Alon USA Partners (ALDW) 10-K 27 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information Document - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 21, 2017	Jun. 30, 2016
Entity Information
Entity Registrant Name	Alon USA Partners, LP
Entity Central Index Key	1,556,766
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		62,520,220
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 115,962,352

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 73,524	$ 132,953
Accounts and other receivables, net	82,292	59,581
Accounts and other receivables, net - related parties	11,425	8,005
Inventories	49,682	35,444
Prepaid expenses and other current assets	4,949	6,745
Total current assets	221,872	242,728
Property, plant and equipment, net	420,554	434,619
Other assets, net	53,211	71,237
Total assets	695,637	748,584
Current liabilities:
Accounts payable	249,835	253,325
Accrued liabilities	43,100	40,707
Current portion of long-term debt	2,500	2,500
Total current liabilities	295,435	296,532
Other non-current liabilities	62,880	31,513
Long-term debt	233,819	289,582
Total liabilities	592,134	617,627
Commitments and contingencies (Note 15)
Partners’ equity:
General Partner	0	0
Common unitholders - 62,520,220 and 62,510,039 units issued and outstanding at December 31, 2016 and 2015, respectively	103,503	130,957
Total partners’ equity	103,503	130,957
Total liabilities and partners’ equity	$ 695,637	$ 748,584

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - shares	Dec. 31, 2016	Dec. 31, 2015
Common units, shares issued	62,520,220	62,510,039
Common units, units outstanding	62,520,220	62,510,039

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net sales (1)	[1]	$ 1,807,732	$ 2,157,191	$ 3,221,373
Operating costs and expenses:
Cost of sales		1,588,219	1,767,291	2,823,694
Direct operating expenses		97,338	98,929	105,760
Selling, general and administrative expenses		31,983	32,353	26,446
Depreciation and amortization		57,524	55,112	47,494
Total operating costs and expenses		1,775,064	1,953,685	3,003,394
Operating income		32,668	203,506	217,979
Interest expense		(37,128)	(45,987)	(46,706)
Other income, net		593	52	646
Income (loss) before state income tax expense		(3,867)	157,571	171,919
State income tax expense		537	672	2,784
Net income (loss)		$ (4,404)	$ 156,899	$ 169,135
Earnings (loss) per unit		$ (0.07)	$ 2.51	$ 2.71
Weighted average common units outstanding (in thousands)		62,516	62,509	62,505
Cash distribution per unit		$ 0.37	$ 3.43	$ 2.02
[1]	Includes sales to related parties of $307,497, $358,194 and $563,008 for the years ended December 31, 2016, 2015 and 2014, respectively.

Consolidated Statements of Ope5

Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Consolidated Statement of Operations (Parenthetical) [Abstract]
Sales to related parties	$ 307,497	$ 358,194	$ 563,008

Consolidated Statement of Partn

Consolidated Statement of Partners' Equity Statement - USD ($) $ in Thousands	Total	Common Unitholders	General Partner
Total partners' equity at Dec. 31, 2013	$ 145,442	$ 145,442	$ 0
Unit-based compensation	87	87	0
Distributions paid to unitholders	(126,262)	(126,262)	0
Net income (loss)	169,135	169,135	0
Total partners' equity at Dec. 31, 2014	188,402	188,402	0
Unit-based compensation	61	61	0
Distributions paid to unitholders	(214,405)	(214,405)	0
Net income (loss)	156,899	156,899	0
Total partners' equity at Dec. 31, 2015	130,957	130,957	0
Unit-based compensation	82	82	0
Distributions paid to unitholders	(23,132)	(23,132)	0
Net income (loss)	(4,404)	(4,404)	0
Total partners' equity at Dec. 31, 2016	$ 103,503	$ 103,503	$ 0

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities:
Net income (loss)	$ (4,404)	$ 156,899	$ 169,135
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation and amortization	57,524	55,112	47,494
Unit-based compensation	82	61	87
Deferred income taxes	0	(921)	657
Amortization of debt issuance costs	1,736	2,408	2,057
Amortization of original issuance discount	650	599	554
Changes in operating assets and liabilities:
Accounts and other receivables, net	(22,711)	8,964	55,236
Accounts and other receivables, net - related parties	(3,420)	1,461	5,155
Inventories	(14,238)	9,718	3,984
Prepaid expenses and other current assets	1,796	2,418	(4,521)
Other assets, net	6,068	(3,065)	(12,371)
Accounts payable	59,549	27,031	(87,829)
Accrued liabilities	3,636	(14,325)	13,671
Other non-current liabilities	(8,153)	(6,615)	3,195
Net cash provided by operating activities	78,115	239,745	196,504
Cash flows from investing activities:
Capital expenditures	(23,587)	(23,566)	(16,064)
Capital expenditures for turnarounds and catalysts	(9,764)	(5,984)	(58,736)
Net cash used in investing activities	(33,351)	(29,550)	(74,800)
Cash flows from financing activities:
Distributions paid to common unitholders	(4,262)	(39,475)	(23,242)
Distributions paid to unitholders - Alon Energy	(18,870)	(174,930)	(103,020)
RINs financing transactions	(23,561)	40,138	(200)
Deferred debt issuance costs	0	(1,800)	0
Revolving credit facility, net	(55,000)	(5,000)	(40,000)
Payments on long-term debt	(2,500)	(2,500)	(2,500)
Net cash used in financing activities	(104,193)	(183,567)	(168,962)
Net increase (decrease) in cash and cash equivalents	(59,429)	26,628	(47,258)
Cash and cash equivalents, beginning of period	132,953	106,325	153,583
Cash and cash equivalents, end of period	73,524	132,953	106,325
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest	35,061	43,247	44,948
Cash paid for income tax	537	1,593	2,127
Supplemental disclosure of non-cash activity:
Capital expenditures included in accounts payable and accrued liabilities	$ 0	$ 466	$ 0

