Blueknight Energy Partners (BKEP) 10-K 9 Mar 17 2016 Q4 Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Mar. 02, 2017	Jun. 30, 2016
Entity Information [Line Items]
Entity Registrant Name	Blueknight Energy Partners, L.P.
Entity Central Index Key	1,392,091
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Public Float			$ 173.4
Entity Common Stock, Shares Outstanding		38,155,434
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q4
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 3,304	$ 3,038
Accounts receivable, net of allowance for doubtful accounts of $38 and $49 at December 31, 2015 and 2016, respectively	7,544	8,697
Receivables from related parties, net of allowance for doubtful accounts of $225 and $0 at December 31, 2015 and 2016, respectively	1,860	1,844
Prepaid insurance	1,578	1,397
Assets held for sale, net of accumulated depreciation of $3,041 at December 31, 2016	4,237	0
Other current assets	7,934	4,384
Total current assets	26,457	19,360
Property, plant and equipment, net of accumulated depreciation of $205,967 and $292,117 at December 31, 2015 and 2016, respectively	307,334	312,934
Investment in unconsolidated affiliate	20,561	19,078
Goodwill	4,746	4,387
Debt issuance costs, net	2,050	2,201
Intangibles and other assets, net	14,515	6,786
Total assets	375,663	364,746
Current liabilities:
Accounts payable	3,174	5,236
Accounts Payable, Related Parties, Current	1,053	0
Accrued interest payable	413	191
Accrued property taxes payable	2,531	2,773
Unearned revenue	2,350	4,299
Unearned revenue with related parties	383	756
Accrued payroll	6,358	7,263
Other current liabilities	4,279	6,358
Total current liabilities	20,541	26,876
Long-term unearned revenue with related parties	640	80
Other long-term liabilities	2,959	2,468
Interest rate swap liabilities	1,947	3,103
Long-term debt	324,000	245,000
Commitments and contingencies (Note 16)
Partners’ capital:
Series A Preferred Units (30,158,619 and 35,125,202 units issued and outstanding at December 31, 2015 and 2016, respectively)	253,923	204,599
Common unitholders (33,039,818 and 38,003,397 units issued and outstanding at December 31, 2015 and December 31, 2016, respectively)	471,180	493,824
General partner interest (1.8% with 1,127,755 general partner units outstanding at December 31, 2015 and 1.7% with 1,225,409 general partner units outstanding at December 31, 2016)	(699,527)	(611,204)
Total partners’ capital	25,576	87,219
Total liabilities and partners’ capital	$ 375,663	$ 364,746

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Accounts receivable, allowance for doubtful accounts	$ 49	$ 38
Receivables from related parties, allowance for doubtful accounts	0	225
Assets held for sale, accumulated depreciation and impairments	(3,041)	0
Property, plant and equipment, accumulated depreciation and Impairments	$ 292,117	$ 205,967
Partners’ capital:
Series A Preferred unitholders, units issued	35,125,202	30,158,619
Series A Preferred unitholders, units outstanding	35,125,202	30,158,619
Common unitholders, units issued	38,003,397	33,039,818
Common unitholders, units outstanding	38,003,397	33,039,818
General partner interest, units outstanding	1,225,409	1,127,755
General partner percentage interest	1.70%	1.80%

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
Service revenue:
Third party revenue	$ 126,215	$ 137,415	$ 139,426
Related party revenue	30,211	39,103	42,788
Product sales revenue:
Third party revenue	20,968	3,511	4,412
Total revenue	177,394	180,029	186,626
Costs and expenses:
Operating expense	111,091	127,974	134,184
Cost of product sales	14,130	3,231	61
General and administrative expense	20,029	18,976	17,498
Asset impairment expense	25,761	21,996	0
Total costs and expenses	171,011	172,177	151,743
Gain on sale of assets	108	6,137	2,464
Operating income	6,491	13,989	37,347
Other income (expense):
Equity earnings in unconsolidated affiliate	1,483	3,932	883
Interest expense (net of capitalized interest of $291, $184, and $41, respectively)	(12,554)	(11,202)	(12,268)
Unrealized gains on investments	0	0	2,079
Income (Loss) before Income Taxes	(4,580)	6,719	28,041
Provision for income taxes	260	323	469
Net income (loss)	(4,840)	6,396	27,572
Allocation of net income (loss) for calculation of earnings per unit:
General partner interest in net income	433	554	641
Preferred interest in net income	25,824	21,564	21,563
Income (loss) available to limited partners	$ (31,097)	$ (15,722)	$ 5,368
Basic and diluted net income (loss) per common unit	$ (0.87)	$ (0.47)	$ 0.20
Weighted average common units outstanding - basic and diluted	35,093	32,945	25,670

CONSOLIDATED STATEMENTS OF OPE5

CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) shares 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
Income Statement [Abstract]
Capitalized Interest									$ 41,241.21	$ 184,388.68	$ 291,456.92
Diluted net income (loss) per common unit	$ (0.18)	$ 0.13	$ (0.71)	$ (0.14)	$ (0.65)	$ 0.21	$ 0.06	$ (0.12)	$ (0.87)	$ (0.47)	$ 0.20
Weighted average common units outstanding - diluted									32,945	25,670	22,706

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL - USD ($) $ in Thousands	Total	Preferred Partner [Member]	Limited Partner [Member]	General Partner Interest [Member]
Balance at Dec. 31, 2013	$ 55,458	$ 204,599	$ 461,149	$ (610,290)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	27,572	21,564	5,517	491
Equity-based incentive compensation	1,619		1,590	29
Profits interest contribution	150			150
Distributions	(36,025)	(21,564)	(13,671)	790
Proceeds from Partnership Contribution	0
Proceeds from issuance of common units, net of offering costs	71,182		71,182
Repurchase of 13,335,390 Series A Preferred Units	0
Balance at Dec. 31, 2014	119,956	204,599	525,767	(610,410)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	6,396	21,564	(15,281)	113
Equity-based incentive compensation	2,131		2,095	36
Profits interest contribution	150			150
Distributions	(41,600)	(21,564)	(18,943)	(1,093)
Proceeds from Partnership Contribution	0
Proceeds from Issuance of Shares under Incentive and Share-based Compensation Plans, Excluding Stock Options	186		186
Repurchase of 13,335,390 Series A Preferred Units	0
Balance at Dec. 31, 2015	87,219	204,599	493,824	(611,204)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(4,840)	24,939	(30,004)	225
Equity-based incentive compensation	2,087		2,051	36
Profits interest contribution	923			923
Distributions	(47,219)	(24,939)	(20,960)	(1,320)
Proceeds from Partnership Contribution	2,384			2,384
Proceeds from issuance of common units, net of offering costs	20,931		20,900
Proceeds from Issuance of Shares under Incentive and Share-based Compensation Plans, Excluding Stock Options	338		338
Repurchase of 13,335,390 Series A Preferred Units	95,348	95,348
Proceeds from issuance of 18,312,968 Series A Preferred Units	144,672	144,672
Proceeds from Issuance of Private Placement	5,000		5,000
Proceeds from issuance of 97,654 general partner units	680
Combination of Entities under Common Control, Consideration Paid in Excess of Historical Cost	91,251			91,251
Balance at Dec. 31, 2016	$ 25,576	$ 253,923	$ 471,180	$ (699,527)

CONSOLIDATED STATEMENTS OF CHA7

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL (Parenthetical) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Limited Partner [Member]
Partners' Capital Account, Units, Sale of Units	3,795,000
Limited Partners' Offering Costs	$ 1,500,000
Partners' Capital Account, Units, Sold in Private Placement	847,457
Partners' Capital Account, Units, Unit-based Compensation	71,807	30,075
General Partner Interest [Member]
Partners' Capital Account, Units, Sale of Units	97,654
Preferred Partner [Member]
Partners' Capital Account, Units, Sale of Units	18,312,968
Stock Repurchased During Period, Shares	13,335,390

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities:
Net income (loss)	$ (4,840,000)	$ 6,396,000	$ 27,572,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Provision for uncollectible receivables from third parties	15,000	(184,000)	126,000
Provision for uncollectible receivables from related parties	(229,000)	0	225,000
Depreciation and amortization	30,820,000	27,228,000	26,045,000
Impairment of intangible assets	0	7,498,000	0
Amortization of debt issuance costs	1,107,000	884,000	821,000
Unrealized loss (gain) related to interest rate swaps	(1,156,000)	469,000	2,634,000
Fixed asset impairment charge	25,761,000	14,498,000	0
Gain on sale of assets	(108,000)	(6,137,000)	(2,464,000)
Equity-based incentive compensation	2,087,000	2,131,000	1,538,000
Equity earnings in unconsolidated affiliate	(1,483,000)	(3,932,000)	(883,000)
Distributions from unconsolidated affiliate	0	4,313,000	0
Gain related to investments	0	267,000	2,079,000
Changes in assets and liabilities
Decrease in accounts receivable	1,138,000	538,000	3,067,000
Decrease in receivables from related parties	213,000	472,000	608,000
Decrease in prepaid insurance	3,008,000	3,998,000	2,943,000
Decrease (increase) in other current assets	237,000	(579,000)	516,000
Increase in other assets	(498,000)	(1,485,000)	(299,000)
Decrease in accounts payable	(237,000)	(792,000)	(580,000)
Increase in accounts payable to related parties	1,053,000	0	0
Increase (decrease) in accrued interest payable	222,000	(42,000)	(249,000)
Increase (decrease) in accrued property taxes	(242,000)	727,000	236,000
Increase (decrease) in unearned revenue	(1,568,000)	2,075,000	(82,000)
Increase (decrease) in unearned revenue from related parties	187,000	(189,000)	782,000
Increase (decrease) in accrued payroll	(905,000)	743,000	(859,000)
Increase (decrease) in other accrued liabilities	(1,733,000)	2,169,000	(1,378,000)
Net cash provided by operating activities	52,849,000	60,532,000	58,240,000
Cash flows from investing activities:
Acquisition of assets from Ergon	122,572,000	0	0
Acquisitions	(18,989,000)	(20,951,000)	0
Capital expenditures	(19,995,000)	(41,609,000)	(37,368,000)
Proceeds from sale of assets	1,993,000	14,687,000	3,063,000
Distributions from unconsolidated affiliate	0	922,000	0
Proceeds from sale of investments	0	2,346,000	0
Net cash used in investing activities	(159,563,000)	(44,605,000)	(34,305,000)
Cash flows from financing activities:
Payment on insurance premium financing agreement	(3,425,000)	(3,286,000)	(2,518,000)
Debt issuance costs	(956,000)	0	(326,000)
Borrowings under credit facility	170,000,000	112,000,000	60,733,000
Payments under credit facility	(91,000,000)	(83,000,000)	(117,733,000)
Proceeds from issuance of Series A Preferred Units	144,672,000	0	0
Proceeds from issuance of common units, net of offering costs	26,269,000	186,000	71,182,000
Proceeds from issuance of general partner units	680,000	0	0
Repurchase of Series A Preferred Units	(95,348,000)	0	0
Capital contributions related to profits interest	923,000	150,000	150,000
Capital contributions	2,384,000	0	0
Distributions	(47,219,000)	(41,600,000)	(35,944,000)
Net cash provided by (used in) financing activities	106,980,000	(15,550,000)	(24,456,000)
Net increase (decrease) in cash and cash equivalents	266,000	377,000	(521,000)
Cash and cash equivalents at beginning of period	3,038,000	2,661,000	3,182,000
Cash and cash equivalents at end of period	3,304,000	3,038,000	2,661,000
Supplemental disclosure of cash flow information:
Increase (decrease) in accounts payable related to purchase of property, plant and equipment	(1,825,000)	(1,598,000)	1,669,000
Increase in accrued liabilities related to insurance premium financing agreement	3,189,000	3,813,000	2,494,000
Cash paid for interest, net of amounts capitalized	12,404,000	9,915,000	9,085,000
Cash paid for income taxes	$ 282,000	$ 412,000	$ 508,000

ORGANIZATION AND NATURE OF BUSI

ORGANIZATION AND NATURE OF BUSINESS	12 Months Ended
	Dec. 31, 2016
ORGANIZATION AND NATURE OF BUSINESS [Abstract]
ORGANIZATION AND NATURE OF BUSINESS	ORGANIZATION AND NATURE OF BUSINESS Blueknight Energy Partners, L.P. and subsidiaries (collectively, the “Partnership”) is a publicly traded master limited partnership with operations in 26 states. The Partnership provides integrated terminalling, storage, processing, gathering and transportation services for companies engaged in the production, distribution and marketing of crude oil and asphalt products. The Partnership manages its operations through four operating segments: (i) asphalt terminalling services, (ii) crude oil terminalling and storage services, (iii) crude oil pipeline services and (iv) crude oil trucking and producer field services. The Partnership’s common units and preferred units, which represent limited partnership interests in the Partnership, are listed on the NASDAQ Global Market under the symbols “BKEP” and “BKEPP,” respectively. The Partnership was formed in February 2007 as a Delaware master limited partnership initially to own, operate and develop a diversified portfolio of complementary midstream energy assets. On October 5, 2016, the Partnership completed the following transactions (the “Ergon Transactions”): (i) a subsidiary of Ergon, Inc. (together with its subsidiaries, “Ergon”) purchased 100% of the outstanding voting stock of Blueknight GP Holding, L.L.C., which owns 100% of the capital stock of the Partnership’s general partner, Blueknight Energy Partners G.P., L.L.C., pursuant to a Membership Interest Purchase Agreement dated July 19, 2016 among CB-Blueknight, LLC, an indirect wholly-owned subsidiary of Charlesbank, Blueknight Energy Holding, Inc., an indirect wholly-owned subsidiary of Vitol Holding B.V. (together with its affiliates and subsidiaries “Vitol”), and Ergon Asphalt Holdings, LLC, a wholly-owned subsidiary of Ergon (the “Ergon Change of Control”); (ii) Ergon contributed nine asphalt terminals plus $22.1 million in cash in return for total consideration of approximately $144.7 million , which consisted of the issuance of 18,312,968 of Series A preferred units in a private placement; and (iii) Ergon acquired an aggregate of $5.0 million of common units for cash in a private placement, pursuant to a Contribution Agreement between the Partnership and Ergon. The Partnership’s acquisition of nine asphalt terminals from Ergon on October 5, 2016 was accounted for as a transaction among entities under common control. As a result, the Partnership recorded the acquired assets at Ergon’s historical cost of $31.3 million , net of accumulated depreciation of $63.0 million . The $91.3 million of consideration in excess of Ergon’s historical net book value was recorded as a deemed distribution to the Partnership’s general partner and is reflected as Consideration paid in excess of historical cost of assets acquired from Ergon on the Partnership’s consolidated statement of changes in partners’ capital.

