as President and Chief Executive Officer of Alon Brands, Inc., our parent company’s subsidiary that manages retail 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.

Corporate Governance

We do not have an audit committee or a compensation committee. The executive officers of our parent company serve as members of our board of directors. Our executive officers are subject to the Corporate Governance Guidelines, Code of Business Conduct and Code of Ethics of our parent company. Copies of such documents are available free of charge through our parent’s website at www.alonusa.com. We do not have a separate website.

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ITEM 11. EXECUTIVE COMPENSATION.

The following table sets forth the name and title of our principal executive officer and principal financial officer and our three other most highly compensated executive officers, which we refer to as the named executive officers:

Name	Title
Paul Eisman	Chief Executive Officer and President
Shai Even	Senior Vice President and Chief Financial Officer
Michael Oster	Vice President of Mergers and Acquisitions
Alan Moret	Vice President of Supply
Kyle McKeen	Vice President of Marketing (Alon USA Partners, LP)

Our named executive officers are also executive officers and employees of our parent company and are compensated by our parent company in their capacities as such. See “Certain Relationships and Related Party Transactions.” We do not directly employ our named executive officers. Our parent company’s compensation committee establishes the base salary, bonus and other elements of compensation for its executive officers, and such determinations are not subject to approvals by our board of directors.

The objectives of our parent company’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 stockholders. In pursuing these objectives, our parent company’s compensation committee believes that compensation should reward executive officers and other employees for both their personal performance and the performance of our parent company and its subsidiaries.

Our parent company’s management provides compensation recommendations to its compensation committee. However, the final determination of a compensation package for the named executive officers is made solely by the compensation committee, except with respect to the compensation package of Mr. Eisman. The compensation package for Mr. Eisman is determined by Mr. Wiessman in consultation with our parent company’s board of directors. Our parent company does not currently engage any consultants relating to executive and/or director compensation practices.

Employment Agreements and Change of Control Arrangements

Paul Eisman. Our parent company is party to a Management Employment Agreement with Paul Eisman, the initial term of which is through March 1, 2015, and the term of which automatically renews for one-year terms unless terminated by either party. Mr. Eisman currently receives a base salary of $500,000 per year and is eligible for annual merit increases. Under his employment agreement, Mr. Eisman is entitled to participate in our parent company’s annual cash bonus plans, pension plan and benefits restoration plan. Additionally, our parent company is required to provide Mr. Eisman with additional benefits to the extent such benefits are made available to other employees, including disability, hospitalization, medical and retiree health benefits and life insurance. Mr. Eisman is subject to a covenant not to compete during the term of his employment. In the event that Mr. Eisman is terminated without cause (as defined in the agreement) or resigns upon at least 30 days’ prior written notice for good reason (as defined in the agreement), he will be entitled to receive his base salary through the termination date, the prorated share of his annual bonus and a severance payment equal to nine months’ base salary. This agreement also prohibits Mr. Eisman from disclosing our parent company’s proprietary information received through his employment.

Shai Even. Our parent company is party to an Executive Employment Agreement with Shai Even to serve for one-year terms upon automatic renewal each August 1st unless terminated by either party. Mr. Even currently receives a base salary of $323,700 per year and is eligible for annual merit increases. Under his employment agreement, Mr. Even is entitled to participate in our parent company’s annual cash bonus plans, pension plan and benefits restoration plan. Additionally, our parent company is required to provide Mr. Even with additional benefits to the extent such benefits are made available to other employees, including disability, hospitalization, medical and retiree health benefits and life insurance. Mr. Even is subject to a covenant not to compete during the term of his employment. In the event that Mr. Even is terminated without cause (as defined in the agreement) or resigns upon at least 30 days’ prior written notice for good reason (as defined in the agreement), he will be entitled to receive his base salary through the termination date, the prorated share of his annual bonus and a severance payment equal to nine months’ base salary. This agreement also prohibits Mr. Even from disclosing our parent company’s proprietary information received through his employment.

Michael Oster. Our parent company is party to a Management Employment Agreement with Michael Oster to serve for one-year terms upon automatic renewal each January 1st unless terminated by either party. Mr. Oster currently receives a base salary of $297,300 per year and is eligible for annual merit increases. Under his employment agreement, Mr. Oster is entitled to participate in our parent company’s annual cash bonus plans, pension plan and benefits restoration plan. Additionally, our

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parent company is required to provide Mr. Oster with additional benefits to the extent such benefits are made available to other employees, including disability, hospitalization, medical and retiree health benefits and life insurance. Mr. Oster is subject to a covenant not to compete during the term of his employment. In the event that Mr. Oster is terminated without cause (as defined in the agreement) or resigns upon at least 30 days’ prior written notice for good reason (as defined in the agreement), he will be entitled to receive his base salary through the termination date, the prorated share of his annual bonus and a severance payment equal to nine months’ base salary. This agreement also prohibits Mr. Oster from disclosing our parent company’s proprietary information received through his employment.

Alan Moret. Our parent company is party to an Employment Agreement with Alan Moret, the term of which automatically renews each November for one-year terms unless terminated by either party. Mr. Moret currently receives a base salary of $342,600 per year and is eligible for annual merit increases. Under his employment agreement, Mr. Moret is entitled to participate in our parent company’s annual cash bonus plans and a 401(k) plan with matching contribution from Alon of up to 6% of Mr. Moret’s base salary. Additionally, our parent company is required to provide Mr. Moret with additional benefits to the extent such benefits are made available to other employees, including disability, hospitalization, medical and retiree health benefits and life insurance. In the event that (i) Mr. Moret is terminated without cause (as defined in the agreement), (ii) our parent company does not elect to extend the employment term (as defined in the agreement) or (iii) Mr. Moret resigns upon at least 90 days’ prior written notice for good reason (as defined in the agreement), he will be entitled to receive any earned but unpaid annual bonus as of the date of termination for the previous year and a severance payment equal to four years’ base salary, provide that, he will receive an additional years’ base salary if our parent company terminates his employment prior to the then effective employment term. In the event that Mr. Moret’s employment is terminated due to death or disability (as defined in the agreement), he will be entitled to receive any earned but unpaid annual bonus as of the date of termination for the previous year, the prorated share of his annual bonus for the current year and a severance payment equal to four years’ base salary. This agreement also prohibits Mr. Moret from disclosing our parent company’s proprietary information received through his employment.

Kyle McKeen. Our parent company is a party to an Executive Employment Agreement with Kyle McKeen, the initial term of which was through May 1, 2013, and the term of which automatically renews for one-year terms unless terminated by either party. Mr. McKeen currently receives a base salary of $323,100 per year and is eligible for annual merit increases. Under his employment agreement, Mr. McKeen is entitled to participate in our parent company’s annual cash bonus plans, pension plan and benefits restoration plan. Additionally, our parent company is required to provide Mr. McKeen with additional benefits to the extent such benefits are made available to other employees, including disability, hospitalization, medical and retiree health benefits and life insurance. Mr. McKeen is subject to a covenant not to compete during the term of his employment. In the event that Mr. McKeen is terminated without Cause (as defined in the agreement) or resigns upon at least 30 days’ prior written notice for Good Reason (as defined in the agreement), he will be entitled to receive his base salary through the termination date, the prorated share of his annual bonus and a severance payment equal to twelve months’ base salary. This agreement also prohibits Mr. McKeen from disclosing our parent company’s proprietary information received through his employment.

Compensation of Directors

Our directors do not receive any compensation in respect of their services as directors of our company.

Compensation Committee Interlocks and Insider Participation

We do not have a compensation committee. Our parent company has a compensation committee consisting of Itzhak Bader and Ron Haddock, directors, and David Wiessman, its and our Executive Chairman of the Board. Our parent company’s compensation committee determines the compensation of the executive officers other than for Mr. Wiessman. Mr. Wiessman’s compensation is determined by our parent company’s board of directors, excluding Mr. Wiessman.

None of our executive officers, other than Mr. Wiessman, serves as a member of the board of directors or compensation committee of any entity that has one or more of its executive officers serving as a member of the board of directors. As described above, Mr. Wiessman serves as a member of the board of directors and compensation committee of our parent company, whose executive officers serve as members of our board of directors.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT ANDRELATED STOCKHOLDER MATTERS.

Omitted under the reduced disclosure format permitted by General Instruction I(2)(a) of Form 10-K.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.

Omitted under the reduced disclosure format permitted by General Instruction I(2)(a) of Form 10-K.

18

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.

Audit Fees. The aggregate fees billed by KPMG LLP (“KPMG”) for professional services rendered for the audit of our annual financial statements, the review of the financial statements included in our annual report on Form 10-K and quarterly reports on Form 10-Q were $0.2 million for the year ended December 31, 2013.

Audit-Related Fees. There were no fees billed by KPMG for assurance and related services related to the performance of audits or review of our financial statements and not described above under “Audit Fees” in 2013.

Tax Fees. No fees were billed by KPMG for professional services rendered for tax compliance, tax advice and tax planning in 2012.

All Other Fees. No fees were billed by KPMG for products and services not described above in 2013.

Pre-Approval Policies and Procedures. In general, all engagements of our outside auditors, whether for auditing or non-auditing services, must be pre-approved by the Board of Directors. During 2013, all of the services performed for us by KPMG were pre-approved by the Board of Directors. The Board of Directors has considered the compatibility of non-audit services with KPMG’s independence and believes the provision of such non-audit services is compatible with KPMG maintaining its independence.

19

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

The following documents are filed as part of this report:

1. Financial Statements. See “Index to Financial Statements” on page F-1.

2. Financial Statement Schedules and Other Financial Information. All financial statement schedules are omitted because either they are not applicable or the required information is included in the financial statements or notes included herein.

3. Exhibits. Exhibits filed as part of this Form 10-K are as follows:

Exhibit No.	Description
3.1	Certificate of Incorporation of Alon Refining Krotz Springs, Inc., as amended by the Certificate of Amendment to Certificate of Incorporation of Alon Refining Krotz Springs, Inc. (incorporated by reference to Exhibit 3.1 to Form S-4, filed by Alon Refining Krotz Springs, Inc. on December 22, 2009, SEC File No. 333-163942).
3.2	Amended and Restated Bylaws of Alon Refining Krotz Springs, Inc. (incorporated by reference to Exhibit 3.2 to Form S-4, filed by Alon Refining Krotz Springs, Inc. on December 22, 2009, SEC File No. 333-163942).
4.1	Indenture, dated as of October 22, 2009, by and among Alon Refining Krotz Springs, Inc. and Wilmington Trust FSB, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K, filed by Alon USA Energy, Inc. on October 23, 2009, SEC File No. 001-32567).
10.1	Stock Purchase Agreement, dated May 7, 2008, between Valero Refining and Marketing Company and Alon Refining Krotz Springs, Inc. (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by Alon USA Energy, Inc. on May 13, 2008, SEC File No. 001-32567).
10.2	First Amendment to Stock Purchase Agreement, dated as of July 3, 2008, by and among Valero Refining and Marketing Company, Alon Refining Krotz Springs, Inc. and Valero Refining Company-Louisiana (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by Alon USA Energy, Inc. on July 10, 2008, SEC File No. 001-32567).
10.3	Registration Rights Agreement, dated October 22, 2009, between Alon Refining Krotz Springs, Inc. and Jefferies & Company, Inc. (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by Alon USA Energy, Inc. on October 23, 2009, SEC File No. 001-32567).
10.4	Purchase Agreement, dated October 13, 2009, between Alon Refining Krotz Springs, Inc. and Jefferies & Co. (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by Alon USA Energy, Inc. on October 19, 2009, SEC File No. 001-32567).
10.5†	Offtake Agreement, dated as of July 3, 2008, by and between Valero Marketing and Supply Company and Alon Refining Krotz Springs, Inc. (incorporated by reference to Exhibit 10.5 to Form S-4/A, filed by Alon Refining Krotz Springs, Inc. on January 12, 2010, SEC File No. 333-163942).
10.6*	Executive Employment Agreement, dated as of July 31, 2000, between Jeff D. Morris and Alon USA GP, Inc., as amended by the Amendment to Executive/Management Employment Agreement, dated May 1, 2005 (incorporated by reference to Exhibit 10.23 to Form S-1, filed by Alon USA Energy, Inc. on May 11, 2005, SEC File No. 333-124797).
10.7*	Second Amendment to Executive Employment Agreement, dated as of November 4, 2008, between Jeff D. Morris and Alon USA GP, LLC (incorporated by reference to Exhibit 10.9 to Form 10-Q, filed by Alon USA Energy, Inc. on November 7, 2008, SEC File No. 001-32567).
10.8*	Executive Employment Agreement between Jeff D. Morris and Alon USA Energy, Inc., dated May 3, 2011, (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by Alon USA Energy, Inc. on May 6, 2011, SEC File No. 001-32567).
10.9*	Management Employment Agreement, dated as of March 1, 2010, between Paul Eisman and Alon USA GP, LLC. (incorporated by reference to Exhibit 10.22 to Form 10-K, filed by Alon USA Energy, Inc. on March 15, 2011 SEC File No. 001-32567).
10.10*	Agreement of Principles of Employment, dated as of December 22, 2009, between David Wiessman and Alon USA Energy, Inc. (incorporated by reference to Exhibit 10.44 to Form 10-K, filed by Alon USA Energy, Inc. on March 13, 2012, SEC File No. 001-32567).
10.11*	Amended and Restated Employment Agreement by and between Paramount Petroleum Corporation and Alan P. Moret, dated July 8, 2011 (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by Alon USA Energy, Inc. on July 13, 2011, SEC File No. 001-32567).
10.12*	Executive Employment Agreement, dated as of August 1, 2003, between Shai Even and Alon USA GP, LLC (incorporated by reference to Exhibit 10.49 to Form 10-K, filed by Alon USA Energy, Inc. on March 15, 2007, SEC File No. 001-32567).

20

Exhibit No.	Description
10.13*	Amendment to Executive Employment Agreement, dated as of November 4, 2008, between Shai Even and Alon USA GP, LLC. (incorporated by reference to Exhibit 10.14 to Form 10-Q, filed by Alon USA Energy, Inc. on November 7, 2008, SEC File No. 001-32567).
10.14*	Management Employment Agreement, dated as of October 30, 2008, between Michael Oster and Alon USA GP, LLC (incorporated by reference to Exhibit 10.71 to Form 10-K, filed by Alon USA Energy, Inc. on April 10, 2009, SEC File No. 001-32567).
10.15*	Description of Annual Bonus Plans (incorporated by reference to Exhibit 10.2 to Form 10-Q, filed by Alon USA Energy, Inc. on May 6, 2008, SEC File No. 001-32567).
10.16*	Change of Control Incentive Bonus Program (incorporated by reference to Exhibit 10.29 to Form S-1, filed by Alon USA Energy, Inc. on May 11, 2005, SEC File No. 333-124797).
10.17*	Form of Officer Indemnification Agreement (incorporated by reference to Exhibit 10.32 to Form S-1, filed by Alon USA Energy, Inc. on May 11, 2005, SEC File No. 333-124797).
10.18*	Form of Director and Officer Indemnification Agreement (incorporated by reference to Exhibit 10.33 to Form S-1, filed by Alon USA Energy, Inc. on May 11, 2005, SEC File No. 333-124797).
10.19*	Alon USA Energy, Inc. Amended and Restated 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by Alon USA Energy, Inc. on May 7, 2010, SEC File No. 001-32567).
10.20*	Form of Restricted Stock Award Agreement relating to Director Grants pursuant to Section 12 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by Alon USA Energy, Inc. on August 5, 2005, SEC File No. 001-32567).
10.21*	Form of Restricted Stock Award Agreement relating to Participant Grants pursuant to Section 8 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by Alon USA Energy, Inc. on August 23, 2005, SEC File No. 001-32567).
10.22*	Form II of Restricted Stock Award Agreement relating to Participant Grants pursuant to Section 8 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.3 to Form 8-K, filed by Alon USA Energy, Inc. on November 8, 2005, SEC File No. 001-32567).
10.23*	Form of Appreciation Rights Award Agreement relating to Participant Grants pursuant to Section 7 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by Alon USA Energy, Inc. on March 12, 2007, SEC File No. 001-32567).
10.24*	Form of Amendment to Appreciation Rights Award Agreement relating to Participant Grants pursuant to Section 7 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by Alon USA Energy, Inc. on January 27, 2010, SEC File No. 001-32567).
10.25*	Form II of Appreciation Rights Award Agreement relating to Participant Grants pursuant to Section 7 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by Alon USA Energy, Inc. on January 27, 2010, SEC File No. 001-32567).
10.26*	Award Agreement between Alon USA Energy, Inc. and Paul Eisman, dated May 5, 2011, (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by Alon USA Energy, Inc. on May 9, 2011, SEC File No. 001-32567).
10.27*	Form of Award Agreement relating to Executive Officer Restricted Stock Grants pursuant to the Alon USA Energy, Inc. 2005 Amended and Restated Incentive Compensation Plan (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by Alon USA Energy, Inc. on May 9, 2011, SEC File No. 001-32567).
10.28	Credit Agreement, dated May 28, 2010, by and between Alon Refining Krotz Springs, Inc. and Goldman Sachs Bank USA, as Issuing Bank (incorporated by reference to Exhibit 10.5 to Form 10-Q, filed by Alon USA Energy, Inc. on August 9, 2010, SEC File No. 001-32567).
10.29	First Amendment, dated as of July 31, 2012, to the Credit Agreement, dated May 28, 2010, by and between Alon Refining Krotz Springs, Inc. and Goldman Sachs Bank USA, as Issuing Bank (incorporated by reference to Exhibit 10.7 to Form 10-Q, filed by Alon USA Energy, Inc., on August 9, 2012, SEC File No. 001-32567).
10.30	Second Amendment to Credit Agreement, dated as of July 31, 2013, to the Credit Agreement, dated May 28, 2010, by and between Alon Refining Krotz Springs, Inc., and Goldman Sachs Bank USA, as Issuing Bank (incorporated by reference to Exhibit 10.1 to Form 10-Q, filed by the Company on August 14, 2013, SEC File No. 333-163942).
10.31	Amended and Restated Supply and Offtake Agreement, dated May 26, 2010 by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.76 to Form 10-K, filed by Alon USA Energy, Inc. on March 14, 2014, SEC File No. 001-32567).
10.32	First Amendment to the Supply and Offtake Agreement, dated January 20, 2011, by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.2 to Form 10-Q, filed by the Company on May 10, 2011, SEC File No. 333-163942).

