UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2019

OR

☐ 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.)
6060 American Plaza, Suite 600 Tulsa, Oklahoma 74135 (Address of principal executive offices, zip code) Registrant’s telephone number, including area code: (918) 237-4000

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    ☒    No   ☐

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   ☒   No   ☐

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 ☐	Accelerated filer ☒
Non-accelerated filer ☐	Smaller reporting company ☐
	Emerging growth company ☐

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. ☐

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

Securities registered pursuant to Section 12(b) of the Exchange Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Units	BKEP	The Nasdaq Global Market
Series A Preferred Units	BKEPP	The Nasdaq Global Market

 As of November 1, 2019, there were 35,125,202 Series A Preferred Units and 40,813,488 common units outstanding.  
 

Table of Contents

		Page
PART I	FINANCIAL INFORMATION	1
Item 1.	Unaudited Condensed Consolidated Financial Statements	1
	Condensed Consolidated Balance Sheets as of December 31, 2018, and September 30, 2019	1
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2018 and 2019	2
	Condensed Consolidated Statements of Changes in Partners’ Capital (Deficit) for the Three and Nine Months Ended September 30, 2018 and 2019	3
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2018 and 2019	4
	Notes to the Unaudited Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	33
Item 4.	Controls and Procedures	33
PART II	OTHER INFORMATION	34
Item 1.	Legal Proceedings	34
Item 1A.	Risk Factors	34
Item 6.	Exhibits	34

i

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, 2018			September 30, 2019
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	1,455		$	2,777
Accounts receivable, net		35,683			25,913
Receivables from related parties, net		1,043			1,873
Other current assets		9,345			7,774
Total current assets		47,526			38,337
Property, plant and equipment, net of accumulated depreciation of $263,554 and $278,768 at December 31, 2018, and September 30, 2019, respectively		248,261			238,818
Goodwill		6,728			6,728
Debt issuance costs, net		3,349			2,595
Operating lease assets		-			11,374
Intangible assets, net		16,834			14,775
Other noncurrent assets		606			1,348
Total assets	$	323,304		$	313,975
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	3,707		$	4,036
Accounts payable to related parties		2,263			3,306
Accrued crude oil purchases		13,949			6,465
Accrued crude oil purchases to related parties		10,219			11,438
Accrued interest payable		465			289
Accrued property taxes payable		3,089			3,701
Unearned revenue		3,206			5,476
Unearned revenue with related parties		4,835			2,624
Accrued payroll		3,667			3,836
Current operating lease liability		-			2,479
Other current liabilities		3,465			3,352
Total current liabilities		48,865			47,002
Long-term unearned revenue with related parties		1,714			1,545
Other long-term liabilities		4,010			3,708
Noncurrent operating lease liability		-			8,968
Contingent liability with related party (Note 9)		10,019			12,061
Long-term debt		265,592			258,592
Commitments and contingencies (Note 15)
Partners’ capital:
Common unitholders (40,424,372 and 40,813,488 units issued and outstanding at December 31, 2018, and September 30, 2019, respectively)		370,972			360,144
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)		(631,791	)		(631,968	)
Total partners’ deficit		(6,896	)		(17,901	)
Total liabilities and partners’ deficit	$	323,304		$	313,975

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

1

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,
	2018			2019			2018			2019
	(unaudited)
Service revenue:
Third-party revenue	$	12,743		$	15,716		$	44,164		$	47,329
Related-party revenue		5,396			3,956			17,780			12,257
Lease revenue:
Third-party revenue		11,368			11,444			31,409			31,026
Related-party revenue		5,406			5,427			20,584			15,179
Product sales revenue:
Third-party revenue		97,763			55,213			146,892			173,773
Related-party revenue		482			-			482			-
Total revenue		133,158			91,756			261,311			279,564
Costs and expenses:
Operating expense		27,174			25,168			87,297			78,326
Cost of product sales		50,815			18,972			73,493			64,069
Cost of product sales from related party		44,106			32,691			67,853			99,886
General and administrative expense		4,322			3,840			13,029			10,495
Asset impairment expense		15			83			631			2,316
Total costs and expenses		126,432			80,754			242,303			255,092
Gain (loss) on sale of assets		(63	)		(40	)		300			1,765
Operating income		6,663			10,962			19,308			26,237
Other income (expenses):
Other income		-			-			-			268
Gain on sale of unconsolidated affiliate		-			-			2,225			-
Interest expense		(4,090	)		(3,989	)		(12,683	)		(12,394	)
Income before income taxes		2,573			6,973			8,850			14,111
Provision for income taxes		165			14			215			39
Net income	$	2,408		$	6,959		$	8,635		$	14,072
Allocation of net income for calculation of earnings per unit:
General partner interest in net income	$	39		$	110		$	298		$	268
Preferred interest in net income	$	6,279		$	6,278		$	18,836		$	18,836
Net income (loss) available to limited partners	$	(3,910	)	$	571		$	(10,499	)	$	(5,032	)
Basic and diluted net income (loss) per common unit	$	(0.09	)	$	0.01		$	(0.25	)	$	(0.12	)
Weighted average common units outstanding - basic and diluted		40,380			40,811			40,331			40,735

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

2

BLUEKNIGHT ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL (DEFICIT)

(in thousands)

	Common Unitholders			Series A Preferred Unitholders			General Partner Interest			Total Partners’ Capital (Deficit)
	(unaudited)
Balance, June 30, 2018	$	436,416		$	253,923		$	(703,704	)	$	(13,365	)
Net income (loss)		(3,910	)		6,279			39			2,408
Equity-based incentive compensation		656			-			9			665
Distributions		(3,319	)		(6,279	)		(156	)		(9,754	)
Capital contributions related to sale of terminal assets to Ergon		-			-			72,967			72,967
Proceeds from sale of 40,081 common units pursuant to the Employee Unit Purchase Plan		116			-			-			116
Balance, September 30, 2018	$	429,959		$	253,923		$	(630,845	)	$	53,037
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
Balance, June 30, 2019	$	360,861		$	253,923		$	(631,952	)	$	(17,168	)
Net income (loss)		574			6,278			107			6,959
Equity-based incentive compensation		284			-			5			289
Distributions		(1,678	)		(6,278	)		(128	)		(8,084	)
Proceeds from sale of 98,631 common units pursuant to the Employee Unit Purchase Plan		103			-			-			103
Balance, September 30, 2019	$	360,144		$	253,923		$	(631,968	)	$	(17,901	)
Balance, December 31, 2018	$	370,972		$	253,923		$	(631,791	)	$	(6,896	)
Net income (loss)		(4,983	)		18,836			219			14,072
Equity-based incentive compensation		637			-			15			652
Distributions		(6,658	)		(18,836	)		(411	)		(25,905	)
Proceeds from sale of 161,971 common units pursuant to the Employee Unit Purchase Plan		176			-			-			176
Balance, September 30, 2019	$	360,144		$	253,923		$	(631,968	)	$	(17,901	)