BASIS OF CONSOLIDATION AND PRES

BASIS OF CONSOLIDATION AND PRESENTATION	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
BASIS OF CONSOLIDATION AND PRESENTATION	BASIS OF CONSOLIDATION AND PRESENTATION The accompanying consolidated financial statements and related notes present and discuss the Partnership’s consolidated financial position as of December 31, 2015 and 2016 , and the consolidated results of the Partnership’s operations, cash flows and changes in partners’ capital for the years ended December 31, 2014 , 2015 and 2016 . The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All significant intercompany accounts and transactions have been eliminated in the preparation of the accompanying consolidated financial statements. Certain reclassifications have been made in the consolidated financial statements for the years ended December 31, 2014 and 2015 to conform to the 2016 financial statement presentation. These were reclassifications of product sales from third party service revenue and cost of product sales from operating expenses. The reclassifications have no impact on net income.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Notes)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Significant Accounting Policies [Text Block]	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES USE OF ESTIMATES - The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts and disclosure of contingencies. Management makes significant estimates including: (1) allowance for doubtful accounts receivable; (2) estimated useful lives of assets, which impacts depreciation; (3) estimated cash flows and fair values inherent in impairment tests; (4) accruals related to revenues and expenses; (5) the estimated fair value of financial instruments; and (6) liability and contingency accruals. Although management believes these estimates are reasonable, actual results could differ from these estimates. CASH AND CASH EQUIVALENTS - The Partnership includes as cash and cash equivalents, cash and all investments with original maturities of three months or less which are readily convertible into known amounts of cash. ACCOUNTS RECEIVABLE - The majority of the Partnership’s accounts receivable relates to its trucking and producer field services and asphalt terminalling services activities. Accounts receivable included in the consolidated balance sheets are reflected net of the allowance for doubtful accounts of less than $0.1 million at both December 31, 2015 and 2016 . The Partnership reviews all outstanding accounts receivable balances on a monthly basis and records a reserve for amounts that the Partnership expects will not be fully recovered. Although the Partnership considers its allowance for doubtful trade accounts receivable to be adequate, there is no assurance that actual amounts will not vary significantly from estimated amounts. PROPERTY, PLANT AND EQUIPMENT - Property, plant and equipment are recorded at cost. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred. The carrying value of the assets is based on estimates, assumptions and judgments relative to useful lives and salvage values. As assets are disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is included in consolidated operating income in the consolidated statements of operations. Depreciation is calculated using the straight-line method, based on estimated useful lives of the assets. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions and supply and demand in the area. When assets are put into service, management makes estimates with respect to useful lives and salvage values that it believes are reasonable. However, subsequent events could cause management to change its estimates, thus impacting the future calculation of depreciation. The Partnership has contractual obligations to perform dismantlement and removal activities in the event that some of its asphalt product and residual fuel oil terminalling and storage assets are abandoned (see Note 16 ). Such obligations are recognized in the period incurred if reasonably estimable. IMPAIRMENT OF LONG-LIVED ASSETS AND OTHER INTANGIBLE ASSETS - Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-down to estimated fair value. A long-lived asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is generally determined from estimated discounted future net cash flows. The Partnership recognized fixed asset impairment charges of $25.8 million during the year ended December 31, 2016 , primarily due to an impairment recognized on the Knight Warrior pipeline project and the East Texas pipeline system. The Knight Warrior pipeline project was canceled due to continued low rig counts in the Eaglebine/Woodbine area coupled with lower production volumes, competing projects and the overall impact of the decreased market price of crude oil. Consequently, shipper commitments related to the project were canceled. In connection with the cancellation of the shipper commitments, the Partnership evaluated the Knight Warrior project for impairment and recognized an impairment expense of $22.6 million during the year ended December 31, 2016 . During the year ended December 31, 2015, the Partnership recognized fixed asset impairment charges of $12.6 million , $1.4 million , and $0.5 million related to the East Texas pipeline system, a portion of the Mid-Continent pipeline system, and the West Texas trucking stations, respectively. The Partnership had no impairment charges during the year ended December 31, 2014 . Acquired customer relationships and non-compete agreements are capitalized and amortized over useful lives ranging from 4 to 20 years using the straight-line method of amortization. An impairment loss is recognized for definite-lived intangibles if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value. No impairment charge was recognized during the years ended December 31, 2014 , 2015 or 2016 with respect to intangible assets. EQUITY METHOD INVESTMENTS - The Partnership’s investment in Advantage Pipeline, L.L.C. (“Advantage Pipeline”), over which the Partnership has significant influence but not control, is accounted for by the equity method. The Partnership does not consolidate any part of the assets or liabilities of its equity investee. As of December 31, 2016 , the Partnership’s investment represents a 30% ownership interest in Advantage Pipeline. The Partnership’s share of net income or loss is reflected as one line item on the Partnership’s consolidated statements of operations entitled “Equity earnings in unconsolidated affiliate” and will increase or decrease, as applicable, the carrying value of the Partnership’s investment in the unconsolidated affiliate on the consolidated balance sheets. Distributions to the Partnership reduce the carrying value of its investment and will be reflected in the Partnership’s consolidated statements of cash flows in the line item “Distributions from unconsolidated affiliate.” In turn, contributions will increase the carrying value of the Partnership’s investment and will be reflected in the Partnership’s consolidated statements of cash flows in investing activities. The Partnership evaluates its equity investment for impairment in accordance with FASB guidance with respect to the equity method of accounting for investments in common stock. An impairment of an equity investment results when factors indicate that the investment’s fair value is less than its carrying value and the reduction in value is other than temporary in nature. DEBT ISSUANCE COSTS - Costs incurred in connection with the issuance of long-term debt related to the Partnership’s credit facilities are capitalized and amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization. INVESTMENTS - In November 2014, the Partnership received 30,393 Class A Common Units of SemCorp in connection with the settlement of two unsecured claims the Partnership filed in connection with SemCorp’s predecessor’s bankruptcy filing in 2008. The fair market value of these units on the date of receipt was $2.5 million . An unrealized loss of $0.4 million was incurred as a result of marking the units to their fair market value of $68.39 per unit as of December 31, 2014. The Partnership presents the unrealized gains and losses related to these units as one line item on the Partnership’s consolidated statements of operations entitled “Unrealized gains on investments.” In March 2015, the Partnership sold all of these units for a total of $2.3 million . GOODWILL - Goodwill represents the excess of the cost of acquisitions over the amounts assigned to assets acquired and liabilities assumed. Goodwill is not amortized but is tested annually for impairment and when events and circumstances warrant an interim evaluation. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit. The Partnership has four reporting units comprised of (i) its asphalt services, (ii) its crude oil terminalling and storage services, (iii) its crude oil pipeline services, and (iv) its crude oil trucking and producer field services. The Partnership has recorded goodwill of $0.9 million related to its crude oil trucking and producer field services reporting unit and $3.9 million related to its asphalt terminalling services reporting unit. During 2015, the Partnership recorded goodwill of $3.5 million attributable to its asphalt terminalling services reporting unit related to the acquisition of an asphalt terminalling facility in Cheyenne, Wyoming, as well as $1.2 million attributable to its crude oil pipeline services reporting unit related to the acquisition of a pipeline system and related crude oil marketing business in southern Oklahoma. During 2016, the Partnership recorded goodwill of $0.4 million attributable to its asphalt terminalling services reporting unit related to the acquisition of asphalt terminalling facilities in Wilmington, North Carolina and Dumfries, Virginia. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered to be impaired. The impairment test is generally based on the estimated discounted future net cash flows of the respective reporting unit, utilizing discount rates and other factors in determining the fair value of the reporting unit. Inputs in the Partnership’s estimated discounted future net cash flows include existing and estimated future asset utilization, estimated growth rates in future cash flows, and estimated terminal values (these are all considered Level 3 inputs). During the fourth quarter of 2015 impairment testing indicated that the fair value of the pipeline services reporting unit was less than the carrying value, and the Partnership recognized impairment of goodwill of $7.5 million related to its crude oil pipeline services reporting unit. Impairment testing indicated there was no impairment of goodwill in 2016. ENVIRONMENTAL MATTERS - Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines, penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. The Partnership recorded loss contingencies related to environmental matters of less than $0.1 million as of December 31, 2015 . The Partnership had no such loss contingencies as of December 31, 2016 . REVENUE RECOGNITION - The Partnership’s revenues consist of (i) terminalling and storage revenues, (ii) gathering, transportation and producer field services revenues, (iii) crude oil marketing revenues and (iv) fuel surcharge revenues. Terminalling and storage revenues consist of (i) storage service fees from actual storage used on a month-to-month basis; (ii) storage service fees resulting from short-term and long-term contracts for committed space that may or may not be utilized by the customer in a given month; and (iii) terminal throughput service charges to pump crude oil to connecting carriers or to deliver asphalt product out of the Partnership’s terminals. Terminal throughput service charges are recognized as the crude oil exits the terminal and is delivered to the connecting crude oil carrier or third-party terminal and as the asphalt product is delivered out of the Partnership’s terminal. Storage service revenues are recognized as the services are provided and the amounts earned on a monthly basis. Gathering and transportation services revenues consist of service fees recognized for the gathering of crude oil for the Partnership’s customers and the transportation of the crude oil to refiners, to common carrier pipelines for ultimate delivery to refiners, or to terminalling and storage facilities owned by the Partnership and others. Revenue for the gathering and transportation of crude oil is recognized when the service is performed and is based upon regulated and non-regulated tariff rates and the related transport volumes. Producer field services revenue consists of a number of services ranging from gathering condensates from natural gas producers to hauling produced water to disposal wells. Revenue for producer field services is recognized when the service is performed. Crude oil marketing revenues consist of sales proceeds recognized for the sale of crude oil to third party customers. Revenue for the sale of crude oil is recognized when title to the crude oil transfers to the customer and is based on contractual prices for the sale of crude oil. Fuel surcharge revenues are comprised of revenues recognized for the reimbursement of fuel and power consumed to operate the Partnership’s asphalt product storage tanks and terminals. The Partnership recognizes fuel surcharge revenues in the period in which the related fuel and power expenses are incurred. INCOME AND OTHER TAXES - For federal and most state income tax purposes, the majority of income, gains, losses, expenses, deductions and tax credits generated by the Partnership flow through to the unitholders of the Partnership. In 2007, the state of Texas implemented a partnership-level tax based on a percentage of the revenue earned for services provided in the state of Texas. The Partnership has estimated its liability related to this tax to be $0.3 million for both December 31, 2015 and 2016 , which is reported as a provision for income taxes on its consolidated statements of operations. See Note 20 for a discussion of certain risks related to the Partnership’s ability to be treated as a partnership for federal income tax purposes. STOCK BASED COMPENSATION - The Partnership’s general partner adopted the Blueknight Energy Partners G.P. L.L.C. Long-Term Incentive Plan (the “LTIP”). The compensation committee of the Board administers the LTIP. Effective April 29, 2014, the Partnership’s unitholders approved an amendment to the LTIP to increase the number of common units reserved for issuance under the incentive plan by 1.5 million common units from 2.6 million common units to 4.1 million common units, subject to adjustment for certain events. Although other types of awards are contemplated under the LTIP, awards issued to date include “phantom” units, which convey the right to receive common units upon vesting, and “restricted” units, which are grants of common units restricted until the time of vesting. Certain of the phantom unit awards also include distribution equivalent rights (“DERs”). A DER entitles the grantee to a cash payment equal to the cash distribution paid on an outstanding common unit prior to the vesting date of the underlying award. Cash distributions paid on DERs are accounted for as partnership distributions. Recipients of restricted units are entitled to receive cash distributions paid on common units during the vesting period. The Partnership classifies unit award grants as either equity or liability awards. All award grants made under the LTIP from its inception through December 31, 2016 have been classified as equity awards. Fair value for award grants classified as equity is determined on the grant date of the award and this value is recognized as compensation expense ratably over the requisite service period of unit award grants, which generally is the vesting period. Fair value for equity awards is calculated as the closing price of the Partnership’s common units representing limited partner interests in the Partnership (“common units”) on the grant date and is reduced by the present value of estimated cash distributions to be paid on common units during the vesting period to the extent a unit award does not include DERs. Compensation expense related to unit-based payments is included in operating and general and administrative expenses on the Partnership’s consolidated statements of operations. FAIR VALUE OF FINANCIAL INSTRUMENTS - The Partnership measures all financial instruments, including derivatives embedded in other contracts, at fair value and recognizes them in the consolidated balance sheets as an asset or a liability, depending on its rights and obligations under the applicable contract. The changes in the fair value of financial instruments are recognized currently in earnings in the consolidated statements of operations.

EQUITY METHOD INVESTMENT (Notes

EQUITY METHOD INVESTMENT (Notes)	12 Months Ended
	Dec. 31, 2016
Equity Method Investments [Abstract]
Equity Method Investments and Joint Ventures Disclosure [Text Block]	EQUITY METHOD INVESTMENT The Partnership’s investment in Advantage Pipeline, over which the Partnership has significant influence but not control, is accounted for by the equity method. As of December 31, 2016 , the Partnership’s investment represents a 30% ownership interest in Advantage Pipeline. On February 12, 2017, Advantage Pipeline entered into a definitive agreement whereby Advantage Pipeline will be acquired by a joint venture (“JV”) formed by Plains All American Pipeline, L.P. (“PAA”) and Noble Midstream Partners LP. The closing of the transaction is expected to occur either late first quarter or early second quarter of 2017 and is subject to customary closing conditions, including the receipt of regulatory approvals. The Partnership expects to elect to receive all cash proceeds from the sale of Advantage Pipeline, and anticipates net proceeds of approximately $27.0 million to $29.0 million , subject to certain customary closing conditions. Once the transaction is closed, the Partnership will no longer maintain an equity ownership interest in Advantage Pipeline. Summarized financial information for Advantage Pipeline is set forth in the tables below for the periods indicated. As of December 31, 2015 2016 (in thousands) Balance sheets Current assets $ 2,496 $ 2,075 Noncurrent assets 86,702 89,065 Total assets $ 89,198 $ 91,140 Current liabilities 2,534 1,327 Long-term liabilities 23,194 20,910 Member’s equity 63,470 68,903 Total liabilities and member’s equity $ 89,198 $ 91,140 Year ended December 31, 2014 2015 2016 (in thousands) Income statements Operating revenues $ 10,894 $ 26,398 $ 17,091 Net income $ 3,354 $ 14,909 $ 5,434

RESTRUCTURING CHARGES (Notes)

RESTRUCTURING CHARGES (Notes)	12 Months Ended
	Dec. 31, 2015
Restructuring Charges [Abstract]
Restructuring and Related Activities Disclosure [Text Block]	RESTRUCTURING CHARGES During the fourth quarter of 2015, the Partnership recognized certain restructuring charges in our crude oil trucking and producer field services segment pursuant to an approved plan to exit the trucking market in West Texas. The following restructuring charges were accrued for as of December 31, 2015 and reported in operating expenses in the Partnership’s consolidated statement of operations for the year ended December 31, 2015 . For the year ended December 31, 2015 (in thousands) Severance charges $ 315 Lease payments related to operating leases for idled equipment 1,250 Total restructuring costs $ 1,565 Changes in the accrued amounts pertaining to the above charges are summarized as follows: Year ended December 31, 2015 2016 (in thousands) Beginning Balance $ — $ 1,565 Charged to expense 1,565 — Cash Payments — 1,091 Ending Balance $ 1,565 $ 474 The remaining accrual relates to lease payments that will be paid over the remaining lease terms, which extend through July 2019.

PROPERTY, PLANT AND EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
PROPERTY, PLANT AND EQUIPMENT	PROPERTY, PLANT AND EQUIPMENT Estimated Useful Lives (Years) December 31, 2015 December 31, 2016 (dollars in thousands) Land N/A $ 19,680 $ 25,863 Land improvements 10-20 6,382 6,698 Pipelines and facilities 5-30 165,497 165,293 Storage and terminal facilities 10-35 251,051 347,656 Transportation equipment 3-10 13,728 12,391 Office property and equipment and other 3-20 28,453 35,578 Pipeline linefill and tank bottoms N/A 3,474 3,234 Construction-in-progress N/A 30,636 2,738 Property, plant and equipment, gross 518,901 599,451 Accumulated depreciation and impairments (205,967 ) (292,117 ) Property, plant and equipment, net $ 312,934 $ 307,334 Depreciation expense for the years ended December 31, 2014 , 2015 and 2016 was $26.0 million , $27.0 million and $29.6 million , respectively. During the year ended December 31, 2015 , the Partnership recorded fixed asset impairment expense of $14.0 million related to its crude oil pipeline services reporting unit and $0.5 million related to its crude oil trucking and field services reporting unit. During the year ended December 31, 2016 , the Partnership recorded fixed asset impairment expense of $25.8 million , primarily due to an impairment recognized on the Knight Warrior pipeline project and the East Texas pipeline system. There was no impairment expense recorded during the year ended December 31, 2014 . Included in assets held for sale on the consolidated balance sheets is the East Texas pipeline, with a net book value of $4.2 million . The Partnership expects to finalize a sale of the East Texas pipeline within a year.

INTANGIBLES AND OTHER ASSETS, N

INTANGIBLES AND OTHER ASSETS, NET (Notes)	12 Months Ended
	Dec. 31, 2016
Intangibles and Other Assets [Abstract]
Intangibles And Other Assets, Net [Text Block]	INTANGIBLES AND OTHER ASSETS, NET Other assets, net of accumulated amortization, consist of the following: December 31, 2015 2016 (in thousands) Customer relationships $ 4,132 $ 12,579 Deferred charges related to pipeline connection agreements 2,627 2,653 Deposits 307 435 Prepaid insurance 12 428 Other prepaid expenses 70 24 Intangibles and other assets, gross 7,148 16,119 Accumulated amortization of intangible assets (362 ) (1,604 ) Intangibles and other assets, net $ 6,786 $ 14,515 Amortization expense related to intangibles for the years ended December 31, 2014 , 2015 and 2016 was less than $0.1 million , $0.2 million and $1.2 million , respectively. The estimated aggregate amortization expense on amortizable intangible assets currently owned by the Partnership is as follows (in thousands): For year ending: December 31, 2017 $ 1,287 December 31, 2018 1,287 December 31, 2019 1,286 December 31, 2020 1,285 December 31, 2021 1,285 Thereafter 7,198 Total estimated aggregate amortization expense $ 13,628 Customer relationships include $8.4 million related to the acquisition of asphalt facilities in February 2016, $3.5 million related to the acquisition of a pipeline and crude oil marketing business in November 2015, and $0.7 million related to the acquisition of a producer field services business in December 2010. The customer relationships are being amortized over a range of 4 to 20 years.

DEBT

DEBT	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
DEBT	DEBT On June 28, 2013, the Partnership entered into an amended and restated credit agreement which consists of a $400.0 million revolving loan facility. On September 15, 2014, the Partnership amended its credit facility to, among other things, amend the maximum permitted consolidated total leverage ratio as discussed below and to increase the limit on material project adjustments to EBITDA (as defined in the credit agreement). On July 19, 2016, the Partnership entered into a second amendment to the credit agreement which, among other things, amended the maximum permitted consolidated total leverage ratio as discussed below. As of March 2, 2017 , approximately $322.0 million of revolver borrowings and $1.5 million of letters of credit were outstanding under the credit facility, leaving the Partnership with approximately $76.5 million available capacity for additional revolver borrowings and letters of credit under the credit facility, although the Partnership’s ability to borrow such funds may be limited by the financial covenants in the credit facility. The proceeds of loans made under the amended and restated credit agreement may be used for working capital and other general corporate purposes of the Partnership. All references herein to the credit agreement refer to the amended and restated credit agreement, as amended on July 19, 2016. The credit agreement is guaranteed by all of the Partnership’s existing subsidiaries. Obligations under the credit agreement are secured by first priority liens on substantially all of the Partnership’s assets and those of the guarantors. The credit agreement includes procedures for additional financial institutions to become revolving lenders, or for any existing lender to increase its revolving commitment thereunder, subject to an aggregate maximum of $500.0 million for all revolving loan commitments under the credit agreement. The credit agreement will mature on June 28, 2018 , and all amounts outstanding under the credit agreement will become due and payable on such date. The Partnership may prepay all loans under the credit agreement at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements. The credit agreement requires mandatory prepayments of amounts outstanding thereunder with the net proceeds from certain asset sales, property or casualty insurance claims, and condemnation proceedings, unless the Partnership reinvests such proceeds in accordance with the credit agreement, but these mandatory prepayments will not require any reduction of the lenders’ commitments under the credit agreement. Borrowings under the credit agreement bear interest, at the Partnership’s option, at either the reserve-adjusted eurodollar rate (as defined in the credit agreement) plus an applicable margin that ranges from 2.0% to 3.0% or the alternate base rate (the highest of the agent bank’s prime rate, the federal funds effective rate plus 0.5% , and the 30-day eurodollar rate plus 1.0% ) plus an applicable margin that ranges from 1.0% to 2.0% . The Partnership pays a per annum fee on all letters of credit issued under the credit agreement, which fee equals the applicable margin for loans accruing interest based on the eurodollar rate, and the Partnership pays a commitment fee ranging from 0.375% to 0.5% on the unused commitments under the credit agreement. The credit agreement does not have a floor for the alternate base rate or the eurodollar rate. The applicable margins for the Partnership’s interest rate, the letter of credit fee and the commitment fee vary quarterly based on the Partnership’s consolidated total leverage ratio (as defined in the credit agreement, being generally computed as the ratio of consolidated total debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges). The credit agreement includes financial covenants that are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter. Prior to the date on which the Partnership issues qualified senior notes in an aggregate principal amount (when combined with all other qualified senior notes previously or concurrently issued) that equals or exceeds $200.0 million , the maximum permitted consolidated total leverage ratio is 4.75 to 1.00; provided that the maximum permitted consolidated total leverage ratio will be 5.25 to 1.00 for certain quarters based on the occurrence of a specified acquisition (as defined in the Partnership’s credit agreement, but generally being an acquisition for which the aggregate consideration is $15.0 million or more). The acquisition of the nine asphalt terminals from Ergon qualified as a specified acquisition. From and after the date on which the Partnership issues qualified senior notes in an aggregate principal amount (when combined with all other qualified senior notes previously or concurrently issued) that equals or exceeds $200.0 million , the maximum permitted consolidated total leverage ratio is 5.00 to 1.00; provided that from and after the fiscal quarter ending immediately preceding the fiscal quarter in which a specified acquisition occurs to and including the last day of the second full fiscal quarter following the fiscal quarter in which such acquisition occurred, the maximum permitted consolidated total leverage ratio is 5.50 to 1.00. The maximum permitted consolidated senior secured leverage ratio (as defined in the credit agreement, but generally computed as the ratio of consolidated total secured debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) is 3.50 to 1.00, but this covenant is only tested from and after the date on which the Partnership issues qualified senior notes in an aggregate principal amount (when combined with all other qualified senior notes previously or concurrently issued) that equals or exceeds $200.0 million . The minimum permitted consolidated interest coverage ratio (as defined in the credit agreement, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest expense) is 2.50 to 1.00. Furthermore, the credit agreement: • requires the Partnership and its subsidiaries execute certain account control agreements; • requires that, to the extent (i) the Partnership’s consolidated total leverage ratio as of the end of the prior fiscal quarter was greater than 4.75 to 1.00 and (ii) the Partnership and its subsidiaries have cash and cash equivalents (subject to certain exceptions) exceeding $20.0 million for four consecutive business days, the Partnership prepay the Partnership’s outstanding obligations under the Partnership’s credit agreement in the amount of such excess; and • restricts the Partnership from borrowing funds under the Partnership’s credit agreement if, after giving effect to such borrowing and the prompt use of the proceeds thereof, the Partnership and its subsidiaries would have cash and cash equivalents (subject to certain exceptions) exceeding $20.0 million . In addition, the credit agreement contains various covenants that, among other restrictions, limit the Partnership’s ability to: • create, issue, incur or assume indebtedness; • create, incur or assume liens; • engage in mergers or acquisitions; • sell, transfer, assign or convey assets; • repurchase the Partnership’s equity, make distributions to unitholders and make certain other restricted payments; • make investments; • modify the terms of certain indebtedness, or prepay certain indebtedness; • engage in transactions with affiliates; • enter into certain hedging contracts; • enter into certain burdensome agreements; • change the nature of the Partnership’s business; • enter into operating leases; and • make certain amendments to the Partnership’s partnership agreement. At December 31, 2016 , the Partnership’s consolidated total leverage ratio was 4.22 to 1.00 and the consolidated interest coverage ratio was 6.09 to 1.00. The Partnership was in compliance with all covenants of its credit agreement as of December 31, 2016 . The credit agreement permits the Partnership to make quarterly distributions of available cash (as defined in the Partnership’s partnership agreement) to unitholders so long as no default or event of default exists under the credit agreement on a pro forma basis after giving effect to such distribution. The Partnership is currently allowed to make distributions to its unitholders in accordance with this covenant; however, the Partnership will only make distributions to the extent it has sufficient cash from operations after establishment of cash reserves as determined by the Board in accordance with the Partnership’s cash distribution policy, including the establishment of any reserves for the proper conduct of the Partnership’s business. See Note 10 for additional information regarding distributions. In addition to other customary events of default, the credit agreement includes an event of default if (i) the General Partner ceases to own 100% of the Partnership’s general partner interest or ceases to control the Partnership, or (ii) Ergon ceases to own and control 50.0% or more of the membership interests of the General Partner. If an event of default relating to bankruptcy or other insolvency events occurs with respect to the General Partner or the Partnership, all indebtedness under the credit agreement will immediately become due and payable. If any other event of default exists under the credit agreement, the lenders may accelerate the maturity of the obligations outstanding under the credit agreement and exercise other rights and remedies. In addition, if any event of default exists under the credit agreement, the lenders may commence foreclosure or other actions against the collateral. If any default occurs under the credit agreement, or if the Partnership is unable to make any of the representations and warranties in the credit agreement, the Partnership will be unable to borrow funds or have letters of credit issued under the credit agreement. During the year ended December 31, 2014 , the Partnership capitalized debt issuance costs of $0.3 million related to the credit facility. During the year ended December 31, 2015 , the Partnership capitalized no debt issuance costs. During the year ended December 31, 2016 , the Partnership capitalized $1.0 million of debt issuance costs related to the credit facility. The debt issuance costs are being amortized over the term of the amended and restated credit agreement. Interest expense related to debt issuance cost amortization for the years ended December 31, 2014 , 2015 and 2016 was $0.8 million , $0.9 million and $1.1 million , respectively. During the years ended December 31, 2014 , 2015 and 2016 , the weighted average interest rate under the Partnership’s credit agreement was 3.44% , 3.37% and 3.95% , respectively, resulting in interest expense of approximately $9.2 million , $7.9 million and $11.2 million , respectively. As of December 31, 2016 , borrowings under the Partnership’s amended and restated credit agreement bore interest at a weighted average interest rate of 4.08% . During the years ended December 31, 2014 , 2015 and 2016 , the Partnership capitalized interest of $0.3 million , $0.2 million and less than $0.1 million , respectively. The Partnership is exposed to market risk for changes in interest rates related to its credit facility. Interest rate swap agreements are used to manage a portion of the exposure related to changing interest rates by converting floating-rate debt to fixed-rate debt. In March 2014 the Partnership entered into two interest rate swap agreements with an aggregate notional amount of $200.0 million . The first agreement has a notional amount of $100.0 million , became effective June 28, 2014, and matures on June 28, 2018. Under the terms of the first interest rate swap agreement, the Partnership pays a fixed rate of 1.45% and receives one-month LIBOR with monthly settlement. The second agreement has a notional amount of $100.0 million , became effective January 28, 2015, and matures on January 28, 2019. Under the terms of the second interest rate swap agreement, the Partnership pays a fixed rate of 1.97% and receives one-month LIBOR with monthly settlement. During the years ended December 31, 2014 , 2015 and 2016 , the Partnership recorded swap interest expense of $0.7 million , $2.9 million and $2.5 million , respectively. The fair market value of the interest rate swaps at December 31, 2015 and 2016 is a liability of $3.1 million and $1.9 million , respectively, and is recorded in long-term interest rate swap liabilities on the consolidated balance sheets. The interest rate swaps do not receive hedge accounting treatment under ASC 815 - Derivatives and Hedging. Changes in the fair value of the interest rate swaps are recorded in interest expense in the consolidated statements of operations.

