Alon USA Partners (ALDW) 10-K 13 Mar 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information Document (USD $)	12 Months Ended
	Dec. 31, 2014	Mar. 01, 2015	Jun. 30, 2014
Entity Information
Entity Registrant Name	Alon USA Partners, LP
Entity Central Index Key	1556766
Current Fiscal Year End Date	-19
Entity Filer Category	Accelerated Filer
Document Type	10-K
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Amendment Flag	FALSE
Entity Common Stock, Shares Outstanding		62,506,550
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$206,195,000

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current assets:
Cash and cash equivalents	$106,325	$153,583
Accounts and other receivables, net	68,545	123,781
Accounts and other receivables, net - related parties	9,466	14,621
Inventories	45,162	49,146
Prepaid expenses and other current assets	9,163	4,642
Total current assets	238,661	345,773
Property, plant and equipment, net	445,706	472,885
Other assets, net	85,879	31,266
Total assets	770,246	849,924
Current liabilities:
Accounts payable	186,156	280,774
Accrued liabilities	54,566	44,492
Current portion of long-term debt	2,500	2,500
Total current liabilities	243,222	327,766
Other non-current liabilities	38,746	34,894
Long-term debt	299,876	341,822
Total liabilities	581,844	704,482
Commitments and contingencies (Note 15)
Partners’ equity:
General Partner	0	0
Common unitholders - 62,506,550 and 62,502,467 units issued and outstanding at December 31, 2014 and 2013, respectively	188,402	145,442
Total partners’ equity	188,402	145,442
Total liabilities and partners’ equity	$770,246	$849,924

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical)	Dec. 31, 2014	Dec. 31, 2013
Consolidated Balance Sheets (Parentheticals) [Abstract]
Common units, shares issued	62,506,550	62,502,467
Common units, shares outstanding	62,506,550	62,502,467

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Net sales (1)	$3,221,373	[1]	$3,430,287	[1]	$3,476,817	[1]
Operating costs and expenses:
Cost of sales	2,823,694		3,073,044		2,883,741
Direct operating expenses	105,760		110,940		100,908
Selling, general and administrative expenses	26,446		22,276		22,807
Depreciation and amortization	47,494		45,329		46,009
Total operating costs and expenses	3,003,394		3,251,589		3,053,465
Loss on disposition of assets	0		-21		0
Operating income	217,979		178,677		423,352
Interest expense	-46,706		-40,474		-22,235
Interest expense - related parties	0		0		-15,691
Other income, net	646		23		8
Income before state income tax expense	171,919		138,226		385,434
State income tax expense	2,784		2,004		3,536
Net income	169,135		136,222		381,898
Less: Net income attributable to Predecessor operations	0		0		344,778
Net income attributable to Alon USA Partners, LP	$169,135		$136,222		$37,120
Earnings per unit	$2.71		$2.18		$0.59
Weighted average common units outstanding (in thousands)	62,505		62,502		62,500
Cash distribution per unit	$2.02		$2.76		$0
[1]	Includes sales to related parties of $563,008, $600,710 and $588,828 for the years ended December 31, 2014, 2013 and 2012, respectively.

Consolidated_Statements_of_Ope1

Consolidated Statements of Operations (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Consolidated Statement of Operations (Parenthetical) [Abstract]
Sales to related parties	$563,008	$600,710	$588,828

Consolidated_Statement_of_Part

Consolidated Statement of Partners' Equity Statement (USD $)	Total	Predecessor	Common Unitholders	General Partner
In Thousands
Total partners' equity at Dec. 31, 2011	$102,689	$102,689
Distributions paid to unitholders	-410,106	-410,106
Net income attributable to Predecessor operations	344,778	344,778
Proceeds from initial public offering, net of offering costs	167,769	167,769
Assumption of term loan facility, net of financing costs	-238,687	-238,687
Conversion of subordinated debt - related parties	178,163	178,163
Predecessor equity transferred to common unitholders	0	-144,606	144,606
Net income attributable to Alon USA Partners, LP	37,120		37,120	0
Total partners' equity at Dec. 31, 2012	181,726	0	181,726	0
Distributions paid to unitholders	-172,506		-172,506	0
Assumption of term loan facility, net of financing costs	0
Net income attributable to Alon USA Partners, LP	136,222		136,222	0
Total partners' equity at Dec. 31, 2013	145,442		145,442	0
Distributions paid to unitholders	-126,262		-126,262	0
Assumption of term loan facility, net of financing costs	0
Unit-based Compensation	87		87	0
Net income attributable to Alon USA Partners, LP	169,135		169,135	0
Total partners' equity at Dec. 31, 2014	$188,402		$188,402	$0

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities:
Net income	$169,135	$136,222	$381,898
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	47,494	45,329	46,009
Unit-based compensation	87	0	0
Non-cash interest on subordinated debt - related parties	0	0	15,691
Amortization of debt issuance costs	2,057	1,990	2,105
Amortization of original issuance discount	554	511	61
Loss on disposition of assets	0	21	0
Changes in operating assets and liabilities:
Accounts and other receivables, net	55,236	-19,662	-3,266
Accounts and other receivables, net - related parties	5,155	-102	-1,731
Inventories	3,984	7,888	-25,296
Prepaid expenses and other current assets	-4,521	2,226	-811
Other assets, net	-12,371	-1,634	1,978
Accounts payable	-87,829	53,453	90,802
Accrued liabilities	13,671	-2,752	14,378
Other non-current liabilities	3,852	-7,153	7,007
Net cash provided by operating activities	196,504	216,337	528,825
Cash flows from investing activities:
Capital expenditures	-16,064	-23,390	-24,490
Capital expenditures for turnarounds and catalysts	-58,736	-6,236	-7,279
Net cash used in investing activities	-74,800	-29,626	-31,769
Cash flows from financing activities:
Distributions paid to unitholders	-23,242	-31,746	0
Distributions paid to unitholders - Alon Energy	-103,020	-140,760	0
Net cash payments to Alon Energy	0	0	-410,106
Proceeds from initial public offering, net of offering costs	0	0	167,769
Inventory agreement transactions	-200	25,200	0
Deferred debt issuance costs	0	-323	-2,543
Repayment of subordinated debt - related parties	0	0	-171,120
Revolving credit facility, net	-40,000	51,000	-151,000
Payments on long-term debt	-2,500	-2,500	0
Net cash used in financing activities	-168,962	-99,129	-567,000
Net increase (decrease) in cash and cash equivalents	-47,258	87,582	-69,944
Cash and cash equivalents, beginning of period	153,583	66,001	135,945
Cash and cash equivalents, end of period	106,325	153,583	66,001
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest	44,948	38,807	19,598
Cash paid for income tax	2,127	2,004	2,597
Supplemental disclosure of non-cash activity:
Capital expenditures included in accounts payable and accrued liabilities	0	5,026	0
Conversion of subordinated debt - related parties	0	0	178,163
Assumption of term loan facility, net of financing costs	$0	$0	($238,687)

