Blueknight Energy Partners, L.P. - Quarter Report: 2018 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended September 30, 2018


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 every Interactive Data File required to be submitted 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 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		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 October 25, 2018, there were 35,125,202 Series A Preferred Units and 40,393,743 common units outstanding.



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		Page
PART I	FINANCIAL INFORMATION	1
Item 1.	Unaudited Condensed Consolidated Financial Statements	1
	Condensed Consolidated Balance Sheets as of December 31, 2017, and September 30, 2018	1
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2017 and 2018	2
	Condensed Consolidated Statement of Changes in Partners’ Capital (Deficit) for the Nine Months Ended September 30, 2018	3
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2017 and 2018	4
	Notes to the Unaudited Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	39
Item 4.	Controls and Procedures	39

PART II	OTHER INFORMATION	40
Item 1.	Legal Proceedings	40
Item 1A.	Risk Factors	40
Item 6.	Exhibits	40

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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			September 30, 2018
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	2,469		$	1,926
Accounts receivable, net of allowance for doubtful accounts of $28 at both dates	7,589			46,917
Receivables from related parties, net of allowance for doubtful accounts of $0 at both dates	3,070			1,647
Prepaid insurance	2,009			2,146
Other current assets	8,438			9,834
Total current assets	23,575			62,470
Property, plant and equipment, net of accumulated depreciation of $316,591 and $276,290 at December 31, 2017, and September 30, 2018, respectively	296,069			295,272
Goodwill	3,870			6,728
Debt issuance costs, net	4,442			3,600
Intangibles and other assets, net	12,913			18,169
Total assets	$	340,869		$	386,239
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	4,439		$	4,311
Accounts payable to related parties	2,268			3,093
Accrued crude oil purchases	1,115			15,142
Accrued crude oil purchases to related parties	—			16,681
Accrued interest payable	694			462
Accrued property taxes payable	2,432			3,776
Unearned revenue	2,393			3,207
Unearned revenue with related parties	551			2,809
Accrued payroll	6,119			3,838
Other current liabilities	3,632			3,820
Total current liabilities	23,643			57,139
Long-term unearned revenue with related parties	1,052			745
Other long-term liabilities	3,673			3,726
Long-term interest rate swap liabilities	225			—
Long-term debt	307,592			271,592
Commitments and contingencies (Note 15)
Partners’ capital:
Common unitholders (40,158,342 and 40,387,006 units issued and outstanding at December 31, 2017, and September 30, 2018, respectively)	454,358			429,959
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		)	(630,845		)
Total partners’ capital	4,684			53,037
Total liabilities and partners’ capital	$	340,869		$	386,239

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 September 30,						Nine Months ended September 30,
	2017			2018			2017			2018
	(unaudited)
Service revenue:
Third-party revenue	$	30,635		$	12,743		$	87,443		$	44,164
Related-party revenue	14,464			5,396			41,611			17,780
Lease revenue:
Third-party revenue	—			11,368			—			31,409
Related-party revenue	—			5,406			—			20,584
Product sales revenue:
Third-party revenue	2,375			97,763			8,637			146,892
Related-party revenue	—			482			—			482
Total revenue	47,474			133,158			137,691			261,311
Costs and expenses:
Operating expense	29,380			27,174			91,896			87,297
Cost of product sales	1,675			50,815			6,483			73,493
Cost of product sales from related party	—			44,106			—			67,853
General and administrative expense	4,093			4,322			13,000			13,029
Asset impairment expense	—			15			45			631
Total costs and expenses	35,148			126,432			111,424			242,303
Gain (loss) on sale of assets	(107		)	(63		)	(986		)	300
Operating income	12,219			6,663			25,281			19,308
Other income (expenses):
Equity earnings in unconsolidated affiliate	—			—			61			—
Gain on sale of unconsolidated affiliate	1,112			—			5,284			2,225
Interest expense	(3,500		)	(4,090		)	(10,795		)	(12,683		)
Income before income taxes	9,831			2,573			19,831			8,850
Provision for income taxes	60			165			147			215
Net income	$	9,771		$	2,408		$	19,684		$	8,635

Allocation of net income for calculation of earnings per unit:
General partner interest in net income	$	312		$	39		$	777		$	298
Preferred interest in net income	$	6,279		$	6,279		$	18,837		$	18,836
Net income (loss) available to limited partners	$	3,180		$	(3,910	)	$	70		$	(10,499	)

Basic and diluted net income (loss) per common unit	$	0.08		$	(0.09	)	$	—		$	(0.25	)

Weighted average common units outstanding - basic and diluted	38,189			40,380			38,164			40,331

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)	(10,655		)	18,836			454			8,635
Equity-based incentive compensation	1,325			—			27			1,352
Distributions	(15,277		)	(18,836		)	(879		)	(34,992		)
Capital contributions	—			—			183			183
Capital contributions related to sale of terminal assets to Ergon	—			—			72,967			72,967
Proceeds from sale of 61,327 common units pursuant to the Employee Unit Purchase Plan	208			—			—			208
Balance, September 30, 2018	$	429,959		$	253,923		$	(630,845	)	$	53,037

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)

	Nine Months ended September 30,
	2017			2018
	(unaudited)
Cash flows from operating activities:
Net income	$	19,684		$	8,635
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for uncollectible receivables from third parties	(19		)	—
Depreciation and amortization	23,586			21,945
Amortization and write-off of debt issuance costs	1,560			1,200
Unrealized gain related to interest rate swaps	(1,253		)	(277		)
Intangible asset impairment charge	—			189
Fixed asset impairment charge	45			442
Loss (gain) on sale of assets	986			(300		)
Gain on sale of unconsolidated affiliate	(5,284		)	(2,225		)
Equity-based incentive compensation	913			1,352
Equity earnings in unconsolidated affiliate	(61		)	—
Changes in assets and liabilities:
Increase in accounts receivable	(352		)	(39,328		)
Decrease (increase) in receivables from related parties	(110		)	1,423
Decrease in prepaid insurance	1,964			1,817
Decrease (increase) in other current assets	53			(949		)
Decrease in other non-current assets	56			424
Decrease in accounts payable	(142		)	(435		)
Increase in payables to related parties	159			1,068
Increase in accrued crude oil purchases	785			15,142
Increase in accrued crude oil purchases to related parties	—			16,681
Increase (decrease) in accrued interest payable	338			(232		)
Increase in accrued property taxes	1,187			1,718
Increase in unearned revenue	775			853
Increase in unearned revenue from related parties	3,835			2,829
Decrease in accrued payroll	(804		)	(2,281		)
Decrease in other accrued liabilities	(1,720		)	(1,504		)
Net cash provided by operating activities	46,181			28,187
Cash flows from investing activities:
Acquisitions	—			(21,959		)
Capital expenditures	(13,312		)	(29,560		)
Proceeds from sale of assets	9,202			4,707
Proceeds from sale of terminal assets to Ergon	—			88,538
Proceeds from sale of unconsolidated affiliate	26,436			2,225
Net cash provided by investing activities	22,326			43,951
Cash flows from financing activities:
Payment on insurance premium financing agreement	(2,074		)	(1,722		)
Debt issuance costs	(4,172		)	(358		)
Borrowings under credit agreement	344,592			216,000
Payments under credit agreement	(371,000		)	(252,000		)
Proceeds from equity issuance	240			208
Capital contributions	104			183
Distributions	(36,853		)	(34,992		)
Net cash used in financing activities	(69,163		)	(72,681		)
Net decrease in cash and cash equivalents	(656		)	(543		)
Cash and cash equivalents at beginning of period	3,304			2,469
Cash and cash equivalents at end of period	$	2,648		$	1,926