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

3

BLUEKNIGHT ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Nine Months ended September 30,
	2018			2019
	(unaudited)
Cash flows from operating activities:
Net income	$	8,635		$	14,072
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		21,945			19,211
Amortization of debt issuance costs		1,200			754
Unrealized (gain) loss related to interest rate swaps		(277	)		44
Intangible asset impairment charge		189			-
Fixed asset impairment charge		442			2,316
Gain on sale of assets		(300	)		(1,765	)
Gain on sale of unconsolidated affiliate		(2,225	)		-
Equity-based incentive compensation		1,352			652
Changes in assets and liabilities:
Decrease (increase) in accounts receivable		(39,328	)		7,128
Decrease (increase) in receivables from related parties		1,423			(830	)
Decrease in other current assets		868			3,571
Decrease in other non-current assets		424			2,255
Decrease in accounts payable		(435	)		(250	)
Increase in payables to related parties		1,068			535
Increase (decrease) in accrued crude oil purchases		15,142			(7,484	)
Increase in accrued crude oil purchases to related parties		16,681			1,219
Decrease in accrued interest payable		(232	)		(176	)
Increase in accrued property taxes		1,718			612
Increase in unearned revenue		853			1,557
Increase (decrease) in unearned revenue from related parties		2,829			(2,380	)
Increase (decrease) in accrued payroll		(2,281	)		169
Decrease in other accrued liabilities		(1,504	)		(2,926	)
Net cash provided by operating activities		28,187			38,284
Cash flows from investing activities:
Acquisitions		(21,959	)		-
Capital expenditures		(29,560	)		(9,428	)
Proceeds from sale of assets		4,707			7,089
Proceeds from sale of terminal assets to Ergon		88,538			-
Proceeds from sale of unconsolidated affiliate		2,225			-
Net cash provided by (used in) investing activities		43,951			(2,339	)
Cash flows from financing activities:
Payments on other financing activities		(1,722	)		(1,894	)
Debt issuance costs		(358	)		-
Borrowings under credit agreement		216,000			218,000
Payments under credit agreement		(252,000	)		(225,000	)
Proceeds from equity issuance		208			176
Capital contributions		183			-
Distributions		(34,992	)		(25,905	)
Net cash used in financing activities		(72,681	)		(34,623	)
Net increase (decrease) in cash and cash equivalents		(543	)		1,322
Cash and cash equivalents at beginning of period		2,469			1,455
Cash and cash equivalents at end of period	$	1,926		$	2,777
Supplemental disclosure of non-cash financing and investing cash flow information:
Non-cash changes in property, plant and equipment	$	(908	)	$	1,528
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	$	2,225		$	2,356

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

4

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. 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, 2019, the condensed consolidated statements of operations for the three and nine months ended September 30, 2018 and 2019, the condensed consolidated statements of changes in partners’ capital (deficit) for the three and nine months ended September 30, 2018 and 2019, and the condensed consolidated statements of cash flows for the nine months ended September 30, 2018 and 2019, 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 2018 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, 2018, filed with the Securities and Exchange Commission (the “SEC”) on March 12, 2019 (the “2018 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 2018 Form 10-K except for new accounting standards adopted in 2019 as discussed Note 3 and Note 13.

Certain reclassifications have been made in the consolidated balance sheet as of December 31, 2018, and the consolidated statement of cash flows for the nine months ended September 30, 2018, to conform to the 2019 financial statement presentation. These reclassifications relate to items included in “Other current assets” and “Other noncurrent assets.” Reclassifications on the consolidated statement of cash flows were limited to the “Cash flows from operating activities” section. The reclassifications have no impact on net income.

3. REVENUE

On January 1, 2019, the Partnership adopted ASU 2016-02, which created the new accounting standard ASC Topic 842 - Leases (“ASC 842”), using the modified retrospective method. Results for reporting periods beginning on January 1, 2019, are presented under ASC 842, while prior period amounts are not adjusted and continue to be reported in accordance with the Partnership’s historic accounting under ASC Topic 840 - Leases. The adoption of ASC 842 did not have a material effect on the Partnership’s revenue recognition. The primary impact is a change to the recognition of variable consideration that has both a service and lease component. Previously, the variable consideration related to the service component was estimated at the beginning of the contract year and recognized on a straight-line basis over the year. Under ASC 842, the variable consideration related to the service component is treated as a change in estimate in the period when the facts and circumstances on which the variable payment is based occur.

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 842. The storage, throughput and handling contracts contain both lease revenue and non-lease service revenue. In accordance with ASC 842 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, and revenue is recognized on a straight-line basis over time as the customer receives and consumes benefits. The lease component is recognized on a straight-line basis over the term of the initial lease. 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 until the service is performed, and the service component is treated as a contract liability.

5

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. In accordance with ASC 842, 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. Additionally, under ASC 842, when variable consideration contains both a lease and non-lease service component, the service component cannot be recognized until the period in which the changes in facts and circumstances on which the variable payment is based occur. At that time, it can be recognized in accordance with ASC 606. The service component of variable throughput fees is treated as a change in estimate in the period in when the changes in facts and circumstances on which the variable payment is based occur and is then recognized on a straight-line basis over time as the customer receives and consumes benefits. Payment on variable throughput consideration is due within 30 days of billing.

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.

The following table includes revenue associated with contractual commitments in place related to future performance obligations as of the end of the reporting period, which are expected to be recognized in revenue in the specified periods (in thousands):

	Revenue from Contracts with Customers(1)		Revenue from Leases
Remainder of 2019	$	7,756	$	14,012
2020		30,602		53,487
2021		27,253		49,244
2022		19,937		38,545
2023		14,533		29,609
Thereafter		9,142		22,342
Total revenue related to future performance obligations	$	109,223	$	207,239

____________________

(1) Excluded from the table is revenue that is either constrained or related to performance obligations that are wholly unsatisfied as of September 30, 2019.

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. Customers are 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.