Description_and_Nature_of_Busi

Description and Nature of Business	12 Months Ended
	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Operations	Description and Nature of Business
	As used in this report, the terms “Alon,” the “Partnership,” “we,” “us” or “our” refer to Alon USA Partners, LP, and its consolidated subsidiaries or to Alon USA Partners, LP or an individual subsidiary. References in this report to “Alon Energy” refer collectively to Alon USA Energy, Inc. and any of its subsidiaries, other than Alon USA Partners, LP, its subsidiaries and its general partner.
	Alon is a Delaware limited partnership formed in August 2012 by Alon Energy and its wholly owned subsidiary Alon USA Partners GP, LLC (the “General Partner”). In November 2012, we completed the initial public offering of 11,500,000 common units representing limited partner interests at a price of $16.00 per unit (the “Offering”).
	Our initial net assets were contributed to us by Alon Energy in exchange for 51,000,000 common units, representing an 81.6% interest in the Partnership, and 100% non-economic ownership interest in the General Partner. As an entity under common control of Alon Energy, we recorded the net assets that Alon Energy contributed to us concurrently with the completion of the Offering at Alon Energy’s historical basis.
	We are a refiner and marketer of petroleum products operating primarily in the South Central and Southwestern regions of the United States. We own and operate a crude oil refinery in Big Spring, Texas with a crude oil throughput capacity of 73,000 barrels per day, or “bpd”, which we refer to as the Big Spring refinery. We refine crude oil into petroleum products, including ultra-low sulfur gasoline, ultra-low sulfur diesel, jet fuel, petrochemicals, petrochemical feedstocks, asphalts and other petroleum products, which we market primarily in West and Central Texas, Oklahoma, New Mexico and Arizona. We refer to our operations in this region as our physically integrated system because it supplies Alon branded and unbranded distributors in this region with motor fuels produced at the Big Spring refinery. Our physically integrated system includes Alon Energy’s owned and operated retail convenience stores. We distribute fuel products through a product pipeline and terminal network, which we own or access through leases or long-term throughput agreements. For financial reporting purposes, we operate in a single reportable segment based on how the business is managed.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation and Significant Accounting Policies	Summary of Significant Accounting Policies
	(a) Basis of Presentation
	The consolidated financial statements and related notes for the periods beginning and following November 27, 2012, present the consolidated financial position, results of operations, cash flows and partners’ equity of the Partnership and its consolidated subsidiaries. Additionally, the accompanying financial statements and related notes for periods presented through November 26, 2012 present the combined results of operations, cash flows and partners’ equity of Alon USA Partners, LP Predecessor (“Predecessor”), our predecessor for accounting purposes, at historical cost. All significant intercompany balances and transactions have been eliminated.
	(b) Use of Estimates
	These consolidated financial statements 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
	(c) Revenue Recognition
	Substantially all of 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 consolidated statements of operations and profits are recognized when the exchanged product is sold.
	Revenue from our inventory financing agreement (Note 8) 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 consolidated statements of operations.
	(d) Cost Classifications
	Cost of sales includes principally crude oil, blending materials, other raw materials and transportation costs, which include costs associated with our crude oil and product pipelines. Cost of sales excludes depreciation and amortization, which is presented separately in the consolidated 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. These costs also include actual costs incurred by Alon Energy and allocated to us.
	Selling, general and administrative expenses primarily include corporate overhead costs and marketing expenses. These costs also include actual costs incurred by Alon Energy and allocated to us.
	Interest expense includes interest expense, letters of credit, financing costs associated with crude oil purchases, financing fees and amortization of both original issuance discount and deferred debt issuance costs but excludes capitalized interest. Original issuance discount and debt issuance costs are amortized over the term of the related debt using the effective interest method.
	(e) Cash and Cash Equivalents
	All highly-liquid instruments with a maturity of three months or less at the time of purchase are considered to be cash equivalents. Cash equivalents are stated at cost, which approximates market value.
	(f) Accounts Receivable
	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. We perform ongoing credit evaluations of our customers and require letters of credit, prepayments or other collateral or guarantees as management deems appropriate. Allowance for doubtful accounts is based on a combination of current sales and specific identification methods.
	Credit risk is minimized as a result of the ongoing credit assessment of our customers and a lack of concentration in our customer base. Credit losses are charged to allowance for doubtful accounts when deemed uncollectible. Our allowance for doubtful accounts is reflected as a reduction of accounts receivable in the consolidated balance sheets.
	The balance in allowance for doubtful accounts was $220 for the year ended December 31, 2014 and $277 for each of the years ended December 31, 2013 and 2012.
	(g) Inventories
	Crude oil, refined products and blendstocks (including crude oil consignment inventory) are stated at the lower of cost or market. Cost is determined under the last-in, first-out (“LIFO”) valuation method and market is determined using current estimated selling prices. Under the LIFO valuation method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In periods of rapidly declining prices, LIFO inventories may have to be written down to market value due to the higher costs assigned to LIFO layers in prior periods. An inventory write-down to market value results in a non-cash accounting adjustment, decreasing the value of our inventory and increasing our cost of sales. Such charges are subject to reversal in subsequent periods, not to exceed LIFO cost, if prices recover. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years when inventory volumes decline and result in charging cost of sales with LIFO inventory costs generated in prior periods. 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 8). As a result of this requirement to repurchase the inventory, no revenue was recorded on these transactions and the inventory volumes remain valued under the LIFO method.
	(h) Hedging Activity
	We participate in Alon Energy’s company-wide risk management program. Under Alon Energy’s risk management program, all commodity forwards, futures, swaps and option contracts are considered to be part of the risk management strategy. All derivative instruments are recorded in the consolidated balance sheets as either assets or liabilities measured at their fair value. 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 in the consolidated statements of operations.
	The derivative transaction related to our inventory financing agreement has 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.
	(i) Property, Plant and Equipment
	The carrying value of property, plant and equipment includes the fair value of the asset retirement obligation and has been reflected in the consolidated 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. The useful lives of depreciable assets used to determine depreciation expense range from 3 to 20 years. We capitalize interest costs associated with major construction projects based on the effective interest rate on aggregate borrowings. Leasehold improvements are depreciated on the straight-line method over the shorter of the contractual lease terms or the estimated useful lives.
	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 consolidated statements of operations.
	(j) 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. The future cash flows and fair values used in this assessment are estimates based on management’s judgment and assumptions. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs of disposition.
	(k) Asset Retirement Obligations
	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 (Note 11).
	(l) Turnarounds and Catalysts Costs
	Our refinery units require regular major maintenance and repairs that are commonly referred to as “turnarounds.” Catalysts used in certain refinery process units are typically replaced in conjunction with planned turnarounds. We record the turnaround and catalysts costs as deferred charges in other assets in the consolidated balance sheets. We amortize the deferred costs on a straight-line basis over the period of time estimated until the next turnaround occurs, beginning the month after the completion of the turnaround. The amortization of deferred turnaround and catalysts costs are presented in depreciation and amortization in our consolidated statements of operations.
	(m) Earnings per Unit
	Earnings per unit applicable to limited partners is computed by dividing limited partners’ interest in net income by the weighted average number of outstanding common units.
	(n) Income Taxes
	We are a partnership for U.S. federal income tax purposes and thus our income is taxed directly to our owners. As a result, we do not incur U.S. federal income taxes.
	Alon Energy is subject to the Texas franchise tax and our operations are included in the consolidated Texas franchise tax return of Alon Energy. For financial reporting purposes, Texas franchise tax is calculated as if a separate return was filed.
	Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement.
	(o) 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. These estimates are 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 (Note 15). 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 15 years. The amount of future expenditures for environmental remediation obligations is impossible to determine with any degree of reliability.
	(p) 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.
	(q) New Accounting Standards
	In May 2014, the Financial Accounting Standards Board (“FASB”) and the International Accounting Standards Board jointly issued a comprehensive new revenue recognition standard that provides accounting guidance for all revenue arising from contracts to provide goods or services to customers. This standard is intended to improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets. The requirements from the new standard are effective for interim and annual periods beginning after December 15, 2016, and early adoption is not permitted. The standard allows for either full retrospective adoption or modified retrospective adoption. We are evaluating the guidance to determine the method of adoption and the impact of this standard on our consolidated financial statements.
	In February 2015, the FASB issued an accounting standards update making targeted changes to the current consolidation guidance. The new standard changes the way certain decisions are made related to substantive rights, related parties, and decision making fees when applying the variable interest entity consolidation model and eliminates certain guidance for limited partnerships and similar entities under the voting interest consolidation model. The requirements from the updated standard are effective for interim and annual periods beginning after December 15, 2015, and early adoption is permitted. We are evaluating the effect that adopting the updated guidance will have on our consolidated financial statements and related disclosures.

Earnings_Per_Unit

Earnings Per Unit	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Earnings Per Unit	Earnings Per Unit
	The following is a summary of our net income for the period after the completion of the Offering through December 31, 2012:
		November 27, 2012 through December 31, 2012
	Net sales	$	324,237
	Operating costs and expenses:
	Cost of sales	264,960
	Direct operating expenses	10,687
	Selling, general and administrative expenses	2,153
	Depreciation and amortization	4,632
	Total operating costs and expenses	282,432
	Operating income	41,805
	Interest expense	(4,335		)
	Interest expense - related parties	—
	Other income (loss), net	(2		)
	Income before state income tax expense	37,468
	State income tax expense	348
	Net income attributable to Alon USA Partners, LP	$	37,120
	Weighted average common units outstanding (in thousands)	62,500
	Earnings per unit	$	0.59
	Earnings per unit is computed by dividing limited partners’ interest in net income by the weighted average number of common units outstanding during the period. Our net income is allocated entirely to the limited partners as the General Partner has a non-economic interest in the Partnership.
	Earnings per unit is only calculated for the Partnership subsequent to the Offering, as there was no outstanding public equity prior to November 27, 2012. Distributions made to our unitholders are determined according to the policy adopted by the board of directors of our General Partner and are not based on the net income allocations used in the calculation of earnings per unit.

Fair_Value

Fair Value	12 Months Ended
	Dec. 31, 2014
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 and the Renewable Identification Numbers (“RINs”) obligation are our only assets and liabilities measured at fair value on a recurring basis.
	The RINs obligation represents the period-end deficit, if any, after considering any RINs acquired or under contract, necessary to meet our requirements to blend biofuels into the products we have produced. The RINs obligation is categorized as level 2 in the fair value hierarchy and is measured at fair value using the market approach based on quoted prices from an independent pricing service.
	The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, in the consolidated balance sheets as of December 31, 2014 and 2013:
		Level 1		Level 2		Level 3		Total
	As of December 31, 2014
	Assets:
	Commodity contracts (futures and forwards)	$	1,406	$	—	$	—	$	1,406
	Fair value hedge	—		10,223		—		10,223
	As of December 31, 2013
	Assets:
	Commodity contracts (futures and forwards)	$	22	$	—	$	—	$	22
	Liabilities:
	Fair value hedge	—		2,304		—		2,304
	RINs obligation	—		334		—		334

Derivative_Financial_Instrumen

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities Disclosure	Derivative Financial Instruments
	We selectively utilize crude oil and refined product commodity derivative contracts to reduce the risk associated with potential price changes on committed obligations as well as to reduce earnings volatility. 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.
	Mark to Market
	We have certain contracts that serve as economic hedges, which are derivatives used for risk management but not designated as hedges for financial accounting purposes. All economic hedge transactions are recorded at fair value and any changes in fair value between reporting periods are recognized in earnings.
	We have contracts that are used to fix prices on forecasted purchases of inventory. 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 executed on the New York Mercantile Exchange which have not been closed or settled at the end of the reporting period.
	Fair Value Hedge
	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.
	We have certain commodity contracts associated with the Supply and Offtake Agreement discussed in Note 8 that have been accounted for as a fair value hedge, which had contract purchase volumes of 293 thousand barrels of crude oil as of December 31, 2014.
	The following tables present the effect of derivative instruments on the consolidated balance sheets:
		As of December 31, 2014
		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		$	2,629			Accrued liabilities		$	1,223
	Total derivatives not designated as hedging instruments			2,629						1,223
	Derivatives designated as hedging instruments:
	Fair value hedge	Other assets		$	10,223					$	—
	Total derivatives designated as hedging instruments			10,223						—
	Total derivatives			$	12,852					$	1,223
		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		$	303			Accrued liabilities		$	281
	Total derivatives not designated as hedging instruments			303						281
	Derivatives designated as hedging instruments:
	Fair value hedge			$	—			Other non-current liabilities		$	2,304
	Total derivatives designated as hedging instruments			—						2,304
	Total derivatives			$	303					$	2,585
	The following tables present the effect of derivative instruments on the consolidated statements of operations:
	Derivatives in fair value hedging relationships:
				Gain (Loss) Recognized in Income
				Year Ended December 31,
		Location		2014				2013				2012
	Fair value hedge (1)	Interest expense		$	12,527			$	(1,977	)		$	(327	)
	Total derivatives			$	12,527			$	(1,977	)		$	(327	)
	___________
	-1	Changes in the fair value hedge are substantially offset by changes in the hedged item.
	Derivatives not designated as hedging instruments:
				Gain (Loss) Recognized in Income
				Year Ended December 31,
		Location		2014				2013				2012
	Commodity contracts (futures and forwards)	Cost of sales		$	(2,352	)		$	4,516			$	7,038
	Commodity contracts (swaps) (1)	Cost of sales		—				—				(13,951		)
	Total derivatives			$	(2,352	)		$	4,516			$	(6,913	)
	___________
	-1	Related to derivatives with a related party.
	Offsetting Assets and Liabilities
	Our derivative 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 consolidated balance sheets.
	The following table presents offsetting information regarding our derivatives by type of transaction as of December 31, 2014 and 2013:
		Gross Amounts of Recognized Assets/ Liabilities				Gross Amounts offset in the Statement of Financial Position				Net Amounts 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, 2014
	Derivative Assets:
	Commodity contracts (futures and forwards)	$	3,309			$	(680	)		$	2,629			$	(1,223	)	$	—	$	1,406
	Fair value hedge	10,223				—				10,223				—			—		10,223
	Derivative Liabilities:
	Commodity contracts (futures and forwards)	$	1,903			$	(680	)		$	1,223			$	(1,223	)	$	—	$	—
	As of December 31, 2013
	Derivative Assets:
	Commodity contracts (futures and forwards)	$	514			$	(211	)		$	303			$	(281	)	$	—	$	22
	Derivative Liabilities:
Commodity contracts (futures and forwards)	$	492			$	(211	)		$	281			$	(281	)	$	—	$	—
Fair value hedge	2,304				—				2,304				—			—		2,304
Compliance Program Market Risk
We are obligated by government regulations to blend a certain percentage of biofuels into the products that we produce and are consumed in the U.S. We purchase biofuels from third parties and blend those biofuels into our products, and each gallon of biofuel purchased includes a renewable identification number, or 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. Alternatively, if we have a RINs surplus, some of those RINs could be sold. Any such sales would be subject to our normal credit evaluation process.
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 manage this risk by purchasing RINs when prices are deemed favorable utilizing fixed price purchase contracts. Some of these contracts are derivative instruments; however, we elect the normal purchase and sale exception and do not record these contracts at their fair values.
The cost of meeting our obligations under these compliance programs was $6,697 and $14,917 for the years ended December 31, 2014 and 2013, respectively. These amounts are reflected in cost of sales in the consolidated statements of operations. We were not subject to the renewable fuel standards requirements for the year ended December 31, 2012.