21

Exhibit No.	Description
10.33	Amended and Restated Second Amendment to the Supply and Offtake Agreement, dated March 1, 2011, by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.3 to Form 10-Q, filed by the Company on May 10, 2011, SEC File No. 333-163942).
10.34	Supplemental Agreement to Supply and Offtake Agreement, dated October 31, 2011, between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.1 to Form 10-Q, filed by the Company on November 7, 2011, SEC File No. 333-163942).
10.35	Amendment, dated as of July 20, 2012, to the Amended and Restated Supply and Offtake Agreement, dated May 26, 2010, by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.80 to Form 10-K, filed by Alon USA Energy, Inc., on March 14, 2014, SEC File No. 001-32567).
10.36	Amendment, dated as of February 1, 2013, to the Amended and Restated Supply and Offtake Agreement, dated May 26, 2010, by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.1 to Form 10-Q, filed by the Company on May 15, 2013, SEC File No. 333-163942).
10.37	Product Offtake Agreement between Alon Refining Krotz Springs, Inc., and BP Products North America, Inc., dated July 1, 2013 (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on July 8, 2013, SEC File No. 333-163942).
10.38	Product Offtake Agreement between Alon Refining Krotz Springs, Inc., and Valero Marketing and Supply Company, dated July 1, 2013 (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on July 8, 2013, SEC File No. 333-163942).
31.1	Certifications of Chief Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
31.2	Certifications of Chief Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002.
101	The following financial information from Alon Refining Krotz Springs, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2013, formatted in XBRL (Extensible Business Reporting Language): (i) Balance Sheets, (ii) Statements of Operations, (iii) Statements of Comprehensive Loss, (iv) Statement of Stockholders’ Equity, (v) Statements of Cash Flows and (vi) Notes to Financial Statements.

____________

*	Identifies management contracts and compensatory plans or arrangements.
†	Portions of the exhibit have been omitted pursuant to a request for confidential treatment. The confidential portions have been furnished to the SEC.

22

ALON REFINING KROTZ SPRINGS, INC.

INDEX TO FINANCIAL STATEMENTS

	Page
Audited Financial Statements:
Report of Independent Registered Public Accounting Firm	F-2
Balance Sheets as of December 31, 2013 and 2012	F-3
Statements of Operations for the Years Ended December 31, 2013, 2012 and 2011	F-4
Statements of Comprehensive Loss for the Years Ended December 31, 2013, 2012 and 2011	F-5
Statement of Stockholders’ Equity for the Years Ended December 31, 2013, 2012 and 2011	F-6
Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011	F-7
Notes to Financial Statements	F-8

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Alon Refining Krotz Springs, Inc.:

We have audited the accompanying balance sheets of Alon Refining Krotz Springs, Inc. as of December 31, 2013 and 2012, and the related statements of operations, comprehensive loss, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these 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 financial statements referred to above present fairly, in all material respects, the financial position of Alon Refining Krotz Springs, Inc. as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.

/s/KPMG LLP

Dallas, Texas

March 26, 2014

ALON REFINING KROTZ SPRINGS, INC.

BALANCE SHEETS

(dollars in thousands, except per share data)

	As of December 31,
	2013			2012
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	1,107
Accounts and other receivables, net	30,431			38,412
Inventories	37,906			44,796
Prepaid expenses and other current assets	315			2,354
Total current assets	68,652			86,669
Property, plant and equipment, net	333,599			343,321
Other assets, net	16,600			22,368
Total assets	$	418,851		$	452,358
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	355,732		$	380,329
Accrued liabilities	29,784			12,499
Current portion of long term debt	75,684			—
Total current liabilities	461,200			392,828
Other non-current liabilities	37,039			29,436
Long-term debt	—			211,573
Total liabilities	498,239			633,837
Commitments and contingencies (Note 15)
Stockholders’ equity:
Class A Common stock, par value $0.01, 75,000 shares authorized: 50,111 shares issued and outstanding at December 31, 2013 and 2012	—			—
Class B Common stock, par value $0.01, 1,000 shares authorized; 90 shares issued and outstanding at December 31, 2013 and 2012	—			—
Accumulated other comprehensive income (loss), net of income tax	(29,982		)	1,514
Additional paid-in capital	312,381			167,656
Retained deficit	(361,787		)	(350,649		)
Total stockholders’ equity	(79,388		)	(181,479		)
Total liabilities and stockholders’ equity	$	418,851		$	452,358

ALON REFINING KROTZ SPRINGS, INC.

STATEMENTS OF OPERATIONS

(dollars in thousands)

	Year Ended December 31,
	2013			2012			2011
Net sales	$	2,680,112		$	2,881,242		$	2,533,092
Operating costs and expenses:
Cost of sales	2,510,720			2,790,998			2,433,910
Direct operating expenses	96,570			95,713			79,972
Selling, general and administrative expenses	8,870			7,828			6,827
Depreciation and amortization	26,565			23,882			22,645
Total operating costs and expenses	2,642,725			2,918,421			2,543,354
Loss on disposition of assets	—			(2,504		)	—
Operating income (loss)	37,387			(39,683		)	(10,262		)
Interest expense	(48,535		)	(44,417		)	(40,977		)
Other income (loss), net	10			(7,289		)	(36,232		)
Loss before income tax benefit	(11,138		)	(91,389		)	(87,471		)
Income tax benefit	—			—			—
Net loss	$	(11,138	)	$	(91,389	)	$	(87,471	)

F-2

ALON REFINING KROTZ SPRINGS, INC.

STATEMENTS OF COMPREHENSIVE LOSS

(dollars in thousands)

	Year Ended December 31,
	2013			2012			2011
Net loss	$	(11,138	)	$	(91,389	)	$	(87,471	)
Other comprehensive income (loss):
Commodity contracts designated as cash flow hedges:
Unrealized holding loss arising during period	(9,475		)	(67,318		)	—
(Gain) loss reclassified to earnings - cost of sales	(22,021		)	68,832			—
Net gain (loss), before tax	(31,496		)	1,514			—
Total other comprehensive income (loss), before tax	(31,496		)	1,514			—
Income tax expense (benefit) related to other comprehensive income (loss)	—			—			—
Total other comprehensive income (loss), net of tax	(31,496		)	1,514			—
Comprehensive loss	$	(42,634	)	$	(89,875	)	$	(87,471	)

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

F-3

ALON REFINING KROTZ SPRINGS, INC.

STATEMENT OF STOCKHOLDERS’ EQUITY

(dollars in thousands)

	Common Stock		Additional Paid-In Capital		Accumulated Other Comprehensive Income (Loss)			Retained Deficit			Total
Balance at December 31, 2010	$	—	$	167,656	$	—		$	(171,789	)	$	(4,133	)
Net loss	—		—		—			(87,471		)	(87,471		)
Balance at December 31, 2011	—		167,656		—			(259,260		)	(91,604		)
Net loss	—		—		—			(91,389		)	(91,389		)
Fair value of commodity swaps, net of tax of $0	—		—		1,514			—			1,514
Balance at December 31, 2012	—		167,656		1,514			(350,649		)	(181,479		)
Capital contribution from parent	—		144,725		—			—			144,725
Net loss	—		—		—			(11,138		)	(11,138		)
Fair value of commodity swaps, net of tax of $0	—		—		(31,496		)	—			(31,496		)
Balance at December 31, 2013	$	—	$	312,381	$	(29,982	)	$	(361,787	)	$	(79,388	)

ALON REFINING KROTZ SPRINGS, INC. STATEMENTS OF CASH FLOWS (dollars in thousands)
	Year Ended December 31,
	2013			2012			2011
Cash flows from operating activities:
Net loss	$	(11,138	)	$	(91,389	)	$	(87,471	)
Adjustments to reconcile net loss to cash provided by operating activities:
Depreciation and amortization	26,565			23,882			22,645
Amortization of debt issuance costs	2,188			2,246			2,044
Amortization of original issuance discount	2,240			2,249			1,946
Write-off of unamortized original issuance discount	1,871			—			—
Write-off of unamortized debt issuance costs	1,871			—			—
Loss on disposition of assets	—			2,504			—
Unrealized (gain) loss on commodity swaps	(3,085		)	31,936			(31,936		)
Changes in operating assets and liabilities:
Accounts and other receivables, net	5,694			(32,593		)	(756		)
Inventories	6,890			(6,439		)	(19,796		)
Prepaid expenses and other current assets	2,039			(1,856		)	1,460
Other assets, net	—			—			484
Accounts payable	(24,597		)	99,518			128,070
Accrued liabilities	2,730			(6,444		)	5,099
Other non-current liabilities	(3,966		)	(4,727		)	6,566
Net cash provided by operating activities	9,302			18,887			28,355
Cash flows from investing activities:
Capital expenditures	(11,621		)	(17,023		)	(18,909		)
Capital expenditures for turnarounds and catalysts	(3,513		)	(1,163		)	(2,649		)
Earnout payments related to refinery acquisition	—			—			(6,562		)
Proceeds from sale of assets	—			20			—
Net cash used in investing activities	(15,134		)	(18,166		)	(28,120		)
Cash flows from financing activities:
Deferred debt issuance costs	—			—			(126		)
Payments on long-term debt	(140,000		)	—			—
Proceeds from parent capital contribution	144,725			—			—
Net cash provided by (used in) financing activities	4,725			—			(126		)
Net increase (decrease) in cash and cash equivalents	(1,107		)	721			109
Cash and cash equivalents, beginning of period	1,107			386			277
Cash and cash equivalents, end of period	$	—		$	1,107		$	386
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest	$	44,202		$	39,322		$	36,987

(1) Description and Nature of Business

As used in this report, the terms “the Company,” “we,” “us” or “our” refer to Alon Refining Krotz Springs, Inc., a subsidiary of Alon USA Energy, Inc. (“Alon Energy”). References in this report to “Alon Energy” or “Parent” refer collectively to Alon USA Energy, Inc. and any of its subsidiaries, other than Alon Refining Krotz Springs, Inc.

We own and operate a high conversion crude oil refinery placed into service in 1980 located in Krotz Springs, Louisiana with a crude oil throughput capacity of approximately 74,000 barrels per day (“bpd”). We refine crude oil into petroleum products, including gasoline, light distillates and intermediate products.

Our refinery is strategically located on approximately 381 acres on the Atchafalaya River in central Louisiana at the intersection of two crude oil pipeline systems and has direct access to the Colonial products pipeline system (“Colonial Pipeline”), providing us with diversified access to both locally sourced and foreign crude oils, as well as distribution of our products to markets throughout the Southern and Eastern United States and along the Mississippi and Ohio Rivers. In industry terms, our refinery is characterized as a “mild residual cracking refinery,” which generally refers to a refinery utilizing vacuum distillation and catalytic cracking processes in addition to basic distillation and naphtha reforming processes to minimize low quality black oil production and to produce higher light product yields such as gasoline, light distillates and intermediate products.

(2) Basis of Presentation and Certain Significant Accounting Policies

(a) Basis of Presentation and Use of Estimates

The financial statements include the accounts of Alon Refining Krotz Springs, Inc. and have been prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”), which 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 financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

(b) Revenue Recognition

Substantially all of our 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). Generally, title 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).

We occasionally enter 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 statements of operations and profits are recognized when the exchanged product is sold.

Revenue from our inventory financing agreement (Note 4) is reported on a gross basis as we are considered a principal in this agreement.

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 statements of operations.

(c) Cost Classifications

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

Direct operating expenses include costs associated with the actual operations of the refinery, such as energy and utility costs, routine maintenance, labor, insurance and environmental compliance costs.

Selling, general and administrative expenses consist primarily of corporate overhead and marketing expenses. These costs also include actual costs incurred by Alon Energy and allocated to us.

Interest expense consists of interest expense, letters of credit, financing costs associated with crude oil purchases, financing fees, and both the amortization and write-off of original issuance discount and deferred debt issuance costs but excludes capitalized interest.

(d) 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.

(e) Accounts Receivable

Financial instruments that potentially subject us to concentration of credit risk consist primarily of trade accounts receivables. Credit is extended based on evaluation of the customer’s financial condition and in certain circumstances, collateral, such as letters of credit, prepayments or guarantees, are required, as management deems appropriate. Credit losses are charged to allowance for doubtful accounts when deemed uncollectible. Reserve for bad debts is based on a combination of current sales and specific identification methods.

(f) 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.

Crude oil inventory consigned to others represents inventory that was sold to third parties, which we are obligated to repurchase at the end of the respective agreements (Note 4). 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.

(g) Hedging Activity

All derivative instruments are recorded in the balance sheets as either assets or liabilities measured at their fair value. We consider all commodity forwards, futures, swaps, and option contracts to be part of our risk management strategy. For commodity derivative contracts not designated as cash flow hedges, the net unrealized gains and losses for changes in fair value are recognized in cost of sales or in other income (loss), net on the statements of operations.

We selectively designate certain commodity derivative contracts as cash flow hedges. The effective portion of the gains or losses associated with these derivative contracts designated and qualifying as cash flow hedges are initially recorded in accumulated other comprehensive income (loss) in the balance sheet and reclassified into the statement of operations in the period in which the underlying hedged forecasted transaction affects income. The amounts recorded into the statement of operations for commodity derivative contracts are recognized as cost of sales. The ineffective portion of the gains or losses on the derivative contracts, if any, is recognized in the statement of operations as it is incurred.

Derivative transactions related to the inventory financing agreement have been designated as a fair value hedge of inventory. The gain or loss on the derivative instrument designated and qualifying as a fair value hedge, as well as the offsetting gain or loss on the hedged item attributable to the hedged risk, is recognized in earnings in the same period.

(h) 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. We capitalize 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 as a gain or loss on disposition of assets in the statements of operations.

(i) Impairment of Long-Lived Assets and Assets to be Disposed Of

We review long-lived assets and certain identifiable intangible assets 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.

(j) Asset Retirement Obligations

The accounting standards established for asset retirement obligations require companies to recognize the 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.

We have asset retirement obligations with respect to our 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 our 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 of these assets, we 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.

(k) Turnarounds and Chemical Catalysts 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 the balance sheets. Turnaround and catalyst costs are 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 chemical catalyst costs are presented in depreciation and amortization in the statements of operations.

(l) Income Taxes

Our results of operations are included in the consolidated U.S. Federal income tax return of Alon Energy. For financial reporting purposes, federal tax expense is allocated to us as if a separate return was filed.

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

(m) Environmental Expenditures

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. Environmental liabilities represent the estimated costs to investigate and remediate contamination at our 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.

Costs of future expenditures for environmental remediation obligations are not discounted to their present value unless payments are fixed or reliably 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.

Substantially all amounts accrued are expected to be paid out over the next five years. The level of future expenditures for environmental remediation obligations is impossible to determine with any degree of reliability.

(n) Other Comprehensive Income (Loss)

Other comprehensive income (loss) consists of gains and losses affecting stockholders’ equity that, under U.S. GAAP, are excluded from net loss, such as gains and losses related to certain derivative instruments in qualifying hedging relationships. The balance in other comprehensive income (loss), net of tax, reported in the statement of stockholders’ equity consists of the fair value of commodity derivative contract adjustments.

(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. Recoveries of environmental remediation costs from third parties, which are probable of realization, are separately recorded as assets, and are not offset against the related environmental liability.

(p) Intangible Assets

Intangible assets are assets that lack physical substance (excluding financial assets). Intangible assets with indefinite useful lives are not amortized and intangible assets with finite useful lives are amortized on a straight-line basis over 1 to 40 years. Intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. We use December 31 of each year as the valuation date for annual impairment testing purposes.

(3) Operating Results and Liquidity

Our refinery average throughput was 64,705 bpd for the year ended December 31, 2013. Cash flow from operating activities for the year ended December 31, 2013 was $9,302.

Our primary sources of liquidity are cash generated from our operating activities, inventory supply and offtake arrangements, other credit lines and additional funding from Alon Energy. Accounts payable to Alon Energy and its subsidiaries of $290,785 at December 31, 2013, while due on demand, are expected to be paid as funds are available. Future operating results will depend on market factors, primarily the difference between the prices we receive from customers for produced products compared to the prices we pay to suppliers for crude oil. We plan to continue to operate the refinery at current or higher utilization rates as long as the refinery is able to generate cash operating margin. Management believes its current liquidity from the above described sources is adequate to operate the refinery.

We have senior secured notes due October 2014 with an outstanding balance (net of unamortized discount) of $75,684 at December 31, 2013. We plan to repay this outstanding balance using cash from operating activities and funding from Alon Energy. As an alternative, we would consider the issuance of new debt to allow for the repayment of the outstanding senior secured notes balance.

(4) Inventory Financing Agreement

We have entered into a Supply and Offtake Agreement and other associated agreements (together 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 us, and we agreed to buy from J. Aron, at market prices, crude oil for processing at the refinery and (ii) we agreed to sell, and J. Aron agreed to buy, at market prices, certain refined products produced at the refinery.