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BLUEKNIGHT ENERGY PARTNERS, L.P. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands)

Supplemental disclosure of non-cash financing and investing cash flow information:
Non-cash changes in property, plant and equipment	$	717	$	(908	)
Non-cash change in assets and liabilities due to settlement items related to the sale of terminal assets to Ergon	$	—	$	(1,308	)
Increase in accrued liabilities related to insurance premium financing agreement	$	2,938	$	2,225

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 February 2007 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 September 30, 2018, the condensed consolidated statements of operations for the three and nine months ended September 30, 2017 and 2018, the condensed consolidated statement of changes in partners’ capital (deficit) for the nine months ended September 30, 2018, and the condensed consolidated statements of cash flows for the nine months ended September 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.

A reclassification has been made in the consolidated balance sheet as of December 31, 2017, to conform to the 2018 financial statement presentation. This was a reclassification of “Accrued crude oil purchases” from “Accrued liabilities.” The reclassification has no impact on net income.

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.

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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 recognizing $1.6 million and $1.3 million less “Service revenue - Third-party revenue” in the unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2018, respectively, and additional “Accounts receivable” of $0.2 million on the unaudited condensed consolidated balance sheet as of September 30, 2018, over what would have been recorded under ASC 605. This represents a shift in revenue recognition between quarters within the fiscal year, and the difference is anticipated to be recognized during the fourth quarter of 2018. 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 decrease to revenue of $0.1 million related to changes in estimated throughput fees for the three months ended September 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.

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As of September 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	$	28,299
1-3 years	51,848
4-5 years	32,536
More than 5 years	10,320
Total revenue related to future performance obligations	$	123,003

____________________


(1)	Excluded from the table is revenue that is either constrained or related to performance obligations that are wholly unsatisfied as of September 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 September 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	$	4,865	$	1,830	$	—	$	—	$	6,695
Variable throughput revenue	112		93		—		—		205
Variable reimbursement revenue	1,943		—		—		—		1,943
Crude oil transportation revenue	—		—		1,166		2,734		3,900
Crude oil product sales revenue	—		—		97,763		—		97,763
Related-party revenue:
Fixed storage, throughput and other revenue	3,011		—		83		—		3,094
Variable throughput revenue	762		—		—		—		762
Variable reimbursement revenue	1,439		—		101		—		1,540
Total revenue from contracts with customers	$	12,132	$	1,923	$	99,113	$	2,734	$	115,902



	Nine Months ended September 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	$	13,038	$	8,679	$	—	$	—	$	21,717
Variable throughput revenue	471		739		—		—		1,210
Variable reimbursement revenue	5,184		—		—		—		5,184
Crude oil transportation revenue	—		—		4,270		11,783		16,053
Crude oil product sales revenue	—		—		146,882		10		146,892
Related-party revenue:
Fixed storage, throughput and other revenue	12,272		—		132		—		12,404
Variable throughput revenue	762		—		—		—		762
Variable reimbursement revenue	4,478		—		136		—		4,614
Total revenue from contracts with customers	$	36,205	$	9,418	$	151,420	$	11,793	$	208,836

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 $44.9 million at December 31, 2017, and September 30, 2018, respectively.

Un-billed accounts receivable from contracts with customers were $0.2 million at September 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 $4.8 million at December 31, 2017, and September 30, 2018, respectively. The change in the unearned revenue balance for the nine months ended September 30, 2018, is driven by $2.8 million in cash payments received in advance of satisfying performance obligations, partially offset by $1.7 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 September 30,		Nine Months ended September 30,
	2017		2017		2018
Beginning balance	$	382	$	474	$	286
Cash payments	48		140		286
Ending balance	$	334	$	334	$	—

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			September 30, 2018
	Estimated Useful Lives (Years)	December 31, 2017			September 30, 2018
		(dollars in thousands)
Land	N/A	$	24,776		$	25,030
Land improvements	10-20	6,787			5,815
Pipelines and facilities	5-30	166,004			173,139
Storage and terminal facilities	10-35	370,056			320,635
Transportation equipment	3-10	3,293			1,314
Office property and equipment and other	3-20	32,011			26,971
Pipeline linefill and tank bottoms	N/A	3,233			14,946
Construction-in-progress	N/A	6,500			3,712
Property, plant and equipment, gross		612,660			571,562
Accumulated depreciation		(316,591		)	(276,290		)
Property, plant and equipment, net		$	296,069		$	295,272

Depreciation expense for the three months ended September 30, 2017 and 2018, was $7.4 million and $6.5 million, respectively. Depreciation expense for the nine months ended September 30, 2017 and 2018, was $22.6 million and $20.2 million, respectively.

On July 12, 2018, the Partnership sold 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 Asphalt & Emulsion, Inc. for a purchase price of $90.0 million, subject to customary adjustments. 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.

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, Inc. (“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 October 25, 2018, approximately $257.6 million of revolver borrowings and $4.2 million of letters of credit were outstanding under the credit agreement, leaving the Partnership with approximately $138.2 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.