NET INCOME PER LIMITED PARTNER

NET INCOME PER LIMITED PARTNER UNIT	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
NET INCOME PER LIMITED PARTNER UNIT	NET INCOME PER LIMITED PARTNER UNIT For purposes of calculating earnings per unit, the excess of distributions over earnings or excess of earnings over distributions for each period are allocated to the Partnership’s general partner based on the general partner’s ownership interest at the time. The following sets forth the computation of basic and diluted net income per common unit (in thousands, except per unit data): Year ended December 31, 2014 2015 2016 Net income (loss) $ 27,572 $ 6,396 $ (4,840 ) General partner interest in net income 641 554 433 Preferred interest in net income 21,563 21,564 25,824 Income (loss) available to limited partners $ 5,368 $ (15,722 ) $ (31,097 ) Basic and diluted weighted average number of units: Common units 25,670 32,945 35,093 Restricted and phantom units 675 685 803 Basic and diluted net income (loss) per common unit $ 0.20 $ (0.47 ) $ (0.87 )

PARTNERS' CAPITAL AND DISTRIBUT

PARTNERS' CAPITAL AND DISTRIBUTIONS	12 Months Ended
	Dec. 31, 2016
Partners' Capital Account, Distributions [Abstract]
PARTNERS' CAPITAL AND DISTRIBUTIONS	PARTNERS’ CAPTIAL AND DISTRIBUTIONS On October 5, 2016, the Partnership issued 847,457 common units to Ergon in a private placement for $5.0 million . In addition, on October 5, 2016, the Partnership repurchased 6,667,695 Series A Preferred Units from each Vitol and Charlesbank for an aggregate purchase price of approximately $95.3 million . Vitol and Charlesbank each retained 2,488,789 Series A Preferred Units upon completion of these transactions. Also, on October, 5, 2016, the Partnership issued 18,312,968 Series A Preferred Units to Ergon for $144.7 million , as well as 97,654 general partner units to Ergon for $0.7 million . On July 26, 2016, the Partnership issued and sold 3,795,000 common units for a public offering price of $5.90 per unit, resulting in proceeds of approximately $20.9 million , net of underwriters’ discount and offering expenses of $1.5 million . On September 22, 2014, the Partnership issued and sold 9,775,000 common units for a public offering price of $7.61 per unit, resulting in proceeds of approximately $71.2 million , net of underwriters’ discount and offering expenses of $3.2 million . The Partnership used the net proceeds from the offering for general partnership purposes, including the repayment of a portion of the outstanding borrowings under the Partnership’s credit facility and partially funding the Knight Warrior pipeline project that was cancelled in the second quarter of 2016 . In accordance with the terms of its partnership agreement, each quarter the Partnership distributes all of its available cash (as defined in the partnership agreement) to its unitholders. Generally, distributions are allocated: first, 98.4% to the Series A Preferred Unitholders and 1.6% to its general partner until the Partnership distributes for each Series A Preferred Unit an amount equal to the Series A quarterly distribution amount discussed below; then 98.4% to the Series A Preferred Unitholders and 1.6% to its general partner until the Partnership distributes for each Series A Preferred Unit an amount equal to any Series A cumulative distribution arrearage; and, thereafter, 98.4% to the common unitholders and 1.6% to its general partner. Distributions are also paid to the holders of restricted units and phantom units as disclosed in Note 13 . The Preferred Units are convertible at the holders’ option into common units. Holders of the Preferred Units are entitled to quarterly distributions of 2.75% per unit per quarter (or 11.0% per unit on an annual basis). If the Partnership fails to pay in full any distribution on the Preferred Units, the amount of such unpaid distribution will accrue and accumulate from the last day of the quarter for which such distribution is due until paid in full. The Partnership paid distributions totaling $21.6 million during 2014 on the Preferred Units for the quarters ending December 31, 2013, March 31, 2014 , June 30, 2014 and September 30, 2014 . The Partnership paid distributions totaling $21.6 million during 2015 on the Preferred Units for the quarters ending December 31, 2014 , March 31, 2015 , June 30, 2015 and September 30, 2015 . The Partnership paid distributions totaling $22.4 million during 2016 on the Preferred Units for the quarters ending December 31, 2015 , March 31, 2016 , June 30, 2016 and September 30, 2016 . On January 19, 2017 , the Board approved a distribution of $0.17875 per Preferred Unit, or a total distribution of $6.3 million , for the quarter ending December 31, 2016 . The Partnership paid this distribution on the Preferred Units on February 14, 2017 to unitholders of record as of February 3, 2017 . The Partnership paid distributions totaling $14.5 million during 2014 on the common units for the quarters ending December 31, 2013, March 31, 2014 , June 30, 2014 and September 30, 2014 . Of the $14.5 million paid during 2014 , approximately $0.8 million and $0.3 million was paid to the Partnership’s general partner and to holders of phantom and restricted units under the LTIP, respectively. The Partnership paid distributions totaling $20.0 million during 2015 on the common units for the quarters ending December 31, 2014 , March 31, 2015 , June 30, 2015 and September 30, 2015 . Of the $20.0 million paid during 2015 , approximately $1.1 million and $0.4 million was paid to the Partnership’s general partner and to holders of phantom and restricted units under the LTIP, respectively. The Partnership paid distributions totaling $20.5 million during 2016 on the common units for the quarters ending December 31, 2015 , March 31, 2016 , June 30, 2016 and September 30, 2016 . Of the $20.5 million paid during 2016 , approximately $1.3 million and $0.5 million was paid to the Partnership’s general partner and to holders of phantom and restricted units under the LTIP, respectively. In addition, on January 19, 2017 , the Board declared a cash distribution of $0.1450 per unit on its outstanding common units for the quarter ending December 31, 2016 . The distribution was paid on February 14, 2017 to unitholders of record on February 3, 2017 . The total distribution was approximately $6.0 million , with approximately $5.5 million and $0.4 million paid to the Partnership’s common unitholders and general partner, respectively, and $0.1 million paid to holders of phantom and restricted units pursuant to awards granted under the LTIP.

Major Customers and Concentrati

Major Customers and Concentration of Credit Risk (Notes)	12 Months Ended
	Dec. 31, 2016
Risks and Uncertainties [Abstract]
Concentration Risk Disclosure [Text Block]	MAJOR CUSTOMERS AND CONCENTRATION OF CREDIT RISK For the year ended December 31, 2016 , Ergon accounted for at least 20% but not more than 30% of asphalt terminalling services revenue. Axeon Marketing, LLC, Heartland Asphalt Materials, Inc. and Suncor Energy USA each accounted for at least 10% but not more than 20% of asphalt terminalling services revenue. Vitol accounted for at least 40% but not more than 50% of total crude oil terminalling and storage revenue, and MV Purchasing, LLC and Sunoco Logistics Partners L.P. each accounted for at least 10% but not more than 20% of total crude oil terminalling and storage revenue. CVR Energy, Inc. accounted for at least 40% but not more than 50% of crude oil pipeline services revenue, and Vitol accounted for at least 10% but no more than 20% of crude oil pipeline services revenue in 2016 . MV Purchasing, LLC, Vitol, DCP Midstream, LLC and Regency Energy Partners LP each accounted for at least 10% but not more than 25% of crude oil trucking and producer field services revenue in 2016 . Vitol, Ergon and Ascent Midstream Partners, LLC. each comprised at least 10% but not more than 20% of total accounts receivable at December 31, 2016 . For the year ended December 31, 2015 , Ergon, Heartland Asphalt Materials, Inc., Suncor Energy USA, Axeon Marketing, LLC and Western States Asphalt, Inc. each accounted for at least 10% but not more than 25% of asphalt terminalling services revenue. Vitol accounted for at least 45% but not more than 55% of total crude oil terminalling and storage revenue, and MV Purchasing, LLC and Sunoco Partners Marketing & Terminals, L.P. each accounted for at least 10% but not more than 20% of total crude oil terminalling and storage revenue. Vitol accounted for at least 30% but not more than 40% of crude oil pipeline services revenue, and XTO Energy, Inc. and Valero Marketing & Supply Co. each accounted for at least 10% but no more than 25% of crude oil pipeline services revenue in 2015. Vitol accounted for at least 40% but no more than 50% of crude oil trucking and producer field services revenue, and MV Purchasing, LLC and Devon Energy Production Co. accounted for at least 10% but not more than 25% of crude oil trucking and producer field services revenue in 2015. Vitol and Coffeyville Resources each comprised at least 15% but not more than 25% of total accounts receivable at December 31, 2015. For the year ended December 31, 2014 , Ergon, Heartland Asphalt Materials, Inc., Axeon Marketing, LLC and Suncor Energy USA accounted for at least 10% but not more than 25% of asphalt terminalling services revenue. Vitol accounted for at least 50% but not more than 60% of total crude oil terminalling and storage revenue, and MV Purchasing, LLC accounted for at least 10% but not more than 20% of total crude oil terminalling and storage revenue. Vitol and XTO Energy Inc. each accounted for at least 20% but no more than 30% of crude oil pipeline services revenue in 2014 . Vitol and MV Purchasing, LLC accounted for at least 25% but not more than 40% of crude oil trucking and producer field services revenue in 2014 . Vitol comprised 20% of total accounts receivable at December 31, 2014 . Financial instruments that potentially subject the Partnership to concentrations of credit risk consist principally of trade receivables. The Partnership’s accounts receivable are primarily from producers, purchasers and shippers of crude oil and asphalt product and at times will include Vitol. This industry concentration has the potential to impact the Partnership’s overall exposure to credit risk in that the customers may be similarly affected by changes in economic, industry or other conditions. The Partnership periodically reviews credit exposure and financial information of its counterparties.

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	RELATED PARTY TRANSACTIONS On October 5, 2016, Ergon purchased 100% of the Partnership’s General Partner from Vitol and Charlesbank, resulting in Ergon being classified as a related party and Vitol and Charlesbank no longer being classified as related parties as of October 5, 2016. The Partnership leases facilities to Ergon and provides asphalt product and residual fuel terminalling, storage and blending services to Ergon. For the years ended December 31, 2014 , 2015 and 2016 , the Partnership recognized revenues of $15.8 million , $15.5 million and $22.2 million , respectively, for services provided to Ergon. For the year ended December 31, 2016, $11.0 million is classified as related party revenues, while all other amounts for the respective periods are classified as third party revenue. As of December 31, 2015, and 2016 the Partnership had receivables from Ergon of $0.7 million and $1.7 million , respectively. The Partnership also provides operating and administrative services to Advantage Pipeline. For the years ended December 31, 2014 , 2015 and 2016 , the Partnership recognized revenues of $1.0 million , $1.3 million and $1.3 million , respectively, for services provided to Advantage Pipeline. At December 31, 2015 and 2016, the Partnership had receivables from Advantage Pipeline of less than $0.1 million and $0.1 million , respectively. The Partnership provides crude oil gathering, transportation, terminalling and storage services to Vitol as well as certain operating, strategic assessment, economic evaluation and project design services. For the years ended December 31, 2014 , 2015 and 2016 , the Partnership recognized revenues of $41.8 million , $37.8 million and $17.9 million , respectively, for services provided to Vitol. For the year ended December 31, 2016, $5.3 million is classified as third party revenues, while all other amounts for the respective periods are classified as related party. As of December 31, 2015 , and 2016 the Partnership had receivables, net of allowances for doubtful accounts, from Vitol of $1.8 million and $1.0 million , respectively. Ergon 2016 Storage and Handling Agreement In October 2016, the Partnership and Ergon entered into a storage, throughput and handling agreement (the “Ergon 2016 Storage, Throughput and Handling Agreement”) pursuant to which the Partnership provides Ergon storage and terminalling services at nine asphalt terminal facilities. The term of the Ergon 2016 Storage, Throughput and Handling Agreement commenced on October 5, 2016 and continues for seven years. The Board’s conflicts committee reviewed and approved this agreement in accordance with the Partnership’s procedures for approval of related party transactions and the provisions of the partnership agreement. During the year ended December 31, 2016, the Partnership generated revenue under this agreement of $6.2 million , all of which is classified as related party revenue. Ergon Master Facilities Lease Agreement In May 2009, the Partnership and Ergon entered into a facilities lease agreement and sublease agreements (the “Ergon Master Facilities Lease and Sublease Agreements”) pursuant to which the Partnership leases Ergon certain facilities. The original term of the Ergon Multiple Sites Facilities Lease Agreement commenced on May 18, 2009 for two years, until December 31, 2011. The Ergon Master Facilities Lease has been amended and extended several times and the current term is scheduled to expire on December 31, 2018. The Ergon Master Facilities Lease agreement currently encompasses ten facilities. The Board’s conflicts committee reviewed and approved these agreements in accordance with the Partnership’s procedures for approval of related party transactions and the provisions of the partnership agreement. During the years ended December 31, 2014, 2015 and 2016, the Partnership generated revenues of $10.7 million , $10.5 million and $9.2 million , respectively. Of these amounts, $1.8 million was classified as related party revenue for 2016 while all other amounts are classified as third party revenue for the respective periods. Ergon Master Facilities Sublease and Sublicense Agreement In May 2009, the Partnership and Ergon entered into multiple sublease and sublicense agreements covering six facilities. The original terms of these agreements commenced on May 18, 2009 for two years, until December 31, 2011. In November 2010, these multiple leases were consolidated under one master sublease and sublicense agreement (the “Ergon Master Facilities Sublease and Sublicense Agreement”). This agreement was amended in June 2015 and has a term scheduled to expire on December 31, 2018. During the years ended December 31, 2014 , 2015 and 2016 , the Partnership generated revenues under this agreement of $3.3 million , $3.2 million and $3.6 million , respectively. Of these amounts, $1.0 million was classified as related party for 2016 while all other amounts are classified as third party for the respective periods. Vitol Storage Agreements In recent years, a significant portion of the Partnership’s crude oil storage capacity has been dedicated to Vitol under multiple agreements. As of December 31, 2014 , 2015 and 2016 , 3.1 million barrels, 2.2 million barrels and 2.2 million barrels of storage capacity, respectively, were dedicated to Vitol under these storage agreements. Service revenues under these agreements are based on the barrels of storage capacity dedicated to Vitol under the applicable agreement at rates that, the Partnership believes, are fair and reasonable to the Partnership and its unitholders and are comparable with the rates the Partnership charges third parties. The Board’s conflicts committee reviewed and approved these agreements in accordance with the Partnership’s procedures for approval of related party transactions and the provisions of the partnership agreement. The Partnership generated revenues under these agreements of approximately $12.0 million , $9.4 million and $9.6 million for the years ended December 31, 2014 , 2015 and 2016 , respectively. Of this amount, $2.1 million was classified as third party revenue for 2016 while all other amounts are classified as related party revenue for the respective periods. As of March 2, 2017 , 2.2 million barrels of storage capacity were dedicated to Vitol under the crude oil storage agreement with the current term scheduled to expire on May 1, 2018. Vitol Operating and Maintenance Agreement In August 2011, the Partnership and Vitol entered into an operating and maintenance agreement (the “Vitol O&M Agreement”) relating to the operation and maintenance of Vitol’s crude oil terminal located in Midland, Texas (the “Midland Terminal”) and Vitol’s crude oil gathering system located near Midland, Texas (the “Midland Gathering System”). Pursuant to the Vitol O&M Agreement, the Partnership provides certain operating and maintenance services with respect to the Midland Terminal and Midland Gathering System. The five year term of the Vitol O&M Agreement commenced on September 1, 2012. During the years ended December 31, 2014 and 2015 , the Partnership generated revenues of $1.6 million and $2.5 million , respectively, under the Vitol O&M Agreement. The Vitol O&M Agreement was terminated in July 2015. Revenues for the year ended December 31, 2015 include a termination fee of $1.2 million and transition services fees of $0.1 million . The Partnership believes that the rates it charged Vitol under the Vitol O&M Agreement were fair and reasonable to the Partnership and its unitholders and were comparable with the rates the Partnership charges third parties. The Board’s conflicts committee reviewed and approved the Vitol O&M Agreement in accordance with the Partnership’s procedures for approval of related party transactions and the provisions of the partnership agreement. Vitol Shared Services Agreement In August 2012, the Partnership and Vitol entered into a shared services agreement (the “Vitol Shared Services Agreement”) pursuant to which the Partnership provides Vitol certain strategic assessment, economic evaluation and project design services. The original term of the Vitol Shared Services Agreement commenced on August 1, 2012 and continued for one year. In August 2013, the term of the Vitol Shared Services Agreement was automatically renewed for one year. The Vitol Shared Services Agreement was terminated in March 2015. During the years ended December 31, 2014 and 2015 , the Partnership generated revenues of $0.1 million and less than $0.1 million , respectively, under the Vitol Shared Services Agreement. The Partnership believes that the rates it charged Vitol under the Vitol Shared Services Agreement are fair and reasonable to the Partnership and its unitholders. The Board’s conflicts committee reviewed and approved the Vitol Shared Services Agreement in accordance with the Partnership’s procedures for approval of related party transactions and the provisions of the partnership agreement. Advantage Pipeline Operating and Administrative Services Agreement In January 2013, the Partnership and Advantage Pipeline entered into an operating and administrative services agreement (the “Advantage O&A Services Agreement”) pursuant to which the Partnership operates Advantage Pipeline’s Pecos River Pipeline in west Texas. Under the Advantage O&A Services Agreement, the Partnership provides certain administrative services to Advantage Pipeline. The initial term of the Advantage O&A Services Agreement commenced on January 31, 2013 with an initial term of ten years, with the Partnership and Advantage Pipeline each having an option to extend the term for an additional five years. On February 12, 2017, Advantage Pipeline entered into a definitive agreement whereby Advantage Pipeline will be acquired by a JV formed by PAA and Noble Midstream Partners LP. After a brief transition period, the Advantage O&A Services Agreement will be terminated. See Note 4 for additional information. During each of the years ended December 31, 2014 , 2015 and 2016 , the Partnership earned revenues of $0.5 million under this agreement.