The Supply and Offtake Agreement also provided for the sale, at market prices, of our 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 our refinery, and to identify prospective purchasers of refined products on J. Aron’s behalf. The Supply and Offtake Agreement was amended in February 2013 and has an initial term that expires in May 2019. J. Aron may elect to terminate the Supply and Offtake Agreement prior to the initial term beginning in May 2016 and upon each anniversary thereof, on six months prior notice. We may elect to terminate in May 2018 on six months prior notice.

Following the 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 refinery.

At December 31, 2013 and 2012, we had net current payables to J. Aron for purchases of $32,081 and $48,311, respectively, and other non-current liabilities related to the original financing of $24,022 and $28,016, respectively, and a consignment receivable representing a deposit paid to J. Aron of $6,206 and $6,206, respectively.

Additionally, we had current payables of $990 and current receivables of $1,565 at December 31, 2013 and 2012, respectively, for forward commitments related to month-end consignment inventory target levels differing from projected levels and the associated pricing with these inventory level differences.

In association with the Supply and Offtake Agreement, we entered into a secured Credit Agreement (the “Standby LC Facility”) by and between the Company, as Borrower, and Goldman Sachs Bank USA, as Issuing Bank. The Standby LC Facility provides for up to $200,000 of letters of credit to be issued to J. Aron. Obligations under the Standby LC Facility are secured by a first priority lien on the existing and future accounts receivable and inventory of the Company. The Standby LC Facility includes customary events of default and restrictions on our activities. The Standby LC Facility contains no maintenance financial covenants. At this time there is no further availability under the Standby LC Facility. In August 2013, we amended the Standby LC Facility to extend the maturity date to July 2016.

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

F-4

ALON REFINING KROTZ SPRINGS, INC.

NOTES TO FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

(5) Fair Value

We 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. We classify financial assets and financial liabilities into the following fair value hierarchy:

• Level 1 -     valued based on quoted prices in active markets for identical assets and liabilities;

• Level 2 -     valued based on quoted prices for similar assets and liabilities in active markets, and inputs other than quoted prices that are observable for the asset or liability; and

• Level 3 -     valued based on unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.

As required, we utilize 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. We generally apply 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 carrying amounts of our 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 instruments are carried at fair value, which are based on quoted market prices. Derivative instruments are our only financial assets and liabilities measured at fair value on a recurring basis.

The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, in the balance sheets at December 31, 2013 and 2012:

	Level 1		Level 2		Level 3		Total
As of December 31, 2013
Liabilities:
Commodity contracts (futures and forwards)	$	310	$	—	$	—	$	310
Commodity contracts (swaps)	—		15,328		11,569		26,897
Fair value hedge	—		2,676		—		2,676
As of December 31, 2012
Assets:
Commodity contracts (futures and forwards)	$	386	$	—	$	—	$	386
Commodity contracts (swaps)	—		1,514		—		1,514
Liabilities:
Fair value hedge	—		346		—		346

Level 3 Financial Instruments

We have commodity price swap contracts that relate to forecasted sales of jet fuel and forecasted purchases of crude oil for which quoted forward market prices are not readily available. The forward rate used to value these commodity price swaps was derived using a projected forward rate using quoted market rates for similar products, adjusted for product grade differentials, a Level 3 input.

F-5

ALON REFINING KROTZ SPRINGS, INC.

NOTES TO FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

The following table presents the changes in fair value of our Level 3 assets and liabilities (all related to commodity price swap contracts) for the year ended December 31, 2013:

	Year Ended
	December 31, 2013
Balance at beginning of period	$	—
Change in fair value of Level 3 trades open at the beginning of the period	—
Fair value of trades entered into during the period - Recognized in other comprehensive income (loss)	(11,569		)
Fair value of reclassification from Level 3 to Level 2	—
Settlement value of contractual maturities - Recognized in cost of sales	—
Balance at end of period	$	(11,569	)

(6) Derivative Financial Instruments

Mark-to-Market

Commodity Derivatives. We selectively utilize crude oil and refined product commodity derivative contracts to reduce the risk associated with potential price changes on committed obligations. We do not speculate using derivative instruments. Credit risk on our 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 of certain refining inventories and firm commitments to purchase inventories. The gain or loss on a derivative instrument designated and qualifying as a fair value hedge, as well as the offsetting gain or loss on the hedged item attributable to the hedged risk, is recognized in earnings in the same period.

As of December 31, 2013, we have accounted for certain commodity contracts as fair value hedges with contract purchase volumes of 272 thousand barrels of crude oil with remaining contract terms through May 2019.

Cash Flow Hedges

To designate a derivative as a cash flow hedge, we document at the inception of the hedge the assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative and the item hedged. If, during the term of the derivative, the hedge is determined to be no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings when the underlying transactions occur.

As of December 31, 2013, we have accounted for certain commodity swap contracts as cash flow hedges with total contract purchase volumes of 5,760 thousand barrels of crude oil and contract sales volumes of 5,760 thousand barrels of refined products with a remaining contract term of twenty-four months. Related to these transactions in Other Comprehensive Income (“OCI”), we recognized unrealized losses of $31,496 and unrealized gains of $1,514 for the years ended December 31, 2013 and 2012, respectively. There were no amounts reclassified from OCI into cost of sales as a result of the discontinuance of cash flow hedge accounting.

In November 2013, we elected to de-designate certain commodity swap contracts that were previously designated as cash flow hedges. Consequently, hedge accounting was discontinued prospectively for the commodity swap contracts and all changes in fair value were recorded in cost of sales in the statements of operations. As of December 31, 2013, we had unrealized losses of $29,982 classified in OCI that related to the application of hedge accounting prior to de-designation that will be recorded into earnings as the forecasted transactions occur during the year ended December 31, 2014. The commodity derivative contracts were subsequently re-designated as cash flow hedges as of December 31, 2013 on a product basis.

For the year ended December 31, 2013, there was $1,879 of hedge ineffectiveness recognized in cost of sales. For the year ended December 31, 2012, there was no hedge ineffectiveness recognized in income. No component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness.

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

	As of December 31, 2013
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives not designated as hedging instruments:
Commodity contracts (futures and forwards)	Accounts receivable	$	607	Accrued liabilities	$	(917	)
Total derivatives not designated as hedging instruments		$	607		$	(917	)
Derivatives designated as hedging instruments:
Commodity contracts (swaps)		$	—	Accrued liabilities	$	(15,328	)
Commodity contracts (swaps)		—		Other non-current liabilities	(11,569		)
Fair value hedge		—		Other non-current liabilities	(2,676		)
Total derivatives designated as hedging instruments		—			(29,573		)
Total derivatives		$	607		$	(30,490	)

	As of December 31, 2012
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives not designated as hedging instruments:
Commodity contracts (futures and forwards)	Accounts receivable	$	386		$	—
Total derivatives not designated as hedging instruments		$	386		$	—
Derivatives designated as hedging instruments:
Commodity contracts (swaps)	Accounts receivable	$	2,287	Accrued liabilities	$	(773	)
Fair value hedge		—		Other non-current liabilities	(346		)
Total derivatives designated as hedging instruments		2,287			(1,119		)
Total derivatives		$	2,673		$	(1,119	)

The following tables present the effect of derivative instruments on the statements of operations and accumulated other comprehensive income:

Derivatives designated as hedging instruments:

Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI			Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)				Gain (Loss) Reclassified from Accumulated OCI into Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
				Location	Amount			Location	Amount
For the Year Ended December 31, 2013
Commodity contracts (swaps)	$	(31,496	)	Cost of sales	$	23,900		Cost of sales	$	(1,879	)
Total derivatives	$	(31,496	)		$	23,900			$	(1,879	)
For the Year Ended December 31, 2012
Commodity contracts (swaps)	$	1,514		Cost of sales	$	(68,832	)		$	—
Total derivatives	$	1,514			$	(68,832	)		$	—

Derivatives in fair value hedging relationships:

		Gain (Loss) Recognized in Income
		Year Ended December 31,
	Location	2013			2012			2011
Fair value hedge	Cost of sales	$	(2,330	)	$	(346	)	$	—
Total derivatives		$	(2,330	)	$	(346	)	$	—

Derivatives not designated as hedging instruments:

		Gain (Loss) Recognized in Income
		Year Ended December 31,
	Location	2013			2012			2011
Commodity contracts (futures & forwards)	Cost of sales	$	(2,143	)	$	4,431		$	10,837
Commodity contracts (swaps)	Cost of sales	4,964			(47,188		)	30,040
Commodity contracts (call options)	Other income (loss), net	—			(7,297		)	(36,280		)
Total derivatives		$	2,821		$	(50,054	)	$	4,597

Offsetting Assets and Liabilities

Our derivative financial instruments are subject to master netting arrangements to manage counterparty credit risk associated with derivatives and we offset the fair value amounts recorded for derivative instruments to the extent possible under these agreements on our balance sheets.

The following table presents offsetting information regarding our derivatives by type of transaction as of December 31, 2013 and 2012:

	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts offset in the Statement of Financial Position			Net Amounts of Assets (Liabilities) Presented in the Statement of Financial Position			Gross Amounts Not offset in the Statement of Financial Position					Net Amount
										Financial Instruments			Cash Collateral Pledged
As of December 31, 2013
Commodity Derivative Assets:
Futures & forwards	$	747		$	(140	)	$	607		$	(607	)	$	—	$	—
Commodity Derivative Liabilities:
Futures & forwards	$	(1,057	)	$	140		$	(917	)	$	607		$	—	$	(310	)
Swaps	(26,897		)	—			(26,897		)	—			—		(26,897		)
Fair value hedge	(2,676		)	—			(2,676		)	—			—		(2,676		)
As of December 31, 2012
Commodity Derivative Assets:
Futures & forwards	$	2,446		$	(2,060	)	$	386		$	—		$	—	$	386
Swaps	4,756			(2,469		)	2,287			(773		)	—		1,514
Commodity Derivative Liabilities:
Futures & forwards	$	(2,060	)	$	2,060		$	—		$	—		$	—	$	—
Swaps	(3,242		)	2,469			(773		)	773			—		—
Fair value hedge	(346		)	—			(346		)	—			—		(346		)

(7) Accounts Receivable

Financial instruments that potentially subject us to concentration of credit risk consist primarily of trade accounts receivables and commodity derivative contracts. Credit risk is minimized as a result of the credit quality of our customer base. We perform ongoing credit evaluations of our customers and require letters of credit, prepayments or other collateral or guarantees as we deem appropriate. Valero Energy Corporation (“Valero”), BP Products North America, Inc. (“BP”) and J. Aron accounted for substantially all of our net sales for the year ended December 31, 2013. The allowance for doubtful accounts is reflected as a reduction of accounts receivable in the balance sheets. The balance in the allowance account was zero at December 31, 2013 and 2012.

As part of the Supply and Offtake Agreement, there is a net out arrangement. Additionally, product sales to parties other than J. Aron are primarily collected when the sale occurs. As a result of these arrangements, we have minimal trade accounts receivable balances at December 31, 2013 and 2012.

(8) Inventories

Carrying value of inventories consisted of the following:

	As of December 31,
	2013		2012
Crude oil, refined products and blendstocks	$	11,710	$	12,268
Crude oil inventory consigned to others (Note 4)	22,545		29,656
Materials and supplies	3,651		2,872
Total inventories	$	37,906	$	44,796

Market values of crude oil, refined products and blendstock inventories exceeded LIFO costs by $13,600 and $14,013 at December 31, 2013 and 2012, respectively.

(9) Property, Plant and Equipment, Net

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

	As of December 31,
	2013			2012
Refining facilities	$	441,152		$	429,531
Accumulated depreciation	(107,553		)	(86,210		)
Property, plant and equipment, net	$	333,599		$	343,321

The useful lives of refining facilities used to determine depreciation expense were 3 to 20 years with an average life of 18 years.

Capitalized interest for the years ended December 31, 2013, 2012 and 2011 was $3,093, $1,574 and $555, respectively. Depreciation expense for the years ended December 31, 2013, 2012 and 2011 was $21,343, $20,261 and $19,899, respectively.

(10) Additional Financial Information

The tables that follow provide additional financial information related to the financial statements.

(a) Other Assets, Net

	As of December 31,
	2013		2012
Deferred turnaround and chemical catalyst cost	$	7,585	$	9,251
Deferred debt issuance costs	826		4,885
Intangible assets	1,983		2,026
Long-term receivables	6,206		6,206
Total other assets	$	16,600	$	22,368

(b) Accrued Liabilities, Other Non-Current Liabilities and Accounts Payable

	As of December 31,
	2013		2012
Accrued Liabilities:
Taxes other than income taxes	$	568	$	1,670
Employee costs	1,280		1,460
Commodity contracts	16,245		773
Accrued finance charges	3,597		7,439
Other	8,094		1,157
Total accrued liabilities	$	29,784	$	12,499
Other Non-Current Liabilities:
Environmental accrual (Note 15)	$	271	$	319
Asset retirement obligations	1,177		1,101
Consignment inventory obligation	24,022		28,016
Commodity contracts	11,569		—
Total other non-current liabilities	$	37,039	$	29,436

Accounts payable includes related parties balance of $290,785 and $294,060 at December 31, 2013 and 2012, respectively.

F-6

ALON REFINING KROTZ SPRINGS, INC.

NOTES TO FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

(11) Income Taxes

Our results of operations are included in the consolidated U.S. Federal income tax return of our parent, Alon Energy. For financial reporting purposes, federal tax expense is allocated to us as if a separate return was filed. The amounts presented below were calculated as if we filed separate federal and state income tax returns. We had no unrecognized tax benefits as of December 31, 2013.

A reconciliation between the income tax benefit computed on pretax loss at the statutory federal rate and the actual provision for income tax benefit is as follows:

	Year Ended December 31,
	2013			2012			2011
Computed tax benefit	$	(3,898	)	$	(31,986	)	$	(30,615	)
State and local income taxes, net of federal benefit	(678		)	(1,444		)	(3,130		)
Other, net	618			836			1,005
Change in valuation allowance	3,958			32,594			32,740
Income tax benefit	$	—		$	—		$	—

The following table sets forth the tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities:

	As of December 31,
	2013			2012
Deferred income tax assets:
Accrued liabilities and other	$	481		$	482
Non-current accrued liabilities and other	3,907			2,506
Net operating loss carryover	204,276			191,626
Deferred income tax assets	208,664			194,614
Less: Valuation allowance	(134,251		)	(130,293		)
Net deferred income tax assets	$	74,413		$	64,321
Deferred income tax liabilities:
Unrealized gains	$	971		$	92
Property, plant and equipment	70,428			60,489
Other non-current	2,285			2,997
Intangibles	729			743
Deferred income tax liabilities	$	74,413		$	64,321
Net deferred income tax after valuation allowance	$	—		$	—

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the level of taxable income and projections for future taxable income, over the periods which the deferred tax assets are deductible, management believes it is more likely than not that we will realize the benefits of these deductible differences, net of the existing valuation allowance at December 31, 2013.

We performed a review of our tax positions in accordance with ASC Subtopic 740-10, Income Taxes, and determined we have no unrecognized tax benefits. We have elected to recognize interest expense related to the underpayment of income taxes in interest expense, and penalties relating to underpayment of income taxes as a reduction to other income (loss), net, in the statements of operations.

F-7

ALON REFINING KROTZ SPRINGS, INC.

NOTES TO FINANCIAL STATEMENTS — (Continued)

(dollars in thousands, except as noted)

(12) Indebtedness

Debt consisted of the following:

	As of December 31,
	2013		2012
Senior secured notes, net of discount	$	75,684	$	211,573

(a) Senior Secured Notes

In October 2009, we issued 13.50% senior secured notes (the “Senior Secured Notes”) in aggregate principal amount of $216,500 in a private offering. In February 2010, we exchanged $216,480 of Senior Secured Notes for an equivalent amount of Senior Secured Notes (“Exchange Notes”) registered under the Securities Act of 1933. The Exchange Notes will mature in October 2014 and the entire principal amount is due at maturity. Interest is payable semi-annually in arrears on April 15 and October 15. The Exchange Notes are substantially identical to the Senior Secured Notes, except that the Exchange Notes have been registered with the Securities and Exchange Commission and are not subject to transfer restrictions. The Senior Secured Notes were issued at an offering price of 94.857% and we received gross proceeds of $205,365 (before fees and expenses related to the offering).

The terms of the Senior Secured Notes are governed by an indenture (the “Indenture”) and the obligations under the Indenture are secured by a first priority lien on our property, plant and equipment and a second priority lien on the our cash, accounts receivable and inventory.

The Indenture also contains restrictive covenants such as restrictions on loans, mergers, sales of assets, additional indebtedness and restricted payments. The Indenture does not contain any maintenance financial covenants.

In October 2013, Alon Energy made a $144,725 capital contribution to us, which we used to redeem $140,000 of the outstanding principal balance on the Senior Secured Notes. As a result of the prepayment of the Senior Secured Notes, a prepayment premium of $4,725 and write-offs of unamortized original issuance discount and debt issuance costs of $1,871 and $1,871, respectively, were charged to interest expense in the statements of operations for the year ended December 31, 2013.

At December 31, 2013, the Senior Secured Notes, due October 2014, had an outstanding balance (net of unamortized discount) of $75,684, included in current portion of long-term debt. At December 31, 2012, the Senior Secured Notes had an outstanding balance (net of unamortized discount) of $211,573, included in long-term debt. We are utilizing the effective interest method to amortize the original issue discount over the life of the Senior Secured Notes.