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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:

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•	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 September 30, 2018, the Partnership’s consolidated total leverage ratio was 5.39 to 1.00 and the consolidated interest coverage ratio was 3.32 to 1.00. The Partnership was in compliance with all covenants of its credit agreement as of September 30, 2018. Based on current operating plans and forecasts, the Partnership expects to remain in compliance with all covenants of its credit agreement for the next 12 months, however with less clearance, given the impact of the third quarter of 2018 results on the trailing twelve-month covenant calculations. There are no assurances that the Partnership can achieve this plan.

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 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.

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Upon the execution of the 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 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 $0.2 million and less than $0.1 million of debt issuance costs during the three months ended September 30, 2017 and 2018, respectively. The Partnership capitalized $4.2 million and $0.4 million of debt issuance costs during the nine months ended September 30, 2017 and 2018, respectively. 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 September 30, 2017 and 2018, was $0.3 million. Interest expense related to debt issuance cost amortization for the nine months ended September 30, 2017 and 2018, was $0.9 million and $0.8 million, respectively.

During the three months ended September 30, 2017 and 2018, the weighted average interest rate under the Partnership’s credit agreement was 4.54% and 5.65%, respectively, resulting in interest expense of approximately $3.5 million and $4.1 million, respectively. During the nine months ended September 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 4.36% and 5.33%, respectively, resulting in interest expense of approximately $10.2 million and $12.6 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 September 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 September 30, 2017 and 2018, the Partnership recorded swap interest expense of $0.3 million and swap interest income of less than $0.1 million, respectively. During the nine months ended September 30, 2017 and 2018, the Partnership recorded swap interest expense of $1.1 million and swap interest income of 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
Derivatives Not Designated as Hedging Instruments	Balance Sheet Location	December 31, 2017		September 30, 2018
Interest rate swap assets - current	Other current assets	$	68	$	120
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 September 30,					Nine Months ended September 30,
		2017		2018			2017		2018
Interest rate swaps	Interest expense, net of capitalized interest	$	278	$	(37	)	$	1,253	$	277

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 September 30,					Nine Months ended September 30,
	2017		2018			2017		2018
Net income	$	9,771	$	2,408		$	19,684	$	8,635
General partner interest in net income	312		39			777		298
Preferred interest in net income	6,279		6,279			18,837		18,836
Net income (loss) available to limited partners	$	3,180	$	(3,910	)	$	70	$	(10,499	)

Basic and diluted weighted average number of units:
Common units	38,189		40,380			38,164		40,331
Restricted and phantom units	922		1,090			845		1,019
Total units	39,111		41,470			39,009		41,350

Basic and diluted net income (loss) per common unit	$	0.08	$	(0.09	)	$	—	$	(0.25	)

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 October 23, 2018, the Board approved a distribution of $0.17875 per outstanding Preferred Unit for the three months ended September 30, 2018. The Partnership will pay this distribution on November 14, 2018, to unitholders of record as of November 2, 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 October 23, 2018, the Board approved a cash distribution of $0.08 per outstanding common unit for the three months ended September 30, 2018. The Partnership will pay this distribution on November 14, 2018, to unitholders of record on November 2, 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 the three months ended September 30, 2017 and 2018, the Partnership recognized related-party revenues of $14.5 million and $11.1 million, respectively, for services provided to Ergon. For the nine months ended September 30, 2017 and 2018, the Partnership recognized related-party revenues of $41.3 million and $38.6 million, respectively, for services provided to Ergon. As of December 31, 2017, and September 30, 2018, the Partnership had receivables from Ergon of $3.1 million and $1.6 million, respectively, net of allowance for doubtful accounts. As of December 31, 2017, and September 30, 2018, the Partnership had unearned revenues from Ergon of $1.6 million and $3.6 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 nine months ended September 30, 2018, the Partnership made purchases of crude oil under this agreement totaling $44.4 million and $74.9 million, respectively. As of September 30, 2018, the Partnership had payables to Ergon related to this agreement of $16.7 million related to the September crude oil settlement cycle, and this balance was paid in full on October 19, 2018.

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 (as defined in the Agreement), which shall be computed by taking Ergon’s total

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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 September 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 nine months ended September 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
Grant Date	Number of Units	Weighted Average Grant Date Fair Value⁽¹⁾		(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
Grant Date	Number of Units	Weighted Average Grant Date Fair Value⁽¹⁾		(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
Grant Date	Number of Units	Weighted Average Grant Date Fair Value⁽¹⁾		(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 September 30, 2018, was $2.4 million, which will be expensed over the remaining vesting period.

The Partnership’s equity-based incentive compensation expense for the three months ended September 30, 2017 and 2018, was $0.6 million and $0.7 million, respectively. The Partnership’s equity-based incentive compensation expense for the nine months ended September 30, 2017 and 2018, was $1.7 million and $1.8 million, respectively.

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	271,760	7.24
Forfeited	106,521	5.43
Nonvested at September 30, 2018	1,003,254	$	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 September 30, 2017 and 2018, for discretionary contributions under the 401(k) Plan. The Partnership recognized expense of $0.9 million for each of the nine months ended September 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 September 30, 2017 and 2018, respectively, for discretionary profit sharing contributions under the 401(k) Plan. The Partnership recognized expense of $0.6 million and $0.1 million for the nine months ended September 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 months

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ended September 30, 2017 and 2018, in connection with the Unit Purchase Plan. The Partnership recognized compensation expense of $0.1 million and less than $0.1 million for the nine months ended September 30, 2017 and 2018, respectively, in connection with the Unit Purchase Plan.

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 nine months ended September 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 September 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	$	120	$	—	$	120	$	—
Total swap assets	$	120	$	—	$	120	$	—

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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 September 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 September 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 services, including storage, blending, processing and throughput services. On July 12, 2018, the Partnership sold three asphalt facilities. See Note 6 for additional information. The Partnership has 53 terminalling 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.