Significant_Customers

Significant Customers	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Schedule of Revenue by Major Customers by Reporting Segments [Table Text Block]	Significant Customers
	For the year ended December 31, 2014, we had two third party customers and related party customers which account for approximately 43% of net sales. Individually, third party customers accounted for 13% and 13% of net sales and related party customers accounted for 17% of net sales for the year ended December 31, 2014.
	For the year ended December 31, 2013, we had two third party customers and related party customers which account for approximately 40% of net sales. Individually, third party customers accounted for 12% and 10% of net sales and related party customers accounted for 18% of net sales for the year ended December 31, 2013.
	For the year ended December 31, 2012, we had two third party customers and related party customers which account for approximately 37% of net sales. Individually, third party customers accounted for 12% and 10% of net sales and related party customers accounted for 15% of net sales for the year ended December 31, 2012.
	At December 31, 2014 and 2013, 24% and 27%, respectively, of total third party and related party accounts and other receivables, net were from significant customers discussed above.

Inventories

Inventories	12 Months Ended
	Dec. 31, 2014
Inventory Disclosure [Abstract]
Inventory Disclosure	Inventories
	Carrying value of inventories consisted of the following:
		As of December 31,
		2014		2013
	Crude oil, refined products and blendstocks	$	30,239	$	25,246
	Crude oil consignment inventory (Note 8)	5,278		14,214
	Materials and supplies	9,645		9,686
	Total inventories	$	45,162	$	49,146
	A reduction of inventory volumes during 2013 resulted in a liquidation of LIFO inventory layers. The liquidation increased cost of sales by $1,091 during 2013. There were no liquidations of LIFO inventory layers during 2014 and 2012.
	At December 31, 2014, the market value of inventories was less than our inventory cost on a LIFO basis, and, as a result, we recorded a lower of cost or market adjustment which increased cost of sales by $4,650. At December 31, 2014, the carrying value of crude oil, refined products and blendstock inventories approximates fair market value. At December 31, 2013, market values of crude oil, refined products and blendstock inventories exceeded LIFO costs by $21,216.

Inventory_Financing_Agreement

Inventory Financing Agreement	12 Months Ended
	Dec. 31, 2014
Inventory Financing Agreement [Abstract]
Inventory Financing Agreements	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 Big Spring refinery and (ii) we agreed to sell to J. Aron, and J. Aron agreed to buy from us, at market prices, certain refined products produced at the Big Spring 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 facilities, and to identify prospective purchasers of refined products on J. Aron’s behalf. As amended in February 2015, the Supply and Offtake Agreement has an initial term that expires in May 2021. J. Aron may elect to terminate the Supply and Offtake Agreement prior to the expiration of the initial term beginning in May 2018 and upon each anniversary thereof, on six months prior notice. We may elect to terminate in May 2020 on six months prior notice.
	Following expiration or termination of the Supply and Offtake Agreement, we are obligated to purchase the crude oil and refined product inventories then owned by J. Aron and located at the Big Spring refinery at then current market prices.
	Associated with the Supply and Offtake Agreement, we have a fair value hedge of our inventory purchase commitment with J. Aron and crude oil inventory consigned to J. Aron (“crude oil consignment inventory”). Additionally, financing charges related to the Supply and Offtake Agreement are recorded as interest expense in the consolidated statements of operations.
	At December 31, 2014 and 2013, we had net current payables of $10,544 and net current receivables of $11,640, respectively, to J. Aron for purchases and sales as well as a consignment inventory receivable representing a deposit paid to J. Aron of $6,290 and $6,290, respectively. Additionally, at December 31, 2014 and 2013, we had non-current liabilities for the original financing of $17,497 and $24,482, respectively, net of the related fair value hedge.
	Additionally, we had current payables of $1,010 and $263 at December 31, 2014 and 2013, 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.

Property_Plant_and_Equipment_N

Property, Plant, and Equipment, Net	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment, Net [Abstract]
Property, Plant and Equipment Disclosure	Property, Plant and Equipment, Net
	Property, plant and equipment, net consisted of the following:
		As of December 31,
		2014			2013
	Refining facilities	$	685,036		$	677,085
	Accumulated depreciation	(239,330		)	(204,200		)
	Property, plant and equipment, net	$	445,706		$	472,885
	Depreciation expense for the years ended December 31, 2014, 2013 and 2012 was $35,185, $34,392 and $33,221, respectively.

Other_Assets_Net

Other Assets, Net	12 Months Ended
	Dec. 31, 2014
Other Assets [Abstract]
Other Assets Disclosure	Other Assets, Net
	Other assets, net consisted of the following:
		As of December 31,
		2014		2013
	Deferred turnaround and catalyst costs	$	54,310	$	7,774
	Deferred debt issuance costs	5,725		7,782
	Receivable from supply and offtake agreement (Note 8)	6,290		6,290
	Fair value hedge (Note 8)	10,223		—
	Other	9,331		9,420
	Total other assets	$	85,879	$	31,266

Accrued_Liabilities_and_Other_

Accrued Liabilities and Other Non-Current Liabilities	12 Months Ended
	Dec. 31, 2014
Accrued Liabilities and Other Liabilities [Abstract]
Accrued Liabilities and Other Non-Current Liabilities	Accrued Liabilities and Other Non-Current Liabilities
	Accrued liabilities and other non-current liabilities consisted of the following:
		As of December 31,
		2014		2013
	Accrued Liabilities:
	Taxes other than income taxes, primarily excise taxes	$	41,357	$	30,354
	Accrued finance charges	427		1,365
	Environmental accrual (Note 15)	1,671		1,307
	Commodity contracts	1,223		281
	Other	9,888		11,185
	Total accrued liabilities	$	54,566	$	44,492
	Other Non-Current Liabilities:
	Consignment inventory obligation (Note 8)	$	27,720	$	22,178
	Fair value hedge (Note 8)	—		2,304
	Environmental accrual (Note 15)	5,486		5,640
	Asset retirement obligations	2,084		1,973
	Other	3,456		2,799
	Total other non-current liabilities	$	38,746	$	34,894
	The following table summarizes the activity relating to the asset retirement obligations for the years ended December 31, 2014 and 2013:
		As of December 31,
		2014		2013
	Balance at beginning of year	$	1,973	$	1,890
	Accretion expense	111		83
	Additions	—		—
	Balance at end of year	$	2,084	$	1,973

Indebtedness

Indebtedness	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Debt Disclosure	Indebtedness
	Debt consisted of the following:
		As of December 31,
		2014			2013
	Term loan credit facility	$	242,376		$	244,322
	Revolving credit facility	60,000			100,000
	Total debt	302,376			344,322
	Less: Current portion	2,500			2,500
	Total long-term debt	$	299,876		$	341,822
	(a)	Partnership Term Loan Credit Facility
	In connection with the Offering, we were assigned $250,000 of the aggregate principal balance of the Alon USA Energy term loan (the “Partnership Term Loan”). The Partnership Term Loan requires principal payments of $2,500 per annum paid in quarterly installments until maturity in November 2018.
	The Partnership Term Loan bears interest at a rate equal to the sum of (i) the Eurodollar rate (with a floor of 1.25% per annum) plus (ii) a margin of 8.00% per annum for a per annum rate of 9.25%, based on current Eurodollar market rates at December 31, 2014.
	The Partnership Term Loan is secured by a first priority lien on all of our fixed assets and other specified property, as well as on our general partner interest held by the General Partner, and a second lien on our cash, accounts receivables, inventories and related assets.
	The Partnership Term Loan contains restrictive covenants, such as restrictions on liens, mergers, consolidations, sales of assets, additional indebtedness, different businesses, certain lease obligations and certain restricted payments. The Partnership Term Loan does not contain any maintenance financial covenants.
	At December 31, 2014 and 2013, the Partnership Term Loan had an outstanding balance (net of unamortized discount) of $242,376 and $244,322, respectively.
	(b)	Revolving Credit Facility
	We have a $240,000 revolving credit facility (the “Revolving Credit Facility”) that will mature in March 2016. The Revolving Credit Facility can be used both for borrowings and the issuance of letters of credit subject to a limit of the lesser of the facility amount or the borrowing base amount under the facility.
	Borrowings under the Revolving Credit Facility bear interest at the Eurodollar rate plus 3.50% per annum subject to an overall minimum interest rate of 4.00%.
	The Revolving Credit Facility is secured by a first lien on our cash, accounts receivables, inventories and related assets and a second lien on our fixed assets and other specified property.
	The Revolving Credit Facility contains maintenance financial covenants. At December 31, 2014, we were in compliance with these covenants.
	We had borrowings of $60,000 and $100,000 and letters of credit outstanding of $23,511 and $109,772 under the Revolving Credit Facility at December 31, 2014 and 2013, respectively.
	(c)	Maturity of Long-Term Debt
	The aggregate scheduled maturities of long-term debt for each of the five years subsequent to December 31, 2014 are as follows:
	2015	$	2,500
	2016	62,500
	2017	2,500
	2018	234,876
	2019	—
	Total	$	302,376
	(d)	Interest and Financing Expense
	Interest and financing expense included the following:
		Year Ended December 31,
		2014			2013			2012
	Interest expense on third party debt	$	24,906		$	25,815		$	9,454
	Letters of credit and finance charges	21,082			13,241			11,628
	Amortization of debt issuance costs	2,057			1,990			2,105
	Amortization of original issuance discount	554			511			61
	Less: Capitalized interest	(1,893		)	(1,083		)	(1,013		)
	Total interest expense	$	46,706		$	40,474		$	22,235

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Tax Disclosure	Income Taxes
	We are a partnership for U.S. federal income tax purposes and thus our income is taxed directly to our owners. As a result, we do not incur U.S. federal income taxes.
	We are unable to readily determine the net difference in the bases of our assets and liabilities for financial and tax reporting purposes because individual unitholders have different investment bases depending upon the timing and price of acquisition of their partnership units.