(b) Interest and Financing Expense

Interest and financing expense included the following:

	Year Ended December 31,
	2013			2012			2011
Interest expense	$	25,399		$	29,228		$	29,228
Letters of credit and finance charges	13,334			12,268			8,314
Amortization of debt issuance costs	2,188			2,246			2,044
Write-off of debt issuance costs	1,871			—			—
Amortization of original issuance discount	2,240			2,249			1,946
Write-off of original issuance discount	1,871			—			—
Prepayment premium	4,725			—			—
Capitalized interest	(3,093		)	(1,574		)	(555		)
Total interest expense	$	48,535		$	44,417		$	40,977

(13) Related Party Transactions

Since the acquisition of our refinery from Valero, we have received equity contributions in the amount of $312,381 from Alon Energy. The most recent contributions were $144,725 received in 2013, which we used to redeem $140,000 of the outstanding principal balance on the Senior Secured Notes.

Alon Israel Oil Company, Ltd. (“Alon Israel”) provided letters of credit to us of $15,000. In December 2012, the amount was reduced by $12,500 and in December 2013, the letter of credit was canceled. For the years endedDecember 31, 2013, 2012 and 2011, we recorded interest expense related to these letters of credit of $96, $600 and $600, respectively.

We are a subsidiary of Alon Energy and we are 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 our executive officers as well as Alon Energy’s other subsidiaries. Alon Energy performs general corporate and administrative services and functions for us 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 in performing these services to us and to its other subsidiaries based primarily on the amount of time the individuals performing such services devote to our business and affairs relative to the amount of time they devote to the business and affairs of Alon Energy’s other subsidiaries. We record the amount of such allocations in our financial statements as selling, general and administrative expenses. Our share of Alon Energy’s selling, general and administrative expenses were $8,870, $7,828 and $6,827, for the years ended December 31, 2013, 2012 and 2011, respectively.

Alon Energy currently owns all of our outstanding voting capital stock. As a result, Alon Energy can control the election of our directors, exercise control or significant influence over our corporate and management policies and generally determine the outcome of any corporate transaction or other matter submitted to our stockholders for approval, including potential mergers or acquisitions, asset sales and other significant corporate transactions. So long as Alon Energy continues to own a majority of the outstanding shares of our voting capital stock, Alon Energy will continue to be able to effectively control or influence the outcome of such matters.

(14) Employee Benefit Plans

Our employees are included in the various employee benefit plans of Alon Energy. These plans include qualified, non-contributory defined benefit retirement plans, defined contribution plans, employee and retiree medical, dental, and life insurance plans, incentive plans (i.e., stock options, restricted stock, and bonuses), and other such benefits. For the purposes of these financial statements, we are considered to be participating in multi-employer benefit plans of Alon Energy.

Our allocated share of Alon Energy’s employee benefit plan expenses, excluding costs related to the incentive plans was $2,095, $1,403 and $2,024for the years endedDecember 31, 2013, 2012 and 2011, respectively.

Employee benefit plan expenses incurred by us are included in direct operating expenses with the related payroll costs.

(15) Commitments and Contingencies

(a) Leases

We have long-term lease commitments for land, buildings and equipment. In most cases, we expect that in the normal course of business, our leases will be renewed or replaced by other leases. We have commitments under long-term operating leases for certain land, buildings and equipment expiring at various dates over the next fifteen years. Certain long-term operating leases relating to buildings and land include options to renew for additional periods. At December 31, 2013, minimum lease payments on operating leases were as follows:

Year ending December 31:
2014	$	561
2015	502
2016	452
2017	313
2018	60
2019 and thereafter	597
Total	$	2,485

Total rental expense was $3,508, $3,144 and $3,475for the years endedDecember 31, 2013, 2012 and 2011, respectively. Contingent rentals and subleases were not significant.

(b) Other Commitments

In the normal course of business, we have long-term commitments to purchase, at market prices, utilities such as natural gas, electricity and water for use by the refinery. We are 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.

Supply and Offtake Agreements

In July 2013, we entered into offtake agreements with Valero and BP that provides for the sale, at market prices, of light cycle oil and high sulfur distillate blendstock through June 2015. Both agreements will automatically extend for successive one year terms unless either we or the other party cancels the agreement by delivering written notice of termination to the other at least 180 days prior to the end of the then current term.

(c) Contingencies

We are involved in various legal actions arising in the ordinary course of business. We believe the ultimate disposition of these matters will not have a material effect on our financial position, results of operations or liquidity.

(d) Environmental

We are subject to loss contingencies pursuant to federal, state, and local environmental laws and regulations. These laws and regulations govern the discharge of materials into the environment and may require us 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 and to compensate others for damage to property and natural resources. These contingent obligations relate to sites that we own and are associated with past or present operations. We are currently participating in environmental investigations, assessments and cleanups pertaining to our refinery. We may be involved in additional future environmental investigations, assessments and cleanups. The magnitude of future costs are unknown and will depend on factors such as the nature and contamination at many sites, the timing, extent and method of the remedial actions which may be required, and the determination of our liability in proportion to other responsible parties.

We have accrued a non-current liability for environmental remediation obligations of $271 and $319 at December 31, 2013 and 2012, respectively.

(16) Renewable Fuel Standard

We are obligated by government regulations under the Renewable Fuel Standard 2 (“RFS2”) to blend a certain percentage of biofuels into the products we produce that are consumed in the U.S. We will purchase biofuels from third parties and blend those biofuels into our products, and each gallon of biofuel purchased includes a Renewable Identification Number (“RIN”). To the degree we are unable to blend biofuels at the required percentage, a RINs deficit is generated and we must acquire that number of RINs by the annual reporting deadline in order to remain in compliance with applicable regulations.

We are exposed to market risk related to the volatility in the price of credits needed to comply with these governmental and regulatory programs. We will manage this risk by purchasing biofuel credits when prices are deemed favorable.

We received an exemption from the RFS2 requirements for the year ended December 31, 2013. We were not subject to the RFS2 requirements for the years ended December 31, 2012 and 2011.

F-8

EXHIBITS

Exhibit No.	Description
3.1	Certificate of Incorporation of Alon Refining Krotz Springs, Inc., as amended by the Certificate of Amendment to Certificate of Incorporation of Alon Refining Krotz Springs, Inc. (incorporated by reference to Exhibit 3.1 to Form S-4, filed by Alon Refining Krotz Springs, Inc. on December 22, 2009, SEC File No. 333-163942).
3.2	Amended and Restated Bylaws of Alon Refining Krotz Springs, Inc. (incorporated by reference to Exhibit 3.2 to Form S-4, filed by Alon Refining Krotz Springs, Inc. on December 22, 2009, SEC File No. 333-163942).
4.1	Indenture, dated as of October 22, 2009, by and among Alon Refining Krotz Springs, Inc. and Wilmington Trust FSB, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K, filed by Alon USA Energy, Inc. on October 23, 2009, SEC File No. 001-32567).
10.1	Stock Purchase Agreement, dated May 7, 2008, between Valero Refining and Marketing Company and Alon Refining Krotz Springs, Inc. (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by Alon USA Energy, Inc. on May 13, 2008, SEC File No. 001-32567).
10.2	First Amendment to Stock Purchase Agreement, dated as of July 3, 2008, by and among Valero Refining and Marketing Company, Alon Refining Krotz Springs, Inc. and Valero Refining Company-Louisiana (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by Alon USA Energy, Inc. on July 10, 2008, SEC File No. 001-32567).
10.3	Registration Rights Agreement, dated October 22, 2009, between Alon Refining Krotz Springs, Inc. and Jefferies & Company, Inc. (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by Alon USA Energy, Inc. on October 23, 2009, SEC File No. 001-32567).
10.4	Purchase Agreement, dated October 13, 2009, between Alon Refining Krotz Springs, Inc. and Jefferies & Co. (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by Alon USA Energy, Inc. on October 19, 2009, SEC File No. 001-32567).
10.5†	Offtake Agreement, dated as of July 3, 2008, by and between Valero Marketing and Supply Company and Alon Refining Krotz Springs, Inc. (incorporated by reference to Exhibit 10.5 to Form S-4/A, filed by Alon Refining Krotz Springs, Inc. on January 12, 2010, SEC File No. 333-163942).
10.6*	Executive Employment Agreement, dated as of July 31, 2000, between Jeff D. Morris and Alon USA GP, Inc., as amended by the Amendment to Executive/Management Employment Agreement, dated May 1, 2005 (incorporated by reference to Exhibit 10.23 to Form S-1, filed by Alon USA Energy, Inc. on May 11, 2005, SEC File No. 333-124797).
10.7*	Second Amendment to Executive Employment Agreement, dated as of November 4, 2008, between Jeff D. Morris and Alon USA GP, LLC (incorporated by reference to Exhibit 10.9 to Form 10-Q, filed by Alon USA Energy, Inc. on November 7, 2008, SEC File No. 001-32567).
10.8*	Executive Employment Agreement between Jeff D. Morris and Alon USA Energy, Inc., dated May 3, 2011, (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by Alon USA Energy, Inc. on May 6, 2011, SEC File No. 001-32567).
10.9*	Management Employment Agreement, dated as of March 1, 2010, between Paul Eisman and Alon USA GP, LLC. (incorporated by reference to Exhibit 10.22 to Form 10-K, filed by Alon USA Energy, Inc. on March 15, 2011 SEC File No. 001-32567).
10.10*	Agreement of Principles of Employment, dated as of December 22, 2009, between David Wiessman and Alon USA Energy, Inc. (incorporated by reference to Exhibit 10.44 to Form 10-K, filed by Alon USA Energy, Inc. on March 13, 2012, SEC File No. 001-32567).
10.11*	Amended and Restated Employment Agreement by and between Paramount Petroleum Corporation and Alan P. Moret, dated July 8, 2011 (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by Alon USA Energy, Inc. on July 13, 2011, SEC File No. 001-32567).
10.12*	Executive Employment Agreement, dated as of August 1, 2003, between Shai Even and Alon USA GP, LLC (incorporated by reference to Exhibit 10.49 to Form 10-K, filed by Alon USA Energy, Inc. on March 15, 2007, SEC File No. 001-32567).
10.13*	Amendment to Executive Employment Agreement, dated as of November 4, 2008, between Shai Even and Alon USA GP, LLC. (incorporated by reference to Exhibit 10.14 to Form 10-Q, filed by Alon USA Energy, Inc. on November 7, 2008, SEC File No. 001-32567).
10.14*	Management Employment Agreement, dated as of October 30, 2008, between Michael Oster and Alon USA GP, LLC (incorporated by reference to Exhibit 10.71 to Form 10-K, filed by Alon USA Energy, Inc. on April 10, 2009, SEC File No. 001-32567).
10.15*	Description of Annual Bonus Plans (incorporated by reference to Exhibit 10.2 to Form 10-Q, filed by Alon USA Energy, Inc. on May 6, 2008, SEC File No. 001-32567).
10.16*	Change of Control Incentive Bonus Program (incorporated by reference to Exhibit 10.29 to Form S-1, filed by Alon USA Energy, Inc. on May 11, 2005, SEC File No. 333-124797).

10.17*	Form of Officer Indemnification Agreement (incorporated by reference to Exhibit 10.32 to Form S-1, filed by Alon USA Energy, Inc. on May 11, 2005, SEC File No. 333-124797).
10.18*	Form of Director and Officer Indemnification Agreement (incorporated by reference to Exhibit 10.33 to Form S-1, filed by Alon USA Energy, Inc. on May 11, 2005, SEC File No. 333-124797).
10.19*	Alon USA Energy, Inc. Amended and Restated 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by Alon USA Energy, Inc. on May 7, 2010, SEC File No. 001-32567).
10.20*	Form of Restricted Stock Award Agreement relating to Director Grants pursuant to Section 12 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by Alon USA Energy, Inc. on August 5, 2005, SEC File No. 001-32567).
10.21*	Form of Restricted Stock Award Agreement relating to Participant Grants pursuant to Section 8 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by Alon USA Energy, Inc. on August 23, 2005, SEC File No. 001-32567).
10.22*	Form II of Restricted Stock Award Agreement relating to Participant Grants pursuant to Section 8 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.3 to Form 8-K, filed by Alon USA Energy, Inc. on November 8, 2005, SEC File No. 001-32567).
10.23*	Form of Appreciation Rights Award Agreement relating to Participant Grants pursuant to Section 7 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by Alon USA Energy, Inc. on March 12, 2007, SEC File No. 001-32567).
10.24*	Form of Amendment to Appreciation Rights Award Agreement relating to Participant Grants pursuant to Section 7 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by Alon USA Energy, Inc. on January 27, 2010, SEC File No. 001-32567).
10.25*	Form II of Appreciation Rights Award Agreement relating to Participant Grants pursuant to Section 7 of the Alon USA Energy, Inc. 2005 Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by Alon USA Energy, Inc. on January 27, 2010, SEC File No. 001-32567).
10.26*	Award Agreement between Alon USA Energy, Inc. and Paul Eisman, dated May 5, 2011, (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by Alon USA Energy, Inc. on May 9, 2011, SEC File No. 001-32567).
10.27*	Form of Award Agreement relating to Executive Officer Restricted Stock Grants pursuant to the Alon USA Energy, Inc. 2005 Amended and Restated Incentive Compensation Plan (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by Alon USA Energy, Inc. on May 9, 2011, SEC File No. 001-32567).
10.28	Credit Agreement, dated May 28, 2010, by and between Alon Refining Krotz Springs, Inc. and Goldman Sachs Bank USA, as Issuing Bank (incorporated by reference to Exhibit 10.5 to Form 10-Q, filed by Alon USA Energy, Inc. on August 9, 2010, SEC File No. 001-32567).
10.29	First Amendment, dated as of July 31, 2012, to the Credit Agreement, dated May 28, 2010, by and between Alon Refining Krotz Springs, Inc. and Goldman Sachs Bank USA, as Issuing Bank (incorporated by reference to Exhibit 10.7 to Form 10-Q, filed by Alon USA Energy, Inc., on August 9, 2012, SEC File No. 001-32567).
10.30	Second Amendment to Credit Agreement, dated as of July 31, 2013, to the Credit Agreement, dated May 28, 2010, by and between Alon Refining Krotz Springs, Inc., and Goldman Sachs Bank USA, as Issuing Bank (incorporated by reference to Exhibit 10.1 to Form 10-Q, filed by the Company on August 14, 2013, SEC File No. 333-163942).
10.31	Amended and Restated Supply and Offtake Agreement, dated May 26, 2010 by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.76 to Form 10-K, filed by Alon USA Energy, Inc. on March 14, 2014, SEC File No. 001-32567).
10.32	First Amendment to the Supply and Offtake Agreement, dated January 20, 2011, by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.2 to Form 10-Q, filed by the Company on May 10, 2011, SEC File No. 333-163942).
10.33	Amended and Restated Second Amendment to the Supply and Offtake Agreement, dated March 1, 2011, by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.3 to Form 10-Q, filed by the Company on May 10, 2011, SEC File No. 333-163942).
10.34	Supplemental Agreement to Supply and Offtake Agreement, dated October 31, 2011, between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.1 to Form 10-Q, filed by the Company on November 7, 2011, SEC File No. 333-163942).
10.35	Amendment, dated as of July 20, 2012, to the Amended and Restated Supply and Offtake Agreement, dated May 26, 2010, by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.80 to Form 10-K, filed by Alon USA Energy, Inc., on March 14, 2014, SEC File No. 001-32567).
10.36	Amendment, dated as of February 1, 2013, to the Amended and Restated Supply and Offtake Agreement, dated May 26, 2010, by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company (incorporated by reference to Exhibit 10.1 to Form 10-Q, filed by the Company on May 15, 2013, SEC File No. 333-163942).

10.37	Product Offtake Agreement between Alon Refining Krotz Springs, Inc., and BP Products North America, Inc., dated July 1, 2013 (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Company on July 8, 2013, SEC File No. 333-163942).
10.38	Product Offtake Agreement between Alon Refining Krotz Springs, Inc., and Valero Marketing and Supply Company, dated July 1, 2013 (incorporated by reference to Exhibit 10.2 to Form 8-K, filed by the Company on July 8, 2013, SEC File No. 333-163942).
31.1	Certifications of Chief Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
31.2	Certifications of Chief Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002.
101	The following financial information from Alon Refining Krotz Springs, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2013, formatted in XBRL (Extensible Business Reporting Language): (i) Balance Sheets, (ii) Statements of Operations, (iii) Statements of Comprehensive Loss, (iv) Statement of Stockholders’ Equity, (v) Statements of Cash Flows and (vi) Notes to Financial Statements.

____________

*	Identifies management contracts and compensatory plans or arrangements.
†	Portions of the exhibit have been omitted pursuant to a request for confidential treatment. The confidential portions have been furnished to the SEC.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date:	March 26, 2014	By:	/s/ Paul Eisman
			Paul Eisman
			Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date:	March 26, 2014	By:	/s/ David Wiessman
			David Wiessman
			Executive Chairman
Date:	March 26, 2014	By:	/s/ Paul Eisman
			Paul Eisman
			Chief Executive Officer, President and Director
Date:	March 26, 2014	By:	/s/ Shai Even
			Shai Even
			Senior Vice President, Chief Financial Officer and Director
			(Principal Accounting Officer)
Date:	March 26, 2014	By:	/s/ Jeff D. Morris
			Jeff D. Morris
			Director
Date:	March 26, 2014	By:	/s/ Joseph A. Concienne III
			Joseph A. Concienne III
			Director

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Paul Eisman, certify that:

1. I have reviewed this Annual Report on Form 10-K of Alon Refining Krotz Springs, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	March 26, 2014	By:	/s/ Paul Eisman
			Paul Eisman
			Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Shai Even, certify that:

1. I have reviewed this Annual Report on Form 10-K of Alon Refining Krotz Springs, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	March 26, 2014	By:	/s/ Shai Even
			Shai Even
			Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. §1350,

AS ADOPTED PURSUANT TO §906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the filing of the Annual Report on Form 10-K of Alon Refining Krotz Springs, Inc., a Delaware corporation (the “Company”), for the period ended December 31, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned officers of the Company certifies, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that, to such officer's knowledge:

1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods expressed in the Report.