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The following table reflects certain financial data for each segment for the periods indicated (in thousands):



	Three Months ended September 30,				Nine Months ended September 30,
	2017		2018		2017		2018
Asphalt Terminalling Services
Service revenue:
Third-party revenue	$	17,690	$	6,921	$	44,172	$	18,693
Related-party revenue	14,464		5,211		41,301		17,512
Lease revenue:
Third-party revenue	—		11,288		—		30,762
Related-party revenue	—		5,406		—		20,584
Product sales revenue:
Related-party revenue	—		482		—		482
Total revenue for reportable segment	32,154		29,308		85,473		88,033
Operating expense, excluding depreciation and amortization	11,608		11,683		35,864		38,412
Operating margin, excluding depreciation and amortization	$	20,546	$	17,625	$	49,609	$	49,621
Total assets (end of period)	$	142,571	$	143,454	$	142,571	$	143,454

Crude Oil Terminalling Services
Service revenue:
Third-party revenue	$	5,162	$	1,923	$	17,013	$	9,418
Intersegment revenue	—		222		—		392
Lease revenue:
Third-party revenue	—		9		—		35
Total revenue for reportable segment	5,162		2,154		17,013		9,845
Operating expense, excluding depreciation and amortization	994		928		2,996		3,115
Operating margin, excluding depreciation and amortization	$	4,168	$	1,226	$	14,017	$	6,730
Total assets (end of period)	$	68,985	$	67,213	$	68,985	$	67,213

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	Three Months ended September 30,						Nine Months ended September 30,
	2017			2018			2017			2018
Crude Oil Pipeline Services
Service revenue:
Third-party revenue	$	2,196		$	1,165		$	7,520		$	4,270
Related-party revenue	—			185			310			268
Lease revenue:
Third-party revenue	—			40			—			452
Product sales revenue:
Third-party revenue	2,375			97,763			8,252			146,882
Total revenue for reportable segment	4,571			99,153			16,082			151,872
Operating expense, excluding depreciation and amortization	3,056			3,094			9,438			8,420
Intersegment operating expense	77			1,644			321			3,243
Third-party cost of product sales	1,675			50,815			6,482			73,493
Related-party cost of product sales	—			44,106			—			67,853
Intersegment cost of product sales	150			—			150			—
Operating margin, excluding depreciation and amortization	$	(387	)	$	(506	)	$	(309	)	$	(1,137	)
Total assets (end of period)	$	116,720		$	171,841		$	116,720		$	171,841

Crude Oil Trucking Services
Service revenue
Third-party revenue	$	5,587		$	2,734		$	18,738		$	11,783
Intersegment revenue	77			1,422			321			2,851
Lease revenue:
Third-party revenue	—			31			—			160
Product sales revenue:
Third-party revenue	—			—			385			10
Intersegment revenue	150			—			150			—
Total revenue for reportable segment	5,814			4,187			19,594			14,804
Operating expense, excluding depreciation and amortization	6,042			4,303			20,013			15,405
Operating margin, excluding depreciation and amortization	$	(228	)	$	(116	)	$	(419	)	$	(601	)
Total assets (end of period)	$	9,781		$	3,731		$	9,781		$	3,731

Total operating margin, excluding depreciation and amortization⁽¹⁾	$	24,099		$	18,229		$	62,898		$	54,613

Total Segment Revenues	$	47,701		$	134,802		$	138,162		$	264,554
Elimination of Intersegment Revenues	(227		)	(1,644		)	(471		)	(3,243		)
Consolidated Revenues	$	47,474		$	133,158		$	137,691		$	261,311

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____________________

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



	Three Months ended September 30,						Nine Months ended September 30,
	2017			2018			2017			2018
Operating margin, excluding depreciation and amortization	$	24,099		$	18,229		$	62,898		$	54,613
Depreciation and amortization	(7,680		)	(7,166		)	(23,586		)	(21,945		)
General and administrative expense	(4,093		)	(4,322		)	(13,000		)	(13,029		)
Asset impairment expense	—			(15		)	(45		)	(631		)
Gain (loss) on sale of assets	(107		)	(63		)	(986		)	300
Interest expense	(3,500		)	(4,090		)	(10,795		)	(12,683		)
Gain on sale of unconsolidated affiliate	1,112			—			5,284			2,225
Equity earnings in unconsolidated affiliate	—			—			61			—
Income before income taxes	$	9,831		$	2,573		$	19,831		$	8,850

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



Deferred Tax Asset
Difference in bases of property, plant and equipment	$	291
Net operating loss carryforwards	—
Deferred tax asset	291
Less: valuation allowance	291
Net deferred tax asset	$	—

The Partnership has considered the taxable income projections in future years, whether the carryforward period is so brief that it would limit realization of tax benefits, whether future revenue and operating cost projections will produce enough taxable income to realize the deferred tax asset based on existing service rates and cost structures, and the Partnership’s earnings history exclusive of the loss that created the future deductible amount for the Partnership’s subsidiary that is taxed as a corporation for purposes of determining the likelihood of realizing the benefits of the deferred tax assets. As a result of the Partnership’s consideration of these factors, the Partnership has provided a valuation allowance against its deferred tax asset as of September 30, 2018.

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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 nine months ended September 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 is a comprehensive update to the lease accounting topic in the Codification intended to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The amendments in ASU 2016-02 include a revised definition of a lease as well as certain scope exceptions. The changes primarily impact lessee accounting, while lessor accounting is largely unchanged from previous GAAP.

The Partnership is currently evaluating the impact of the pending adoption of ASC 842. The status of implementation is as follows:


•	Management has formed an implementation team that meets to discuss implementation challenges, technical interpretations, industry-specific treatment of certain contract types, and project status.


•	Management is in the process of gathering data and reviewing contracts in order to identify all impacted contracts.


•	Management is evaluating the potential information technology and internal control changes that will be required for adoption based on the findings from its contract review process.


•	Management plans to provide internal training and awareness related to the revised guidance to the key stakeholders throughout its organization.

The amendments in ASU 2016-02 are effective for public entities for annual reporting periods beginning after December 15, 2018, and for interim periods within that reporting period. Early application is permitted. The Partnership plans to adopt ASU 2016-02 on January 1, 2019 using the modified retrospective method. ASC 842 provides for a number of practical expedients. The Partnership intends to elect the following practical expedients upon adoption of ASC 842:


•	An entity need not reassess whether any expired or existing contracts are or contain leases.

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•	An entity need not reassess the lease classification for any expired or existing leases.


•	An entity need not reassess initial direct costs for any existing leases.


•	An entity may elect to not assess whether existing or expired land easements that were not previously accounted for as leases are or contain a lease under ASC 842.

While the Partnership is still in the process of quantifying the impact of adoption, it does not currently expect the adoption to have a material impact. The Partnership expects to recognize a right of use asset and lease liability at the implementation date, but cannot reasonably estimate the full impact of the standard at this time. Additionally, the Partnership is currently evaluating business processes, systems, and controls to ensure the accuracy and timeliness of the recognition and disclosure requirements under the new lease guidance.

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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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 October 25, 2018, the forward price curve is in a shallow contango. 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.

