10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x QuarterlyReport Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended June 30, 2018

OR 

o TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________ to _________

Commission File Number 001-33503

BLUEKNIGHT ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)	20-8536826 (IRS Employer Identification No.)
201 NW 10th, Suite 200 Oklahoma City, Oklahoma 73103 (Address of principal executive offices, zip code) Registrant’s telephone number, including area code: (405) 278-6400

(Former name, former address and former fiscal year, if changed since last report)

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

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

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

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

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

As of July 26, 2018, there were 35,125,202 Series A Preferred Units and 40,387,006 common units outstanding.   

Table of Contents
		Page
PART I	FINANCIAL INFORMATION	1
Item 1.	Unaudited Condensed Consolidated Financial Statements	1
	Condensed Consolidated Balance Sheets as of December 31, 2017, and June 30, 2018	1
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2017 and 2018	2
	Condensed Consolidated Statement of Changes in Partners’ Capital (Deficit) for the Six Months Ended June 30, 2018	3
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2017 and 2018	4
	Notes to the Unaudited Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	36
Item 4.	Controls and Procedures	36
PART II	OTHER INFORMATION	37
Item 1.	Legal Proceedings	37
Item 1A.	Risk Factors	37
Item 5.	Other Information	37
Item 6.	Exhibits	37

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PART I. FINANCIAL INFORMATION

Item 1.    Unaudited Condensed Consolidated Financial Statements

BLUEKNIGHT ENERGY PARTNERS, L.P. CONDENSED CONSOLIDATED BALANCE SHEETS (in thousands, except unit data)
	As of			As of
	December 31, 2017			June 30, 2018
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	2,469		$	1,193
Accounts receivable, net of allowance for doubtful accounts of $28 and $29 at December 31, 2017 and June 30, 2018, respectively	7,589			31,268
Receivables from related parties, net of allowance for doubtful accounts of $0 at both dates	3,070			1,219
Prepaid insurance	2,009			2,093
Other current assets	8,438			12,716
Total current assets	23,575			48,489
Property, plant and equipment, net of accumulated depreciation of $316,591 and $269,978 at December 31, 2017 and June 30, 2018, respectively	296,069			295,711
Assets held for sale, net of accumulated depreciation of $55,583 at June 30, 2018	—			16,857
Goodwill	3,870			6,728
Debt issuance costs, net	4,442			3,802
Intangibles and other assets, net	12,913			18,919
Total assets	$	340,869		$	390,506
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	4,439		$	5,244
Accounts payable to related parties	2,268			12,878
Accrued interest payable	694			644
Accrued property taxes payable	2,432			3,365
Unearned revenue	2,393			2,039
Unearned revenue with related parties	551			4,384
Accrued payroll	6,119			3,671
Other current liabilities	4,747			17,379
Total current liabilities	23,643			49,604
Long-term unearned revenue with related parties	1,052			960
Other long-term liabilities	3,673			3,715
Long-term interest rate swap liabilities	225			—
Long-term debt	307,592			349,592
Commitments and contingencies (Note 15)
Partners’ capital:
Common unitholders (40,158,342 and 40,326,571 units issued and outstanding at December 31, 2017 and June 30, 2018, respectively)	454,358			436,416
Preferred Units (35,125,202 units issued and outstanding at both dates)	253,923			253,923
General partner interest (1.6% interest with 1,225,409 general partner units outstanding at both dates)	(703,597		)	(703,704		)
Total partners’ capital	4,684			(13,365		)
Total liabilities and partners’ capital	$	340,869		$	390,506

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

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BLUEKNIGHT ENERGY PARTNERS, L.P. CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per unit data)
	Three Months ended June 30,						Six Months ended June 30,
	2017			2018			2017			2018
	(unaudited)
Service revenue:
Third-party revenue	$	28,145		$	14,103		$	56,808		$	31,421
Related-party revenue	13,505			6,063			27,147			12,384
Lease revenue:
Third-party revenue	—			10,237			—			20,041
Related-party revenue	—			7,475			—			15,178
Product sales revenue:
Third-party revenue	2,227			45,615			6,262			49,129
Total revenue	43,877			83,493			90,217			128,153
Costs and expenses:
Operating expense	30,610			28,988			62,516			60,123
Third-party cost of product sales	1,669			20,041			4,808			22,678
Related-party cost of product sales	—			23,747			—			23,747
General and administrative expense	4,322			4,486			8,907			8,707
Asset impairment expense	17			—			45			616
Total costs and expenses	36,618			77,262			76,276			115,871
Gain (loss) on sale of assets	(754		)	599			(879		)	363
Operating income	6,505			6,830			13,062			12,645
Other income (expenses):
Equity earnings in unconsolidated affiliate	—			—			61			—
Gain on sale of unconsolidated affiliate	4,172			—			4,172			2,225
Interest expense (net of capitalized interest of $3, $43, $5 and $72, respectively)	(4,265		)	(5,024		)	(7,295		)	(8,593		)
Income before income taxes	6,412			1,806			10,000			6,277
Provision for income taxes	41			21			87			50
Net income	$	6,371		$	1,785		$	9,913		$	6,227
Allocation of net income for calculation of earnings per unit:
General partner interest in net income	$	256		$	28		$	465		$	259
Preferred interest in net income	$	6,279		$	6,279		$	12,558		$	12,557
Net loss available to limited partners	$	(164	)	$	(4,522	)	$	(3,110	)	$	(6,589	)
Basic and diluted net loss per common unit	$	—		$	(0.11	)	$	(0.08	)	$	(0.16	)
Weighted average common units outstanding - basic and diluted	38,155			40,324			38,151			40,306

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

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BLUEKNIGHT ENERGY PARTNERS, L.P. CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL (DEFICIT) (in thousands)
	Common Unitholders			Series A Preferred Unitholders			General Partner Interest			Total Partners’ Capital (Deficit)
	(unaudited)
Balance, December 31, 2017	$	454,358		$	253,923		$	(703,597	)	$	4,684
Net income (loss)	(6,745		)	12,557			415			6,227
Equity-based incentive compensation	669			—			18			687
Distributions	(11,958		)	(12,557		)	(723		)	(25,238		)
Capital contributions	—			—			183			183
Proceeds from sale of 21,246 common units pursuant to the Employee Unit Purchase Plan	92			—			—			92
Balance, June 30, 2018	$	436,416		$	253,923		$	(703,704	)	$	(13,365	)

The accompanying notes are an integral part of this unaudited condensed consolidated financial statement.

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BLUEKNIGHT ENERGY PARTNERS, L.P. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands)
	Six Months ended June 30,
	2017			2018
	(unaudited)
Cash flows from operating activities:
Net income	$	9,913		$	6,227
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for uncollectible receivables from third parties	(12		)	1
Depreciation and amortization	15,905			14,779
Amortization and write-off of debt issuance costs	1,307			949
Unrealized gain related to interest rate swaps	(975		)	(314		)
Intangible asset impairment charge	—			189
Fixed asset impairment charge	45			427
Loss (gain) on sale of assets	879			(363		)
Gain on sale of unconsolidated affiliate	(4,172		)	(2,225		)
Equity-based incentive compensation	524			687
Equity earnings in unconsolidated affiliate	(61		)	—
Changes in assets and liabilities:
Increase in accounts receivable	(1,785		)	(23,680		)
Decrease in receivables from related parties	326			1,851
Decrease in prepaid insurance	1,194			1,494
Decrease (increase) in other current assets	148			(2,920		)
Decrease in other non-current assets	111			90
Increase (decrease) in accounts payable	183			(502		)
Increase in payables to related parties	156			10,504
Increase (decrease) in accrued interest payable	316			(50		)
Increase in accrued property taxes	232			933
Increase (decrease) in unearned revenue	1,352			(346		)
Increase in unearned revenue from related parties	3,953			3,679
Decrease in accrued payroll	(2,017		)	(2,448		)
Increase (decrease) in other accrued liabilities	(961		)	12,113
Net cash provided by operating activities	26,561			21,075
Cash flows from investing activities:
Acquisitions	—			(21,959		)
Capital expenditures	(10,331		)	(22,125		)
Proceeds from sale of assets	8,474			3,893
Proceeds from sale of unconsolidated affiliate	25,324			2,225
Net cash provided by (used in) investing activities	23,467			(37,966		)
Cash flows from financing activities:
Payment on insurance premium financing agreement	(1,271		)	(1,113		)
Debt issuance costs	(4,017		)	(309		)
Borrowings under credit agreement	335,592			113,000
Payments under credit agreement	(356,000		)	(71,000		)
Proceeds from equity issuance	84			92
Capital contributions	104			183
Distributions	(24,550		)	(25,238		)
Net cash provided by (used in) financing activities	(50,058		)	15,615
Net decrease in cash and cash equivalents	(30		)	(1,276		)
Cash and cash equivalents at beginning of period	3,304			2,469
Cash and cash equivalents at end of period	$	3,274		$	1,193
Supplemental disclosure of non-cash financing and investing cash flow information:
Non-cash changes in property, plant and equipment	$	1,545		$	294
Increase in accrued liabilities related to insurance premium financing agreement	$	2,281		$	1,578

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

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BLUEKNIGHT ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1.    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 27 states. The Partnership provides integrated terminalling, gathering, transportation and marketing 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 services, (iii) crude oil pipeline services and (iv) crude oil trucking services. On April 24, 2018, the Partnership sold the producer field services business. As a result of the sale of the producer field services business, the Partnership changed the name of the crude oil trucking and producer field services operating segment to crude oil trucking services during the second quarter of 2018. See Note 6 for additional information. 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 February2007 as a Delaware master limited partnership initially to own, operate and develop a diversified portfolio of complementary midstream energy assets.

2.    BASIS OF CONSOLIDATION AND PRESENTATION

The financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).  The condensed consolidated balance sheet as of June 30, 2018, the condensed consolidated statements of operations for the three and six months ended June 30,2017 and 2018, the condensed consolidated statement of changes in partners’ capital (deficit) for the six months ended June 30,2018 and the condensed consolidated statements of cash flows for the six months ended June 30,2017 and 2018, are unaudited.  In the opinion of management, the unaudited condensed consolidated financial statements have been prepared on the same basis as the audited financial statements and include all adjustments necessary to state fairly the financial position and results of operations for the respective interim periods.  All adjustments are of a recurring nature unless otherwise disclosed herein.  The 2017 year-end condensed consolidated balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP.  These unaudited condensed consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes thereto included in the Partnership’s annual report on Form 10-K for the year ended December 31, 2017, filed with the Securities and Exchange Commission (the “SEC”) on March 8, 2018 (the “2017 Form 10-K”).  Interim financial results are not necessarily indicative of the results to be expected for an annual period.  The Partnership’s significant accounting policies are consistent with those disclosed in Note 3 of the Notes to Consolidated Financial Statements in its 2017 Form 10-K.

The Partnership’s investment in Advantage Pipeline, L.L.C. (“Advantage Pipeline”), over which the Partnership had significant influence but not control, was accounted for by the equity method. The Partnership did not consolidate any part of the assets or liabilities of its equity investee. The Partnership’s share of net income or loss is reflected as one line item on the Partnership’s unaudited condensed consolidated statements of operations entitled “Equity earnings in unconsolidated affiliate” and increased or decreased, as applicable, the carrying value of the Partnership’s “Investment in unconsolidated affiliate” on the unaudited condensed consolidated balance sheets. Distributions to the Partnership reduced the carrying value of its investment and, to the extent received, were reflected in the Partnership’s unaudited condensed consolidated statements of cash flows in the line item “Distributions from unconsolidated affiliate.” Contributions increased the carrying value of the Partnership’s investment and were reflected in the Partnership’s unaudited condensed consolidated statements of cash flows in investing activities. On April 3, 2017, the Partnership sold its investment in Advantage Pipeline. See Note 5 for additional information.

3.    REVENUE

Revenue from Contracts with Customers

On January 1, 2018, the Partnership adopted the new accounting standard ASC 606 - Revenue from Contracts with Customers and all related amendments (“new revenue standard”) using the modified retrospective method, and as a result applied the new guidance only to contracts that are not completed at the adoption date. Results for reporting periods beginning on January 1, 2018, are presented under the new revenue standard, while prior period amounts are not adjusted and continue to be reported in accordance with the Partnership’s historic accounting under ASC 605 - Revenue Recognition.

The majority of the Partnership’s service revenue continues to be recognized as services are performed. Under the new revenue standard, the timing of revenue recognition on variable throughput fees will change, within a single reporting year, compared to the previous recognition.  The effect will be straight-line recognition of unconstrained estimated annual throughput

5

volumes over each contract year.  See further discussion on variable throughput fees below. In addition, as a result of the adoption of the new revenue standard, revenue from leases is required to be presented separately from revenue from customers. As the Partnership applied the modified retrospective method, prior periods have not been reclassified.

Upon adoption of the new revenue standard, there was no cumulative adjustment to the balance sheet at January 1, 2018. Adoption of the new revenue standard resulted in recognition of an additional $0.2 million and $0.3 million of “Service revenue - Third-party revenue” in the unaudited condensed consolidated statements of operations for the three and six months ended June 30,2018, respectively, and additional “Accounts receivable” of $0.3 million on the unaudited condensed consolidated balance sheet as of June 30, 2018, over what would have been recorded under ASC 605. While some revenue under storage, throughput and handling contracts in the asphalt terminalling segment will shift between quarters within a fiscal year, the impact of adoption of the new revenue standard is not expected to be material to net income on an ongoing basis because the analysis of contracts under the new revenue standard supports the recognition of revenue as services are performed, which is consistent with the previous revenue recognition model.

There are two types of contracts in the asphalt terminalling segment: (i) operating lease contracts, under which customers operate the facilities, and (ii) storage, throughput and handling contracts, under which the Partnership operates the facilities. The operating lease contracts are accounted for in accordance with ASC 840 - Leases. The storage, throughput and handling contracts contain both lease revenue and non-lease service revenue. In accordance with ASC 840 and 606, fixed consideration is allocated to the lease and service components based on their relative stand-alone selling price. The stand-alone selling price of the lease component is calculated using the average internal rate of return under the operating lease agreements. The stand-alone selling price of the service component is calculated by applying an appropriate margin to the expected costs to operate the facility. The service component contains a single performance obligation that consists of a stand-ready obligation to perform activities as directed by the customer. Revenue is recognized on a straight-line basis over time as the customer receives and consumes benefits. Fixed consideration, consisting of the monthly storage and handling fees, is billed a month prior to the performance of services and is due by the first day of the month of service. Payments received in advance of the month of service are recorded as unearned revenue (contract liability) until the service is performed.

Asphalt storage, throughput and handling contracts also contain variable consideration in the form of reimbursements of utility, fuel and power expenses and throughput fees. Utility, fuel and power reimbursements are allocated entirely to the service component of the contracts. Utility, fuel and power reimbursements relate directly to the distinct monthly service that makes up the overall performance obligation and revenue is recognized in the period in which the service takes place. Variable consideration related to reimbursements of utility, fuel and power expenses is billed in the month subsequent to the period of service, and payment is due within 30 days of billing. Throughput fees are allocated to both the lease and service component of the contracts using the allocation percentages from contract inception. Total throughput fees are estimated at contract inception and updated at the beginning of each reporting period based on historical trends, current year throughput activities at the facilities, and analysis with customers regarding expectations for the current year. This consideration can be constrained when there is a lack of historical data or other uncertainties exist regarding expected throughput volumes. The service component of throughput fees is recognized on a straight-line basis over time as the customer receives and consumes benefits. In accordance with ASC 840, the lease component of variable throughput fees is recognized in the period when the changes in facts and circumstances on which the variable payment is based occur. Fees related to actual throughput are billed in the month subsequent to the period of movement, which can result in the recognition of un-billed accounts receivable (contract assets) when there is a variance in the straight-line revenue recognition and actual throughput fees billed. Payment on variable throughput consideration is due within 30 days of billing. Changes in estimated throughput fees affect the total transaction price and will be recorded as an adjustment to revenue in the period in which the change is identified. The Partnership recorded a $0.1 million adjustment related to changes in estimated throughput fees for both the three and six months ended June 30,2018.

Certain asphalt storage, throughput and handling contracts contain provisions for reimbursement of specified major maintenance costs above a specified threshold over the life of the contract. Reimbursements of specified major maintenance costs are allocated to both the lease and service component of the contracts using the allocation percentages from contract inception. Reimbursements of specified major maintenance costs are reviewed and paid quarterly, which may result in overpayments that must be paid back to the customer in future years. As such, the service component of this consideration is constrained and recorded in unearned revenue (contract liability) until facts and circumstances indicate it is probable that the minimum threshold will be met. In the event the minimum threshold is not met, the Partnership will return the reimbursement to the customer.

As of June 30, 2018, the Partnership has performance obligations satisfied over time under asphalt storage, throughput and handling contracts that are wholly or partially unsatisfied. The revenue related to these performance obligations will be recognized as follows (in thousands):

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Revenue Related to Future Performance Obligations Due by Period(1)
Less than 1 year	$	35,257
1-3 years	64,767
4-5 years	46,024
More than 5 years	13,591
Total revenue related to future performance obligations	$	159,639

____________________

(1) Excluded from the table is revenue that is either constrained or related to performance obligations that are wholly unsatisfied as of June 30, 2018.

Crude oil terminalling services contracts can be either short- or long-term written contracts. The contracts contain a single performance obligation that consists of a series of distinct services provided over time. Customers are billed a month prior to the performance of terminalling services and payment is due by the first day of the month of service. Payments received in advance of the month of service are recorded as unearned revenue (contract liability) until the service is performed. These contracts also contain provisions under which customers are invoiced for product throughput in the month following the month in which the service is provided. Payment on product throughput is due within 30 days. The Partnership has elected to use the right-to-invoice expedient on crude oil terminalling services contracts as the right to consideration corresponds directly with the value to the customer of performance completed to date.

There are primarily two types of contracts in the crude oil pipeline segment: (i) monthly transportation contracts and (ii) product sales contracts.

Under crude oil pipeline services monthly transportation contracts, customers submit nominations for transportation monthly and a contract is created upon the Partnership’s acceptance of the nomination under its published tariffs. Crude oil pipeline services contracts have a single performance obligation to perform the transportation service. The transportation service is provided to the customer in the same month in which the customer makes the related nomination. Revenue is recorded in the month of service and invoiced in the following month. Payment is due within 30 days. The Partnership has elected to use the right-to-invoice expedient on crude oil pipeline services contracts as the right to consideration corresponds directly with the value to the customer of performance completed to date.

The Partnership also purchases crude oil and resells to third parties under written product sales contracts. Product sales contracts have a single performance obligation, and revenue is recognized at the point in time that control is transferred to the customer. Control is considered transferred to the customer on the day of the sale. Revenue is recorded in the month of service and invoiced in the following month. Payment is due within 30 days. The Partnership has elected to use the right-to-invoice expedient on product sales contracts as the right to consideration corresponds directly with the value to the customer of performance completed to date.

Services in the crude oil trucking segment are provided under master service agreements with customers that include rate sheets. Contracts are initiated when a customer requests service and both parties are committed upon the Partnership’s acceptance of the customer’s request. Crude oil trucking contracts have a single performance obligation to perform the service, which is completed in a day. Revenue is recorded in the month of service and invoiced in the following month. Payment is due within 30 days. The Partnership has elected to use the right-to-invoice expedient on crude oil trucking revenues as the right to consideration corresponds directly with the value to the customer of performance completed to date.

Disaggregation of Revenue

Disaggregation of revenue from contracts with customers for each operating segment by revenue type is presented as follows (in thousands):

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	Three Months ended June 30, 2018
	Asphalt  Terminalling Services		Crude Oil Terminalling Services		Crude Oil Pipeline Services		Crude Oil Trucking Services		Total
Third-party revenue:
Fixed storage, throughput and other revenue	$	4,622	$	2,767	$	—	$	—	$	7,389
Variable throughput revenue	242		143		—		—		385
Variable reimbursement revenue	1,775		—		—		—		1,775
Crude oil transportation revenue	—		—		1,045		3,509		4,554
Crude oil product sales revenue	—		—		45,612		3		45,615
Related-party revenue:
Fixed storage, throughput and other revenue	4,632		—		48		—		4,680
Variable reimbursement revenue	1,349		—		34		—		1,383
Total revenue from contracts with customers	$	12,620	$	2,910	$	46,739	$	3,512	$	65,781

	Six Months ended June 30, 2018
	Asphalt  Terminalling Services		Crude Oil Terminalling Services		Crude Oil Pipeline Services		Crude Oil Trucking Services		Total
Third-party revenue:
Fixed storage, throughput and other revenue	$	8,171	$	6,849	$	—	$	—	$	15,020
Variable throughput revenue	359		647		—		—		1,006
Variable reimbursement revenue	3,241		—		—		—		3,241
Crude oil transportation revenue	—		—		3,105		9,049		12,154
Crude oil product sales revenue	—		—		49,120		9		49,129
Related-party revenue:
Fixed storage, throughput and other revenue	9,263		—		48		—		9,311
Variable reimbursement revenue	3,039		—		34		—		3,073
Total revenue from contracts with customers	$	24,073	$	7,496	$	52,307	$	9,058	$	92,934

Contract Balances

The timing of revenue recognition, billings and cash collections result in billed accounts receivable, un-billed accounts receivable (contract assets) and unearned revenue (contract liabilities) on the unaudited condensed consolidated balance sheet as noted in the contract discussions above. Accounts receivable and un-billed accounts receivable are both reflected in the line items “Accounts receivable” and “Receivables from related parties” on the unaudited condensed consolidated balance sheet. Unearned revenue is included in the line items “Unearned revenue,” “Unearned revenue with related parties,” “Long-term unearned revenue with related parties” and “Other long-term liabilities” on the unaudited condensed consolidated balance sheet.

Billed accounts receivable from contracts with customers were $8.5 million and $27.9 million at December 31, 2017, and June 30, 2018, respectively.

Un-billed accounts receivable from contracts with customers were $0.3 million at June 30, 2018. There were no un-billed accounts receivable at December 31, 2017.

The Partnership records unearned revenues when cash payments are received in advance of performance. Unearned revenue related to contracts with customers was $3.7 million and $4.6 million at December 31, 2017, and June 30, 2018, respectively. The change in the unearned revenue balance for the six months ended June 30,2018, is driven by $2.5 million in cash payments received in advance of satisfying performance obligations, partially offset by $1.6 million of revenues recognized that were included in the unearned revenue balance at the beginning of the period.

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Practical Expedients and Exemptions

The Partnership does not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less and (ii) contracts for which revenue is recognized at the amount to which the Partnership has the right to invoice for services performed. The Partnership is using the right-to-invoice practical expedient on all contracts with customers in its crude oil terminalling services, crude oil pipeline services and crude oil trucking services segments.

4.     RESTRUCTURING CHARGES

During the fourth quarter of 2015, the Partnership recognized certain restructuring charges in its crude oil trucking services segment pursuant to an approved plan to exit the trucking market in West Texas. The restructuring charges included an accrual related to leased vehicles that were idled as part of the restructuring plan. This accrual was being amortized over the remaining lease term of the vehicles. In June 2018, the Partnership purchased the vehicles off lease and resold them to a third party, paying off the remaining liability.

Changes in the accrued amounts pertaining to the restructuring charges are summarized as follows (in thousands):

	Three Months ended June 30,				Six Months ended June 30,
	2017		2018		2017		2018
Beginning balance	$	428	$	237	$	474	$	286
Cash payments	46		237		92		286
Ending balance	$	382	$	—	$	382	$	—

5.    EQUITY METHOD INVESTMENT

On April 3, 2017, Advantage Pipeline was acquired by a joint venture formed by affiliates of Plains All American Pipeline, L.P. and Noble Midstream Partners LP. The Partnership received cash proceeds at closing from the sale of its approximate 30% equity ownership interest in Advantage Pipeline of approximately $25.3 million and recorded a gain on the sale of the investment of $4.2 million. Approximately 10% of the gross sale proceeds were held in escrow, subject to certain post-closing settlement terms and conditions. The Partnership received approximately $1.1 million of the funds held in escrow in August 2017, and approximately $2.2 million for its pro rata portion of the remaining net escrow proceeds in January 2018. The Partnership’s proceeds were used to prepay revolving debt (without a commitment reduction). The operating and administrative services agreement to which the Partnership and Advantage Pipeline were parties and under which the Partnership operated the 70-mile, 16-inch Advantage crude oil pipeline, located in the southern Delaware Basin in Texas, was terminated at closing. The Partnership and the Plains/Noble joint venture entered into a short-term transition services agreement under which the Partnership provided certain services through August 1, 2017.

Summarized financial information for Advantage Pipeline is set forth in the tables below for the period indicated in which the Partnership held the investment in Advantage Pipeline (in thousands):

	Period ended April 3, 2017
Income Statement
Operating revenues	$	3,150
Operating expenses	$	465
Net income	$	187

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6.    PROPERTY, PLANT AND EQUIPMENT

	Estimated Useful Lives (Years)	December 31, 2017			June 30, 2018
		(dollars in thousands)
Land	N/A	$	24,776		$	25,067
Land improvements	10-20	6,787			5,815
Pipelines and facilities	5-30	166,004			167,624
Storage and terminal facilities	10-35	370,056			319,344
Transportation equipment	3-10	3,293			1,056
Office property and equipment and other	3-20	32,011			26,958
Pipeline linefill and tank bottoms	N/A	3,233			11,694
Construction-in-progress	N/A	6,500			8,131
Property, plant and equipment, gross		612,660			565,689
Accumulated depreciation		(316,591		)	(269,978		)
Property, plant and equipment, net		$	296,069		$	295,711

Depreciation expense for the three months ended June 30,2017 and 2018, was $7.5 million and $6.7 million, respectively. Depreciation expense for the six months ended June 30,2017 and 2018, was $15.3 million and $13.7 million, respectively.

In April 2018, the Partnership sold its producer field services business. The Partnership received cash proceeds at closing of approximately $3.0 million and recorded a gain of $0.4 million. The sale of the producer field services business does not qualify as discontinued operations as it does not represent a strategic shift that will have a major effect on the Partnership’s operations or financial results.

In March 2018, the Partnership acquired an asphalt terminalling facility in Oklahoma from a third party for approximately $22.0 million, consisting of property, plant and equipment of $11.5 million, intangible assets of $7.6 million and goodwill of $2.9 million.

On December 1, 2017, the Partnership issued 1.9 million common units to Ergon in a private placement valued at $10.2 million in exchange for an asphalt terminalling facility in Bainbridge, Georgia.

In April 2017, the Partnership sold its East Texas pipeline system. The Partnership received cash proceeds at closing of approximately $4.8 million and recorded a gain of less than $0.1 million. The Partnership used the proceeds received at closing to prepay revolving debt (without a commitment reduction).

7.    DEBT

On May 11, 2017, the Partnership entered into an amended and restated credit agreement. On June 28, 2018, the credit agreement was amended to, among other things, reduce the revolving loan facility from $450.0 million to $400.0 million and amend the maximum permitted consolidated total leverage ratio as discussed below.

As of July 26, 2018, approximately $263.6 million of revolver borrowings and $3.4 million of letters of credit were outstanding under the credit agreement, leaving the Partnership with approximately $133.0 million available capacity for additional revolver borrowings and letters of credit under the credit agreement, although the Partnership’s ability to borrow such funds may be limited by the financial covenants in the credit agreement. The proceeds of loans made under the credit agreement may be used for working capital and other general corporate purposes of the Partnership.

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 $600.0 million for all revolving loan commitments under the credit agreement.

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The credit agreement will mature on May 11, 2022, and all amounts outstanding under the credit agreement will become due and payable on such date. The credit agreement requires mandatory prepayments of amounts outstanding thereunder with the net proceeds of 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 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 5.50 to 1.00 for the fiscal quarters ending June 30, 2018, through December 31, 2018; 5.25 to 1.00 for the fiscal quarters ending March 31, 2019, and June 30, 2019; 5.00 to 1.00 for the fiscal quarters ending September 30, 2019, and December 31, 2019; and 4.75 to 1.00 for the fiscal quarter ending March 31, 2020, and each fiscal quarter thereafter; and

• based on the occurrence of a specified acquisition (as defined in the credit agreement, but generally being an acquisition for which the aggregate consideration is $15.0 million or more), the maximum permitted consolidated total leverage ratio may be increased to 5.25 to 1.00 for the fiscal quarter ending March 31, 2020, and for certain fiscal quarters thereafter.

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 will be 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.

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;

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• 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; and

• make certain amendments to the Partnership’s partnership agreement.