LONG-TERM INCENTIVE PLAN

LONG-TERM INCENTIVE PLAN	12 Months Ended
	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
LONG-TERM INCENTIVE PLAN	LONG-TERM INCENTIVE PLAN In July 2007, the General Partner adopted the LTIP. The compensation committee of the Board administers the LTIP. Effective April 29, 2014, the Partnership’s unitholders approved an amendment to the LTIP to increase the number of common units reserved for issuance under the incentive plan to 4.1 million common units, subject to adjustment for certain events. Although other types of awards are contemplated under the LTIP, currently outstanding awards include “phantom” units, which convey the right to receive common units upon vesting, and “restricted” units, which are grants of common units restricted until the time of vesting. Certain of the phantom unit awards also include DERs. Subject to applicable earning criteria, a DER entitles the grantee to a cash payment equal to the cash distribution paid on an outstanding common unit prior to the vesting date of the underlying award. Recipients of restricted units are entitled to receive cash distributions paid on common units during the vesting period which distributions are reflected initially as a reduction of partners’ capital. Distributions paid on units which ultimately do not vest are reclassified as compensation expense. Awards granted to date are equity awards and, accordingly, the fair value of the awards as of the grant date is expensed over the vesting period. In connection with each anniversary of joining the Board, restricted common units are granted to the independent directors. The units vest in one-third increments over three years. The following table includes information on grants made to the directors under the LTIP: Grant Date Number of Units Weighted Average Grant Date Fair Value Grant Date Total Fair Value (in thousands) December 2014 7,500 $ 6.43 $ 48 December 2015 15,120 5.06 77 December 2016 10,950 6.85 75 Additionally, in December 2016 , 10,220 common units were granted that have no vesting requirements. This grant was made as part of the independent directors’ compensation. The fair value of this grant was $0.1 million . In October 2016, all of the independent directors’ remaining unvested 2014 and 2015 units vested due to the Ergon Change of Control. The Partnership recorded compensation cost of $0.1 million during the year ended December 31, 2016 related to this early vesting. The Partnership also grants phantom units to employees. These grants are equity awards under ASC 718 – Stock Compensation , and, accordingly, the fair value of the awards as of the grant date is expensed over the vesting period. The following table includes information on the outstanding grants: Grant Date Number of Units Weighted Average Grant Date Fair Value Grant Date Total Fair Value (in thousands) March 2014 276,773 $ 9.06 $ 2,508 March 2015 266,076 7.74 2,059 March 2016 416,131 4.77 1,985 October 2016 9,960 5.85 58 The unrecognized estimated compensation cost of outstanding phantom units at December 31, 2016 was $1.8 million , which will be recognized over the remaining vesting period. On January 1, 2017, 213,923 units of the March 2014 grant vested. In September 2012 , Mark Hurley was granted 500,000 phantom units under the LTIP upon his employment as the Chief Executive Officer of the General Partner. These grants are equity awards under ASC 718 – Stock Compensation , and, accordingly, the fair value of the awards as of the grant date is expensed over the vesting period. These units vest ratably over five years pursuant to the Employee Phantom Unit Agreement between Mr. Hurley and the General Partner and do not include DERs. The weighted average grant date fair value for the units of $5.62 was determined based on the closing market price of the Partnership’s common units on the grant date of the award, less the present value of the estimated distributions to be paid to holders of an outstanding common unit prior to the vesting of the underlying award. The value of this award grant was approximately $2.8 million on the grant date, and the unrecognized estimated compensation cost at December 31, 2016 was $0.4 million and will be expensed over the remaining vesting period. The Partnership’s equity-based incentive compensation expense for the years ended December 31, 2014 , 2015 and 2016 was $2.3 million , $2.7 million and $2.5 million , respectively. Activity pertaining to phantom common units and restricted common unit awards granted under the LTIP is as follows: Number of Units Weighted Average Grant Date Fair Value Nonvested at December 31, 2015 915,541 $ 7.81 Granted 447,261 4.89 Vested 347,193 7.55 Forfeited 100,429 6.72 Nonvested at December 31, 2016 915,180 $ 6.61

EMPLOYEE BENEFIT PLAN

EMPLOYEE BENEFIT PLAN	12 Months Ended
	Dec. 31, 2016
Compensation and Retirement Disclosure [Abstract]
EMPLOYEE BENEFIT PLAN	EMPLOYEE BENEFIT PLAN Under the Partnership’s 401(k) Plan, which was instituted in 2009 , employees who meet specified service requirements may contribute a percentage of their total compensation, up to a specified maximum, to the 401(k) Plan. The Partnership may match each employee’s contribution, up to a specified maximum, in full or on a partial basis. The Partnership recognized expense of $1.5 million for both of the years ended December 31, 2014 and 2015 , and $1.2 million for the year ended December 31, 2016 for discretionary contributions under the 401(k) Plan. The Partnership may also make annual lump-sum contributions to the 401(k) Plan irrespective of the employee’s contribution match. The Partnership may make a discretionary annual contribution in the form of profit sharing calculated as a percentage of an employee’s eligible compensation. This contribution is retirement income under the qualified 401(k) Plan. Annual profit sharing contributions to the 401(k) Plan are submitted to and approved by the Board. The Partnership recognized expense of $0.9 million for each of the years ended December 31, 2014 and 2015 , and $0.8 million for the year ended December 31, 2016 , for discretionary profit sharing contributions under the 401(k) Plan.

PROFITS INTEREST OF BLUEKNIGHT

PROFITS INTEREST OF BLUEKNIGHT GP HOLDING, LLC (Notes)	12 Months Ended
	Dec. 31, 2016
PROFITS INTEREST OF BLUEKNIGHT GP HOLDING, LLC [Abstract]
Profits Interest Of Parent Company [Text Block]	PROFITS INTEREST OF BLUEKNIGHT GP HOLDING, LLC In October 2012, the owners of Blueknight GP Holding, LLC (“HoldCo”), the owner of the General Partner, admitted Mr. Hurley as a member of HoldCo. In connection with his admission as a member of HoldCo, Mr. Hurley was issued a non-voting economic interest in HoldCo (the “Profits Interest”). Upon the Ergon Change of Control, Vitol and Charlesbank, the previous owners of HoldCo, repurchased and canceled the Profits Interest. Although the entire economic burden of the Profits Interest, which was equity classified, was borne solely by HoldCo and did not impact the Partnership’s cash or units outstanding, the intent of the Profits Interest was to provide a performance incentive and encourage retention of Mr. Hurley. Therefore, the Partnership recognized the grant date fair value of the Profits Interest as compensation expense over the service period and the repurchase of the Profits Interest in the period paid. The expense is also reflected as a capital contribution and thus, results in a corresponding credit to Partners’ Capital in the Partnership’s Consolidated Financial Statements. The Partnership recognized expense of $0.1 million in relation to the Profits Interest for each of years ended December 31, 2014 and 2015 , and $0.9 million for the year ended December 31, 2016 .

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
COMMITMENT AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES The Partnership leases certain real property, equipment and operating facilities under various operating and capital leases. It also incurs costs associated with leased land, rights-of-way, permits and regulatory fees, the contracts for which generally extend beyond one year but can be cancelled at any time should they not be required for operations. Future non-cancellable commitments related to these items at December 31, 2016 , are summarized below (in thousands): Operating Leases For years ending: December 31, 2017 $ 5,087 December 31, 2018 4,307 December 31, 2019 3,042 December 31, 2020 1,494 December 31, 2021 746 Thereafter 1,630 Total future minimum lease payments $ 16,306 Rental expense related to operating leases was $8.4 million , $9.5 million and $6.5 million for each of the years ended December 31, 2014 , 2015 and 2016 , respectively. The Partnership is from time to time subject to various legal actions and claims incidental to its business. Management believes that these legal proceedings will not have a material adverse effect on the financial position, results of operations or cash flows of the Partnership. Once management determines that information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred and the amount of such liability can be reasonably estimated, an accrual is established equal to its estimate of the likely exposure. The Partnership may become the subject of additional private or government actions regarding these matters in the future. Litigation may be time-consuming, expensive and disruptive to normal business operations, and the outcome of litigation is difficult to predict. The defense of these lawsuits may result in the incurrence of significant legal expense, both directly and as the result of the Partnership’s indemnification obligations. The litigation may also divert management’s attention from the Partnership’s operations which may cause its business to suffer. An unfavorable outcome in any of these matters may have a material adverse effect on the Partnership’s business, financial condition, results of operations, cash flows, ability to make distributions to its unitholders, the trading price of the Partnership’s common units and its ability to conduct its business. All or a portion of the defense costs and any amount the Partnership may be required to pay to satisfy a judgment or settlement of these claims may or may not be covered by insurance. The Partnership has contractual obligations to perform dismantlement and removal activities in the event that some of its asphalt product and residual fuel oil terminalling and storage assets are abandoned. These obligations include varying levels of activity including completely removing the assets and returning the land to its original state. The Partnership has determined that the settlement dates related to the retirement obligations are indeterminate. The assets with indeterminate settlement dates have been in existence for many years and with regular maintenance will continue to be in service for many years to come. Also, it is not possible to predict when demands for the Partnership’s terminalling and storage services will cease, and the Partnership does not believe that such demand will cease for the foreseeable future. Accordingly, the Partnership believes the date when these assets will be abandoned is indeterminate. With no reasonably determinable abandonment date, the Partnership cannot reasonably estimate the fair value of the associated asset retirement obligations. Management believes that if the Partnership’s asset retirement obligations were settled in the foreseeable future the potential cash flows that would be required to settle the obligations based on current costs are not material. The Partnership will record asset retirement obligations for these assets in the period in which sufficient information becomes available for it to reasonably determine the settlement dates.

ENVIRONMENTAL REMEDIATION (Note

ENVIRONMENTAL REMEDIATION (Notes)	12 Months Ended
	Dec. 31, 2016
Accrual for Environmental Loss Contingencies Disclosure [Abstract]
Environmental Loss Contingency Disclosure [Text Block]	ENVIRONMENTAL REMEDIATION The Partnership maintains insurance of various types with varying levels of coverage that it considers adequate under the circumstances to cover its operations and properties. The insurance policies are subject to deductibles and retention levels that the Partnership considers reasonable and not excessive. Consistent with insurance coverage generally available in the industry, in certain circumstances the Partnership’s insurance policies provide limited coverage for losses or liabilities relating to gradual pollution, with broader coverage for sudden and accidental occurrences. Although the Partnership maintains a program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to environmental releases from its assets may substantially affect its business. At December 31, 2015 and 2016 , the Partnership was aware of existing conditions that may cause it to incur expenditures in the future for the remediation of existing environmental matters. The Partnership recorded loss contingencies related to environmental matters of less than $0.1 million as of December 31, 2015 , and had no such loss contingencies as of December 31, 2016 . Changes in the Partnership’s estimates and assumptions may occur as a result of the passage of time and the occurrence of future events.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	FAIR VALUE MEASUREMENTS The Partnership utilizes a three-tier framework for assets and liabilities required to be measured at fair value. In addition, the Partnership uses valuation techniques, such as the market approach (comparable market prices), the income approach (present value of future income or cash flow), and the cost approach (cost to replace the service capacity of an asset or replacement cost) to value these assets and liabilities as appropriate. The Partnership uses an exit price when determining the fair value. The exit price represents amounts that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The Partnership utilizes a three-tier fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three broad levels. The following is a brief description of those three levels: Level 1 Observable inputs such as quoted prices (unadjusted) in active markets for identical assets or liabilities. Level 2 Inputs other than quoted prices that are observable for these assets or liabilities, either directly or indirectly. These include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active. Level 3 Unobservable inputs in which there is little market data, which requires the reporting entity to develop its own assumptions. This hierarchy requires the use of observable market data, when available, to minimize the use of unobservable inputs when determining fair value. In periods in which they occur, the Partnership recognizes transfers into and out of Level 3 as of the end of the reporting period. Transfers out of Level 3 represent existing assets and liabilities that were classified previously as Level 3 for which the observable inputs became a more significant portion of the fair value estimates. Determining the appropriate classification of the Partnership’s fair value measurements within the fair value hierarchy requires management’s judgment regarding the degree to which market data is observable or corroborated by observable market data. The Partnership’s recurring financial assets and liabilities subject to fair value measurements and the necessary disclosures are as follows (in thousands): Fair Value Measurements as of December 31, 2015 Description Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Liabilities: Interest rate swap liabilities $ 3,103 $ — $ 3,103 $ — Total $ 3,103 $ — $ 3,103 $ — Fair Value Measurements as of December 31, 2016 Description Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Liabilities: Interest rate swap liabilities $ 1,947 $ — $ 1,947 $ — Total $ 1,947 $ — $ 1,947 $ — Fair Value of Other Financial Instruments The following disclosure of the estimated fair value of financial instruments is made in accordance with accounting guidance for financial instruments. The Partnership has determined the estimated fair values by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts. At December 31, 2016 , the carrying values on the consolidated balance sheets for cash and cash equivalents (classified as Level 1), accounts receivable and accounts payable approximate their fair value because of their short term nature. Based on the borrowing rates currently available to the Partnership for credit agreement debt with similar terms and maturities and consideration of the Partnership’s non-performance risk, long-term debt associated with the Partnership’s credit agreement at December 31, 2016 approximates its fair value. The fair value of the Partnership’s long-term debt was calculated using observable inputs (LIBOR for the risk free component) and unobservable company-specific credit spread information. As such, the Partnership considers this debt to be Level 3.

OPERATING SEGMENTS

OPERATING SEGMENTS	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
OPERATING SEGMENTS	OPERATING SEGMENTS The Partnership’s operations consist of four operating segments: (i) asphalt terminalling services, (ii) crude oil terminalling and storage services, (iii) crude oil pipeline services and (iv) crude oil trucking and producer field services. ASPHALT TERMINALLING SERVICES —The Partnership provides asphalt product and residual fuel terminalling, storage and blending services at its 54 terminalling and storage facilities located in 26 states. CRUDE OIL TERMINALLING AND STORAGE SERVICES —The Partnership provides crude oil terminalling and storage services at its terminalling and storage facilities located in Oklahoma and Texas. CRUDE OIL PIPELINE SERVICES —The Partnership owns and operates two pipeline systems, the Mid-Continent system which includes the Eagle North system, and the East Texas system, that gather crude oil purchased by its customers and transports it to refiners, to common carrier pipelines for ultimate delivery to refiners or to terminalling and storage facilities owned by the Partnership and others. The Partnership refers to its pipeline system located in Oklahoma and the Texas Panhandle as the Mid-Continent system. The Mid-Continents system also includes the Eagle North system that originates in Cushing, Oklahoma and terminates in Ardmore, Oklahoma. It refers to its second pipeline system, which is located in Texas, as the East Texas system. Crude oil marketing revenues consist of sales proceeds recognized for the sale of crude oil to third party customers. Revenue for the sale of crude oil is recognized when title to the crude oil transfers to the customer and is based on contractual prices for the sale of crude oil. CRUDE OIL TRUCKING AND PRODUCER FIELD SERVICES — The Partnership uses its owned and leased tanker trucks to gather crude oil for its customers at remote wellhead locations generally not covered by pipeline and gathering systems and to transport the crude oil to aggregation points and storage facilities located along pipeline gathering and transportation systems. Crude oil producer field services consist of a number of producer field services, ranging from gathering condensates from natural gas companies to hauling produced water to disposal wells. The Partnership’s management evaluates performance based upon segment operating margin, which includes revenues from related parties and external customers and operating expenses excluding depreciation and amortization. The non-GAAP measure of operating margin (in the aggregate and by segment) is presented in the following table. The Partnership computes the components of operating margin by using amounts that are determined in accordance with GAAP. A reconciliation of operating margin to income before income taxes, which is its nearest comparable GAAP financial measure, is included in the following table. The Partnership believes that investors benefit from having access to the same financial measures being utilized by management. Operating margin is an important measure of the economic performance of the Partnership’s core operations. This measure forms the basis of the Partnership’s internal financial reporting and is used by its management in deciding how to allocate capital resources among segments. Income before income taxes, alternatively, includes expense items, such as depreciation and amortization, general and administrative expenses and interest expense, which management does not consider when evaluating the core profitability of the Partnership’s operations. The following table reflects certain financial data for each segment for the periods indicated (in thousands): For the year ended December 31, 2014 2015 2016 Asphalt Terminalling Services Service revenue Third party revenue $ 66,273 $ 72,152 $ 75,655 Related party revenue 1,119 1,278 11,762 Total revenue for reportable segments 67,392 73,430 87,417 Operating expense (excluding depreciation and amortization) 26,148 25,218 30,648 Operating margin (excluding depreciation and amortization) 41,244 48,212 56,769 Additions to long-lived assets 6,766 19,769 148,622 Total assets (end of period) $ 92,628 $ 98,848 $ 141,280 Crude Oil Terminalling and Storage Services Service revenue Third party revenue $ 9,258 $ 13,076 $ 16,387 Related party revenue 13,524 11,522 7,858 Total revenue for reportable segments 22,782 24,598 24,245 Operating expense (excluding depreciation and amortization) 3,964 5,756 4,197 Operating margin (excluding depreciation and amortization) 18,818 18,842 20,048 Additions to long-lived assets 8,551 3,282 2,126 Total assets (end of period) $ 69,469 $ 73,502 $ 71,689 Crude Oil Pipeline Services Service revenue Third party revenue $ 13,834 $ 15,148 $ 8,662 Related party revenue 8,381 10,687 5,433 Product sales revenue Third party revenue 4,190 3,511 20,968 Total revenue for reportable segments 26,405 29,346 35,063 Operating expense (excluding depreciation and amortization) 15,948 18,162 15,270 Operating expense (intersegment) — 259 890 Cost of product sales — 3,231 14,130 Cost of product sales (intersegment) — — 426 Operating margin (excluding depreciation and amortization) 10,457 7,694 4,347 Additions to long-lived assets 20,970 34,953 8,250 Total assets (end of period) $ 184,933 $ 175,142 $ 150,043 Crude Oil Trucking and Producer Field Services Service revenue Third party revenue $ 50,061 $ 37,039 $ 25,511 Related party revenue 19,764 15,616 5,158 Intersegment revenue — 259 890 Product sales revenue Third party revenue 222 — — Intersegment revenue — — 426 For the year ended December 31, 2014 2015 2016 Total revenue for reportable segments 70,047 52,914 31,985 Operating expense (excluding depreciation and amortization) 62,140 51,610 30,156 Operating margin (excluding depreciation and amortization) 7,907 1,304 1,829 Additions to long-lived assets 1,081 4,556 2,558 Total assets (end of period) $ 17,365 $ 17,256 $ 12,651 Total operating margin (excluding depreciation and amortization) (1) $ 78,426 $ 76,052 $ 82,993 Total Segment Revenues 186,626 180,288 178,710 Elimination of Intersegment Revenues — (259 ) (1,316 ) Consolidated Revenues 186,626 180,029 177,394 ____________________ (1) The following table reconciles segment operating margin (excluding depreciation and amortization) to income (loss) before income taxes (in thousands): For the year ended December 31, 2014 2015 2016 Operating margin (excluding depreciation and amortization) $ 78,426 $ 76,052 $ 82,993 Depreciation and amortization (26,045 ) (27,228 ) (30,820 ) General and administrative expenses (17,498 ) (18,976 ) (20,029 ) Asset impairment expense — (21,996 ) (25,761 ) Gain on sale of assets 2,464 6,137 108 Equity earnings in unconsolidated entity 883 3,932 1,483 Interest expense (12,268 ) (11,202 ) (12,554 ) Unrealized gains on investments 2,079 — — Income (loss) before income taxes $ 28,041 $ 6,719 $ (4,580 )

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES The anticipated after-tax economic benefit of an investment in the Partnership’s common units depends largely on the Partnership being treated as a partnership for federal income tax purposes. If less than 90% of the gross income of a publicly traded partnership, such as the Partnership, for any taxable year is “qualifying income” from sources such as the transportation, marketing (other than to end users), or processing of crude oil, natural gas or products thereof, interest, dividends or similar sources, that partnership will be taxable as a corporation under Section 7704 of the Internal Revenue Code for federal income tax purposes for that taxable year and all subsequent years. If the Partnership were treated as a corporation for federal income tax purposes, then it would pay federal income tax on its income at the corporate tax rate, which is currently a maximum of 35% , and would likely pay state income tax at varying rates. Distributions would generally be taxed again to unitholders as corporate distributions and none of the Partnership’s income, gains, losses, deductions or credits would flow through to its unitholders. Because a tax would be imposed upon the Partnership as an entity, cash available for distribution to its unitholders would be substantially reduced. Treatment of the Partnership as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to unitholders and thus would likely result in a substantial reduction in the value of the Partnership’s common units. The Partnership has entered into storage contracts and leases with third party customers with respect to substantially all of its asphalt facilities. At the time of entering into such agreements, it was unclear under current tax law as to whether the rental income from the leases, and the fees attributable to certain of the processing services the Partnership provides under certain of the storage contracts, constitute “qualifying income.” In the second quarter of 2009, the Partnership submitted a request for a ruling from the IRS that rental income from the leases constitutes “qualifying income.” In October 2009, the Partnership received a favorable ruling from the IRS. As part of this ruling, however, the Partnership agreed to transfer, and has transferred, certain of its asphalt processing assets and related fee income to a subsidiary taxed as a corporation. This transfer occurred in the first quarter of 2010. Such subsidiary is required to pay federal income tax on its income at the corporate tax rate, which is currently a maximum of 35% , and will likely pay state (and possibly local) income tax at varying rates. Distributions from this subsidiary will generally be taxed again to unitholders as corporate distributions and none of the income, gains, losses, deductions or credits of this subsidiary will flow through to the Partnership’s unitholders. In relation to the Partnership’s taxable subsidiary, the tax effects of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts at December 31, 2016 are presented below (dollars in thousands): Deferred tax assets Difference in bases of property, plant and equipment $ 844 Deferred tax asset 844 Less: valuation allowance (844 ) Net deferred tax asset $ — The Partnership has considered the taxable income projections in future years, whether the carryforward period is so brief that it would limit realization of tax benefits, whether future revenue and operating cost projections will produce enough taxable income to realize the deferred tax asset based on existing service rates and cost structures, and the Partnership’s earnings history exclusive of the loss that created the future deductible amount for the Partnership’s subsidiary that is taxed as a corporation for purposes of determining the likelihood of realizing the benefits of the deferred tax assets. As a result of the Partnership’s consideration of these factors, the Partnership has provided a full valuation allowance against its deferred tax asset as of December 31, 2016 .