Description and Nature of Busin

Description and Nature of Business	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description and Nature of Business	Description and Nature of Business As used in this report, the terms “Alon,” the “Partnership,” “we,” “our” and “us” or like terms 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. We are a Delaware limited partnership formed in August 2012 by Alon Energy and Alon USA Partners GP, LLC (the “General Partner”). The General Partner, a wholly-owned subsidiary of Alon Energy, owns 100% of our general partner interest, which is a non-economic interest. We are engaged principally in the business of operating a crude oil refinery in Big Spring, Texas, with a crude oil throughput capacity of 73,000 barrels per day. We refine crude oil into finished products, which are marketed primarily in Central and West Texas, Oklahoma, New Mexico and Arizona through our integrated wholesale distribution network to both Alon Energy’s retail convenience stores and other third-party distributors. We distribute fuel products through a network of pipelines and terminals that 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 our business is managed.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
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 include the accounts of Alon USA Partners, LP and its consolidated subsidiaries. All significant intercompany balances and transactions have been eliminated. (b) Use of Estimates These consolidated financial statements have been prepared in accordance 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 7 ) 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, RINs, 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 $172 , $172 and $220 for the years ended December 31, 2016 , 2015 and 2014 , respectively. (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 7 ). 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 10 ). (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 (generally 3 to 5 years), 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 (Loss) per Unit Earnings (loss) per unit applicable to limited partners is computed by dividing limited partners’ interest in net income (loss) 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. Estimates are updated to reflect changes in factual information, available technology or applicable laws and regulations (Note 15) . Substantially all amounts accrued are expected to be paid out over the next 15 years . The amount of future expenditures for environmental remediation obligations cannot be determined 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 Pronouncements 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 standard allows for either full retrospective adoption or modified retrospective adoption. In August 2015, the FASB updated the guidance to include a one-year deferral of the effective date for the new revenue standard, making the requirements of the standard effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted for interim and annual periods beginning after December 15, 2016. We are evaluating the guidance to determine the method of adoption and the impact this standard will have on our consolidated financial statements and related disclosures. Based on our initial evaluation, though not currently quantified, the adoption of the standard is not expected to have a material impact on the timing of revenue recognized, statements of operations or cash flows. In February 2016, the FASB issued new guidance on the accounting for leases, which requires lessees to recognize assets and liabilities on the balance sheet for the present value of the rights and obligations created by all leases with terms of more than 12 months. The ASU also will require disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. The requirements from this guidance are effective for interim and annual periods beginning after December 31, 2018. We are evaluating the guidance to determine the impact this standard will have on our consolidated financial statements. In June 2016, the FASB issued an accounting standards update requiring the measurement of all expected credit losses for financial assets held at the reporting date based on historical experience, current conditions, and reasonable and supportable forecasts. Financial institutions and other organizations will now use forward-looking information to better inform their credit loss estimates. The requirements from the updated standard are effective for interim and annual periods beginning after December 15, 2019. We are evaluating the guidance to determine the impact this standard will have on our consolidated financial statements. In August 2016, the FASB issued an accounting standards update addressing eight specific cash flow issues with the objective of eliminating the existing diversity in practice. The amendments from this update are effective for interim and annual periods beginning after December 15, 2017. We do not expect application of this standard to have a material effect on our consolidated financial statements. In January 2017, the FASB issued new guidance that changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities is a business. The amendments from this update are effective for interim and annual periods beginning after December 15, 2017. We do not expect application of this standard to have a material effect on our consolidated financial statements.

Fair Value

Fair Value	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Disclosures	Fair Value We determine fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We classify financial assets and financial liabilities into the following fair value hierarchy: • Level 1 - valued based on quoted prices in active markets for identical assets and liabilities; • Level 2 - valued based on quoted prices for similar assets and liabilities in active markets, and inputs other than quoted prices that are observable for the asset or liability; and • Level 3 - valued based on unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. As required, we utilize valuation techniques that maximize the use of observable inputs (levels 1 and 2) and minimize the use of unobservable inputs (level 3) within the fair value hierarchy. We generally apply the “market approach” to determine fair value. This method uses pricing and other information generated by market transactions for identical or comparable assets and liabilities. Assets and liabilities are classified within the fair value hierarchy based on the lowest level (least observable) input that is significant to the measurement in its entirety. The carrying amounts of our cash and cash equivalents, receivables, payables and accrued liabilities approximate fair value due to the short-term maturities of these assets and liabilities. The reported amounts of long-term debt approximate fair value. Derivative instruments are carried at fair value, which are based on quoted market prices. Derivative instruments are our only assets and liabilities measured at fair value on a recurring basis. The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, in the consolidated balance sheets as of December 31, 2016 and 2015 : Level 1 Level 2 Level 3 Total As of December 31, 2016 Assets: Fair value hedge of consigned inventory $ — $ 4,389 $ — $ 4,389 Liabilities: Commodity contracts (futures and forwards) 689 — — 689 As of December 31, 2015 Assets: Fair value hedge of consigned inventory $ — $ 11,564 $ — $ 11,564 Liabilities: Commodity contracts (futures and forwards) 40 — — 40

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2016
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, which we refer to as futures and forwards. Futures represent trades executed on the New York Mercantile Exchange which have not been closed or settled at the end of the reporting period. 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. 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 7 that have been accounted for as a fair value hedge, which had purchase volumes of 126 thousand barrels of crude oil as of December 31, 2016 . The following tables present the effect of derivative instruments on the consolidated balance sheets: As of December 31, 2016 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 $ 30 Accrued liabilities $ 719 Total derivatives not designated as hedging instruments 30 719 Derivatives designated as hedging instruments: Fair value hedge of consigned inventory Other assets $ 4,389 $ — Total derivatives designated as hedging instruments 4,389 — Total derivatives $ 4,419 $ 719 As of December 31, 2015 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 $ 59 Accrued liabilities $ 99 Total derivatives not designated as hedging instruments 59 99 Derivatives designated as hedging instruments: Fair value hedge of consigned inventory Other assets $ 11,564 $ — Total derivatives designated as hedging instruments 11,564 — Total derivatives $ 11,623 $ 99 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 2016 2015 2014 Fair value hedge of consigned inventory (1) Interest expense $ (7,175 ) $ 1,341 $ 12,527 Total derivatives $ (7,175 ) $ 1,341 $ 12,527 _______________________ (1) Changes in the fair value hedge are substantially offset in earnings by changes in the hedged item. Derivatives not designated as hedging instruments: Gain (Loss) Recognized in Income Year Ended December 31, Location 2016 2015 2014 Commodity contracts (futures and forwards) Cost of sales $ 4,319 $ 2,251 $ (2,352 ) Total derivatives $ 4,319 $ 2,251 $ (2,352 ) 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, 2016 and 2015 : 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, 2016 Derivative Assets: Commodity contracts (futures and forwards) $ 980 $ (950 ) $ 30 $ (30 ) $ — $ — Fair value hedge of consigned inventory 4,389 — 4,389 — — 4,389 Derivative Liabilities: Commodity contracts (futures and forwards) $ 1,669 $ (950 ) $ 719 $ (30 ) $ — $ 689 As of December 31, 2015 Derivative Assets: Commodity contracts (futures and forwards) $ 192 $ (133 ) $ 59 $ (59 ) $ — $ — Fair value hedge of consigned inventory 11,564 — 11,564 — — 11,564 Derivative Liabilities: Commodity contracts (futures and forwards) $ 232 $ (133 ) $ 99 $ (59 ) $ — $ 40 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. We may also sell the RINs with an agreement to repurchase in the future. 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 $14,262 , $11,500 and $6,697 for the years ended December 31, 2016 , 2015 and 2014 , respectively. These amounts are reflected in cost of sales in the consolidated statements of operations.

Significant Customers

Significant Customers	12 Months Ended
	Dec. 31, 2016
Significant Customers [Abstract]
Significant Customers	Significant Customers For the year ended December 31, 2016 , we had two third-party customers and related party customers which account for approximately 43% of net sales. Individually, third-party customers accounted for 14% and 12% of net sales and related party customers accounted for 17% of net sales for the year ended December 31, 2016 . For the year ended December 31, 2015 , we had one third-party customer and related party customers which account for approximately 27% of net sales. Individually, third-party customer accounted for 12% of net sales and related party customers accounted for 15% of net sales for the year ended December 31, 2015 . 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 . At December 31, 2016 and 2015 , 33% and 21% , 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, 2016
Inventory Disclosure [Abstract]
Inventories	Inventories Carrying value of inventories consisted of the following: As of December 31, 2016 2015 Crude oil, refined products and blendstocks $ 36,259 $ 24,548 Crude oil consignment inventory (Note 7) (1) 1,850 (95 ) Materials and supplies 11,573 10,991 Total inventories $ 49,682 $ 35,444 _______________________ (1) The fair value of the hedged item designated in our fair value hedge reduced the carrying value of our consigned inventory valued at LIFO below zero at December 31, 2015. Reductions of crude oil inventory volumes during 2015 resulted in a liquidation of LIFO inventory layers. The liquidations increased cost of sales by $7,878 . There were no liquidations of LIFO inventory layers during 2016 and 2014. At December 31, 2016 and 2015 , the market value of our refined products and blendstock inventories was less than inventories valued on a LIFO cost basis which resulted in a lower of cost or market reserve of $6,213 and $9,396 , respectively. At December 31, 2016 and 2015 , the market value of our crude oil inventories exceeded LIFO costs, net of the fair value hedged item, by $5,236 and $6,387 , respectively.