At June 30, 2018, the Partnership’s consolidated total leverage ratio was 4.65 to 1.00 and the consolidated interest coverage ratio was 3.78 to 1.00.  The Partnership was in compliance with all covenants of its credit agreement as of June 30, 2018.

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, provided, however, commencing with the fiscal quarter ending September 30, 2018, in no event shall aggregate quarterly distributions in any individual fiscal quarter exceed $10.7 million through, and including, the fiscal quarter ending December 31, 2019. 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 of Directors (the “Board”) of Blueknight Energy Partners G.P., L.L.C (the “general partner”) 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 9 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;

(ii) Ergon, Inc. (“Ergon”) ceases to own and control 50% or more of the membership interests of the general partner; or

(iii) during any period of 12 consecutive months, a majority of the members of the Board of the general partner ceases to be composed of individuals:

(A) who were members of the Board on the first day of such period;

(B) whose election or nomination to the Board was approved by individuals referred to in clause (A) above constituting at the time of such election or nomination at least a majority of the Board; or

(C) whose election or nomination to the Board was approved by individuals referred to in clauses (A) and (B) above constituting at the time of such election or nomination at least a majority of the Board, provided that any changes to the composition of individuals serving as members of the Board approved by Ergon will not cause an event of default.

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 to have letters of credit issued under the credit agreement. 

Upon the execution of the amended and restated credit agreement in May 2017, the Partnership expensed $0.7 million of debt issuance costs related to the prior revolving loan facility, leaving a remaining balance of $0.9 million ascribed to those lenders with commitments under both the prior and the amended and restated credit agreement. Additionally, due to the reduction in available borrowing capacity, the Partnership expensed $0.4 million of debt issuance costs upon the execution of the first amendment to its credit agreement in June 2018. The Partnership capitalized $4.0 million of debt issuance costs during each of the three and six months ended June 30,2017, and capitalized $0.3 million of debt issuance costs during each of the three and six months ended June 30,2018. Debt issuance costs are being amortized over the term of the credit agreement. Interest expense related to debt issuance cost amortization for each of the three months ended June 30,2017 and 2018, was $0.3 million. Interest expense related to debt issuance cost amortization for the six months ended June 30,2017 and 2018, was $0.6 million and $0.5 million, respectively.

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During the three months ended June 30,2017 and 2018, the weighted average interest rate under the Partnership’s credit agreement, excluding the $0.7 million and $0.4 million, respectively, of debt issuance costs that were expensed as described above, was 4.44% and 5.39%, respectively, resulting in interest expense of approximately $3.4 million and $4.7 million, respectively. During the six months ended June 30,2017 and 2018, the weighted average interest rate under the Partnership’s credit agreement, excluding the $0.7 million and $0.4 million, respectively, of debt issuance costs that were expensed as described above, was 4.27% and 5.18%, respectively, resulting in interest expense of approximately $6.7 million and $8.6 million, respectively.

During each of the three months ended June 30,2017 and 2018, the Partnership capitalized interest of less than $0.1 million. During the six months ended June 30,2017 and 2018, the Partnership capitalized interest of less than $0.1 million and $0.1 million, respectively.

The Partnership is exposed to market risk for changes in interest rates related to its credit agreement. 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. As of December 31, 2017, and June 30, 2018, the Partnership had interest rate swap agreements with notional amounts totaling $200.0 million and $100.0 million, respectively, to hedge the variability of its LIBOR-based interest payments. An interest rate swap agreement with a notional amount of $100.0 million expired on June 28, 2018. Interest rate swap agreements with notional amounts totaling $100.0 million will mature on January 28, 2019. During the three months ended June 30,2017 and 2018, the Partnership recorded swap interest expense of $0.4 million and $0.1 million, respectively. During the six months ended June 30,2017 and 2018, the Partnership recorded swap interest expense of $0.8 million and less than $0.1 million, respectively. The interest rate swaps do not receive hedge accounting treatment under ASC 815 - Derivatives and Hedging.

The following provides information regarding the Partnership’s assets and liabilities related to its interest rate swap agreements as of the periods indicated (in thousands):

Derivatives Not Designated as Hedging Instruments	Balance Sheet Location	Fair Value of Derivatives
		December 31, 2017		June 30, 2018
Interest rate swap assets - current	Other current assets	$	68	$	157
Interest rate swap liabilities - noncurrent	Long-term interest rate swap liabilities	$	225	$	—

Changes in the fair value of the interest rate swaps are reflected in the unaudited condensed consolidated statements of operations as follows (in thousands):

Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss) Recognized in Net Income on Derivatives	Amount of Gain (Loss) Recognized in Net Income on Derivatives
		Three Months ended June 30,					Six Months ended June 30,
		2017		2018			2017		2018
Interest rate swaps	Interest expense, net of capitalized interest	$	223	$	(40	)	$	975	$	314

8.    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): 

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	Three Months ended June 30,						Six Months ended June 30,
	2017			2018			2017			2018
Net income	$	6,371		$	1,785		$	9,913		$	6,227
General partner interest in net income	256			28			465			259
Preferred interest in net income	6,279			6,279			12,558			12,557
Net loss available to limited partners	$	(164	)	$	(4,522	)	$	(3,110	)	$	(6,589	)
Basic and diluted weighted average number of units:
Common units	38,155			40,324			38,151			40,306
Restricted and phantom units	923			1,133			806			983
Total units	39,078			41,457			38,957			41,289
Basic and diluted net loss per common unit	$	—		$	(0.11	)	$	(0.08	)	$	(0.16	)

9.    PARTNERS’ CAPITAL AND DISTRIBUTIONS

On December 1, 2017, the Partnership issued 1.9 million common units to Ergon in a private placement valued at $10.2 million in exchange for an asphalt terminalling facility in Bainbridge, Georgia.

On July 19, 2018, the Board approved a distribution of $0.17875 per outstanding Preferred Unit for the three months ended June 30,2018. The Partnership will pay this distribution on August 14, 2018, to unitholders of record as of August 3, 2018. The total distribution will be approximately $6.4 million, with approximately $6.3 million and $0.1 million paid to the Partnership’s preferred unitholders and general partner, respectively.

In addition, on July 19, 2018, the Board approved a cash distribution of $0.08 per outstanding common unit for the three months ended June 30,2018. The Partnership will pay this distribution on August 14, 2018, to unitholders of record on August 3, 2018. The total distribution will be approximately $3.4 million, with approximately $3.2 million and $0.1 million to be paid to the Partnership’s common unitholders and general partner, respectively, and $0.1 million to be paid to holders of phantom and restricted units pursuant to awards granted under the Partnership’s Long-Term Incentive Plan.

10.    RELATED-PARTY TRANSACTIONS

Transactions with Ergon

The Partnership leases asphalt facilities and provides asphalt terminalling services to Ergon. For both the three months ended June 30,2017 and 2018, the Partnership recognized related-party revenues of $13.5 million for services provided to Ergon. For the six months ended June 30,2017 and 2018, the Partnership recognized related-party revenues of $26.8 million and $27.5 million, respectively, for services provided to Ergon. As of December 31, 2017, and June 30, 2018, the Partnership had receivables from Ergon of $3.1 million and $1.2 million, respectively, net of allowance for doubtful accounts. As of December 31, 2017, and June 30, 2018, the Partnership had unearned revenues from Ergon of $1.6 million and $5.3 million, respectively.

Effective April 1, 2018, the Partnership entered into an agreement with Ergon under which the Partnership purchases crude oil in connection with its crude oil marketing operations. For the three and six months ended June 30,2018, the Partnership made purchases of crude oil under this agreement totaling $30.5 million. As of June 30, 2018, the Partnership has payables to Ergon related to this agreement of $9.8 million.

The Partnership and Ergon have an agreement (the “Agreement”) that gives each party rights concerning the purchase or sale of Ergon’s interest in Cimarron Express Pipeline, LLC (“Cimarron Express”), subject to certain terms and conditions. The Agreement was filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed May 14, 2018. The Cimarron Express will be a new 16-inch diameter, 65-mile crude oil pipeline running from northeastern Kingfisher County, Oklahoma to the Partnership’s Cushing, Oklahoma crude oil terminal. Ergon has formed a Delaware limited liability company, Ergon - Oklahoma Pipeline, LLC (“DEVCO”), which will hold Ergon’s 50% membership interest in Cimarron Express. Under the Agreement, the Partnership has the right, at any time, to purchase 100% of the authorized and outstanding member interests in DEVCO from Ergon for the Purchase Price, which shall be computed by taking Ergon’s total investment in the Cimarron Express plus interest, by giving written notice to Ergon (the “Call”). Ergon has the right to require BKEP to purchase 100% of

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the authorized and outstanding member interests of DEVCO for the Purchase Price (the “Put”) at any time beginning the earlier of (i) 18 months from the formation of the joint venture company to build the pipeline or (ii) six months after completion of the pipeline. Upon exercise of the Call or the Put, Ergon and the Partnership will execute the Member Interest Purchase Agreement which is attached to the Agreement as Exhibit B. Upon receipt of the Purchase Price, Ergon shall be obligated to convey 100% of the authorized and outstanding member interests in DEVCO to BKEP or its designee. There is not a separate amount of consideration for the put or the call exchanged between the parties. Therefore, based on applicable GAAP, no value was assigned to the combined instrument on the Partnership's balance sheet upon the execution of the put/call instrument. Construction of the Cimarron Express pipeline is anticipated to be complete and the pipeline placed in-service during the third quarter of 2019. As of June 30, 2018, neither Ergon nor the Partnership has exercised their options under the Agreement.

Transactions with Advantage Pipeline

The Partnership provided operating and administrative services to Advantage Pipeline. On April 3, 2017, the Partnership sold its investment in Advantage Pipeline. See Note 5 for additional information. For the six months ended June 30,2017, the Partnership earned revenues of $0.3 million for services provided to Advantage Pipeline.

11.    LONG-TERM INCENTIVE PLAN

In July 2007, the general partner adopted the Long-Term Incentive Plan (the “LTIP”), which is administered by the compensation committee of the Board. 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 4,100,000 common units, subject to adjustments 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. The phantom unit awards also include distribution equivalent rights (“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 and phantom units are entitled to receive cash distributions paid on common units during the vesting period which 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 outstanding grants made to the directors under the LTIP:

Grant Date	Number of Units	Weighted Average Grant Date Fair Value(1)		Grant Date Total Fair Value
				(in thousands)
December 2016	10,950	$	6.85	$	75
December 2017	15,306	$	4.85	$	74

_________________

(1)    Fair value is the closing market price on the grant date of the awards.

In addition, the independent directors received common unit grants that have no vesting requirement as part of their compensation. The following table includes information on grants made to the directors under the LTIP that have no vesting requirement:

Grant Date	Number of Units	Weighted Average Grant Date Fair Value(1)		Grant Date Total Fair Value
				(in thousands)
December 2016	10,220	$	6.85	$	70
December 2017	14,286	$	4.85	$	69

_________________

(1)    Fair value is the closing market price on the grant date of the awards.

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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(1)		Grant Date Total Fair Value
				(in thousands)
March 2016	416,131	$	4.77	$	1,985
October 2016	9,960	$	5.85	$	58
March 2017	323,339	$	7.15	$	2,312
March 2018	457,984	$	4.77	$	2,185

_________________

(1)    Fair value is the closing market price on the grant date of the awards.

The unrecognized estimated compensation cost of outstanding phantom and restricted units at June 30, 2018, was $3.1 million, which will be expensed over the remaining vesting period.

The Partnership’s equity-based incentive compensation expense for each of the three months ended June 30,2017 and 2018, was $0.6 million. The Partnership’s equity-based incentive compensation expense for each of the six months ended June 30,2017 and 2018 was $1.1 million.

Activity pertaining to phantom 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, 2017	923,551	$	6.29
Granted	457,984	4.77
Vested	241,629	7.46
Forfeited	10,865	5.39
Nonvested at June 30, 2018	1,129,041	$	5.88

12.    EMPLOYEE BENEFIT PLANS

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 $0.3 million for each of the three months ended June 30,2017 and 2018, for discretionary contributions under the 401(k) Plan. The Partnership recognized expense of $0.6 million for each of the six months ended June 30,2017 and 2018, 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 $0.2 million and less than $0.1 million for the three months ended June 30,2017 and 2018, respectively, for discretionary profit sharing contributions under the 401(k) Plan. The Partnership recognized expense of $0.4 million and $0.1 million for the six months ended June 30,2017 and 2018, respectively, for discretionary profit sharing contributions under the 401(k) Plan.

Under the Partnership’s Employee Unit Purchase Plan (the “Unit Purchase Plan”), which was instituted in January 2015, employees have the opportunity to acquire or increase their ownership of common units representing limited partner interests in the Partnership. Eligible employees who enroll in the Unit Purchase Plan may elect to have a designated whole percentage, up to a specified maximum, of their eligible compensation for each pay period withheld for the purchase of common units at a discount to the then current market value. A maximum of 1,000,000 common units may be delivered under the Unit Purchase Plan, subject to adjustment for a recapitalization, split, reorganization, or similar event pursuant to the terms of the Unit Purchase Plan. The Partnership recognized compensation expense of less than $0.1 million during each of the three and six months ended June 30,2017 and 2018, in connection with the Unit Purchase Plan.

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13.    FAIR VALUE MEASUREMENTS

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 assets and liabilities required to be measured at fair value, 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. There were no transfers during the six months ended June 30,2018. 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, 2017
Description	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs   (Level 3)
Assets:
Interest rate swap assets	$	68	$	—	$	68	$	—
Total swap assets	$	68	$	—	$	68	$	—
Liabilities:
Interest rate swap liabilities	$	225	$	—	$	225	$	—
Total swap liabilities	$	225	$	—	$	225	$	—

	Fair Value Measurements as of June 30, 2018
Description	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs   (Level 3)
Assets:
Interest rate swap assets	$	157	$	—	$	157	$	—
Total swap assets	$	157	$	—	$	157	$	—

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

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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 June 30, 2018, the carrying values on the unaudited condensed 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 June 30, 2018, 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.

14.    OPERATING SEGMENTS

The Partnership’s operations consist of four operating segments: (i) asphalt terminalling services, (ii) crude oil terminalling services, (iii) crude oil pipeline services and (iv) crude oil trucking services.  

ASPHALT TERMINALLING SERVICES —The Partnership provides asphalt product and residual fuel terminalling, storage and blending services. As of July 26, 2018, the Partnership has 53 terminalling and storage facilities located in 26 states.

CRUDE OIL TERMINALLING SERVICES —The Partnership provides crude oil terminalling services at its terminalling facility located in Oklahoma.

CRUDE OIL PIPELINE SERVICES —The Partnership owns and operates pipeline systems 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 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 pipeline system. The Partnership previously owned and operated the East Texas pipeline system, which was located in Texas. On April 17, 2017, the Partnership sold the East Texas pipeline system. See Note 6 for additional information. Crude oil product sales revenues consist of sales proceeds recognized for the sale of crude oil to third-party customers.

CRUDE OIL TRUCKING 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.  On April 24, 2018, the Partnership sold the producer field services business. As a result of the sale of the producer field services business, the Partnership changed the name of this operating segment to crude oil trucking services during the second quarter of 2018. See Note 6 for additional information.

The Partnership’s management evaluates performance based upon operating margin, excluding amortization and depreciation, which includes revenues from related parties and external customers and operating expense, excluding depreciation and amortization. The non-GAAP measure of operating margin, excluding depreciation and amortization (in the aggregate and by segment) is presented in the following table. The Partnership computes the components of operating margin, excluding depreciation and amortization by using amounts that are determined in accordance with GAAP. The Partnership accounts for intersegment product sales as if the sales were to third parties, that is, at current market prices. A reconciliation of operating margin, excluding depreciation and amortization 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, excluding depreciation and amortization 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): 

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	Three Months ended June 30,					Six Months ended June 30,
	2017		2018			2017		2018
Asphalt Terminalling Services
Service revenue:
Third-party revenue	$	13,259	$	6,639		$	26,482	$	11,771
Related-party revenue	13,505		5,981			26,837		12,302
Lease revenue:
Third-party revenue	—		10,016			—		19,473
Related-party revenue	—		7,475			—		15,178
Total revenue for reportable segment	26,764		30,111			53,319		58,724
Operating expense, excluding depreciation and amortization	11,935		13,393			24,255		26,728
Operating margin, excluding depreciation and amortization	$	14,829	$	16,718		$	29,064	$	31,996
Total assets (end of period)	$	147,832	$	167,849		$	147,832	$	167,849
Crude Oil Terminalling Services
Service revenue:
Third-party revenue	$	5,726	$	2,910		$	11,851	$	7,496
Intersegment revenue	—		170			—		170
Lease revenue:
Third-party revenue	—		12			—		27
Total revenue for reportable segment	5,726		3,092			11,851		7,693
Operating expense, excluding depreciation and amortization	992		913			2,003		2,188
Operating margin, excluding depreciation and amortization	$	4,734	$	2,179		$	9,848	$	5,505
Total assets (end of period)	$	69,834	$	67,150		$	69,834	$	67,150
Crude Oil Pipeline Services
Service revenue:
Third-party revenue	$	2,720	$	1,045		$	5,324	$	3,105
Related-party revenue	—		82			310		82
Lease revenue:
Third-party revenue	—		177			—		412
Product sales revenue:
Third-party revenue	2,227		45,612			5,877		49,120
Total revenue for reportable segment	4,947		46,916			11,511		52,719
Operating expense, excluding depreciation and amortization	3,142		2,542			6,383		5,327
Operating expense (intersegment)	74		1,156			244		1,599
Third-party cost of product sales	1,669		20,041			4,808		22,678
Related-party cost of product sales	—		23,747			—		23,747
Operating margin, excluding depreciation and amortization	$	62	$	(570	)	$	76	$	(632	)
Total assets (end of period)	$	117,222	$	152,105		$	117,222	$	152,105

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	Three Months ended June 30,						Six Months ended June 30,
	2017			2018			2017			2018
Crude Oil Trucking Services
Service revenue:
Third-party revenue	$	6,440		$	3,509		$	13,151		$	9,049
Intersegment revenue	74			986			244			1,429
Lease revenue:
Third-party revenue	—			32			—			129
Product sales revenue:
Third-party revenue	—			3			385			9
Total revenue for reportable segment	6,514			4,530			13,780			10,616
Operating expense, excluding depreciation and amortization	6,702			4,727			13,970			11,101
Operating margin, excluding depreciation and amortization	$	(188	)	$	(197	)	$	(190	)	$	(485	)
Total assets (end of period)	$	11,208		$	3,402		$	11,208		$	3,402
Total operating margin, excluding depreciation and amortization(1)	$	19,437		$	18,130		$	38,798		$	36,384
Total segment revenues	$	43,951		$	84,649		$	90,461		$	129,752
Elimination of intersegment revenues	(74		)	(1,156		)	(244		)	(1,599		)
Consolidated revenues	$	43,877		$	83,493		$	90,217		$	128,153

____________________

(1)The following table reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes (in thousands):

	Three Months ended June 30,						Six Months ended June 30,
	2017			2018			2017			2018
Operating margin, excluding depreciation and amortization	$	19,437		$	18,130		$	38,798		$	36,384
Depreciation and amortization	(7,839		)	(7,413		)	(15,905		)	(14,779		)
General and administrative expense	(4,322		)	(4,486		)	(8,907		)	(8,707		)
Asset impairment expense	(17		)	—			(45		)	(616		)
Gain (loss) on sale of assets	(754		)	599			(879		)	363
Interest expense	(4,265		)	(5,024		)	(7,295		)	(8,593		)
Gain on sale of unconsolidated affiliate	4,172			—			4,172			2,225
Equity earnings in unconsolidated affiliate	—			—			61			—
Income before income taxes	$	6,412		$	1,806		$	10,000		$	6,277

15.    COMMITMENTS AND CONTINGENCIES

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 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 present value of potential cash flows that

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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.

16.    INCOME TAXES

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 June 30, 2018, are presented below (dollars in thousands):

Deferred Tax Asset
Difference in bases of property, plant and equipment	$	444
Net operating loss carryforwards	11
Deferred tax asset	455
Less: valuation allowance	444
Net deferred tax asset	$	11

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 valuation allowance against its deferred tax asset related to the difference in bases of property, plant and equipment as of June 30, 2018.

17.    RECENTLY ISSUED ACCOUNTING STANDARDS

Except as discussed below and in the 2017 Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the six months ended June 30,2018, that are of significance or potential significance to the Partnership.

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. The Partnership adopted these updates in the three-month period ending March 31, 2018. See Note 3 for disclosures related to the adoption of this standard and the impact on the Partnership’s financial position, results of operations and 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 in order 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 adopted this update in the three-month

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period ending March 31, 2018, and there was no impact on the Partnership’s financial position, results of operations or cash flows.

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. Throughout 2017 and 2018, the FASB issued a series of subsequent updates to the guidance in Topic 842. This update, as well as related updates, 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 three-month period ending March 31, 2019.

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 (including bank-owned life insurance policies); 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 adopted this update in the three-month period ending March 31, 2018, and there was no impact on the Partnership’s financial position, results of operations or cash flows.

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 eliminate 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 adopted this update in the three-month period ending March 31, 2018, and there was no impact on the Partnership’s financial position, results of operations or cash flows.

In November 2016, the FASB issued ASU 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash (a Consensus 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 adopted this update in the three-month period ending March 31, 2018, and there was no impact on the Partnership’s financial position, results of operations or cash flows.

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 adopted this update in the three-month period ending March 31, 2018, and there was no impact on the Partnership’s financial position, results of operations or cash flows.

In February 2017, the FASB issued ASU 2017-05, “Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20).” This update clarifies the scope of Subtopic 610-20 and adds guidance for partial sales of nonfinancial assets. Subtopic 610-20, which was issued in May 2014 as a part of ASU 2014-09, “Revenue from Contracts with Customers (Topic 606),” provides guidance for recognizing gains and losses from the transfer of nonfinancial assets in contracts with noncustomers. The amendments in ASU 2017-05 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. The Partnership adopted this update in the three-month period ending March 31, 2018, and there was no impact on the Partnership’s financial position, results of operations or cash flows.

In May 2017, the FASB issued ASU 2017-09, “Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting.” This update provides clarity and reduces both diversity in practice and cost and complexity when applying the guidance of Topic 718, Compensation - Stock Compensation, to a change in the terms or conditions of a share-based payment award. 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 adopted this update in the three-month period ending March 31, 2018, and there was no impact on the Partnership’s financial position, results of operations or cash flows.

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18.    SUBSEQUENT EVENTS

Sale of Asphalt Facilities

On June 29, 2018, the Partnership entered into a definitive agreement to sell certain asphalt terminals, storage tanks and related real property, contracts, permits, assets and other interests located in Lubbock and Saginaw, Texas and Memphis, Tennessee properties (the “Divestiture”) to Ergon Asphalt & Emulsion, Inc. (“Ergon A&E”) for a purchase price of $90.0 million, subject to customary adjustments. The Partnership closed the Divestiture on July 12, 2018, and filed a Current Report on Form 8-K on July 13, 2018. The Divestiture does not qualify as discontinued operations as it does not represent a strategic shift that will have a major effect on the Partnership’s operations or financial results. The Partnership used the proceeds received at closing to prepay revolving debt under its credit agreement.

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Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations.

As used in this quarterly report, unless we indicate otherwise: (1) “Blueknight Energy Partners,” “our,” “we,” “us” and similar terms refer to Blueknight Energy Partners, L.P., together with its subsidiaries, (2) our “General Partner” refers to Blueknight Energy Partners G.P., L.L.C., (3) “Ergon” refers to Ergon, Inc., its affiliates and subsidiaries (other than our General Partner and us) and (4) “Vitol” refers to Vitol Holding B.V., its affiliates and subsidiaries.  The following discussion analyzes the historical financial condition and results of operations of the Partnership and should be read in conjunction with our financial statements and notes thereto, and Management’s Discussion and Analysis of Financial Condition and Results of Operations presented in our Annual Report on Form 10-K for the year ended December 31, 2017, which was filed with the Securities and Exchange Commission (the “SEC”) on March 8, 2018 (the “2017 Form 10-K”). 

Forward-Looking Statements

This report contains forward-looking statements.  Statements included in this quarterly report that are not historical facts (including any statements regarding plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), including, without limitation, the information set forth in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “will,” “should,” “believe,” “expect,” “intend,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition, or state other “forward-looking” information. We and our representatives may from time to time make other oral or written statements that are also forward-looking statements.

Such forward-looking statements are subject to various risks and uncertainties that could cause actual results to differ materially from those anticipated as of the date of the filing of this report. Although we believe that the expectations reflected in these forward-looking statements are based on reasonable assumptions, no assurance can be given that these expectations will prove to be correct. Important factors that could cause our actual results to differ materially from the expectations reflected in these forward-looking statements include, among other things, those set forth in “Part I, Item 1A. Risk Factors” in the 2017 Form 10-K.

All forward-looking statements included in this report are based on information available to us on the date of this report. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements contained throughout this report.

Overview

We are a publicly traded master limited partnership with operations in 27 states. We provide integrated terminalling, gathering and transportation services for companies engaged in the production, distribution and marketing of liquid asphalt and crude oil.  We manage our operations through four operating segments: (i) asphalt terminalling services, (ii) crude oil terminalling services, (iii) crude oil pipeline services and (iv) crude oil trucking services.  In April 2018, we sold our producer field services business that has been historically reported along with the crude oil trucking services. As a result of the sale of the producer field services business, we changed the name of this operating segment to crude oil trucking services during the second quarter of 2018.

Potential Impact of Crude Oil Market Price Changes and Other Matters on Future Revenues

The crude oil market price and the corresponding forward market pricing curve may fluctuate significantly from period to period. In addition, volatility in the overall energy industry and specifically in publicly traded midstream energy partnerships may impact our partnership in the near term. Factors include the overall market price for crude oil and whether or not the forward price curve is in contango (in which future prices are higher than current prices and a premium is placed on storing product and selling at a later time) or backwardated (in which the current crude oil price per barrel is higher than the future price per barrel and a premium is placed on delivering product to market and selling as soon as possible), changes in crude oil production volume and the demand for storage and transportation capacity in the areas in which we serve, geopolitical concerns and overall changes in our cost of capital. As of July 26, 2018, the forward price curve is backwardated. Potential impacts of these factors are discussed below.

Asphalt Terminalling Services - Although there is no direct correlation between the price of crude oil and the price of asphalt, the asphalt industry tends to benefit from a lower crude oil price environment, a strong economy and an increase in

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infrastructure spending. Accordingly, we do not currently anticipate a significant impact on our asphalt terminalling services operating segment as a result of crude oil market price changes.

On June 29, 2018, we entered into a definitive agreement to sell certain asphalt terminals, storage tanks and related real property, contracts, permits, assets and other interests located in Lubbock and Saginaw, Texas and Memphis, Tennessee (the “Divestiture”) to Ergon for a purchase price of $90.0 million, subject to customary adjustments. We closed the Divestiture on July 12, 2018, and filed a Current Report on Form 8-K on July 13, 2018.

Crude Oil Terminalling Services - A contango crude oil curve tends to favor the crude oil storage business as crude oil marketers are incentivized to store crude oil during the current month and sell into the future month. Since March 2016, the crude oil curve has generally been in a shallow contango or backwardation. In these shallow contango or backwardated markets there is no clear incentive for marketers to store barrels. A shallow contango or a backwardated market may impact our ability to re-contract expiring contracts and/or decrease the storage rate at which we are able to re-contract. Total Cushing inventories peaked at just under 70 million barrels stored in March 2017, and as of July 26, 2018, were at approximately 23.7 million barrels stored, which is approximately 51% below the 5-year average, 58% below last year’s storage level and the lowest level since November 2014. As a result of the current shape of the curve and lessened overall demand for Cushing storage, we anticipate a weak recontracting environment which may impact both the volume of storage we are able to successfully recontract and the rate at which we recontract.

Crude Oil Pipeline Services - A backwardated crude oil curve tends to favor the crude oil pipeline transportation business as crude oil marketers are incentivized to transport crude oil to market for sale as soon as possible. However, our crude oil pipeline services business has been impacted recently by an out-of-service pipeline. Since April 2016, we have been operating one Oklahoma pipeline system, instead of two systems, providing us with a capacity of approximately 20,000 to 25,000 barrels per day (Bpd). In July 2018, we were able to restore service to a second system which has increased the transportation capacity of our pipeline systems by approximately 20,000 Bpd. The ability to fully utilize the capacity of these systems may be impacted by the market price of crude oil and producers’ decisions to increase or decrease production in the areas we serve.