6

Disaggregation of Revenue

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

	Asphalt Terminalling Services		Crude Oil Terminalling Services		Crude Oil Pipeline Services		Crude Oil Trucking Services		Total
	Three Months ended September 30, 2018
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
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

	Three Months ended September 30, 2019
Third-party revenue:
Fixed storage, throughput and other revenue	$	5,138	$	3,509	$	-	$	-	$	8,647
Variable throughput revenue		518		716		-		-		1,234
Variable reimbursement revenue		1,729		-		-		-		1,729
Crude oil transportation revenue		-		-		1,284		2,822		4,106
Crude oil product sales revenue		-		-		55,213		-		55,213
Related-party revenue:
Fixed storage, throughput and other revenue		2,794		-		63		-		2,857
Variable reimbursement revenue		1,098		-		1		-		1,099
Total revenue from contracts with customers	$	11,277	$	4,225	$	56,561	$	2,822	$	74,885

	Nine Months ended September 30, 2019
Third-party revenue:
Fixed storage, throughput and other revenue	$	15,174	$	9,956	$	-	$	-	$	25,130
Variable throughput revenue		554		1,863		-		-		2,417
Variable reimbursement revenue		5,489		-		-		-		5,489
Crude oil transportation revenue		-		-		5,753		8,540		14,293
Crude oil product sales revenue		-		-		173,773		-		173,773
Related-party revenue:
Fixed storage, throughput and other revenue		8,500		-		229		-		8,729
Variable reimbursement revenue		3,491		-		37		-		3,528
Total revenue from contracts with customers	$	33,208	$	11,819	$	179,792	$	8,540	$	233,359

7

Contract Balances

The timing of revenue recognition, billings and cash collections result in billed accounts receivable and unearned revenue (contract liabilities) on the unaudited condensed consolidated balance sheets as noted in the contract discussions above. Accounts receivable are reflected in the line items “Accounts receivable” and “Receivables from related parties” on the unaudited condensed consolidated balance sheets. 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 sheets.

Billed accounts receivable from contracts with customers were $34.6 million and $24.6 million at December 31, 2018, and September 30, 2019, respectively.

The Partnership records unearned revenues when cash payments are received in advance of performance. Unearned revenue related to contracts with customers was $5.9 million and $5.7 million at December 31, 2018, and September 30, 2019, respectively. The change in the unearned revenue balance for the nine months ended September 30, 2019, is driven by $3.2 million in cash payments received in advance of satisfying performance obligations, partially offset by $3.4 million of revenues recognized that were included in the unearned revenue balance at the beginning of the period.

Practical Expedients and Exemptions

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

4. EQUITY METHOD INVESTMENT

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 Advantage Pipeline. 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). As of September 30, 2019, the Partnership had no equity investments.

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5. PROPERTY, PLANT AND EQUIPMENT

	Estimated Useful	December 31,			September 30,
	Lives (Years)	2018			2019
		(dollars in thousands)
Land	N/A	$	24,705		$	24,705
Land improvements	10-20		5,758			5,804
Pipelines and facilities	5-30		116,155			118,449
Storage and terminal facilities	10-35		321,096			326,738
Transportation equipment	3-10		2,798			3,140
Office property and equipment and other	3-20		26,980			27,415
Pipeline linefill and tank bottoms	N/A		10,297			8,258
Construction-in-progress	N/A		4,026			3,077
Property, plant and equipment, gross			511,815			517,586
Accumulated depreciation			(263,554	)		(278,768	)
Property, plant and equipment, net		$	248,261		$	238,818

Property, plant and equipment under operating leases at September 30, 2019, in which the Partnership is the lessor, had a cost basis of $285.3 million and accumulated depreciation of $178.6 million.

Depreciation expense for the three months ended September 30, 2018 and 2019, was $6.5 million and $5.5 million, respectively. Depreciation expense for the nine months ended September 30, 2018 and 2019, was $20.2 million and $16.9 million, respectively.

During the nine months ended September 30, 2019, the Partnership recognized asset impairment expense of $2.3 million. A change in estimate of the push-down impairment related to Cimarron Express Pipeline, LLC (“Cimarron Express”) resulted in additional impairment expense of $2.0 million. This impairment is recorded at the corporate level and the estimate is based on the expected amount due to Ergon, Inc. (“Ergon”) if the Put (as defined in Note 9) is exercised (see Note 9 for more information). In addition, flooding at several asphalt plants in the Midwest led to an impairment of $0.3 million.

During the nine months ended September 30, 2019, the Partnership sold various surplus assets, including the sale of three truck stations for $1.6 million, which resulted in a gain of $1.5 million, and the sale of pipeline linefill for $1.6 million, which resulted in a gain of $0.3 million. In addition, proceeds received during the nine months ended September 30, 2019, included $2.6 million related to a sale of pipeline linefill in December 2018 for which the proceeds were received in January 2019.

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 from the sale 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. The Partnership used the proceeds from the sale to prepay revolving debt under its credit agreement.

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.

9

6. 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 November 1, 2019, approximately $250.6 million of revolver borrowings and $1.0 million of letters of credit were outstanding under the credit agreement, leaving the Partnership with approximately $148.4 million available capacity for additional revolver borrowings and letters of credit under the credit agreement, although the Partnership’s ability to borrow such funds may be limited by the financial covenants in the credit agreement.  The proceeds of loans made under the credit agreement may be used for working capital and other general corporate purposes of the Partnership.

The credit agreement is guaranteed by all of the Partnership’s existing subsidiaries. Obligations under the credit agreement are secured by first priority liens on substantially all of the Partnership’s assets and those of the guarantors.

The credit agreement includes procedures for additional financial institutions to become revolving lenders, or for any existing lender to increase its revolving commitment thereunder, subject to an aggregate maximum of $600.0 million for all revolving loan commitments under the credit agreement.

The credit agreement will mature on May 11, 2022, and all amounts outstanding under the credit agreement will become due and payable on such date. The credit agreement requires mandatory prepayments of amounts outstanding thereunder with the net proceeds of certain asset sales, property or casualty insurance claims and condemnation proceedings, unless the Partnership reinvests such proceeds in accordance with the credit agreement, but these mandatory prepayments will not require any reduction of the lenders’ commitments under the credit agreement.

Borrowings under the credit agreement bear interest, at the Partnership’s option, at either the reserve-adjusted eurodollar rate (as defined in the credit agreement) plus an applicable margin that ranges from 2.0% to 3.25% 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 2.25%.  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 will be 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; provided that the maximum permitted consolidated total leverage ratio may be increased to 5.25 to 1.00 for certain quarters after December 31, 2019, 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).