Inventory Financing Agreement

Inventory Financing Agreement	12 Months Ended
	Dec. 31, 2016
Inventory Financing Agreement [Abstract]
Inventory Financing Agreement	Inventory Financing Agreement We have entered into a Supply and Offtake Agreement and other associated agreements (together the “Supply and Offtake Agreement”), with J. Aron & Company (“J. Aron”). Pursuant to the Supply and Offtake Agreement, (i) J. Aron agreed to sell to us, and we agreed to buy from J. Aron, at market prices, crude oil for processing at our refinery and (ii) we agreed to sell, and J. Aron agreed to buy, at market prices, certain refined products produced at our 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 the identification of prospective purchasers of refined products on J. Aron’s behalf. 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, 2016 and 2015 , we had net current receivables of $10,569 and $4,975 , respectively, with J. Aron for sales and purchases, and a consignment inventory receivable representing a deposit paid to J. Aron of $6,290 and $6,290 , respectively. At December 31, 2016 and 2015 , we had non-current liabilities for the original financing of $7,550 and $9,761 , respectively, net of the related fair value hedge. Additionally, we had net current payables of $719 and $99 at December 31, 2016 and 2015 , 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,

Property, Plant, and Equipment, Net	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment, Net [Abstract]
Property, Plant and Equipment, Net	Property, Plant and Equipment, Net Property, plant and equipment, net consisted of the following: As of December 31, 2016 2015 Refining facilities $ 732,697 $ 709,779 Accumulated depreciation (312,143 ) (275,160 ) Property, plant and equipment, net $ 420,554 $ 434,619 Depreciation expense for the years ended December 31, 2016 , 2015 and 2014 was $36,983 , $35,830 and $35,185 , respectively.

Other Assets, Net

Other Assets, Net	12 Months Ended
	Dec. 31, 2016
Other Assets [Abstract]
Other Assets, Net	Other Assets, Net Other assets, net consisted of the following: As of December 31, 2016 2015 Deferred turnaround and catalyst costs $ 34,252 $ 43,021 Receivable from supply and offtake agreement (Note 7) 6,290 6,290 Fair value hedge of consigned inventory (Note 4) 4,389 11,564 Other 8,280 10,362 Total other assets $ 53,211 $ 71,237

Accounts Payable, Accrued Liabi

Accounts Payable, Accrued Liabilities and Other Non-Current Liabilities	12 Months Ended
	Dec. 31, 2016
Accrued Liabilities and Other Liabilities [Abstract]
Accounts Payable, Accrued Liabilities and Other Non-Current Liabilities	Accounts Payable, Accrued Liabilities and Other Non-Current Liabilities (a) Accounts Payable Included in accounts payable was $78,565 and $91,179 related to RINs financing transactions as of December 31, 2016 and 2015 , respectively. (b) Accrued Liabilities and Other Non-Current Liabilities As of December 31, 2016 2015 Accrued Liabilities: Taxes other than income taxes, primarily excise taxes $ 31,882 $ 25,018 Accrued finance charges 372 394 Environmental accrual (Note 15) 796 1,716 Commodity contracts 719 99 Other 9,331 13,480 Total accrued liabilities $ 43,100 $ 40,707 Other Non-Current Liabilities: Consignment inventory obligation (Note 7) $ 11,939 $ 21,325 Environmental accrual (Note 15) 5,796 4,725 Asset retirement obligations 3,131 2,927 RINs financing transactions 39,478 — Other 2,536 2,536 Total other non-current liabilities $ 62,880 $ 31,513 The following table summarizes the activity relating to the asset retirement obligations for the years ended December 31, 2016 and 2015 : As of December 31, 2016 2015 Balance at beginning of year $ 2,927 $ 2,084 Accretion expense 204 85 Revisions in estimated cash flows — 758 Retirements — — Additions — — Balance at end of year $ 3,131 $ 2,927 The revisions in estimated cash flows during 2015 include increased tank retirement costs partially offset by changes in expected inflationary rates.

Indebtedness

Indebtedness	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Indebtedness	Indebtedness Debt consisted of the following: As of December 31, 2016 2015 Term loan credit facility $ 236,319 $ 237,082 Revolving credit facility — 55,000 Total debt 236,319 292,082 Less: Current portion 2,500 2,500 Total long-term debt $ 233,819 $ 289,582 (a) Partnership Term Loan Credit Facility In November 2012, we entered into a $250,000 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. Based on Eurodollar market rates at December 31, 2016 , the interest rate was 9.25% per annum. 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, 2016 and 2015 , the Partnership Term Loan had an outstanding balance, net of unamortized issuance costs and issuance discount, of $236,319 and $237,082 , respectively. (b) Revolving Credit Facility We have a $240,000 revolving credit facility (the “Revolving Credit Facility”) that will mature in March 2019. 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 3.00% per annum. 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, 2016 , we were in compliance with these covenants . At December 31, 2016 , there were no outstanding borrowings under our Revolving Credit Facility, compared to borrowings of $55,000 at December 31, 2015 . At December 31, 2016 and 2015 , we had letters of credit outstanding of $100,613 and $48,590 , respectively. (c) Maturity of Long-Term Debt The aggregate scheduled maturities of long-term debt for each of the two years subsequent to December 31, 2016 are as follows: 2017 $ 2,500 2018 237,500 Total $ 240,000 (d) Interest and Financing Expense Interest and financing expense included the following: Year Ended December 31, 2016 2015 2014 Interest expense on debt $ 23,804 $ 24,446 $ 24,906 Letters of credit and finance charges 13,528 19,928 21,082 Amortization of debt issuance costs 1,736 2,408 2,057 Amortization of original issuance discount 650 599 554 Less: Capitalized interest (2,590 ) (1,394 ) (1,893 ) Total interest expense $ 37,128 $ 45,987 $ 46,706