Partners_Equity

Partners' Equity	12 Months Ended
	Dec. 31, 2014
Partners' Capital Notes [Abstract]
Partners' Capital Notes Disclosure	Partners' Equity (unit values in dollars)
	We had 62,506,550 common public units outstanding as of December 31, 2014. Alon Energy owned 51,000,000 of our common units as of December 31, 2014 which constitutes 81.6% ownership interest in us.
	Cash Distributions. We have adopted a policy pursuant to which we will distribute all of the available cash generated each quarter, as defined in the partnership agreement and subject to the approval of the board of directors of the General Partner. The per unit amount of available cash to be distributed each quarter, if any, will be distributed within 60 days following the end of such quarter.
	During the year ended December 31, 2014, we paid cash distributions of $126,262, or $2.02 per unit. During the year ended December 31, 2013, we paid cash distributions of $172,506, or $2.76 per unit. As the initial public offering was completed in November 2012, no cash distributions were paid during the year ended December 31, 2012, however, our Predecessor made net cash payments to Alon Energy of $410,106.
	Restricted Units. We, through our General Partner, have adopted the Alon USA Partners, LP 2012 Long-Term Incentive Plan (the “LTIP”) for the employees, consultants and the directors of the Partnership, the General Partner and its affiliates who perform services for us. The LTIP provides grants of options, unit appreciation rights, restricted units, phantom units, unit awards, substitute awards, other unit-based awards, cash awards, performance awards and distribution equivalent rights. The maximum aggregate number of common units that may be issued under the LTIP shall not exceed 3,125,000 units.
	During the year ended December 31, 2014, we granted awards totaling 4,083 restricted common units at an average grant date price of $18.38 per unit to non-employee directors of the General Partner. During the year ended December 31, 2013, we granted awards totaling 2,467 restricted common units at an average grant date price of $20.27 per unit to non-employee directors of the General Partner. The restricted common units granted to the non-employee directors vest over a period of three
	years, assuming continued service at vesting.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies Disclosure [Text Block]	Commitments and Contingencies
	(a) Leases
	We have long-term lease commitments for land, office facilities and related equipment and various equipment and facilities used in the storage and transportation of refined products. In most cases 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 buildings, land, equipment, and pipelines expiring at various dates over the next nine years. Certain long-term operating leases relating to buildings, land and pipelines include options to renew for additional periods. At December 31, 2014, minimum lease payments on operating leases were as follows:
	Year ending December 31,
	2015	$	17,430
	2016	17,215
	2017	17,067
	2018	11,568
	2019	5,806
	2020 and thereafter	3,240
	Total	$	72,326
	Total rental expense was $15,546, $11,396 and $11,735 for the years ended December 31, 2014, 2013 and 2012, respectively. Contingent rentals and subleases were not significant.
	(b) 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 our refinery, terminals and pipelines. We are also party to various refined product and crude oil supply and exchange agreements, which are typically short-term in nature or provide terms for cancellation.
	We have a pipelines and terminals agreement with Holly Energy Partners (“HEP”) through February 2020 with three additional five year renewal terms exercisable at our sole option. Pursuant to the pipelines and terminals agreement, we have committed to transport and store minimum volumes of refined products in these pipelines and terminals. The tariff rates applicable to the transportation of refined products on the pipelines are variable, with a base fee which is reduced for volumes exceeding defined volumetric targets. The agreement provides for the reduction of the minimum volume requirement under certain circumstances. The service fees for the storage of refined products in the terminals are initially set at rates competitive in the marketplace.
	We have a throughput and deficiency agreement with Sunoco Pipeline, LP (“Sunoco”) that gives us the option to transport crude oil through the Amdel Pipeline either (1) westbound from the Nederland Terminal to the Big Spring refinery, or (2) eastbound from the Big Spring refinery to the Nederland Terminal for further barge transportation to Alon Energy’s Krotz Springs, Louisiana refinery. Our minimum throughput commitment is 15,645 bpd. The agreement is for five years from the operational date of September 2012 with an option to extend the agreement by four additional thirty-month periods.
	We have an arrangement with Centurion Pipeline L.P. (“Centurion”) through June 2021. This arrangement gives us transportation pipeline capacity to ship crude oil from Midland to the Big Spring refinery using Centurion’s approximately forty-mile long pipeline system from Midland to Roberts Junction and our three-mile pipeline from Roberts Junction to the Big Spring refinery which we lease to Centurion. Our minimum throughput commitment is 25,000 bpd.
	(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 owned by the Partnership and are associated with past or present operations. We are currently participating in environmental investigations, assessments and cleanups pertaining to the refinery, pipelines and terminals. 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 an environmental agreement with HEP pursuant to which we agreed to indemnify HEP against costs and liabilities incurred by HEP to the extent resulting from the existence of environmental conditions at the pipelines or terminals or from violations of environmental laws with respect to the pipelines and terminals occurring prior to February 28, 2005. Our environmental indemnification obligations under the environmental agreement expired on March 1, 2015. However, with respect to any remediation required for environmental conditions existing prior to February 28, 2005, we have the option under the environmental agreement to perform such remediation ourself in lieu of indemnifying HEP for their costs of performing such remediation. Pursuant to this option, we continue to perform the ongoing remediation at the Abilene and Wichita Falls terminals. Any remediation required under the terms of the environmental agreement is limited to the standards under the applicable environmental laws as in effect at February 28, 2005.
	We have an environmental agreement with Sunoco pursuant to which we agreed to indemnify Sunoco against costs and liabilities incurred by Sunoco to the extent resulting from the existence of environmental conditions at the pipelines or from violations of environmental laws with respect to the pipelines occurring prior to March 1, 2006. With respect to any remediation required for environmental conditions existing prior to March 1, 2006, we have the option to perform such remediation ourself in lieu of indemnifying Sunoco for their costs of performing such remediation.
	We have accrued environmental remediation obligations of $7,157 ($1,671 current liability and $5,486 non-current liability) at December 31, 2014 and $6,947 ($1,307 current liability and $5,640 non-current liability) at December 31, 2013. Environmental liabilities with payments that are fixed or reliably determinable have been discounted to present value at a rate of 2.32%.
	The table below summarizes our environmental liability accruals:
		As of December 31,
		2014		2013
	Discounted environmental liabilities	$	5,011	$	5,815
	Undiscounted environmental liabilities	2,146		1,132
	Total accrued environmental liabilities	$	7,157	$	6,947
	As of December 31, 2014, the estimated future payments of environmental obligations for which discounts have been applied are as follows:
	Year ending December 31,
	2015	$	755
	2016	542
	2017	507
	2018	387
	2019	387
	2020 and thereafter	3,245
	Discounted environmental liabilities, gross	5,823
	Less: Discount applied	812
	Discounted environmental liabilities	$	5,011