In the second quarter of 2018, we increased the volumes of crude oil transported for our internal crude oil marketing operations with the objective of increasing the overall utilization of our Oklahoma crude oil pipeline systems.  Typically, the volume of crude oil we purchase in a given month will be sold in the same month. However, we may have market price exposure for inventory that is carried over month-to-month as well as pipeline linefill we maintain. We may also be exposed to price risk with respect to the differing qualities of crude oil we transport and our ability to effectively blend them to market specifications.

On April 3, 2017, Advantage Pipeline, L.L.C., in which we owned an approximate 30% equity ownership interest, was acquired by a joint venture formed by affiliates of Plains All American Pipeline, L.P. and Noble Midstream Partners LP. We received cash proceeds at closing from the sale of our approximate 30% equity ownership interest in Advantage Pipeline of approximately $25.3 million and recorded a gain on the sale of the investment of $4.2 million. Approximately 10% of the gross sales proceeds were held in escrow, subject to certain post-closing settlement terms and conditions. We received approximately $1.1 million of the funds held in escrow in August 2017 and our remaining balance of $2.2 million in January 2018.

Crude Oil Trucking Services - Crude oil trucking, while potentially influenced by the shape of the crude oil market curve, is typically impacted more by overall drilling activity and the ability to have the appropriate level of assets located properly to efficiently move the barrels to delivery points for customers.

In December 2017, we evaluated our producer field services business for impairment and recognized an impairment expense of $2.4 million to record our assets at their estimated fair value. On April 24, 2018, we sold our producer field services business, which has been historically reported along with the crude oil trucking services.

Our Revenues

Our revenues consist of (i) terminalling revenues, (ii) gathering and transportation revenues, (iii) product sales revenues and (iv) fuel surcharge revenues. For the six months ended June 30,2018, the Partnership recognized revenues of $27.5 million for services provided to Ergon, with the remainder of our services being provided to third parties.

Terminalling revenues consist of (i) 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 (ii) throughput fees to pump crude oil to connecting carriers or to deliver asphalt product out of our terminals. We earn terminalling revenues in two of our segments: (i)

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asphalt terminalling services and (ii) crude oil terminalling services. Storage service revenues are recognized as the services are provided on a monthly basis. Throughput fees in our asphalt terminalling services segment are recognized straight-line over time. Throughput fees in our crude oil terminalling services segments are recognized as the crude oil is delivered out of our terminal.

As of June 30, 2018, we had leases and terminalling agreements with customers for all of our 56 asphalt facilities, including 26 facilities under contract with Ergon.  On July 12, 2018, we closed the sale of three of our asphalt facilities to Ergon (see Note 18 to our unaudited condensed consolidated financial statements for additional information). Lease and terminalling agreements related to 16 of the remaining facilities have terms that expire at the end of 2018, while the agreements relating to our additional 37 facilities have on average five years remaining under their respective terms. Fifteen of the contracts that expire in 2018 are with Ergon. We may not be able to extend, renegotiate or replace these contracts when they expire and the terms of any renegotiated contracts may not be as favorable as the contracts they replace. We operate the asphalt facilities pursuant to the terminalling agreements, while our contract counterparties operate the asphalt facilities that are subject to lease agreements.

As of July 27, 2018, we had approximately 5.0 million barrels of crude oil storage under service contracts, including an intercompany contract for 0.3 million barrels and a contract for 2.0 million barrels that commences November 1, 2018, out of our total storage capacity of 6.6 million barrels. Of these agreements, service contracts relating to 1.7 million barrels expire in 2018.

We are in negotiations to either extend contracts with other existing customers or enter into new customer contracts for the agreements expiring in 2018; however, there is no certainty that we will have success in contracting available capacity or that extended or new contracts will be at the same or similar rates as the expiring contracts. If we are unable to renew the majority of the expiring storage contracts, we may experience lower utilization of our assets which could have a material adverse effect on our business, cash flows, ability to make distributions to our unitholders, the price of our common units, results of operations and ability to conduct our business.

Gathering and transportation services revenues consist of service fees recognized for the gathering of crude oil for our customers and the transportation of crude oil to refiners, to common carrier pipelines for ultimate delivery to refiners or to terminalling facilities owned by us and others. We earn gathering and transportation revenues in two of our segments: (i) crude oil pipeline services and (ii) crude oil trucking services. 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.  

During the three months ended June 30,2018, we transported approximately 20,000 Bpd on our Mid-Continent pipeline system, which is a decrease of 13% compared to the three months ended June 30,2017. During the six months ended June 30,2018, we transported approximately 21,000 Bpd on our Mid-Continent pipeline system, which is a decrease of 9% compared to the six months ended June 30,2017. We completed work on the Eagle pipeline system and restored service in July 2018, increasing the transportation capacity of our pipeline systems by approximately 20,000 Bpd. See Crude oil pipeline services segment within our results of operations discussion for additional detail. Vitol accounted for 61% and 25% of volumes transported in our pipelines in the three months ended June 30,2017 and 2018, respectively. Vitol accounted for 56% and 43% of volumes transported in our pipelines in the six months ended June 30,2017 and 2018, respectively.

For the three months ended June 30,2018, we transported approximately 26,000 Bpd on our crude oil transport trucks, an increase of 18% as compared to the three months ended June 30,2017. For the six months ended June 30,2018, we transported approximately 25,000 Bpd on our crude oil transport trucks, an increase of 14% as compared to the six months ended June 30,2017. Vitol accounted for approximately 55% and 4% of volumes transported by our crude oil transport trucks in the three months ended June 30,2017 and 2018, respectively. Vitol accounted for approximately 50% and 16% of volumes transported by our crude oil transport trucks in the six months ended June 30,2017 and 2018, respectively. With our second Oklahoma pipeline system resuming service, we anticipate additional increases in volumes transported by our crude oil transport trucks as we gather barrels to be transported on this pipeline.

Product sales revenues are comprised of (i) revenues recognized for the sale of crude oil to our customers that we purchase at production leases and (ii) revenue recognized in buy/sell transactions with our customers. We earn product sales revenue in our crude oil pipeline services operating segment. Product sales revenue is recognized for products upon delivery and when the customer assumes the risks and rewards of ownership.

Fuel surcharge revenues are comprised of revenues recognized for the reimbursement of fuel and power consumed to operate our asphalt terminals.  We recognize fuel surcharge revenues in the period in which the related fuel and power expenses are incurred.

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Our Expenses

Operating expenses decreased by 4% for the six months ended June 30,2018, as compared to the six months ended June 30,2017. This is primarily a result of a decrease in depreciation expense due to certain assets reaching the end of their depreciable lives as well as a decrease in vehicle expenses due to a reduction in the size of our fleet. General and administrative expenses remained consistent for the six months ended June 30,2018, as compared to the six months ended June 30,2017. Our interest expense increased by $1.3 million for the six months ended June 30,2018, as compared to the six months ended June 30,2017. See Interest expense within our results of operations discussion for additional detail regarding the factors that contributed to the increase in interest expense in 2018.

Income Taxes

As part of the process of preparing the unaudited condensed consolidated financial statements, we are required to estimate the federal and state income taxes in each of the jurisdictions in which our subsidiary that is taxed as a corporation operates. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for tax and accounting purposes. These differences result in deferred tax assets and liabilities, which are included in our unaudited condensed consolidated balance sheets. We must then assess, using all available positive and negative evidence, the likelihood that the deferred tax assets will be recovered from future taxable income. Unless we believe that recovery is more likely than not, we must establish a valuation allowance. To the extent we establish a valuation allowance or increase or decrease this allowance in a period, we must include an expense or reduction of expense within the tax provisions in the unaudited condensed consolidated statements of operations.

Under ASC 740 – Accounting for Income Taxes, an enterprise must use judgment in considering the relative impact of negative and positive evidence. The weight given to the potential effect of negative and positive evidence should be commensurate with the extent to which it can be objectively verified. The more negative evidence that exists, (a) the more positive evidence is necessary and (b) the more difficult it is to support a conclusion that a valuation allowance is not needed for some portion or all of the deferred tax asset. Among the more significant types of evidence that we consider are:

• taxable income projections in future years;

• whether the carryforward period is so brief that it would limit realization of tax benefits;

• future revenue and operating cost projections that will produce more than enough taxable income to realize the deferred tax asset based on existing service rates and cost structures; and

• our earnings history exclusive of the loss that created the future deductible amount coupled with evidence indicating that the loss is an aberration rather than a continuing condition.

Based on the consideration of the above factors for our subsidiary that is taxed as a corporation for purposes of determining the likelihood of realizing the benefits of the deferred tax assets, we have provided a valuation allowance against our deferred tax asset related to the difference in bases of property, plant and equipment as of June 30, 2018.

Distributions

The amount of distributions we pay and the decision to make any distribution is determined by the Board of Directors of our General Partner (the “Board”), which has broad discretion to establish cash reserves for the proper conduct of our business and for future distributions to our unitholders. In addition, our cash distribution policy is subject to restrictions on distributions under our credit agreement. 

On July 19, 2018, the Board approved a distribution of $0.17875 per outstanding Preferred Unit for the three months ended June 30,2018. We will pay this distribution on August 14, 2018, to unitholders of record as of August 3, 2018. The total distribution will be approximately $6.4 million, with approximately $6.3 million and $0.1 million paid to our preferred unitholders and General Partner, respectively.

In addition, on July 19, 2018, the Board approved a cash distribution of $0.08 per outstanding common unit for the three months ended June 30,2018. We will pay this distribution August 14, 2018, to unitholders of record on August 3, 2018. The total distribution will be approximately $3.4 million, with approximately $3.2 million and $0.1 million paid to our common unitholders and General Partner, respectively, and $0.1 million paid to holders of phantom and restricted units pursuant to awards granted under our Long-Term Incentive Plan.

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Results of Operations

Non-GAAP Financial Measures

To supplement our financial information presented in accordance with GAAP, management uses additional measures that are known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future.  The primary measure used by management is operating margin, excluding depreciation and amortization.

Management believes that the presentation of such additional financial measures provides useful information to investors regarding our performance and results of operations because these measures, when used in conjunction with related GAAP financial measures, (i) provide additional information about our core operating performance and ability to generate and distribute cash flow; (ii) provide investors with the financial analytical framework upon which management bases financial, operational, compensation and planning decisions and (iii) present measurements that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. These additional financial measures are reconciled to the most directly comparable measures as reported in accordance with GAAP, and should be viewed in addition to, and not in lieu of, our unaudited condensed consolidated financial statements and footnotes. 

The table below summarizes our financial results for the three and six months ended June 30,2017 and 2018, reconciled to the most directly comparable GAAP measure:

Operating Results	Three Months ended June 30,						Six Months ended June 30,						Favorable/(Unfavorable)
													Three Months					Six Months
(dollars in thousands)	2017			2018			2017			2018			$			%		$			%
Operating margin, excluding depreciation and amortization:
Asphalt terminalling services	$	14,829		$	16,718		$	29,064		$	31,996		$	1,889		13	%	$	2,932		10	%
Crude oil terminalling services	4,734			2,179			9,848			5,505			(2,555		)	(54	)%	(4,343		)	(44	)%
Crude oil pipeline services	62			(570		)	76			(632		)	(632		)	(1,019	)%	(708		)	(932	)%
Crude oil trucking services	(188		)	(197		)	(190		)	(485		)	(9		)	(5	)%	(295		)	(155	)%
Total operating margin, excluding depreciation and amortization	19,437			18,130			38,798			36,384			(1,307		)	(7	)%	(2,414		)	(6	)%
Depreciation and amortization	(7,839		)	(7,413		)	(15,905		)	(14,779		)	426			5	%	1,126			7	%
General and administrative expense	(4,322		)	(4,486		)	(8,907		)	(8,707		)	(164		)	(4	)%	200			2	%
Asset impairment expense	(17		)	—			(45		)	(616		)	17			100	%	(571		)	(1,269	)%
Gain (loss) on sale of assets	(754		)	599			(879		)	363			1,353			179	%	1,242			141	%
Operating income	6,505			6,830			13,062			12,645			325			5	%	(417		)	(3	)%
Other income (expenses):
Equity earnings in unconsolidated affiliate	—			—			61			—			N/A			N/A		(61		)	(100	)%
Gain on sale of unconsolidated affiliate	4,172			—			4,172			2,225			(4,172		)	(100	)%	(1,947		)	(47	)%
Interest expense	(4,265		)	(5,024		)	(7,295		)	(8,593		)	(759		)	(18	)%	(1,298		)	(18	)%
Provision for income taxes	(41		)	(21		)	(87		)	(50		)	20			49	%	37			43	%
Net income	$	6,371		$	1,785		$	9,913		$	6,227		$	(4,586	)	(72	)%	$	(3,686	)	(37	)%

For the three and six months ended June 30,2018, operating margin, excluding depreciation and amortization, increased in our asphalt terminalling services segment as compared to the same period in 2017 primarily due to the acquisition of two asphalt facilities, one from Ergon in December 2017 and one from a third party in March 2018, as well as the conversion of another facility from a lease agreement to a storage, handling and throughput agreement. These increases were offset by lower operating margins in our other segments. The decrease in our crude oil terminalling services operating margin, excluding depreciation and amortization, was primarily due to lower storage rates as well as the expiration of a 2.2-million-barrel storage contract on April 30, 2018. The crude oil pipeline services margin, excluding depreciation and amortization, continues to be affected by the suspended service on our Mid-Continent pipeline system due to the discovery of a pipeline exposure in April

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2016. Crude oil trucking services operating margin, excluding depreciation and amortization, decreased due to decreases in the average miles hauled per transaction, which results in lower revenues per barrel transported.

    A more detailed analysis of changes in operating margin by segment follows.

Analysis of Operating Segments

Asphalt terminalling services segment

Our asphalt terminalling services segment operations generally consist of fee-based activities associated with providing terminalling services, including storage, blending, processing and throughput services, for asphalt product and residual fuel oil. Revenue is generated through operating lease contracts and storage, throughput and handling contracts.

The following table sets forth our operating results from our asphalt terminalling services segment for the periods indicated:

Operating results	Three Months ended June 30,				Six Months ended June 30,				Favorable/(Unfavorable)
									Three Months					Six Months
(dollars in thousands)	2017		2018		2017		2018		$			%		$			%
Service revenue:
Third-party revenue	$	13,259	$	6,639	$	26,482	$	11,771	$	(6,620	)	(50	)%	$	(14,711	)	(56	)%
Related-party revenue	13,505		5,981		26,837		12,302		(7,524		)	(56	)%	(14,535		)	(54	)%
Lease revenue:
Third-party revenue	—		10,016		—		19,473		10,016			N/A		19,473			N/A
Related-party revenue	—		7,475		—		15,178		7,475			N/A		15,178			N/A
Total revenue	26,764		30,111		53,319		58,724		3,347			13	%	5,405			10	%
Operating expense, excluding depreciation and amortization	11,935		13,393		24,255		26,728		(1,458		)	(12	)%	(2,473		)	(10	)%
Operating margin, excluding depreciation and amortization	$	14,829	$	16,718	$	29,064	$	31,996	$	1,889		13	%	$	2,932		10	%

The following is a discussion of items impacting asphalt terminalling services segment operating margin for the periods indicated:

• Due to the adoption of ASC 606 - Revenue from Contracts with Customers, revenue from contracts with customers is now presented separately from lease revenue. Prior periods were not reclassified.

• Overall revenues have increased for the three and six months ended June 30,2018, as compared to the three and six months ended June 30,2017, primarily due to the acquisition of two asphalt facilities, one from Ergon in December 2017 and one from a third party in March 2018. In addition, a third facility converted from a lease contract to a storage, throughput and handling contract, which generates higher gross revenue. Third-party revenues also increased overall due to increases in fuel and power reimbursement revenues.

• Operating expenses increased for the three and six months ended June 30,2018, as compared to the three and six months ended June 30,2017, primarily as a result of the acquisitions noted above. In addition, ad valorem taxes increased due to increases in the assessed values of some of our asphalt terminals.

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Crude oil terminalling services segment

Our crude oil terminalling services segment operations generally consist of fee-based activities associated with providing terminalling services, including storage, blending, processing and throughput services for crude oil. Revenue is generated through short- and long-term storage contracts.

The following table sets forth our operating results from our crude oil terminalling services segment for the periods indicated:

Operating results	Three Months ended June 30,				Six Months ended June 30,				Favorable/(Unfavorable)
									Three Months					Six Months
(dollars in thousands)	2017		2018		2017		2018		$			%		$			%
Service revenue:
Third-party revenue	$	5,726	$	2,910	$	11,851	$	7,496	$	(2,816	)	(49	)%	$	(4,355	)	(37	)%
Intersegment revenue	—		170		—		170		$	170		N/A		$	170		N/A
Lease revenue:
Third-party revenue	—		12		—		27		12			N/A		27			N/A
Total revenue	5,726		3,092		11,851		7,693		(2,634		)	(46	)%	(4,158		)	(35	)%
Operating expense, excluding depreciation and amortization	992		913		2,003		2,188		79			8	%	(185		)	(9	)%
Operating margin, excluding depreciation and amortization	$	4,734	$	2,179	$	9,848	$	5,505	$	(2,555	)	(54	)%	$	(4,343	)	(44	)%
Average crude oil stored per month at our Cushing terminal (in thousands of barrels)	5,484		1,126		5,719		1,485		(4,358		)	(79	)%	(4,234		)	(74	)%
Average crude oil delivered to our Cushing terminal (in thousands of barrels per day)	50		36		47		59		(14		)	(28	)%	12			26	%

The following is a discussion of items impacting crude oil terminalling services segment operating margin for the periods indicated:

• Total revenues for three and six months ended June 30,2018, have decreased as compared to the same period in 2017 due to a decrease in market rates for storage contracts. In addition, a 2.2-million-barrel storage contract expired on April 30, 2018, and was not renewed or replaced as of June 30, 2018.

• Operating expenses for the three and six months ended June 30,2018, varied compared to the three and six months ended June 30,2017, primarily due to the timing of routine tank maintenance and utility costs.

• As of July 27, 2018, we had approximately 5.0 million barrels of crude oil storage under service contracts, including an intercompany contract for 0.3 million barrels and a contract for 2.0 million barrels that commences November 1, 2018, out of our total storage capacity of 6.6 million barrels. Of these agreements, service contracts relating to 1.7 million barrels expire in 2018.

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Crude oil pipeline services segment

Our crude oil pipeline services segment operations include both service and product sales revenue. Service revenue generally consists of tariffs and other fees associated with transporting crude oil products on pipelines. Product sales revenue is comprised of (i) revenues recognized for the sale of crude oil to our customers that we purchase at production leases and (ii) revenue recognized in buy/sell transactions with our customers. Product sales revenue is recognized for products upon delivery and when the customer assumes the risks and rewards of ownership.

The following table sets forth our operating results from our crude oil pipeline services segment for the periods indicated:

Operating results	Three Months ended June 30,					Six Months ended June 30,					Favorable/(Unfavorable)
											Three Months					Six Months
(dollars in thousands)	2017		2018			2017		2018			$			%		$			%
Service revenue:
Third-party revenue	$	2,720	$	1,045		$	5,324	$	3,105		$	(1,675	)	(62	)%	$	(2,219	)	(42	)%
Related-party revenue	—		82			310		82			82			N/A		(228		)	(74	)%
Product sales revenue:
Third-party revenue	2,227		45,612			5,877		49,120			43,385			1,948	%	43,243			736	%
Lease revenue:
Third-party revenue	—		177			—		412			177			N/A		412			N/A
Total revenue	4,947		46,916			11,511		52,719			41,969			848	%	41,208			358	%
Operating expense, excluding depreciation and amortization	3,142		2,542			6,383		5,327			600			19	%	1,056			17	%
Operating expense (intersegment)	74		1,156			244		1,599			(1,082		)	(1,462	)%	(1,355		)	(555	)%
Third-party cost of product sales	1,669		20,041			4,808		22,678			(18,372		)	(1,101	)%	(17,870		)	(372	)%
Related-party cost of product sales	—		23,747			—		23,747			(23,747		)	N/A		(23,747		)	N/A
Operating margin, excluding depreciation and amortization	$	62	$	(570	)	$	76	$	(632	)	$	(632	)	(1,019	)%	$	(708	)	(932	)%
Average throughput volume (in thousands of barrels per day)
Mid-Continent	23		20			23		21			(3		)	(13	)%	(2		)	(9	)%
East Texas(1)	—		—			2		—			—			N/A		(2		)	(100	)%

(1) Average throughput on the East Texas system for 2017 was calculated based on the period of time we operated the system (January 1, 2017 through April 18, 2017).

The following is a discussion of items impacting crude oil pipeline services segment operating margin for the periods indicated:

• In late April 2016, as a precautionary measure we suspended service on our Mid-Continent pipeline system due to discovery of a pipeline exposure caused by heavy rains and the erosion of a riverbed in southern Oklahoma. There was no damage to the pipe and no loss of product. In the second quarter of 2016, we took action to mitigate the service suspension and worked with customers to divert volumes and, in certain circumstances, transported volumes to a third-party pipeline system via truck. In addition, the term of the throughput and deficiency agreement on our Eagle pipeline system expired on June 30, 2016, and in July 2016 we completed a connection of the southeastern-most portion of our Mid-Continent pipeline system to our Eagle pipeline system and concurrently reversed the Eagle pipeline system. This enabled us to recapture diverted volumes and deliver those barrels to Cushing, Oklahoma. We are currently operating one Oklahoma mainline system, which is a combination of both the Mid-Continent and Eagle pipeline systems, instead of two separate systems, providing us with a current capacity of approximately 20,000 to 25,000 Bpd. We restored service of the second Oklahoma pipeline system in July 2018, increasing the transportation capacity of our pipeline systems by approximately 20,000 Bpd. The ability to fully utilize the capacity of these systems may be impacted by the market price of crude oil and producers’ decisions to increase or decrease production in the areas we serve.

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• Service revenues for the three and six months ended June 30,2018, decreased as compared to the three and six months ended June 30,2017, primarily as a result of a decrease in volume transported for third parties on our Mid-Continent pipeline system. For the three and six months ended June 30,2018, approximately 39% and 20%, respectively, of the total volume transported on our Mid-Continent system was comprised of barrels that we are purchasing from producers in the field and transporting to our Cushing terminal to support our crude oil marketing operations.

• Product sales revenues for the three and six months ended June 30,2018, increased as compared to the three and six months ended June 30,2017, as a result of supplementing a portion of the crude oil volumes transported for third party customers with barrels that are being transported for our internal crude oil marketing operations.  As a result of our marketing operations utilizing a portion of the capacity of our Mid-Continent system, we have increased our balance of the total linefill requirements of the pipeline system.  This increasing of our linefill balance during the three months ended June 30,2018, resulted in the total volume of crude oil we purchased during this period exceeding the volume of crude oil we sold in the period, and we expect our operating margin in this segment to increase in future periods when we are no longer building linefill balances.

• On April 18, 2017, we sold the East Texas pipeline system. We received cash proceeds at closing of approximately $4.8 million and recorded a gain of less than $0.1 million. The sale of the East Texas pipeline system resulted in decreased service revenues of $0.5 million for the six months ended June 30,2018, as compared to the six months ended June 30,2017.

• Operating expenses decreased for the six months ended June 30,2018, as compared to the six months ended June 30,2017, by $0.6 million as a result of the sale of the East Texas pipeline system, by $0.4 million as a result of decreased repair and maintenance expenses and by $0.2 million as a result of the sale of our investment in Advantage Pipeline, for which we provided operational and administrative services through August 1, 2017.

• Intersegment operating expenses for the six months ended June 30,2018, as compared to the six months ended June 30,2017, increased by $1.4 million as a result of an increase in our crude oil marketing operations. These expenses represent intersegment charges for our crude oil marketing operations’ utilization of our crude oil trucking services to gather crude oil purchased at production leases and deliver it to our pipelines.

Crude oil trucking services segment

Our crude oil trucking services segment operations generally consist of fee-based activity associated with transporting crude oil products on trucks. Revenues are generated primarily through transportation fees. In April 2018, we sold our producer field services business that has been historically reported along with the crude oil trucking services. As a result of the sale of the producer field services business, the Partnership changed the name of this operating segment to crude oil trucking services during the second quarter of 2018.

The following table sets forth our operating results from our crude oil trucking services segment for the periods indicated:

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Operating results	Three Months ended June 30,						Six Months ended June 30,						Favorable/(Unfavorable)
													Three Months					Six Months
(dollars in thousands)	2017			2018			2017			2018			$			%		$			%
Service revenue:
Third-party revenue	$	6,440		$	3,509		$	13,151		$	9,049		$	(2,931	)	(46	)%	$	(4,102	)	(31	)%
Intersegment revenue	74			986			244			1,429			912			1,232	%	1,185			486	%
Product sales revenue:
Third-party revenue	—			3			385			9			3			N/A		(376		)	(98	)%
Lease revenue:
Third-party revenue	—			32			—			129			32			N/A		129			N/A
Total revenue	6,514			4,530			13,780			10,616			(1,984		)	(30	)%	(3,164		)	(23	)%
Operating expense, excluding depreciation and amortization	6,702			4,727			13,970			11,101			1,975			29	%	2,869			21	%
Operating margin, excluding depreciation and amortization	$	(188	)	$	(197	)	$	(190	)	$	(485	)	$	(9	)	(5	)%	$	(295	)	(155	)%
Average volume (in thousands of barrels per day)	22			26			22			25			4			18	%	3			14	%

The following is a discussion of items impacting crude oil trucking services segment operating margin for the periods indicated:

• Service revenues have decreased despite an increase in volumes as the volumes hauled in 2018 were, on average, over a shorter distance than in 2017, which results in lower revenue per barrel transported. Additionally, service revenues decreased for the three and six months ended June 30,2018, as compared to the three and six months ended June 30,2017, by $1.8 million and $2.3 million, respectively, due to the sale of the producer field services business.

• Employment costs and vehicle-related expenses decreased for the three and six months ended June 30,2018, as compared to the three and six months ended June 30,2017, as we reduced our headcount and fleet size to better match demand.

• Operating expense, excluding depreciation and amortization, decreased for the three and six months ended June 30,2018, as compared to the three and six months ended June 30,2017, by $1.7 million and $2.0 million, respectively, due to the sale of our producer field services business.

• Product sales revenues for the six months ended June 30, 2017, were the result of crude oil sales in our field services business, and there were minimal such sales during the three and six months ended June 30, 2018.

Other Income and Expenses

Depreciation and amortization expense. Depreciation and amortization decreased by $0.4 million to $7.4 million for the three months ended June 30,2018, compared to $7.8 million for the three months ended June 30,2017. Depreciation and amortization decreased by $1.1 million to $14.8 million for the six months ended June 30,2018, compared to $15.9 million for the six months ended June 30,2017. This decrease is primarily the result of certain assets reaching the end of their depreciable lives.

General and administrative expenses.  General and administrative expenses, inclusive of $0.6 million of fees related to the Divestiture, were relatively consistent at $4.5 million for the three months ended June 30,2018, compared to $4.3 million for the three months ended June 30,2017. General and administrative expenses decreased slightly to $8.7 million for the six months ended June 30,2018, compared to $8.9 million for the six months ended June 30,2017, with the change primarily resulting from decreases in compensation and travel expenses, partially offset by $0.6 million of fees related to the Divestiture.

Asset impairment expense. Asset impairment expense was $0.6 million and less than $0.1 million for the six months ended June 30,2018 and 2017, respectively. Asset impairment expense for 2018 included approximately $0.4 million related to the value of obsolete trucking stations, as well as $0.2 million related to an intangible customer contract asset that was not renewed.

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Gain (loss) on sale of assets. Gain on sale of assets was $0.6 million for the three months ended June 30,2018, compared to a loss of $0.8 million for the three months ended June 30,2017. Gain on sale of assets was $0.4 million for the six months ended June 30,2018, compared to a loss of $0.9 million for the six months ended June 30,2017. We recognized a gain on the sale of our producer field services business of $0.4 million in April 2018. Losses for the three and six months ended June 30,2017, include $0.4 million related to the disposal of an asphalt tank floor that had to be prematurely replaced due to corrosion. Additional gains and losses in all periods were primarily comprised of sales of surplus, used property and equipment.