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
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, 2016
Partners' Capital Notes [Abstract]
Partners' Capital Notes Disclosure	Partners' Equity (unit values in dollars) Our limited partner interests are represented as common units outstanding. As of December 31, 2016 and 2015 , we had 62,520,220 and 62,510,039 common units issued and outstanding, respectively. As of December 31, 2016 , the 11,520,220 common units held by the public represent 18.4% of our common units outstanding. Alon Energy owns the remaining 51,000,000 common units and the General Partner, a wholly-owned subsidiary of Alon Energy, owns 100% of our general partner interest, which is a non-economic interest. 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, 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. The following table summarizes our cash distribution activity for the years ended December 31, 2016 , 2015 and 2014 : Cash Available for Distribution per Unit (1) Distributions Paid Per Unit Total Distributions Paid 2016 $ 0.40 $ 0.37 $ 23,132 2015 2.81 3.43 214,405 2014 2.54 2.02 126,262 _______________________ (1) Represents the aggregate cash available for distribution per unit attributable to the period indicated. This represents the difference between cash available for distribution and distributions paid in the table above. 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. As of December 31, 2016, we have issued 20,220 common units under the LTIP. Non-employee directors of the General Partner are awarded an annual grant of $25 in restricted units, which vest over a period of three years , assuming continued service at vesting. During the year ended December 31, 2016 , we granted awards of 10,181 restricted common units at an average grant date price of $9.82 per unit. During the year ended December 31, 2015 , we granted awards of 3,489 restricted common units at an average grant date price of $21.50 per unit.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Related Party Transactions	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 $14,172 , $12,055 and $11,229 for the years ended December 31, 2016 , 2015 and 2014 , 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 and selling, general and administrative expenses. The allocated portion of Alon Energy’s employee expense costs included in direct operating expenses was $28,840 , $27,204 and $26,473 for the years ended December 31, 2016 , 2015 and 2014 , respectively. The allocated portion of Alon Energy’s employee expense costs included in selling, general and administrative expenses were $4,424 , $4,103 and $4,311 for the years ended December 31, 2016 , 2015 and 2014 , 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 $4,422 , $6,405 and $7,270 for the years ended December 31, 2016 , 2015 and 2014 , respectively. Distributions During the year ended December 31, 2016 , we paid cash distributions of $23,132 , or $0.37 per unit, of which $18,870 was paid to Alon Energy. During the year ended December 31, 2015 , we paid cash distributions of $214,405 , or $3.43 per unit, of which $174,930 was paid to Alon Energy. During the year ended December 31, 2014 , we paid cash distributions of $126,262 , or $2.02 per unit, of which $103,020 was paid to Alon Energy. Agreements with Alon Energy As of December 31, 2016 , 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 market 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. Related to these agreements, we recorded selling, general and administrative expense of $4,920 , $4,920 and $2,460 for the years ended December 31, 2016 , 2015 and 2014 , respectively. Transactions with Delek US Holdings, Inc. In May 2015, Delek US Holdings, Inc. (“Delek”) completed the purchase of approximately 48% of Alon Energy’s outstanding common stock from Alon Israel Oil Company, Ltd. (“Alon Israel”). We have transactions with Delek that occur in the ordinary course of business. Including amounts prior to the transaction, we purchased refined products from Delek of $995 , $11,406 and $5,486 for the years ended December 31, 2016 , 2015 and 2014 , respectively.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies Disclosure	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 seven years . Certain long-term operating leases relating to buildings, land and pipelines include options to renew for additional periods. At December 31, 2016 , minimum lease payments on operating leases were as follows: Year ending December 31, 2017 $ 18,484 2018 12,789 2019 5,711 2020 3,511 2021 2,617 2022 and thereafter 3,883 Total $ 46,995 Total rental expense was $22,065 , $22,397 and $15,546 for the years ended December 31, 2016 , 2015 and 2014 , 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. Our minimum commitment under this agreement is $24,573 for 2017. 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 which is a $14,254 commitment for 2017. 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 which is a $2,454 commitment for 2017. We have entered into a transportation services agreement with Navigator Energy Services, LLC (“Navigator”), which provides for the construction and operation of a pipeline system to facilitate delivery of crude oil to the Big Spring refinery from a number of injection points in the area of the refinery. The term of the agreement begins upon the commencement of shipments and continues for an initial period of ten years, with two additional five-year renewal terms exercisable at our sole option. Our minimum throughput commitment is 10,000 bpd which is a $2,144 commitment for 2017. (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 ourselves 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 ourselves in lieu of indemnifying Sunoco for their costs of performing such remediation. We have accrued environmental remediation obligations of $6,592 ( $796 current liability and $5,796 non-current liability) at December 31, 2016 and $6,441 ( $1,716 current liability and $4,725 non-current liability) at December 31, 2015 . Environmental liabilities with payments that are fixed or reliably determinable have been discounted to present value at a rate of 2.62% . The table below summarizes our environmental liability accruals: As of December 31, 2016 2015 Discounted environmental liabilities $ 6,365 $ 5,366 Undiscounted environmental liabilities 227 1,075 Total accrued environmental liabilities $ 6,592 $ 6,441 As of December 31, 2016 , the estimated future payments of environmental obligations for which discounts have been applied are as follows: Year ending December 31, 2017 $ 686 2018 634 2019 614 2020 614 2021 613 2022 and thereafter 4,409 Discounted environmental liabilities, gross 7,570 Less: Discount applied 1,205 Discounted environmental liabilities $ 6,365

Quarterly Information (unaudite

Quarterly Information (unaudited)	12 Months Ended
	Dec. 31, 2016
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 2016 Net sales $ 368,009 $ 468,457 $ 462,257 $ 509,009 Operating income 2,117 10,998 10,191 9,362 Net income (loss) (8,562 ) 1,191 2,083 884 Earnings (loss) per unit $ (0.14 ) $ 0.02 $ 0.03 $ 0.01 2015 Net sales $ 542,442 $ 625,064 $ 551,813 $ 437,872 Operating income 48,535 69,851 65,766 19,354 Net income 36,451 59,426 53,776 7,246 Earnings per unit $ 0.58 $ 0.95 $ 0.86 $ 0.12

Subsequent Event

Subsequent Event	12 Months Ended
	Dec. 31, 2016
Subsequent Events [Abstract]
Subsequent Event	Subsequent Event Distribution Declared On February 9, 2017 the board of directors of the General Partner declared a cash distribution to our common unitholders of $6,877 , or $0.11 per common unit. The cash distribution will be paid on February 28, 2017 to unitholders of record at the close of business on February 21, 2017 .

Significant Accounting Policies

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Consolidation, Policy	Basis of Presentation The consolidated financial statements and related notes include the accounts of Alon USA Partners, LP and its consolidated subsidiaries. All significant intercompany balances and transactions have been eliminated.
Use of Estimates, Policy	Use of Estimates These consolidated financial statements have been prepared in accordance 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 7 ) 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, RINs, 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.
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 $172 , $172 and $220 for the years ended December 31, 2016 , 2015 and 2014 , respectively.
Inventories, 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 7 ). 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.
Hedging Activity, 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 10 ).
Turnarounds and Catalysts Costs, 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 (generally 3 to 5 years), 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 (Loss) Per Unit, Policy	Earnings (Loss) per Unit Earnings (loss) per unit applicable to limited partners is computed by dividing limited partners’ interest in net income (loss) by the weighted average number of outstanding common units.
Income Taxes, 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 Expenditures, 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. Estimates are updated to reflect changes in factual information, available technology or applicable laws and regulations (Note 15) . Substantially all amounts accrued are expected to be paid out over the next 15 years . The amount of future expenditures for environmental remediation obligations cannot be determined 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 Pronouncements 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 standard allows for either full retrospective adoption or modified retrospective adoption. In August 2015, the FASB updated the guidance to include a one-year deferral of the effective date for the new revenue standard, making the requirements of the standard effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted for interim and annual periods beginning after December 15, 2016. We are evaluating the guidance to determine the method of adoption and the impact this standard will have on our consolidated financial statements and related disclosures. Based on our initial evaluation, though not currently quantified, the adoption of the standard is not expected to have a material impact on the timing of revenue recognized, statements of operations or cash flows. In February 2016, the FASB issued new guidance on the accounting for leases, which requires lessees to recognize assets and liabilities on the balance sheet for the present value of the rights and obligations created by all leases with terms of more than 12 months. The ASU also will require disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. The requirements from this guidance are effective for interim and annual periods beginning after December 31, 2018. We are evaluating the guidance to determine the impact this standard will have on our consolidated financial statements. In June 2016, the FASB issued an accounting standards update requiring the measurement of all expected credit losses for financial assets held at the reporting date based on historical experience, current conditions, and reasonable and supportable forecasts. Financial institutions and other organizations will now use forward-looking information to better inform their credit loss estimates. The requirements from the updated standard are effective for interim and annual periods beginning after December 15, 2019. We are evaluating the guidance to determine the impact this standard will have on our consolidated financial statements. In August 2016, the FASB issued an accounting standards update addressing eight specific cash flow issues with the objective of eliminating the existing diversity in practice. The amendments from this update are effective for interim and annual periods beginning after December 15, 2017. We do not expect application of this standard to have a material effect on our consolidated financial statements. In January 2017, the FASB issued new guidance that changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities is a business. The amendments from this update are effective for interim and annual periods beginning after December 15, 2017. We do not expect application of this standard to have a material effect on our consolidated financial statements.