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Related Party Transactions Disclosure	Related Party Transactions
	Sales and Receivables
	Sales to related parties include motor fuels and asphalt sold to other Alon Energy subsidiaries at prices substantially determined by reference to market commodity pricing information. These sales are included in net sales in the consolidated statements of operations. Accounts receivable from related parties includes sales of motor fuels and is shown separately on the consolidated balance sheets.
	Costs Allocated from Alon Energy
	The Partnership is a subsidiary of Alon Energy and is operated as a component of the integrated operations of Alon Energy. As such, the executive officers of Alon Energy, who are employed by another subsidiary of Alon Energy, also serve as executive officers of the General Partner and Alon Energy’s other subsidiaries.
	(a)	Corporate Overhead Allocations
	Alon Energy performs general corporate and administrative services and functions for us and their 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 the Partnership based primarily on the estimated 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. The management of Alon Energy and the General Partner consider these allocations to be reasonable. We record the amount of such allocations as selling, general and administrative expenses within our consolidated statements of operations. Our allocation for selling, general and administrative expenses was $11,229, $11,731 and $10,952 for the years ended December 31, 2014, 2013 and 2012, respectively.
	(b)	Labor Costs
	As we are operated as a component of Alon Energy’s integrated operations, we have no employees. As a result, employee expense costs for Alon Energy employees working in our operations have been allocated to us and recorded as payroll expense in direct operating expenses. The allocated portion of Alon Energy’s employee expense costs included in direct operating expenses was $26,473, $24,401 and $23,064 for the years ended December 31, 2014, 2013 and 2012, respectively.
	(c)	Insurance Costs
	Insurance costs related to the Big Spring refinery and wholesale marketing operations are allocated to us by Alon Energy based on estimated insurance premiums on a stand-alone basis relative to Alon Energy’s total insurance premium. Our allocation for insurance costs included in direct operating expenses was $7,270, $10,494 and $9,992 for the years ended December 31, 2014, 2013 and 2012, respectively.
	Subordinated Debt
	Our Predecessor had subordinated debt notes with Alon Energy and certain of its subsidiaries. These notes were to mature in January 2018. The notes had no prepayment penalty or any covenant requirements. The interest rates charged on these notes ranged from 6% to 10%. Interest expense pertaining to the subordinated notes is disclosed separately on the consolidated statements of operations. In conjunction with the Offering in 2012, we repaid $171,120 of the subordinated debt notes and Alon Energy contributed to us the remaining outstanding subordinated debt note balance of $178,163, leaving no remaining subordinated debt balance.
	Distributions
	During the year ended December 31, 2014, we paid cash distributions of $126,262, or $2.02 per unit. The total cash distribution paid to Alon Energy was $103,020. During the year ended December 31, 2013, we paid cash distributions of $172,506, or $2.76 per unit. The total cash distribution paid to Alon Energy was $140,760. As the initial public offering was completed in November 2012, no cash distributions were paid during the year ended December 31, 2012, however, our Predecessor made net cash payments to Alon Energy of $410,106.
	Agreements with Alon Energy
	As of December 31, 2014, we have the following agreements with Alon Energy:
	(a)	Omnibus Agreement
	Under the terms of the omnibus agreement between us and Alon Energy, we have the right of first refusal if Alon Energy or any of its controlled affiliates has the opportunity to acquire a controlling interest in any refinery and related crude oil and refined product logistic assets, including non-retail transportation terminal sales, and that operate in Arizona, Arkansas, Colorado, Kansas, New Mexico, Oklahoma or Texas. In addition, pursuant to the terms of the omnibus agreement, we will have a 60-day exclusive right of negotiation if Alon Energy or any of its controlled affiliates decide to attempt to sell any refinery and related crude oil and refined product logistic assets, including non-retail transportation terminal sales, that operate in Arizona, Arkansas, Colorado, Kansas, New Mexico, Oklahoma or Texas.
	(b)	Services Agreement
	The Services Agreement among the Partnership, the General Partner and Alon Energy addresses certain aspects of our relationship with the General Partner and Alon Energy, including the provision by Alon Energy or its service subsidiary to us of certain general and administrative services and our agreement to reimburse Alon Energy for such services; and the provision by Alon Energy or its service subsidiary to us of such employees as may be necessary to operate and manage our business, and our agreement to reimburse Alon Energy for the expenses associated with such employees.
	Pursuant to the Services Agreement, we have agreed to reimburse Alon Energy or its service subsidiary for (i) all reasonable direct and indirect costs and expenses incurred by it in connection with the performance of these services and (ii) all other reasonable expenses allocable to the Partnership or the General Partner or otherwise incurred by Alon Energy in connection with the operation of our business.
	(c)	Tax Sharing Agreement
	Under the terms of the Tax Sharing Agreement by and among the Partnership and Alon Energy, we must reimburse Alon Energy for our share of state and local income and other taxes borne by Alon Energy due to our results being included in a combined or consolidated tax return filed by Alon Energy.
	(d)	Fuel Supply Agreement
	Pursuant to the terms of the 20-year Fuel Supply Agreement between the Partnership and Southwest Convenience Stores, LLC (“Southwest”), a subsidiary of Alon Energy, we supply substantially all of the motor fuel requirements of Alon Energy’s retail convenience stores. The volume of motor fuels sold under the Fuel Supply Agreement is determined monthly based upon Southwest’s estimated requirements. Southwest purchases such motor fuels at a price equal to the price per unit in effect at the time of delivery less applicable terminal discounts plus all applicable freight, taxes, pipeline tariff and delivery place differentials.
	The Fuel Supply Agreement additionally provides for (i) Southwest’s mandatory participation in our credit card payment network, (ii) Southwest’s use of the “Alon” name and related marks in connection with the use of the credit card payment network and the resale of the motor fuels purchased pursuant to the Fuel Supply Agreement and (iii) marketing services for the benefit of Southwest (at an additional cost).
	(e)	Asphalt Supply Agreement
	We also entered into a 20-year Asphalt Supply Agreement with Alon Asphalt Company (“Alon Asphalt”), a subsidiary of Alon Energy, under which Alon Asphalt purchases all of the asphalt that we produce. The volume of asphalt sold pursuant to the Asphalt Supply Agreement is based upon actual production, but we are required to provide good faith non-binding forecasts of our monthly production estimates for each contract year.
	Products are sold under the Asphalt Supply Agreement at prices equal to the three day average price for such product, determined by reference to the value derived from the pricing formula set forth in the Asphalt Supply Agreement for such product on the day of delivery or lifting and for the two business days prior to the date of delivery or lifting. Products with a contract term exceeding one year require the parties to meet annually to reexamine the price for such product.
	(f)	Leasing Agreements
	In June 2014, we entered into six-year lease agreements with a subsidiary of Alon Energy to lease equipment at the Big Spring refinery. The lease agreements were effective July 1, 2014 and require fixed monthly payments amounting to $4,920 annually. Rent payments were $2,460 for the year ended December 31, 2014.
	These agreements were reviewed and approved by the Conflicts Committee of the General Partner.

Quarterly_Information_unaudite

Quarterly Information (unaudited)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Information [Text Block]	Quarterly Information (unaudited)
	Selected financial data by quarter is set forth in the table below:
		Quarters
		First		Second		Third			Fourth
	2014
	Net sales	$	856,460	$	725,852	$	838,882		$	800,179
	Operating income	54,038		19,010		89,623			55,308
	Net income	42,241		7,802		76,993			42,099
	Earnings per unit	$	0.68	$	0.12	$	1.23		$	0.67
	2013
	Net sales	$	804,167	$	865,694	$	881,902		$	878,524
	Operating income (loss)	103,813		54,750		(3,932		)	24,046
	Net income (loss)	93,525		45,321		(16,120		)	13,496
	Earnings (loss) per unit	$	1.5	$	0.73	$	(0.26	)	$	0.22

Subsequent_Events

Subsequent Events	12 Months Ended
	Dec. 31, 2014
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events
	Partnership Distribution
	On February 5, 2015 the Board of the General Partner approved a cash distribution to our common unitholders of $0.70 per common unit. The cash distribution was paid on March 2, 2015 to unitholders of record at the close of business on February 17, 2015.
	Amended Supply and Offtake Agreement
	In February 2015, we amended the Supply and Offtake Agreement with J. Aron and extended the initial terms through May 2021. J. Aron may elect to terminate the Supply and Offtake Agreement prior to the expiration of the initial term beginning in May 2018 and upon each anniversary thereof, on six months prior notice. We may elect to terminate in May 2020 on six months prior notice.

Significant_Accounting_Policie

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Consolidation, Policy	Basis of Presentation
	The consolidated financial statements and related notes for the periods beginning and following November 27, 2012, present the consolidated financial position, results of operations, cash flows and partners’ equity of the Partnership and its consolidated subsidiaries. Additionally, the accompanying financial statements and related notes for periods presented through November 26, 2012 present the combined results of operations, cash flows and partners’ equity of Alon USA Partners, LP Predecessor (“Predecessor”), our predecessor for accounting purposes, at historical cost. All significant intercompany balances and transactions have been eliminated.
Use of Estimates, Policy	Use of Estimates
	These consolidated financial statements 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Revenue Recognition, Policy	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 consolidated statements of operations and profits are recognized when the exchanged product is sold.
	Revenue from our inventory financing agreement (Note 8) 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 consolidated statements of operations.
Cost Classifications, Policy	Cost Classifications
	Cost of sales includes principally crude oil, blending materials, other raw materials and transportation costs, which include costs associated with our crude oil and product pipelines. Cost of sales excludes depreciation and amortization, which is presented separately in the consolidated 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. These costs also include actual costs incurred by Alon Energy and allocated to us.
	Selling, general and administrative expenses primarily include corporate overhead costs and marketing expenses. These costs also include actual costs incurred by Alon Energy and allocated to us.
	Interest expense includes interest expense, letters of credit, financing costs associated with crude oil purchases, financing fees and amortization of both original issuance discount and deferred debt issuance costs but excludes capitalized interest. Original issuance discount and debt issuance costs are amortized over the term of the related debt using the effective interest method.
Cash and Cash Equivalents, Policy	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.
Trade and Other Accounts Receivable, Policy	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. We perform ongoing credit evaluations of our customers and require letters of credit, prepayments or other collateral or guarantees as management deems appropriate. Allowance for doubtful accounts is based on a combination of current sales and specific identification methods.
	Credit risk is minimized as a result of the ongoing credit assessment of our customers and a lack of concentration in our customer base. Credit losses are charged to allowance for doubtful accounts when deemed uncollectible. Our allowance for doubtful accounts is reflected as a reduction of accounts receivable in the consolidated balance sheets.
	The balance in allowance for doubtful accounts was $220 for the year ended December 31, 2014 and $277 for each of the years ended December 31, 2013 and 2012.
Inventory, Policy	Inventories
	Crude oil, refined products and blendstocks (including crude oil consignment inventory) are stated at the lower of cost or market. Cost is determined under the last-in, first-out (“LIFO”) valuation method and market is determined using current estimated selling prices. Under the LIFO valuation method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In periods of rapidly declining prices, LIFO inventories may have to be written down to market value due to the higher costs assigned to LIFO layers in prior periods. An inventory write-down to market value results in a non-cash accounting adjustment, decreasing the value of our inventory and increasing our cost of sales. Such charges are subject to reversal in subsequent periods, not to exceed LIFO cost, if prices recover. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years when inventory volumes decline and result in charging cost of sales with LIFO inventory costs generated in prior periods. 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 8). As a result of this requirement to repurchase the inventory, no revenue was recorded on these transactions and the inventory volumes remain valued under the LIFO method.
Derivatives, Policy	Hedging Activity
	We participate in Alon Energy’s company-wide risk management program. Under Alon Energy’s risk management program, all commodity forwards, futures, swaps and option contracts are considered to be part of the risk management strategy. All derivative instruments are recorded in the consolidated balance sheets as either assets or liabilities measured at their fair value. 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 in the consolidated statements of operations.
	The derivative transaction related to our inventory financing agreement has 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	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 consolidated 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. The useful lives of depreciable assets used to determine depreciation expense range from 3 to 20 years. We capitalize interest costs associated with major construction projects based on the effective interest rate on aggregate borrowings. Leasehold improvements are depreciated on the straight-line method over the shorter of the contractual lease terms or the estimated useful lives.
	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 consolidated statements of operations.
Impairment or Disposal of Long-Lived Assets, Policy	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. The future cash flows and fair values used in this assessment 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	Asset Retirement Obligations
	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 (Note 11).
Property, Plant and Equipment, Planned Major Maintenance Activities, Policy	Turnarounds and Catalysts Costs
	Our refinery units require regular major maintenance and repairs that are commonly referred to as “turnarounds.” Catalysts used in certain refinery process units are typically replaced in conjunction with planned turnarounds. We record the turnaround and catalysts costs as deferred charges in other assets in the consolidated balance sheets. We amortize the deferred costs on a straight-line basis over the period of time estimated until the next turnaround occurs, beginning the month after the completion of the turnaround. The amortization of deferred turnaround and catalysts costs are presented in depreciation and amortization in our consolidated statements of operations.
Earnings Per Unit, Policy	Earnings per Unit
	Earnings per unit applicable to limited partners is computed by dividing limited partners’ interest in net income by the weighted average number of outstanding common units.
Income Tax, Policy	Income Taxes
	We are a partnership for U.S. federal income tax purposes and thus our income is taxed directly to our owners. As a result, we do not incur U.S. federal income taxes.
	Alon Energy is subject to the Texas franchise tax and our operations are included in the consolidated Texas franchise tax return of Alon Energy. For financial reporting purposes, Texas franchise tax is calculated as if a separate return was filed.
	Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement.
Environmental Costs, Policy	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. These estimates are 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 (Note 15). 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 15 years. The amount of future expenditures for environmental remediation obligations is impossible to determine with any degree of reliability.
Commitments and Contingencies, Policy	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.
New Accounting Pronouncements, Policy	New Accounting Standards
	In May 2014, the Financial Accounting Standards Board (“FASB”) and the International Accounting Standards Board jointly issued a comprehensive new revenue recognition standard that provides accounting guidance for all revenue arising from contracts to provide goods or services to customers. This standard is intended to improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets. The requirements from the new standard are effective for interim and annual periods beginning after December 15, 2016, and early adoption is not permitted. The standard allows for either full retrospective adoption or modified retrospective adoption. We are evaluating the guidance to determine the method of adoption and the impact of this standard on our consolidated financial statements.
	In February 2015, the FASB issued an accounting standards update making targeted changes to the current consolidation guidance. The new standard changes the way certain decisions are made related to substantive rights, related parties, and decision making fees when applying the variable interest entity consolidation model and eliminates certain guidance for limited partnerships and similar entities under the voting interest consolidation model. The requirements from the updated standard are effective for interim and annual periods beginning after December 15, 2015, and early adoption is permitted. We are evaluating the effect that adopting the updated guidance will have on our consolidated financial statements and related disclosures.