Equity earnings in unconsolidated affiliate/Gain on sale of unconsolidated affiliate. The equity earnings are attributable to our former investment in Advantage Pipeline. On April 3, 2017, we sold our investment in Advantage Pipeline and received cash proceeds at closing from the sale of approximately $25.3 million, recognizing a gain on sale of unconsolidated affiliate of $4.2 million. Approximately 10% of the gross sale proceeds were held in escrow, subject to certain post-closing settlement terms and conditions. We received approximately $1.1 million of the funds held in escrow in August 2017, for which we recognized an additional gain on sale of unconsolidated affiliate during the three months ended September 30, 2017. We received approximately $2.2 million for the pro rata portion of the remaining net escrow proceeds in January 2018, for which we recognized an additional gain on sale of unconsolidated affiliate during the six months ended June 30, 2018.

Interest expense. Interest expense represents interest on borrowings under our credit agreement as well as amortization of debt issuance costs and unrealized gains and losses related to the change in fair value of interest rate swaps.

Total interest expense for the three months ended June 30,2018, increased by $0.8 million compared to the three months ended June 30,2017. The increase was driven by additional interest on our credit agreement of approximately $1.3 million due to increases in our average debt outstanding and the weighted average interest rate under our credit agreement. In addition, during the three months ended June 30,2018, we recorded unrealized losses of less than $0.1 million due to the change in fair value of interest rate swaps compared to unrealized gains of $0.2 million during the three months ended June 30,2017. These increases in interest expense were partially offset by a decrease in monthly net interest payments on the interest rate swaps of $0.5 million for the three months ended June 30,2018, as compared to the three months ended June 30,2017. Also included in interest expense is the amortization of debt issuance costs of $0.7 million and $1.0 million, which includes write-offs due to credit facility amendments of $0.4 million and $0.7 million, respectively, for the three months ended June 30,2018, and 2017, respectively.

Total interest expense for the six months ended June 30,2018, increased by $1.3 million compared to the six months ended June 30,2017. The increase was driven by additional interest on our credit agreement of approximately $1.9 million due to increases in our average debt outstanding and the weighted average interest rate under our credit agreement. In addition, during the six months ended June 30,2018, we recorded unrealized gains of $0.3 million due to the change in fair value of interest rate swaps compared to unrealized gains of $1.0 million during the six months ended June 30,2017. These increases in interest expense were partially offset by a decrease in monthly net interest payments on the interest rate swaps of $0.9 million for the six months ended June 30,2018, as compared to the six months ended June 30,2017. Also included in interest expense is the amortization of debt issuance costs of $0.9 million and $1.3 million, which includes write-offs due to credit facility amendments of $0.4 million and $0.7 million, respectively, for the six months ended June 30,2018 and 2017, respectively.

Effects of Inflation

In recent years, inflation has been modest and has not had a material impact upon the results of our operations.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements as defined by Item 303 of Regulation S-K.

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Liquidity and Capital Resources

Cash Flows and Capital Expenditures

The following table summarizes our sources and uses of cash for the six months ended June 30,2017 and 2018: 

	Six Months ended June 30,
	2017			2018
	(in millions)
Net cash provided by operating activities	$	26.6		$	21.1
Net cash provided by (used in) investing activities	$	23.5		$	(38.0	)
Net cash provided by (used in) financing activities	$	(50.1	)	$	15.6

Operating Activities.  Net cash provided by operating activities decreased to $21.1 million for the six months ended June 30,2018, as compared to $26.6 million for the six months ended June 30,2017, due to decreased net income as discussed above and changes in working capital.

Investing Activities.  Net cash used in investing activities was $38.0 million for the six months ended June 30,2018, as compared to net cash provided by $23.5 million for the six months ended June 30,2017.  The six months ended June 30,2017, included proceeds from the sale of an unconsolidated affiliate of $25.3 million. On March 7, 2018, we acquired an asphalt terminalling facility from a third party for $22.0 million. Capital expenditures for the six months ended June 30,2018 and 2017, included gross maintenance capital expenditures of $4.2 million and $5.0 million, respectively, and expansion capital expenditures of $17.9 million and $5.3 million, respectively.

Financing Activities.  Net cash provided by financing activities was $15.6 million for the six months ended June 30,2018, as compared to net cash used in financing activities of $50.1 million for the six months ended June 30,2017.  Cash provided by financing activities for the six months ended June 30,2018, consisted primarily of net borrowings on long-term debt of $42.0 million partially offset by $25.2 million in distributions to our unitholders. Net cash used in financing activities for the six months ended June 30,2017, consisted primarily of $24.6 million in distributions to our unitholders and net payments on long-term debt of $20.4 million.

Our Liquidity and Capital Resources

Cash flows from operations and from our credit agreement are our primary sources of liquidity. At June 30, 2018, we had a working capital deficit of $1.1 million. This is primarily a function of our approach to cash management.

At June 30, 2018, we had approximately $47.0 million of availability under our credit agreement, and we could borrow all of the remaining availability and still remain within our covenant restrictions. On July 12, 2018, we used $88.0 million of proceeds received for the sale of three asphalt facilities to pay down the revolving debt balance (see Note 18 to our unaudited condensed consolidated financial statements). As of July 26, 2018, we have aggregate unused commitments under our revolving credit facility of approximately $133.0 million and cash on hand of approximately $1.4 million.  The credit agreement is scheduled to mature on May 11, 2022.  As previously indicated, because the current forward price curve for crude oil is slightly backwardated and total Cushing storage volumes are below the 5-year average, we are anticipating a relatively weak recontracting environment which may impact both the volume of storage and the storage rate we are able to successfully recontract in 2018. As of July 27, 2018, we had approximately 5.0 million barrels of crude oil storage under service contracts, including an intercompany contract for 0.3 million barrels and a contract for 2.0 million barrels that commences November 1, 2018, out of our total storage capacity of 6.6 million barrels. Of these agreements, service contracts relating to 1.7 million barrels expire in 2018.

.

Capital Requirements. Our capital requirements consist of the following:

• maintenance capital expenditures, which are capital expenditures made to maintain the existing integrity and operating capacity of our assets and related cash flows, further extending the useful lives of the assets; and

• expansion capital expenditures, which are capital expenditures made to expand the operating capacity or revenue of existing or new assets, whether through construction, acquisition or modification.

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Expansion capital expenditures for organic growth projects, net of reimbursable expenditures of $0.3 million, totaled $17.6 million in the six months ended June 30,2018, compared to $5.2 million in the six months ended June 30,2017.  Expansion capital expenditures for the six months ended June 30,2018, included $9.8 million related to crude oil purchases for pipeline linefill and storage tank heels at the Cushing terminal. We currently expect our expansion capital expenditures for organic growth projects to be approximately $19.0 million to $22.0 million, inclusive of anticipated crude oil purchases for Cushing terminal and pipeline linefill and net of reimbursable expenditures, for all of 2018.  Maintenance capital expenditures totaled $3.8 million, net of reimbursable expenditures of $0.4 million, in the six months ended June 30,2018, compared to $4.5 million in the six months ended June 30,2017.  We currently expect maintenance capital expenditures to be approximately $8.0 million to $10.0 million, net of reimbursable expenditures, for all of 2018.

Our Ability to Grow Depends on Our Ability to Access External Expansion Capital. Our partnership agreement requires that we distribute all of our available cash to our unitholders. Available cash is reduced by cash reserves established by our General Partner to provide for the proper conduct of our business (including for future capital expenditures) and to comply with the provisions of our credit agreement.  We may not grow as quickly as businesses that reinvest their available cash to expand ongoing operations because we distribute all of our available cash. 

Recent Accounting Pronouncements

For information regarding recent accounting developments that may affect our future financial statements, see Note 17 to our unaudited condensed consolidated financial statements.

Item 3.    Quantitative and Qualitative Disclosures about Market Risk.

We are exposed to market risk due to variable interest rates under our credit agreement.

As of July 26, 2018, we had $263.6 million outstanding under our credit agreement that was subject to a variable interest rate.  Borrowings under our credit agreement bear interest, at our option, at either the reserve adjusted eurodollar rate (as defined in the credit agreement) plus an applicable margin 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%) plus an applicable margin. 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, we entered into two interest rate swap agreements with an aggregate notional value of $200.0 million. The first $100.0 million agreement became effective June 28, 2014, and matured on June 28, 2018. Under the terms of the first interest rate swap agreement, we paid a fixed rate of 1.45% and received one-month LIBOR with monthly settlement. The second agreement became effective January 28, 2015, and matures on January 28, 2019. Under the terms of the second interest rate swap agreement, we pay a fixed rate of 1.97% and receive one-month LIBOR with monthly settlement. The fair market value of the interest rate swaps at June 30, 2018, consists of a current asset of $0.2 million and is recorded in other current assets on our unaudited condensed 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 unaudited condensed consolidated statements of operations.

During the six months ended June 30,2018, the weighted average interest rate under our credit agreement was 5.18%.

Changes in economic conditions could result in higher interest rates, thereby increasing our interest expense and reducing our funds available for capital investment, operations or distributions to our unitholders. Based on borrowings as of June 30, 2018, the terms of our credit agreement, current interest rates and the effect of our interest rate swaps, an increase or decrease of 100 basis points in the interest rate would result in increased or decreased annual interest expense of approximately $2.5 million. 

Item 4.    Controls and Procedures.

Evaluation of disclosure controls and procedures.  Our General Partner’s management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, evaluated, as of the end of the period covered by this report, the effectiveness of our disclosure controls and procedures as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of our General Partner concluded that our disclosure controls and procedures, as of June 30, 2018, were not effective because of the material weakness in our internal control over financial reporting described in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A of Part II of our Annual Report on Form 10-K for the year ended December 31, 2017. 

Remediation Plan for the Material Weakness.Our management is actively engaged in remediation efforts to address the material weakness identified. Specifically, our management is in the process of providing additional training of financial

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reporting personnel with respect to the preparation and review of the consolidated statements of cash flows with specific focus on the control that identifies non-cash components of transactions on the statement of cash flows. Our management believes that these actions will remediate the material weakness in internal control over financial reporting.

Changes in internal control over financial reporting.  Except for the remediation efforts noted above, there were no changes in our internal control over financial reporting during the three months ended June 30, 2018, which materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1.    Legal Proceedings.

The information required by this item is included under the caption “Commitments and Contingencies” in Note 15 to our unaudited condensed consolidated financial statements and is incorporated herein by reference thereto.

Item 1A.    Risk Factors.

See the risk factors set forth in Part I, Item 1A, of our Annual Report on Form 10-K for the year ended December 31, 2017.

Item 5.    Other Information.

On July 27, 2018, Jimmy Langdon, Executive Vice President and Chief Operating Officer of Ergon, Inc., and a member of our Board of Directors passed away.  A replacement for Mr. Langdon has not yet been determined.

Item 6.    Exhibits.

The information required by this Item 6 is set forth in the Index to Exhibits accompanying this quarterly report and is incorporated herein by reference.

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SIGNATURES

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

		BLUEKNIGHT ENERGY PARTNERS, L.P.
		By:	Blueknight Energy Partners, G.P., L.L.C
			its General Partner
Date:	August 2, 2018	By:	/s/ Alex G. Stallings
			Alex G. Stallings
			Chief Financial Officer and Secretary
Date:	August 2, 2018	By:	/s/ James R. Griffin
			James R. Griffin
			Chief Accounting Officer

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INDEX TO EXHIBITS

Exhibit Number	Description
2.1	Asset Purchase Agreement, dated June 29, 2018, by and between BKEP Materials, L.L.C., BKEP Terminalling, L.L.C., BKEP Asphalt, L.L.C., and Ergon Asphalt & Emulsions, Inc. (filed as Exhibit 2.1 to the Partnership’s Current Report on Form 8-K, filed June 29, 2018, and incorporated herein by reference).
3.1	Amended and Restated Certificate of Limited Partnership of the Partnership, dated November 19, 2009, but effective as of December 1, 2009 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed November 25, 2009 (Commission File No. 001-33503), and incorporated herein by reference).
3.2	Fourth Amended and Restated Agreement of Limited Partnership of the Partnership, dated September 14, 2011 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed September 14, 2011, and incorporated herein by reference).
3.3	Amended and Restated Certificate of Formation of the General Partner, dated November 20, 2009 but effective as of December 1, 2009 (filed as Exhibit 3.2 to the Partnership’s Current Report on Form 8-K, filed November 25, 2009 (Commission File No. 001-33503), and incorporated herein by reference).
3.4	Second Amended and Restated Limited Liability Company Agreement of the General Partner, dated December 1, 2009 (filed as Exhibit 3.2 to the Partnership’s Current Report on Form 8-K, filed December 7, 2009 (Commission File No. 001-33503), and incorporated herein by reference).
4.1	Registration Rights Agreement, dated October 5, 2016, by and among Blueknight Energy Partners, L.P., Ergon Asphalt & Emulsions, Inc., Ergon Terminaling, Inc. and Ergon Asphalt Holdings, LLC (filed as Exhibit 4.1 to the Partnership’s Current Report on Form 8-K, filed October 5, 2016, and incorporated herein by reference).
10.1	Agreement, dated May 9, 2018, by and between Ergon Terminaling, Inc. and Blueknight Energy Partners, L. P. (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed May 14, 2018, and incorporated herein by reference).
10.2	First Amendment to Second Amended and Restated Credit Agreement, dated as of June 28, 2018, by and among the Partnership, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders party thereto (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed June 29, 2018, and incorporated herein by reference).
10.3	Domestic Crude Oil and Condensate Agreement, dated March 28, 2018, by and between Ergon Oil Purchasing, Inc. and BKEP Supply and Marketing, LLC.
31.1#	Certifications of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2#	Certifications of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1#	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”
101#	The following financial information from Blueknight Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018, formatted in XBRL (eXtensible Business Reporting Language): (i) Document and Entity Information; (ii) Unaudited Condensed Consolidated Balance Sheets as of December 31, 2017 and June 30, 2018; (iii) Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2017 and 2018; (iv) Unaudited Condensed Consolidated Statement of Changes in Partners’ Capital (Deficit) for the six months ended June 30, 2018; (v) Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2017 and 2018; and (vi) Notes to Unaudited Condensed Consolidated Financial Statements.

____________________

#     Furnished herewith

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EX-10.3

Exhibit 10.3

3/22/2018	BKEP Contact:	Bryan Adcock
	BKEP Contract #:	2018-00097
	Ergon’s BKEP Contract:
		(Please Supply)

CONFIRMATION OF AGREEMENT

Company:	Ergon Oil Purchasing, Inc.
Marketer:	Barton Lampton
	P.O. Box 1308
	Jackson, MS 39215
Email:	Barton.Lampton@ergon.com

Ergon’s Sale and Delivery to BKEP

This agreement (“Original Agreement”) is made between BKEP Supply and Marketing LLC (“BKEP”) and Ergon Oil Purchasing, Inc. (“Ergon”) whereby Ergon agrees to sell and deliver and BKEP agrees to purchase and receive crude oil and/or condensate under the terms and conditions set forth herein:

1.	Quality:	Oklahoma Sweet Crude Oil
2.	Quantity:	100% of Seller’s owned or controlled production from the leases listed in Exhibit A
3.	Price:	Price as indicated on Exhibit A
4.	Term:	Commencing April 1, 2018 through April 30, 2018, thereafter month to month until either party provides thirty (30) days’ advance written notice of cancellation
5.	Payment:	Commencing April 1, 2018 through April 30, 2018, thereafter month to month until either party provides thirty (30) days’ advance written notice of cancellation
6.	Payment:	Commencing April 1, 2018 through April 30, 2018, thereafter month to month until either party provides thirty (30) days’ advance written notice of cancellation
7.	General Terms and Provisions:	All other terms and conditions not specifically stated shall be governed by COP General Provisions as revised January 1, 2017, and by Exhibit B, both attached hereto and made a part hereof:

The confirmation sets forth BKEP’s and Ergon’s understanding of the terms of our agreement. Please notify our Contract Administrator in writing by email or fax - with specific reference to the BKEP contract number provided above - of your acceptance of the terms and conditions set forth in this confirmation, upon which this confirmation shall be final and binding on all parties. Additional terms other than commercial terms submitted with any such notice will not form a part of our agreement unless otherwise expressly agreed to in writing by the parties

Questions may be directed to the Contract Administrator, Kathryn Stephens, at: phone (405) 278-6441, fax

(405) 278-6479 or KStephens@bkep.com .

BUYER:		SELLER:
BKEP Supply and Marketing LLC		Ergon Oil Purchasing, Inc.
By	/s/ Brian L Melton	Signed	/s/ Leslie Barton Lampton, IV
Title	Chief Commercial Officer	Printed Name	Vice President-General Manager
Date	3/28/2018	Date	3/22/2018

Sincerely,

BKEP Supply and Marketing LLC

GENERAL PROVISIONS

DOMESTIC CRUDE OIL AND CONDENSATE AGREEMENTS

A.     Measurement and Tests:     All measurements hereunder shall be made in accordance with the ConocoPhillips Company Crude Oil and Condensate Quantity and Quality Determination Guidelines attached as Appendix 1. The Product delivered hereunder shall be marketable and acceptable in the applicable common or segregated stream of the carriers involved but not to exceed 1% S&W.

B.     Warranty:     The Seller warrants good title to all Product delivered hereunder and warrants that such Product shall be free from all royalties, liens, and encumbrances (except for any statutory lien applicable where Buyer is the first purchaser of the Product).

Seller further warrants that the Product delivered shall not be contaminated by chemicals foreign to virgin Product and its production including, but not limited to chlorinated and/or oxygenated hydrocarbons and lead. Buyer shall have the right, without prejudice to any other remedy available to Buyer, to reject and return to Seller any quantities of Product which are found to be so contaminated, even after delivery to Buyer.

Except as expressly set forth in Section B, Seller makes no other warranties, express or implied, including without limitation any implied warranty of merchantability or fitness for any particular purpose.

C.     Rules and Regulations:    The terms, provisions and activities undertaken pursuant to this Agreement shall be subject to, and each party shall comply with, all applicable laws, orders and regulations of all governmental authorities. If at any time a provision hereof violates any such applicable laws, orders or regulations, such provision shall be voided and the remainder of the Agreement shall continue in full force and effect unless terminated by either party upon giving written notice to the other party hereto.

D.     Hazard Communication:    Seller shall provide or make available its Safety Data Sheet ("SDS") to Buyer. Buyer acknowledges that it is familiar with the Product and is sophisticated and knowledgeable of the hazards and risks associated with the Product. Buyer shall read the SDS and advise its employees, its affiliates, and third parties, who may purchase or come into contact with such Product, about the hazards of the Product, as well as the precautionary procedures for handling said Product, which are set forth in such SDS and any supplementary SDS or written warning(s) which Seller may provide to Buyer from time to time. Each party acknowledges that it will comply with all safety and health related governmental requirements concerning the Product, including its handling, transportation, storage and use. The Parties acknowledge that the SDS for any Product sold by COP hereunder is made available by COP at:

http://www.conocophillips.com/sustainable-development/safety-health/Pages/safety-data-sheets.aspx.

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E.     Force Majeure:    Except for payment due hereunder, either party hereto shall be relieved fromliability for failure to perform hereunder for the duration and to the extent its performance is prevented by war, riots, insurrections, fire, explosions, sabotage, strikes, and other labor or industrial disturbances, acts of God or the elements, governmental laws, regulations, sanctions, or requests, acts in furtherance of a program of the International Energy Agency, disruption or breakdown of production or transportation facilities, delays of pipeline carrier in receiving and delivering Product tendered, or by any other cause, whether similar or not, reasonably beyond the control of such party (Force Majeure). Neither party shall be required to supply substitute quantities from other sources of supply. Failure to perform due to events of Force Majeure shall not extend the term of this Agreement except to the extent necessary to comply with the provisions of Section J (Buy/Sell and Exchange Balancing). The party declaring a Force Majeure situation (the Declaring Party) shall take commercially reasonable steps to ameliorate the cause of such Force Majeure event to enable it to resume performance during the term of this Agreement.

In addition to the above, and in the event substantially similar volumes are intended to be bought and sold or exchanged under this Agreement, the parties shall have the rights and obligations set forth in the circumstances described below:

(1)    If, because of Force Majeure, the Declaring Party is unable to deliver part or all of the quantity of Product which it is obligated to deliver under this Agreement, the other party shall have the right, but not the obligation, to reduce its deliveries of Product under this Agreement to match the volume actually delivered by the Declaring Party.

(2)    If, because of Force Majeure, the Declaring Party is unable to take part or all of the quantity of Product which it is obligated to take under this Agreement, the other party shall have the right, but not the obligation, to reduce its receipts of Product under this Agreement to match the volume actually taken by the Declaring Party.

The Declaring Party must provide prompt notice to the other party. Initial notice may be given orally, but written notice with reasonably full particulars of the event or occurrence is required as soon as reasonably possible. Upon providing written notice of Force Majeure to the other party, the Declaring Party will be relieved of its obligation, from the onset of the Force Majeure event, to make or accept delivery, as applicable, to the extent and for the duration of the Force Majeure, and neither party shall be deemed to have failed in such obligations to the other during such occurrence or event.

F.    Payment:    Unless otherwise specified in the Special Provisions of this Agreement, Buyer agrees to make payment against Seller's invoice for the Product purchased hereunder to a bank designated by Seller in U.S. dollars by wire transfer in immediately available funds. Unless otherwise specified in the Special Provisions of this Agreement, payment will be due on or before the 20th of the month following the month of delivery or within 10 business days after receipt of the invoice, whichever is later. If payment due date is on a Saturday or New York bank holiday other than Monday, payment shall be due on the preceding New York banking day. If payment due date is on a Sunday or a

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Monday New York bank holiday, payment shall be due on the succeeding New York banking day.

Payment shall be deemed to be made on the date good funds are credited to Seller's account at Seller's designated bank.

In the event that Buyer fails to make any payment when due, Seller shall have the right to charge interest on the amount of the overdue payment at a per annum rate which shall be two percentage points higher than the then-effective prime rate of interest published under Money Rates by the Wall Street Journal on the date payment was due, but not to exceed the maximum rate permitted by law.

G.     Financial Responsibility:    Notwithstanding anything to the contrary in this Agreement, should Seller reasonably believe it necessary to assure payment, Seller may at any time require, by written notice to Buyer, advance cash payment or satisfactory security in the form of a Letter or Letters of Credit at Buyer's expense in a form and from a bank acceptable to Seller (Payment Assurance), to cover any or all deliveries of Product. If Buyer does not provide Payment Assurance on or before the date specified in Seller's notice under this section (which date shall be no less than two Business Days after such notice is received), or if Payment Assurance is required under the Special Provisions of this Agreement and Buyer does not provide same, then Seller may terminate this Agreement forthwith. In no event shall Seller be obligated to schedule or complete delivery of the Product until said Payment Assurance is received by and found acceptable to Seller.

If a party to this Agreement should (1) become the subject of bankruptcy or other insolvency proceedings, or proceedings for the appointment of a receiver, trustee, or similar official, (2) become generally unable to pay its debts as they become due, or (3) make a general assignment for the benefit of creditors, such an event shall be an Insolvency Event and the other party to this Agreement may withhold shipments without notice.

H.     Default and Remedies:

(1)     Rights of Parties.     At any time after the occurrence of an Event of Default, the other party to the Agreement (the "Non-Defaulting Party") shall have the right, at its sole discretion, to suspend performance, and/or to terminate and liquidate this Agreement upon giving written notice to the Defaulting Party. Upon termination, the parties shall have no further rights or obligations with respect to this Agreement, except for the payment of the amount(s) (the "Settlement Amount" or "Settlement Amounts") determined as provided in Paragraph (2) of this section and any unpaid amounts.

(2)     Settlement Amount.     The Settlement Amount under this Agreement shall be equal to the aggregate of (i) the portion(s) of the contract quantity(ies) of Product not yet delivered, multiplied by the difference between the applicable contract price per Barrel specified in this Agreement (the "Contract Price") and the applicable market price per Barrel of Product on the date the Non-Defaulting Party terminates this Agreement (the

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"Market Price") and (ii) any Unpaid Amounts, with amounts under clause (i) expressed as owed to the Seller, if the Market Price is less than the Contract Price, or expressed as owed to the Buyer, if the Market Price is greater than the Contract Price.

(3)     Market Price.         Unless otherwise provided in this Agreement, the Market Price of Product sold or exchanged under this Agreement shall be the market price for a similar sale of Product at the same delivery location, as determined by the Non-Defaulting Party in a commercially reasonable manner.

(4)     Payment of Settlement Amount.     The Settlement Amount due upon termination of this Agreement shall be aggregated and the Non-Defaulting Party may elect to set off any amount that would be payable to the Defaulting Party against any amounts payable by the Defaulting Party or its affiliates to the Non-Defaulting Party or its affiliates under any other agreement or arrangement. The party owing the net amount after such aggregation and set off shall pay such net amount to the other party in immediately available funds within two Business Days after the date on which the Non-Defaulting Party gives notice of the amount owed.

(5)     Forward Contract.     The parties hereby acknowledge that each party is a forward contract merchant and this Agreement constitutes a forward contract for purposes of Section 556 of the U.S. Bankruptcy Code.

(6)     Miscellaneous.     This section shall not limit the rights and remedies available to the Non-Defaulting Party (whether by law or under other provisions of this Agreement or otherwise).

I.     Equal Daily Deliveries:    For pricing purposes only, unless otherwise specified in the Special Provisions, all Product delivered hereunder during any calendar month shall be considered to have been delivered in equal daily quantities during such month.

J     Buy/Sell and Exchange Balancing:     The terms of this Section J shall only apply to this Agreement if substantially similar volumes are intended to be bought and sold or exchanged under this Agreement:

(1)    Each party shall be responsible for maintaining the volumes bought and sold or exchanged in balance on a month-to-month basis, as near as reasonably possible.

(2)    If, for any reason (including events of Force Majeure), a party complies with the requirements of Section J(1) but fails to deliver or accept delivery of the contractually specified volume during any month (an Imbalance Month), then the party that delivered the lesser volume during the Imbalance Month (the Underdelivering Party) shall deliver to the other party a volume of Product equal to the difference between (a) the volume delivered by the Underdelivering Party during the Imbalance Month, and (b) the volume delivered by the other party during the Imbalance Month (such difference being the Imbalance Volume). The Imbalance Volume shall be delivered as soon after the Imbalance Month as is reasonably practicable it being understood that the parties shall endeavor to cause the Imbalance Volumes confirmed by the 20th day of the Imbalance

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Month to be delivered during the immediately following calendar month, and the Imbalance Volumes confirmed after the 20th day of the Imbalance month to be delivered during the second calendar month after the Imbalance Month, except to the extent prevented by a new or continued event of Force Majeure.

(3)    When a party fails to deliver or accept delivery of the contractually specified volume during an Imbalance Month due to an event of Force Majeure, if the Imbalance Volume has not been delivered before the end of the second calendar month after the Imbalance Month, and if no other resolution of the Imbalance Volumes has been agreed between the Parties, during the third month after the Imbalance Month, the Underdelivering Party shall deliver, and the other party shall take, an amount of Product equal to the Imbalance Volume, and such delivery shall be of the same type of Product, at the same location and (except as provided in Section J(4) below) at the same price as the Product received by the Underdelivering Party during the Imbalance Month.

(4)     To the extent that an Imbalance Volume is delivered after the Imbalance Month, and except as provided in the Special Provisions of this Agreement: (1) if the price specified in this Agreement is a fixed price or a formula price based on the price of a commodity on a date or during a specified range of dates (e.g., April 12, 2009, or April 12-19, 2009), the price of the Imbalance Volumes shall be equal to such price without regard to the month of actual delivery; and (2) if the price specified in this Agreement is a formula price based on the price of a commodity on a date or during a range of dates that is not tied to a specific date or range of dates (e.g., bill of lading date, month of delivery, NYMEX trade month, Argus trade month, or calendar month average), the price for the Imbalance Volumes will be calculated according to such formula for the actual month the Imbalance Volume is delivered.

(5)    The foregoing notwithstanding, the obligation of either party to deliver or take an Imbalance Volume less than 1000 Barrels at the end of this Agreement shall be excused.

K.     Delivery, Title, and Risk of Loss:     Title to, responsibility for and risk of loss of the Product shall pass from the Seller to the Buyer upon delivery. Delivery shall be effected as follows:

(1)    For lease delivery locations, delivery of the Product to the Buyer shall be effected as the Product passes the last permanent delivery flange and/or meter connecting the Seller's lease/unit storage tanks or processing facilities to the Buyer's carrier.

(2)    For delivery locations other than lease/unit delivery locations, delivery of the Product to the Buyer shall be effected as the Product passes the last permanent delivery flange and/or meter connecting the Seller’s carrier (or other storage or delivery facility designated by the Seller, as applicable) to the Buyer's carrier.