Our Wilmington, North Carolina, asphalt plant was affected by Hurricane Florence in September 2018. Damage to the plant was primarily limited to the loss of insulation on multiple storage tanks. While the impairment of these assets reflected in the three and nine months ended September 30, 2018, is minimal due to the low net book value of the assets, anticipated future-period costs to replace the insulation and clean up debris are currently estimated to be approximately $0.6 million, consisting of $0.5 million in maintenance capital expenditures and $0.1 million in maintenance expense. While we are pursuing insurance claims for this event, there can be no assurance of the amount or timing of any proceeds we may receive under such claims. The majority of revenues earned at the Wilmington facility are fixed fees; however, we anticipate a loss of throughput revenues as we were unable to deliver product out of the terminal for several weeks. In addition, our Bainbridge, Georgia, asphalt plant was affected by Hurricane Michael in October 2018. We are in the early stages of assessing the damages at this facility, and we anticipate the damages to be limited to loss of insulation on multiple storage tanks. We anticipate future-period costs to replace the insulation and clean up debris to be approximately $0.4 million, consisting of $0.3 million in maintenance capital expenditures and $0.1 million in maintenance expense.

On July 12, 2018, we sold 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.

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. As a result of the current shape of the curve and overall demand for Cushing storage, we anticipate a challenging 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. Between April 2016 and July 2018, we had 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 third 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.

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 nine months ended September 30, 2018, the Partnership recognized revenues of $38.6 million for services provided to Ergon, with the remainder of our services being provided to third parties.

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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) 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.

We have leases and terminalling agreements with customers for all of our 53 asphalt facilities, including 23 facilities under contract with Ergon. On July 12, 2018, we closed the sale of three of our asphalt facilities to Ergon (see Note 6 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 four 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 October 25, 2018, we had approximately 4.5 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. The intercompany contract expires on October 31, 2018, and a new agreement for 0.5 million barrels will be effective November 1, 2018. Of the third-party storage agreements, service contracts relating to 0.3 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.

The following is a summary of our average gathering and transportation volumes for the periods indicated (in thousands of barrels per day):



	Three Months ended September 30,		Nine Months ended September 30,		Favorable/(Unfavorable)
	Three Months ended September 30,		Nine Months ended September 30,		Three Months			Nine Months
	2017	2018	2017	2018	$	%		$	%
Average pipeline throughput volume	21	23	22	22	2	10	%	—	—	%
Average trucking transportation volume	20	29	21	26	9	45	%	5	24	%

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 57% and 27% of volumes transported in our pipelines in the three months ended September 30, 2017 and 2018, respectively. Vitol accounted for 57% and 37% of volumes transported in our pipelines in the nine months ended September 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. Vitol accounted for approximately 40% and 3% of volumes transported by our crude oil transport trucks in the three months ended September 30, 2017 and 2018, respectively. Vitol accounted for approximately 48% and 12% of volumes transported by our crude oil transport trucks in the nine months ended September 30, 2017 and 2018, respectively.

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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.

Our Expenses

Operating expenses decreased by 5% for the nine months ended September 30, 2018, as compared to the nine months ended September 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 relatively consistent for the nine months ended September 30, 2018, as compared to the nine months ended September 30, 2017. Our interest expense increased by $1.9 million for the nine months ended September 30, 2018, as compared to the nine months ended September 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 September 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 October 23, 2018, the Board approved a distribution of $0.17875 per outstanding Preferred Unit for the three months ended September 30, 2018. We will pay this distribution on November 14, 2018, to unitholders of record as of November 2,

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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 October 23, 2018, the Board approved a cash distribution of $0.08 per outstanding common unit for the three months ended September 30, 2018. We will pay this distribution November 14, 2018, to unitholders of record on November 2, 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.

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.

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



Operating Results	Three Months ended September 30,						Nine Months ended September 30,						Favorable/(Unfavorable)
Operating Results	Three Months ended September 30,						Nine Months ended September 30,						Three Months					Nine Months
(dollars in thousands)	2017			2018			2017			2018			$			%		$			%
Operating margin, excluding depreciation and amortization:
Asphalt terminalling services	$	20,546		$	17,625		$	49,609		$	49,621		$	(2,921	)	(14	)%	$	12		—	%
Crude oil terminalling services	4,168			1,226			14,017			6,730			(2,942		)	(71	)%	(7,287		)	(52	)%
Crude oil pipeline services	(387		)	(506		)	(309		)	(1,137		)	(119		)	(31	)%	(828		)	(268	)%
Crude oil trucking services	(228		)	(116		)	(419		)	(601		)	112			49	%	(182		)	(43	)%
Total operating margin, excluding depreciation and amortization	24,099			18,229			62,898			54,613			(5,870		)	(24	)%	(8,285		)	(13	)%

Depreciation and amortization	(7,680		)	(7,166		)	(23,586		)	(21,945		)	514			7	%	1,641			7	%
General and administrative expense	(4,093		)	(4,322		)	(13,000		)	(13,029		)	(229		)	(6	)%	(29		)	—	%
Asset impairment expense	—			(15		)	(45		)	(631		)	(15		)	N/A		(586		)	(1,302	)%
Gain (loss) on sale of assets	(107		)	(63		)	(986		)	300			44			41	%	1,286			130	%
Operating income	12,219			6,663			25,281			19,308			(5,556		)	(45	)%	(5,973		)	(24	)%

Other income (expenses):
Equity earnings in unconsolidated affiliate	—			—			61			—			N/A			N/A		(61		)	(100	)%
Gain on sale of unconsolidated affiliate	1,112			—			5,284			2,225			(1,112		)	(100	)%	(3,059		)	(58	)%
Interest expense	(3,500		)	(4,090		)	(10,795		)	(12,683		)	(590		)	(17	)%	(1,888		)	(17	)%
Provision for income taxes	(60		)	(165		)	(147		)	(215		)	(105		)	(175	)%	(68		)	(46	)%
Net income	$	9,771		$	2,408		$	19,684		$	8,635		$	(7,363	)	(75	)%	$	(11,049	)	(56	)%

For the three and nine months ended September 30, 2018, overall operating margin, excluding depreciation and amortization, decreased as compared to the same periods in 2017. Our asphalt terminalling services segment operating margin, excluding depreciation and amortization, was impacted by the sale of three asphalt terminals to Ergon in July 2018 and the acquisition of two asphalt facilities, one from Ergon in December 2017 and one from a third party in March 2018. 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. While our second Mid-Continent pipeline was placed back in service in July 2018, margins in our crude oil pipeline services segment continued to reflect the impact of suspended service since April 2016 due to the discovery of a pipeline exposure. Crude oil trucking services operating margin, excluding depreciation and amortization, improved for the three months ended September 30, 2018, due to an increase in volumes transported.