Earnings_Per_Unit_Tables

Earnings Per Unit (Tables)	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	The following is a summary of our net income for the period after the completion of the Offering through December 31, 2012:
		November 27, 2012 through December 31, 2012
	Net sales	$	324,237
	Operating costs and expenses:
	Cost of sales	264,960
	Direct operating expenses	10,687
	Selling, general and administrative expenses	2,153
	Depreciation and amortization	4,632
	Total operating costs and expenses	282,432
	Operating income	41,805
	Interest expense	(4,335		)
	Interest expense - related parties	—
	Other income (loss), net	(2		)
	Income before state income tax expense	37,468
	State income tax expense	348
	Net income attributable to Alon USA Partners, LP	$	37,120
	Weighted average common units outstanding (in thousands)	62,500
	Earnings per unit	$	0.59

Fair_Value_Tables

Fair Value (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [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 consolidated balance sheets as of December 31, 2014 and 2013:
		Level 1		Level 2		Level 3		Total
	As of December 31, 2014
	Assets:
	Commodity contracts (futures and forwards)	$	1,406	$	—	$	—	$	1,406
	Fair value hedge	—		10,223		—		10,223
	As of December 31, 2013
	Assets:
	Commodity contracts (futures and forwards)	$	22	$	—	$	—	$	22
	Liabilities:
	Fair value hedge	—		2,304		—		2,304
	RINs obligation	—		334		—		334

Derivative_Financial_Instrumen1

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	The following tables present the effect of derivative instruments on the consolidated balance sheets:
		As of December 31, 2014
		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		$	2,629			Accrued liabilities		$	1,223
	Total derivatives not designated as hedging instruments			2,629						1,223
	Derivatives designated as hedging instruments:
	Fair value hedge	Other assets		$	10,223					$	—
	Total derivatives designated as hedging instruments			10,223						—
	Total derivatives			$	12,852					$	1,223
		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		$	303			Accrued liabilities		$	281
	Total derivatives not designated as hedging instruments			303						281
	Derivatives designated as hedging instruments:
	Fair value hedge			$	—			Other non-current liabilities		$	2,304
	Total derivatives designated as hedging instruments			—						2,304
	Total derivatives			$	303					$	2,585
Schedule of Fair Value Hedging Instruments, Statements of Financial Performance and Financial Position, Location	The following tables present the effect of derivative instruments on the consolidated statements of operations:
	Derivatives in fair value hedging relationships:
				Gain (Loss) Recognized in Income
				Year Ended December 31,
		Location		2014				2013				2012
	Fair value hedge (1)	Interest expense		$	12,527			$	(1,977	)		$	(327	)
	Total derivatives			$	12,527			$	(1,977	)		$	(327	)
	___________
	-1	Changes in the fair value hedge are substantially offset by changes in the hedged item.
Derivative Instruments, Gain (Loss)	Derivatives not designated as hedging instruments:
				Gain (Loss) Recognized in Income
				Year Ended December 31,
		Location		2014				2013				2012
	Commodity contracts (futures and forwards)	Cost of sales		$	(2,352	)		$	4,516			$	7,038
	Commodity contracts (swaps) (1)	Cost of sales		—				—				(13,951		)
	Total derivatives			$	(2,352	)		$	4,516			$	(6,913	)
	___________
	-1	Related to derivatives with a related party.
Summary of offsetting derivative instruments by type	The following table presents offsetting information regarding our derivatives by type of transaction as of December 31, 2014 and 2013:
		Gross Amounts of Recognized Assets/ Liabilities				Gross Amounts offset in the Statement of Financial Position				Net Amounts 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, 2014
	Derivative Assets:
	Commodity contracts (futures and forwards)	$	3,309			$	(680	)		$	2,629			$	(1,223	)	$	—	$	1,406
	Fair value hedge	10,223				—				10,223				—			—		10,223
	Derivative Liabilities:
	Commodity contracts (futures and forwards)	$	1,903			$	(680	)		$	1,223			$	(1,223	)	$	—	$	—
	As of December 31, 2013
	Derivative Assets:
	Commodity contracts (futures and forwards)	$	514			$	(211	)		$	303			$	(281	)	$	—	$	22
	Derivative Liabilities:
	Commodity contracts (futures and forwards)	$	492			$	(211	)		$	281			$	(281	)	$	—	$	—
	Fair value hedge	2,304				—				2,304				—			—		2,304

Inventories_Tables

Inventories (Tables)	12 Months Ended
	Dec. 31, 2014
Inventory Disclosure [Abstract]
Schedule of Inventory, Current	Carrying value of inventories consisted of the following:
		As of December 31,
		2014		2013
	Crude oil, refined products and blendstocks	$	30,239	$	25,246
	Crude oil consignment inventory (Note 8)	5,278		14,214
	Materials and supplies	9,645		9,686
	Total inventories	$	45,162	$	49,146

Property_Plant_and_Equipment_N1

Property, Plant, and Equipment, Net (Tables)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment, Net [Abstract]
Property, Plant and Equipment	Property, plant and equipment, net consisted of the following:
		As of December 31,
		2014			2013
	Refining facilities	$	685,036		$	677,085
	Accumulated depreciation	(239,330		)	(204,200		)
	Property, plant and equipment, net	$	445,706		$	472,885

Other_Assets_Net_Tables

Other Assets, Net (Tables)	12 Months Ended
	Dec. 31, 2014
Other Assets [Abstract]
Schedule of Other Assets	Other assets, net consisted of the following:
		As of December 31,
		2014		2013
	Deferred turnaround and catalyst costs	$	54,310	$	7,774
	Deferred debt issuance costs	5,725		7,782
	Receivable from supply and offtake agreement (Note 8)	6,290		6,290
	Fair value hedge (Note 8)	10,223		—
	Other	9,331		9,420
	Total other assets	$	85,879	$	31,266

Accrued_Liabilities_and_Other_1

Accrued Liabilities and Other Non-Current Liabilities (Tables)	12 Months Ended
	Dec. 31, 2014
Accrued Liabilities and Other Liabilities [Abstract]
Schedule of Accrued Liabilities and Other Non-Current Liabilities	Accrued liabilities and other non-current liabilities consisted of the following:
		As of December 31,
		2014		2013
	Accrued Liabilities:
	Taxes other than income taxes, primarily excise taxes	$	41,357	$	30,354
	Accrued finance charges	427		1,365
	Environmental accrual (Note 15)	1,671		1,307
	Commodity contracts	1,223		281
	Other	9,888		11,185
	Total accrued liabilities	$	54,566	$	44,492
	Other Non-Current Liabilities:
	Consignment inventory obligation (Note 8)	$	27,720	$	22,178
	Fair value hedge (Note 8)	—		2,304
	Environmental accrual (Note 15)	5,486		5,640
	Asset retirement obligations	2,084		1,973
	Other	3,456		2,799
	Total other non-current liabilities	$	38,746	$	34,894
Schedule of Change in Asset Retirement Obligation	The following table summarizes the activity relating to the asset retirement obligations for the years ended December 31, 2014 and 2013:
		As of December 31,
		2014		2013
	Balance at beginning of year	$	1,973	$	1,890
	Accretion expense	111		83
	Additions	—		—
	Balance at end of year	$	2,084	$	1,973

Indebtedness_Tables

Indebtedness (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments	Debt consisted of the following:
		As of December 31,
		2014			2013
	Term loan credit facility	$	242,376		$	244,322
	Revolving credit facility	60,000			100,000
	Total debt	302,376			344,322
	Less: Current portion	2,500			2,500
	Total long-term debt	$	299,876		$	341,822
Schedule of Maturities of Long-term Debt	The aggregate scheduled maturities of long-term debt for each of the five years subsequent to December 31, 2014 are as follows:
	2015	$	2,500
	2016	62,500
	2017	2,500
	2018	234,876
	2019	—
	Total	$	302,376
Schedule of Debt	Interest and financing expense included the following:
		Year Ended December 31,
		2014			2013			2012
	Interest expense on third party debt	$	24,906		$	25,815		$	9,454
	Letters of credit and finance charges	21,082			13,241			11,628
	Amortization of debt issuance costs	2,057			1,990			2,105
	Amortization of original issuance discount	554			511			61
	Less: Capitalized interest	(1,893		)	(1,083		)	(1,013		)
	Total interest expense	$	46,706		$	40,474		$	22,235