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ConocoPhillips Company

(3)    If delivery is by in-line or in-tank transfer, delivery of the Product to the Buyer shall be effected at the particular pipeline point or storage tank facility designated in this Agreement as specified in the pipeline or storage tank facility documentation authorizing the transfer of title for the specified quantity at such location or, in the absence of such documentation, upon the date of transfer shown in the title transfer documentation provided to such pipeline or storage facility operator.

Where ConocoPhillips Company is Seller, (a) ConocoPhillips shall be responsible for performance of the pre-transportation functions as defined in 49 CFR 171.1(b) and 171.8 and shall certify in compliance with the requirements of 49 CFR 172.204, with respect to non-pipeline transportation of the Product to the delivery location and (b) Buyer shall be responsible for performance of the pre-transportation functions as defined in 49 CFR 171.1(b) and 171.8 and shall certify in compliance with the requirements of 49 CFR 172.204, with respect to non-pipeline transportation of the Product from the delivery location.

L.     Term:     Unless otherwise specified in the Special Provisions, delivery months begin at 7:00 a.m. at the delivery location on the first day of the calendar month and end at 7:00 a.m. at the delivery location on the first day of the following calendar month. The term of the Agreement specified in the Special Provisions shall be extended as necessary to enable the parties to comply with their obligations under Section J (Buy/Sell and Exchange Balancing).

M.     Governing Law:     This Agreement and any disputes arising hereunder shall be governed by the laws of the State of Texas, without regard to principles of conflicts of law.

N.     Limitation of Liability:     IN NO EVENT SHALL EITHER PARTY BE LIABLE FOR LOSS OF PROFITS OR INDIRECT, SPECIAL, EXEMPLARY, PUNITIVE OR CONSEQUENTIAL DAMAGES, EXCEPT (IF APPLICABLE) FOR THIRD PARTY CLAIMS FOR WHICH A PARTY IS OBLIGATED TO INDEMNIFY THE OTHER PARTY UNDER THIS AGREEMENT..

O.     Indemnity:     TO THE FULLEST EXTENT PERMITTED BY LAW, (A) SELLER SHALL INDEMNIFY, DEFEND AND HOLD HARMLESS BUYER FROM AND AGAINST ALL LOSSES, LIABILITIES, COSTS, EXPENSES, DEMANDS, ACTIONS, SUITS, DAMAGES, SETTLEMENTS, JUDGMENTS, AND CLAIMS, INCLUDING REASONABLE ATTORNEYS’ FEES AND COSTS OF COURT (CLAIMS), FROM ANY AND ALL PERSONS, ARISING FROM OR OUT OF ANY INCIDENT RELATED TO THE PRODUCT THAT OCCURS BEFORE ITS DELIVERY TO BUYER UNDER THIS AGREEMENT; AND (B) BUYER SHALL INDEMNIFY, DEFEND AND HOLD HARMLESS SELLER FROM ALL CLAIMS, FROM ANY AND ALL PERSONS, ARISING FROM OR OUT OF ANY INCIDENT RELATED TO THE PRODUCT WHICH OCCURS UPON OR AFTER ITS DELIVERY TO BUYER UNDER THIS AGREEMENT. INCIDENT SHALL REFER TO THE OCCURRENCE OF BODILY INJURY, PROPERTY DAMAGE, OR ECONOMIC LOSS. EACH PARTY’S INDEMNITY OBLIGATIONS HEREUNDER SHALL BE

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WITHOUT REGARD TO THE FAULT OR CAUSES THEREOF, INCLUDING ANY BREACH OF DUTY (STATUTORY, COMMON LAW, OR OTHERWISE), CONTRACT OR WARRANTY, TORT OR STRICT LIABILITY, OR THE NEGLIGENCE OF ANY PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR ACTIVE OR PASSIVE, AND INCLUDING CLAIMS FOR PERSONAL INJURY, PROPERTY DAMAGE, OR ECONOMIC LOSS

P.     Taxes:     Seller shall be responsible for and shall pay any applicable Taxes that are imposed on or with respect to the Product prior to the transfer of title to the Product to Buyer. The Price does not include, and Buyer shall be responsible for and shall pay, any applicable Taxes that are imposed on or with respect to the Product upon or after the transfer of title to the Product to Buyer. If a party is required by applicable law to collect and remit applicable Taxes that are the other party’s responsibility hereunder, the party so required will comply with such collection and remission requirements, and the party responsible for such Taxes will promptly reimburse the other party for such Taxes. If there are any applicable exemptions, the party entitled to such exemption will furnish to the other party a fully executed exemption certificate or other like documentation prior to claiming such exemption. As used herein, Taxes means any applicable federal, state and local sales, use, gross receipts, excise and other similar taxes, levies, duties, fees and charges in the nature of a tax, other than any income, franchise, license privilege, net worth, gross margin, gross profit, payroll, ad valorem or other similar taxes imposed on a party in connection with the operation of its business or the ownership of its assets.

Q.     Notices:     Notices, requests or other communications to be given to the other party in connection with this Agreement shall be in writing, shall be addressed as provided in the Special Provisions (or to such other address as a party has designated by at least 10 days prior written notice), and shall be delivered in person, sent by telecopy or sent by a recognized overnight delivery service. Notices so delivered shall be deemed properly given when received; provided, however, any notice received on a day that is not a Business Day and any notice received after 5:00 pm local time on any day will be deemed received on the following Business Day.

R.     Necessary Documents:    Upon request, each party agrees to furnish all substantiating documents incident to the transaction, including a Delivery Ticket for each volume delivered and an invoice for any month in which the sums are due.

S.     Waiver:     No waiver by either party regarding the performance of the other party under any of the provisions of this Agreement shall be construed as a waiver of any subsequent performance under the same or any other provisions.

T.     Assignment:         Neither party shall assign this Agreement or any rights hereunder without the written consent of the other party unless such assignment is made to a person controlling, controlled by or under common control with assignor, in which event assignor shall remain responsible for proper performance of the Agreement.

U.     Status of Parties; Entirety of Agreement:     Neither party is acting as a fiduciary for or an advisor to the other party in respect of this Agreement or any transaction hereunder.

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The Special Provisions and these General Provisions contain the entire Agreement of the parties; there are no other promises, representations or warranties. Any modification of this Agreement shall be by written instrument. Any conflict between the Special Provisions and these General Provisions shall be resolved in favor of the Special Provisions. The section headings are for convenience only and shall not limit or change the subject matter of this Agreement.

V. Trade Controls and Boycotts, Export Compliance, and Anti-Corruption:

(1)    Trade Controls and Boycotts. Each Party shall comply with all U.S. laws, regulations, rules and requirements that relate to foreign trade controls, export and re-export controls, embargoes or international boycotts of any type (Trade Control Laws). Nothing shall be shipped to, transshipped through, or otherwise transferred to, directly or indirectly, any country, entity or individual, or for any end use, that is prohibited under Trade Control Laws, or that is prohibited by sanctions imposed by the United States or the United Nations (including Trade Control Laws or sanctions imposed after this Agreement is entered into but before Product is delivered). At any time, the Seller may require the Buyer to provide any relevant documents for the purpose of verifying the final destination of the Product, and the Buyer shall provide such documents upon request. Notwithstanding anything to the contrary herein, nothing in the Agreement is intended, and nothing herein should be interpreted or construed, to induce or require either party hereto to act in any manner (including failing to take any actions in connection with a transaction) which is inconsistent with, penalized or prohibited under Trade Control Laws.

(2)     Export Compliance. If Product sold by ConocoPhillips Company to Buyer under this Agreement is to be exported by Buyer from the United States, then unless otherwise provided in the Special Provisions: (1) Buyer and its authorized US agent, if applicable, shall obtain all licenses, permits or approvals and comply with all applicable laws, regulations, governmental rules and requirements for export of the Product from the United States and shall prepare and file any export related filings and pay any export-related duties, taxes or other fees; (2) if Buyer is a U.S. entity, then Buyer shall be the U.S. Principle Party in Interest; and (3) Upon request from Seller, Buyer shall promptly provide Seller a copy of any export documentation or filing submitted.

(3)     Anti-Corruption. Each Party warrants to the other, that in connection with the Agreement, it will comply with all applicable laws, rules, regulations, decrees and/or official government orders of the United States, and any other jurisdiction applicable to it, relating to anti-bribery and anti-money laundering, including but not limited to the U.S. Foreign Corrupt Practices Act. Neither Party nor its employees or representatives shall, directly or indirectly: (i) pay salaries, commissions or fees, or make payments or rebates to any of the other Party’s employees or representatives, or their designees; (ii) favor any of the other Party’s employees or representatives or their designees with gifts or entertainment of significant cost or value, or with services or goods sold at less than full market value; or (iii) enter into business arrangements with any of the other Party’s employees or representatives unless such individual is acting in his official capacity as a representative of such Party.

(4)    Violations and Remedies. Either Party may terminate the Agreement upon written notice to the other at any time if in its reasonable judgment the other is in breach of

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any representation, warranty, undertaking or obligation under the above clauses for Trade Controls and Boycotts, Export Compliance, and Anti-Corruption. Further, each Party shall indemnify and hold harmless the other Party from and against any claims, liabilities, losses, costs, damages, fines and/or penalties arising from the indemnifying Party’s breach of the above clauses for Trade Controls and Boycotts, Export Compliance, and Anti-Corruption.

W.     Definitions:     When used in this Agreement, the terms listed below have the following meanings:

"API" means the American Petroleum Institute.

"ASME" means the American Society of Mechanical Engineers.

"ASTM" means the American Society for Testing Materials.

"Barrel" means 42 U.S. gallons of 231 cubic inches per gallon corrected to 60 degrees Fahrenheit.

"Business Day" means a day other than a Saturday or Sunday when federal banks are open for business in New York, New York.

"Carrier" means a pipeline, barge, truck, or other suitable transporter of Product.

"Day," "month," and "year" mean, respectively, calendar day, calendar month, and calendar year, unless otherwise specified.

"Delivery Ticket" means a shipping/loading document or documents stating the type and quality of Product delivered, the volume delivered and method of measurement, the corrected specific gravity, temperature, and S&W content.

"Event of Default" means, with respect to a party hereto (the Defaulting Party), (a) the failure to make, when due, any payment required hereunder, if such failure is not cured within 2 Business Days of written notice; (b) the failure to timely provide Payment Assurance; or (c) the occurrence of an Insolvency Event.

"Invoice" means a statement setting forth at least the following information: The date(s) of delivery under the transaction; the location(s) of delivery; the volume(s); price(s); the specific gravity and gravity adjustments to the price(s) (where applicable); and the of payment instructions.

"Product" means the crude oil, condensate or other product to be delivered by Seller per the Special Provisions.

"S&W" means sediment and water.

"Unpaid Amounts" means any amounts owed but not yet paid to Seller for Product already delivered under this Agreement.

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APPENDIX 1

CONOCOPHILLIPS COMPANY

CRUDE OIL AND CONDENSATE

QUANTITY AND QUALITY DETERMINATION GUIDELINES

The procedures, equipment, calculations, and tests for determining the quantity and quality of crude oil or condensate (Product) received or delivered shall be those as specified in the latest revision of the American Petroleum Institute - Manual of Petroleum Measurement (API MPMS), and test methods as specified in the American Society for Testing and Materials (ASTM). The specific procedures, guidelines and tests as applicable are given below.

1.     Pipeline, Truck, or Rail Car Measurement.

1.1 The quantity of Product received or delivered by pipeline shall be determined by one of the following methods in the following order of preference:

1.1.1	Calibrated custody transfer meters, or
1.1.1	Tank gauge with appropriate application of certified tank strapping tables before and after transfer.

1.2 The quantity of Product received or delivered by truck or rail car shall be determined by one of the following methods in order of preference:

1.2.1	Calibrated custody transfer meters,
1.2.2	Tank gauge of static tanks with the appropriate application of certified tank strapping tables before and after transfer,
1.2.3	Certified Scales, or
1.2.4	Truck or railcar gauge with appropriate application of certified truck/ railcar strapping tables.

2. Marine Measurement.

2.1 The quantity and quality of marine cargo received or delivered shall be determined by a mutually appointed Independent Inspection Company (IIC).

2.2 The quantity of Product received or delivered shall be determined by one of the following methods in order of preference

2.2.1	Calibrated custody transfer meters,
2.2.2	Shore tank gauge of static shore tanks with the appropriate application of certified tank strapping tables before and after transfer,
2.2.3	Vessel gauge before and after transfer, with application of a valid Vessel Experience Factor (VEF) as determined from API MPMS Chapter 17.9, or
2.2.4	By agreement between the Buyer and Seller.

ConocoPhillips Company - Crude Oil and Condensate Quantity and Quality Determination Guidelines

Effective January 1, 2017     Page 1 of 2

2.3 Gauged quantities shall not be made through unslotted standpipes. Tanks shall be static, and measurements shall not be taken in critical zones, or when tanks or vessels contain insufficient Product to allow for an accurate measurement.

2.4 A line fullness verification shall be performed prior to custody transfer of the Product using any of the approved methods in API MPMS Chapter 17.6. Adjustments to the quantities received or delivered shall be consistent with the methodologies in API MPMS Chapter 17.6. When the line displacement method of line fullness verification is employed, it will be performed by the delivering vessel pumping to the furthermost receiving shore tank to be utilized during each marine vessel transfer.

2.5 Quantity as determined by the IIC shall be final and binding on all parties and will be the basis for preparing relevant shipping documents and invoices save fraud and/or manifest error. If, for any reason an IIC is not in attendance or if terminal operating procedures prevail, then quantity as determined by terminal personnel shall be final and binding on all parties and will be the basis for preparing relevant shipping documents and invoices save fraud and/or manifest error.

3.     Calculations, Sampling, and Testing.

3.1 Volume measurements shall be corrected to 60 degrees Fahrenheit and one atmosphere (14.696 psia) in accordance with the latest revision of API MPMS Chapter 11 Table 6A. Gravity measurements shall be corrected to 60 degrees Fahrenheit and one atmosphere (14.696 psia).

3.2 Product shall be sampled for quality analysis based on one of the following methods in order of preference:

3.2.1	In-line sampler, obtained by a flow-proportional in-line sampler that performs in accordance with API MPMS Chapter 8.2,
3.2.2	Spot samples by manually sampling tanks, vessels, trucks/ cars, or pipelines in accordance with API MPMS Chapter 8.1, or
3.2.3	As mutually agreed by Buyer and Seller.

3.3 S&W shall be determined from samples of Product using one of the following methods in order of preference:

3.3.1	Membrane Filtration (ASTM D4807) and Karl Fischer (ASTM D4928),
3.3.2	Extraction (ASTM D473) and Distillation (D4006), or
3.3.3	Centrifuge (ASTM D4007),

3.4 A full deduction for all free water and S&W shall be made in accordance with the API MPMS methods and standards.

3.5 Seller and Buyer shall have the right to have a representative witness all measurements and tests. Measurements and tests conducted in the absence of a party’s representative shall be presumed to be correct and binding on both parties and will be the basis for the preparation of relevant shipping documents and invoices except in the case of fraud or manifest error.

ConocoPhillips Company - Crude Oil and Condensate Quantity and Quality Determination Guidelines

Effective January 1, 2017     Page 2 of 2

EX-31.1

Exhibit 31.1

CERTIFICATION

PURSUANT TO AND IN CONNECTION WITH THE REPORTS

TO BE FILED UNDER SECTION 13 AND 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Mark Hurley, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Blueknight Energy Partners, L.P.;

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

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

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

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

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

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

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

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

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

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

Date:	August 2, 2018
/s/ Mark Hurley
Mark Hurley
Chief Executive Officer
Blueknight Energy Partners, G.P., L.L.C.,
general partner of Blueknight Energy Partners, L.P.

EX-31.2

Exhibit 31.2

CERTIFICATION

PURSUANT TO AND IN CONNECTION WITH THE REPORTS

TO BE FILED UNDER SECTION 13 AND 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Alex G. Stallings, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Blueknight Energy Partners, L.P.;

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

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

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

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

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

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

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

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

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

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

Date:	August 2, 2018
/s/ Alex G. Stallings
Alex G. Stallings
Chief Financial Officer and Secretary of
Blueknight Energy Partners, G.P., L.L.C.,
general partner of Blueknight Energy Partners, L.P.

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002 (18 U.S.C. SECTION 1350)*

In connection with the Quarterly Report of Blueknight Energy Partners, L.P., a Delaware limited partnership (the “Partnership”), on Form 10-Q for the quarter ended June 30, 2018 as filed with the Securities and Exchange Commission (the “Report”), each of the undersigned, Mark Hurley, Chief Executive Officer of Blueknight Energy Partners G.P., L.L.C., and Alex G. Stallings, Chief Financial Officer and Secretary of Blueknight Energy Partners G.P., L.L.C., certifies, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), that to his knowledge:

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

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Partnership.

/s/ Mark Hurley

Mark Hurley

Chief Executive Officer of

Blueknight Energy Partners G.P., L.L.C.,

general partner of Blueknight Energy Partners, L.P.

August 2, 2018

/s/ Alex G. Stallings

Alex G. Stallings

Chief Financial Officer and Secretary of

Blueknight Energy Partners G.P., L.L.C.,

general partner of Blueknight Energy Partners, L.P.

August 2, 2018

* A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request. The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Report.

XML

Document And Entity Information - shares	6 Months Ended
	Jun. 30, 2018	Jul. 26, 2018	Dec. 31, 2017
Entity Information [Line Items]
Series A Preferred unitholders, units outstanding	35,125,202		35,125,202
Entity Registrant Name	Blueknight Energy Partners, L.P.
Entity Central Index Key	0001392091
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
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2018
Entity Common Stock, Shares Outstanding		40,387,006
Subsequent Event [Member]
Entity Information [Line Items]
Series A Preferred unitholders, units outstanding		35,125,202

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 1,193	$ 2,469
Accounts receivable, net of allowance for doubtful accounts of $28 and $29 at December 31, 2017 and June 30, 2018, respectively	31,268	7,589
Receivables from related parties, net of allowance for doubtful accounts of $0 at both dates	1,219	3,070
Prepaid insurance	2,093	2,009
Other current assets	12,716	8,438
Total current assets	48,489	23,575
Assets, Noncurrent [Abstract]
Property, plant and equipment, net of accumulated depreciation of $316,591 and $269,978 at December 31, 2017 and June 30, 2018, respectively	295,711	296,069
Assets held for sale, net of accumulated depreciation of $55,583 at June 30, 2018	16,857	0
Goodwill	6,728	3,870
Debt issuance costs, net	3,802	4,442
Intangibles and other assets, net	18,919	12,913
Total assets	390,506	340,869
Current liabilities:
Accounts payable	5,244	4,439
Accounts payable to related parties	12,878	2,268
Accrued interest payable	644	694
Accrued property taxes payable	3,365	2,432
Unearned revenue	2,039	2,393
Unearned revenue with related parties	4,384	551
Accrued payroll	3,671	6,119
Other current liabilities	17,379	4,747
Total current liabilities	49,604	23,643
Long-term unearned revenue with related parties	960	1,052
Other long-term liabilities	3,715	3,673
Long-term interest rate swap liabilities	0	225
Long-term debt	349,592	307,592
Commitments and contingencies (Note 15)
Partners’ capital:
Common unitholders (40,158,342 and 40,326,571 units issued and outstanding at December 31, 2017 and June 30, 2018, respectively)	436,416	454,358
Preferred Units (35,125,202 units issued and outstanding at both dates)	253,923	253,923
General partner interest (1.6% interest with 1,225,409 general partner units outstanding at both dates)	(703,704)	(703,597)
Total partners’ capital	(13,365)	4,684
Total liabilities and partners’ capital	$ 390,506	$ 340,869

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Current assets:
Accounts receivable, allowance for doubtful accounts	$ 29	$ 28
Receivables from related parties, allowance for doubtful accounts	0	0
Assets, Noncurrent [Abstract]
Accumulated depreciation	269,978	316,591
Accumulated Depreciation, Assets held for sale	$ (55,583)	$ 0
Partners’ capital:
Common unitholders, units issued	40,326,571	40,158,342
Common unitholders, units outstanding	40,326,571	40,158,342
Series A Preferred unitholders, units issued	35,125,202	35,125,202
Series A Preferred unitholders, units outstanding	35,125,202	35,125,202
General partner interest, units outstanding	1,225,409	1,225,409
General partner percentage interest	1.60%	1.60%

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Service revenue:
Third-party revenue	$ 14,103	$ 28,145	$ 31,421	$ 56,808
Related-party revenue	6,063	13,505	12,384	27,147
Lease revenue:
Third-party revenue	10,237	0	20,041	0
Related-party revenue	7,475	0	15,178	0
Product sales revenue:
Third-party revenue	45,615	2,227	49,129	6,262
Total revenue	83,493	43,877	128,153	90,217
Costs and expenses:
Operating expense	28,988	30,610	60,123	62,516
Third-party cost of product sales	20,041	1,669	22,678	4,808
Related-party cost of product sales	23,747	0	23,747	0
General and administrative expense	4,486	4,322	8,707	8,907
Asset impairment expense	0	17	616	45
Total costs and expenses	77,262	36,618	115,871	76,276
Gain (loss) on sale of assets	599	(754)	363	(879)
Operating income	6,830	6,505	12,645	13,062
Other income (expenses):
Equity earnings in unconsolidated affiliate	0	0	0	61
Gain on sale of unconsolidated affiliate	0	4,172	2,225	4,172
Interest expense (net of capitalized interest of $3, $43, $5 and $72, respectively)	(5,024)	(4,265)	(8,593)	(7,295)
Income before income taxes	1,806	6,412	6,277	10,000
Provision for income taxes	21	41	50	87
Net income	1,785	6,371	6,227	9,913
Allocation of net income for calculation of earnings per unit:
General partner interest in net income	28	256	259	465
Preferred interest in net income	6,279	6,279	12,557	12,558
Net loss available to limited partners	$ (4,522)	$ (164)	$ (6,589)	$ (3,110)
Basic and diluted net loss per common unit	$ (0.11)	$ 0.00	$ (0.16)	$ (0.08)
Weighted average common units outstanding - basic and diluted	40,324	38,155	40,306	38,151

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CONSOLIDATED STATEMENTS OF OPERATIONS CONSOLIDATED STATEMENT OF OPERATIONS (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Income Statement [Abstract]
Capitalized interest	$ 43	$ 3	$ 72	$ 5

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CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL - 6 months ended Jun. 30, 2018 - USD ($) $ in Thousands	Total	Limited Partner [Member]	General Partner [Member]	Preferred Partner [Member]
Balance at Dec. 31, 2017	$ 4,684	$ 454,358	$ (703,597)	$ 253,923
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	6,227	(6,745)	415	12,557
Equity-based incentive compensation	687	669	18
Distributions	(25,238)	(11,958)	(723)	(12,557)
Capital contributions	183		183
Proceeds from sale of 21,246 common units pursuant to the Employee Unit Purchase Plan	92	92
Balance at Jun. 30, 2018	$ (13,365)	$ 436,416	$ (703,704)	$ 253,923

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CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL (Parenthetical)	6 Months Ended
	Jun. 30, 2018 shares
Changes in Partners Capital [Abstract]
Units Issued, Unit Based Compensation	21,246

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Cash flows from operating activities:
Net income	$ 6,227	$ 9,913
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for uncollectible receivables from third parties	1	(12)
Depreciation and amortization	14,779	15,905
Amortization and write-off of debt issuance costs	949	1,307
Unrealized gain related to interest rate swaps	(314)	(975)
Intangible asset impairment charge	189	0
Fixed asset impairment charge	427	45
Loss (gain) on sale of assets	(363)	879
Gain on sale of unconsolidated affiliate	(2,225)	(4,172)
Equity-based incentive compensation	687	524
Equity earnings in unconsolidated affiliate	0	(61)
Changes in assets and liabilities:
Increase in accounts receivable	(23,680)	(1,785)
Decrease in receivables from related parties	1,851	326
Decrease in prepaid insurance	1,494	1,194
Decrease (increase) in other current assets	(2,920)	148
Decrease in other non-current assets	90	111
Increase (decrease) in accounts payable	(502)	183
Increase in payables to related parties	10,504	156
Increase (decrease) in accrued interest payable	(50)	316
Increase in accrued property taxes	933	232
Increase (decrease) in unearned revenue	(346)	1,352
Increase in unearned revenue from related parties	3,679	3,953
Decrease in accrued payroll	(2,448)	(2,017)
Increase (decrease) in other accrued liabilities	12,113	(961)
Net cash provided by operating activities	21,075	26,561
Cash flows from investing activities:
Acquisitions	(21,959)	0
Capital expenditures	(22,125)	(10,331)
Proceeds from sale of assets	3,893	8,474
Proceeds from sale of unconsolidated affiliate	2,225	25,324
Net cash provided by (used in) investing activities	(37,966)	23,467
Cash flows from financing activities:
Payment on insurance premium financing agreement	(1,113)	(1,271)
Debt issuance costs	(309)	(4,017)
Borrowings under credit agreement	113,000	335,592
Payments under credit agreement	71,000	356,000
Proceeds from equity issuance	92	84
Capital contributions	183	104
Distributions	(25,238)	(24,550)
Net cash provided by (used in) financing activities	15,615	(50,058)
Net decrease in cash and cash equivalents	(1,276)	(30)
Cash and cash equivalents at beginning of period	2,469	3,304
Cash and cash equivalents at end of period	1,193	3,274
Supplemental disclosure of non-cash financing and investing cash flow information:
Non-cash changes in property, plant and equipment	294	1,545
Increase in accrued liabilities related to insurance premium financing agreement	$ 1,578	$ 2,281

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ORGANIZATION AND NATURE OF BUSINESS

6 Months Ended

Jun. 30, 2018

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 27 states. The Partnership provides integrated terminalling, gathering, transportation and marketing 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 services, (iii) crude oil pipeline services and (iv) crude oil trucking services. On April 24, 2018, the Partnership sold the producer field services business. As a result of the sale of the producer field services business, the Partnership changed the name of the crude oil trucking and producer field services operating segment to crude oil trucking services during the second quarter of 2018. See Note 6 for additional information. 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 February2007 as a Delaware master limited partnership initially to own, operate and develop a diversified portfolio of complementary midstream energy assets.

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BASIS OF CONSOLIDATION AND PRESENTATION

6 Months Ended

Jun. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

BASIS OF CONSOLIDATION AND PRESENTATION

BASIS OF CONSOLIDATION AND PRESENTATION

The financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).  The condensed consolidated balance sheet as of June 30, 2018, the condensed consolidated statements of operations for the three and six months ended June 30,2017 and 2018, the condensed consolidated statement of changes in partners’ capital (deficit) for the six months ended June 30,2018 and the condensed consolidated statements of cash flows for the six months ended June 30,2017 and 2018, are unaudited.  In the opinion of management, the unaudited condensed consolidated financial statements have been prepared on the same basis as the audited financial statements and include all adjustments necessary to state fairly the financial position and results of operations for the respective interim periods.  All adjustments are of a recurring nature unless otherwise disclosed herein.  The 2017 year-end condensed consolidated balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP.  These unaudited condensed consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes thereto included in the Partnership’s annual report on Form 10-K for the year ended December 31, 2017, filed with the Securities and Exchange Commission (the “SEC”) on March 8, 2018 (the “2017 Form 10-K”).  Interim financial results are not necessarily indicative of the results to be expected for an annual period.  The Partnership’s significant accounting policies are consistent with those disclosed in Note 3 of the Notes to Consolidated Financial Statements in its 2017 Form 10-K.

The Partnership’s investment in Advantage Pipeline, L.L.C. (“Advantage Pipeline”), over which the Partnership had significant influence but not control, was accounted for by the equity method. The Partnership did not consolidate any part of the assets or liabilities of its equity investee. The Partnership’s share of net income or loss is reflected as one line item on the Partnership’s unaudited condensed consolidated statements of operations entitled “Equity earnings in unconsolidated affiliate” and increased or decreased, as applicable, the carrying value of the Partnership’s “Investment in unconsolidated affiliate” on the unaudited condensed consolidated balance sheets. Distributions to the Partnership reduced the carrying value of its investment and, to the extent received, were reflected in the Partnership’s unaudited condensed consolidated statements of cash flows in the line item “Distributions from unconsolidated affiliate.” Contributions increased the carrying value of the Partnership’s investment and were reflected in the Partnership’s unaudited condensed consolidated statements of cash flows in investing activities. On April 3, 2017, the Partnership sold its investment in Advantage Pipeline. See Note 5 for additional information.