RECENTLY ISSUED ACCOUNTING STAN

RECENTLY ISSUED ACCOUNTING STANDARDS	12 Months Ended
	Dec. 31, 2016
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
RECENTLY ISSUED ACCOUNTING STANDARDS	RECENTLY ISSUED ACCOUNTING STANDARDS In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers.” The amendments in this update create Topic 606, Revenue from Contracts with Customers, and supersede the revenue recognition requirements in Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the Industry Topics of the Codification. In addition, the amendments supersede the cost guidance in Subtopic 605-35, Revenue Recognition-Construction-Type and Production-Type Contracts, and create new Subtopic 340-40, Other Assets and Deferred Costs-Contracts with Customers. In summary, the core principle of Topic 606 is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Throughout 2015 and 2016, the FASB has issued a series of subsequent updates to the revenue recognition guidance in Topic 606, including ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients, and ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. The amendments in ASU 2014-09, ASU 2016-08, ASU 2016-10, ASU 2016-12, and ASU 2016-20 are effective for public entities for annual reporting periods beginning after December 15, 2017, and for interim periods within that reporting period. Early application is permitted for annual reporting periods beginning after December 15, 2016. We are evaluating the impact of this standard on us, which will be adopted beginning with the Partnership’s quarterly report for the period ending March 31, 2018. Our evaluation process includes a review of our contracts and transaction types across all of the business segments. In addition, we are currently evaluating the methods of adoption and analyzing the impact of the standard on our internal controls, accounting policies and financial statements and disclosures. In August 2014, the FASB issued ASU 2014-15, “Presentation of Financial Statements - Going Concern.” The Update provides U.S. GAAP guidance on management’s responsibility in evaluating whether there is substantial doubt about a company’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, management will be required to evaluate whether there are conditions or events that raise substantial doubt about a company’s ability to continue as a going concern within one year from the date the financial statements are issued. The amendments in this update are effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. The Partnership adopted this update for the period ending December 30, 2016, and there was no impact on the Partnership’s financial position, results of operations or cash flows. In January 2015, the FASB issued ASU 2015-01, “Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items.” The objective of this Update is to simplify the income statement presentation requirements by eliminating the concept of extraordinary items. Extraordinary items are events and transactions that are distinguished by their unusual nature and by the infrequency of their occurrence. Eliminating the extraordinary classification simplifies income statement presentation by altogether removing the concept of extraordinary items from consideration. The amendments in this update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2015. The Partnership adopted this update in the three month period ending March 31, 2016, and there was no impact on the Partnership’s financial position, results of operations or cash flow. In February 2015, the FASB issued ASU 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis,” which eliminates the presumption that a general partner should consolidate a limited partnership. It also modifies the evaluation of whether limited partnerships are variable interest entities or voting interest entities and adds requirements that limited partnerships must meet to qualify as voting interest entities. This guidance is effective for public companies for fiscal years beginning after December 15, 2015. The Partnership adopted this update in the three month period ending March 31, 2016, and there was no material impact on the Partnership’s financial position, results of operations or cash flow. On April 7, 2015, the FASB issued ASU 2015-03, “Simplifying the Presentation of Debt Issuance Costs,” which requires debt issuance costs to be presented in the balance sheet as a direct deduction from the associated debt liability. This update is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The Partnership adopted this update for the period ending March 31, 2016, and there was no material impact on the Partnership’s financial position, results of operations or cash flow. On April 30, 2015, the FASB issued ASU 2015-06, “Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions.” Master limited partnerships (MLPs) apply the two-class method to calculate earnings per unit (EPU) because the general partner, limited partners, and incentive distribution rights holders each participate differently in the distribution of available cash. When a general partner transfers (or “drops down”) net assets to a master limited partnership and that transaction is accounted for as a transaction between entities under common control, the statements of operations of the master limited partnership are adjusted retrospectively to reflect the dropdown transaction as if it occurred on the earliest date during which the entities were under common control. The amendments in ASU 2015-06 specify that for purposes of calculating historical EPU under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner interest, and previously reported EPU of the limited partners would not change as a result of a dropdown transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs also are required. This update is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The Partnership adopted this update in the three month period ending March 31, 2016, and there was no material impact on the Partnership’s financial position, results of operations or cash flow. In September 2015, the FASB issued ASU 2015-16, “Business Combinations (Topic 805).” Topic 805 requires that an acquirer retrospectively adjust provisional amounts recognized in a business combination, during the measurement period. To simplify the accounting for adjustments made to provisional amounts, the amendments in this update require that the acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amount is determined. The acquirer is required to also record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. In addition, an entity is required to present separately on the face of the income statement or disclose in the notes to the financial statements the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. This update is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The Partnership adopted this update in the three month period ending March 31, 2016, and there was no material impact on the Partnership’s financial position, results of operations or cash flow. In November 2015, the FASB issued ASU 2015-17, “Income Taxes (Topic 740).” This update simplifies the presentation of deferred income taxes on the balance sheet. This update is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those fiscal years. The Partnership has evaluated the impact of this guidance, which will be adopted beginning with the Partnership’s quarterly report for the period ending March 31, 2017, and does not anticipate a material impact on the Partnership’s financial position, results of operations or cash flows. In January 2016, the FASB issued ASU 2016-01, “Financial Instruments - Overall (Subtopic 825-10).” This update is intended to enhance the reporting model for financial instruments to provide users of financial statements with more decision-useful information. The amendments in the update address certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. This update is effective for financial statements issued for annual periods beginning after December 15, 2017, and interim periods within those fiscal years. The Partnership is evaluating the impact of this guidance, which will be adopted beginning with the Partnership’s quarterly report for the period ending March 31, 2018. In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” This update introduces a new lease model that requires the recognition of lease assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements. This update is effective for financial statements issued for annual periods beginning after December 15, 2018, and interim periods within those fiscal years. The Partnership is evaluating the impact of this guidance, which will be adopted beginning with the Partnership’s quarterly report for the period ending March 31, 2019. In March 2016, the FASB issued ASU 2016-09, “Compensation - Stock Compensation (Topic 718).” This update is intended to simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This update is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those fiscal years. The Partnership has evaluated the impact of this guidance, which will be adopted beginning with the Partnership’s quarterly report for the period ending March 31, 2017, and does not anticipate a material impact on the Partnership’s financial position, results of operations or cash flows. In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.” This update addresses the following eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies (COLIs) (including bank-owned life insurance policies (BOLIs)); distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. This update is effective for financial statements issued for annual periods beginning after December 15, 2017, and interim periods within those fiscal years. The Partnership is evaluating the impact of this guidance, which will be adopted beginning with the Partnership’s quarterly report for the period ending March 31, 2018. In October 2016, the FASB issued ASU 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory.” This update is intended to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. The amendments in the Update eliminates the prohibition of recognizing current and deferred income taxes for an intra-entity asset transfer other than inventory until the asset has been sold to an outside party. This update is effective for financial statements issued for annual periods beginning after December 15, 2017, and interim periods within those fiscal years. The Partnership is evaluating the impact of this guidance, which will be adopted beginning with the Partnership’s quarterly report for the period ending March 31, 2018. In November 2016, the FASB issued ASU 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash (a Consenus of the FASB Emerging Issues Task Force.” This update requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents . This update is effective for financial statements issued for annual periods beginning after December 15, 2017, and interim periods within those fiscal years. The Partnership is evaluating the impact of this guidance, which will be adopted beginning with the Partnership’s quarterly report for the period ending March 31, 2018. In January 2017, the FASB issued ASU 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business.” This update clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This update is effective for financial statements issued for annual periods beginning after December 15, 2017, and interim periods within those fiscal years. The Partnership is evaluating the impact of this guidance, which will be adopted beginning with the Partnership’s quarterly report for the period ending March 31, 2018. In January 2017, the FASB issued ASU 2017-04, “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” This update simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. This update is effective for financial statements issued for annual periods beginning after December 15, 2019, and interim periods within those fiscal years. The Partnership is evaluating the impact of this guidance, which will be adopted beginning with the Partnership’s quarterly report for the period ending March 31, 2020.

QUARTERLY FINANCIAL DATA (Notes

QUARTERLY FINANCIAL DATA (Notes)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Data [Abstract]
Quarterly Financial Information [Text Block]	QUARTERLY FINANCIAL DATA (UNAUDITED) Summarized quarterly financial data is as follows (in thousands, except per unit data): First Quarter Second Quarter Third Quarter Fourth Quarter Full Year 2015: Revenues $ 42,356 $ 46,574 $ 47,217 $ 43,882 $ 180,029 Operating income (loss) 5,297 8,484 17,010 (16,802 ) 13,989 Net income (loss) 1,579 7,710 13,967 (16,860 ) 6,396 Basic net income (loss) per common unit (0.12 ) 0.06 0.24 (0.65 ) (0.47 ) Diluted net income (loss) per common unit (0.12 ) 0.06 0.21 (0.65 ) (0.47 ) 2016: Revenues $ 41,009 $ 43,425 $ 46,939 $ 46,021 $ 177,394 Operating income (loss) 5,013 (15,348 ) 13,398 3,428 6,491 Net income (loss) 726 (18,936 ) 11,419 1,951 (4,840 ) Basic net income (loss) per common unit (0.14 ) (0.71 ) 0.13 (0.18 ) (0.87 ) Diluted net income (loss) per common unit (0.14 ) (0.71 ) 0.13 (0.18 ) (0.87 )

SUMMARY OF SIGNIFICANT ACCOUN31

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Use of Estimates, Policy [Policy Text Block]	USE OF ESTIMATES - The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts and disclosure of contingencies. Management makes significant estimates including: (1) allowance for doubtful accounts receivable; (2) estimated useful lives of assets, which impacts depreciation; (3) estimated cash flows and fair values inherent in impairment tests; (4) accruals related to revenues and expenses; (5) the estimated fair value of financial instruments; and (6) liability and contingency accruals. Although management believes these estimates are reasonable, actual results could differ from these estimates.
Cash and Cash Equivalents, Policy [Policy Text Block]	CASH AND CASH EQUIVALENTS - The Partnership includes as cash and cash equivalents, cash and all investments with original maturities of three months or less which are readily convertible into known amounts of cash.
Trade and Other Accounts Receivable, Policy [Policy Text Block]	ACCOUNTS RECEIVABLE - The majority of the Partnership’s accounts receivable relates to its trucking and producer field services and asphalt terminalling services activities. Accounts receivable included in the consolidated balance sheets are reflected net of the allowance for doubtful accounts of less than $0.1 million at both December 31, 2015 and 2016 . The Partnership reviews all outstanding accounts receivable balances on a monthly basis and records a reserve for amounts that the Partnership expects will not be fully recovered. Although the Partnership considers its allowance for doubtful trade accounts receivable to be adequate, there is no assurance that actual amounts will not vary significantly from estimated amounts.
Property, Plant and Equipment, Policy [Policy Text Block]	PROPERTY, PLANT AND EQUIPMENT - Property, plant and equipment are recorded at cost. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred. The carrying value of the assets is based on estimates, assumptions and judgments relative to useful lives and salvage values. As assets are disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is included in consolidated operating income in the consolidated statements of operations. Depreciation is calculated using the straight-line method, based on estimated useful lives of the assets. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions and supply and demand in the area. When assets are put into service, management makes estimates with respect to useful lives and salvage values that it believes are reasonable. However, subsequent events could cause management to change its estimates, thus impacting the future calculation of depreciation. The Partnership has contractual obligations to perform dismantlement and removal activities in the event that some of its asphalt product and residual fuel oil terminalling and storage assets are abandoned (see Note 16 ). Such obligations are recognized in the period incurred if reasonably estimable.
Impairment or Disposal of Long-Lived Assets, Including Intangible Assets, Policy [Policy Text Block]	IMPAIRMENT OF LONG-LIVED ASSETS AND OTHER INTANGIBLE ASSETS - Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-down to estimated fair value. A long-lived asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is generally determined from estimated discounted future net cash flows. The Partnership recognized fixed asset impairment charges of $25.8 million during the year ended December 31, 2016 , primarily due to an impairment recognized on the Knight Warrior pipeline project and the East Texas pipeline system. The Knight Warrior pipeline project was canceled due to continued low rig counts in the Eaglebine/Woodbine area coupled with lower production volumes, competing projects and the overall impact of the decreased market price of crude oil. Consequently, shipper commitments related to the project were canceled. In connection with the cancellation of the shipper commitments, the Partnership evaluated the Knight Warrior project for impairment and recognized an impairment expense of $22.6 million during the year ended December 31, 2016 . During the year ended December 31, 2015, the Partnership recognized fixed asset impairment charges of $12.6 million , $1.4 million , and $0.5 million related to the East Texas pipeline system, a portion of the Mid-Continent pipeline system, and the West Texas trucking stations, respectively. The Partnership had no impairment charges during the year ended December 31, 2014 . Acquired customer relationships and non-compete agreements are capitalized and amortized over useful lives ranging from 4 to 20 years using the straight-line method of amortization. An impairment loss is recognized for definite-lived intangibles if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value. No impairment charge was recognized during the years ended December 31, 2014 , 2015 or 2016 with respect to intangible assets.
Equity Method Investments, Policy [Policy Text Block]	EQUITY METHOD INVESTMENTS - The Partnership’s investment in Advantage Pipeline, L.L.C. (“Advantage Pipeline”), over which the Partnership has significant influence but not control, is accounted for by the equity method. The Partnership does not consolidate any part of the assets or liabilities of its equity investee. As of December 31, 2016 , the Partnership’s investment represents a 30% ownership interest in Advantage Pipeline. The Partnership’s share of net income or loss is reflected as one line item on the Partnership’s consolidated statements of operations entitled “Equity earnings in unconsolidated affiliate” and will increase or decrease, as applicable, the carrying value of the Partnership’s investment in the unconsolidated affiliate on the consolidated balance sheets. Distributions to the Partnership reduce the carrying value of its investment and will be reflected in the Partnership’s consolidated statements of cash flows in the line item “Distributions from unconsolidated affiliate.” In turn, contributions will increase the carrying value of the Partnership’s investment and will be reflected in the Partnership’s consolidated statements of cash flows in investing activities. The Partnership evaluates its equity investment for impairment in accordance with FASB guidance with respect to the equity method of accounting for investments in common stock. An impairment of an equity investment results when factors indicate that the investment’s fair value is less than its carrying value and the reduction in value is other than temporary in nature.
Debt, Policy [Policy Text Block]	DEBT ISSUANCE COSTS - Costs incurred in connection with the issuance of long-term debt related to the Partnership’s credit facilities are capitalized and amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization.
Investment, Policy [Policy Text Block]	INVESTMENTS - In November 2014, the Partnership received 30,393 Class A Common Units of SemCorp in connection with the settlement of two unsecured claims the Partnership filed in connection with SemCorp’s predecessor’s bankruptcy filing in 2008. The fair market value of these units on the date of receipt was $2.5 million . An unrealized loss of $0.4 million was incurred as a result of marking the units to their fair market value of $68.39 per unit as of December 31, 2014. The Partnership presents the unrealized gains and losses related to these units as one line item on the Partnership’s consolidated statements of operations entitled “Unrealized gains on investments.” In March 2015, the Partnership sold all of these units for a total of $2.3 million .
Goodwill and Intangible Assets, Goodwill, Policy [Policy Text Block]	GOODWILL - Goodwill represents the excess of the cost of acquisitions over the amounts assigned to assets acquired and liabilities assumed. Goodwill is not amortized but is tested annually for impairment and when events and circumstances warrant an interim evaluation. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit. The Partnership has four reporting units comprised of (i) its asphalt services, (ii) its crude oil terminalling and storage services, (iii) its crude oil pipeline services, and (iv) its crude oil trucking and producer field services. The Partnership has recorded goodwill of $0.9 million related to its crude oil trucking and producer field services reporting unit and $3.9 million related to its asphalt terminalling services reporting unit. During 2015, the Partnership recorded goodwill of $3.5 million attributable to its asphalt terminalling services reporting unit related to the acquisition of an asphalt terminalling facility in Cheyenne, Wyoming, as well as $1.2 million attributable to its crude oil pipeline services reporting unit related to the acquisition of a pipeline system and related crude oil marketing business in southern Oklahoma. During 2016, the Partnership recorded goodwill of $0.4 million attributable to its asphalt terminalling services reporting unit related to the acquisition of asphalt terminalling facilities in Wilmington, North Carolina and Dumfries, Virginia. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered to be impaired. The impairment test is generally based on the estimated discounted future net cash flows of the respective reporting unit, utilizing discount rates and other factors in determining the fair value of the reporting unit. Inputs in the Partnership’s estimated discounted future net cash flows include existing and estimated future asset utilization, estimated growth rates in future cash flows, and estimated terminal values (these are all considered Level 3 inputs). During the fourth quarter of 2015 impairment testing indicated that the fair value of the pipeline services reporting unit was less than the carrying value, and the Partnership recognized impairment of goodwill of $7.5 million related to its crude oil pipeline services reporting unit. Impairment testing indicated there was no impairment of goodwill in 2016.
Environmental Costs, Policy [Policy Text Block]	ENVIRONMENTAL MATTERS - Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines, penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. The Partnership recorded loss contingencies related to environmental matters of less than $0.1 million as of December 31, 2015 . The Partnership had no such loss contingencies as of December 31, 2016 .
Revenue Recognition, Policy [Policy Text Block]	REVENUE RECOGNITION - The Partnership’s revenues consist of (i) terminalling and storage revenues, (ii) gathering, transportation and producer field services revenues, (iii) crude oil marketing revenues and (iv) fuel surcharge revenues. Terminalling and storage revenues consist of (i) storage service fees from actual storage used on a month-to-month basis; (ii) storage service fees resulting from short-term and long-term contracts for committed space that may or may not be utilized by the customer in a given month; and (iii) terminal throughput service charges to pump crude oil to connecting carriers or to deliver asphalt product out of the Partnership’s terminals. Terminal throughput service charges are recognized as the crude oil exits the terminal and is delivered to the connecting crude oil carrier or third-party terminal and as the asphalt product is delivered out of the Partnership’s terminal. Storage service revenues are recognized as the services are provided and the amounts earned on a monthly basis. Gathering and transportation services revenues consist of service fees recognized for the gathering of crude oil for the Partnership’s customers and the transportation of the crude oil to refiners, to common carrier pipelines for ultimate delivery to refiners, or to terminalling and storage facilities owned by the Partnership and others. Revenue for the gathering and transportation of crude oil is recognized when the service is performed and is based upon regulated and non-regulated tariff rates and the related transport volumes. Producer field services revenue consists of a number of services ranging from gathering condensates from natural gas producers to hauling produced water to disposal wells. Revenue for producer field services is recognized when the service is performed. Crude oil marketing revenues consist of sales proceeds recognized for the sale of crude oil to third party customers. Revenue for the sale of crude oil is recognized when title to the crude oil transfers to the customer and is based on contractual prices for the sale of crude oil. Fuel surcharge revenues are comprised of revenues recognized for the reimbursement of fuel and power consumed to operate the Partnership’s asphalt product storage tanks and terminals. The Partnership recognizes fuel surcharge revenues in the period in which the related fuel and power expenses are incurred.
Income Tax, Policy [Policy Text Block]	INCOME AND OTHER TAXES - For federal and most state income tax purposes, the majority of income, gains, losses, expenses, deductions and tax credits generated by the Partnership flow through to the unitholders of the Partnership. In 2007, the state of Texas implemented a partnership-level tax based on a percentage of the revenue earned for services provided in the state of Texas. The Partnership has estimated its liability related to this tax to be $0.3 million for both December 31, 2015 and 2016 , which is reported as a provision for income taxes on its consolidated statements of operations. See Note 20 for a discussion of certain risks related to the Partnership’s ability to be treated as a partnership for federal income tax purposes.
Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block]	STOCK BASED COMPENSATION - The Partnership’s general partner adopted the Blueknight Energy Partners G.P. L.L.C. Long-Term Incentive Plan (the “LTIP”). The compensation committee of the Board administers the LTIP. Effective April 29, 2014, the Partnership’s unitholders approved an amendment to the LTIP to increase the number of common units reserved for issuance under the incentive plan by 1.5 million common units from 2.6 million common units to 4.1 million common units, subject to adjustment for certain events. Although other types of awards are contemplated under the LTIP, awards issued to date include “phantom” units, which convey the right to receive common units upon vesting, and “restricted” units, which are grants of common units restricted until the time of vesting. Certain of the phantom unit awards also include distribution equivalent rights (“DERs”). A DER entitles the grantee to a cash payment equal to the cash distribution paid on an outstanding common unit prior to the vesting date of the underlying award. Cash distributions paid on DERs are accounted for as partnership distributions. Recipients of restricted units are entitled to receive cash distributions paid on common units during the vesting period. The Partnership classifies unit award grants as either equity or liability awards. All award grants made under the LTIP from its inception through December 31, 2016 have been classified as equity awards. Fair value for award grants classified as equity is determined on the grant date of the award and this value is recognized as compensation expense ratably over the requisite service period of unit award grants, which generally is the vesting period. Fair value for equity awards is calculated as the closing price of the Partnership’s common units representing limited partner interests in the Partnership (“common units”) on the grant date and is reduced by the present value of estimated cash distributions to be paid on common units during the vesting period to the extent a unit award does not include DERs. Compensation expense related to unit-based payments is included in operating and general and administrative expenses on the Partnership’s consolidated statements of operations.
Fair Value of Financial Instruments, Policy [Policy Text Block]	FAIR VALUE OF FINANCIAL INSTRUMENTS - The Partnership measures all financial instruments, including derivatives embedded in other contracts, at fair value and recognizes them in the consolidated balance sheets as an asset or a liability, depending on its rights and obligations under the applicable contract. The changes in the fair value of financial instruments are recognized currently in earnings in the consolidated statements of operations.