Date:	March 26, 2014	By:	/s/ Paul Eisman
			Paul Eisman
			Chief Executive Officer
Date:	March 26, 2014	By:	/s/ Shai Even
			Shai Even
			Chief Financial Officer

XML

Derivative Financial Instruments (Textuals) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash Flow Hedges - Commodity Derivatives:
Maximum Length of Time Hedged in Cash Flow Hedge	24 months
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before tax	$ (31,496)	$ 1,514	$ 0
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	29,982
Gain (Loss) on Cash Flow Hedge Ineffectiveness, Net	$ 1,879
Fair Value Hedging [Member]
Cash Flow Hedges - Commodity Derivatives:
Derivative, Nonmonetary Notional Amount	272,000
Cash Flow Hedging [Member]
Cash Flow Hedges - Commodity Derivatives:
Derivative, Nonmonetary Notional Amount	5,760,000

XML

Indebtedness Long-Term Debt (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Senior secured notes, net of discount	$ 75,684	$ 211,573

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Property, Plant and Equipment, Net (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment, Net [Line Items]
Refining facilities	$ 441,152	$ 429,531
Accumulated depreciation	(107,553)	(86,210)
Property, plant and equipment, net	$ 333,599	$ 343,321

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Indebtedness Indebtedness (Textuals) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	13.50%
Issuance Price, Percentage	94.857%
Debt Instrument, Gross Proceeds	$ 205,365
Proceeds from Contributions from Parent	144,725	0	0
Early Repayment of Senior Debt	140,000
Prepayment premium	4,725	0	0
Write-off of original issuance discount	1,871	0	0
Write-off of unamortized debt issuance costs	1,871	0	0
Senior Notes	75,684	211,573
Senior Secured Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	216,500
Exchange Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 216,480

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Inventories (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Inventory Disclosure [Abstract]
Crude oil, refined products, asphalt and blendstocks	$ 11,710	$ 12,268
Crude oil inventory consigned to others	22,545	29,656
Materials and supplies	3,651	2,872
Total inventories	$ 37,906	$ 44,796

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Commitments and Contingencies Future Minimum Lease Payments (Tables)

12 Months Ended

Dec. 31, 2013

Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]

Future Minimum Lease Payments [Table Text Block]

At December 31, 2013, minimum lease payments on operating leases were as follows:

Year ending December 31:
2014	$	561
2015	502
2016	452
2017	313
2018	60
2019 and thereafter	597
Total	$	2,485

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Related Party Transactions (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]
Proceeds from Contributions from Affiliates	$ 312,381
Proceeds from Contributions from Parent	144,725	0	0
Early Repayment of Senior Debt	140,000
Related Party Transaction, Expenses from Transactions with Related Party	8,870	7,828	6,827
Alon Israel [Member]
Related Party Transaction [Line Items]
Line of Credit Facility, Capacity Available for Specific Purpose Other than for Trade Purchases		15,000
Repayments of Lines of Credit		12,500
Interest Expense, Related Party	$ 96	$ 600	$ 600

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Basis of Presentation and Certain Significant Accounting Policies Basis of Presentation and Certain Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Use of Estimates, Policy [Policy Text Block]

Basis of Presentation and Use of Estimates

The financial statements include the accounts of Alon Refining Krotz Springs, Inc. and have been prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”), which 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 financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Revenue Recognition, Policy [Policy Text Block]

Revenue Recognition

Substantially all of our 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). Generally, title 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).

We occasionally enter 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 statements of operations and profits are recognized when the exchanged product is sold.

Revenue from our inventory financing agreement (Note 4) is reported on a gross basis as we are considered a principal in this agreement.

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 statements of operations.

Cost Classifications [Policy Text Block]

Cost Classifications

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

Direct operating expenses include costs associated with the actual operations of the refinery, such as energy and utility costs, routine maintenance, labor, insurance and environmental compliance costs.

Selling, general and administrative expenses consist primarily of corporate overhead and marketing expenses. These costs also include actual costs incurred by Alon Energy and allocated to us.

Interest expense consists of interest expense, letters of credit, financing costs associated with crude oil purchases, financing fees, and both the amortization and write-off of original issuance discount and deferred debt issuance costs but excludes capitalized interest.

Cash and Cash Equivalents, Policy [Policy Text Block]

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.

Accounts Receivable, Policy [Policy Text Block]

Accounts Receivable

Financial instruments that potentially subject us to concentration of credit risk consist primarily of trade accounts receivables. Credit is extended based on evaluation of the customer’s financial condition and in certain circumstances, collateral, such as letters of credit, prepayments or guarantees, are required, as management deems appropriate. Credit losses are charged to allowance for doubtful accounts when deemed uncollectible. Reserve for bad debts is based on a combination of current sales and specific identification methods.

Inventories, Policy [Policy Text Block]

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.

Crude oil inventory consigned to others represents inventory that was sold to third parties, which we are obligated to repurchase at the end of the respective agreements (Note 4). 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.

Hedging Activity, Policy [Policy Text Block]

Hedging Activity

All derivative instruments are recorded in the balance sheets as either assets or liabilities measured at their fair value. We consider all commodity forwards, futures, swaps, and option contracts to be part of our risk management strategy. For commodity derivative contracts not designated as cash flow hedges, the net unrealized gains and losses for changes in fair value are recognized in cost of sales or in other income (loss), net on the statements of operations.

We selectively designate certain commodity derivative contracts as cash flow hedges. The effective portion of the gains or losses associated with these derivative contracts designated and qualifying as cash flow hedges are initially recorded in accumulated other comprehensive income (loss) in the balance sheet and reclassified into the statement of operations in the period in which the underlying hedged forecasted transaction affects income. The amounts recorded into the statement of operations for commodity derivative contracts are recognized as cost of sales. The ineffective portion of the gains or losses on the derivative contracts, if any, is recognized in the statement of operations as it is incurred.

Derivative transactions related to the inventory financing agreement have been designated as a fair value hedge of inventory. The gain or loss on the derivative instrument designated and qualifying as a fair value hedge, as well as the offsetting gain or loss on the hedged item attributable to the hedged risk, is recognized in earnings in the same period.

Property, Plant and Equipment, Policy [Policy Text Block]

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. We capitalize 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 as a gain or loss on disposition of assets in the statements of operations.

Impairment of Long-Lived Assets and Assets to be Disposed Of, Policy [Policy Text Block]

Impairment of Long-Lived Assets and Assets to be Disposed Of

We review long-lived assets and certain identifiable intangible assets 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.

Asset Retirement Obligations, Policy [Policy Text Block]

Asset Retirement Obligations

The accounting standards established for asset retirement obligations require companies to recognize the 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.

We have asset retirement obligations with respect to our 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 our 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 of these assets, we 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.

Turnarounds and Chemical Catalyst Costs, Policy [Policy Text Block]

Turnarounds and Chemical Catalysts 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 the balance sheets. Turnaround and catalyst costs are 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 chemical catalyst costs are presented in depreciation and amortization in the statements of operations.

Income Taxes, Policy [Policy Text Block]

Income Taxes

Our results of operations are included in the consolidated U.S. Federal income tax return of Alon Energy. For financial reporting purposes, federal tax expense is allocated to us as if a separate return was filed.

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

Environmental Expenditures, Policy [Policy Text Block]

Environmental Expenditures

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. Environmental liabilities represent the estimated costs to investigate and remediate contamination at our 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.

Costs of future expenditures for environmental remediation obligations are not discounted to their present value unless payments are fixed or reliably 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.

Substantially all amounts accrued are expected to be paid out over the next five years. The level of future expenditures for environmental remediation obligations is impossible to determine with any degree of reliability.

Other Comprehensive Income (Loss), Policy [Policy Text Block]

Other Comprehensive Income (Loss)

Other comprehensive income (loss) consists of gains and losses affecting stockholders’ equity that, under U.S. GAAP, are excluded from net loss, such as gains and losses related to certain derivative instruments in qualifying hedging relationships. The balance in other comprehensive income (loss), net of tax, reported in the statement of stockholders’ equity consists of the fair value of commodity derivative contract adjustments.

Commitments and Contingencies, Policy [Policy Text Block]

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. Recoveries of environmental remediation costs from third parties, which are probable of realization, are separately recorded as assets, and are not offset against the related environmental liability.

Intangible Assets, Policy [Policy Text Block]

Intangible Assets

Intangible assets are assets that lack physical substance (excluding financial assets). Intangible assets with indefinite useful lives are not amortized and intangible assets with finite useful lives are amortized on a straight-line basis over 1 to 40 years. Intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. We use December 31 of each year as the valuation date for annual impairment testing purposes.

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Additional Financial Information Other Assets (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Other Assets:
Deferred turnaround and chemical catalyst cost	$ 7,585	$ 9,251
Deferred debt issuance costs	826	4,885
Intangible assets	1,983	2,026
Long-term receivables	6,206	6,206
Total other assets	$ 16,600	$ 22,368

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Derivative Financial Instruments Schedule of Fair Value Hedging Instruments, Statements of Financial Performance (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss)
Derivative Instruments, Gain (Loss) Recognized in Income, Net	$ (2,330)	$ (346)	$ 0
Commodity contracts (futures and forwards) | Cost of Sales
Derivative Instruments, Gain (Loss)
Derivative Instruments, Gain (Loss) Recognized in Income, Net	$ (2,330)	$ (346)	$ 0

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Fair Value (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities:
Liabilities	$ (30,490)	$ (1,119)
Fair Value, Measurements, Recurring | Commodity contracts (futures and forwards)
Fair Value, Assets and Liabilities:
Assets		386
Liabilities	310
Fair Value, Measurements, Recurring | Commodity contracts (futures and forwards) | Level 1
Fair Value, Assets and Liabilities:
Assets		386
Liabilities	310
Fair Value, Measurements, Recurring | Commodity contracts (futures and forwards) | Level 2
Fair Value, Assets and Liabilities:
Assets		0
Liabilities	0
Fair Value, Measurements, Recurring | Commodity contracts (futures and forwards) | Level 3
Fair Value, Assets and Liabilities:
Assets		0
Liabilities	0
Fair Value, Measurements, Recurring | Fair value hedge
Fair Value, Assets and Liabilities:
Liabilities	2,676	346
Fair Value, Measurements, Recurring | Fair value hedge | Level 1
Fair Value, Assets and Liabilities:
Liabilities	0	0
Fair Value, Measurements, Recurring | Fair value hedge | Level 2
Fair Value, Assets and Liabilities:
Liabilities	2,676	346
Fair Value, Measurements, Recurring | Fair value hedge | Level 3
Fair Value, Assets and Liabilities:
Liabilities	0	0
Fair Value, Measurements, Recurring | Commodity contracts (swaps)
Fair Value, Assets and Liabilities:
Assets		1,514
Liabilities	26,897
Fair Value, Measurements, Recurring | Commodity contracts (swaps) | Level 1
Fair Value, Assets and Liabilities:
Assets		0
Liabilities	0
Fair Value, Measurements, Recurring | Commodity contracts (swaps) | Level 2
Fair Value, Assets and Liabilities:
Assets		1,514
Liabilities	15,328
Fair Value, Measurements, Recurring | Commodity contracts (swaps) | Level 3
Fair Value, Assets and Liabilities:
Assets		0
Liabilities	$ 11,569

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Income Taxes Schedule of Effective Income Tax Rate Reconciliation (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Computed tax benefit	$ (3,898)	$ (31,986)	$ (30,615)
State and local income taxes, net of federal benefit	(678)	(1,444)	(3,130)
Other, net	618	836	1,005
Change in valuation allowance	3,958	32,594	32,740
Income tax benefit	$ 0	$ 0	$ 0

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Inventories Textuals (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Inventory Disclosure [Abstract]
Excess of Replacement or Current Costs over Stated LIFO Value	$ 13,600	$ 14,013

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Description and Nature of Business

12 Months Ended

Dec. 31, 2013

Description and Nature of Business [Abstract]

Description and Nature of Business

Description and Nature of Business

As used in this report, the terms “the Company,” “we,” “us” or “our” refer to Alon Refining Krotz Springs, Inc., a subsidiary of Alon USA Energy, Inc. (“Alon Energy”). References in this report to “Alon Energy” or “Parent” refer collectively to Alon USA Energy, Inc. and any of its subsidiaries, other than Alon Refining Krotz Springs, Inc.

We own and operate a high conversion crude oil refinery placed into service in 1980 located in Krotz Springs, Louisiana with a crude oil throughput capacity of approximately 74,000 barrels per day (“bpd”). We refine crude oil into petroleum products, including gasoline, light distillates and intermediate products.

Our refinery is strategically located on approximately 381 acres on the Atchafalaya River in central Louisiana at the intersection of two crude oil pipeline systems and has direct access to the Colonial products pipeline system (“Colonial Pipeline”), providing us with diversified access to both locally sourced and foreign crude oils, as well as distribution of our products to markets throughout the Southern and Eastern United States and along the Mississippi and Ohio Rivers. In industry terms, our refinery is characterized as a “mild residual cracking refinery,” which generally refers to a refinery utilizing vacuum distillation and catalytic cracking processes in addition to basic distillation and naphtha reforming processes to minimize low quality black oil production and to produce higher light product yields such as gasoline, light distillates and intermediate products.

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Derivative Financial Instruments Schedule of Derivative Instruments, Gain (Loss) in Statements of Financial Performance (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss)
Derivative Instruments, Gain (Loss) Recognized in Income, Net	$ 2,821	$ (50,054)	$ 4,597
Commodity contracts (futures and forwards) | Cost of Sales
Derivative Instruments, Gain (Loss)
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(2,143)	4,431	10,837
Commodity contracts (swaps) | Cost of Sales
Derivative Instruments, Gain (Loss)
Derivative Instruments, Gain (Loss) Recognized in Income, Net	4,964	(47,188)	30,040
Commodity contracts (call options) | Other income (loss), net
Derivative Instruments, Gain (Loss)
Derivative Instruments, Gain (Loss) Recognized in Income, Net	$ 0	$ (7,297)	$ (36,280)

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Property, Plant and Equipment, Net (Tables)

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Table Text Block]

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

	As of December 31,
	2013			2012
Refining facilities	$	441,152		$	429,531
Accumulated depreciation	(107,553		)	(86,210		)
Property, plant and equipment, net	$	333,599		$	343,321

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Inventories (Tables)

12 Months Ended

Dec. 31, 2013

Inventory Disclosure [Abstract]

Schedule of Inventory

Carrying value of inventories consisted of the following:

	As of December 31,
	2013		2012
Crude oil, refined products and blendstocks	$	11,710	$	12,268
Crude oil inventory consigned to others (Note 4)	22,545		29,656
Materials and supplies	3,651		2,872
Total inventories	$	37,906	$	44,796

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Indebtedness Interest and Other Financing Expenses (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Interest and Other Financing Expenses [Abstract]
Interest expense	$ 25,399	$ 29,228	$ 29,228
Letters of credit and finance charges	13,334	12,268	8,314
Amortization of debt issuance costs	2,188	2,246	2,044
Write-off of debt issuance costs	1,871	0	0
Amortization of original issuance discount	2,240	2,249	1,946
Write-off of original issuance discount	1,871	0	0
Prepayment premium	4,725	0	0
Capitalized interest	(3,093)	(1,574)	(555)
Total interest expense	$ 48,535	$ 44,417	$ 40,977

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Derivative Financial Instruments Summary of offsetting derivative instruments by type (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Commodity Derivative Assets:
Gross Amounts of Recognized Assets	$ 607	$ 2,673
Commodty contracts (futures and forwards)
Commodity Derivative Assets:
Gross Amounts of Recognized Assets	747	2,446
Gross Amounts Offset in the Statement of Financial Position	(140)	(2,060)
Net Amounts of Assets Presented in the Statement of Financial Position	607	386
Derivative Asset, Not Subject to Master Netting Arrangement	(607)	0
Cash Collateral Received	0	0
Derivative Asset, Net Amount	0	386
Commodity Derivative Liabilities:
Gross Amounts of Recognized Liabilities	(1,057)	(2,060)
Gross Amounts Offset in the Statement of Financial Position	140	2,060
Net Amounts of Liabilities Presented in the Statement of Financial Position	(917)	0
Derivative Liability, Not Subject to Master Netting Arrangement	607	0
Cash Collateral Pledged	0	0
Derivative Liability, Net Amount	(310)	0
Commodity contracts (swaps)
Commodity Derivative Assets:
Gross Amounts of Recognized Assets		4,756
Gross Amounts Offset in the Statement of Financial Position		(2,469)
Net Amounts of Assets Presented in the Statement of Financial Position		2,287
Derivative Asset, Not Subject to Master Netting Arrangement		(773)
Cash Collateral Received		0
Derivative Asset, Net Amount		1,514
Commodity Derivative Liabilities:
Gross Amounts of Recognized Liabilities	(26,897)	(3,242)
Gross Amounts Offset in the Statement of Financial Position	0	2,469
Net Amounts of Liabilities Presented in the Statement of Financial Position	(26,897)	(773)
Derivative Liability, Not Subject to Master Netting Arrangement	0	773
Cash Collateral Pledged	0	0
Derivative Liability, Net Amount	(26,897)	0
Commodity Contract [Member]
Commodity Derivative Liabilities:
Gross Amounts of Recognized Liabilities	(2,676)	(346)
Gross Amounts Offset in the Statement of Financial Position	0	0
Net Amounts of Liabilities Presented in the Statement of Financial Position	(2,676)	(346)
Derivative Liability, Not Subject to Master Netting Arrangement	0	0
Cash Collateral Pledged	0	0
Derivative Liability, Net Amount	$ (2,676)	$ (346)