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

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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 September 30,				Nine Months ended September 30,				Favorable/(Unfavorable)
Operating results	Three Months ended September 30,				Nine Months ended September 30,				Three Months					Nine Months
(dollars in thousands)	2017		2018		2017		2018		$			%		$			%
Service revenue:
Third-party revenue	$	17,690	$	6,921	$	44,172	$	18,693	$	(10,769	)	(61	)%	$	(25,479	)	(58	)%
Related-party revenue	14,464		5,211		41,301		17,512		(9,253		)	(64	)%	(23,789		)	(58	)%
Lease revenue:
Third-party revenue	—		11,288		—		30,762		11,288			N/A		30,762			N/A
Related-party revenue	—		5,406		—		20,584		5,406			N/A		20,584			N/A
Product sales revenue:
Related-party revenue	—		482		—		482		482			N/A		482			N/A
Total revenue	32,154		29,308		85,473		88,033		(2,846		)	(9	)%	2,560			3	%
Operating expense, excluding depreciation and amortization	11,608		11,683		35,864		38,412		(75		)	(1	)%	(2,548		)	(7	)%
Operating margin, excluding depreciation and amortization	$	20,546	$	17,625	$	49,609	$	49,621	$	(2,921	)	(14	)%	$	12		—	%

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.

•

Total revenue decreased for the three months ended September 30, 2018, as compared to the three months ended September 30, 2017, primarily due to a change in the timing of the recognition of minimum throughput volume revenue as the result of the adoption of ASC 606. Certain contractually-guaranteed minimum throughput revenue that had previously been recognized in the third quarter of the year as minimum throughput levels were exceeded is now being recognized throughout the year on a straight-line basis as services are being provided. This resulted in a decrease of $1.6 million in minimum throughput revenues recognized in the three months ended September 30, 2018 as compared to the three months ended September 30, 2017.

•

In addition, total revenue increased for the nine months ended September 30, 2018, as compared to the nine months ended September 30, 2017. The two asphalt plants that were acquired in December 2017 and March 2018 resulted in an increase of $6.8 million in revenue and were partially offset by a decrease in revenues of $4.0 million due to the sale of three asphalt plants in July 2018 and lower product throughput volumes at some of our facilities.


•	Operating expenses increased for the three and nine months ended September 30, 2018, as compared to the three and nine months ended September 30, 2017, primarily as a result of the acquisitions noted above offset by the three facilities sold in July 2018. 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 September 30,				Nine Months ended September 30,				Favorable/(Unfavorable)
Operating results	Three Months ended September 30,				Nine Months ended September 30,				Three Months					Nine Months
(dollars in thousands)	2017		2018		2017		2018		$			%		$			%
Service revenue:
Third-party revenue	$	5,162	$	1,923	$	17,013	$	9,418	$	(3,239	)	(63	)%	$	(7,595	)	(45	)%
Intersegment revenue	—		222		—		392		222			N/A		392			N/A
Lease revenue:
Third-party revenue	—		9		—		35		9			N/A		35			N/A
Total revenue	5,162		2,154		17,013		9,845		(3,008		)	(58	)%	(7,168		)	(42	)%
Operating expense, excluding depreciation and amortization	994		928		2,996		3,115		66			7	%	(119		)	(4	)%
Operating margin, excluding depreciation and amortization	$	4,168	$	1,226	$	14,017	$	6,730	$	(2,942	)	(71	)%	$	(7,287	)	(52	)%

Average crude oil stored per month at our Cushing terminal (in thousands of barrels)	5,124		779		5,520		1,249		(4,345		)	(85	)%	(4,271		)	(77	)%
Average crude oil delivered to our Cushing terminal (in thousands of barrels per day)	27		32		40		50		5			19	%	10			25	%

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

•

Total revenues for three and nine months ended September 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 a 0.7-million-barrel storage contract expired on October 31, 2017. The expired contracts were not renewed or replaced as of September 30, 2018.

•

As of October 25, 2018, we had approximately 4.5 million barrels of crude oil storage under service contracts, including an intercompany contract for 0.3 million barrels and a third-party contract for 2.0 million barrels that commences November 1, 2018, out of our total storage capacity of 6.6 million barrels. The intercompany contract expires on October 31, 2018, and a new agreement for 0.5 million barrels will be effective November 1, 2018. Of the third-party storage agreements, service contracts relating to 0.3 million barrels expire in 2018.


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

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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 September 30,						Nine Months ended September 30,						Favorable/(Unfavorable)
Operating results	Three Months ended September 30,						Nine Months ended September 30,						Three Months					Nine Months
(dollars in thousands)	2017			2018			2017			2018			$			%		$			%
Service revenue:
Third-party revenue	$	2,196		$	1,165		$	7,520		$	4,270		$	(1,031	)	(47	)%	$	(3,250	)	(43	)%
Related-party revenue	—			185			310			268			185			N/A		(42		)	(14	)%
Lease revenue:
Third-party revenue	—			40			—			452			40			N/A		452			N/A
Product sales revenue:
Third-party revenue	2,375			97,763			8,252			146,882			95,388			4,016	%	138,630			1,680	%
Total revenue	4,571			99,153			16,082			151,872			94,582			2,069	%	135,790			844	%
Operating expense, excluding depreciation and amortization	3,056			3,094			9,438			8,420			(38		)	(1	)%	1,018			11	%
Intersegment operating expense	77			1,644			321			3,243			(1,567		)	(2,035	)%	(2,922		)	(910	)%
Third-party cost of product sales	1,675			50,815			6,482			73,493			(49,140		)	(2,934	)%	(67,011		)	(1,034	)%
Related-party cost of product sales	—			44,106			—			67,853			(44,106		)	N/A		(67,853		)	N/A
Intersegment cost of product sales	150			—			150			—			150			100	%	150			100	%
Operating margin, excluding depreciation and amortization	$	(387	)	$	(506	)	$	(309	)	$	(1,137	)	$	(119	)	(31	)%	$	(828	)	(268	)%

Average throughput volume (in thousands of barrels per day)	21			23			22			22			2			10	%	—			—	%

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 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.