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]	At December 31, 2014, minimum lease payments on operating leases were as follows:
	Year ending December 31,
	2015	$	17,430
	2016	17,215
	2017	17,067
	2018	11,568
	2019	5,806
	2020 and thereafter	3,240
	Total	$	72,326
Schedule of Accrued Environmental Obligations [Table Text Block]	The table below summarizes our environmental liability accruals:
		As of December 31,
		2014		2013
	Discounted environmental liabilities	$	5,011	$	5,815
	Undiscounted environmental liabilities	2,146		1,132
	Total accrued environmental liabilities	$	7,157	$	6,947
Schedule of Estimated Undiscounted Cash Flows for Discounted Environmental Remediation Liabilities in Future Periods [Table Text Block]	As of December 31, 2014, the estimated future payments of environmental obligations for which discounts have been applied are as follows:
	Year ending December 31,
	2015	$	755
	2016	542
	2017	507
	2018	387
	2019	387
	2020 and thereafter	3,245
	Discounted environmental liabilities, gross	5,823
	Less: Discount applied	812
	Discounted environmental liabilities	$	5,011

Quarterly_Information_unaudite1

Quarterly Information (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	Selected financial data by quarter is set forth in the table below:
		Quarters
		First		Second		Third			Fourth
	2014
	Net sales	$	856,460	$	725,852	$	838,882		$	800,179
	Operating income	54,038		19,010		89,623			55,308
	Net income	42,241		7,802		76,993			42,099
	Earnings per unit	$	0.68	$	0.12	$	1.23		$	0.67
	2013
	Net sales	$	804,167	$	865,694	$	881,902		$	878,524
	Operating income (loss)	103,813		54,750		(3,932		)	24,046
	Net income (loss)	93,525		45,321		(16,120		)	13,496
	Earnings (loss) per unit	$	1.5	$	0.73	$	(0.26	)	$	0.22

Description_and_Nature_of_Busi1

Description and Nature of Business (Details) (USD $)	0 Months Ended	12 Months Ended
	Nov. 26, 2012	Dec. 31, 2014	Dec. 31, 2013
Limited Partners' Capital Account
Common units, shares outstanding		62,506,550	62,502,467
Ownership Percentage held by Parent	81.60%
Ownership Percentage by Parent in General Partnership	100.00%
Maximum
Limited Partners' Capital Account
Throughput, Average		73,000
Partner Type of Partners' Capital, Affiliated
Limited Partners' Capital Account
Common units, shares outstanding	51,000,000	51,000,000
IPO
Limited Partners' Capital Account
Sale of stock, price per share	16
IPO | Partner Type of Partners' Capital, Non-Affiliated
Limited Partners' Capital Account
Partners' Capital Account, Units, Sold in Public Offering	11,500,000

Significant_Accounting_Policie1

Significant Accounting Policies (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Allowance for Doubtful Accounts Receivable, Current	$220	$277	$277
Site Contingency, Time Frame of Disbursements	15 years
Minimum
Property, Plant and Equipment, Useful Life	3 years
Maximum
Property, Plant and Equipment, Useful Life	20 years

Earnings_Per_Unit_Details

Earnings Per Unit (Details) (USD $)	1 Months Ended	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Earnings Per Share [Abstract]
Net sales	$324,237	$800,179	$838,882	$725,852	$856,460	$878,524	$881,902	$865,694	$804,167	$3,221,373	[1]	$3,430,287	[1]	$3,476,817	[1]
Operating costs and expenses:
Cost of sales	264,960									2,823,694		3,073,044		2,883,741
Direct operating expenses	10,687									105,760		110,940		100,908
Selling, general and administrative expenses	2,153									26,446		22,276		22,807
Depreciation and amortization	4,632									47,494		45,329		46,009
Total operating costs and expenses	282,432									3,003,394		3,251,589		3,053,465
Operating income	41,805	55,308	89,623	19,010	54,038	24,046	-3,932	54,750	103,813	217,979		178,677		423,352
Interest expense	-4,335									-24,906		-25,815		-9,454
Interest expense - related parties	0									0		0		-15,691
Other income (loss), net	-2									646		23		8
Income before state income tax expense	37,468									171,919		138,226		385,434
State income tax expense	348									2,784		2,004		3,536
Net income attributable to Alon USA Partners, LP	$37,120									$169,135		$136,222		$37,120
Weighted average common units outstanding (in thousands)	62,500
Earnings per unit	$0.59	$0.67	$1.23	$0.12	$0.68	$0.22	($0.26)	$0.73	$1.50	$2.71		$2.18		$0.59
[1]	Includes sales to related parties of $563,008, $600,710 and $588,828 for the years ended December 31, 2014, 2013 and 2012, respectively.

Fair_Value_Details

Fair Value (Details) (Fair Value, Measurements, Recurring, USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Liabilities:
RINs obligation		$334
Forward Contracts | Commodity Contracts
Assets:
Derivative Assets	1,406	22
Forward Contracts | Fair Value Hedges
Assets:
Derivative Assets	10,223
Liabilities:
Derivative Liabilities		2,304
Level 1
Liabilities:
RINs obligation		0
Level 1 | Forward Contracts | Commodity Contracts
Assets:
Derivative Assets	1,406	22
Level 1 | Forward Contracts | Fair Value Hedges
Assets:
Derivative Assets	0
Liabilities:
Derivative Liabilities		0
Level 2
Liabilities:
RINs obligation		334
Level 2 | Forward Contracts | Commodity Contracts
Assets:
Derivative Assets	0	0
Level 2 | Forward Contracts | Fair Value Hedges
Assets:
Derivative Assets	10,223
Liabilities:
Derivative Liabilities		2,304
Level 3
Liabilities:
RINs obligation		0
Level 3 | Forward Contracts | Commodity Contracts
Assets:
Derivative Assets	0	0
Level 3 | Forward Contracts | Fair Value Hedges
Assets:
Derivative Assets	0
Liabilities:
Derivative Liabilities		$0

Derivative_Financial_Instrumen2

Derivative Financial Instruments, Schedule of Derivative Instruments in Statement of Financial Position, Fair Value (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivatives, Fair Value
Derivative Instruments and Hedges, Assets	$12,852	$303
Derivative Instruments and Hedges, Liabilities	1,223	2,585
Forward Contracts | Commodity Contracts
Derivatives, Fair Value
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	2,629	303
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	1,223	281
Forward Contracts | Fair Value Hedges
Derivatives, Fair Value
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	10,223
Derivative Liability, Fair Value, Amount Not Offset Against Collateral		2,304
Not Designated as Hedging Instrument
Derivatives, Fair Value
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	2,629	303
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	1,223	281
Not Designated as Hedging Instrument | Accounts Receivable | Forward Contracts | Commodity Contracts
Derivatives, Fair Value
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	2,629	303
Not Designated as Hedging Instrument | Accrued Liabilities | Forward Contracts | Commodity Contracts
Derivatives, Fair Value
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	1,223	281
Designated as Hedging Instrument
Derivatives, Fair Value
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	10,223	0
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	2,304
Designated as Hedging Instrument | Other Assets | Forward Contracts | Fair Value Hedges
Derivatives, Fair Value
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	10,223	0
Designated as Hedging Instrument | Other Noncurrent Liabilities | Forward Contracts | Fair Value Hedges
Derivatives, Fair Value
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	$0	$2,304

Derivative_Financial_Instrumen3

Derivative Financial Instruments, Schedule of Fair Value Hedging Instruments (Details) (Designated as Hedging Instrument, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Derivative Instruments, Gain (Loss)
Gain (Loss) on Fair Value Hedges Recognized in Earnings	$12,527		($1,977)		($327)
Interest Expense | Forward Contracts | Fair Value Hedges
Derivative Instruments, Gain (Loss)
Gain (Loss) on Fair Value Hedges Recognized in Earnings	$12,527	[1]	($1,977)	[1]	($327)	[1]
[1]	Changes in the fair value hedge are substantially offset by changes in the hedged item.

Derivative_Financial_Instrumen4

Derivative Financial Instruments, Schedule of Derivative Instruments, Gain (Loss) in Statements of Financial Performance (Details) (Not Designated as Hedging Instrument, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Derivative Instruments, Gain (Loss)
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	($2,352)		$4,516		($6,913)
Cost of Sales | Forward Contracts | Commodity Contracts
Derivative Instruments, Gain (Loss)
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	-2,352		4,516		7,038
Cost of Sales | Swaps | Commodity Contracts
Derivative Instruments, Gain (Loss)
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$0	[1]	$0	[1]	($13,951)	[1]
[1]	Related to derivatives with a related party.

Derivative_Financial_Instrumen5

Derivative Financial Instruments, Schedule of Offsetting Derivative Instruments by Type (Details) (Forward Contracts, USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Commodity Contracts
Derivative Asset, Fair Value, Net
Gross Amounts of Recognized Assets	$3,309	$514
Gross Amounts Offset in the Statement of Financial Position	-680	-211
Net Amounts of Assets Presented in the Statement of Financial Position	2,629	303
Derivative, Collateral, Obligation to Return Securities	-1,223	-281
Cash Collateral Received	0	0
Derivative Asset, Net Amount	1,406	22
Derivative Liability, Fair Value, Net
Gross Amounts of Recognized Liabilities	1,903	492
Gross Amounts Offset in the Statement of Financial Position	-680	-211
Net Amounts of Liabilities Presented in the Statement of Financial Position	1,223	281
Derivative, Collateral, Right to Reclaim Securities	-1,223	-281
Cash Collateral Pledged	0	0
Derivative Liability, Net Amount	0	0
Fair Value Hedges
Derivative Asset, Fair Value, Net
Gross Amounts of Recognized Assets	10,223
Gross Amounts Offset in the Statement of Financial Position	0
Net Amounts of Assets Presented in the Statement of Financial Position	10,223
Derivative, Collateral, Obligation to Return Securities	0
Cash Collateral Received	0
Derivative Asset, Net Amount	10,223
Derivative Liability, Fair Value, Net
Gross Amounts of Recognized Liabilities		2,304
Gross Amounts Offset in the Statement of Financial Position		0
Net Amounts of Liabilities Presented in the Statement of Financial Position		2,304
Derivative, Collateral, Right to Reclaim Securities		0
Cash Collateral Pledged		0
Derivative Liability, Net Amount		$2,304

Derivative_Financial_Instrumen6

Derivative Financial Instruments Textuals (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Derivative
Compliance Program Costs	$6,697	$14,917
Forward Contracts | Fair Value Hedges
Derivative
Derivative, Nonmonetary Notional Amount	293,000