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REVENUE REVENUE

6 Months Ended

Jun. 30, 2018

Revenue from Contract with Customer [Abstract]

Revenue from Contracts with Customers [Text Block]

REVENUE

Revenue from Contracts with Customers

On January 1, 2018, the Partnership adopted the new accounting standard ASC 606 - Revenue from Contracts with Customers and all related amendments (“new revenue standard”) using the modified retrospective method, and as a result applied the new guidance only to contracts that are not completed at the adoption date. Results for reporting periods beginning on January 1, 2018, are presented under the new revenue standard, while prior period amounts are not adjusted and continue to be reported in accordance with the Partnership’s historic accounting under ASC 605 - Revenue Recognition.

The majority of the Partnership’s service revenue continues to be recognized as services are performed. Under the new revenue standard, the timing of revenue recognition on variable throughput fees will change, within a single reporting year, compared to the previous recognition.  The effect will be straight-line recognition of unconstrained estimated annual throughput volumes over each contract year.  See further discussion on variable throughput fees below. In addition, as a result of the adoption of the new revenue standard, revenue from leases is required to be presented separately from revenue from customers. As the Partnership applied the modified retrospective method, prior periods have not been reclassified.

Upon adoption of the new revenue standard, there was no cumulative adjustment to the balance sheet at January 1, 2018. Adoption of the new revenue standard resulted in recognition of an additional $0.2 million and $0.3 million of “Service revenue - Third-party revenue” in the unaudited condensed consolidated statements of operations for the three and six months ended June 30,2018, respectively, and additional “Accounts receivable” of $0.3 million on the unaudited condensed consolidated balance sheet as of June 30, 2018, over what would have been recorded under ASC 605. While some revenue under storage, throughput and handling contracts in the asphalt terminalling segment will shift between quarters within a fiscal year, the impact of adoption of the new revenue standard is not expected to be material to net income on an ongoing basis because the analysis of contracts under the new revenue standard supports the recognition of revenue as services are performed, which is consistent with the previous revenue recognition model.

There are two types of contracts in the asphalt terminalling segment: (i) operating lease contracts, under which customers operate the facilities, and (ii) storage, throughput and handling contracts, under which the Partnership operates the facilities. The operating lease contracts are accounted for in accordance with ASC 840 - Leases. The storage, throughput and handling contracts contain both lease revenue and non-lease service revenue. In accordance with ASC 840 and 606, fixed consideration is allocated to the lease and service components based on their relative stand-alone selling price. The stand-alone selling price of the lease component is calculated using the average internal rate of return under the operating lease agreements. The stand-alone selling price of the service component is calculated by applying an appropriate margin to the expected costs to operate the facility. The service component contains a single performance obligation that consists of a stand-ready obligation to perform activities as directed by the customer. Revenue is recognized on a straight-line basis over time as the customer receives and consumes benefits. Fixed consideration, consisting of the monthly storage and handling fees, is billed a month prior to the performance of services and is due by the first day of the month of service. Payments received in advance of the month of service are recorded as unearned revenue (contract liability) until the service is performed.

Asphalt storage, throughput and handling contracts also contain variable consideration in the form of reimbursements of utility, fuel and power expenses and throughput fees. Utility, fuel and power reimbursements are allocated entirely to the service component of the contracts. Utility, fuel and power reimbursements relate directly to the distinct monthly service that makes up the overall performance obligation and revenue is recognized in the period in which the service takes place. Variable consideration related to reimbursements of utility, fuel and power expenses is billed in the month subsequent to the period of service, and payment is due within 30 days of billing. Throughput fees are allocated to both the lease and service component of the contracts using the allocation percentages from contract inception. Total throughput fees are estimated at contract inception and updated at the beginning of each reporting period based on historical trends, current year throughput activities at the facilities, and analysis with customers regarding expectations for the current year. This consideration can be constrained when there is a lack of historical data or other uncertainties exist regarding expected throughput volumes. The service component of throughput fees is recognized on a straight-line basis over time as the customer receives and consumes benefits. In accordance with ASC 840, the lease component of variable throughput fees is recognized in the period when the changes in facts and circumstances on which the variable payment is based occur. Fees related to actual throughput are billed in the month subsequent to the period of movement, which can result in the recognition of un-billed accounts receivable (contract assets) when there is a variance in the straight-line revenue recognition and actual throughput fees billed. Payment on variable throughput consideration is due within 30 days of billing. Changes in estimated throughput fees affect the total transaction price and will be recorded as an adjustment to revenue in the period in which the change is identified. The Partnership recorded a $0.1 million adjustment related to changes in estimated throughput fees for both the three and six months ended June 30,2018.

Certain asphalt storage, throughput and handling contracts contain provisions for reimbursement of specified major maintenance costs above a specified threshold over the life of the contract. Reimbursements of specified major maintenance costs are allocated to both the lease and service component of the contracts using the allocation percentages from contract inception. Reimbursements of specified major maintenance costs are reviewed and paid quarterly, which may result in overpayments that must be paid back to the customer in future years. As such, the service component of this consideration is constrained and recorded in unearned revenue (contract liability) until facts and circumstances indicate it is probable that the minimum threshold will be met. In the event the minimum threshold is not met, the Partnership will return the reimbursement to the customer.

As of June 30, 2018, the Partnership has performance obligations satisfied over time under asphalt storage, throughput and handling contracts that are wholly or partially unsatisfied. The revenue related to these performance obligations will be recognized as follows (in thousands):

Revenue Related to Future Performance Obligations Due by Period(1)
Less than 1 year	$	35,257
1-3 years	64,767
4-5 years	46,024
More than 5 years	13,591
Total revenue related to future performance obligations	$	159,639

____________________

(1) Excluded from the table is revenue that is either constrained or related to performance obligations that are wholly unsatisfied as of June 30, 2018.

Crude oil terminalling services contracts can be either short- or long-term written contracts. The contracts contain a single performance obligation that consists of a series of distinct services provided over time. Customers are billed a month prior to the performance of terminalling services and payment is due by the first day of the month of service. Payments received in advance of the month of service are recorded as unearned revenue (contract liability) until the service is performed. These contracts also contain provisions under which customers are invoiced for product throughput in the month following the month in which the service is provided. Payment on product throughput is due within 30 days. The Partnership has elected to use the right-to-invoice expedient on crude oil terminalling services contracts as the right to consideration corresponds directly with the value to the customer of performance completed to date.

There are primarily two types of contracts in the crude oil pipeline segment: (i) monthly transportation contracts and (ii) product sales contracts.

Under crude oil pipeline services monthly transportation contracts, customers submit nominations for transportation monthly and a contract is created upon the Partnership’s acceptance of the nomination under its published tariffs. Crude oil pipeline services contracts have a single performance obligation to perform the transportation service. The transportation service is provided to the customer in the same month in which the customer makes the related nomination. Revenue is recorded in the month of service and invoiced in the following month. Payment is due within 30 days. The Partnership has elected to use the right-to-invoice expedient on crude oil pipeline services contracts as the right to consideration corresponds directly with the value to the customer of performance completed to date.

The Partnership also purchases crude oil and resells to third parties under written product sales contracts. Product sales contracts have a single performance obligation, and revenue is recognized at the point in time that control is transferred to the customer. Control is considered transferred to the customer on the day of the sale. Revenue is recorded in the month of service and invoiced in the following month. Payment is due within 30 days. The Partnership has elected to use the right-to-invoice expedient on product sales contracts as the right to consideration corresponds directly with the value to the customer of performance completed to date.

Services in the crude oil trucking segment are provided under master service agreements with customers that include rate sheets. Contracts are initiated when a customer requests service and both parties are committed upon the Partnership’s acceptance of the customer’s request. Crude oil trucking contracts have a single performance obligation to perform the service, which is completed in a day. Revenue is recorded in the month of service and invoiced in the following month. Payment is due within 30 days. The Partnership has elected to use the right-to-invoice expedient on crude oil trucking revenues as the right to consideration corresponds directly with the value to the customer of performance completed to date.

Disaggregation of Revenue

Disaggregation of revenue from contracts with customers for each operating segment by revenue type is presented as follows (in thousands):

	Three Months ended June 30, 2018
	Asphalt  Terminalling Services		Crude Oil Terminalling Services		Crude Oil Pipeline Services		Crude Oil Trucking Services		Total
Third-party revenue:
Fixed storage, throughput and other revenue	$	4,622	$	2,767	$	—	$	—	$	7,389
Variable throughput revenue	242		143		—		—		385
Variable reimbursement revenue	1,775		—		—		—		1,775
Crude oil transportation revenue	—		—		1,045		3,509		4,554
Crude oil product sales revenue	—		—		45,612		3		45,615
Related-party revenue:
Fixed storage, throughput and other revenue	4,632		—		48		—		4,680
Variable reimbursement revenue	1,349		—		34		—		1,383
Total revenue from contracts with customers	$	12,620	$	2,910	$	46,739	$	3,512	$	65,781

	Six Months ended June 30, 2018
	Asphalt  Terminalling Services		Crude Oil Terminalling Services		Crude Oil Pipeline Services		Crude Oil Trucking Services		Total
Third-party revenue:
Fixed storage, throughput and other revenue	$	8,171	$	6,849	$	—	$	—	$	15,020
Variable throughput revenue	359		647		—		—		1,006
Variable reimbursement revenue	3,241		—		—		—		3,241
Crude oil transportation revenue	—		—		3,105		9,049		12,154
Crude oil product sales revenue	—		—		49,120		9		49,129
Related-party revenue:
Fixed storage, throughput and other revenue	9,263		—		48		—		9,311
Variable reimbursement revenue	3,039		—		34		—		3,073
Total revenue from contracts with customers	$	24,073	$	7,496	$	52,307	$	9,058	$	92,934

Contract Balances

The timing of revenue recognition, billings and cash collections result in billed accounts receivable, un-billed accounts receivable (contract assets) and unearned revenue (contract liabilities) on the unaudited condensed consolidated balance sheet as noted in the contract discussions above. Accounts receivable and un-billed accounts receivable are both reflected in the line items “Accounts receivable” and “Receivables from related parties” on the unaudited condensed consolidated balance sheet. Unearned revenue is included in the line items “Unearned revenue,” “Unearned revenue with related parties,” “Long-term unearned revenue with related parties” and “Other long-term liabilities” on the unaudited condensed consolidated balance sheet.

Billed accounts receivable from contracts with customers were $8.5 million and $27.9 million at December 31, 2017, and June 30, 2018, respectively.

Un-billed accounts receivable from contracts with customers were $0.3 million at June 30, 2018. There were no un-billed accounts receivable at December 31, 2017.

The Partnership records unearned revenues when cash payments are received in advance of performance. Unearned revenue related to contracts with customers was $3.7 million and $4.6 million at December 31, 2017, and June 30, 2018, respectively. The change in the unearned revenue balance for the six months ended June 30,2018, is driven by $2.5 million in cash payments received in advance of satisfying performance obligations, partially offset by $1.6 million of revenues recognized that were included in the unearned revenue balance at the beginning of the period.

Practical Expedients and Exemptions

The Partnership does not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less and (ii) contracts for which revenue is recognized at the amount to which the Partnership has the right to invoice for services performed. The Partnership is using the right-to-invoice practical expedient on all contracts with customers in its crude oil terminalling services, crude oil pipeline services and crude oil trucking services segments.

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RESTRUCTURING CHARGES RESTRUCTURING CHARGES

6 Months Ended

Jun. 30, 2018

Restructuring and Related Activities [Abstract]

Restructuring and Related Activities Disclosure [Text Block]

RESTRUCTURING CHARGES

During the fourth quarter of 2015, the Partnership recognized certain restructuring charges in its crude oil trucking services segment pursuant to an approved plan to exit the trucking market in West Texas. The restructuring charges included an accrual related to leased vehicles that were idled as part of the restructuring plan. This accrual was being amortized over the remaining lease term of the vehicles. In June 2018, the Partnership purchased the vehicles off lease and resold them to a third party, paying off the remaining liability.

Changes in the accrued amounts pertaining to the restructuring charges are summarized as follows (in thousands):

	Three Months ended June 30,				Six Months ended June 30,
	2017		2018		2017		2018
Beginning balance	$	428	$	237	$	474	$	286
Cash payments	46		237		92		286
Ending balance	$	382	$	—	$	382	$	—

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EQUITY METHOD INVESTMENT EQUITY METHOD INVESTMENT

6 Months Ended

Jun. 30, 2018

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments and Joint Ventures Disclosure [Text Block]

EQUITY METHOD INVESTMENT

On April 3, 2017, Advantage Pipeline was acquired by a joint venture formed by affiliates of Plains All American Pipeline, L.P. and Noble Midstream Partners LP. The Partnership received cash proceeds at closing from the sale of its approximate 30% equity ownership interest in Advantage Pipeline of approximately $25.3 million and recorded a gain on the sale of the investment of $4.2 million. Approximately 10% of the gross sale proceeds were held in escrow, subject to certain post-closing settlement terms and conditions. The Partnership received approximately $1.1 million of the funds held in escrow in August 2017, and approximately $2.2 million for its pro rata portion of the remaining net escrow proceeds in January 2018. The Partnership’s proceeds were used to prepay revolving debt (without a commitment reduction). The operating and administrative services agreement to which the Partnership and Advantage Pipeline were parties and under which the Partnership operated the 70-mile, 16-inch Advantage crude oil pipeline, located in the southern Delaware Basin in Texas, was terminated at closing. The Partnership and the Plains/Noble joint venture entered into a short-term transition services agreement under which the Partnership provided certain services through August 1, 2017.

Summarized financial information for Advantage Pipeline is set forth in the tables below for the period indicated in which the Partnership held the investment in Advantage Pipeline (in thousands):

	Period ended April 3, 2017
Income Statement
Operating revenues	$	3,150
Operating expenses	$	465
Net income	$	187

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PROPERTY, PLANT AND EQUIPMENT

6 Months Ended

Jun. 30, 2018

Property, Plant and Equipment [Abstract]

PROPERTY, PLANT AND EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT

	Estimated Useful Lives (Years)	December 31, 2017			June 30, 2018
		(dollars in thousands)
Land	N/A	$	24,776		$	25,067
Land improvements	10-20	6,787			5,815
Pipelines and facilities	5-30	166,004			167,624
Storage and terminal facilities	10-35	370,056			319,344
Transportation equipment	3-10	3,293			1,056
Office property and equipment and other	3-20	32,011			26,958
Pipeline linefill and tank bottoms	N/A	3,233			11,694
Construction-in-progress	N/A	6,500			8,131
Property, plant and equipment, gross		612,660			565,689
Accumulated depreciation		(316,591		)	(269,978		)
Property, plant and equipment, net		$	296,069		$	295,711

Depreciation expense for the three months ended June 30,2017 and 2018, was $7.5 million and $6.7 million, respectively. Depreciation expense for the six months ended June 30,2017 and 2018, was $15.3 million and $13.7 million, respectively.

In April 2018, the Partnership sold its producer field services business. The Partnership received cash proceeds at closing of approximately $3.0 million and recorded a gain of $0.4 million. The sale of the producer field services business does not qualify as discontinued operations as it does not represent a strategic shift that will have a major effect on the Partnership’s operations or financial results.

In March 2018, the Partnership acquired an asphalt terminalling facility in Oklahoma from a third party for approximately $22.0 million, consisting of property, plant and equipment of $11.5 million, intangible assets of $7.6 million and goodwill of $2.9 million.

On December 1, 2017, the Partnership issued 1.9 million common units to Ergon in a private placement valued at $10.2 million in exchange for an asphalt terminalling facility in Bainbridge, Georgia.

In April 2017, the Partnership sold its East Texas pipeline system. The Partnership received cash proceeds at closing of approximately $4.8 million and recorded a gain of less than $0.1 million. The Partnership used the proceeds received at closing to prepay revolving debt (without a commitment reduction).

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DEBT

6 Months Ended

Jun. 30, 2018

Debt Disclosure [Abstract]

DEBT

DEBT

On May 11, 2017, the Partnership entered into an amended and restated credit agreement. On June 28, 2018, the credit agreement was amended to, among other things, reduce the revolving loan facility from $450.0 million to $400.0 million and amend the maximum permitted consolidated total leverage ratio as discussed below.

As of July 26, 2018, approximately $263.6 million of revolver borrowings and $3.4 million of letters of credit were outstanding under the credit agreement, leaving the Partnership with approximately $133.0 million available capacity for additional revolver borrowings and letters of credit under the credit agreement, although the Partnership’s ability to borrow such funds may be limited by the financial covenants in the credit agreement. The proceeds of loans made under the credit agreement may be used for working capital and other general corporate purposes of the Partnership.

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 $600.0 million for all revolving loan commitments under the credit agreement.

The credit agreement will mature on May 11, 2022, and all amounts outstanding under the credit agreement will become due and payable on such date. The credit agreement requires mandatory prepayments of amounts outstanding thereunder with the net proceeds of 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 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 5.50 to 1.00 for the fiscal quarters ending June 30, 2018, through December 31, 2018; 5.25 to 1.00 for the fiscal quarters ending March 31, 2019, and June 30, 2019; 5.00 to 1.00 for the fiscal quarters ending September 30, 2019, and December 31, 2019; and 4.75 to 1.00 for the fiscal quarter ending March 31, 2020, and each fiscal quarter thereafter; and

• based on the occurrence of a specified acquisition (as defined in the credit agreement, but generally being an acquisition for which the aggregate consideration is $15.0 million or more), the maximum permitted consolidated total leverage ratio may be increased to 5.25 to 1.00 for the fiscal quarter ending March 31, 2020, and for certain fiscal quarters thereafter.

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 will be 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.

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; and

• make certain amendments to the Partnership’s partnership agreement.

At June 30, 2018, the Partnership’s consolidated total leverage ratio was 4.65 to 1.00 and the consolidated interest coverage ratio was 3.78 to 1.00.  The Partnership was in compliance with all covenants of its credit agreement as of June 30, 2018.

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, provided, however, commencing with the fiscal quarter ending September 30, 2018, in no event shall aggregate quarterly distributions in any individual fiscal quarter exceed $10.7 million through, and including, the fiscal quarter ending December 31, 2019. 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 of Directors (the “Board”) of Blueknight Energy Partners G.P., L.L.C (the “general partner”) 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 9 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;

(ii) Ergon, Inc. (“Ergon”) ceases to own and control 50% or more of the membership interests of the general partner; or

(iii) during any period of 12 consecutive months, a majority of the members of the Board of the general partner ceases to be composed of individuals:

(A) who were members of the Board on the first day of such period;

(B) whose election or nomination to the Board was approved by individuals referred to in clause (A) above constituting at the time of such election or nomination at least a majority of the Board; or

(C) whose election or nomination to the Board was approved by individuals referred to in clauses (A) and (B) above constituting at the time of such election or nomination at least a majority of the Board, provided that any changes to the composition of individuals serving as members of the Board approved by Ergon will not cause an event of default.

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 to have letters of credit issued under the credit agreement. 

Upon the execution of the amended and restated credit agreement in May 2017, the Partnership expensed $0.7 million of debt issuance costs related to the prior revolving loan facility, leaving a remaining balance of $0.9 million ascribed to those lenders with commitments under both the prior and the amended and restated credit agreement. Additionally, due to the reduction in available borrowing capacity, the Partnership expensed $0.4 million of debt issuance costs upon the execution of the first amendment to its credit agreement in June 2018. The Partnership capitalized $4.0 million of debt issuance costs during each of the three and six months ended June 30,2017, and capitalized $0.3 million of debt issuance costs during each of the three and six months ended June 30,2018. Debt issuance costs are being amortized over the term of the credit agreement. Interest expense related to debt issuance cost amortization for each of the three months ended June 30,2017 and 2018, was $0.3 million. Interest expense related to debt issuance cost amortization for the six months ended June 30,2017 and 2018, was $0.6 million and $0.5 million, respectively.

During the three months ended June 30,2017 and 2018, the weighted average interest rate under the Partnership’s credit agreement, excluding the $0.7 million and $0.4 million, respectively, of debt issuance costs that were expensed as described above, was 4.44% and 5.39%, respectively, resulting in interest expense of approximately $3.4 million and $4.7 million, respectively. During the six months ended June 30,2017 and 2018, the weighted average interest rate under the Partnership’s credit agreement, excluding the $0.7 million and $0.4 million, respectively, of debt issuance costs that were expensed as described above, was 4.27% and 5.18%, respectively, resulting in interest expense of approximately $6.7 million and $8.6 million, respectively.

During each of the three months ended June 30,2017 and 2018, the Partnership capitalized interest of less than $0.1 million. During the six months ended June 30,2017 and 2018, the Partnership capitalized interest of less than $0.1 million and $0.1 million, respectively.

The Partnership is exposed to market risk for changes in interest rates related to its credit agreement. 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. As of December 31, 2017, and June 30, 2018, the Partnership had interest rate swap agreements with notional amounts totaling $200.0 million and $100.0 million, respectively, to hedge the variability of its LIBOR-based interest payments. An interest rate swap agreement with a notional amount of $100.0 million expired on June 28, 2018. Interest rate swap agreements with notional amounts totaling $100.0 million will mature on January 28, 2019. During the three months ended June 30,2017 and 2018, the Partnership recorded swap interest expense of $0.4 million and $0.1 million, respectively. During the six months ended June 30,2017 and 2018, the Partnership recorded swap interest expense of $0.8 million and less than $0.1 million, respectively. The interest rate swaps do not receive hedge accounting treatment under ASC 815 - Derivatives and Hedging.

The following provides information regarding the Partnership’s assets and liabilities related to its interest rate swap agreements as of the periods indicated (in thousands):

Derivatives Not Designated as Hedging Instruments	Balance Sheet Location	Fair Value of Derivatives
		December 31, 2017		June 30, 2018
Interest rate swap assets - current	Other current assets	$	68	$	157
Interest rate swap liabilities - noncurrent	Long-term interest rate swap liabilities	$	225	$	—

Changes in the fair value of the interest rate swaps are reflected in the unaudited condensed consolidated statements of operations as follows (in thousands):

Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss) Recognized in Net Income on Derivatives	Amount of Gain (Loss) Recognized in Net Income on Derivatives
		Three Months ended June 30,					Six Months ended June 30,
		2017		2018			2017		2018
Interest rate swaps	Interest expense, net of capitalized interest	$	223	$	(40	)	$	975	$	314

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NET INCOME PER LIMITED PARTNER UNIT

6 Months Ended

Jun. 30, 2018

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): 

	Three Months ended June 30,						Six Months ended June 30,
	2017			2018			2017			2018
Net income	$	6,371		$	1,785		$	9,913		$	6,227
General partner interest in net income	256			28			465			259
Preferred interest in net income	6,279			6,279			12,558			12,557
Net loss available to limited partners	$	(164	)	$	(4,522	)	$	(3,110	)	$	(6,589	)
Basic and diluted weighted average number of units:
Common units	38,155			40,324			38,151			40,306
Restricted and phantom units	923			1,133			806			983
Total units	39,078			41,457			38,957			41,289
Basic and diluted net loss per common unit	$	—		$	(0.11	)	$	(0.08	)	$	(0.16	)

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PARTNERS' CAPITAL AND DISTRIBUTIONS

6 Months Ended

Jun. 30, 2018

Partners' Capital Account, Distributions [Abstract]

PARTNERS' CAPITAL AND DISTRIBUTIONS

PARTNERS’ CAPITAL AND DISTRIBUTIONS

On December 1, 2017, the Partnership issued 1.9 million common units to Ergon in a private placement valued at $10.2 million in exchange for an asphalt terminalling facility in Bainbridge, Georgia.

On July 19, 2018, the Board approved a distribution of $0.17875 per outstanding Preferred Unit for the three months ended June 30,2018. The Partnership will pay this distribution on August 14, 2018, to unitholders of record as of August 3, 2018. The total distribution will be approximately $6.4 million, with approximately $6.3 million and $0.1 million paid to the Partnership’s preferred unitholders and general partner, respectively.

In addition, on July 19, 2018, the Board approved a cash distribution of $0.08 per outstanding common unit for the three months ended June 30,2018. The Partnership will pay this distribution on August 14, 2018, to unitholders of record on August 3, 2018. The total distribution will be approximately $3.4 million, with approximately $3.2 million and $0.1 million to be paid to the Partnership’s common unitholders and general partner, respectively, and $0.1 million to be paid to holders of phantom and restricted units pursuant to awards granted under the Partnership’s Long-Term Incentive Plan.

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RELATED PARTY TRANSACTIONS

6 Months Ended

Jun. 30, 2018

Related Party Transactions [Abstract]

RELATED PARTY TRANSACTIONS

RELATED-PARTY TRANSACTIONS

Transactions with Ergon

The Partnership leases asphalt facilities and provides asphalt terminalling services to Ergon. For both the three months ended June 30,2017 and 2018, the Partnership recognized related-party revenues of $13.5 million for services provided to Ergon. For the six months ended June 30,2017 and 2018, the Partnership recognized related-party revenues of $26.8 million and $27.5 million, respectively, for services provided to Ergon. As of December 31, 2017, and June 30, 2018, the Partnership had receivables from Ergon of $3.1 million and $1.2 million, respectively, net of allowance for doubtful accounts. As of December 31, 2017, and June 30, 2018, the Partnership had unearned revenues from Ergon of $1.6 million and $5.3 million, respectively.

Effective April 1, 2018, the Partnership entered into an agreement with Ergon under which the Partnership purchases crude oil in connection with its crude oil marketing operations. For the three and six months ended June 30,2018, the Partnership made purchases of crude oil under this agreement totaling $30.5 million. As of June 30, 2018, the Partnership has payables to Ergon related to this agreement of $9.8 million.

The Partnership and Ergon have an agreement (the “Agreement”) that gives each party rights concerning the purchase or sale of Ergon’s interest in Cimarron Express Pipeline, LLC (“Cimarron Express”), subject to certain terms and conditions. The Agreement was filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed May 14, 2018. The Cimarron Express will be a new 16-inch diameter, 65-mile crude oil pipeline running from northeastern Kingfisher County, Oklahoma to the Partnership’s Cushing, Oklahoma crude oil terminal. Ergon has formed a Delaware limited liability company, Ergon - Oklahoma Pipeline, LLC (“DEVCO”), which will hold Ergon’s 50% membership interest in Cimarron Express. Under the Agreement, the Partnership has the right, at any time, to purchase 100% of the authorized and outstanding member interests in DEVCO from Ergon for the Purchase Price, which shall be computed by taking Ergon’s total investment in the Cimarron Express plus interest, by giving written notice to Ergon (the “Call”). Ergon has the right to require BKEP to purchase 100% of the authorized and outstanding member interests of DEVCO for the Purchase Price (the “Put”) at any time beginning the earlier of (i) 18 months from the formation of the joint venture company to build the pipeline or (ii) six months after completion of the pipeline. Upon exercise of the Call or the Put, Ergon and the Partnership will execute the Member Interest Purchase Agreement which is attached to the Agreement as Exhibit B. Upon receipt of the Purchase Price, Ergon shall be obligated to convey 100% of the authorized and outstanding member interests in DEVCO to BKEP or its designee. There is not a separate amount of consideration for the put or the call exchanged between the parties. Therefore, based on applicable GAAP, no value was assigned to the combined instrument on the Partnership's balance sheet upon the execution of the put/call instrument. Construction of the Cimarron Express pipeline is anticipated to be complete and the pipeline placed in-service during the third quarter of 2019. As of June 30, 2018, neither Ergon nor the Partnership has exercised their options under the Agreement.

Transactions with Advantage Pipeline

The Partnership provided operating and administrative services to Advantage Pipeline. On April 3, 2017, the Partnership sold its investment in Advantage Pipeline. See Note 5 for additional information. For the six months ended June 30,2017, the Partnership earned revenues of $0.3 million for services provided to Advantage Pipeline.

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LONG-TERM INCENTIVE PLAN

6 Months Ended

Jun. 30, 2018

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 Long-Term Incentive Plan (the “LTIP”), which is administered by the compensation committee of the Board. 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 4,100,000 common units, subject to adjustments 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. The phantom unit awards also include distribution equivalent rights (“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 and phantom units are entitled to receive cash distributions paid on common units during the vesting period which 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 outstanding grants made to the directors under the LTIP:

Grant Date	Number of Units	Weighted Average Grant Date Fair Value(1)		Grant Date Total Fair Value
				(in thousands)
December 2016	10,950	$	6.85	$	75
December 2017	15,306	$	4.85	$	74

_________________

(1)    Fair value is the closing market price on the grant date of the awards.