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 (“credit agreement EBITDA”) to consolidated interest expense) is 2.50 to 1.00.

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In addition, the credit agreement contains various covenants that, among other restrictions, limit the Partnership’s ability to:

• create, issue, incur or assume indebtedness;

• create, incur or assume liens;

• engage in mergers or acquisitions;

• sell, transfer, assign or convey assets;

• repurchase the Partnership’s equity, make distributions to unitholders and make certain other restricted payments;

• make investments;

• modify the terms of certain indebtedness, or prepay certain indebtedness;

• engage in transactions with affiliates;

• enter into certain hedging contracts;

• enter into certain burdensome agreements;

• change the nature of the Partnership’s business; and

• make certain amendments to the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership (the “Partnership’s partnership agreement”).

At September 30, 2019, the Partnership’s consolidated total leverage ratio was 4.24 to 1.00 and the consolidated interest coverage ratio was 3.96 to 1.00.  The Partnership was in compliance with all covenants of its credit agreement as of September 30, 2019.

Management evaluates whether conditions and/or events raise substantial doubt about the Partnership’s ability to continue as a going concern within one year after the date that the consolidated financial statements are issued (the “assessment period”). In performing this assessment, management considered the risk associated with its ongoing ability to meet the financial covenants.

Based on the Partnership’s forecasted credit agreement EBITDA during the assessment period, management believes that it will remain in compliance with these financial covenants (as described below). However, there are certain inherent risks associated with our continued ability to comply with our consolidated total leverage ratio covenant. These risks relate, among other things, to potential future (a) decreases in storage volumes and rates as well as throughput and transportation rates realized; (b) weather phenomenon that may potentially hinder the Partnership’s asphalt business activity; and (c) other items affecting forecasted levels of expenditures and uses of cash resources. Violation of the consolidated total leverage ratio covenant would be an event of default under the credit agreement, which would cause our $258.6 million in outstanding debt, as of September 30, 2019, to become immediately due and payable. If this were to occur, the Partnership would not expect to have sufficient liquidity to repay these outstanding amounts then due, which could cause the lenders under the credit facility to pursue other remedies. Such remedies could include exercising their collateral rights to the Partnership’s assets.

Based on management’s current forecasts, management believes the Partnership will be able to comply with the consolidated total leverage ratio during the assessment period. However, the Partnership cannot make any assurances that it will be able to achieve management’s forecasts. If the Partnership is unable to achieve management’s forecasts, further actions may be necessary to remain in compliance with the Partnership’s consolidated total leverage ratio covenant including, but not limited to, cost reductions, common and preferred unitholder distribution curtailments, and/or asset sales. The Partnership can make no assurances that it would be successful in undertaking these actions or that the Partnership will remain in compliance with the consolidated total leverage ratio during the assessment period.

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 8 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. 

11

Upon the execution of the first amendment to its credit agreement in June 2018, the Partnership expensed $0.4 million of debt issuance costs due to the reduction in available borrowing capacity. The Partnership capitalized less than $0.1 million and $0.4 million of debt issuance costs during each of the three and nine months ended September 30, 2018, respectively. Debt issuance costs are being amortized over the term of the credit agreement. Interest expense related to debt issuance cost amortization for both the three months ended September 30, 2019 and 2018, was $0.3 million. Interest expense related to debt issuance cost amortization for both the nine months ended September 30, 2018 and 2019, was $0.8 million.

During the three months ended September 30, 2018 and 2019, the weighted average interest rate under the Partnership’s credit agreement was 5.65% and 5.90%, respectively, resulting in interest expense of approximately $4.1 million and $4.0 million, respectively. During the nine months ended September 30, 2018 and 2019, the weighted average interest rate under the Partnership’s credit agreement, excluding the $0.4 million of debt issuance costs in 2018 that were expensed as described above, was 5.33% and 6.20%, respectively, resulting in interest expense of approximately $12.6 million and $12.3 million, respectively.

The Partnership is exposed to market risk for changes in interest rates related to its credit agreement. Interest rate swap agreements are sometimes used to manage a portion of the exposure related to changing interest rates by converting floating-rate debt to fixed-rate debt. As of September 30, 2019, the Partnership had no interest rate swap agreements; interest rate swap agreements with notional amounts totaling $100.0 million matured on January 28, 2019. During the three months ended September 30, 2018, the Partnership recorded swap interest income of less than $0.1 million. During the nine months ended September 30, 2018 and 2019, the Partnership recorded swap interest income of less than $0.1 million for both periods. The interest rate swaps did 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):

		Fair Value of Derivatives
Derivatives Not Designated as Hedging Instruments	Balance Sheet Location	December 31, 2018
Interest rate swap assets - current	Other current assets	$	44

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,
		2018			2018		2019
Interest rate swaps	Interest expense	$	(37	)	$	277	$	(44	)

7. NET INCOME PER LIMITED PARTNER UNIT

For purposes of calculating earnings per unit, the excess of distributions over earnings or excess of earnings over distributions for each period are allocated to the Partnership’s general partner based on the general partner’s ownership interest at the time. The following sets forth the computation of basic and diluted net income per common unit (in thousands, except per unit data): 

	Three Months ended September 30,					Nine Months ended September 30,
	2018			2019		2018			2019
Net income	$	2,408		$	6,959	$	8,635		$	14,072
General partner interest in net income		39			110		298			268
Preferred interest in net income		6,279			6,278		18,836			18,836
Net income (loss) available to limited partners	$	(3,910	)	$	571	$	(10,499	)	$	(5,032	)
Basic and diluted weighted average number of units:
Common units		40,380			40,811		40,331			40,735
Restricted and phantom units		1,090			1,130		1,019			1,004
Total units		41,470			41,941		41,350			41,739
Basic and diluted net income (loss) per common unit	$	(0.09	)	$	0.01	$	(0.25	)	$	(0.12	)

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8. PARTNERS’ CAPITAL AND DISTRIBUTIONS

On October 17, 2019, the Board approved a cash distribution of $0.17875 per outstanding preferred unit for the three months ended September 30, 2019.  The Partnership will pay this distribution on November 14, 2019, to unitholders of record as of November 4, 2019. 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, the Board approved a cash distribution of $0.04 per outstanding common unit for the three months ended September 30, 2019. The Partnership will pay this distribution on November 14, 2019, to unitholders of record on November 4, 2019. The total distribution will be approximately $1.7 million, with approximately $1.6 million and less than $0.1 million to be paid to the Partnership’s common unitholders and general partner, respectively, and less than $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.