Fair Value (Tables)

Fair Value (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 : Level 1 Level 2 Level 3 Total As of December 31, 2016 Assets: Fair value hedge of consigned inventory $ — $ 4,389 $ — $ 4,389 Liabilities: Commodity contracts (futures and forwards) 689 — — 689 As of December 31, 2015 Assets: Fair value hedge of consigned inventory $ — $ 11,564 $ — $ 11,564 Liabilities: Commodity contracts (futures and forwards) 40 — — 40

Derivative Financial Instrume27

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 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 $ 30 Accrued liabilities $ 719 Total derivatives not designated as hedging instruments 30 719 Derivatives designated as hedging instruments: Fair value hedge of consigned inventory Other assets $ 4,389 $ — Total derivatives designated as hedging instruments 4,389 — Total derivatives $ 4,419 $ 719 As of December 31, 2015 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 $ 59 Accrued liabilities $ 99 Total derivatives not designated as hedging instruments 59 99 Derivatives designated as hedging instruments: Fair value hedge of consigned inventory Other assets $ 11,564 $ — Total derivatives designated as hedging instruments 11,564 — Total derivatives $ 11,623 $ 99
Schedule of Fair Value Hedging Instruments, Statements of Financial Performance	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 2016 2015 2014 Fair value hedge of consigned inventory (1) Interest expense $ (7,175 ) $ 1,341 $ 12,527 Total derivatives $ (7,175 ) $ 1,341 $ 12,527 _______________________ (1) Changes in the fair value hedge are substantially offset in earnings by changes in the hedged item.
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance	Derivatives not designated as hedging instruments: Gain (Loss) Recognized in Income Year Ended December 31, Location 2016 2015 2014 Commodity contracts (futures and forwards) Cost of sales $ 4,319 $ 2,251 $ (2,352 ) Total derivatives $ 4,319 $ 2,251 $ (2,352 )
Offsetting Assets	The following table presents offsetting information regarding our derivatives by type of transaction as of December 31, 2016 and 2015 : 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, 2016 Derivative Assets: Commodity contracts (futures and forwards) $ 980 $ (950 ) $ 30 $ (30 ) $ — $ — Fair value hedge of consigned inventory 4,389 — 4,389 — — 4,389 Derivative Liabilities: Commodity contracts (futures and forwards) $ 1,669 $ (950 ) $ 719 $ (30 ) $ — $ 689 As of December 31, 2015 Derivative Assets: Commodity contracts (futures and forwards) $ 192 $ (133 ) $ 59 $ (59 ) $ — $ — Fair value hedge of consigned inventory 11,564 — 11,564 — — 11,564 Derivative Liabilities: Commodity contracts (futures and forwards) $ 232 $ (133 ) $ 99 $ (59 ) $ — $ 40
Offsetting Liabilities	The following table presents offsetting information regarding our derivatives by type of transaction as of December 31, 2016 and 2015 : 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, 2016 Derivative Assets: Commodity contracts (futures and forwards) $ 980 $ (950 ) $ 30 $ (30 ) $ — $ — Fair value hedge of consigned inventory 4,389 — 4,389 — — 4,389 Derivative Liabilities: Commodity contracts (futures and forwards) $ 1,669 $ (950 ) $ 719 $ (30 ) $ — $ 689 As of December 31, 2015 Derivative Assets: Commodity contracts (futures and forwards) $ 192 $ (133 ) $ 59 $ (59 ) $ — $ — Fair value hedge of consigned inventory 11,564 — 11,564 — — 11,564 Derivative Liabilities: Commodity contracts (futures and forwards) $ 232 $ (133 ) $ 99 $ (59 ) $ — $ 40

Inventories (Tables)

Inventories (Tables)	12 Months Ended
	Dec. 31, 2016
Inventory Disclosure [Abstract]
Schedule of Inventory	Carrying value of inventories consisted of the following: As of December 31, 2016 2015 Crude oil, refined products and blendstocks $ 36,259 $ 24,548 Crude oil consignment inventory (Note 7) (1) 1,850 (95 ) Materials and supplies 11,573 10,991 Total inventories $ 49,682 $ 35,444 _______________________ (1) The fair value of the hedged item designated in our fair value hedge reduced the carrying value of our consigned inventory valued at LIFO below zero at December 31, 2015.

Property, Plant, and Equipmen29

Property, Plant, and Equipment, Net (Tables)	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment, Net [Abstract]
Property, Plant and Equipment, Net	Property, plant and equipment, net consisted of the following: As of December 31, 2016 2015 Refining facilities $ 732,697 $ 709,779 Accumulated depreciation (312,143 ) (275,160 ) Property, plant and equipment, net $ 420,554 $ 434,619

Other Assets, Net (Tables)

Other Assets, Net (Tables)	12 Months Ended
	Dec. 31, 2016
Other Assets [Abstract]
Schedule of Other Assets	Other assets, net consisted of the following: As of December 31, 2016 2015 Deferred turnaround and catalyst costs $ 34,252 $ 43,021 Receivable from supply and offtake agreement (Note 7) 6,290 6,290 Fair value hedge of consigned inventory (Note 4) 4,389 11,564 Other 8,280 10,362 Total other assets $ 53,211 $ 71,237

Accounts Payable, Accrued Lia31

Accounts Payable, Accrued Liabilities and Other Non-Current Liabilities (Tables)	12 Months Ended
	Dec. 31, 2016
Accrued Liabilities and Other Liabilities [Abstract]
Schedule of Accrued Liabilities and Other Non-Current Liabilities	Accrued Liabilities and Other Non-Current Liabilities As of December 31, 2016 2015 Accrued Liabilities: Taxes other than income taxes, primarily excise taxes $ 31,882 $ 25,018 Accrued finance charges 372 394 Environmental accrual (Note 15) 796 1,716 Commodity contracts 719 99 Other 9,331 13,480 Total accrued liabilities $ 43,100 $ 40,707 Other Non-Current Liabilities: Consignment inventory obligation (Note 7) $ 11,939 $ 21,325 Environmental accrual (Note 15) 5,796 4,725 Asset retirement obligations 3,131 2,927 RINs financing transactions 39,478 — Other 2,536 2,536 Total other non-current liabilities $ 62,880 $ 31,513
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, 2016 and 2015 : As of December 31, 2016 2015 Balance at beginning of year $ 2,927 $ 2,084 Accretion expense 204 85 Revisions in estimated cash flows — 758 Retirements — — Additions — — Balance at end of year $ 3,131 $ 2,927