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Additional Financial Information (Tables)

12 Months Ended

Dec. 31, 2013

Additional Financial Information [Abstract]

Schedule of Other Assets

Other Assets, Net

	As of December 31,
	2013		2012
Deferred turnaround and chemical catalyst cost	$	7,585	$	9,251
Deferred debt issuance costs	826		4,885
Intangible assets	1,983		2,026
Long-term receivables	6,206		6,206
Total other assets	$	16,600	$	22,368

Schedule of Accrued Liabilities and Other Non-Current Liabilities

Accrued Liabilities, Other Non-Current Liabilities and Accounts Payable

	As of December 31,
	2013		2012
Accrued Liabilities:
Taxes other than income taxes	$	568	$	1,670
Employee costs	1,280		1,460
Commodity contracts	16,245		773
Accrued finance charges	3,597		7,439
Other	8,094		1,157
Total accrued liabilities	$	29,784	$	12,499
Other Non-Current Liabilities:
Environmental accrual (Note 15)	$	271	$	319
Asset retirement obligations	1,177		1,101
Consignment inventory obligation	24,022		28,016
Commodity contracts	11,569		—
Total other non-current liabilities	$	37,039	$	29,436

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Income Taxes Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

A reconciliation between the income tax benefit computed on pretax loss at the statutory federal rate and the actual provision for income tax benefit is as follows:

	Year Ended December 31,
	2013			2012			2011
Computed tax benefit	$	(3,898	)	$	(31,986	)	$	(30,615	)
State and local income taxes, net of federal benefit	(678		)	(1,444		)	(3,130		)
Other, net	618			836			1,005
Change in valuation allowance	3,958			32,594			32,740
Income tax benefit	$	—		$	—		$	—

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

The following table sets forth the tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities:

	As of December 31,
	2013			2012
Deferred income tax assets:
Accrued liabilities and other	$	481		$	482
Non-current accrued liabilities and other	3,907			2,506
Net operating loss carryover	204,276			191,626
Deferred income tax assets	208,664			194,614
Less: Valuation allowance	(134,251		)	(130,293		)
Net deferred income tax assets	$	74,413		$	64,321
Deferred income tax liabilities:
Unrealized gains	$	971		$	92
Property, plant and equipment	70,428			60,489
Other non-current	2,285			2,997
Intangibles	729			743
Deferred income tax liabilities	$	74,413		$	64,321
Net deferred income tax after valuation allowance	$	—		$	—

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Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities:
Net loss	$ (11,138)	$ (91,389)	$ (87,471)
Adjustments to reconcile net loss to cash provided by operating activities:
Depreciation and amortization	26,565	23,882	22,645
Amortization of debt issuance costs	2,188	2,246	2,044
Amortization of original issuance discount	2,240	2,249	1,946
Write-off of unamortized original issuance discount	1,871	0	0
Write-off of unamortized debt issuance costs	1,871	0	0
Loss on disposition of assets	0	2,504	0
Unrealized (gain) loss on commodity swaps	(3,085)	31,936	(31,936)
Changes in operating assets and liabilities:
Accounts and other receivables, net	5,694	(32,593)	(756)
Inventories	6,890	(6,439)	(19,796)
Prepaid expenses and other current assets	2,039	(1,856)	1,460
Other assets, net	0	0	484
Accounts payable	(24,597)	99,518	128,070
Accrued liabilities	2,730	(6,444)	5,099
Other non-current liabilities	(3,966)	(4,727)	6,566
Net cash provided by operating activities	9,302	18,887	28,355
Cash flows from investing activities:
Capital expenditures	(11,621)	(17,023)	(18,909)
Capital expenditures for turnarounds and catalysts	(3,513)	(1,163)	(2,649)
Earnout payments related to refinery acquisition	0	0	(6,562)
Proceeds from sale of assets	0	20	0
Net cash used in investing activities	(15,134)	(18,166)	(28,120)
Cash flows from financing activities:
Deferred debt issuance costs	0	0	(126)
Payments on long-term debt	(140,000)	0	0
Proceeds from parent capital contribution	144,725	0	0
Net cash provided by (used in) financing activities	4,725	0	(126)
Net increase (decrease) in cash and cash equivalents	(1,107)	721	109
Cash and cash equivalents, beginning of period	1,107	386	277
Cash and cash equivalents, end of period	0	1,107	386
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest	$ 44,202	$ 39,322	$ 36,987

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Indebtedness (Tables)

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Schedule of Long-term Debt Instruments [Table Text Block]

Debt consisted of the following:

	As of December 31,
	2013		2012
Senior secured notes, net of discount	$	75,684	$	211,573

Interest and Other Financing Expense [Table Text Block]

Interest and financing expense included the following:

	Year Ended December 31,
	2013			2012			2011
Interest expense	$	25,399		$	29,228		$	29,228
Letters of credit and finance charges	13,334			12,268			8,314
Amortization of debt issuance costs	2,188			2,246			2,044
Write-off of debt issuance costs	1,871			—			—
Amortization of original issuance discount	2,240			2,249			1,946
Write-off of original issuance discount	1,871			—			—
Prepayment premium	4,725			—			—
Capitalized interest	(3,093		)	(1,574		)	(555		)
Total interest expense	$	48,535		$	44,417		$	40,977

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Derivative Financial Instruments Schedule of Derivative Instruments in Statement of Financial Position, Fair Value (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivatives not designated as hedging instruments:
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	$ 607	$ 386
Derivative Instruments Not Designated as Hedging Instruments, Liability, at Fair Value	(917)	0
Derivatives designated as hedging instruments:
Derivative Instruments in Hedges, Assets, at Fair Value	0	2,287
Derivative Instruments in Hedges, Liabilities, at Fair Value	(29,573)	(1,119)
Derivative Asset, Fair Value, Gross Asset	607	2,673
Derivative Liabilities	(30,490)	(1,119)
Commodity contracts (swaps)
Derivatives designated as hedging instruments:
Derivative Asset, Fair Value, Gross Asset		4,756
Commodity contracts (futures and forwards)
Derivatives designated as hedging instruments:
Derivative Asset, Fair Value, Gross Asset	747	2,446
Accounts Receivable | Commodity contracts (swaps)
Derivatives designated as hedging instruments:
Cash Flow Hedge Derivative Instrument Assets at Fair Value	0	2,287
Accounts Receivable | Commodity contracts (futures and forwards)
Derivatives not designated as hedging instruments:
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	607	386
Accrued Liabilities | Commodity contracts (swaps)
Derivatives designated as hedging instruments:
Cash Flow Hedge Derivative Instrument Liabilities at Fair Value	(15,328)	(773)
Accrued Liabilities | Commodity contracts (futures and forwards)
Derivatives not designated as hedging instruments:
Derivative Instruments Not Designated as Hedging Instruments, Liability, at Fair Value	(917)	0
Other Noncurrent Assets | Fair value hedge
Derivatives designated as hedging instruments:
Fair Value Hedge Assets	0	0
Other Noncurrent Liabilities | Commodity contracts (swaps)
Derivatives designated as hedging instruments:
Cash Flow Hedge Derivative Instrument Liabilities at Fair Value	(11,569)
Other Noncurrent Liabilities | Fair value hedge
Derivatives designated as hedging instruments:
Fair Value Hedge Liabilities	$ (2,676)	$ (346)

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Income Taxes Schedule of Deferred Tax Assets and Liabilities (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Deferred income tax assets:
Accrued liabilities and other	$ 481	$ 482
Non-current accrued liabilities and other	3,907	2,506
Net operating loss carryover	204,276	191,626
Deferred income tax assets	208,664	194,614
Less: Valuation allowance	(134,251)	(130,293)
Net deferred income tax assets	74,413	64,321
Deferred income tax liabilities:
Unrealized gains	971	92
Property, plant and equipment	70,428	60,489
Other non-current	2,285	2,997
Intangibles	729	743
Deferred income tax liabilities	74,413	64,321
Net deferred income tax after valuation allowance	$ 0	$ 0

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Balance Sheets (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 0	$ 1,107
Accounts and other receivables, net	30,431	38,412
Inventories	37,906	44,796
Prepaid expenses and other current assets	315	2,354
Total current assets	68,652	86,669
Property, plant and equipment, net	333,599	343,321
Other assets, net	16,600	22,368
Total assets	418,851	452,358
Current liabilities:
Accounts payable	355,732	380,329
Accrued liabilities	29,784	12,499
Current portion of long term debt	75,684	0
Total current liabilities	461,200	392,828
Other non-current liabilities	37,039	29,436
Long-term debt	0	211,573
Total liabilities	498,239	633,837
Commitments and contingencies (Note 15)
Stockholders’ equity:
Accumulated other comprehensive income (loss), net of income tax	(29,982)	1,514
Additional paid-in capital	312,381	167,656
Retained deficit	(361,787)	(350,649)
Total stockholders’ equity	(79,388)	(181,479)
Total liabilities and stockholders’ equity	418,851	452,358
Common Class A [Member]
Stockholders’ equity:
Common stock, par value $0.01	0	0
Common Class B [Member]
Stockholders’ equity:
Common stock, par value $0.01	$ 0	$ 0

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Accounts Receivable Accounts Receivable (Textuals) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Accounts Receivable (Textuals) [Abstract]
Allowance for Doubtful Accounts Receivable, Current	$ 0	$ 0

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Statement of Stockholders' Equity (USD $) In Thousands	Total	Common Stock	Additional Paid-in Capital	Accumulated Other Comprehensive Income (Loss)	Retained Deficit
Balance at Dec. 31, 2010	$ (4,133)	$ 0	$ 167,656	$ 0	$ (171,789)
Net loss	(87,471)	0	0	0	(87,471)
Balance at Dec. 31, 2011	(91,604)	0	167,656	0	(259,260)
Net loss	(91,389)	0	0	0	(91,389)
Fair value of commodity swaps, net of tax	1,514	0	0	1,514	0
Balance at Dec. 31, 2012	(181,479)	0	167,656	1,514	(350,649)
Capital contribution from parent	144,725	0	144,725	0	0
Net loss	(11,138)	0	0	0	(11,138)
Fair value of commodity swaps, net of tax	(31,496)	0	0	(31,496)	0
Balance at Dec. 31, 2013	$ (79,388)	$ 0	$ 312,381	$ (29,982)	$ (361,787)

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Commitments and Contingencies Leases (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Leases [Abstract]
Operating Leases, Future Minimum Payments Due, Current	$ 561
Operating Leases, Future Minimum Payments Receivable, in Two Years	502
Operating Leases, Future Minimum Payments, Due in Three Years	452
Operating Leases, Future Minimum Payments, Due in Four Years	313
Operating Leases, Future Minimum Payments, Due in Five Years	60
Operating Leases, Future Minimum Payments, Due Thereafter	597
Operating Leases, Future Minimum Payments Due	2,485
Operating Leases, Rent Expense, Net	$ 3,508	$ 3,144	$ 3,475

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Opertaing Results and Liquidity (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Results and Liquidity [Abstract]
Accounts Payable, Related Parties	$ 290,785	$ 294,060
Throughput, Average	64,705
Net Cash Provided by Operating Activities	9,302	18,887	28,355
Senior Notes	$ 75,684	$ 211,573

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Employee Benefit Plans

12 Months Ended

Dec. 31, 2013

Employee Benefit Plans [Abstract]

Employee Benefit Plans

Employee Benefit Plans

Our employees are included in the various employee benefit plans of Alon Energy. These plans include qualified, non-contributory defined benefit retirement plans, defined contribution plans, employee and retiree medical, dental, and life insurance plans, incentive plans (i.e., stock options, restricted stock, and bonuses), and other such benefits. For the purposes of these financial statements, we are considered to be participating in multi-employer benefit plans of Alon Energy.

Our allocated share of Alon Energy’s employee benefit plan expenses, excluding costs related to the incentive plans was $2,095, $1,403 and $2,024for the years endedDecember 31, 2013, 2012 and 2011, respectively.

Employee benefit plan expenses incurred by us are included in direct operating expenses with the related payroll costs.

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Inventory Financing Agreement (Textuals) (Details) (USD $) In Thousands, unless otherwise specified								12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Standby Letters of Credit	Dec. 31, 2013 J.Aron	Dec. 31, 2012 J.Aron	Dec. 31, 2013 Derivative Consigned inventory	Dec. 31, 2012 Derivative Consigned inventory	Dec. 31, 2013 Standby Letters of Credit
Accounts payable	$ 355,732	$ 380,329		$ 32,081	$ 48,311
Recorded Unconditional Purchase Obligation	24,022	28,016		24,022	28,016
Financing Receivable	6,206	6,206		6,206	6,206
Derivative Liability	(30,490)	(1,119)				990
Derivative Asset							1,565
Line of Credit Facility, Capacity Available for Specific Purpose Other than for Trade Purchases			200,000
Line of Credit Facility, Current Borrowing Capacity			$ 0
Debt Instrument, Maturity Date								Jul. 31, 2016

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Renewable Fuel Standard (Notes)

12 Months Ended

Dec. 31, 2013

Renewable Fuel Standard [Abstract]

Compliance Program Costs Disclosure [Text Block]

Renewable Fuel Standard

We are obligated by government regulations under the Renewable Fuel Standard 2 (“RFS2”) to blend a certain percentage of biofuels into the products we produce that are consumed in the U.S. We will purchase biofuels from third parties and blend those biofuels into our products, and each gallon of biofuel purchased includes a Renewable Identification Number (“RIN”). To the degree we are unable to blend biofuels at the required percentage, a RINs deficit is generated and we must acquire that number of RINs by the annual reporting deadline in order to remain in compliance with applicable regulations.

We are exposed to market risk related to the volatility in the price of credits needed to comply with these governmental and regulatory programs. We will manage this risk by purchasing biofuel credits when prices are deemed favorable.

We received an exemption from the RFS2 requirements for the year ended December 31, 2013. We were not subject to the RFS2 requirements for the years ended December 31, 2012 and 2011.

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Statement of Stockholders' Equity Parenthetical (Parentheticals) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Fair value of commodity derivative contracts, tax	$ 0	$ 0	$ 0

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Balance Sheets Parentheticals (Parentheticals) (USD $)	Mar. 01, 2014 Common Class A [Member]	Dec. 31, 2013 Common Class A [Member]	Dec. 31, 2012 Common Class A [Member]	Mar. 01, 2014 Common Class B [Member]	Dec. 31, 2013 Common Class B [Member]	Dec. 31, 2012 Common Class B [Member]
Common Stock, Par or Stated Value Per Share		$ 0.01	$ 0.01		$ 0.01	$ 0.01
Common Stock, Shares Authorized		75,000	75,000		1,000	1,000
Common Stock, Shares, Issued		50,111	50,111		90	90
Common Stock, Shares, Outstanding		50,111	50,111		90	90
Entity Common Stock, Shares Outstanding	50,111			90

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Property, Plant and Equipment, Net

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment, Net [Abstract]

Property, Plant and Equipment, Net

Property, Plant and Equipment, Net

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

	As of December 31,
	2013			2012
Refining facilities	$	441,152		$	429,531
Accumulated depreciation	(107,553		)	(86,210		)
Property, plant and equipment, net	$	333,599		$	343,321

The useful lives of refining facilities used to determine depreciation expense were 3 to 20 years with an average life of 18 years.

Capitalized interest for the years ended December 31, 2013, 2012 and 2011 was $3,093, $1,574 and $555, respectively. Depreciation expense for the years ended December 31, 2013, 2012 and 2011 was $21,343, $20,261 and $19,899, respectively.

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Document and Entity Information Document (USD $)	12 Months Ended
	Dec. 31, 2013	Jun. 30, 2013
Document Information [Line Items]
Entity Registrant Name	Alon Refining Krotz Springs, Inc.
Entity Central Index Key	0001479142
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	Yes
Entity Current Reporting Status	Yes
Entity Public Float		$ 0

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Additional Financial Information

12 Months Ended

Dec. 31, 2013

Additional Financial Information [Abstract]

Additional Financial Information

Additional Financial Information

The tables that follow provide additional financial information related to the financial statements.

(a) Other Assets, Net

	As of December 31,
	2013		2012
Deferred turnaround and chemical catalyst cost	$	7,585	$	9,251
Deferred debt issuance costs	826		4,885
Intangible assets	1,983		2,026
Long-term receivables	6,206		6,206
Total other assets	$	16,600	$	22,368

(b) Accrued Liabilities, Other Non-Current Liabilities and Accounts Payable

	As of December 31,
	2013		2012
Accrued Liabilities:
Taxes other than income taxes	$	568	$	1,670
Employee costs	1,280		1,460
Commodity contracts	16,245		773
Accrued finance charges	3,597		7,439
Other	8,094		1,157
Total accrued liabilities	$	29,784	$	12,499
Other Non-Current Liabilities:
Environmental accrual (Note 15)	$	271	$	319
Asset retirement obligations	1,177		1,101
Consignment inventory obligation	24,022		28,016
Commodity contracts	11,569		—
Total other non-current liabilities	$	37,039	$	29,436

Accounts payable includes related parties balance of $290,785 and $294,060 at December 31, 2013 and 2012, respectively.