9. RELATED-PARTY TRANSACTIONS

The Partnership leases asphalt facilities and provides asphalt terminalling services to Ergon. For the three months ended September 30, 2018 and 2019, the Partnership recognized related-party revenues of $11.1 million and $9.3 million, respectively, for services provided to Ergon. For the nine months ended September 30, 2018 and 2019, the Partnership recognized related-party revenues of $38.6 million and $27.2 million, respectively, for services provided to Ergon. As of December 31, 2018, and September 30, 2019, the Partnership had receivables from Ergon of $1.0 million and $1.8 million, respectively. As of December 31, 2018, and September 30, 2019, the Partnership had unearned revenues from Ergon of $6.5 million and $4.2 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 months ended September 30, 2018 and 2019, the Partnership made purchases of crude oil under this agreement totaling $44.4 million and $32.8 million, respectively. For the nine months ended September 30, 2018 and 2019, the Partnership made purchases of crude oil under this agreement totaling $74.9 million and $98.6 million, respectively. As of September 30, 2019, the Partnership had payables to Ergon related to this agreement of $11.4 million related to the September crude oil settlement cycle, and this balance was paid in full on October 21, 2019.

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, subject to certain terms and conditions. Cimarron Express was planned to 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, with an originally anticipated in-service date in the second half of 2019. Ergon formed a Delaware limited liability company, Ergon - Oklahoma Pipeline, LLC (“DEVCO”), which holds 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 investment in Cimarron Express plus interest, by giving written notice to Ergon (the “Call”). Ergon has the right to require the Partnership 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, May 9, 2018, of the joint venture company to build the pipeline, (ii) six months after completion of the pipeline, or (iii) the event of dissolution of Cimarron Express. Upon exercise of the Call or the Put, the Partnership and Ergon 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 the Partnership or its designee. As of September 30, 2019, neither Ergon nor the Partnership has exercised their options under the Agreement.

In December 2018, the Partnership and Ergon were informed that Kingfisher Midstream, LLC (“Kingfisher Midstream”) made the decision to suspend future investments in Cimarron Express as Kingfisher Midstream determined that the anticipated volumes from the currently dedicated acreage and the resultant project economics did not support additional investment from Kingfisher Midstream. As of December 31, 2018, Cimarron Express had spent approximately $30.6 million on the pipeline project, primarily related to the purchase of steel pipe and equipment, rights of way and engineering and design services. Cimarron Express recorded a $20.9 million impairment charge in the fourth quarter of 2018 to reduce the carrying amount of its assets to their estimated fair value. Ergon recorded a $10.0 million other-than-temporary impairment on its investment in Cimarron Express as of December 31, 2018, to reduce its investment to its estimated fair value. As a result, the Partnership considered the SEC staff’s opinions outlined in SAB 107 Topic 5.T Accounting for Expenses or Liabilities Paid by Principal Stockholders. The Agreement was designed to have the Partnership, ultimately and from the onset, bear any risk of loss on the construction of the pipeline project and eventually own a 50% interest in the pipeline. As a result, the Partnership recorded on a push-down basis a $10.0 million impairment of Ergon’s investment in Cimarron Express in its consolidated results of operations during the year ended December 31, 2018, and a contingent liability payable to Ergon as of December 31, 2018. In April 2019, certain assets from the project were sold to a third party for approximately $1.4 million over the fair market value that was estimated at December 31, 2018, and the Partnership recorded its share, on a push-down basis, based on Ergon’s 50% interest in the assets. Ergon’s interest in DEVCO includes its capital contributions, its share of the cash received for the assets sale discussed above and internal Ergon labor costs, which brings its investment in DEVCO to approximately $10.4 million through September 30, 2019. During the nine months ended September 30, 2019, a change in estimate and accrued interest resulted in the Partnership recording additional impairment expense of $2.0 million. The Partnership’s contingent liability as of September 30, 2019, consists of Ergon’s $10.4 million investment plus accrued interest of $1.7 million, of which $0.4 million relates to the three months ended September 30, 2019.

On September 5, 2019, the management committee of Cimarron Express met and voted to terminate the project pipeline, wind up the business of Cimarron Express, distribute to its members the cash and assets of Cimarron Express, and thereafter dissolve the company.  Ergon and Kingfisher Midstream are in the process of negotiating final agreements to windup the business, distribute the assets, and dissolve Cimarron Express.

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10. 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.  

Restricted common units are granted to the independent directors on each anniversary of joining the Board. The units vest in one-third increments over three years. The following table includes information on outstanding grants made to the directors under the LTIP:

Grant Date	Number of Units		Weighted Average Grant Date Fair Value(1)		Grant Date Total Fair Value (in thousands)
December 2016		10,950	$	6.85	$	75
December 2017		15,306	$	4.85	$	74
December 2018		23,436	$	1.20	$	28

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

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

Grant Date	Number of Units		Weighted Average Grant Date Fair Value(1)		Grant Date Total Fair Value (in thousands)
December 2016		10,220	$	6.85	$	70
December 2017		14,286	$	4.85	$	69
December 2018		21,875	$	1.20	$	26

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

The Partnership also grants phantom units to employees. These grants are equity awards under ASC 718 – Stock Compensation and, accordingly, the fair value of the awards as of the grant date is expensed over the three-year vesting period. The following table includes information on the outstanding grants:

Grant Date	Number of Units		Weighted Average Grant Date Fair Value(1)		Grant Date Total Fair Value (in thousands)
March 2017		323,339	$	7.15	$	2,312
March 2018		457,984	$	4.77	$	2,185
March 2019		524,997	$	1.14	$	598
June 2019		46,168	$	1.08	$	50

(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, 2019, was $1.1 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, 2018 and 2019, was $0.7 million and $0.3 million, respectively. The Partnership’s equity-based incentive compensation expense for the nine months ended September 30, 2018 and 2019, was $1.8 million and $0.8 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, 2018		998,219	$	5.88
Granted		571,165		1.14
Vested		366,282		4.80
Forfeited		104,758		4.10
Nonvested at September 30, 2019		1,098,344	$	3.45

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11. 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 both the three months ended September 30, 2018 and 2019, for discretionary contributions under the 401(k) Plan. The Partnership recognized expense of $0.9 million and $0.8 million for the nine months ended September 30, 2018 and 2019, respectively, 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 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 less than $0.1 million and $0.2 million for the three months ended September 30, 2018 and 2019, respectively, for discretionary profit sharing contributions under the 401(k) Plan. The Partnership recognized expense of $0.1 million and $0.5 million for the nine months ended September 30, 2018 and 2019, 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 for the each of the three and nine months ended September 30, 2018 and 2019, in connection with the Unit Purchase Plan.