In addition, the independent directors received common unit grants that have no vesting requirement as part of their compensation. The following table includes information on grants made to the directors under the LTIP that have no vesting requirement:

Grant Date	Number of Units	Weighted Average Grant Date Fair Value(1)		Grant Date Total Fair Value
				(in thousands)
December 2016	10,220	$	6.85	$	70
December 2017	14,286	$	4.85	$	69

_________________

(1)    Fair value is the closing market price on the grant date of the awards.

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(1)		Grant Date Total Fair Value
				(in thousands)
March 2016	416,131	$	4.77	$	1,985
October 2016	9,960	$	5.85	$	58
March 2017	323,339	$	7.15	$	2,312
March 2018	457,984	$	4.77	$	2,185

_________________

(1)    Fair value is the closing market price on the grant date of the awards.

The unrecognized estimated compensation cost of outstanding phantom and restricted units at June 30, 2018, was $3.1 million, which will be expensed over the remaining vesting period.

The Partnership’s equity-based incentive compensation expense for each of the three months ended June 30,2017 and 2018, was $0.6 million. The Partnership’s equity-based incentive compensation expense for each of the six months ended June 30,2017 and 2018 was $1.1 million.

Activity pertaining to phantom 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, 2017	923,551	$	6.29
Granted	457,984	4.77
Vested	241,629	7.46
Forfeited	10,865	5.39
Nonvested at June 30, 2018	1,129,041	$	5.88

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EMPLOYEE BENEFIT PLAN

6 Months Ended

Jun. 30, 2018

Retirement Benefits [Abstract]

EMPLOYEE BENEFIT PLAN

EMPLOYEE BENEFIT PLANS

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 $0.3 million for each of the three months ended June 30,2017 and 2018, for discretionary contributions under the 401(k) Plan. The Partnership recognized expense of $0.6 million for each of the six months ended June 30,2017 and 2018, 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 $0.2 million and less than $0.1 million for the three months ended June 30,2017 and 2018, respectively, for discretionary profit sharing contributions under the 401(k) Plan. The Partnership recognized expense of $0.4 million and $0.1 million for the six months ended June 30,2017 and 2018, respectively, for discretionary profit sharing contributions under the 401(k) Plan.

Under the Partnership’s Employee Unit Purchase Plan (the “Unit Purchase Plan”), which was instituted in January 2015, employees have the opportunity to acquire or increase their ownership of common units representing limited partner interests in the Partnership. Eligible employees who enroll in the Unit Purchase Plan may elect to have a designated whole percentage, up to a specified maximum, of their eligible compensation for each pay period withheld for the purchase of common units at a discount to the then current market value. A maximum of 1,000,000 common units may be delivered under the Unit Purchase Plan, subject to adjustment for a recapitalization, split, reorganization, or similar event pursuant to the terms of the Unit Purchase Plan. The Partnership recognized compensation expense of less than $0.1 million during each of the three and six months ended June 30,2017 and 2018, in connection with the Unit Purchase Plan.

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FAIR VALUE MEASUREMENTS

6 Months Ended

Jun. 30, 2018

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

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 assets and liabilities required to be measured at fair value, 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. There were no transfers during the six months ended June 30,2018. 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, 2017
Description	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs   (Level 3)
Assets:
Interest rate swap assets	$	68	$	—	$	68	$	—
Total swap assets	$	68	$	—	$	68	$	—
Liabilities:
Interest rate swap liabilities	$	225	$	—	$	225	$	—
Total swap liabilities	$	225	$	—	$	225	$	—

	Fair Value Measurements as of June 30, 2018
Description	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs   (Level 3)
Assets:
Interest rate swap assets	$	157	$	—	$	157	$	—
Total swap assets	$	157	$	—	$	157	$	—

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 June 30, 2018, the carrying values on the unaudited condensed 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 June 30, 2018, 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.

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OPERATING SEGMENTS

6 Months Ended

Jun. 30, 2018

Segment Reporting [Abstract]

OPERATING SEGMENTS

OPERATING SEGMENTS

The Partnership’s operations consist of four operating segments: (i) asphalt terminalling services, (ii) crude oil terminalling services, (iii) crude oil pipeline services and (iv) crude oil trucking services.  

ASPHALT TERMINALLING SERVICES —The Partnership provides asphalt product and residual fuel terminalling, storage and blending services. As of July 26, 2018, the Partnership has 53 terminalling and storage facilities located in 26 states.

CRUDE OIL TERMINALLING SERVICES —The Partnership provides crude oil terminalling services at its terminalling facility located in Oklahoma.

CRUDE OIL PIPELINE SERVICES —The Partnership owns and operates pipeline systems 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 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 pipeline system. The Partnership previously owned and operated the East Texas pipeline system, which was located in Texas. On April 17, 2017, the Partnership sold the East Texas pipeline system. See Note 6 for additional information. Crude oil product sales revenues consist of sales proceeds recognized for the sale of crude oil to third-party customers.

CRUDE OIL TRUCKING 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.  On April 24, 2018, the Partnership sold the producer field services business. As a result of the sale of the producer field services business, the Partnership changed the name of this operating segment to crude oil trucking services during the second quarter of 2018. See Note 6 for additional information.

The Partnership’s management evaluates performance based upon operating margin, excluding amortization and depreciation, which includes revenues from related parties and external customers and operating expense, excluding depreciation and amortization. The non-GAAP measure of operating margin, excluding depreciation and amortization (in the aggregate and by segment) is presented in the following table. The Partnership computes the components of operating margin, excluding depreciation and amortization by using amounts that are determined in accordance with GAAP. The Partnership accounts for intersegment product sales as if the sales were to third parties, that is, at current market prices. A reconciliation of operating margin, excluding depreciation and amortization 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, excluding depreciation and amortization 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): 

	Three Months ended June 30,					Six Months ended June 30,
	2017		2018			2017		2018
Asphalt Terminalling Services
Service revenue:
Third-party revenue	$	13,259	$	6,639		$	26,482	$	11,771
Related-party revenue	13,505		5,981			26,837		12,302
Lease revenue:
Third-party revenue	—		10,016			—		19,473
Related-party revenue	—		7,475			—		15,178
Total revenue for reportable segment	26,764		30,111			53,319		58,724
Operating expense, excluding depreciation and amortization	11,935		13,393			24,255		26,728
Operating margin, excluding depreciation and amortization	$	14,829	$	16,718		$	29,064	$	31,996
Total assets (end of period)	$	147,832	$	167,849		$	147,832	$	167,849
Crude Oil Terminalling Services
Service revenue:
Third-party revenue	$	5,726	$	2,910		$	11,851	$	7,496
Intersegment revenue	—		170			—		170
Lease revenue:
Third-party revenue	—		12			—		27
Total revenue for reportable segment	5,726		3,092			11,851		7,693
Operating expense, excluding depreciation and amortization	992		913			2,003		2,188
Operating margin, excluding depreciation and amortization	$	4,734	$	2,179		$	9,848	$	5,505
Total assets (end of period)	$	69,834	$	67,150		$	69,834	$	67,150
Crude Oil Pipeline Services
Service revenue:
Third-party revenue	$	2,720	$	1,045		$	5,324	$	3,105
Related-party revenue	—		82			310		82
Lease revenue:
Third-party revenue	—		177			—		412
Product sales revenue:
Third-party revenue	2,227		45,612			5,877		49,120
Total revenue for reportable segment	4,947		46,916			11,511		52,719
Operating expense, excluding depreciation and amortization	3,142		2,542			6,383		5,327
Operating expense (intersegment)	74		1,156			244		1,599
Third-party cost of product sales	1,669		20,041			4,808		22,678
Related-party cost of product sales	—		23,747			—		23,747
Operating margin, excluding depreciation and amortization	$	62	$	(570	)	$	76	$	(632	)
Total assets (end of period)	$	117,222	$	152,105		$	117,222	$	152,105

	Three Months ended June 30,						Six Months ended June 30,
	2017			2018			2017			2018
Crude Oil Trucking Services
Service revenue:
Third-party revenue	$	6,440		$	3,509		$	13,151		$	9,049
Intersegment revenue	74			986			244			1,429
Lease revenue:
Third-party revenue	—			32			—			129
Product sales revenue:
Third-party revenue	—			3			385			9
Total revenue for reportable segment	6,514			4,530			13,780			10,616
Operating expense, excluding depreciation and amortization	6,702			4,727			13,970			11,101
Operating margin, excluding depreciation and amortization	$	(188	)	$	(197	)	$	(190	)	$	(485	)
Total assets (end of period)	$	11,208		$	3,402		$	11,208		$	3,402
Total operating margin, excluding depreciation and amortization(1)	$	19,437		$	18,130		$	38,798		$	36,384
Total segment revenues	$	43,951		$	84,649		$	90,461		$	129,752
Elimination of intersegment revenues	(74		)	(1,156		)	(244		)	(1,599		)
Consolidated revenues	$	43,877		$	83,493		$	90,217		$	128,153

____________________

(1)The following table reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes (in thousands):

	Three Months ended June 30,						Six Months ended June 30,
	2017			2018			2017			2018
Operating margin, excluding depreciation and amortization	$	19,437		$	18,130		$	38,798		$	36,384
Depreciation and amortization	(7,839		)	(7,413		)	(15,905		)	(14,779		)
General and administrative expense	(4,322		)	(4,486		)	(8,907		)	(8,707		)
Asset impairment expense	(17		)	—			(45		)	(616		)
Gain (loss) on sale of assets	(754		)	599			(879		)	363
Interest expense	(4,265		)	(5,024		)	(7,295		)	(8,593		)
Gain on sale of unconsolidated affiliate	4,172			—			4,172			2,225
Equity earnings in unconsolidated affiliate	—			—			61			—
Income before income taxes	$	6,412		$	1,806		$	10,000		$	6,277

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COMMITMENTS AND CONTINGENCIES

6 Months Ended

Jun. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

COMMITMENT AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

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 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 present value of 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.

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INCOME TAXES

6 Months Ended

Jun. 30, 2018

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

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 June 30, 2018, are presented below (dollars in thousands):

Deferred Tax Asset
Difference in bases of property, plant and equipment	$	444
Net operating loss carryforwards	11
Deferred tax asset	455
Less: valuation allowance	444
Net deferred tax asset	$	11

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 valuation allowance against its deferred tax asset related to the difference in bases of property, plant and equipment as of June 30, 2018.

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RECENTLY ISSUED ACCOUNTING STANDARDS

6 Months Ended

Jun. 30, 2018

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

RECENTLY ISSUED ACCOUNTING STANDARDS

RECENTLY ISSUED ACCOUNTING STANDARDS

Except as discussed below and in the 2017 Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the six months ended June 30,2018, that are of significance or potential significance to the Partnership.

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. The Partnership adopted these updates in the three-month period ending March 31, 2018. See Note 3 for disclosures related to the adoption of this standard and the impact on the Partnership’s financial position, results of operations and 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 in order 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 adopted this update in the three-month period ending March 31, 2018, and there was no impact on the Partnership’s financial position, results of operations or cash flows.

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. Throughout 2017 and 2018, the FASB issued a series of subsequent updates to the guidance in Topic 842. This update, as well as related updates, 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 three-month period ending March 31, 2019.

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 (including bank-owned life insurance policies); 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 adopted this update in the three-month period ending March 31, 2018, and there was no impact on the Partnership’s financial position, results of operations or cash flows.

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 eliminate 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 adopted this update in the three-month period ending March 31, 2018, and there was no impact on the Partnership’s financial position, results of operations or cash flows.

In November 2016, the FASB issued ASU 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash (a Consensus 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 adopted this update in the three-month period ending March 31, 2018, and there was no impact on the Partnership’s financial position, results of operations or cash flows.

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 adopted this update in the three-month period ending March 31, 2018, and there was no impact on the Partnership’s financial position, results of operations or cash flows.

In February 2017, the FASB issued ASU 2017-05, “Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20).” This update clarifies the scope of Subtopic 610-20 and adds guidance for partial sales of nonfinancial assets. Subtopic 610-20, which was issued in May 2014 as a part of ASU 2014-09, “Revenue from Contracts with Customers (Topic 606),” provides guidance for recognizing gains and losses from the transfer of nonfinancial assets in contracts with noncustomers. The amendments in ASU 2017-05 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. The Partnership adopted this update in the three-month period ending March 31, 2018, and there was no impact on the Partnership’s financial position, results of operations or cash flows.

In May 2017, the FASB issued ASU 2017-09, “Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting.” This update provides clarity and reduces both diversity in practice and cost and complexity when applying the guidance of Topic 718, Compensation - Stock Compensation, to a change in the terms or conditions of a share-based payment award. 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 adopted this update in the three-month period ending March 31, 2018, and there was no impact on the Partnership’s financial position, results of operations or cash flows.

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SUBSEQUENT EVENTS SUBSEQUENT EVENTS

6 Months Ended

Jun. 30, 2018

Subsequent Events [Abstract]

Subsequent Events

SUBSEQUENT EVENTS

Sale of Asphalt Facilities

On June 29, 2018, the Partnership entered into a definitive agreement to sell certain asphalt terminals, storage tanks and related real property, contracts, permits, assets and other interests located in Lubbock and Saginaw, Texas and Memphis, Tennessee properties (the “Divestiture”) to Ergon Asphalt & Emulsion, Inc. (“Ergon A&E”) for a purchase price of $90.0 million, subject to customary adjustments. The Partnership closed the Divestiture on July 12, 2018, and filed a Current Report on Form 8-K on July 13, 2018. The Divestiture does not qualify as discontinued operations as it does not represent a strategic shift that will have a major effect on the Partnership’s operations or financial results. The Partnership used the proceeds received at closing to prepay revolving debt under its credit agreement.

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REVENUE Revenue from Contracts with Customers (Tables)

6 Months Ended

Jun. 30, 2018

Revenue from Contract with Customer [Abstract]

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block]

As of June 30, 2018, the Partnership has performance obligations satisfied over time under asphalt storage, throughput and handling contracts that are wholly or partially unsatisfied. The revenue related to these performance obligations will be recognized as follows (in thousands):

Revenue Related to Future Performance Obligations Due by Period(1)
Less than 1 year	$	35,257
1-3 years	64,767
4-5 years	46,024
More than 5 years	13,591
Total revenue related to future performance obligations	$	159,639

____________________

(1) Excluded from the table is revenue that is either constrained or related to performance obligations that are wholly unsatisfied as of June 30, 2018.

Disaggregation of Revenue [Table Text Block]

Disaggregation of revenue from contracts with customers for each operating segment by revenue type is presented as follows (in thousands):

	Three Months ended June 30, 2018
	Asphalt  Terminalling Services		Crude Oil Terminalling Services		Crude Oil Pipeline Services		Crude Oil Trucking Services		Total
Third-party revenue:
Fixed storage, throughput and other revenue	$	4,622	$	2,767	$	—	$	—	$	7,389
Variable throughput revenue	242		143		—		—		385
Variable reimbursement revenue	1,775		—		—		—		1,775
Crude oil transportation revenue	—		—		1,045		3,509		4,554
Crude oil product sales revenue	—		—		45,612		3		45,615
Related-party revenue:
Fixed storage, throughput and other revenue	4,632		—		48		—		4,680
Variable reimbursement revenue	1,349		—		34		—		1,383
Total revenue from contracts with customers	$	12,620	$	2,910	$	46,739	$	3,512	$	65,781

	Six Months ended June 30, 2018
	Asphalt  Terminalling Services		Crude Oil Terminalling Services		Crude Oil Pipeline Services		Crude Oil Trucking Services		Total
Third-party revenue:
Fixed storage, throughput and other revenue	$	8,171	$	6,849	$	—	$	—	$	15,020
Variable throughput revenue	359		647		—		—		1,006
Variable reimbursement revenue	3,241		—		—		—		3,241
Crude oil transportation revenue	—		—		3,105		9,049		12,154
Crude oil product sales revenue	—		—		49,120		9		49,129
Related-party revenue:
Fixed storage, throughput and other revenue	9,263		—		48		—		9,311
Variable reimbursement revenue	3,039		—		34		—		3,073
Total revenue from contracts with customers	$	24,073	$	7,496	$	52,307	$	9,058	$	92,934

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RESTRUCTURING CHARGES (Tables)

6 Months Ended

Jun. 30, 2018

Crude Oil Trucking Services [Member] | West Texas Trucking Market Exit Plan [Member]

Restructuring Cost and Reserve [Line Items]

Restructuring and Related Costs [Table Text Block]

Changes in the accrued amounts pertaining to the restructuring charges are summarized as follows (in thousands):

	Three Months ended June 30,				Six Months ended June 30,
	2017		2018		2017		2018
Beginning balance	$	428	$	237	$	474	$	286
Cash payments	46		237		92		286
Ending balance	$	382	$	—	$	382	$	—

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EQUITY METHOD INVESTMENT (Tables)

6 Months Ended

Jun. 30, 2018

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments [Table Text Block]

Summarized financial information for Advantage Pipeline is set forth in the tables below for the period indicated in which the Partnership held the investment in Advantage Pipeline (in thousands):

	Period ended April 3, 2017
Income Statement
Operating revenues	$	3,150
Operating expenses	$	465
Net income	$	187

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PROPERTY, PLANT AND EQUIPMENT (Tables)

6 Months Ended

Jun. 30, 2018

Property, Plant and Equipment [Abstract]

Schedule of Property, Plant and Equipment

	Estimated Useful Lives (Years)	December 31, 2017			June 30, 2018
		(dollars in thousands)
Land	N/A	$	24,776		$	25,067
Land improvements	10-20	6,787			5,815
Pipelines and facilities	5-30	166,004			167,624
Storage and terminal facilities	10-35	370,056			319,344
Transportation equipment	3-10	3,293			1,056
Office property and equipment and other	3-20	32,011			26,958
Pipeline linefill and tank bottoms	N/A	3,233			11,694
Construction-in-progress	N/A	6,500			8,131
Property, plant and equipment, gross		612,660			565,689
Accumulated depreciation		(316,591		)	(269,978		)
Property, plant and equipment, net		$	296,069		$	295,711

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DEBT Fair Values of Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

The following provides information regarding the Partnership’s assets and liabilities related to its interest rate swap agreements as of the periods indicated (in thousands):

Derivatives Not Designated as Hedging Instruments	Balance Sheet Location	Fair Value of Derivatives
		December 31, 2017		June 30, 2018
Interest rate swap assets - current	Other current assets	$	68	$	157
Interest rate swap liabilities - noncurrent	Long-term interest rate swap liabilities	$	225	$	—

Changes in the fair value of the interest rate swaps are reflected in the unaudited condensed consolidated statements of operations as follows (in thousands):

Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss) Recognized in Net Income on Derivatives	Amount of Gain (Loss) Recognized in Net Income on Derivatives
		Three Months ended June 30,					Six Months ended June 30,
		2017		2018			2017		2018
Interest rate swaps	Interest expense, net of capitalized interest	$	223	$	(40	)	$	975	$	314

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NET INCOME PER LIMITED PARTNER UNIT (Tables)

6 Months Ended

Jun. 30, 2018

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): 

	Three Months ended June 30,						Six Months ended June 30,
	2017			2018			2017			2018
Net income	$	6,371		$	1,785		$	9,913		$	6,227
General partner interest in net income	256			28			465			259
Preferred interest in net income	6,279			6,279			12,558			12,557
Net loss available to limited partners	$	(164	)	$	(4,522	)	$	(3,110	)	$	(6,589	)
Basic and diluted weighted average number of units:
Common units	38,155			40,324			38,151			40,306
Restricted and phantom units	923			1,133			806			983
Total units	39,078			41,457			38,957			41,289
Basic and diluted net loss per common unit	$	—		$	(0.11	)	$	(0.08	)	$	(0.16	)

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LONG-TERM INCENTIVE PLAN (Tables)

6 Months Ended

Jun. 30, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Share-based Compensation Arrangements 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 outstanding grants made to the directors under the LTIP:

Grant Date	Number of Units	Weighted Average Grant Date Fair Value(1)		Grant Date Total Fair Value
				(in thousands)
December 2016	10,950	$	6.85	$	75
December 2017	15,306	$	4.85	$	74

_________________

(1)    Fair value is the closing market price on the grant date of the awards.

In addition, the independent directors received common unit grants that have no vesting requirement as part of their compensation. The following table includes information on grants made to the directors under the LTIP that have no vesting requirement:

Grant Date	Number of Units	Weighted Average Grant Date Fair Value(1)		Grant Date Total Fair Value
				(in thousands)
December 2016	10,220	$	6.85	$	70
December 2017	14,286	$	4.85	$	69

_________________

(1)    Fair value is the closing market price on the grant date of the awards.

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(1)		Grant Date Total Fair Value
				(in thousands)
March 2016	416,131	$	4.77	$	1,985
October 2016	9,960	$	5.85	$	58
March 2017	323,339	$	7.15	$	2,312
March 2018	457,984	$	4.77	$	2,185

_________________

(1)    Fair value is the closing market price on the grant date of the awards.

Schedule Of Phantom Common Units And Restricted Common Units Activity

Activity pertaining to phantom 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, 2017	923,551	$	6.29
Granted	457,984	4.77
Vested	241,629	7.46
Forfeited	10,865	5.39
Nonvested at June 30, 2018	1,129,041	$	5.88

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FAIR VALUE MEASUREMENTS Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2018

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, 2017
Description	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs   (Level 3)
Assets:
Interest rate swap assets	$	68	$	—	$	68	$	—
Total swap assets	$	68	$	—	$	68	$	—
Liabilities:
Interest rate swap liabilities	$	225	$	—	$	225	$	—
Total swap liabilities	$	225	$	—	$	225	$	—

	Fair Value Measurements as of June 30, 2018
Description	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs   (Level 3)
Assets:
Interest rate swap assets	$	157	$	—	$	157	$	—
Total swap assets	$	157	$	—	$	157	$	—

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OPERATING SEGMENTS (Tables)

6 Months Ended

Jun. 30, 2018

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): 

	Three Months ended June 30,					Six Months ended June 30,
	2017		2018			2017		2018
Asphalt Terminalling Services
Service revenue:
Third-party revenue	$	13,259	$	6,639		$	26,482	$	11,771
Related-party revenue	13,505		5,981			26,837		12,302
Lease revenue:
Third-party revenue	—		10,016			—		19,473
Related-party revenue	—		7,475			—		15,178
Total revenue for reportable segment	26,764		30,111			53,319		58,724
Operating expense, excluding depreciation and amortization	11,935		13,393			24,255		26,728
Operating margin, excluding depreciation and amortization	$	14,829	$	16,718		$	29,064	$	31,996
Total assets (end of period)	$	147,832	$	167,849		$	147,832	$	167,849
Crude Oil Terminalling Services
Service revenue:
Third-party revenue	$	5,726	$	2,910		$	11,851	$	7,496
Intersegment revenue	—		170			—		170
Lease revenue:
Third-party revenue	—		12			—		27
Total revenue for reportable segment	5,726		3,092			11,851		7,693
Operating expense, excluding depreciation and amortization	992		913			2,003		2,188
Operating margin, excluding depreciation and amortization	$	4,734	$	2,179		$	9,848	$	5,505
Total assets (end of period)	$	69,834	$	67,150		$	69,834	$	67,150
Crude Oil Pipeline Services
Service revenue:
Third-party revenue	$	2,720	$	1,045		$	5,324	$	3,105
Related-party revenue	—		82			310		82
Lease revenue:
Third-party revenue	—		177			—		412
Product sales revenue:
Third-party revenue	2,227		45,612			5,877		49,120
Total revenue for reportable segment	4,947		46,916			11,511		52,719
Operating expense, excluding depreciation and amortization	3,142		2,542			6,383		5,327
Operating expense (intersegment)	74		1,156			244		1,599
Third-party cost of product sales	1,669		20,041			4,808		22,678
Related-party cost of product sales	—		23,747			—		23,747
Operating margin, excluding depreciation and amortization	$	62	$	(570	)	$	76	$	(632	)
Total assets (end of period)	$	117,222	$	152,105		$	117,222	$	152,105

	Three Months ended June 30,						Six Months ended June 30,
	2017			2018			2017			2018
Crude Oil Trucking Services
Service revenue:
Third-party revenue	$	6,440		$	3,509		$	13,151		$	9,049
Intersegment revenue	74			986			244			1,429
Lease revenue:
Third-party revenue	—			32			—			129
Product sales revenue:
Third-party revenue	—			3			385			9
Total revenue for reportable segment	6,514			4,530			13,780			10,616
Operating expense, excluding depreciation and amortization	6,702			4,727			13,970			11,101
Operating margin, excluding depreciation and amortization	$	(188	)	$	(197	)	$	(190	)	$	(485	)
Total assets (end of period)	$	11,208		$	3,402		$	11,208		$	3,402
Total operating margin, excluding depreciation and amortization(1)	$	19,437		$	18,130		$	38,798		$	36,384
Total segment revenues	$	43,951		$	84,649		$	90,461		$	129,752
Elimination of intersegment revenues	(74		)	(1,156		)	(244		)	(1,599		)
Consolidated revenues	$	43,877		$	83,493		$	90,217		$	128,153

____________________

(1)The following table reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes (in thousands):

	Three Months ended June 30,						Six Months ended June 30,
	2017			2018			2017			2018
Operating margin, excluding depreciation and amortization	$	19,437		$	18,130		$	38,798		$	36,384
Depreciation and amortization	(7,839		)	(7,413		)	(15,905		)	(14,779		)
General and administrative expense	(4,322		)	(4,486		)	(8,907		)	(8,707		)
Asset impairment expense	(17		)	—			(45		)	(616		)
Gain (loss) on sale of assets	(754		)	599			(879		)	363
Interest expense	(4,265		)	(5,024		)	(7,295		)	(8,593		)
Gain on sale of unconsolidated affiliate	4,172			—			4,172			2,225
Equity earnings in unconsolidated affiliate	—			—			61			—
Income before income taxes	$	6,412		$	1,806		$	10,000		$	6,277

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INCOME TAXES (Tables)

6 Months Ended

Jun. 30, 2018

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 June 30, 2018, are presented below (dollars in thousands):

Deferred Tax Asset
Difference in bases of property, plant and equipment	$	444
Net operating loss carryforwards	11
Deferred tax asset	455
Less: valuation allowance	444
Net deferred tax asset	$	11

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ORGANIZATION AND NATURE OF BUSINESS (Narrative) (Details)	6 Months Ended
	Jun. 30, 2018 Operating-segments States
ORGANIZATION AND NATURE OF BUSINESS [Abstract]
Number of states in which entity operates (in states) | States	27
Number of operating segments (in operating segments) | Operating-segments	4