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Statements of Operations (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net sales	$ 2,680,112	$ 2,881,242	$ 2,533,092
Operating costs and expenses:
Cost of sales	2,510,720	2,790,998	2,433,910
Direct operating expenses	96,570	95,713	79,972
Selling, general and administrative expenses	8,870	7,828	6,827
Depreciation and amortization	26,565	23,882	22,645
Total operating costs and expenses	2,642,725	2,918,421	2,543,354
Loss on disposition of assets	0	(2,504)	0
Operating income (loss)	37,387	(39,683)	(10,262)
Interest expense	(48,535)	(44,417)	(40,977)
Other income (loss), net	10	(7,289)	(36,232)
Loss before income tax benefit	(11,138)	(91,389)	(87,471)
Income tax benefit	0	0	0
Net loss	$ (11,138)	$ (91,389)	$ (87,471)

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Inventory Financing Agreement

12 Months Ended

Dec. 31, 2013

Inventory Financing Agreement [Abstract]

Inventory Financing Agreement

Inventory Financing Agreement

We have entered into a Supply and Offtake Agreement and other associated agreements (together 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 us, and we agreed to buy from J. Aron, at market prices, crude oil for processing at the refinery and (ii) we agreed to sell, and J. Aron agreed to buy, at market prices, certain refined products produced at the refinery.

The Supply and Offtake Agreement also provided for the sale, at market prices, of our 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 our refinery, and to identify prospective purchasers of refined products on J. Aron’s behalf. The Supply and Offtake Agreement was amended in February 2013 and has an initial term that expires in May 2019. J. Aron may elect to terminate the Supply and Offtake Agreement prior to the initial term beginning in May 2016 and upon each anniversary thereof, on six months prior notice. We may elect to terminate in May 2018 on six months prior notice.

Following the 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 refinery.

At December 31, 2013 and 2012, we had net current payables to J. Aron for purchases of $32,081 and $48,311, respectively, and other non-current liabilities related to the original financing of $24,022 and $28,016, respectively, and a consignment receivable representing a deposit paid to J. Aron of $6,206 and $6,206, respectively.

Additionally, we had current payables of $990 and current receivables of $1,565 at December 31, 2013 and 2012, respectively, for forward commitments related to month-end consignment inventory target levels differing from projected levels and the associated pricing with these inventory level differences.

In association with the Supply and Offtake Agreement, we entered into a secured Credit Agreement (the “Standby LC Facility”) by and between the Company, as Borrower, and Goldman Sachs Bank USA, as Issuing Bank. The Standby LC Facility provides for up to $200,000 of letters of credit to be issued to J. Aron. Obligations under the Standby LC Facility are secured by a first priority lien on the existing and future accounts receivable and inventory of the Company. The Standby LC Facility includes customary events of default and restrictions on our activities. The Standby LC Facility contains no maintenance financial covenants. At this time there is no further availability under the Standby LC Facility. In August 2013, we amended the Standby LC Facility to extend the maturity date to July 2016

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Operating Results and Liquidity

12 Months Ended

Dec. 31, 2013

Operating Results and Liquidity [Abstract]

Operating Results and Liquidity

Operating Results and Liquidity

Our refinery average throughput was 64,705 bpd for the year ended December 31, 2013. Cash flow from operating activities for the year ended December 31, 2013 was $9,302.

Our primary sources of liquidity are cash generated from our operating activities, inventory supply and offtake arrangements, other credit lines and additional funding from Alon Energy. Accounts payable to Alon Energy and its subsidiaries of $290,785 at December 31, 2013, while due on demand, are expected to be paid as funds are available. Future operating results will depend on market factors, primarily the difference between the prices we receive from customers for produced products compared to the prices we pay to suppliers for crude oil. We plan to continue to operate the refinery at current or higher utilization rates as long as the refinery is able to generate cash operating margin. Management believes its current liquidity from the above described sources is adequate to operate the refinery.

We have senior secured notes due October 2014 with an outstanding balance (net of unamortized discount) of $75,684 at December 31, 2013. We plan to repay this outstanding balance using cash from operating activities and funding from Alon Energy. As an alternative, we would consider the issuance of new debt to allow for the repayment of the outstanding senior secured notes balance.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies Disclosure

Commitments and Contingencies

(a) Leases

We have long-term lease commitments for land, buildings and equipment. In most cases, we expect that in the normal course of business, our leases will be renewed or replaced by other leases. We have commitments under long-term operating leases for certain land, buildings and equipment expiring at various dates over the next fifteen years. Certain long-term operating leases relating to buildings and land include options to renew for additional periods. At December 31, 2013, minimum lease payments on operating leases were as follows:

Year ending December 31:
2014	$	561
2015	502
2016	452
2017	313
2018	60
2019 and thereafter	597
Total	$	2,485

Total rental expense was $3,508, $3,144 and $3,475for the years endedDecember 31, 2013, 2012 and 2011, respectively. Contingent rentals and subleases were not significant.

(b) Other Commitments

In the normal course of business, we have long-term commitments to purchase, at market prices, utilities such as natural gas, electricity and water for use by the refinery. We are 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.

Supply and Offtake Agreements

In July 2013, we entered into offtake agreements with Valero and BP that provides for the sale, at market prices, of light cycle oil and high sulfur distillate blendstock through June 2015. Both agreements will automatically extend for successive one year terms unless either we or the other party cancels the agreement by delivering written notice of termination to the other at least 180 days prior to the end of the then current term.

(c) Contingencies

We are involved in various legal actions arising in the ordinary course of business. We believe the ultimate disposition of these matters will not have a material effect on our financial position, results of operations or liquidity.

(d) Environmental

We are subject to loss contingencies pursuant to federal, state, and local environmental laws and regulations. These laws and regulations govern the discharge of materials into the environment and may require us 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 and to compensate others for damage to property and natural resources. These contingent obligations relate to sites that we own and are associated with past or present operations. We are currently participating in environmental investigations, assessments and cleanups pertaining to our refinery. We may be involved in additional future environmental investigations, assessments and cleanups. The magnitude of future costs are unknown and will depend on factors such as the nature and contamination at many sites, the timing, extent and method of the remedial actions which may be required, and the determination of our liability in proportion to other responsible parties.

We have accrued a non-current liability for environmental remediation obligations of $271 and $319 at December 31, 2013 and 2012, respectively.

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Income Taxes

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Our results of operations are included in the consolidated U.S. Federal income tax return of our parent, Alon Energy. For financial reporting purposes, federal tax expense is allocated to us as if a separate return was filed. The amounts presented below were calculated as if we filed separate federal and state income tax returns. We had no unrecognized tax benefits as of December 31, 2013.

A reconciliation between the income tax benefit computed on pretax loss at the statutory federal rate and the actual provision for income tax benefit is as follows:

	Year Ended December 31,
	2013			2012			2011
Computed tax benefit	$	(3,898	)	$	(31,986	)	$	(30,615	)
State and local income taxes, net of federal benefit	(678		)	(1,444		)	(3,130		)
Other, net	618			836			1,005
Change in valuation allowance	3,958			32,594			32,740
Income tax benefit	$	—		$	—		$	—

The following table sets forth the tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities:

	As of December 31,
	2013			2012
Deferred income tax assets:
Accrued liabilities and other	$	481		$	482
Non-current accrued liabilities and other	3,907			2,506
Net operating loss carryover	204,276			191,626
Deferred income tax assets	208,664			194,614
Less: Valuation allowance	(134,251		)	(130,293		)
Net deferred income tax assets	$	74,413		$	64,321
Deferred income tax liabilities:
Unrealized gains	$	971		$	92
Property, plant and equipment	70,428			60,489
Other non-current	2,285			2,997
Intangibles	729			743
Deferred income tax liabilities	$	74,413		$	64,321
Net deferred income tax after valuation allowance	$	—		$	—

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the level of taxable income and projections for future taxable income, over the periods which the deferred tax assets are deductible, management believes it is more likely than not that we will realize the benefits of these deductible differences, net of the existing valuation allowance at December 31, 2013.

We performed a review of our tax positions in accordance with ASC Subtopic 740-10, Income Taxes, and determined we have no unrecognized tax benefits. We have elected to recognize interest expense related to the underpayment of income taxes in interest expense, and penalties relating to underpayment of income taxes as a reduction to other income (loss), net, in the statements of operations.

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Accounts Receivable

12 Months Ended

Dec. 31, 2013

Accounts Receivable, Net, Current [Abstract]

Accounts Receivable

Accounts Receivable

Financial instruments that potentially subject us to concentration of credit risk consist primarily of trade accounts receivables and commodity derivative contracts. Credit risk is minimized as a result of the credit quality of our customer base. We perform ongoing credit evaluations of our customers and require letters of credit, prepayments or other collateral or guarantees as we deem appropriate. Valero Energy Corporation (“Valero”), BP Products North America, Inc. (“BP”) and J. Aron accounted for substantially all of our net sales for the year ended December 31, 2013. The allowance for doubtful accounts is reflected as a reduction of accounts receivable in the balance sheets. The balance in the allowance account was zero at December 31, 2013 and 2012.

As part of the Supply and Offtake Agreement, there is a net out arrangement. Additionally, product sales to parties other than J. Aron are primarily collected when the sale occurs. As a result of these arrangements, we have minimal trade accounts receivable balances at December 31, 2013 and 2012.

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Environmental (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Loss Contingency [Abstract]
Environmental accrual	$ 271	$ 319

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Fair Value

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Fair Value Disclosures

Fair Value

We 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. We classify financial assets and financial liabilities into the following fair value hierarchy:

• Level 1 -     valued based on quoted prices in active markets for identical assets and liabilities;

• Level 2 -     valued based on quoted prices for similar assets and liabilities in active markets, and inputs other than quoted prices that are observable for the asset or liability; and

• Level 3 -     valued based on unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.

As required, we utilize 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. We generally apply 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 carrying amounts of our 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 instruments are carried at fair value, which are based on quoted market prices. Derivative instruments are our only financial assets and liabilities measured at fair value on a recurring basis.

The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, in the balance sheets at December 31, 2013 and 2012:

	Level 1		Level 2		Level 3		Total
As of December 31, 2013
Liabilities:
Commodity contracts (futures and forwards)	$	310	$	—	$	—	$	310
Commodity contracts (swaps)	—		15,328		11,569		26,897
Fair value hedge	—		2,676		—		2,676
As of December 31, 2012
Assets:
Commodity contracts (futures and forwards)	$	386	$	—	$	—	$	386
Commodity contracts (swaps)	—		1,514		—		1,514
Liabilities:
Fair value hedge	—		346		—		346

Level 3 Financial Instruments

We have commodity price swap contracts that relate to forecasted sales of jet fuel and forecasted purchases of crude oil for which quoted forward market prices are not readily available. The forward rate used to value these commodity price swaps was derived using a projected forward rate using quoted market rates for similar products, adjusted for product grade differentials, a Level 3 input.

The following table presents the changes in fair value of our Level 3 assets and liabilities (all related to commodity price swap contracts) for the year ended December 31, 2013:

	Year Ended
	December 31, 2013
Balance at beginning of period	$	—
Change in fair value of Level 3 trades open at the beginning of the period	—
Fair value of trades entered into during the period - Recognized in other comprehensive income (loss)	(11,569		)
Fair value of reclassification from Level 3 to Level 2	—
Settlement value of contractual maturities - Recognized in cost of sales	—
Balance at end of period	$	(11,569	)

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Derivative Financial Instruments

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities Disclosure

Derivative Financial Instruments

Mark-to-Market

Commodity Derivatives. We selectively utilize crude oil and refined product commodity derivative contracts to reduce the risk associated with potential price changes on committed obligations. We do not speculate using derivative instruments. Credit risk on our 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 of certain refining inventories and firm commitments to purchase inventories. The gain or loss on a derivative instrument designated and qualifying as a fair value hedge, as well as the offsetting gain or loss on the hedged item attributable to the hedged risk, is recognized in earnings in the same period.

As of December 31, 2013, we have accounted for certain commodity contracts as fair value hedges with contract purchase volumes of 272 thousand barrels of crude oil with remaining contract terms through May 2019.

Cash Flow Hedges

To designate a derivative as a cash flow hedge, we document at the inception of the hedge the assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative and the item hedged. If, during the term of the derivative, the hedge is determined to be no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings when the underlying transactions occur.

As of December 31, 2013, we have accounted for certain commodity swap contracts as cash flow hedges with total contract purchase volumes of 5,760 thousand barrels of crude oil and contract sales volumes of 5,760 thousand barrels of refined products with a remaining contract term of twenty-four months. Related to these transactions in Other Comprehensive Income (“OCI”), we recognized unrealized losses of $31,496 and unrealized gains of $1,514 for the years ended December 31, 2013 and 2012, respectively. There were no amounts reclassified from OCI into cost of sales as a result of the discontinuance of cash flow hedge accounting.

In November 2013, we elected to de-designate certain commodity swap contracts that were previously designated as cash flow hedges. Consequently, hedge accounting was discontinued prospectively for the commodity swap contracts and all changes in fair value were recorded in cost of sales in the statements of operations. As of December 31, 2013, we had unrealized losses of $29,982 classified in OCI that related to the application of hedge accounting prior to de-designation that will be recorded into earnings as the forecasted transactions occur during the year ended December 31, 2014. The commodity derivative contracts were subsequently re-designated as cash flow hedges as of December 31, 2013 on a product basis.

For the year ended December 31, 2013, there was $1,879 of hedge ineffectiveness recognized in cost of sales. For the year ended December 31, 2012, there was no hedge ineffectiveness recognized in income. No component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness.

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

	As of December 31, 2013
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives not designated as hedging instruments:
Commodity contracts (futures and forwards)	Accounts receivable	$	607	Accrued liabilities	$	(917	)
Total derivatives not designated as hedging instruments		$	607		$	(917	)
Derivatives designated as hedging instruments:
Commodity contracts (swaps)		$	—	Accrued liabilities	$	(15,328	)
Commodity contracts (swaps)		—		Other non-current liabilities	(11,569		)
Fair value hedge		—		Other non-current liabilities	(2,676		)
Total derivatives designated as hedging instruments		—			(29,573		)
Total derivatives		$	607		$	(30,490	)

	As of December 31, 2012
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives not designated as hedging instruments:
Commodity contracts (futures and forwards)	Accounts receivable	$	386		$	—
Total derivatives not designated as hedging instruments		$	386		$	—
Derivatives designated as hedging instruments:
Commodity contracts (swaps)	Accounts receivable	$	2,287	Accrued liabilities	$	(773	)
Fair value hedge		—		Other non-current liabilities	(346		)
Total derivatives designated as hedging instruments		2,287			(1,119		)
Total derivatives		$	2,673		$	(1,119	)

The following tables present the effect of derivative instruments on the statements of operations and accumulated other comprehensive income:

Derivatives designated as hedging instruments:

Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI			Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)				Gain (Loss) Reclassified from Accumulated OCI into Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
				Location	Amount			Location	Amount
For the Year Ended December 31, 2013
Commodity contracts (swaps)	$	(31,496	)	Cost of sales	$	23,900		Cost of sales	$	(1,879	)
Total derivatives	$	(31,496	)		$	23,900			$	(1,879	)
For the Year Ended December 31, 2012
Commodity contracts (swaps)	$	1,514		Cost of sales	$	(68,832	)		$	—
Total derivatives	$	1,514			$	(68,832	)		$	—

Derivatives in fair value hedging relationships:

		Gain (Loss) Recognized in Income
		Year Ended December 31,
	Location	2013			2012			2011
Fair value hedge	Cost of sales	$	(2,330	)	$	(346	)	$	—
Total derivatives		$	(2,330	)	$	(346	)	$	—

Derivatives not designated as hedging instruments:

		Gain (Loss) Recognized in Income
		Year Ended December 31,
	Location	2013			2012			2011
Commodity contracts (futures & forwards)	Cost of sales	$	(2,143	)	$	4,431		$	10,837
Commodity contracts (swaps)	Cost of sales	4,964			(47,188		)	30,040
Commodity contracts (call options)	Other income (loss), net	—			(7,297		)	(36,280		)
Total derivatives		$	2,821		$	(50,054	)	$	4,597

Offsetting Assets and Liabilities

Our derivative financial instruments are subject to master netting arrangements to manage counterparty credit risk associated with derivatives and we offset the fair value amounts recorded for derivative instruments to the extent possible under these agreements on our balance sheets.

The following table presents offsetting information regarding our derivatives by type of transaction as of December 31, 2013 and 2012:

	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts offset in the Statement of Financial Position			Net Amounts of Assets (Liabilities) Presented in the Statement of Financial Position			Gross Amounts Not offset in the Statement of Financial Position					Net Amount
										Financial Instruments			Cash Collateral Pledged
As of December 31, 2013
Commodity Derivative Assets:
Futures & forwards	$	747		$	(140	)	$	607		$	(607	)	$	—	$	—
Commodity Derivative Liabilities:
Futures & forwards	$	(1,057	)	$	140		$	(917	)	$	607		$	—	$	(310	)
Swaps	(26,897		)	—			(26,897		)	—			—		(26,897		)
Fair value hedge	(2,676		)	—			(2,676		)	—			—		(2,676		)
As of December 31, 2012
Commodity Derivative Assets:
Futures & forwards	$	2,446		$	(2,060	)	$	386		$	—		$	—	$	386
Swaps	4,756			(2,469		)	2,287			(773		)	—		1,514
Commodity Derivative Liabilities:
Futures & forwards	$	(2,060	)	$	2,060		$	—		$	—		$	—	$	—
Swaps	(3,242		)	2,469			(773		)	773			—		—
Fair value hedge	(346		)	—			(346		)	—			—		(346		)

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Inventories

12 Months Ended

Dec. 31, 2013

Inventory Disclosure [Abstract]

Inventory Disclosure

Inventories

Carrying value of inventories consisted of the following:

	As of December 31,
	2013		2012
Crude oil, refined products and blendstocks	$	11,710	$	12,268
Crude oil inventory consigned to others (Note 4)	22,545		29,656
Materials and supplies	3,651		2,872
Total inventories	$	37,906	$	44,796

Market values of crude oil, refined products and blendstock inventories exceeded LIFO costs by $13,600 and $14,013 at December 31, 2013 and 2012, respectively.