12. 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, 2019. 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, 2018
			Quoted Prices		Significant
			in Active		Other		Significant
			Markets for		Observable		Unobservable
			Identical Assets		Inputs		Inputs
Description	Total		(Level 1)		(Level 2)		(Level 3)
Assets:
Interest rate swap assets	$	44	$	-	$	44	$	-
Total swap assets	$	44	$	-	$	44	$	-

As of September 30, 2019, the Partnership had no interest rate swap agreements.

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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, 2019, 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, 2019, 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.

13. LEASES

The Partnership adopted ASC 842 as of January 1, 2019, using the modified retrospective approach applied at the beginning of the period of adoption. The Partnership elected the package of practical expedients permitted under the transition guidance within the new standard, which, among other things, allowed it to carry forward the historical lease classification.

Adoption of the new standard resulted in the recording of additional net right of use operating lease assets and operating lease liabilities of approximately $11.8 million and $11.9 million, respectively, as of January 1, 2019. The standard did not materially impact the consolidated statement of operations and had no impact on cash flows.

The Partnership leases certain office space, land and equipment. Leases with an initial term of 12 months or less are not recorded on the balance sheet; lease expense for these leases is recognized as paid over the lease term. For real property leases, the Partnership has elected the practical expedient to not separate nonlease components (e.g., common-area maintenance costs) from lease components and to instead account for each component as a single lease component. For leases that do not contain an implicit interest rate, the Partnership uses its most recent incremental borrowing rate.

Some real property and equipment leases contain options to renew, with renewal terms that can extend indefinitely. The exercise of such lease renewal options is at the Partnership’s sole discretion. Certain equipment leases also contain purchase options and residual value guarantees. The Partnership determines the lease term at the lease commencement date as the non-cancellable period of the lease, including options to extend or terminate the lease when such an option is reasonably certain to be exercised. The Partnership uses various data to analyze these options, including historical trends, current expectations and useful lives of assets related to the lease.

		As of
	Classification	September 30, 2019
		(thousands)
Assets
Operating lease assets	Operating lease assets	$	11,374
Finance lease assets	Other noncurrent assets		839
Total leased assets		$	12,213
Liabilities
Current
Operating lease liabilities	Current operating lease liability	$	2,479
Finance lease liabilities	Other current liabilities		336
Noncurrent
Operating lease liabilities	Noncurrent operating lease liability		8,968
Finance lease liabilities	Other long-term liabilities		503
Total lease liabilities		$	12,286

Future commitments, including options to extend lease terms that are reasonably certain of being exercised, related to leases at September 30, 2019, are summarized below (in thousands):

	Operating Leases		Financing Leases
Twelve months ending September 30, 2020	$	2,696	$	369
Twelve months ending September 30, 2021		2,349		296
Twelve months ending September 30, 2022		1,569		183
Twelve months ending September 30, 2023		1,470		48
Twelve months ending September 30, 2024		969		2
Thereafter		6,199		-
Total		15,252		898
Less: Interest		3,805		60
Present value of lease liabilities	$	11,447	$	838

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Future non-cancellable commitments related to operating leases at December 31, 2018, are summarized below (in thousands):

	Operating Leases
Year ending December 31, 2019	$	2,862
Year ending December 31, 2020		1,904
Year ending December 31, 2021		1,242
Year ending December 31, 2022		640
Year ending December 31, 2023		548
Thereafter		1,259
Total future minimum lease payments	$	8,455

The following table summarizes the Partnership’s total lease cost by type as well as cash flow information (in thousands):

		Three Months ended September 30,		Nine Months ended September 30,
	Classification	2019		2019
Total Lease Cost by Type:
Operating lease cost(1)	Operating Expense	$	1,085	$	3,281
Finance lease cost
Amortization of leased assets	Operating Expense		85		236
Interest on lease liabilities	Interest Expense		10		27
Net lease cost		$	1,180	$	3,544
Supplemental cash flow disclosures:
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases				$	2,195
Operating cash flows from finance leases				$	77
Financing cash flows from finance leases				$	201
Leased assets obtained in exchange for new operating lease liabilities				$	1,714
Leased assets obtained in exchange for new finance lease liabilities				$	520

(1) Includes short-term and variable lease costs, which are immaterial.

	As of
Lease Term and Discount Rate		September 30, 2019
Weighted-average remaining lease term (years)
Operating leases		9.7
Finance leases		2.8
Weighted-average discount rate
Operating leases		5.78	%
Finance leases		4.83	%

The Partnership also incurs costs associated with acquiring and maintaining rights-of-way. The contracts for these generally either extend beyond one year but can be cancelled at any time should they no longer be required for operations or have no contracted term but contain perpetual annual or monthly renewal options. Rights-of-way generally do not provide for exclusive use of the land and as such are not accounted for as leases.

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14. OPERATING SEGMENTS

The Partnership’s operations consist of four reportable 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. 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.  

The Partnership’s management evaluates segment 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. Operating margin, excluding depreciation and amortization (in the aggregate and by segment) is presented in the following table. The Partnership computes the components of operating margin, excluding depreciation and amortization by using amounts that are determined in accordance with GAAP. The Partnership accounts for intersegment product sales as if the sales were to third parties, that is, at current market prices. A reconciliation of operating margin, excluding depreciation and amortization to income before income taxes, which is its nearest comparable GAAP financial measure, is included in the following table. The Partnership believes that investors benefit from having access to the same financial measures being utilized by management. Operating margin, excluding depreciation and amortization is an important measure of the economic performance of the Partnership’s core operations. This measure forms the basis of the Partnership’s internal financial reporting and is used by its management in deciding how to allocate capital resources among segments. Income before income taxes, alternatively, includes expense items, such as depreciation and amortization, general and administrative expenses and interest expense, which management does not consider when evaluating the core profitability of the Partnership’s operations.