EQUITY METHOD INVESTMENT (Table

EQUITY METHOD INVESTMENT (Tables)	12 Months Ended
	Dec. 31, 2016
Equity Method Investments [Abstract]
Equity Method Investments [Table Text Block]	Summarized financial information for Advantage Pipeline is set forth in the tables below for the periods indicated. As of December 31, 2015 2016 (in thousands) Balance sheets Current assets $ 2,496 $ 2,075 Noncurrent assets 86,702 89,065 Total assets $ 89,198 $ 91,140 Current liabilities 2,534 1,327 Long-term liabilities 23,194 20,910 Member’s equity 63,470 68,903 Total liabilities and member’s equity $ 89,198 $ 91,140 Year ended December 31, 2014 2015 2016 (in thousands) Income statements Operating revenues $ 10,894 $ 26,398 $ 17,091 Net income $ 3,354 $ 14,909 $ 5,434

RESTRUCTURING CHARGES (Tables)

RESTRUCTURING CHARGES (Tables)	12 Months Ended
	Dec. 31, 2016
Crude Oil Trucking and Producer Field Services [Member] | West Texas Trucking Market Exit Plan [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Costs [Table Text Block]	The following restructuring charges were accrued for as of December 31, 2015 and reported in operating expenses in the Partnership’s consolidated statement of operations for the year ended December 31, 2015 . For the year ended December 31, 2015 (in thousands) Severance charges $ 315 Lease payments related to operating leases for idled equipment 1,250 Total restructuring costs $ 1,565 Changes in the accrued amounts pertaining to the above charges are summarized as follows: Year ended December 31, 2015 2016 (in thousands) Beginning Balance $ — $ 1,565 Charged to expense 1,565 — Cash Payments — 1,091 Ending Balance $ 1,565 $ 474

PROPERTY, PLANT AND EQUIPMENT (

PROPERTY, PLANT AND EQUIPMENT (Tables)	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant and Equipment	Estimated Useful Lives (Years) December 31, 2015 December 31, 2016 (dollars in thousands) Land N/A $ 19,680 $ 25,863 Land improvements 10-20 6,382 6,698 Pipelines and facilities 5-30 165,497 165,293 Storage and terminal facilities 10-35 251,051 347,656 Transportation equipment 3-10 13,728 12,391 Office property and equipment and other 3-20 28,453 35,578 Pipeline linefill and tank bottoms N/A 3,474 3,234 Construction-in-progress N/A 30,636 2,738 Property, plant and equipment, gross 518,901 599,451 Accumulated depreciation and impairments (205,967 ) (292,117 ) Property, plant and equipment, net $ 312,934 $ 307,334

INTANGIBLES AND OTHER ASSETS,35

INTANGIBLES AND OTHER ASSETS, NET (Tables)	12 Months Ended
	Dec. 31, 2016
Intangibles and Other Assets [Abstract]
Schedule of Finite-Lived Intangible Assets [Table Text Block]	Other assets, net of accumulated amortization, consist of the following: December 31, 2015 2016 (in thousands) Customer relationships $ 4,132 $ 12,579 Deferred charges related to pipeline connection agreements 2,627 2,653 Deposits 307 435 Prepaid insurance 12 428 Other prepaid expenses 70 24 Intangibles and other assets, gross 7,148 16,119 Accumulated amortization of intangible assets (362 ) (1,604 ) Intangibles and other assets, net $ 6,786 $ 14,515
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block]	The estimated aggregate amortization expense on amortizable intangible assets currently owned by the Partnership is as follows (in thousands): For year ending: December 31, 2017 $ 1,287 December 31, 2018 1,287 December 31, 2019 1,286 December 31, 2020 1,285 December 31, 2021 1,285 Thereafter 7,198 Total estimated aggregate amortization expense $ 13,628

NET INCOME PER LIMITED PARTNE36

NET INCOME PER LIMITED PARTNER UNIT (Tables)	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Schedule of Basic and Diluted Net Income (Loss) Per Common and Subordinated Units	The following sets forth the computation of basic and diluted net income per common unit (in thousands, except per unit data): Year ended December 31, 2014 2015 2016 Net income (loss) $ 27,572 $ 6,396 $ (4,840 ) General partner interest in net income 641 554 433 Preferred interest in net income 21,563 21,564 25,824 Income (loss) available to limited partners $ 5,368 $ (15,722 ) $ (31,097 ) Basic and diluted weighted average number of units: Common units 25,670 32,945 35,093 Restricted and phantom units 675 685 803 Basic and diluted net income (loss) per common unit $ 0.20 $ (0.47 ) $ (0.87 )

LONG-TERM INCENTIVE PLAN (Table

LONG-TERM INCENTIVE PLAN (Tables)	12 Months Ended
	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Share-based Compensation Arrangement by Share-based Payment Award, Restricted Stock Units, Vested and Expected to Vest [Table Text Block]	In connection with each anniversary of joining the Board, restricted common units are granted to the independent directors. The units vest in one-third increments over three years. The following table includes information on grants made to the directors under the LTIP: Grant Date Number of Units Weighted Average Grant Date Fair Value Grant Date Total Fair Value (in thousands) December 2014 7,500 $ 6.43 $ 48 December 2015 15,120 5.06 77 December 2016 10,950 6.85 75 A
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Table Text Block]	The Partnership also grants phantom units to employees. These grants are equity awards under ASC 718 – Stock Compensation , and, accordingly, the fair value of the awards as of the grant date is expensed over the vesting period. The following table includes information on the outstanding grants: Grant Date Number of Units Weighted Average Grant Date Fair Value Grant Date Total Fair Value (in thousands) March 2014 276,773 $ 9.06 $ 2,508 March 2015 266,076 7.74 2,059 March 2016 416,131 4.77 1,985 October 2016 9,960 5.85 58
Schedule Of Phantom Common Units And Restricted Common Units Activity	Activity pertaining to phantom common units and restricted common unit awards granted under the LTIP is as follows: Number of Units Weighted Average Grant Date Fair Value Nonvested at December 31, 2015 915,541 $ 7.81 Granted 447,261 4.89 Vested 347,193 7.55 Forfeited 100,429 6.72 Nonvested at December 31, 2016 915,180 $ 6.61

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]	Future non-cancellable commitments related to these items at December 31, 2016 , are summarized below (in thousands): Operating Leases For years ending: December 31, 2017 $ 5,087 December 31, 2018 4,307 December 31, 2019 3,042 December 31, 2020 1,494 December 31, 2021 746 Thereafter 1,630 Total future minimum lease payments $ 16,306

FAIR VALUE MEASUREMENTS Fair Va

FAIR VALUE MEASUREMENTS Fair Value Measurrements (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value, by Balance Sheet Grouping [Table Text Block]	The Partnership’s recurring financial assets and liabilities subject to fair value measurements and the necessary disclosures are as follows (in thousands): Fair Value Measurements as of December 31, 2015 Description Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Liabilities: Interest rate swap liabilities $ 3,103 $ — $ 3,103 $ — Total $ 3,103 $ — $ 3,103 $ — Fair Value Measurements as of December 31, 2016 Description Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Liabilities: Interest rate swap liabilities $ 1,947 $ — $ 1,947 $ — Total $ 1,947 $ — $ 1,947 $ —

OPERATING SEGMENTS (Tables)

OPERATING SEGMENTS (Tables)	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	The following table reflects certain financial data for each segment for the periods indicated (in thousands): For the year ended December 31, 2014 2015 2016 Asphalt Terminalling Services Service revenue Third party revenue $ 66,273 $ 72,152 $ 75,655 Related party revenue 1,119 1,278 11,762 Total revenue for reportable segments 67,392 73,430 87,417 Operating expense (excluding depreciation and amortization) 26,148 25,218 30,648 Operating margin (excluding depreciation and amortization) 41,244 48,212 56,769 Additions to long-lived assets 6,766 19,769 148,622 Total assets (end of period) $ 92,628 $ 98,848 $ 141,280 Crude Oil Terminalling and Storage Services Service revenue Third party revenue $ 9,258 $ 13,076 $ 16,387 Related party revenue 13,524 11,522 7,858 Total revenue for reportable segments 22,782 24,598 24,245 Operating expense (excluding depreciation and amortization) 3,964 5,756 4,197 Operating margin (excluding depreciation and amortization) 18,818 18,842 20,048 Additions to long-lived assets 8,551 3,282 2,126 Total assets (end of period) $ 69,469 $ 73,502 $ 71,689 Crude Oil Pipeline Services Service revenue Third party revenue $ 13,834 $ 15,148 $ 8,662 Related party revenue 8,381 10,687 5,433 Product sales revenue Third party revenue 4,190 3,511 20,968 Total revenue for reportable segments 26,405 29,346 35,063 Operating expense (excluding depreciation and amortization) 15,948 18,162 15,270 Operating expense (intersegment) — 259 890 Cost of product sales — 3,231 14,130 Cost of product sales (intersegment) — — 426 Operating margin (excluding depreciation and amortization) 10,457 7,694 4,347 Additions to long-lived assets 20,970 34,953 8,250 Total assets (end of period) $ 184,933 $ 175,142 $ 150,043 Crude Oil Trucking and Producer Field Services Service revenue Third party revenue $ 50,061 $ 37,039 $ 25,511 Related party revenue 19,764 15,616 5,158 Intersegment revenue — 259 890 Product sales revenue Third party revenue 222 — — Intersegment revenue — — 426 For the year ended December 31, 2014 2015 2016 Total revenue for reportable segments 70,047 52,914 31,985 Operating expense (excluding depreciation and amortization) 62,140 51,610 30,156 Operating margin (excluding depreciation and amortization) 7,907 1,304 1,829 Additions to long-lived assets 1,081 4,556 2,558 Total assets (end of period) $ 17,365 $ 17,256 $ 12,651 Total operating margin (excluding depreciation and amortization) (1) $ 78,426 $ 76,052 $ 82,993 Total Segment Revenues 186,626 180,288 178,710 Elimination of Intersegment Revenues — (259 ) (1,316 ) Consolidated Revenues 186,626 180,029 177,394 ____________________ (1) The following table reconciles segment operating margin (excluding depreciation and amortization) to income (loss) before income taxes (in thousands): For the year ended December 31, 2014 2015 2016 Operating margin (excluding depreciation and amortization) $ 78,426 $ 76,052 $ 82,993 Depreciation and amortization (26,045 ) (27,228 ) (30,820 ) General and administrative expenses (17,498 ) (18,976 ) (20,029 ) Asset impairment expense — (21,996 ) (25,761 ) Gain on sale of assets 2,464 6,137 108 Equity earnings in unconsolidated entity 883 3,932 1,483 Interest expense (12,268 ) (11,202 ) (12,554 ) Unrealized gains on investments 2,079 — — Income (loss) before income taxes $ 28,041 $ 6,719 $ (4,580 )

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Schedule of Deferred Tax Assets	In relation to the Partnership’s taxable subsidiary, the tax effects of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts at December 31, 2016 are presented below (dollars in thousands): Deferred tax assets Difference in bases of property, plant and equipment $ 844 Deferred tax asset 844 Less: valuation allowance (844 ) Net deferred tax asset $ —

QUARTERLY FINANCIAL DATA (Table

QUARTERLY FINANCIAL DATA (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Data [Abstract]
Schedule of Quarterly Financial Information [Table Text Block]	Summarized quarterly financial data is as follows (in thousands, except per unit data): First Quarter Second Quarter Third Quarter Fourth Quarter Full Year 2015: Revenues $ 42,356 $ 46,574 $ 47,217 $ 43,882 $ 180,029 Operating income (loss) 5,297 8,484 17,010 (16,802 ) 13,989 Net income (loss) 1,579 7,710 13,967 (16,860 ) 6,396 Basic net income (loss) per common unit (0.12 ) 0.06 0.24 (0.65 ) (0.47 ) Diluted net income (loss) per common unit (0.12 ) 0.06 0.21 (0.65 ) (0.47 ) 2016: Revenues $ 41,009 $ 43,425 $ 46,939 $ 46,021 $ 177,394 Operating income (loss) 5,013 (15,348 ) 13,398 3,428 6,491 Net income (loss) 726 (18,936 ) 11,419 1,951 (4,840 ) Basic net income (loss) per common unit (0.14 ) (0.71 ) 0.13 (0.18 ) (0.87 ) Diluted net income (loss) per common unit (0.14 ) (0.71 ) 0.13 (0.18 ) (0.87 )

ORGANIZATION AND NATURE OF BU43

ORGANIZATION AND NATURE OF BUSINESS (Narrative) (Details) $ in Thousands	Oct. 05, 2016USD ($)	Dec. 31, 2016Operating-segmentsStates	Dec. 31, 2016USD ($)States	Dec. 31, 2016StatesTerminalling_And_Storage_Facilities	Dec. 31, 2016States	Dec. 31, 2016Statesshares
Proceeds from Issuance of Private Placement			$ 5,000
Combination of Entities under Common Control, Consideration Paid in Excess of Historical Cost			$ 91,251
Number of states in which entity operates (in states) | States		26	26	26	26	26
Number of Operating Segments		4			4
Ergon [Member]
Combination of Entities under Common Control, Number Of Asphalt Terminals Acquired | Terminalling_And_Storage_Facilities				9
Combination of Entities under Common Control, Cash Received	$ 22,100
Combination of Entities under Common Control, Consideration Transferred	$ 144,700
Combination of Entities under Common Control, Historical Cost of Assets Acquired			$ 31,300
Combination of Entities under Common Control, Accumulated Depreciation on Assets Acquired			63,000
Combination of Entities under Common Control, Consideration Paid in Excess of Historical Cost			91,300
Blueknight GP Holding, LLC [Member]
Business Acquisition, Percentage of Voting Interests Acquired	100.00%
General Partner Interest [Member]
Business Acquisition, Percentage of Voting Interests Acquired	100.00%
Series A Preferred Stock [Member]
Combination of Entities under Common Control, Units Issued | shares						18,312,968
Limited Partner [Member]
Proceeds from Issuance of Private Placement			$ 5,000

SUMMARY OF SIGNIFICANT ACCOUN44

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) $ / shares in Units, $ in Thousands	1 Months Ended	3 Months Ended	4 Months Ended	12 Months Ended
	Dec. 31, 2014USD ($)$ / shares	Jun. 30, 2014shares	Mar. 05, 2015USD ($)	Dec. 31, 2016USD ($)shares	Dec. 31, 2016USD ($)Operating-segmentsshares	Dec. 31, 2016USD ($)shares	Dec. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)$ / shares	Nov. 19, 2014USD ($)shares	Apr. 28, 2014shares
Accounting Policies [Line Items]
Accounts receivable, allowance for doubtful accounts				$ 49	$ 49	$ 49	$ 49	$ 38
Fixed asset impairment charge						25,761		14,498	$ 0
Impairment of intangible assets						0		0	$ 0
Number of Units Received from Claims Settlement | shares										30,393
Fair Market Value of Units Received From Settlement										$ 2,500
Unrealized Gain (Loss) on Investments	$ 400
Price Per Unit of Units Received From Claim Settlement | $ / shares	$ 68.39								$ 68.39
Trading Securities, Realized Gain (Loss)			$ 2,300
Number of Operating Segments					4		4
Goodwill				4,746	$ 4,746	4,746	$ 4,746	4,387
Goodwill, Impairment Loss						0
Accrual for Environmental Loss Contingencies				$ 0	$ 0	0	$ 0	100
Provision for income taxes						260		323	$ 469
Customer Relationships [Member] | Minimum [Member]
Accounting Policies [Line Items]
Finite-Lived Intangible Asset, Useful Life				4 years
Customer Relationships [Member] | Maximum [Member]
Accounting Policies [Line Items]
Finite-Lived Intangible Asset, Useful Life				20 years
State and Local Jurisdiction [Member]
Accounting Policies [Line Items]
Provision for income taxes						$ 300		300
Blueknight Energy Partners G.P., L.L.C. Long-Term Incentive Plan [Member]
Accounting Policies [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Additional Shares Authorized | shares		1,500,000
Number of units authorized | shares				4,100,000	4,100,000	4,100,000	4,100,000				2,600,000
Crude Oil Pipeline Services [Member]
Accounting Policies [Line Items]
Goodwill, Acquired During Period								1,200
Goodwill, Impairment Loss								7,500
Crude Oil Trucking and Producer Field Services [Member]
Accounting Policies [Line Items]
Goodwill				$ 900	$ 900	$ 900	$ 900
Asphalt Services [Member]
Accounting Policies [Line Items]
Goodwill				$ 3,900	$ 3,900	3,900	$ 3,900
Goodwill, Acquired During Period						$ 400		3,500
OKLAHOMA | Crude Oil Pipeline Services [Member] | Pipelines [Member]
Accounting Policies [Line Items]
Fixed asset impairment charge								1,400
Texas [Member] | Crude Oil Pipeline Services [Member] | Pipelines [Member]
Accounting Policies [Line Items]
Fixed asset impairment charge								12,600
Texas [Member] | Crude Oil Trucking and Producer Field Services [Member] | Truck Station Assets [Member]
Accounting Policies [Line Items]
Fixed asset impairment charge								$ 500
Advantage Pipeline, L.L.C. [Member]
Accounting Policies [Line Items]
Equity Method Investment, Ownership Percentage				30.00%	30.00%	30.00%	30.00%
Knight Warrior pipeline project [Member] | Texas [Member] | Crude Oil Pipeline Services [Member] | Pipelines [Member]
Accounting Policies [Line Items]
Fixed asset impairment charge						$ 22,600

EQUITY METHOD INVESTMENT (Detai

EQUITY METHOD INVESTMENT (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Advantage Pipeline, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Summarized Financial Information, Current Assets		$ 2,075,000	$ 2,496,000
Equity Method Investment, Summarized Financial Information, Noncurrent Assets		89,065,000	86,702,000
Equity Method Investment, Summarized Financial Information, Assets		91,140,000	89,198,000
Equity Method Investment, Summarized Financial Information, Current Liabilities		1,327,000	2,534,000
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities		20,910,000	23,194,000
Equity Method Investment Summarized Financial Information, Equity		68,903,000	63,470,000
Equity Method Investment, Summarized Financial Information, Liabilities and Equity		91,140,000	89,198,000
Equity Method Investment, Summarized Financial Information, Revenue		17,091	26,398	$ 10,894
Equity Method Investment, Summarized Financial Information, Net Income (Loss)		$ 5,434	$ 14,909	$ 3,354
Advantage Pipeline, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage		30.00%
Minimum [Member] | Subsequent Event [Member] | Advantage Pipeline, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Net Sales Proceeds	$ 27,000
Maximum [Member] | Subsequent Event [Member] | Advantage Pipeline, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Net Sales Proceeds	$ 29,000

RESTRUCTURING CHARGES (Details)