•

Service revenues for the three and nine months ended September 30, 2018, decreased as compared to the three and nine months ended September 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 nine months ended September 30, 2018, approximately 56% and 34%, respectively, of the total volume transported on our Mid-Continent system was comprised of barrels that we

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are purchasing from producers in the field and transporting to our Cushing terminal to support our crude oil marketing operations.

•

Product sales revenues and cost of product sales for the three and nine months ended September 30, 2018, increased as compared to the three and nine months ended September 30, 2017, as a result of supplementing 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 increased our balance of the total linefill requirements of the pipeline system which resulted in the total volume of crude oil we purchased exceeding the volume of crude oil we sold during the three and nine months ended September 30, 2018. We reached our linefill requirements during the three months ended September 30, 2018, and expect our operating margin in this segment to increase in future periods.


•	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 nine months ended September 30, 2018, as compared to the nine months ended September 30, 2017.

•

Operating expenses decreased for the nine months ended September 30, 2018, as compared to the nine months ended September 30, 2017, by $0.6 million as a result of the sale of the East Texas pipeline system, by $0.2 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 three and nine months ended September 30, 2018, as compared to the three and nine months ended September 30, 2017, increased by $1.6 million and $2.9 million, respectively, 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 as well as our crude oil marketing operations’ utilization of crude oil blending services provided by our crude oil terminalling services segment.

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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:



Operating results	Three Months ended September 30,						Nine Months ended September 30,						Favorable/(Unfavorable)
Operating results	Three Months ended September 30,						Nine Months ended September 30,						Three Months					Nine Months
(dollars in thousands)	2017			2018			2017			2018			$			%		$			%
Service revenue
Third-party revenue	$	5,587		$	2,734		$	18,738		$	11,783		$	(2,853	)	(51	)%	$	(6,955	)	(37	)%
Intersegment revenue	77			1,422			321			2,851			1,345			1,747	%	2,530			788	%
Lease revenue:
Third-party revenue	—			31			—			160			31			N/A		160			N/A
Product sales revenue:
Third-party revenue	—			—			385			10			—			N/A		(375		)	(97	)%
Intersegment revenue	150			—			150			—			(150		)	(100	)%	(150		)	(100	)%
Total revenue	5,814			4,187			19,594			14,804			(1,627		)	(28	)%	(4,790		)	(24	)%
Operating expense, excluding depreciation and amortization	6,042			4,303			20,013			15,405			1,739			29	%	4,608			23	%
Operating margin, excluding depreciation and amortization	$	(228	)	$	(116	)	$	(419	)	$	(601	)	$	112		49	%	$	(182	)	(43	)%

Average volume (in thousands of barrels per day)	20			29			21			26			9			45	%	5			24	%

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

•

Service revenues decreased for the three and nine months ended September 30, 2018, as compared to the three and nine months ended September 30, 2017, by $2.0 million and $4.3 million, respectively, due to the sale of the producer field services business. Additionally, 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.


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

•

Operating expense, excluding depreciation and amortization, decreased for the three and nine months ended September 30, 2018, as compared to the three and nine months ended September 30, 2017, by $2.2 million and $4.2 million, respectively, due to the sale of our producer field services business. Additional reductions in employment and vehicle-related expenses resulted from a decrease in our crude oil trucking services fleet size during the comparative periods.

Other Income and Expenses

Depreciation and amortization expense. Depreciation and amortization expense decreased by $0.5 million to $7.2 million for the three months ended September 30, 2018, compared to $7.7 million for the three months ended September 30, 2017. Depreciation and amortization expense decreased by $1.6 million to $21.9 million for the nine months ended September 30, 2018, compared to $23.6 million for the nine months ended September 30, 2017. These decreases are primarily the result of

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certain assets reaching the end of their depreciable lives. Decreases in depreciation and amortization expense due to the sale of the producer field services business in April 2018 and the three asphalt facilities in July 2018 were offset by additional depreciation and amortization expense related to the two asphalt facilities acquired in December 2017 and March 2018.

General and administrative expenses. General and administrative expenses, inclusive of $0.6 million of fees related to the sale of three asphalt facilities to Ergon in July 2018, increased to $4.3 million for the three months ended September 30, 2018, compared to $4.1 million for the three months ended September 30, 2017. General and administrative expenses for the three months ended September 30, 2018, were impacted by $0.9 million in insurance premium payments being made to a fraudulent bank account as a result of a business e-mail compromise attack. While we are pursuing recovery of these funds, there can be no assurance of a successful recovery. General and administrative expenses were consistent at $13.0 million for the both the nine months ended September 30, 2018 and 2017. Decreases in compensation and travel expenses were offset by $0.6 million of fees related to the sale of three asphalt facilities to Ergon in July 2018.

Asset impairment expense. Asset impairment expense was $0.6 million and less than $0.1 million for the nine months ended September 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.

Gain (loss) on sale of assets. Gain on sale of assets was $0.3 million for the nine months ended September 30, 2018, compared to a loss of $1.0 million for the nine months ended September 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 nine months ended September 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 three months ended March 31, 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 September 30, 2018, increased by $0.6 million compared to the three months ended September 30, 2017. Total interest expense for the nine months ended September 30, 2018, increased by $1.9 million compared to the nine months ended September 30, 2017. The following table presents the significant components of interest expense:



	Three Months ended September 30,						Nine Months ended September 30,						Favorable/(Unfavorable)
	Three Months ended September 30,						Nine Months ended September 30,						Three Months					Nine Months
	2017			2018			2017			2018			$			%		$			%
Credit agreement interest	$	3,256		$	3,815		$	9,388		$	11,856		$	(559	)	(17	)%	$	(2,468	)	(26	)%
Amortization of debt issuance costs	251			251			865			764			—			—		101			12	%
Write-off of debt issuance costs	—			—			693			437			—			—	%	256			37	%
Interest rate swaps interest expense (income)	257			(25		)	1,085			(49		)	282			110	%	1,134			105	%
Loss (gain) on interest rate swaps mark-to-market	(278		)	36			(1,252		)	(276		)	(314		)	113	%	(976		)	78	%
Other	14			13			16			(49		)	1			7	%	65			406	%
Total interest expense	$	3,500		$	4,090		$	10,795		$	12,683		$	(590	)	(17	)%	$	(1,888	)	(17	)%

Effects of Inflation

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

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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 nine months ended September 30, 2017 and 2018:



	Nine Months ended September 30,
	2017			2018
	(in millions)
Net cash provided by operating activities	$	46.2		$	28.2
Net cash provided by investing activities	$	22.3		$	44.0
Net cash used in financing activities	$	(69.2	)	$	(72.7	)

Operating Activities. Net cash provided by operating activities decreased to $28.2 million for the nine months ended September 30, 2018, as compared to $46.2 million for the nine months ended September 30, 2017, due to decreased net income as discussed in Results of Operations above as well as changes in working capital.