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

	Three Months ended September 30,				Nine Months ended September 30,
	2018		2019		2018		2019
Asphalt Terminalling Services
Service revenue:
Third-party revenue	$	6,921	$	7,385	$	18,693	$	21,217
Related-party revenue		5,211		3,892		17,512		11,991
Lease revenue:
Third-party revenue		11,288		11,444		30,762		31,026
Related-party revenue		5,406		5,427		20,584		15,179
Product sales revenue:
Related-party revenue		482		-		482		-
Total revenue for reportable segment		29,308		28,148		88,033		79,413
Operating expense, excluding depreciation and amortization		11,683		11,025		38,412		34,980
Operating margin, excluding depreciation and amortization	$	17,625	$	17,123	$	49,621	$	44,433
Total assets (end of period)	$	143,454	$	145,761	$	143,454	$	145,761
Crude Oil Terminalling Services
Service revenue:
Third-party revenue	$	1,923	$	4,225	$	9,418	$	11,819
Intersegment revenue		222		278		392		853
Lease revenue:
Third-party revenue		9		-		35		-
Total revenue for reportable segment		2,154		4,503		9,845		12,672
Operating expense, excluding depreciation and amortization		928		1,212		3,115		3,511
Operating margin, excluding depreciation and amortization	$	1,226	$	3,291	$	6,730	$	9,161
Total assets (end of period)	$	67,213	$	66,045	$	67,213	$	66,045

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	Three Months ended September 30,						Nine Months ended September 30,
	2018			2019			2018			2019
Crude Oil Pipeline Services
Service revenue:
Third-party revenue	$	1,165		$	1,284		$	4,270		$	5,753
Related-party revenue		185			64			268			266
Lease revenue:
Third-party revenue		40			-			452			-
Product sales revenue:
Third-party revenue		97,763			55,213			146,882			173,773
Total revenue for reportable segment		99,153			56,561			151,872			179,792
Operating expense, excluding depreciation and amortization		3,094			2,638			8,420			8,109
Intersegment operating expense		1,644			1,642			3,243			4,971
Third-party cost of product sales		50,815			18,972			73,493			64,069
Related-party cost of product sales		44,106			32,691			67,853			99,886
Operating margin, excluding depreciation and amortization	$	(506	)	$	618		$	(1,137	)	$	2,757
Total assets (end of period)	$	171,841		$	96,221		$	171,841		$	96,221
Crude Oil Trucking Services
Service revenue
Third-party revenue	$	2,734		$	2,822		$	11,783			8,540
Intersegment revenue		1,422			1,364			2,851			4,118
Lease revenue:
Third-party revenue		31			-			160			-
Product sales revenue:
Third-party revenue		-			-			10			-
Total revenue for reportable segment		4,187			4,186			14,804			12,658
Operating expense, excluding depreciation and amortization		4,303			4,053			15,405			12,515
Operating margin, excluding depreciation and amortization	$	(116	)	$	133		$	(601	)	$	143
Total assets (end of period)	$	3,731		$	5,948		$	3,731		$	5,948
Total operating margin, excluding depreciation and amortization(1)	$	18,229		$	21,165		$	54,613		$	56,494
Total Segment Revenues	$	134,802		$	93,398		$	264,554		$	284,535
Elimination of Intersegment Revenues		(1,644	)		(1,642	)		(3,243	)		(4,971	)
Consolidated Revenues	$	133,158		$	91,756		$	261,311		$	279,564

(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,
	2018			2019			2018			2019
Operating margin, excluding depreciation and amortization	$	18,229		$	21,165		$	54,613		$	56,494
Depreciation and amortization		(7,166	)		(6,240	)		(21,945	)		(19,211	)
General and administrative expense		(4,322	)		(3,840	)		(13,029	)		(10,495	)
Asset impairment expense		(15	)		(83	)		(631	)		(2,316	)
Gain (loss) on sale of assets		(63	)		(40	)		300			1,765
Other income		-			-			-			268
Gain on sale of unconsolidated affiliate		-			-			2,225			-
Interest expense		(4,090	)		(3,989	)		(12,683	)		(12,394	)
Income before income taxes	$	2,573		$	6,973		$	8,850		$	14,111

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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, 2019, are presented below (dollars in thousands):

Deferred Tax Asset
Difference in bases of property, plant and equipment	$	236
Net operating loss carryforwards		24
Deferred tax asset		260
Less: valuation allowance		260
Net deferred tax asset	$	-

The Partnership has considered the taxable income projections in future years, 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, 2019.

17. RECENTLY ISSUED ACCOUNTING STANDARDS

Except as discussed below and in the 2018 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, 2019, that are of significance or potential significance to the Partnership.

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 adopted this standard as of January 1, 2019, using the modified retrospective approach. See Note 3 and Note 13 for disclosures related to the adoption of this standard and the impact on the Partnership’s financial position, results of operations and 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, 2018, which was filed with the Securities and Exchange Commission (the “SEC”) on March 12, 2019 (the “2018 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 2018 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.

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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 November 1, 2019, the forward price curve is in a shallow contango. Potential impacts of these factors are discussed below.

Asphalt Terminalling Services - Historically, there have only been limited times in which asphalt prices and volumes have had a direct correlation with the price of crude oil. As a result, we do not expect that changes in the price of crude oil will necessarily have a significant impact on our asphalt terminalling services operating segment. Generally, asphalt volumes correlate more closely with the strength of state and local economies, the level of allocations of tax funding to transportation spending and an increase in infrastructure spending needs.

In 2019, the level of customer throughput volumes through our terminals have varied across the country, primarily impacted by weather patterns, refinery disruptions and the customers’ own supply chain needs. The Midwest has been impacted by higher levels of rain earlier in the year that slowed customer throughput; however, activity has increased later in the season to help make up for this.  In addition, during the first half of 2019, several of our asphalt facilities in the Midwest were damaged by flooding. While the facilities were able to successfully execute flood plans to minimize damages, costs related to the floods are expected to include approximately $0.7 million of expenses for cleanup and the removal and reinstallation of equipment and $1.9 million of capital expenditures to restore land improvements and equipment. As of September 30, 2019, $1.3 million of these amounts have been spent. Impairment expense related to the assets was $0.3 million. As of September 30, 2019, we have recognized $0.7 million of insurance recoveries. While we are pursuing additional insurance claims for these events, there can be no assurance of the amount or timing of any proceeds we may receive under such claims.

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 crude oil. 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. Alternatively, despite a shallow contango curve, we have seen increased activity and interests from customers that are regularly turning over their volumes by blending various crude grades and delivering it out of the terminal or customers utilizing the storage for more operational purposes for their downstream operations. As a result of this change in demand factors for Cushing storage, we anticipate a more complex recontracting environment which has the potential to affect both the volumes and rate of our recontracting efforts.