RESTRUCTURING CHARGES (Details) - Crude Oil Trucking and Producer Field Services [Member] - West Texas Trucking Market Exit Plan [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Restructuring Cost and Reserve [Line Items]
Severance Costs		$ 315
Other Restructuring Costs		1,250
Restructuring Reserve	$ 474	1,565	$ 0
Restructuring and Related Cost, Incurred Cost	0	1,565
Payments for Restructuring	$ 1,091	$ 0

PROPERTY, PLANT AND EQUIPMENT47

PROPERTY, PLANT AND EQUIPMENT (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 599,451	$ 518,901
Property, plant and equipment, accumulated depreciation and Impairments	292,117	205,967
Property, plant and equipment, net	307,334	312,934
Depreciation	29,600	27,000	$ 26,000
Fixed asset impairment charge	25,761	14,498	$ 0
Assets held for sale, net of accumulated depreciation	4,237	0
Land
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	25,863	19,680
Land improvements
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 6,698	6,382
Land improvements | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives	10 years
Land improvements | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives	20 years
Pipelines and facilities
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 165,293	165,497
Pipelines and facilities | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives	5 years
Pipelines and facilities | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives	30 years
Storage and terminal facilities
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 347,656	251,051
Storage and terminal facilities | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives	10 years
Storage and terminal facilities | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives	35 years
Transportation equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 12,391	13,728
Transportation equipment | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives	3 years
Transportation equipment | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives	10 years
Office property and equipment and other
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 35,578	28,453
Office property and equipment and other | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives	3 years
Office property and equipment and other | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives	20 years
Pipeline linefill and tank bottoms
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 3,234	3,474
Construction-in-progress
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	2,738	30,636
Texas & Oklahoma [Member] | Pipelines [Member] | Crude Oil Pipeline Services [Member]
Property, Plant and Equipment [Line Items]
Fixed asset impairment charge		14,000
Texas [Member] | Crude Oil Pipeline Services [Member]
Property, Plant and Equipment [Line Items]
Assets held for sale, net of accumulated depreciation	$ 4,200
Texas [Member] | Pipelines [Member] | Crude Oil Pipeline Services [Member]
Property, Plant and Equipment [Line Items]
Fixed asset impairment charge		12,600
Texas [Member] | Truck Station Assets [Member] | Crude Oil Trucking and Producer Field Services [Member]
Property, Plant and Equipment [Line Items]
Fixed asset impairment charge		$ 500

INTANGIBLES AND OTHER ASSETS,48

INTANGIBLES AND OTHER ASSETS, NET Narrative (Details) - USD ($) $ in Thousands	1 Months Ended		12 Months Ended
	Feb. 29, 2016	Nov. 30, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2010
Finite-Lived Intangible Assets [Line Items]
Other Finite-Lived Intangible Assets, Gross			$ 2,653	$ 2,627
Impairment of intangible assets			0	0	$ 0
Amortization of Intangible Assets			$ 1,200	$ 200	$ 100
Crude Oil Trucking and Producer Field Services [Member] | Customer Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-lived Intangible Assets Acquired						$ 700
Crude Oil Pipeline Services [Member] | Customer Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-lived Intangible Assets Acquired		$ 3,500
Asphalt Services [Member] | Customer Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-lived Intangible Assets Acquired	$ 8,400
Minimum [Member] | Customer Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life			4 years
Maximum [Member] | Customer Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life			20 years

INTANGIBLES AND OTHER ASSETS,49

INTANGIBLES AND OTHER ASSETS, NET Other Assets, Net of Accumulated Depreciation (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
INTANGIBLE AND OTHER ASSETS, NET [Abstract]
Customer relationships	$ 12,579	$ 4,132
Other Finite-Lived Intangible Assets, Gross	2,653	2,627
Deposits	435	307
Prepaid insurance	428	12
Other prepaid expenses	24	70
Intangibles and other assets, gross	16,119	7,148
Accumulated amortization of intangible assets	(1,604)	(362)
Intangibles and other assets, net	$ 14,515	$ 6,786

INTANGIBLES AND OTHER ASSETS,50

INTANGIBLES AND OTHER ASSETS, NET ESTIMATED AGGREGATE AMORTIZATION EXPENSE ON INTANGIBLE ASSETS (Details) $ in Thousands	Dec. 31, 2016USD ($)
For the twelve months ending:
December 31, 2014	$ 1,287
December 31, 2015	1,287
December 31, 2016	1,286
December 31, 2017	1,285
December 31, 2018	1,285
Thereafter	7,198
Finite-lived Intangible Assets, Net	$ 13,628

DEBT (Credit Agreements) (Detai

DEBT (Credit Agreements) (Details)	12 Months Ended
	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Mar. 02, 2017USD ($)	Dec. 31, 2013USD ($)
Debt Instrument [Line Items]
Cash and cash equivalents	$ 3,304,000	$ 3,038,000	$ 2,661,000		$ 3,182,000
Debt issuance costs	956,000	0	326,000
Amortization of debt issuance costs	$ 1,107,000	$ 884,000	$ 821,000
Debt Instrument, Interest Rate During Period	3.95%	3.37%	3.44%
Interest expense for long-term debt	$ 11,200,000	$ 7,900,000	$ 9,200,000
Weighted average interest rate (as a percent)	4.08%
Capitalized Interest	$ 41,241.21	184,388.68	291,456.92
Derivative, Notional Amount	200,000,000
Interest Expense, Other	2,500,000	2,900,000	700,000
Interest rate swap liabilities	$ 1,947,000	3,103,000
Blueknight General Partners G. P., L.L.C. [Member]
Debt Instrument [Line Items]
Credit agreement, Constitute a change of control, if ceases to own, directly or indirectly, exactly 50% of the membership interests of the General Partner or if General Partner ceases to be controlled (as a percent)	100.00%
Ergon [Member]
Debt Instrument [Line Items]
Credit agreement, Constitute a change of control if Ergon ceases to own and control 50% of the GP	50.00%
Letter of Credit [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Letters of credit outstanding, amount				$ 1,500,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Revolving credit facility amount	$ 400,000,000
Maximum borrowing capacity including additional lenders	$ 500,000,000
Debt Instrument Maximum Covenant Consolidated Senior Secured Leverage Ratio	3.50
Consolidated interest coverage (as a ratio), minimum permitted	2.50
Consolidated total leverage (as a ratio), actual	4.22
Consolidated interest coverage (as a ratio), actual	6.09
Debt issuance costs	$ 1,000,000	0	$ 300,000
Revolving Credit Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Unused capacity, commitment fee (as a percent)	0.375%
Debt Instrument Covenant, Issued Qualified Senior Notes	$ 200,000,000
Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Unused capacity, commitment fee (as a percent)	0.50%
Revolving Credit Facility [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Long-term Line of Credit				322,000,000
Unused borrowing capacity				$ 76,500,000
Revolving Credit Facility [Member] | Federal funds rate [Member]
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	0.50%
Revolving Credit Facility [Member] | Eurodollar rate [Member]
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	1.00%
Revolving Credit Facility [Member] | Applicable margin based on ABR [Member] | Minimum [Member]
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	1.00%
Revolving Credit Facility [Member] | Applicable margin based on ABR [Member] | Maximum [Member]
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	2.00%
Revolving Credit Facility [Member] | Applicable margin based on Eurodollar rate [Member] | Minimum [Member]
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	2.00%
Revolving Credit Facility [Member] | Applicable margin based on Eurodollar rate [Member] | Maximum [Member]
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	3.00%
Interest Rate Swap [Member]
Debt Instrument [Line Items]
Derivative, Notional Amount	$ 100,000,000
Derivative, Fixed Interest Rate	1.45%
Interest Rate Swap Two [Member]
Debt Instrument [Line Items]
Derivative, Notional Amount	$ 100,000,000
Derivative, Fixed Interest Rate	1.97%
Aggregate Principal Below Threshold [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument Covenant, Issued Qualified Senior Notes	$ 200,000,000
Minimum Acquisition Costs	15,000,000
Cash and cash equivalents	20,000,000
Aggregate Principal Above Threshold [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument Covenant, Issued Qualified Senior Notes	$ 200,000,000
Provision One, Applicable Period One [Member] | Aggregate Principal Below Threshold [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Consolidated total leverage (as a ratio), Maximum permitted	4.75
Provision One, Applicable Period One [Member] | Aggregate Principal Above Threshold [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Consolidated total leverage (as a ratio), Maximum permitted	5.50
Provision One, Applicable Period Two [Member] | Aggregate Principal Below Threshold [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Consolidated total leverage (as a ratio), Maximum permitted	5.25
Provision Two, Applicable Period One [Member] | Aggregate Principal Above Threshold [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Consolidated total leverage (as a ratio), Maximum permitted	5
Fair Value, Inputs, Level 2 [Member]
Debt Instrument [Line Items]
Interest rate swap liabilities	$ 1,947,000	$ 3,103,000

NET INCOME PER LIMITED PARTNE52

NET INCOME PER LIMITED PARTNER UNIT (Details) - USD ($) $ / shares in Units, shares in Thousands, $ 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
Earnings Per Share [Abstract]
Net income (loss)	$ 1,951	$ 11,419	$ (18,936)	$ 726	$ (16,860)	$ 13,967	$ 7,710	$ 1,579	$ (4,840)	$ 6,396	$ 27,572
General partner interest in net income									433	554	641
Preferred interest in net income									25,824	21,564	21,563
Income (loss) available to limited partners									$ (31,097)	$ (15,722)	$ 5,368
Basic and diluted weighted average number of units:
Weighted average common units outstanding - basic and diluted									35,093	32,945	25,670
Weighted average common units outstanding - diluted									32,945	25,670	22,706
Restricted and phantom units									803	685	675
Basic net income (loss) per common unit	$ (0.18)	$ 0.13	$ (0.71)	$ (0.14)	$ (0.65)	$ 0.24	$ 0.06	$ (0.12)	$ (0.87)	$ (0.47)	$ 0.20
Diluted net income (loss) per common unit	$ (0.18)	$ 0.13	$ (0.71)	$ (0.14)	$ (0.65)	$ 0.21	$ 0.06	$ (0.12)	$ (0.87)	$ (0.47)	$ 0.20

PARTNERS' CAPITAL AND DISTRIB53

PARTNERS' CAPITAL AND DISTRIBUTIONS Issuance Narrative (Details) - USD ($)	Oct. 05, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jul. 26, 2016	Sep. 22, 2014
Capital Unit [Line Items]
Proceeds from Issuance of Private Placement		$ 5,000,000
Proceeds from issuance of common units, net of offering costs		20,931,000		$ 71,182,000
Repurchase of Series A Preferred Units		$ (95,348,000)	$ 0	0
Preferred Units, Outstanding		35,125,202	30,158,619
Proceeds from Issuance of Series A Preferred Units		$ 144,672,000
Partners' Capital Account, Sale of Units		$ 680,000
Preferred Partner [Member]
Capital Unit [Line Items]
Stock Repurchased During Period, Shares		13,335,390
Partners' Capital Account, Units, Sale of Units		18,312,968
Repurchase of Series A Preferred Units		$ (95,348,000)
Proceeds from Issuance of Series A Preferred Units		$ 144,672,000
Limited Partner [Member]
Capital Unit [Line Items]
Partners' Capital Account, Units, Sold in Private Placement		847,457
Proceeds from Issuance of Private Placement		$ 5,000,000
Proceeds from issuance of common units, net of offering costs		20,900,000		71,182,000
Limited Partners' Offering Costs		$ 1,500,000		$ 3,200,000	$ 1,500,000	$ 3,200,000
Partners' Capital Account, Units, Sale of Units		3,795,000		9,775,000
Sale of Stock, Price Per Share					$ 5.90	$ 7.61
General Partner Interest [Member]
Capital Unit [Line Items]
Partners' Capital Account, Units, Sale of Units		97,654
Partners' Capital Account, Sale of Units	$ 700,000
Charlesbank [Member] | Preferred Partner [Member]
Capital Unit [Line Items]
Stock Repurchased During Period, Shares		6,667,695
Preferred Units, Outstanding	2,488,789
Vitol [Member] | Preferred Partner [Member]
Capital Unit [Line Items]
Stock Repurchased During Period, Shares		6,667,695
Preferred Units, Outstanding	2,488,789

PARTNERS' CAPITAL AND DISTRIB54

PARTNERS' CAPITAL AND DISTRIBUTIONS (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Distribution Made to Member or Limited Partner, Cash Distributions Declared	$ 6
Phantom Share Units and Restricted Units [Member]
Distribution Made to Limited Partner, Cash Distributions Paid		$ 0.5	$ 0.4	$ 0.3
Distribution Made to Member or Limited Partner, Cash Distributions Declared	$ 0.1
Preferred Partner [Member]
Quarterly Distribution, Per Unit Per Quarter, Percentage	2.75%	2.75%
Quarterly Distributions, Per Unit Per Quarter, Annual Percentage	11.00%	11.00%
Distribution Made to Limited Partner, Cash Distributions Paid		$ 22.4	21.6	21.6
Distribution Made to Member or Limited Partner, Distributions Declared (in dollars per unit)	$ 0.17875
Distribution Made to Member or Limited Partner, Cash Distributions Declared	$ 6.3
Preferred Partner [Member] | First Tier Cash Distribution for each Series A Preferred Unit an Amount Equal to the Series A Quarterly Distribution Amount [Member]
Partners' Capital Account, Distributions, Allocation Percentage		98.40%
Preferred Partner [Member] | Second Tier Cash Distribution for each Series A Preferred Unit an Amount Equal to the Series A Cumulative Distribution Arrearage [Member]
Partners' Capital Account, Distributions, Allocation Percentage		98.40%
Preferred Partner [Member] | Third Tier Cash Distribution [Member]
Partners' Capital Account, Distributions, Allocation Percentage		98.40%
General Partner Interest [Member]
Distribution Made to Limited Partner, Cash Distributions Paid		$ 1.3	1.1	0.8
Distribution Made to Member or Limited Partner, Cash Distributions Declared	$ 0.4
General Partner Interest [Member] | First Tier Cash Distribution for each Series A Preferred Unit an Amount Equal to the Series A Quarterly Distribution Amount [Member]
Partners' Capital Account, Distributions, Allocation Percentage		1.60%
General Partner Interest [Member] | Second Tier Cash Distribution for each Series A Preferred Unit an Amount Equal to the Series A Cumulative Distribution Arrearage [Member]
Partners' Capital Account, Distributions, Allocation Percentage		1.60%
General Partner Interest [Member] | Third Tier Cash Distribution [Member]
Partners' Capital Account, Distributions, Allocation Percentage		1.60%
Limited Partner [Member]
Distribution Made to Limited Partner, Cash Distributions Paid		$ 20.5	$ 20	$ 14.5
Distribution Made to Member or Limited Partner, Distributions Declared (in dollars per unit)	$ 0.1450
Distribution Made to Member or Limited Partner, Cash Distributions Declared	$ 5.5

Major Customers and Concentra55

Major Customers and Concentration of Credit Risk (Details) - Customer Concentration Risk [Member]	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Ergon Asphalt & Emulsions, Inc. [Member] | Asphalt Services [Member] | Sales Revenue, Services, Net [Member] | Minimum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	20.00%
Ergon Asphalt & Emulsions, Inc. [Member] | Asphalt Services [Member] | Sales Revenue, Services, Net [Member] | Maximum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	30.00%
Axeon Marketing, LLC, Heartland Asphalt Materials, Inc. and Suncor Energy USA [Member] | Asphalt Services [Member] | Sales Revenue, Services, Net [Member] | Minimum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	10.00%
Axeon Marketing, LLC, Heartland Asphalt Materials, Inc. and Suncor Energy USA [Member] | Asphalt Services [Member] | Sales Revenue, Services, Net [Member] | Maximum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	20.00%
Ergon Asphalt & Emulsions, Heartland Asphalt Materials, Inc., Suncor Energy USA, Axeon Marketing, LLC and Western States Asphalt, Inc. [Member] | Asphalt Services [Member] | Sales Revenue, Services, Net [Member] | Minimum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		10.00%
Ergon Asphalt & Emulsions, Heartland Asphalt Materials, Inc., Suncor Energy USA, Axeon Marketing, LLC and Western States Asphalt, Inc. [Member] | Asphalt Services [Member] | Sales Revenue, Services, Net [Member] | Maximum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		25.00%
Vitol and MV Purchasing, LLC [Member] | Crude Oil Trucking and Producer Field Services [Member] | Sales Revenue, Services, Net [Member] | Minimum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			25.00%
Vitol and MV Purchasing, LLC [Member] | Crude Oil Trucking and Producer Field Services [Member] | Sales Revenue, Services, Net [Member] | Maximum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			40.00%
Ergon Asphalt & Emulsions, Heartland Asphalt Materials, Inc., Nustar Marketing, LLC and Suncor Energy USA [Member] | Asphalt Services [Member] | Sales Revenue, Services, Net [Member] | Minimum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			10.00%
Ergon Asphalt & Emulsions, Heartland Asphalt Materials, Inc., Nustar Marketing, LLC and Suncor Energy USA [Member] | Asphalt Services [Member] | Sales Revenue, Services, Net [Member] | Maximum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			25.00%
MV Purchasing, LLC [Member] | Crude Oil Terminalling and Storage Services [Member] | Sales Revenue, Services, Net [Member] | Minimum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			10.00%
MV Purchasing, LLC [Member] | Crude Oil Terminalling and Storage Services [Member] | Sales Revenue, Services, Net [Member] | Maximum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			20.00%
Vitol and XTO Energy Inc. | Crude Oil Pipeline Services [Member] | Sales Revenue, Services, Net [Member] | Minimum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			20.00%
Vitol and XTO Energy Inc. | Crude Oil Pipeline Services [Member] | Sales Revenue, Services, Net [Member] | Maximum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			30.00%
Vitol [Member] | Accounts Receivable [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			20.00%
Vitol [Member] | Crude Oil Terminalling and Storage Services [Member] | Sales Revenue, Services, Net [Member] | Minimum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	40.00%	45.00%	50.00%
Vitol [Member] | Crude Oil Terminalling and Storage Services [Member] | Sales Revenue, Services, Net [Member] | Maximum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	50.00%	55.00%	60.00%
Vitol [Member] | Crude Oil Pipeline Services [Member] | Sales Revenue, Services, Net [Member] | Minimum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	10.00%	30.00%
Vitol [Member] | Crude Oil Pipeline Services [Member] | Sales Revenue, Services, Net [Member] | Maximum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	20.00%	40.00%
Vitol [Member] | Crude Oil Trucking and Producer Field Services [Member] | Sales Revenue, Services, Net [Member] | Minimum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		40.00%
Vitol [Member] | Crude Oil Trucking and Producer Field Services [Member] | Sales Revenue, Services, Net [Member] | Maximum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		50.00%
MV Purchasing, LLC and Sunoco Logistics Partners L.P. [Member] | Crude Oil Terminalling and Storage Services [Member] | Sales Revenue, Services, Net [Member] | Minimum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	10.00%
MV Purchasing, LLC and Sunoco Logistics Partners L.P. [Member] | Crude Oil Terminalling and Storage Services [Member] | Sales Revenue, Services, Net [Member] | Maximum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	20.00%
MV Purchasing, LLC, Vitol, DCP Midstream, LLC and Regency Energy Partners LP [Member] | Crude Oil Trucking and Producer Field Services [Member] | Sales Revenue, Services, Net [Member] | Minimum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	10.00%
MV Purchasing, LLC, Vitol, DCP Midstream, LLC and Regency Energy Partners LP [Member] | Crude Oil Trucking and Producer Field Services [Member] | Sales Revenue, Services, Net [Member] | Maximum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	25.00%
Vitol, Ergon and Ascent Midstream Partners, LLC [Member] | Accounts Receivable [Member] | Minimum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	10.00%
Vitol, Ergon and Ascent Midstream Partners, LLC [Member] | Accounts Receivable [Member] | Maximum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	20.00%
MV Purchasing, LLC and Devon Energy Production Co [Member] | Crude Oil Trucking and Producer Field Services [Member] | Sales Revenue, Services, Net [Member] | Minimum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		10.00%
MV Purchasing, LLC and Devon Energy Production Co [Member] | Crude Oil Trucking and Producer Field Services [Member] | Sales Revenue, Services, Net [Member] | Maximum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		25.00%
Vitol and Coffeyville Resources [Member] | Accounts Receivable [Member] | Minimum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		15.00%
Vitol and Coffeyville Resources [Member] | Accounts Receivable [Member] | Maximum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		25.00%
XTO Energy, Inc. and Valero Marketing & Supply Co [Member] | Crude Oil Pipeline Services [Member] | Sales Revenue, Services, Net [Member] | Minimum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		10.00%
XTO Energy, Inc. and Valero Marketing & Supply Co [Member] | Crude Oil Pipeline Services [Member] | Sales Revenue, Services, Net [Member] | Maximum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		25.00%
MV Purchasing, LLC and Sunoco Partners Marketing & Terminals, LP [Member] | Crude Oil Terminalling and Storage Services [Member] | Sales Revenue, Services, Net [Member] | Minimum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		10.00%
MV Purchasing, LLC and Sunoco Partners Marketing & Terminals, LP [Member] | Crude Oil Terminalling and Storage Services [Member] | Sales Revenue, Services, Net [Member] | Maximum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		20.00%
CVR Energy, Inc. [Member] | Crude Oil Pipeline Services [Member] | Sales Revenue, Services, Net [Member] | Minimum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	40.00%
CVR Energy, Inc. [Member] | Crude Oil Pipeline Services [Member] | Sales Revenue, Services, Net [Member] | Maximum [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	50.00%