Investing Activities. Net cash provided by investing activities was $44.0 million for the nine months ended September 30, 2018, as compared to $22.3 million for the nine months ended September 30, 2017. The nine months ended September 30, 2018, included proceeds from the sale of three asphalt terminals of $88.5 million. The nine months ended September 30, 2017, included proceeds from the sale of an unconsolidated affiliate of $26.4 million. On March 7, 2018, we acquired an asphalt terminalling facility from a third party for $22.0 million. Capital expenditures for the nine months ended September 30, 2018 and 2017, included maintenance capital expenditures of $6.0 million and $6.6 million, respectively, and expansion capital expenditures of $23.6 million and $6.7 million, respectively.

Financing Activities. Net cash used in financing activities was $72.7 million for the nine months ended September 30, 2018, as compared to $69.2 million for the nine months ended September 30, 2017. Cash used in financing activities for the nine months ended September 30, 2018, consisted primarily of net payments on long-term debt of $36.0 million and $35.0 million in distributions to our unitholders. Net cash used in financing activities for the nine months ended September 30, 2017, consisted primarily of net payments on long-term debt of $26.4 million and $36.9 million in distributions to our unitholders.

Our Liquidity and Capital Resources

Cash flows from operations and from our credit agreement are our primary sources of liquidity. At September 30, 2018, we had working capital of $5.3 million.

At September 30, 2018, we had approximately $125.2 million of availability under our credit agreement. 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 6 to our unaudited condensed consolidated financial statements). As of October 25, 2018, we have aggregate unused commitments under our revolving credit facility of approximately $138.2 million and cash on hand of approximately $1.0 million. The credit agreement is scheduled to mature on May 11, 2022.

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.

Expansion capital expenditures for organic growth projects, net of reimbursable expenditures of $0.3 million, totaled $23.3 million in the nine months ended September 30, 2018, compared to $6.2 million in the nine months ended September 30, 2017. Expansion capital expenditures for the nine months ended September 30, 2018, included $13.1 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 $24.0 million to $25.0 million, inclusive of crude oil purchases for Cushing terminal and pipeline linefill and net of reimbursable expenditures, for all of 2018. Maintenance capital expenditures totaled $5.4 million, net of reimbursable expenditures of $0.6 million, in the nine months ended September 30,

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2018, compared to $6.1 million in the nine months ended September 30, 2017. We currently expect maintenance capital expenditures to be approximately $8.0 million to $9.0 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 October 25, 2018, we had $257.6 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 September 30, 2018, consists of a current asset of $0.1 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 nine months ended September 30, 2018, the weighted average interest rate under our credit agreement was 5.33%.

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 September 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 $1.7 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 September 30, 2018, were effective.

Changes in internal control over financial reporting. There were no changes to our internal control over financial reporting that occurred during the three months ended September 30, 2018, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

As discussed in the 2017 Form 10-K, management identified a material weakness in internal control over financial reporting related to the presentation of transactions within the consolidated statement of cash flows. Management implemented a remediation plan in the first quarter of 2018 to provide additional training of financial 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. The remediation and ultimate resolution was reviewed by the Audit

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Committee of the Board. As a result of this change, management has concluded that the previously reported material weakness no longer exists as of September 30, 2018.

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.

In addition to the information set forth in this quarterly report, you should carefully consider the risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2017. The risks described in our Annual Report on Form 10-K for the year ended December 31, 2017 and in this quarterly report are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

The threat and impact of cyberattacks may adversely impact our operations and could result in information theft, data corruption, operational disruption, and/or financial loss.

We depend on digital technology, including information systems and related infrastructure, as well as, cloud applications and services, to store, transmit, process and record sensitive information (including trade secrets, employee information and financial and operating data), communicate with our employees and business partners and for many other activities related to our business. Our business processes depend on the availability, capacity, reliability and security of our information technology infrastructure and our ability to expand and continually update this infrastructure in response to our changing needs and, therefore, it is critical to our business that our facilities and infrastructure remain secure. While we have implemented strategies to mitigate impacts from these types of events, we cannot guarantee that measures taken to defend against cybersecurity threats will be sufficient for this purpose. The ability of the information technology function to support our business in the event of a security breach or a disaster such as fire or flood and our ability to recover key systems and information from unexpected interruptions cannot be fully tested, and there is a risk that, if such an event actually occurs, we may not be able to address immediately the repercussions of the breach or disaster. In that event, key information and systems may be unavailable for a number of days or weeks, leading to our inability to conduct business or perform some business processes in a timely manner. Moreover, if any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial condition or results of operations.

Our employees have been and will continue to be targeted by parties using fraudulent “spoof” and “phishing” emails to misappropriate information or to introduce viruses or other malware through “trojan horse” programs to our computers. These emails appear to be legitimate emails but direct recipients to fake websites operated by the sender of the email or request that the recipient send a password or other confidential information through email or download malware. “Spoof” and “phishing” activities are a serious risk that may damage our information technology infrastructure.

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:	November 1, 2018	By:	/s/ James R. Griffin
			James R. Griffin
			Chief Accounting Officer and Authorized Signatory

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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 the Partnership, 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		First Amendment to the Storage, Throughput and Handling Agreement, dated July 12, 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 10.1 to the Partnership’s Current Report on Form 8-K, filed July 13, 2018, and incorporated herein by reference).
10.2		Amended and Restated Omnibus Agreement, dated July 12, 2018, by and between Ergon Asphalt & Emulsions, Inc., Blueknight Energy Partners G.P., L.L.C., Blueknight Energy Partners, L.P., Blueknight Terminalling, L.L.C., BKEP Materials, L.L.C. and BKEP Asphalt, L.L.C. (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, filed July 13, 2018, and incorporated herein by reference).
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 September 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 September 30, 2018; (iii) Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2017 and 2018; (iv) Unaudited Condensed Consolidated Statement of Changes in Partners’ Capital (Deficit) for the nine months ended September 30, 2018; (v) Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2017 and 2018; and (vi) Notes to Unaudited Condensed Consolidated Financial Statements.

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# Furnished herewith