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Description and Nature of Business Description and Nature of Business (Details)	12 Months Ended
	Dec. 31, 2013
Throughput, Average	64,705
Maximum
Throughput, Average	74,000

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Additional Financial Information Accrued Liabilities and Other Non-Current Liabilities (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Accrued Liabilities:
Taxes other than income taxes	$ 568	$ 1,670
Employee costs	1,280	1,460
Commodity contracts	16,245	773
Accrued finance charges	3,597	7,439
Other	8,094	1,157
Total accrued liabilities	29,784	12,499
Other Non-Current Liabilities:
Environmental accrual (Note 15)	271	319
Asset retirement obligations	1,177	1,101
Consignment inventory obligation	24,022	28,016
Commodity contracts	11,569	0
Total other non-current liabilities	37,039	29,436
Accounts Payable (Textuals)
Accounts Payable, Related Parties	$ 290,785	$ 294,060

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Related Party Transactions

12 Months Ended

Dec. 31, 2013

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

Since the acquisition of our refinery from Valero, we have received equity contributions in the amount of $312,381 from Alon Energy. The most recent contributions were $144,725 received in 2013, which we used to redeem $140,000 of the outstanding principal balance on the Senior Secured Notes.

Alon Israel Oil Company, Ltd. (“Alon Israel”) provided letters of credit to us of $15,000. In December 2012, the amount was reduced by $12,500 and in December 2013, the letter of credit was canceled. For the years endedDecember 31, 2013, 2012 and 2011, we recorded interest expense related to these letters of credit of $96, $600 and $600, respectively.

We are a subsidiary of Alon Energy and we are 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 our executive officers as well as Alon Energy’s other subsidiaries. Alon Energy performs general corporate and administrative services and functions for us 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 in performing these services to us and to its other subsidiaries based primarily on the amount of time the individuals performing such services devote to our business and affairs relative to the amount of time they devote to the business and affairs of Alon Energy’s other subsidiaries. We record the amount of such allocations in our financial statements as selling, general and administrative expenses. Our share of Alon Energy’s selling, general and administrative expenses were $8,870, $7,828 and $6,827, for the years ended December 31, 2013, 2012 and 2011, respectively.

Alon Energy currently owns all of our outstanding voting capital stock. As a result, Alon Energy can control the election of our directors, exercise control or significant influence over our corporate and management policies and generally determine the outcome of any corporate transaction or other matter submitted to our stockholders for approval, including potential mergers or acquisitions, asset sales and other significant corporate transactions. So long as Alon Energy continues to own a majority of the outstanding shares of our voting capital stock, Alon Energy will continue to be able to effectively control or influence the outcome of such matters.

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Fair Value (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, in the balance sheets at December 31, 2013 and 2012:

	Level 1		Level 2		Level 3		Total
As of December 31, 2013
Liabilities:
Commodity contracts (futures and forwards)	$	310	$	—	$	—	$	310
Commodity contracts (swaps)	—		15,328		11,569		26,897
Fair value hedge	—		2,676		—		2,676
As of December 31, 2012
Assets:
Commodity contracts (futures and forwards)	$	386	$	—	$	—	$	386
Commodity contracts (swaps)	—		1,514		—		1,514
Liabilities:
Fair value hedge	—		346		—		346

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]

The following table presents the changes in fair value of our Level 3 assets and liabilities (all related to commodity price swap contracts) for the year ended December 31, 2013:

	Year Ended
	December 31, 2013
Balance at beginning of period	$	—
Change in fair value of Level 3 trades open at the beginning of the period	—
Fair value of trades entered into during the period - Recognized in other comprehensive income (loss)	(11,569		)
Fair value of reclassification from Level 3 to Level 2	—
Settlement value of contractual maturities - Recognized in cost of sales	—
Balance at end of period	$	(11,569	)

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Property, Plant and Equipment, Net Textuals (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Property, Plant and Equipment, Net [Line Items]
Interest Costs, Capitalized During Period	$ (3,093)	$ (1,574)	$ (555)
Depreciation	$ 21,343	$ 20,261	$ 19,899
Minimum [Member]
Property, Plant and Equipment, Net [Line Items]
Property, Plant and Equipment, Useful Life, Minimum	3 years
Maximum
Property, Plant and Equipment, Net [Line Items]
Property, Plant and Equipment, Useful Life, Minimum	20 years
Average [Member]
Property, Plant and Equipment, Net [Line Items]
Property, Plant and Equipment, Useful Life, Minimum	18 years

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Derivative Financial Instruments Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments, Gain (Loss)
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	$ (31,496)	$ 1,514
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	23,900	(68,832)
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	(1,879)	0
Commodity contracts (swaps)
Derivative Instruments, Gain (Loss)
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	(31,496)	1,514
Cost of Sales | Commodity contracts (swaps)
Derivative Instruments, Gain (Loss)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	23,900	(68,832)
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	$ (1,879)	$ 0

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Statements of Comprehensive Income Statement (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net loss	$ (11,138)	$ (91,389)	$ (87,471)
Commodity contracts designated as cash flow hedges:
Unrealized holding loss arising during period	(9,475)	(67,318)	0
(Gain) loss reclassified to earnings - cost of sales	(22,021)	68,832	0
Net gain (loss), before tax	(31,496)	1,514	0
Total other comprehensive income (loss), before tax	(31,496)	1,514	0
Income tax expense (benefit) related to other comprehensive income (loss)	0	0	0
Total other comprehensive income (loss), net of tax	(31,496)	1,514	0
Comprehensive loss	$ (42,634)	$ (89,875)	$ (87,471)

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Basis of Presentation and Certain Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation and Certain Significant Accounting Policies

Basis of Presentation and Certain Significant Accounting Policies

(a) Basis of Presentation and Use of Estimates

The financial statements include the accounts of Alon Refining Krotz Springs, Inc. and have been prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”), which 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 financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

(b) Revenue Recognition

Substantially all of our 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). Generally, title 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).

We occasionally enter 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 statements of operations and profits are recognized when the exchanged product is sold.

Revenue from our inventory financing agreement (Note 4) is reported on a gross basis as we are considered a principal in this agreement.

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 statements of operations.

(c) Cost Classifications

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

Direct operating expenses include costs associated with the actual operations of the refinery, such as energy and utility costs, routine maintenance, labor, insurance and environmental compliance costs.

Selling, general and administrative expenses consist primarily of corporate overhead and marketing expenses. These costs also include actual costs incurred by Alon Energy and allocated to us.

Interest expense consists of interest expense, letters of credit, financing costs associated with crude oil purchases, financing fees, and both the amortization and write-off of original issuance discount and deferred debt issuance costs but excludes capitalized interest.

(d) 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.

(e) Accounts Receivable

Financial instruments that potentially subject us to concentration of credit risk consist primarily of trade accounts receivables. Credit is extended based on evaluation of the customer’s financial condition and in certain circumstances, collateral, such as letters of credit, prepayments or guarantees, are required, as management deems appropriate. Credit losses are charged to allowance for doubtful accounts when deemed uncollectible. Reserve for bad debts is based on a combination of current sales and specific identification methods.

(f) 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.

Crude oil inventory consigned to others represents inventory that was sold to third parties, which we are obligated to repurchase at the end of the respective agreements (Note 4). 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.

(g) Hedging Activity

All derivative instruments are recorded in the balance sheets as either assets or liabilities measured at their fair value. We consider all commodity forwards, futures, swaps, and option contracts to be part of our risk management strategy. For commodity derivative contracts not designated as cash flow hedges, the net unrealized gains and losses for changes in fair value are recognized in cost of sales or in other income (loss), net on the statements of operations.

We selectively designate certain commodity derivative contracts as cash flow hedges. The effective portion of the gains or losses associated with these derivative contracts designated and qualifying as cash flow hedges are initially recorded in accumulated other comprehensive income (loss) in the balance sheet and reclassified into the statement of operations in the period in which the underlying hedged forecasted transaction affects income. The amounts recorded into the statement of operations for commodity derivative contracts are recognized as cost of sales. The ineffective portion of the gains or losses on the derivative contracts, if any, is recognized in the statement of operations as it is incurred.

Derivative transactions related to the inventory financing agreement have been designated as a fair value hedge of inventory. The gain or loss on the derivative instrument designated and qualifying as a fair value hedge, as well as the offsetting gain or loss on the hedged item attributable to the hedged risk, is recognized in earnings in the same period.

(h) 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. We capitalize 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 as a gain or loss on disposition of assets in the statements of operations.

(i) Impairment of Long-Lived Assets and Assets to be Disposed Of

We review long-lived assets and certain identifiable intangible assets 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.

(j) Asset Retirement Obligations

The accounting standards established for asset retirement obligations require companies to recognize the 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.

We have asset retirement obligations with respect to our 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 our 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 of these assets, we 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.

(k) Turnarounds and Chemical Catalysts 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 the balance sheets. Turnaround and catalyst costs are 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 chemical catalyst costs are presented in depreciation and amortization in the statements of operations.

(l) Income Taxes

Our results of operations are included in the consolidated U.S. Federal income tax return of Alon Energy. For financial reporting purposes, federal tax expense is allocated to us as if a separate return was filed.

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

(m) Environmental Expenditures

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. Environmental liabilities represent the estimated costs to investigate and remediate contamination at our 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.

Costs of future expenditures for environmental remediation obligations are not discounted to their present value unless payments are fixed or reliably 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.

Substantially all amounts accrued are expected to be paid out over the next five years. The level of future expenditures for environmental remediation obligations is impossible to determine with any degree of reliability.

(n) Other Comprehensive Income (Loss)

Other comprehensive income (loss) consists of gains and losses affecting stockholders’ equity that, under U.S. GAAP, are excluded from net loss, such as gains and losses related to certain derivative instruments in qualifying hedging relationships. The balance in other comprehensive income (loss), net of tax, reported in the statement of stockholders’ equity consists of the fair value of commodity derivative contract adjustments.

(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. Recoveries of environmental remediation costs from third parties, which are probable of realization, are separately recorded as assets, and are not offset against the related environmental liability.

(p) Intangible Assets

Intangible assets are assets that lack physical substance (excluding financial assets). Intangible assets with indefinite useful lives are not amortized and intangible assets with finite useful lives are amortized on a straight-line basis over 1 to 40 years. Intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. We use December 31 of each year as the valuation date for annual impairment testing purposes.

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Employee Benefit Plans (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Employee Benefit Plans [Abstract]
Pension and Other Postretirement Benefit Expense	$ 2,095	$ 1,403	$ 2,024

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Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

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

	As of December 31, 2013
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives not designated as hedging instruments:
Commodity contracts (futures and forwards)	Accounts receivable	$	607	Accrued liabilities	$	(917	)
Total derivatives not designated as hedging instruments		$	607		$	(917	)
Derivatives designated as hedging instruments:
Commodity contracts (swaps)		$	—	Accrued liabilities	$	(15,328	)
Commodity contracts (swaps)		—		Other non-current liabilities	(11,569		)
Fair value hedge		—		Other non-current liabilities	(2,676		)
Total derivatives designated as hedging instruments		—			(29,573		)
Total derivatives		$	607		$	(30,490	)

	As of December 31, 2012
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives not designated as hedging instruments:
Commodity contracts (futures and forwards)	Accounts receivable	$	386		$	—
Total derivatives not designated as hedging instruments		$	386		$	—
Derivatives designated as hedging instruments:
Commodity contracts (swaps)	Accounts receivable	$	2,287	Accrued liabilities	$	(773	)
Fair value hedge		—		Other non-current liabilities	(346		)
Total derivatives designated as hedging instruments		2,287			(1,119		)
Total derivatives		$	2,673		$	(1,119	)

Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)

Derivatives designated as hedging instruments:

Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI			Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)				Gain (Loss) Reclassified from Accumulated OCI into Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
				Location	Amount			Location	Amount
For the Year Ended December 31, 2013
Commodity contracts (swaps)	$	(31,496	)	Cost of sales	$	23,900		Cost of sales	$	(1,879	)
Total derivatives	$	(31,496	)		$	23,900			$	(1,879	)
For the Year Ended December 31, 2012
Commodity contracts (swaps)	$	1,514		Cost of sales	$	(68,832	)		$	—
Total derivatives	$	1,514			$	(68,832	)		$	—

Schedule of Fair Value Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

Derivatives in fair value hedging relationships:

		Gain (Loss) Recognized in Income
		Year Ended December 31,
	Location	2013			2012			2011
Fair value hedge	Cost of sales	$	(2,330	)	$	(346	)	$	—
Total derivatives		$	(2,330	)	$	(346	)	$	—

Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance

Derivatives not designated as hedging instruments:

		Gain (Loss) Recognized in Income
		Year Ended December 31,
	Location	2013			2012			2011
Commodity contracts (futures & forwards)	Cost of sales	$	(2,143	)	$	4,431		$	10,837
Commodity contracts (swaps)	Cost of sales	4,964			(47,188		)	30,040
Commodity contracts (call options)	Other income (loss), net	—			(7,297		)	(36,280		)
Total derivatives		$	2,821		$	(50,054	)	$	4,597

Summary of offsetting derivative instruments by type

The following table presents offsetting information regarding our derivatives by type of transaction as of December 31, 2013 and 2012:

	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts offset in the Statement of Financial Position			Net Amounts of Assets (Liabilities) Presented in the Statement of Financial Position			Gross Amounts Not offset in the Statement of Financial Position					Net Amount
										Financial Instruments			Cash Collateral Pledged
As of December 31, 2013
Commodity Derivative Assets:
Futures & forwards	$	747		$	(140	)	$	607		$	(607	)	$	—	$	—
Commodity Derivative Liabilities:
Futures & forwards	$	(1,057	)	$	140		$	(917	)	$	607		$	—	$	(310	)
Swaps	(26,897		)	—			(26,897		)	—			—		(26,897		)
Fair value hedge	(2,676		)	—			(2,676		)	—			—		(2,676		)
As of December 31, 2012
Commodity Derivative Assets:
Futures & forwards	$	2,446		$	(2,060	)	$	386		$	—		$	—	$	386
Swaps	4,756			(2,469		)	2,287			(773		)	—		1,514
Commodity Derivative Liabilities:
Futures & forwards	$	(2,060	)	$	2,060		$	—		$	—		$	—	$	—
Swaps	(3,242		)	2,469			(773		)	773			—		—
Fair value hedge	(346		)	—			(346		)	—			—		(346		)

XML

Fair Value Fair Value, Unobservable Inputs Reconciliation Schedule (Details) (Swap [Member], USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Balance at beginning of period	$ 0
Change in fair value of Level 3 trades open at the beginning of the period	0
Fair value of trades entered into during the period - Recognized in other comprehensive income (loss)	(11,569)
Fair value of reclassification from Level 3 to Level 2	0
Settlement value of contractual maturities - Recognized in cost of sales	0
Balance at end of period	$ (11,569)

XML

Indebtedness

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Debt Disclosure

Indebtedness

Debt consisted of the following:

	As of December 31,
	2013		2012
Senior secured notes, net of discount	$	75,684	$	211,573

(a) Senior Secured Notes

In October 2009, we issued 13.50% senior secured notes (the “Senior Secured Notes”) in aggregate principal amount of $216,500 in a private offering. In February 2010, we exchanged $216,480 of Senior Secured Notes for an equivalent amount of Senior Secured Notes (“Exchange Notes”) registered under the Securities Act of 1933. The Exchange Notes will mature in October 2014 and the entire principal amount is due at maturity. Interest is payable semi-annually in arrears on April 15 and October 15. The Exchange Notes are substantially identical to the Senior Secured Notes, except that the Exchange Notes have been registered with the Securities and Exchange Commission and are not subject to transfer restrictions. The Senior Secured Notes were issued at an offering price of 94.857% and we received gross proceeds of $205,365 (before fees and expenses related to the offering).

The terms of the Senior Secured Notes are governed by an indenture (the “Indenture”) and the obligations under the Indenture are secured by a first priority lien on our property, plant and equipment and a second priority lien on the our cash, accounts receivable and inventory.

The Indenture also contains restrictive covenants such as restrictions on loans, mergers, sales of assets, additional indebtedness and restricted payments. The Indenture does not contain any maintenance financial covenants.

In October 2013, Alon Energy made a $144,725 capital contribution to us, which we used to redeem $140,000 of the outstanding principal balance on the Senior Secured Notes. As a result of the prepayment of the Senior Secured Notes, a prepayment premium of $4,725 and write-offs of unamortized original issuance discount and debt issuance costs of $1,871 and $1,871, respectively, were charged to interest expense in the statements of operations for the year ended December 31, 2013.

At December 31, 2013, the Senior Secured Notes, due October 2014, had an outstanding balance (net of unamortized discount) of $75,684, included in current portion of long-term debt. At December 31, 2012, the Senior Secured Notes had an outstanding balance (net of unamortized discount) of $211,573, included in long-term debt. We are utilizing the effective interest method to amortize the original issue discount over the life of the Senior Secured Notes.

(b) Interest and Financing Expense

Interest and financing expense included the following:

	Year Ended December 31,
	2013			2012			2011
Interest expense	$	25,399		$	29,228		$	29,228
Letters of credit and finance charges	13,334			12,268			8,314
Amortization of debt issuance costs	2,188			2,246			2,044
Write-off of debt issuance costs	1,871			—			—
Amortization of original issuance discount	2,240			2,249			1,946
Write-off of original issuance discount	1,871			—			—
Prepayment premium	4,725			—			—
Capitalized interest	(3,093		)	(1,574		)	(555		)
Total interest expense	$	48,535		$	44,417		$	40,977