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) - USD ($) $ 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	Oct. 05, 2016
Related Party Transaction [Line Items]
Related party revenue									$ 30,211	$ 39,103	$ 42,788
Accounts receivable	$ 7,544				$ 8,697				7,544	8,697
Revenues	46,021	$ 46,939	$ 43,425	$ 41,009	43,882	$ 47,217	$ 46,574	$ 42,356	177,394	180,029	186,626
Receivables from related parties	1,860				1,844				1,860	1,844
Ergon [Member]
Related Party Transaction [Line Items]
Related party revenue									11,000
Receivables from related parties	1,700								1,700
Vitol [Member]
Related Party Transaction [Line Items]
Related party revenue										37,800	41,800
Receivables from related parties					1,800					1,800
Advantage Pipeline, L.L.C. [Member]
Related Party Transaction [Line Items]
Related party revenue									1,300	1,300	1,000
Receivables from related parties	100				100				100	100
Ergon [Member]
Related Party Transaction [Line Items]
Accounts receivable					$ 700					700
Revenues									22,200	$ 15,500	$ 15,800
Vitol [Member]
Related Party Transaction [Line Items]
Accounts receivable	$ 1,000								1,000
Revenues									17,900
Other Revenue, Net									$ 5,300
Blueknight GP Holding, LLC [Member]
Related Party Transaction [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired												100.00%

RELATED PARTY TRANSACTIONS Ergo

RELATED PARTY TRANSACTIONS Ergon Agreements (Details) $ in Thousands	Oct. 05, 2016	May 18, 2009	Dec. 31, 2016USD ($)Terminalling_And_Storage_Facilities	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2016USD ($)Terminalling_And_Storage_Facilities	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Related Party Transaction [Line Items]
Related party revenue											$ 30,211	$ 39,103	$ 42,788
Revenues			$ 46,021	$ 46,939	$ 43,425	$ 41,009	$ 43,882	$ 47,217	$ 46,574	$ 42,356	177,394	180,029	186,626
Ergon [Member]
Related Party Transaction [Line Items]
Related party revenue											$ 11,000
Ergon Storage and Handling Agreement [Member] | Ergon [Member]
Related Party Transaction [Line Items]
Initial term (in years)	7 years
Number Of Asphalt Terminalling And Storage Facilities | Terminalling_And_Storage_Facilities			9								9
Related party revenue											$ 6,200
Ergon Master Facilities Lease Agreement [Member] | Ergon [Member]
Related Party Transaction [Line Items]
Initial term (in years)		2 years
Number Of Asphalt Terminalling And Storage Facilities | Terminalling_And_Storage_Facilities			10								10
Related party revenue											$ 1,800
Ergon Master Facilities Sublease and Sublicense Agreement [Member] | Ergon [Member]
Related Party Transaction [Line Items]
Initial term (in years)		2 years
Number Of Asphalt Terminalling And Storage Facilities | Terminalling_And_Storage_Facilities			6								6
Related party revenue											$ 1,000
Ergon [Member]
Related Party Transaction [Line Items]
Revenues											22,200	15,500	15,800
Ergon [Member] | Ergon Master Facilities Lease Agreement [Member]
Related Party Transaction [Line Items]
Revenues											9,200	10,500	10,700
Ergon [Member] | Ergon Master Facilities Sublease and Sublicense Agreement [Member]
Related Party Transaction [Line Items]
Revenues											$ 3,600	$ 3,200	$ 3,300

RELATED PARTY TRANSACTIONS (Vit

RELATED PARTY TRANSACTIONS (Vitol Storage Agreements) (Details) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016USD ($)bbl	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)bbl	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2016USD ($)bbl	Dec. 31, 2015USD ($)bbl	Dec. 31, 2014USD ($)bbl	Mar. 02, 2017bbl
Related Party Transaction [Line Items]
Related party revenue									$ 30,211	$ 39,103	$ 42,788
Receivables from related parties, net of allowance for doubtful accounts of $225 and $0 at December 31, 2015 and 2016, respectively	$ 1,860				$ 1,844				1,860	1,844
Revenues	$ 46,021	$ 46,939	$ 43,425	$ 41,009	43,882	$ 47,217	$ 46,574	$ 42,356	177,394	180,029	186,626
Vitol [Member]
Related Party Transaction [Line Items]
Related party revenue										37,800	41,800
Receivables from related parties, net of allowance for doubtful accounts of $225 and $0 at December 31, 2015 and 2016, respectively					$ 1,800					1,800
Vitol [Member] | Vitol Storage Agreements [Member]
Related Party Transaction [Line Items]
Related party revenue										$ 9,400	$ 12,000
Barrels of storage capacity of crude oil storage tanks dedicated to related party (in barrels) | bbl					2,215,000					2,215,000	3,050,000
Vitol [Member]
Related Party Transaction [Line Items]
Revenues									17,900
Other Revenue, Net									$ 5,300
Vitol [Member] | Vitol Storage Agreements [Member]
Related Party Transaction [Line Items]
Barrels of storage capacity of crude oil storage tanks dedicated to related party (in barrels) | bbl	2,200,000								2,200,000
Revenues									$ 9,600
Other Revenue, Net									$ 2,100
Vitol [Member] | Subsequent Event [Member] | Vitol 2012 Storage 12 Month Agreement [Member]
Related Party Transaction [Line Items]
Barrels of storage capacity of crude oil storage tanks dedicated to related party (in barrels) | bbl												2,215,000

RELATED PARTY TRANSACTIONS (Oth

RELATED PARTY TRANSACTIONS (Other Vitol Agreements) (Details) - USD ($) $ in Thousands	Aug. 02, 2013	Aug. 31, 2012	Aug. 01, 2012	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Related party revenue				$ 30,211	$ 39,103	$ 42,788
Vitol [Member]
Related Party Transaction [Line Items]
Related party revenue					37,800	41,800
Vitol [Member] | Vitol Operating and Maintenance Agreement [Member]
Related Party Transaction [Line Items]
Gain (Loss) on Contract Termination					1,200
Transition Services Revenue					100
Initial term (in years)		5 years
Related party revenue					2,500	1,600
Vitol [Member] | Vitol Shared Services Agreement [Member]
Related Party Transaction [Line Items]
Initial term (in years)			1 year
Related Party Transaction, Renewed Term	1 year
Related party revenue					$ 100	$ 100

RELATED PARTY TRANSACTIONS (Adv

RELATED PARTY TRANSACTIONS (Advantage Pipeline Operating and Administrative Services Agreement) (Details) - USD ($) $ in Thousands	Jan. 31, 2013	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Related party revenue		$ 30,211	$ 39,103	$ 42,788
Advantage Pipeline, L.L.C. [Member]
Related Party Transaction [Line Items]
Related party revenue		1,300	1,300	1,000
Advantage Pipeline, L.L.C. [Member] | Operating and Administrative Services Agreement [Member]
Related Party Transaction [Line Items]
Initial term (in years)	10 years
Related Party Transaction, Option to Extend Term	5 years
Related party revenue		$ 500	$ 500	$ 500

LONG-TERM INCENTIVE PLAN (Detai

LONG-TERM INCENTIVE PLAN (Details) - USD ($) $ / shares in Units, $ in Thousands	Jan. 02, 2017	Dec. 31, 2016	Oct. 31, 2016	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014	Sep. 30, 2012	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Apr. 28, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based incentive compensation expense (in dollars)										$ 2,087	$ 2,131	$ 1,538
Blueknight Energy Partners G.P., L.L.C. Long-Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of units authorized		4,100,000								4,100,000			2,600,000
Blueknight Energy Partners G.P., L.L.C. Long-Term Incentive Plan [Member] | Phantom Share Units (PSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized estimated compensation cost (in dollars)		$ 1,800								$ 1,800
Equity-based incentive compensation expense (in dollars)										$ 2,500	$ 2,700	$ 2,300
Number of Units [Roll Forward]
Number of Units, Nonvested, Beginning balance	915,180									915,541
Number of Units, Granted										447,261
Number of Units, Vested										347,193
Number of Units, Forfeited										100,429
Number of Units, Nonvested, Ending balance		915,180			915,541					915,180	915,541
Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value, Nonvested, Beginning balance (in dollars per unit)	$ 6.61									$ 7.81
Weighted Average Grant Date Fair Value, Granted (in dollars per unit)										4.89
Weighted Average Grant Date Fair Value, Vested (in dollars per unit)										7.55
Weighted Average Grant Date Fair Value, Forfeited (in dollars per unit)										6.72
Weighted Average Grant Date Fair Value, Nonvested, Ending balance (in dollars per unit)		$ 6.61			$ 7.81					$ 6.61	$ 7.81
Blueknight Energy Partners G.P., L.L.C. Long-Term Incentive Plan [Member] | Phantom Share Units (PSUs) [Member] | Chief Executive Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period									5 years
Value of award grants (in dollars)									$ 2,800
Unrecognized estimated compensation cost (in dollars)		$ 400								$ 400
Number of Units [Roll Forward]
Number of Units, Granted									500,000
Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value, Granted (in dollars per unit)									$ 5.62
Blueknight Energy Partners G.P., L.L.C. Long-Term Incentive Plan [Member] | Phantom Share Units (PSUs) [Member] | Vesting Period One [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Value of award grants (in dollars)								$ 2,508
Number of Units [Roll Forward]
Number of Units, Granted								276,773
Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value, Granted (in dollars per unit)								$ 9.06
Blueknight Energy Partners G.P., L.L.C. Long-Term Incentive Plan [Member] | Phantom Share Units (PSUs) [Member] | Vesting Period One [Member] | Subsequent Event [Member]
Number of Units [Roll Forward]
Number of Units, Vested	213,923
Blueknight Energy Partners G.P., L.L.C. Long-Term Incentive Plan [Member] | Phantom Share Units (PSUs) [Member] | Vesting Period Two [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Value of award grants (in dollars)						$ 2,059
Number of Units [Roll Forward]
Number of Units, Granted						266,076
Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value, Granted (in dollars per unit)						$ 7.74
Blueknight Energy Partners G.P., L.L.C. Long-Term Incentive Plan [Member] | Phantom Share Units (PSUs) [Member] | Vesting Period Three [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Value of award grants (in dollars)			$ 58	$ 1,985
Number of Units [Roll Forward]
Number of Units, Granted			9,960	416,131
Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value, Granted (in dollars per unit)			$ 5.85	$ 4.77
Blueknight Energy Partners G.P., L.L.C. Long-Term Incentive Plan [Member] | Restricted common units [Member] | Independent Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period										3 years
Value of award grants (in dollars)		$ 75			$ 77		$ 48
Number of Units [Roll Forward]
Number of Units, Granted		10,950			15,120		7,500
Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value, Granted (in dollars per unit)		$ 6.85			$ 5.06		$ 6.43
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost										$ 100
Blueknight Energy Partners G.P., L.L.C. Long-Term Incentive Plan [Member] | Common Stock [Member] | Independent Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Value of award grants (in dollars)		$ 100
Number of Units [Roll Forward]
Number of Units, Granted		10,220

EMPLOYEE BENEFIT PLAN (Details)

EMPLOYEE BENEFIT PLAN (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Contribution Pension [Member]
Defined Contribution Plan Disclosure [Line Items]
Employer discretionary contribution amount	$ 1.2	$ 1.5	$ 1.5
Deferred Profit Sharing [Member]
Defined Contribution Plan Disclosure [Line Items]
Employer discretionary contribution amount	$ 0.8	$ 0.9	$ 0.9

PROFITS INTEREST OF BLUEKNIGH63

PROFITS INTEREST OF BLUEKNIGHT GP HOLDING, LLC (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Chief Executive Officer [Member]
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Chief Executive Officer Non Voting Economic Interest In Company, Amount Recognized During Period	$ 0.9	$ 0.1	$ 0.1

COMMITMENTS AND CONTINGENCIES64

COMMITMENTS AND CONTINGENCIES (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Operating Leases, Rent Expense	$ 6.5	$ 9.5	$ 8.4

COMMITMENTS AND CONTINGENCIES O

COMMITMENTS AND CONTINGENCIES Operating Leases (Details) $ in Thousands	Dec. 31, 2016USD ($)
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$ 5,087
Operating Leases, Future Minimum Payments, Due in Three Years	4,307
Operating Leases, Future Minimum Payments, Due in Four Years	3,042
Operating Leases, Future Minimum Payments, Due in Five Years	1,494
Operating Leases, Future Minimum Payments, Due in Five Years	746
Operating Leases, Future Minimum Payments, Due Thereafter	1,630
Operating Leases, Future Minimum Payments Due	$ 16,306

ENVIRONMENTAL REMEDIATION (Deta

ENVIRONMENTAL REMEDIATION (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Accrual for Environmental Loss Contingencies Disclosure [Abstract]
Accrual for Environmental Loss Contingencies	$ 0	$ 0.1

FAIR VALUE MEASUREMENTS Fair 67

FAIR VALUE MEASUREMENTS Fair Value Measurement (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate swap liabilities	$ 1,947	$ 3,103
Total	1,947	3,103
Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate swap liabilities	0	0
Total	0	0
Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate swap liabilities	1,947	3,103
Total	1,947	3,103
Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate swap liabilities	0	0
Total	$ 0	$ 0

OPERATING SEGMENTS (Details)

OPERATING SEGMENTS (Details) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016USD ($)StatesTerminalling_And_Storage_Facilities	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2016USD ($)Operating-segmentsStatesTerminalling_And_Storage_Facilities	Dec. 31, 2016USD ($)StatesTerminalling_And_Storage_Facilities	Dec. 31, 2016USD ($)StatesTerminalling_And_Storage_Facilities	Dec. 31, 2016USD ($)StatesTerminalling_And_Storage_FacilitiesPipeline_Systems	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Segment Reporting Information [Line Items]
Number of Operating Segments									4		4
Service revenue
Third party revenue										$ 126,215			$ 137,415	$ 139,426
Related party revenue										30,211			39,103	42,788
Intersegment Revenues										(1,316)			(259)	0
Product sales revenue:
Third party revenue										20,968			3,511	4,412
Total revenue for reportable segments	$ 46,021	$ 46,939	$ 43,425	$ 41,009	$ 43,882	$ 47,217	$ 46,574	$ 42,356		177,394			180,029	186,626
Cost of product sales										14,130			3,231	61
Operating margin (excluding depreciation and amortization)										82,993			76,052	78,426
Total assets (end of period)	375,663				364,746				$ 375,663	375,663	$ 375,663	$ 375,663	364,746
Reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes
Operating margin (excluding depreciation and amortization)										82,993			76,052	78,426
Depreciation and amortization										(30,820)			(27,228)	(26,045)
General and administrative expenses										(20,029)			(18,976)	(17,498)
Asset impairment expense										(25,761)			(21,996)	0
Gain on sale of assets										108			6,137	2,464
Equity loss in unconsolidated affiliate										1,483			3,932	883
Interest expense										12,554			11,202	12,268
Unrealized gains on investments										0			0	2,079
Income (Loss) before Income Taxes										(4,580)			6,719	28,041
Crude Oil Terminalling and Storage Services [Member]
Service revenue
Third party revenue										16,387			13,076	9,258
Related party revenue										7,858			11,522	13,524
Product sales revenue:
Total revenue for reportable segments										24,245			24,598	22,782
Operating expense (excluding depreciation and amortization)										4,197			5,756	3,964
Operating margin (excluding depreciation and amortization)										20,048			18,842	18,818
Property, Plant and Equipment, Additions										2,126			3,282	8,551
Total assets (end of period)	71,689				73,502				71,689	71,689	71,689	$ 71,689	73,502	69,469
Reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes
Operating margin (excluding depreciation and amortization)										20,048			18,842	18,818
Crude Oil Pipeline Services [Member]
Segment Reporting Information [Line Items]
Number of Pipelines Systems Owned And Operated | Pipeline_Systems												2
Service revenue
Third party revenue										8,662			15,148	13,834
Related party revenue										5,433			10,687	8,381
Product sales revenue:
Third party revenue										20,968			3,511	4,190
Total revenue for reportable segments										35,063			29,346	26,405
Operating expense (excluding depreciation and amortization)										15,270			18,162	15,948
Inter-segment Operating Expenses										890			259	0
Cost of product sales										14,130			3,231	0
Inter-Segment Cost of Purchased Oil and Gas										426			0	0
Operating margin (excluding depreciation and amortization)										4,347			7,694	10,457
Property, Plant and Equipment, Additions										8,250			34,953	20,970
Total assets (end of period)	150,043				175,142				150,043	150,043	150,043	$ 150,043	175,142	184,933
Reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes
Operating margin (excluding depreciation and amortization)										4,347			7,694	10,457
Crude Oil Trucking and Producer Field Services [Member]
Service revenue
Third party revenue										25,511			37,039	50,061
Related party revenue										5,158			15,616	19,764
Intersegment Revenues										890			259	0
Product sales revenue:
Third party revenue										0			0	222
InterSegment Sales Revenue										426			0	0
Total revenue for reportable segments										31,985			52,914	70,047
Operating expense (excluding depreciation and amortization)										30,156			51,610	62,140
Operating margin (excluding depreciation and amortization)										1,829			1,304	7,907
Property, Plant and Equipment, Additions										2,558			4,556	1,081
Total assets (end of period)	$ 12,651				17,256				$ 12,651	12,651	$ 12,651	$ 12,651	17,256	17,365
Reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes
Operating margin (excluding depreciation and amortization)										$ 1,829			1,304	7,907
Asphalt Services [Member]
Segment Reporting Information [Line Items]
Number Of Asphalt Terminalling And Storage Facilities | Terminalling_And_Storage_Facilities	54								54	54	54	54
Number of states where Asphalt terminalling and storage are located | States	26								26	26	26	26
Service revenue
Third party revenue										$ 75,655			72,152	66,273
Related party revenue										11,762			1,278	1,119
Product sales revenue:
Total revenue for reportable segments										87,417			73,430	67,392
Operating expense (excluding depreciation and amortization)										30,648			25,218	26,148
Operating margin (excluding depreciation and amortization)										56,769			48,212	41,244
Property, Plant and Equipment, Additions										148,622			19,769	6,766
Total assets (end of period)	$ 141,280				$ 98,848				$ 141,280	141,280	$ 141,280	$ 141,280	98,848	92,628
Reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes
Operating margin (excluding depreciation and amortization)										56,769			48,212	41,244
Operating Segments [Member]
Product sales revenue:
Total revenue for reportable segments										$ 178,710			$ 180,288	$ 186,626

INCOME TAXES (Details)

INCOME TAXES (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)
Income Tax Disclosure [Abstract]
Percent of Qualifying Income, minimum	90.00%
Federal statutory income tax rate (as a percent)	35.00%
Difference in bases of property, plant and equipment	$ 844
Deferred tax asset	844
Less: valuation allowance	(844)
Net deferred tax asset	$ 0

QUARTERLY FINANCIAL DATA (Detai

QUARTERLY FINANCIAL DATA (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 Data [Abstract]
Revenues	$ 46,021	$ 46,939	$ 43,425	$ 41,009	$ 43,882	$ 47,217	$ 46,574	$ 42,356	$ 177,394	$ 180,029	$ 186,626
Operating Income (Loss)	3,428	13,398	(15,348)	5,013	(16,802)	17,010	8,484	5,297	6,491	13,989	37,347
Net income (loss)	$ 1,951	$ 11,419	$ (18,936)	$ 726	$ (16,860)	$ 13,967	$ 7,710	$ 1,579	$ (4,840)	$ 6,396	$ 27,572
Basic net income (loss) per common unit	$ (0.18)	$ 0.13	$ (0.71)	$ (0.14)	$ (0.65)	$ 0.24	$ 0.06	$ (0.12)	$ (0.87)	$ (0.47)	$ 0.20
Diluted net income (loss) per common unit	$ (0.18)	$ 0.13	$ (0.71)	$ (0.14)	$ (0.65)	$ 0.21	$ 0.06	$ (0.12)	$ (0.87)	$ (0.47)	$ 0.20