Significant_Customers_Details

Significant Customers (Details) (Customer Concentration Risk)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenue
Major Customer
Concentration Risk, Percentage	43.00%	40.00%	37.00%
Revenue | Third Party Customer A
Major Customer
Concentration Risk, Percentage	13.00%	12.00%	12.00%
Revenue | Third Party Customer B
Major Customer
Concentration Risk, Percentage	13.00%	10.00%	10.00%
Revenue | Related Party Customer
Major Customer
Concentration Risk, Percentage	17.00%	18.00%	15.00%
Accounts Receivable
Major Customer
Concentration Risk, Percentage	24.00%	27.00%

Inventories_Details

Inventories (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Inventory Disclosure [Abstract]
Crude oil, refined products and blendstocks	$30,239	$25,246
Crude oil consignment inventory (Note 8)	5,278	14,214
Materials and supplies	9,645	9,686
Total inventories	$45,162	$49,146

Inventories_Textuals_Details

Inventories Textuals (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Inventory Disclosure [Abstract]
LIFO Inventory Liquidation Effect on Income - Increase (Decrease) Income		($1,091)
Lower of Cost or Market Adjustment	4,650
Excess of Replacement or Current Costs over Stated LIFO Value		$21,216

Inventory_Financing_Agreement_

Inventory Financing Agreement (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Accounts Payable, Net, Current	$186,156	$280,774
Receivable from supply agreement	6,290	6,290
Non-current liability for consignment inventory	27,720	22,178
Derivative Liabilities	1,223	281
J.Aron
Accounts Payable, Net, Current	10,544
Accounts Receivable, Net, Current		11,640
Receivable from supply agreement	6,290	6,290
Non-current liability for consignment inventory	17,497	24,482
Consigned inventory | Forward Contracts | Other Contract
Derivative Liabilities	$1,010	$263

Property_Plant_and_Equipment_N2

Property, Plant, and Equipment, Net (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Property, Plant and Equipment
Refining facilities	$685,036	$677,085
Accumulated depreciation	-239,330	-204,200
Property, plant and equipment, net	$445,706	$472,885

Property_Plant_and_Equipment_N3

Property, Plant, and Equipment, Net Textuals (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment
Depreciation	$35,185	$34,392	$33,221

Other_Assets_Net_Details

Other Assets, Net (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Other Assets, Net:
Deferred turnaround and catalyst costs	$54,310	$7,774
Deferred debt issuance costs	5,725	7,782
Receivable from supply and offtake agreement (Note 8)	6,290	6,290
Fair value hedge (Note 8)	10,223	0
Other	9,331	9,420
Total other assets	$85,879	$31,266

Accrued_Liabilities_and_Other_2

Accrued Liabilities and Other Non-Current Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Accrued Liabilities:
Taxes other than income taxes, primarily excise taxes	$41,357	$30,354
Accrued finance charges	427	1,365
Environmental accrual (Note 15)	1,671	1,307
Commodity contracts	1,223	281
Other	9,888	11,185
Total accrued liabilities	54,566	44,492
Other Non-Current Liabilities:
Consignment inventory obligation (Note 8)	27,720	22,178
Fair value hedge (Note 8)	0	2,304
Environmental accrual (Note 15)	5,486	5,640
Asset retirement obligations	2,084	1,973
Other	3,456	2,799
Total other non-current liabilities	$38,746	$34,894

Accrued_Liabilities_and_Other_3

Accrued Liabilities and Other Non-Current Liabilities, Changes in Asset Retirement Obligation (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation
Balance at beginning of year	$1,973	$1,890
Accretion expense	111	83
Additions	0	0
Balance at end of year	$2,084	$1,973

Schedule_of_LongTerm_Debt_Deta

Schedule of Long-Term Debt (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Debt Instrument
Long-term debt	$302,376	$344,322
Less: Current portion	2,500	2,500
Long-term debt	299,876	341,822
Term loan credit facility
Debt Instrument
Long-term debt	242,376	244,322
Revolving credit facility
Debt Instrument
Long-term debt	$60,000	$100,000

Partnership_Term_Loan_Credit_F

Partnership Term Loan Credit Facility (Details) (Partnership Term Loan, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument
Debt Instrument, Face Amount	$250,000
Debt Instrument, Annual Principal Payment	2,500
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum	9.25%
Partnership Term Loan Balance	$242,376	$244,322
Eurodollar
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum	1.25%
Debt Instrument, Basis Spread on Variable Rate	8.00%

Revolving_Credit_Facility_Deta

Revolving Credit Facility (Details) (Alon USA LP Credit Facility, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument
Debt Instrument, Face Amount	$240,000
Debt Instrument, Covenant Compliance	we were in compliance with these covenants
Long-term Line of Credit	60,000	100,000
Letters of Credit Outstanding, Amount	$23,511	$109,772
Eurodollar
Debt Instrument
Debt Instrument, Basis Spread on Variable Rate	3.50%
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum	4.00%

Maturity_of_LongTerm_Debt_Deta

Maturity of Long-Term Debt (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Maturities of Long-term Debt
2015	$2,500
2016	62,500
2017	2,500
2018	234,876
2019	0
Total	$302,376

Interest_and_Financing_Expense

Interest and Financing Expense (Details) (USD $)	1 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Interest Expense, Debt
Interest expense on third party debt	$4,335	$24,906	$25,815	$9,454
Letters of credit and finance charges		21,082	13,241	11,628
Amortization of debt issuance costs		2,057	1,990	2,105
Amortization of original issuance discount		554	511	61
Less: Capitalized interest		-1,893	-1,083	-1,013
Total interest expense		$46,706	$40,474	$22,235

Partners_Equity_Details

Partners' Equity (Details) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Nov. 26, 2012
Limited Partners' Capital Account
Common units, shares outstanding	62,506,550	62,502,467
Distribution Made to Limited Partner, Cash Distributions Paid	$126,262	$172,506
Cash distribution per unit	$2.02	$2.76	$0
Net cash payments to Alon Energy	$0	$0	$410,106
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	3,125,000
Stock Issued During Period, Shares, Restricted Stock Award, Gross	4,083	2,467
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$18.38	$20.27
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Partner Type of Partners' Capital, Affiliated
Limited Partners' Capital Account
Common units, shares outstanding	51,000,000			51,000,000
Ownership Percentage held by Parent	81.60%

Commitments_and_Contingencies_1

Commitments and Contingencies, Minimum Lease Payments (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Year ending December 31,
2015	$17,430
2016	17,215
2017	17,067
2018	11,568
2019	5,806
2020 and thereafter	3,240
Total	72,326
Operating Leases, Rent Expense	$15,546	$11,396	$11,735

Commitments_and_Contingencies_2

Commitments and Contingencies, Remediation Obligations (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Commitments and Contingencies Disclosure [Abstract]
Accrual for Environmental Loss Contingencies	$7,157	$6,947
Accrued Environmental Loss Contingencies, Current	1,671	1,307
Accrued Environmental Loss Contingencies, Noncurrent	$5,486	$5,640
Accrual for Environmental Loss Contingencies, Discount Rate	2.32%

Commitments_and_Contingencies_3

Commitments and Contingencies, Environmental Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Accrued Environmental Obligations [Abstract]
Discounted environmental liabilities	$5,011	$5,815
Undiscounted environmental liabilities	2,146	1,132
Total accrued environmental liabilities	$7,157	$6,947

Commitments_and_Contingencies_4

Commitments and Contingencies, Environmental (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Year ending December 31,
2015	$755
2016	542
2017	507
2018	387
2019	387
2020 and thereafter	3,245
Discounted environmental liabilities, gross	5,823
Less: Discount applied	812
Discounted environmental liabilities	$5,011	$5,815

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	12 Months Ended			1 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jun. 30, 2014
Repayments of Related Party Debt	$0	$0	$171,120
Conversion of Subordinated Debt - Related Parties			178,163
Distribution Made to Limited Partner, Cash Distributions Paid	126,262	172,506
Cash distribution per unit	$2.02	$2.76	$0
Net cash payments to Alon Energy	0	0	410,106
Operating Leases, Future Minimum Payments Due, Next Twelve Months	17,430
Operating Leases, Rent Expense	15,546	11,396	11,735
Distributions
Distribution Made to Limited Partner, Cash Distributions Paid	126,262	172,506
Cash distribution per unit	$2.02	$2.76
Net cash payments to Alon Energy			410,106
Alon Energy | Corporate Overhead Allocation
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party	11,229	11,731	10,952
Alon Energy | Labor Costs
Related Party Transaction, Expenses from Transactions with Related Party	26,473	24,401	23,064
Alon Energy | Insurance Costs
Related Party Transaction, Expenses from Transactions with Related Party	7,270	10,494	9,992
Alon Energy | Repayment of Subordinated Debt
Repayments of Related Party Debt			171,120
Conversion of Subordinated Debt - Related Parties			178,163
Alon Energy | Repayment of Subordinated Debt | Minimum
Subordinated Borrowing, Interest Rate			6.00%
Alon Energy | Repayment of Subordinated Debt | Maximum
Subordinated Borrowing, Interest Rate			10.00%
Alon Energy | Leasing Agreements
Lessee Leasing Arrangements, Operating Leases, Term of Contract				6 years
Operating Leases, Future Minimum Payments Due, Next Twelve Months	4,920
Operating Leases, Rent Expense	2,460
Alon Energy | Distributions
Distribution Made to Limited Partner, Cash Distributions Paid	$103,020	$140,760

Quarterly_Information_unaudite2

Quarterly Information (unaudited) (Details) (USD $)	1 Months Ended	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Net sales	$324,237	$800,179	$838,882	$725,852	$856,460	$878,524	$881,902	$865,694	$804,167	$3,221,373	[1]	$3,430,287	[1]	$3,476,817	[1]
Operating income (loss)	41,805	55,308	89,623	19,010	54,038	24,046	-3,932	54,750	103,813	217,979		178,677		423,352
Net income		$42,099	$76,993	$7,802	$42,241	$13,496	($16,120)	$45,321	$93,525
Earnings (loss) per unit	$0.59	$0.67	$1.23	$0.12	$0.68	$0.22	($0.26)	$0.73	$1.50	$2.71		$2.18		$0.59
[1]	Includes sales to related parties of $563,008, $600,710 and $588,828 for the years ended December 31, 2014, 2013 and 2012, respectively.

Subsequent_Events_Details

Subsequent Events (Details) (Subsequent Event, USD $)	0 Months Ended
	Feb. 05, 2015
Subsequent Event
Subsequent Event
Cash distribution per unit	$0.70