Indebtedness (Tables)

Indebtedness (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments	Debt consisted of the following: As of December 31, 2016 2015 Term loan credit facility $ 236,319 $ 237,082 Revolving credit facility — 55,000 Total debt 236,319 292,082 Less: Current portion 2,500 2,500 Total long-term debt $ 233,819 $ 289,582
Schedule of Maturities of Long-term Debt	The aggregate scheduled maturities of long-term debt for each of the two years subsequent to December 31, 2016 are as follows: 2017 $ 2,500 2018 237,500 Total $ 240,000
Schedule of Debt	Interest and financing expense included the following: Year Ended December 31, 2016 2015 2014 Interest expense on debt $ 23,804 $ 24,446 $ 24,906 Letters of credit and finance charges 13,528 19,928 21,082 Amortization of debt issuance costs 1,736 2,408 2,057 Amortization of original issuance discount 650 599 554 Less: Capitalized interest (2,590 ) (1,394 ) (1,893 ) Total interest expense $ 37,128 $ 45,987 $ 46,706

Partners' Equity Distributions

Partners' Equity Distributions (Tables)	12 Months Ended
	Dec. 31, 2016
Dividends [Abstract]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	The following table summarizes our cash distribution activity for the years ended December 31, 2016 , 2015 and 2014 : Cash Available for Distribution per Unit (1) Distributions Paid Per Unit Total Distributions Paid 2016 $ 0.40 $ 0.37 $ 23,132 2015 2.81 3.43 214,405 2014 2.54 2.02 126,262 _______________________ (1) Represents the aggregate cash available for distribution per unit attributable to the period indicated. This represents the difference between cash available for distribution and distributions paid in the table above.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]	At December 31, 2016 , minimum lease payments on operating leases were as follows: Year ending December 31, 2017 $ 18,484 2018 12,789 2019 5,711 2020 3,511 2021 2,617 2022 and thereafter 3,883 Total $ 46,995
Schedule of Accrued Environmental Obligations [Table Text Block]	The table below summarizes our environmental liability accruals: As of December 31, 2016 2015 Discounted environmental liabilities $ 6,365 $ 5,366 Undiscounted environmental liabilities 227 1,075 Total accrued environmental liabilities $ 6,592 $ 6,441
Schedule of Estimated Undiscounted Cash Flows for Discounted Environmental Remediation Liabilities in Future Periods [Table Text Block]	As of December 31, 2016 , the estimated future payments of environmental obligations for which discounts have been applied are as follows: Year ending December 31, 2017 $ 686 2018 634 2019 614 2020 614 2021 613 2022 and thereafter 4,409 Discounted environmental liabilities, gross 7,570 Less: Discount applied 1,205 Discounted environmental liabilities $ 6,365

Quarterly Information (unaudi35

Quarterly Information (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
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 2016 Net sales $ 368,009 $ 468,457 $ 462,257 $ 509,009 Operating income 2,117 10,998 10,191 9,362 Net income (loss) (8,562 ) 1,191 2,083 884 Earnings (loss) per unit $ (0.14 ) $ 0.02 $ 0.03 $ 0.01 2015 Net sales $ 542,442 $ 625,064 $ 551,813 $ 437,872 Operating income 48,535 69,851 65,766 19,354 Net income 36,451 59,426 53,776 7,246 Earnings per unit $ 0.58 $ 0.95 $ 0.86 $ 0.12

Description and Nature of Bus36

Description and Nature of Business Description and Nature of Business (Details)	12 Months Ended
	Dec. 31, 2016bbl / d
Ownership Percentage by Parent in General Partnership	100.00%
Maximum
Throughput, Average	73,000

Significant Accounting Polici37

Significant Accounting Policies (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Allowance for Doubtful Accounts Receivable, Current	$ 172	$ 172	$ 220
Site Contingency, Time Frame of Disbursements	15 years
Minimum
Property, Plant and Equipment, Useful Life	3 years
Refinery Turnaround Costs, Amortization Period	3 years
Maximum
Property, Plant and Equipment, Useful Life	20 years
Refinery Turnaround Costs, Amortization Period	5 years

Fair Value (Details)

Fair Value (Details) - Fair Value, Measurements, Recurring - Forward Contracts - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Commodity Contracts
Liabilities:
Derivative Liabilities	$ 689	$ 40
Fair Value Hedge
Assets:
Derivative Assets	4,389	11,564
Level 1 | Commodity Contracts
Liabilities:
Derivative Liabilities	689	40
Level 1 | Fair Value Hedge
Assets:
Derivative Assets	0	0
Level 2 | Commodity Contracts
Liabilities:
Derivative Liabilities	0	0
Level 2 | Fair Value Hedge
Assets:
Derivative Assets	4,389	11,564
Level 3 | Commodity Contracts
Liabilities:
Derivative Liabilities	0	0
Level 3 | Fair Value Hedge
Assets:
Derivative Assets	$ 0	$ 0

Derivative Financial Instrume39

Derivative Financial Instruments, Schedule of Derivative Instruments in Statement of Financial Position, Fair Value (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Derivatives, Fair Value
Derivative Assets	$ 4,419	$ 11,623
Derivative Liabilities	719	99
Commodity Contracts | Forward Contracts
Derivatives, Fair Value
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	30	59
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	719	99
Fair Value Hedge | Forward Contracts
Derivatives, Fair Value
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	4,389	11,564
Not Designated as Hedging Instrument
Derivatives, Fair Value
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	30	59
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	719	99
Not Designated as Hedging Instrument | Accounts Receivable | Commodity Contracts | Forward Contracts
Derivatives, Fair Value
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	30	59
Not Designated as Hedging Instrument | Accrued Liabilities | Commodity Contracts | Forward Contracts
Derivatives, Fair Value
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	719	99
Designated as Hedging Instrument
Derivatives, Fair Value
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	4,389	11,564
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	0
Designated as Hedging Instrument | Other Assets | Fair Value Hedge | Forward Contracts
Derivatives, Fair Value
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	4,389	11,564
Designated as Hedging Instrument | Other Noncurrent Liabilities | Fair Value Hedge | Forward Contracts
Derivatives, Fair Value
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	$ 0	$ 0

Derivative Financial Instrume40

Derivative Financial Instruments, Schedule of Fair Value Hedging Instruments (Details) - Designated as Hedging Instrument - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments, Gain (Loss)
Gain (Loss) on Fair Value Hedges Recognized in Earnings		$ (7,175)	$ 1,341	$ 12,527
Interest Expense | Fair Value Hedge | Forward Contracts
Derivative Instruments, Gain (Loss)
Gain (Loss) on Fair Value Hedges Recognized in Earnings	[1]	$ (7,175)	$ 1,341	$ 12,527
[1]	Changes in the fair value hedge are substantially offset in earnings by changes in the hedged item.