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REVENUE Narrative (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Third-party revenue	$ 14,103,000	$ 28,145,000	$ 31,421,000	$ 56,808,000
Accounts Receivable, Net, Current	31,268,000		31,268,000		$ 7,589,000
Revenue related to future performance obligations	159,639,000		159,639,000
Contract with Customer, Performance Obligation Satisfied in Previous Period	114,039
Billed contract accounts receivable	27,900,000		27,900,000		8,500,000
Contract with Customer, Asset, Net, Current	300,000		300,000		0
Contract with Customer, Liability, Noncurrent	4,600,000		4,600,000		$ 3,700,000
Changes in deferred revenue [Roll Forward]
Deferred revenue, additions			2,500,000
Contract with customer, liability, revenue recognized			(1,600,000)
Fixed Storage and Throughput Revenue [Member]
Third-party revenue	7,389,000		15,020,000
Variable Throughput Revenue [Member]
Third-party revenue	385,000		1,006,000
Variable Reimbursement Revenue [Member]
Third-party revenue	1,775,000		3,241,000
Crude Oil Transportation Revenue [Member]
Third-party revenue	4,554,000		12,154,000
Asphalt Terminalling Services [Member]
Third-party revenue	6,639,000	13,259,000	11,771,000	26,482,000
Asphalt Terminalling Services [Member] | Fixed Storage and Throughput Revenue [Member]
Third-party revenue	4,622,000		8,171,000
Asphalt Terminalling Services [Member] | Variable Throughput Revenue [Member]
Third-party revenue	242,000		$ 359,000
Revenue, Performance Obligation, Description of Payment Terms			P30D
Asphalt Terminalling Services [Member] | Variable Reimbursement Revenue [Member]
Third-party revenue	1,775,000		$ 3,241,000
Revenue, Performance Obligation, Description of Payment Terms			P30D
Asphalt Terminalling Services [Member] | Crude Oil Transportation Revenue [Member]
Third-party revenue	0		$ 0
Crude Oil Terminalling Services [Member]
Third-party revenue	2,910,000	5,726,000	7,496,000	11,851,000
Crude Oil Terminalling Services [Member] | Fixed Storage and Throughput Revenue [Member]
Third-party revenue	2,767,000		6,849,000
Crude Oil Terminalling Services [Member] | Variable Throughput Revenue [Member]
Third-party revenue	143,000		$ 647,000
Revenue, Performance Obligation, Description of Payment Terms			P30D
Crude Oil Terminalling Services [Member] | Variable Reimbursement Revenue [Member]
Third-party revenue	0		$ 0
Crude Oil Terminalling Services [Member] | Crude Oil Transportation Revenue [Member]
Third-party revenue	0		0
Crude Oil Pipeline Services [Member]
Third-party revenue	1,045,000	2,720,000	3,105,000	5,324,000
Crude Oil Pipeline Services [Member] | Fixed Storage and Throughput Revenue [Member]
Third-party revenue	0		0
Crude Oil Pipeline Services [Member] | Variable Throughput Revenue [Member]
Third-party revenue	0		0
Crude Oil Pipeline Services [Member] | Variable Reimbursement Revenue [Member]
Third-party revenue	0		0
Crude Oil Pipeline Services [Member] | Crude Oil Transportation Revenue [Member]
Third-party revenue	1,045,000		$ 3,105,000
Revenue, Performance Obligation, Description of Payment Terms			P30D
Crude Oil Pipeline Services [Member] | Crude Oil Product Sales Revenue [Member]
Revenue, Performance Obligation, Description of Payment Terms			P30D
Crude Oil Trucking Services [Member]
Third-party revenue	3,509,000	$ 6,440,000	$ 9,049,000	$ 13,151,000
Crude Oil Trucking Services [Member] | Fixed Storage and Throughput Revenue [Member]
Third-party revenue	0		0
Crude Oil Trucking Services [Member] | Variable Throughput Revenue [Member]
Third-party revenue	0		0
Crude Oil Trucking Services [Member] | Variable Reimbursement Revenue [Member]
Third-party revenue	0		0
Crude Oil Trucking Services [Member] | Crude Oil Transportation Revenue [Member]
Third-party revenue	3,509,000		$ 9,049,000
Revenue, Performance Obligation, Description of Payment Terms			P30D
Accounting Standards Update 2014-09 [Member]
Third-party revenue	200,000		$ 300,000
Accounts Receivable, Net, Current	$ 300,000		$ 300,000

XML

REVENUE Disaggregation of Revenue (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Disaggregation of Revenue [Line Items]
Third-party revenue	$ 14,103	$ 28,145	$ 31,421	$ 56,808
Third-party revenue, product sales	45,615	2,227	49,129	6,262
Related-party revenue	6,063	13,505	12,384	27,147
Revenue from contracts with customers	65,781		92,934
Fixed Storage and Throughput Revenue [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue	7,389		15,020
Related-party revenue	4,680		9,311
Variable Throughput Revenue [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue	385		1,006
Variable Reimbursement Revenue [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue	1,775		3,241
Related-party revenue	1,383		3,073
Crude Oil Transportation Revenue [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue	4,554		12,154
Crude Oil Product Sales Revenue [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue, product sales	45,615		49,129
Asphalt Terminalling Services [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue	6,639	13,259	11,771	26,482
Related-party revenue			12,302	26,837
Revenue from contracts with customers	12,620		24,073
Asphalt Terminalling Services [Member] | Fixed Storage and Throughput Revenue [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue	4,622		8,171
Related-party revenue	4,632		9,263
Asphalt Terminalling Services [Member] | Variable Throughput Revenue [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue	242		359
Asphalt Terminalling Services [Member] | Variable Reimbursement Revenue [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue	1,775		3,241
Related-party revenue	1,349		3,039
Asphalt Terminalling Services [Member] | Crude Oil Transportation Revenue [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue	0		0
Asphalt Terminalling Services [Member] | Crude Oil Product Sales Revenue [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue, product sales	0		0
Crude Oil Terminalling Services [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue	2,910	5,726	7,496	11,851
Revenue from contracts with customers	2,910		7,496
Crude Oil Terminalling Services [Member] | Fixed Storage and Throughput Revenue [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue	2,767		6,849
Related-party revenue	0		0
Crude Oil Terminalling Services [Member] | Variable Throughput Revenue [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue	143		647
Crude Oil Terminalling Services [Member] | Variable Reimbursement Revenue [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue	0		0
Related-party revenue	0		0
Crude Oil Terminalling Services [Member] | Crude Oil Transportation Revenue [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue	0		0
Crude Oil Terminalling Services [Member] | Crude Oil Product Sales Revenue [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue, product sales	0		0
Crude Oil Pipeline Services [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue	1,045	2,720	3,105	5,324
Third-party revenue, product sales	45,612	2,227	49,120	5,877
Related-party revenue			82	310
Revenue from contracts with customers	46,739		52,307
Crude Oil Pipeline Services [Member] | Fixed Storage and Throughput Revenue [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue	0		0
Related-party revenue	48		48
Crude Oil Pipeline Services [Member] | Variable Throughput Revenue [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue	0		0
Crude Oil Pipeline Services [Member] | Variable Reimbursement Revenue [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue	0		0
Related-party revenue	34		34
Crude Oil Pipeline Services [Member] | Crude Oil Transportation Revenue [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue	1,045		3,105
Crude Oil Pipeline Services [Member] | Crude Oil Product Sales Revenue [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue, product sales	45,612		49,120
Crude Oil Trucking Services [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue	3,509	6,440	9,049	13,151
Third-party revenue, product sales	3	$ 0	9	$ 385
Revenue from contracts with customers	3,512		9,058
Crude Oil Trucking Services [Member] | Fixed Storage and Throughput Revenue [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue	0		0
Related-party revenue	0		0
Crude Oil Trucking Services [Member] | Variable Throughput Revenue [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue	0		0
Crude Oil Trucking Services [Member] | Variable Reimbursement Revenue [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue	0		0
Related-party revenue	0		0
Crude Oil Trucking Services [Member] | Crude Oil Transportation Revenue [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue	3,509		9,049
Crude Oil Trucking Services [Member] | Crude Oil Product Sales Revenue [Member]
Disaggregation of Revenue [Line Items]
Third-party revenue, product sales	$ 3		$ 9

XML

REVENUE Revenue Related to Future Performance Obligations Due by Period (Details) $ in Thousands	Jun. 30, 2018 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue related to future performance obligations	$ 159,639
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue related to future performance obligations	35,257
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue related to future performance obligations	64,767
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue related to future performance obligations	46,024
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue related to future performance obligations	$ 13,591

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RESTRUCTURING CHARGES (Details) - West Texas Trucking Market Exit Plan [Member] - Crude Oil Trucking Services [Member] - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2016
Restructuring Cost and Reserve [Line Items]
Restructuring reserve	$ 0	$ 382	$ 0	$ 382	$ 237	$ 286	$ 428	$ 474
Cash payments	$ 237	$ 46	$ 286	$ 92

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EQUITY METHOD INVESTMENT (Details) - USD ($) $ in Thousands			3 Months Ended			6 Months Ended
	Jan. 02, 2018	Apr. 03, 2017	Jun. 30, 2018	Sep. 30, 2017	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Schedule of Equity Method Investments [Line Items]
Proceeds from sale of unconsolidated affiliate						$ 2,225	$ 25,324
Gain on sale of unconsolidated affiliate			$ 0		$ 4,172	$ 2,225	4,172
Advantage Pipeline, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage		30.00%
Proceeds from sale of unconsolidated affiliate	$ 2,200	$ 25,300		$ 1,100
Equity Method Investment, Summarized Financial Information, Revenue							3,150
Equity Method Investment, Summarized Financial Information, Cost of Sales							465
Equity Method Investment, Summarized Financial Information, Net income							$ 187
Gain on sale of unconsolidated affiliate		$ 4,200
Proceeds from Sale of Equity Method Investment, Percent Held In Escrow		10.00%

XML

PROPERTY, PLANT AND EQUIPMENT (Details) - USD ($) $ in Thousands				3 Months Ended		6 Months Ended
	Apr. 24, 2018	Dec. 01, 2017	Apr. 18, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross				$ 565,689		$ 565,689		$ 612,660
Accumulated depreciation				269,978		269,978		316,591
Property, plant and equipment, net				295,711		295,711		296,069
Depreciation				6,700	$ 7,500	13,700	$ 15,300
Payments to Acquire Businesses, Gross						21,959	0
Land
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross				25,067		25,067		24,776
Land improvements
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross				5,815		5,815		6,787
Pipelines and facilities
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross				167,624		167,624		166,004
Storage and terminal facilities
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross				319,344		319,344		370,056
Transportation equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross				1,056		1,056		3,293
Office property and equipment and other
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross				26,958		26,958		32,011
Pipeline linefill and tank bottoms
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross				11,694		11,694		3,233
Construction-in-progress
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross				8,131		$ 8,131		$ 6,500
Min | Land improvements
Property, Plant and Equipment [Line Items]
Estimated Useful Lives (Years)						10 years
Min | Pipelines and facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Lives (Years)						5 years
Min | Storage and terminal facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Lives (Years)						10 years
Min | Transportation equipment
Property, Plant and Equipment [Line Items]
Estimated Useful Lives (Years)						3 years
Min | Office property and equipment and other
Property, Plant and Equipment [Line Items]
Estimated Useful Lives (Years)						3 years
Max | Land improvements
Property, Plant and Equipment [Line Items]
Estimated Useful Lives (Years)						20 years
Max | Pipelines and facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Lives (Years)						30 years
Max | Storage and terminal facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Lives (Years)						35 years
Max | Transportation equipment
Property, Plant and Equipment [Line Items]
Estimated Useful Lives (Years)						10 years
Max | Office property and equipment and other
Property, Plant and Equipment [Line Items]
Estimated Useful Lives (Years)						20 years
Oklahoma [Member] | Asphalt Terminalling Services [Member]
Property, Plant and Equipment [Line Items]
Payments to Acquire Businesses, Gross							$ 22,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment				11,500		$ 11,500
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles				7,600		7,600
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net				$ 2,900		$ 2,900
Texas [Member] | Crude Oil Trucking Services [Member]
Property, Plant and Equipment [Line Items]
Proceeds from Sale of Property Held-for-sale	$ 3,000
Gain (Loss) on Disposition of Assets	$ 400
Texas [Member] | Crude Oil Pipeline Services [Member]
Property, Plant and Equipment [Line Items]
Proceeds from Sale of Property Held-for-sale			$ 4,800
Gain (Loss) on Disposition of Assets			$ 100
Limited Partner [Member] | Ergon [Member]
Property, Plant and Equipment [Line Items]
Stock Issued During Period, Shares, Acquisitions		1,898,380
Stock Issued During Period, Value, Acquisitions		$ 10,200

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DEBT (Credit Agreements) (Details)			3 Months Ended		6 Months Ended
	Jun. 28, 2018 USD ($)	May 11, 2017 USD ($)	Jun. 30, 2018 USD ($)	Jun. 30, 2017 USD ($)	Jun. 30, 2018 USD ($)	Jun. 30, 2017 USD ($)	Jul. 26, 2018 USD ($)	Dec. 31, 2017 USD ($)
Debt Instrument [Line Items]
Maximum quarterly distribution					$ 10,700,000
Write-off of deferred debt issuance costs	$ 400,000	$ 700,000
Debt issuance costs, noncurrent, net			$ 3,802,000		3,802,000			$ 4,442,000
Payments for Debt issuance costs					309,000	$ 4,017,000
Amortization of debt issuance costs			256,000	$ 273,000	513,000	614,000
Interest expense for long-term debt			4,700,000	3,400,000	8,600,000	6,700,000
Capitalized interest			43,000	3,000	72,000	5,000
Long-term Debt, Excluding Current Maturities			349,592,000		349,592,000			307,592,000
Derivative, Notional Amount			100,000,000		100,000,000			$ 200,000,000
Interest Expense, Other			100,000	$ 400,000	$ 100,000	$ 800,000
Blueknight General Partners G. P., L.L.C. [Member]
Debt Instrument [Line Items]
Credit agreement change of control provision, General Partner ownership minimum					100.00%
Ergon [Member]
Debt Instrument [Line Items]
Credit agreement change of control provision, Ergon minimum control percentage					50.00%
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Revolving credit facility amount	450,000,000		400,000,000		$ 400,000,000
Maximum borrowing capacity including additional lenders			$ 600,000,000		$ 600,000,000
Debt instrument maximum covenant consolidated senior secured leverage ratio			3.50		3.50
Consolidated interest coverage (as a ratio), minimum permitted			2.50		2.50
Consolidated total leverage (as a ratio), actual			4.65		4.65
Consolidated interest coverage (as a ratio), actual			3.78		3.78
Write-off of deferred debt issuance costs	$ 400,000
Debt issuance costs, noncurrent, net		$ 900,000
Debt instrument, interest rate during period			5.39%	4.44%	5.18%	4.27%
Payments for Debt issuance costs			$ 309,000	$ 4,010,000	$ 300,000	$ 4,017,000
Revolving Credit Facility [Member] | Min
Debt Instrument [Line Items]
Unused capacity, commitment fee (as a percent)					0.375%
Debt instrument covenant, issued qualified senior notes			$ 200,000,000		$ 200,000,000
Revolving Credit Facility [Member] | Max
Debt Instrument [Line Items]
Unused capacity, commitment fee (as a percent)					0.50%
Revolving Credit Facility [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Revolver borrowings							$ 263,600,000
Unused borrowing capacity							133,000,000
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] | Min
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)					1.00%
Revolving Credit Facility [Member] | Applicable margin based on ABR [Member] | Max
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] | Min
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] | Max
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)					3.00%
Letter of Credit [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Letters of credit outstanding							$ 3,400,000
Aggregate Principal Below Threshold [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Consolidated total leverage (as a ratio), maximum permitted			4.75		4.75
Minimum acquisition costs					$ 15,000,000.0
Debt instrument covenant, issued qualified senior notes			$ 200,000,000		200,000,000
Aggregate Principal Above Threshold [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt instrument covenant, issued qualified senior notes			$ 200,000,000		$ 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			5.50		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		5.25
Provision One, Applicable Period Three [Member] | Aggregate Principal Below Threshold [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Consolidated total leverage (as a ratio), maximum permitted			5.00		5.00
Provision One, Applicable Period Four [Member] | Aggregate Principal Below Threshold [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Consolidated total leverage (as a ratio), maximum permitted			4.75		4.75
Provision Two, 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			5.25		5.25
Provision Three, 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			5.00		5.00
Provision Three, Applicable Period Two [Member] | Aggregate Principal Above Threshold [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Consolidated total leverage (as a ratio), maximum permitted			5.50		5.50

XML

DEBT Derivative Instruments (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Interest Rate Swaps, Notional Amount	$ 100,000		$ 100,000		$ 200,000
Unrealized Gain (Loss) on Interest Rate Swaps	(40)	$ 223	314	$ 975
Other Current Assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Interest Rate Swap Assets - Current	157		157		68
Other Noncurrent Liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Interest Rate Swap Liabilities - Noncurrent	$ 0		$ 0		$ 225

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NET INCOME PER LIMITED PARTNER UNIT (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Earnings Per Share [Abstract]
Net income	$ 1,785	$ 6,371	$ 6,227	$ 9,913
General partner interest in net income	28	256	259	465
Preferred interest in net income	6,279	6,279	12,557	12,558
Net loss available to limited partners	$ (4,522)	$ (164)	$ (6,589)	$ (3,110)
Basic and diluted weighted average number of units:
Common units	40,324	38,155	40,306	38,151
Weighted Average Restricted and Phantom Partnership Units Outstanding, Basic and Diluted	1,133	923	983	806
Total Weighted Average Limited Partnership Units Outstanding, Basic and Diluted	41,457	39,078	41,289	38,957
Basic and diluted net loss per common unit	$ (0.11)	$ 0.00	$ (0.16)	$ (0.08)

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PARTNERS' CAPITAL AND DISTRIBUTIONS Issuances Narrative (Details) - Ergon [Member] - Limited Partner [Member] $ in Millions	Dec. 01, 2017 USD ($) shares
Capital Unit [Line Items]
Value of stock issued during the period for acquisitions | $	$ 10.2
Common units issued during the period for acquisitions | shares	1,898,380

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PARTNERS' CAPITAL AND DISTRIBUTIONS Cash Distributions Paid on Preferred Units (Details) - Preferred Units [Member] $ / shares in Units, $ in Millions	3 Months Ended
	Jun. 30, 2018 USD ($) $ / shares
Preferred and General Partners [Member]
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Cash Distributions Declared	$ 6.4
Preferred Partner [Member]
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit | $ / shares	$ 0.17875
Distribution Made to Limited Partner, Cash Distributions Declared	$ 6.3
General Partner [Member]
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Cash Distributions Declared	$ 0.1

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PARTNERS' CAPITAL AND DISTRIBUTIONS Cash Distributions Paid on Common Units (Details) - Common Units [Member] $ / shares in Units, $ in Millions	3 Months Ended
	Jun. 30, 2018 USD ($) $ / shares
Limited, General Partner, Phantom Share and Restricted Units [Member]
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Cash Distributions Declared	$ 3.4
Limited Partner [Member]
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit | $ / shares	$ 0.0800
Distribution Made to Limited Partner, Cash Distributions Declared	$ 3.2
General Partner [Member]
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Cash Distributions Declared	0.1
Phantom Share Units and Restricted Units [Member]
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Cash Distributions Declared	$ 0.1

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RELATED PARTY TRANSACTIONS (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Related Party Transaction [Line Items]
Receivables from related parties	$ 1,219		$ 1,219		$ 3,070
Accounts payable to related parties	$ 12,878		$ 12,878		2,268
Noncontrolling Interest, Ownership Percentage by Parent	50.00%		50.00%
Ergon [Member]
Related Party Transaction [Line Items]
Related-party revenue	$ 13,500	$ 13,500	$ 27,500	$ 26,800
Receivables from related parties	1,219		1,219		3,100
Payables to Related Parties	$ 5,300		$ 5,300		$ 1,600
Joint Venture Purchase Option	100.00%		100.00%
Advantage Pipeline, L.L.C. [Member]
Related Party Transaction [Line Items]
Related-party revenue				$ 300
Crude Oil Purchase Agreement [Member] | Ergon [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	$ 30,000		$ 30,000
Accounts payable to related parties	$ 9,800		$ 9,800

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LONG-TERM INCENTIVE PLAN (Details) - USD ($) $ / shares in Units, $ in Thousands		1 Months Ended								3 Months Ended		6 Months Ended
		Mar. 31, 2018	Dec. 31, 2017		Mar. 31, 2017	Dec. 31, 2016		Oct. 31, 2016	Mar. 31, 2016	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based incentive compensation expense (in dollars)												$ 687	$ 524
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
Number of Units [Roll Forward]
Nonvested at December 31, 2017												923,551
Granted												457,984
Vested												241,629
Forfeited												10,865
Nonvested at June 30, 2018			923,551							1,129,041		1,129,041
Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value, Nonvested, Beginning balance (in dollars per unit)												$ 6.29
Weighted Average Grant Date Fair Value, Granted (in dollars per unit)												4.77
Weighted Average Grant Date Fair Value, Vested (in dollars per unit)												7.46
Weighted Average Grant Date Fair Value, Forfeited (in dollars per unit)												5.39
Weighted Average Grant Date Fair Value, Nonvested, Ending balance (in dollars per unit)			$ 6.29							$ 5.88		$ 5.88
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)			$ 69			$ 70
Number of Units [Roll Forward]
Granted			14,286			10,220
Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value, Granted (in dollars per unit)	[1]		$ 4.85			$ 6.85
Blueknight Energy Partners G.P., L.L.C. Long-Term Incentive Plan [Member] | Phantom common units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized estimated compensation cost (in dollars)										$ 3,100		$ 3,100
Equity-based incentive compensation expense (in dollars)										$ 600	$ 600	$ 1,100	$ 1,100
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)			$ 74			$ 75
Number of Units [Roll Forward]
Granted			15,306			10,950
Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value, Granted (in dollars per unit)			$ 4.85	[1]		$ 6.85	[2]
January 2019 Vesting [Member] | Blueknight Energy Partners G.P., L.L.C. Long-Term Incentive Plan [Member] | Phantom common units [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]
Granted								9,960	416,131
Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value, Granted (in dollars per unit)	[3]							$ 5.85	$ 4.77
January 2020 Vesting [Member] | Blueknight Energy Partners G.P., L.L.C. Long-Term Incentive Plan [Member] | Phantom common units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Value of award grants (in dollars)					$ 2,312
Number of Units [Roll Forward]
Granted					323,339
Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value, Granted (in dollars per unit)	[3]				$ 7.15
January 2021 Vesting [Member] | Blueknight Energy Partners G.P., L.L.C. Long-Term Incentive Plan [Member] | Phantom common units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Value of award grants (in dollars)		$ 2,185
Number of Units [Roll Forward]
Granted		457,984
Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value, Granted (in dollars per unit)	[3]	$ 4.77

[1] Fair value is the closing market price on the grant date of the awards.

[2] Fair value is the closing market price on the grant date of the awards.

[3] Fair value is the closing market price on the grant date of the awards.

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EMPLOYEE BENEFIT PLAN (Details) - Blueknight Energy Partners G.P., L.L.C. 401(K) Plan [Member] - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Employer discretionary contribution amount	$ 0.3	$ 0.3	$ 0.6	$ 0.6
Other Postretirement Benefits Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Employer discretionary contribution amount	$ 0.1	$ 0.2	$ 0.1	$ 0.4

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EMPLOYEE BENEFIT PLAN EUPP (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
EUPP [Abstract]
Employee Stock Ownership Plan (ESOP), Shares in ESOP	1,000,000		1,000,000
Employee Stock Ownership Plan (ESOP), Compensation Expense	$ 0.1	$ 0.1	$ 0.1	$ 0.1

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FAIR VALUE MEASUREMENTS Fair Value Measurements (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate swap assets	$ 157	$ 68
Total Swap Assets	157	68
Interest rate swap liabilities	0	225
Total swap liabilities		225
Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate swap assets	0	0
Total Swap Assets	0	0
Interest rate swap liabilities		0
Total swap liabilities		0
Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate swap assets	157	68
Total Swap Assets	157	68
Interest rate swap liabilities		225
Total swap liabilities		225
Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate swap assets	0	0
Total Swap Assets	$ 0	0
Interest rate swap liabilities		0
Total swap liabilities		$ 0

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OPERATING SEGMENTS (Details) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018 USD ($)	Jun. 30, 2017 USD ($)	Jun. 30, 2018 USD ($) Operating-segments	Jun. 30, 2017 USD ($)	Jul. 26, 2018 Terminalling_And_Storage_Facilities	Dec. 31, 2017 USD ($)
Segment Reporting Information [Line Items]
Number of operating segments (in operating segments) | Operating-segments			4
Service revenue
Third-party revenue	$ 14,103	$ 28,145	$ 31,421	$ 56,808
Sales revenue from related parties, services, net	6,063	13,505	12,384	27,147
Lease revenue:
Third-party revenue	10,237	0	20,041	0
Related-party revenue	7,475	0	15,178	0
Product sales revenue:
Third-party revenue	45,615	2,227	49,129	6,262
Total revenue for reportable segments	83,493	43,877	128,153	90,217
Third-party cost of product sales	20,041	1,669	22,678	4,808
Related-party cost of product sales	23,747	0	23,747	0
Operating margin, excluding depreciation and amortization	18,130	19,437	36,384	38,798
Total assets (end of period)	390,506		390,506			$ 340,869
Reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes
Operating margin, excluding depreciation and amortization	18,130	19,437	36,384	38,798
Depreciation and amortization	(7,413)	(7,839)	(14,779)	(15,905)
General and administrative expense	(4,486)	(4,322)	(8,707)	(8,907)
Asset impairment expense	0	(17)	(616)	(45)
Gain (loss) on sale of assets	599	(754)	363	(879)
Interest expense	(5,024)	(4,265)	(8,593)	(7,295)
Gain on sale of unconsolidated affiliate	0	4,172	2,225	4,172
Equity earnings in unconsolidated affiliate	0	0	0	61
Income before income taxes	1,806	6,412	6,277	10,000
Asphalt Terminalling Services [Member]
Service revenue
Third-party revenue	6,639	13,259	11,771	26,482
Related-party revenue	5,981	13,505
Sales revenue from related parties, services, net			12,302	26,837
Lease revenue:
Third-party revenue	10,016	0	19,473	0
Related-party revenue	7,475	0	15,178	0
Product sales revenue:
Total revenue for reportable segments	30,111	26,764	58,724	53,319
Operating expenses (excluding depreciation and amortization)	13,393	11,935	26,728	24,255
Operating margin, excluding depreciation and amortization	16,718	14,829	31,996	29,064
Total assets (end of period)	167,849	147,832	167,849	147,832
Reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes
Operating margin, excluding depreciation and amortization	16,718	14,829	31,996	29,064
Crude Oil Terminalling Services [Member]
Service revenue
Third-party revenue	2,910	5,726	7,496	11,851
Intersegment Revenues	170	0	170	0
Lease revenue:
Third-party revenue	12	0	27	0
Product sales revenue:
Total revenue for reportable segments	3,092	5,726	7,693	11,851
Operating expenses (excluding depreciation and amortization)	913	992	2,188	2,003
Operating margin, excluding depreciation and amortization	2,179	4,734	5,505	9,848
Total assets (end of period)	67,150	69,834	67,150	69,834
Reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes
Operating margin, excluding depreciation and amortization	2,179	4,734	5,505	9,848
Crude Oil Pipeline Services [Member]
Service revenue
Third-party revenue	1,045	2,720	3,105	5,324
Related-party revenue	82	0
Sales revenue from related parties, services, net			82	310
Lease revenue:
Third-party revenue	177	0	412	0
Product sales revenue:
Third-party revenue	45,612	2,227	49,120	5,877
Total revenue for reportable segments	46,916	4,947	52,719	11,511
Operating expenses (excluding depreciation and amortization)	2,542	3,142	5,327	6,383
Intersegment operating expenses	1,156	74	1,599	244
Third-party cost of product sales	20,041	1,669	22,678	4,808
Related-party cost of product sales	23,747	0	23,747	0
Operating margin, excluding depreciation and amortization	(570)	62	(632)	76
Total assets (end of period)	152,105	117,222	152,105	117,222
Reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes
Operating margin, excluding depreciation and amortization	(570)	62	(632)	76
Crude Oil Trucking Services [Member]
Service revenue
Third-party revenue	3,509	6,440	9,049	13,151
Intersegment Revenues	986	74	1,429	244
Lease revenue:
Third-party revenue	32	0	129	0
Product sales revenue:
Third-party revenue	3	0	9	385
Total revenue for reportable segments	4,530	6,514	10,616	13,780
Operating expenses (excluding depreciation and amortization)	4,727	6,702	11,101	13,970
Operating margin, excluding depreciation and amortization	(197)	(188)	(485)	(190)
Total assets (end of period)	3,402	11,208	3,402	11,208
Reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes
Operating margin, excluding depreciation and amortization	(197)	(188)	(485)	(190)
Operating Segments [Member]
Service revenue
Intersegment Revenues	(1,156)	(74)	(1,599)	(244)
Product sales revenue:
Total revenue for reportable segments	$ 84,649	$ 43,951	$ 129,752	$ 90,461
Subsequent Event [Member] | Asphalt Terminalling Services [Member]
Segment Reporting Information [Line Items]
Number of terminalling and storage facilities providing asphalt product and residual fuel terminalling storage and blending services (in terminalling and storage facilities) | Terminalling_And_Storage_Facilities					53
Reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes
Number of states where Asphalt terminalling and storage facilities are located | Terminalling_And_Storage_Facilities					26

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INCOME TAXES (Details) $ in Thousands	Jun. 30, 2018 USD ($)
Valuation Allowance [Line Items]
Difference in bases of property, plant and equipment	$ 444
Deferred tax asset, operating loss carryforwards	11
Deferred tax asset	455
Less: valuation allowance	444
Net deferred tax asset	$ 11

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SUBSEQUENT EVENTS (Details) $ in Millions	Jul. 13, 2018 USD ($)
Asphalt Terminalling Services [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Proceeds from Sale of Property Held-for-sale	$ 90.0