Derivative Financial Instrume41

Derivative Financial Instruments, Schedule of Derivative Instruments, Gain (Loss) in Statements of Financial Performance (Details) - Not Designated as Hedging Instrument - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments, Gain (Loss)
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ 4,319	$ 2,251	$ (2,352)
Cost of Sales | Commodity Contracts | Forward Contracts
Derivative Instruments, Gain (Loss)
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ 4,319	$ 2,251	$ (2,352)

Derivative Financial Instrume42

Derivative Financial Instruments, Schedule of Offsetting Derivative Instruments by Type (Details) - Forward Contracts - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Commodity Contracts
Derivative Asset, Fair Value, Net
Gross Amounts of Recognized Assets	$ 980	$ 192
Gross Amounts Offset in the Statement of Financial Position	(950)	(133)
Net Amounts of Assets Presented in the Statement of Financial Position	30	59
Derivative, Collateral, Obligation to Return Securities	(30)	(59)
Cash Collateral Received	0	0
Derivative Asset, Net Amount	0	0
Derivative Liability, Fair Value, Net
Gross Amounts of Recognized Liabilities	1,669	232
Gross Amounts Offset in the Statement of Financial Position	(950)	(133)
Net Amounts of Liabilities Presented in the Statement of Financial Position	719	99
Derivative, Collateral, Right to Reclaim Securities	(30)	(59)
Cash Collateral Pledged	0	0
Derivative Liability, Net Amount	689	40
Fair Value Hedge
Derivative Asset, Fair Value, Net
Gross Amounts of Recognized Assets	4,389	11,564
Gross Amounts Offset in the Statement of Financial Position	0	0
Net Amounts of Assets Presented in the Statement of Financial Position	4,389	11,564
Derivative, Collateral, Obligation to Return Securities	0	0
Cash Collateral Received	0	0
Derivative Asset, Net Amount	$ 4,389	$ 11,564

Derivative Financial Instrume43

Derivative Financial Instruments Textuals (Details) bbl in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)bbl	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Derivative
Compliance Program Costs | $	$ 14,262	$ 11,500	$ 6,697
Fair Value Hedge | Forward Contracts
Derivative
Derivative, Nonmonetary Notional Amount | bbl	126

Significant Customers (Details)

Significant Customers (Details) - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Sales Revenue, Net
Concentration Risk
Concentration Risk, Percentage	43.00%	27.00%	43.00%
Sales Revenue, Net | Related Party
Concentration Risk
Concentration Risk, Percentage	17.00%	15.00%	17.00%
Sales Revenue, Net | Third Party Customer A
Concentration Risk
Concentration Risk, Percentage	14.00%	12.00%	13.00%
Sales Revenue, Net | Third Party Customer B
Concentration Risk
Concentration Risk, Percentage	12.00%		13.00%
Accounts Receivable
Concentration Risk
Concentration Risk, Percentage	33.00%	21.00%

Inventories (Details)

Inventories (Details) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Inventory Disclosure [Abstract]
Crude oil, refined products and blendstocks		$ 36,259	$ 24,548
Crude oil consignment inventory (Note 7) (1)	[1]	1,850	(95)
Materials and supplies		11,573	10,991
Total inventories		$ 49,682	$ 35,444
[1]	The fair value of the hedged item designated in our fair value hedge reduced the carrying value of our consigned inventory valued at LIFO below zero at December 31, 2015.

Inventories Textuals (Details)

Inventories Textuals (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2016
Inventory Disclosure [Abstract]
LIFO Inventory Liquidation Effect on Income - Increase (Decrease) Income	$ (7,878)
Inventory Lower of Cost or Market Reserve	9,396	$ 6,213
Excess of Replacement or Current Costs over Stated LIFO Value, Net of the Fair Value Hedged Item	$ 6,387	$ 5,236

Inventory Financing Agreement (

Inventory Financing Agreement (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Receivable from supply and offtake agreement	$ 6,290	$ 6,290
Derivative Liabilities	719	99
Consigned inventory | Forward Contracts
Derivative Liabilities	719	99
J.Aron
Accounts Receivable, Net, Current	10,569	4,975
Receivable from supply and offtake agreement	6,290	6,290
Non-current liability for consignment inventory	$ 7,550	$ 9,761

Property, Plant, and Equipmen48

Property, Plant, and Equipment, Net (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment, Net
Refining facilities	$ 732,697	$ 709,779
Accumulated depreciation	(312,143)	(275,160)
Property, plant and equipment, net	$ 420,554	$ 434,619

Property, Plant, and Equipmen49

Property, Plant, and Equipment, Net Textuals (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment, Net
Depreciation	$ 36,983	$ 35,830	$ 35,185

Other Assets, Net (Details)

Other Assets, Net (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Other Assets, Net:
Deferred turnaround and catalyst costs	$ 34,252	$ 43,021
Receivable from supply and offtake agreement (Note 7)	6,290	6,290
Fair value hedge of consigned inventory (Note 4)	4,389	11,564
Other	8,280	10,362
Total other assets	$ 53,211	$ 71,237

Accounts Payable, Accrued Lia51

Accounts Payable, Accrued Liabilities and Other Non-Current Liabilities Accounts Payable Textuals (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Accounts Payable [Abstract]
Accounts Payable, RINs financing transactions	$ 78,565	$ 91,179

Accrued Liabilities and Other N

Accrued Liabilities and Other Non-Current Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Accrued Liabilities:
Taxes other than income taxes, primarily excise taxes	$ 31,882	$ 25,018
Accrued finance charges	372	394
Environmental accrual (Note 15)	796	1,716
Commodity contracts	719	99
Other	9,331	13,480
Total accrued liabilities	43,100	40,707
Other Non-Current Liabilities:
Consignment inventory obligation (Note 7)	11,939	21,325
Environmental accrual (Note 15)	5,796	4,725
Asset retirement obligations	3,131	2,927
RINs financing transactions	39,478	0
Other	2,536	2,536
Total other non-current liabilities	$ 62,880	$ 31,513

Accrued Liabilities and Other53

Accrued Liabilities and Other Non-Current Liabilities, Changes in Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligations
Balance at beginning of year	$ 2,927	$ 2,084
Accretion expense	204	85
Revisions in estimated cash flows	0	758
Retirements	0	0
Additions	0	0
Balance at end of year	$ 3,131	$ 2,927

Schedule of Long-Term Debt (Det

Schedule of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument
Long-term debt	$ 236,319	$ 292,082
Less: Current portion	2,500	2,500
Total long-term debt	233,819	289,582
Term loan credit facility
Debt Instrument
Long-term debt	236,319	237,082
Revolving credit facility
Debt Instrument
Long-term debt	$ 0	$ 55,000

Partnership Term Loan Credit Fa

Partnership Term Loan Credit Facility (Details) - Partnership Term Loan - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Nov. 30, 2012
Debt Instrument
Debt Instrument, Face Amount			$ 250,000
Debt Instrument, Annual Principal Payment	$ 2,500
Partnership Term Loan Balance	$ 236,319	$ 237,082
Minimum
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	9.25%
Eurodollar
Debt Instrument
Debt Instrument, Basis Spread on Variable Rate	8.00%
Eurodollar | Minimum
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	1.25%

Revolving Credit Facility (Deta

Revolving Credit Facility (Details) - Alon USA LP Credit Facility - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument
Debt Instrument, Face Amount	$ 240,000
Debt Instrument, Covenant Compliance	we were in compliance with these covenants
Long-term Line of Credit	$ 0	$ 55,000
Letters of Credit Outstanding, Amount	$ 100,613	$ 48,590
Eurodollar
Debt Instrument
Debt Instrument, Basis Spread on Variable Rate	3.00%

Maturity of Long-Term Debt (Det

Maturity of Long-Term Debt (Details) $ in Thousands	Dec. 31, 2016USD ($)
Maturities of Long-term Debt
2,017	$ 2,500
2,018	237,500
Total	$ 240,000

Interest and Financing Expense

Interest and Financing Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Interest Expense, Debt
Interest expense on debt	$ 23,804	$ 24,446	$ 24,906
Letters of credit and finance charges	13,528	19,928	21,082
Amortization of debt issuance costs	1,736	2,408	2,057
Amortization of original issuance discount	650	599	554
Less: Capitalized interest	(2,590)	(1,394)	(1,893)
Total interest expense	$ 37,128	$ 45,987	$ 46,706

Partners' Equity (Details)

Partners' Equity (Details) - shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Limited Partners' Capital Account
Common units, units outstanding	62,520,220	62,510,039
Ownership Percentage by Parent in General Partnership	100.00%
Limited Partner, Public
Limited Partners' Capital Account
Common units, units outstanding	11,520,220
Ownership Percentage by Noncontrolling Owners	18.40%
Limited Partner, Affiliated
Limited Partners' Capital Account
Common units, units outstanding	51,000,000

Partners' Equity Distribution60

Partners' Equity Distributions Made to Limited Partner, by Distribution (Details) - USD ($) $ / shares in Units, $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Distribution Made to Limited Partner
Distribution Made to Limited Partner, Distributions Paid, Per Unit		$ 0.37	$ 3.43	$ 2.02
Cash Distribution
Distribution Made to Limited Partner
Cash Available for Distributions, Per Unit	[1]	0.40	2.81	2.54
Distribution Made to Limited Partner, Distributions Paid, Per Unit		$ 0.37	$ 3.43	$ 2.02
Distribution Made to Limited Partner, Cash Distributions Paid		$ 23,132	$ 214,405	$ 126,262
[1]	Represents the aggregate cash available for distribution per unit attributable to the period indicated. This represents the difference between cash available for distribution and distributions paid in the table above.

Partners' Equity Restricted Uni

Partners' Equity Restricted Units (Details) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	3,125,000
Restricted Unit
Share-based Compensation Arrangement by Share-based Payment Award
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding, Number	20,220
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Stock Issued During Period, Shares, Restricted Stock Award, Gross	10,181	3,489
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 9.82	$ 21.50

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended		12 Months Ended
	May 31, 2015	Jun. 30, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Distribution Made to Limited Partner, Distributions Paid, Per Unit			$ 0.37	$ 3.43	$ 2.02
Operating Leases, Future Minimum Payments Due, Next Twelve Months			$ 18,484
Operating Leases, Rent Expense			22,065	$ 22,397	$ 15,546
Distributions
Distribution Made to Limited Partner, Cash Distributions Paid			$ 23,132	$ 214,405	$ 126,262
Distribution Made to Limited Partner, Distributions Paid, Per Unit			$ 0.37	$ 3.43	$ 2.02
Alon Energy | Corporate Overhead Allocation
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party			$ 14,172	$ 12,055	$ 11,229
Alon Energy | Labor Costs
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party			4,424	4,103	4,311
Related Party Transaction, Expenses from Transactions with Related Party			28,840	27,204	26,473
Alon Energy | Insurance Costs
Related Party Transaction, Expenses from Transactions with Related Party			4,422	6,405	7,270
Alon Energy | Distributions
Distribution Made to Limited Partner, Cash Distributions Paid			18,870	174,930	103,020
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			4,920	4,920	2,460
Delek
Sale of Stock, Percentage of Ownership after Transaction	48.00%
Related Party Transaction, Purchases from Related Party			$ 995	$ 11,406	$ 5,486

Commitments and Contingencies,

Commitments and Contingencies, Minimum Lease Payments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Period covered	7 years
Year ending December 31,
2,017	$ 18,484
2,018	12,789
2,019	5,711
2,020	3,511
2,021	2,617
2022 and thereafter	3,883
Total	46,995
Operating Leases, Rent Expense	$ 22,065	$ 22,397	$ 15,546

Commitments and Contingencies64

Commitments and Contingencies, Commitments (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)Boe
Holly Energy Partners
Commitments
Other Commitment, Due in Next Twelve Months	$ 24,573
Sunoco Pipeline, LP
Commitments
Other Commitment, Due in Next Twelve Months	$ 14,254
Long-term Purchase Commitment, Minimum Volume Required | Boe	15,645
Centurion Pipeline LP
Commitments
Other Commitment, Due in Next Twelve Months	$ 2,454
Long-term Purchase Commitment, Minimum Volume Required | Boe	25,000
Navigator Energy Services, LLC
Commitments
Other Commitment, Due in Next Twelve Months	$ 2,144
Long-term Purchase Commitment, Minimum Volume Required | Boe	10,000

Commitments and Contingencies65

Commitments and Contingencies, Remediation Obligations (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Accrual for Environmental Loss Contingencies	$ 6,592	$ 6,441
Accrued Environmental Loss Contingencies, Current	796	1,716
Accrued Environmental Loss Contingencies, Noncurrent	$ 5,796	$ 4,725
Accrual for Environmental Loss Contingencies, Discount Rate	2.62%

Commitments and Contingencies66

Commitments and Contingencies, Environmental Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Accrued Environmental Obligations [Abstract]
Discounted environmental liabilities	$ 6,365	$ 5,366
Undiscounted environmental liabilities	227	1,075
Total accrued environmental liabilities	$ 6,592	$ 6,441

Commitments and Contingencies67

Commitments and Contingencies, Environmental Liabilities, Future Payments (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Year ending December 31,
2,017	$ 686
2,018	634
2,019	614
2,020	614
2,021	613
2022 and thereafter	4,409
Discounted environmental liabilities, gross	7,570
Less: Discount applied	1,205
Discounted environmental liabilities	$ 6,365	$ 5,366

Quarterly Information (unaudi68

Quarterly Information (unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Net sales	$ 509,009	$ 462,257	$ 468,457	$ 368,009	$ 437,872	$ 551,813	$ 625,064	$ 542,442	$ 1,807,732	[1]	$ 2,157,191	[1]	$ 3,221,373	[1]
Operating income	9,362	10,191	10,998	2,117	19,354	65,766	69,851	48,535	32,668		203,506		217,979
Net income (loss)	$ 884	$ 2,083	$ 1,191	$ (8,562)	$ 7,246	$ 53,776	$ 59,426	$ 36,451	$ (4,404)		$ 156,899		$ 169,135
Earnings (loss) per unit	$ 0.01	$ 0.03	$ 0.02	$ (0.14)	$ 0.12	$ 0.86	$ 0.95	$ 0.58	$ (0.07)		$ 2.51		$ 2.71
[1]	Includes sales to related parties of $307,497, $358,194 and $563,008 for the years ended December 31, 2016, 2015 and 2014, respectively.

Subsequent Event (Details)

Subsequent Event (Details) - Subsequent Event - Cash Distribution $ / shares in Units, $ in Thousands	Feb. 09, 2017USD ($)$ / shares
Subsequent Event
Distribution Made to Limited Partner, Cash Distributions Declared | $	$ 6,877
Distribution Made to Limited Partner, Distributions Declared, Per Unit | $ / shares	$ 0.11