Crude Oil Pipeline Services - Crude oil pipeline transportation, while potentially influenced by the shape of the crude oil market curve, is typically impacted more by overall drilling activity. From April 2016 to July 2018, a portion of our Oklahoma system was out of service, which reduced transportation capacity by approximately 20,000 Bpd. In July 2018, we were able to restore service to that portion of pipeline. The ability to fully utilize the capacity of the system may be impacted by the market price of crude oil and producers’ decisions to increase or decrease production in the areas we serve.

Over the past year, 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 system.  Typically, the volume of crude oil we purchase in a given month will be sold in the same month. However, we have market price exposure for inventory that is carried over month-to-month as well as pipeline linefill we maintain. Since our pipeline tariffs require shippers to carry their share of linefill, our crude oil marketing operations, as a shipper, also carries linefill. We may also be exposed to price risk with respect to the differing qualities of crude oil we transport and our ability to effectively blend them to market specifications.

On May 10, 2018, we, together with affiliates of Ergon and Kingfisher Midstream, LLC, a subsidiary of Alta Mesa Resources, Inc., announced the execution of definitive agreements to form Cimarron Express Pipeline, LLC (“Cimarron Express”). See Note 9 to our unaudited condensed consolidated financial statements for discussion on the suspension of this project.

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.

On April 24, 2018, we sold our producer field services business, which has been historically reported along with the crude oil trucking services.

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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, 2019, the Partnership recognized revenues of $27.2 million and $0.3 million for services provided to Ergon and Cimarron Express, respectively, with the remainder of our services being provided to third parties.

Terminalling revenues consist of (i) storage service fees resulting from short-term and long-term contracts for committed space that may or may not be utilized by the customer in a given month and (ii) terminal throughput service charges 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. Terminal throughput service charges are recognized as the crude oil or asphalt product 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.  These agreements have, on average, approximately 3.8 years remaining under their terms. While agreements with one customer for four of the facilities expire by the end of 2019, we have commercially agreed to all terms on a new contract with the same customer and expect to finalize it in the near term. The remaining agreements expire at varying times thereafter, including agreements for 23 facilities with Ergon that expire in 2023. 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 November 1, 2019, we had approximately 5.2 million barrels of crude oil storage under service contracts, including 2.5 million barrels of crude oil storage contracts that expire in 2019. The decrease in contracted storage barrels from prior quarter is due to the expiration of an intracompany contract for 0.5 million barrels, which has no net impact on our consolidated financial results. The remaining terms on the service contracts that extend beyond 2019 range from 3 to 26 months. Storage contracts with Vitol represent 2.9 million barrels of crude oil storage capacity under contract. We are in negotiations to either extend contracts or enter into new customer contracts for the agreements expiring in 2019; 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 expiring contracts. If we are unable to renew even some 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)
	2018		2019		2018		2019		Three Months					Nine Months
Average pipeline throughput volume		23		23		22		31		-		0	%		9	41	%
Average trucking transportation volume		29		25		26		26		(4	)	(14	)%		-	0	%

In July 2018, we restored service on an out-of-service portion of our Oklahoma system, 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 27% and 28% of volumes transported on our pipelines in the three months ended September 30, 2018 and 2019, respectively. Vitol accounted for 37% and 38% of volumes transported on our pipelines in the nine months ended September 30, 2018 and 2019, respectively.

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.

23

Our Expenses

Operating expenses decreased by 10% for the nine months ended September 30, 2019, as compared to the nine months ended September 30, 2018. In addition to decreases related to the sale of the three asphalt plants in July 2018, depreciation expense decreased due to certain assets reaching the end of their depreciable lives and vehicle expenses decreased due to a reduction in the size of our fleet. General and administrative expenses decreased 19% for the nine months ended September 30, 2019, as compared to the nine months ended September 30, 2018. The decrease is primarily due to decreased compensation and professional fees expense, as well as the receipt of a $0.5 million settlement related to a payment made in 2018 to a fraudulent bank account due to a compromise of the vendor’s email system as disclosed in the 2018 Form 10-K, which were offset by expenses related to the Ergon buyout offer of $0.4 million. Our interest expense decreased by 2% for the nine months ended September 30, 2019, as compared to the nine months ended September 30, 2018. See Interest expense within our results of operations discussion for additional detail regarding the factors that contributed to the decrease in interest expense in 2019.

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;

• 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 full valuation allowance against our deferred tax asset as of September 30, 2019.

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 17, 2019, the Board approved a cash distribution of $0.17875 per outstanding preferred unit for the three months ended September 30, 2019. We will pay this distribution on November 14, 2019, to unitholders of record as of November 4, 2019. 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, the Board approved a cash distribution of $0.04 per outstanding common unit for the three months ended September 30, 2019. We will pay this distribution November 14, 2019, to unitholders of record on November 4, 2019. The total distribution will be approximately $1.7 million, with approximately $1.6 million and less than $0.1 million paid to our common unitholders and General Partner, respectively, and less than $0.1 million paid to holders of phantom and restricted units pursuant to awards granted under our Long-Term Incentive Plan.

Ergon Buyout Offer

On August 5, 2019, Ergon filed an amendment to its Schedule 13D with the SEC disclosing that Ergon made a non-binding proposal to the Board, pursuant to which Ergon would acquire all the outstanding Common Units and Series A Preferred Units of the Partnership not already owned by Ergon and its affiliates. The proposal was referred to the Conflicts Committee of the Board for consideration. The proposal was withdrawn by Ergon on September 11, 2019.

24

Results of Operations

Non-GAAP Financial Measures

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

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

The table below summarizes our financial results for the three and nine months ended September 30, 2018 and 2019, reconciled to the most directly comparable GAAP measure:

	Three Months ended						Nine Months ended						Favorable/(Unfavorable)
Operating results	September 30,						September 30,						Three Months						Nine Months
(dollars in thousands)	2018			2019			2018			2019			$			%			$			%
Operating margin, excluding depreciation and amortization:
Asphalt terminalling services	$	17,625		$	17,123		$	49,621		$	44,433		$	(502	)		(3	)%	$	(5,188	)		(10	)%
Crude oil terminalling services		1,226			3,291			6,730			9,161			2,065			168	%		2,431			36	%
Crude oil pipeline services		(506	)		618			(1,137	)		2,757			1,124			222	%		3,894			342	%
Crude oil trucking services		(116	)		133			(601	)		143			249			215	%		744			124	%
Total operating margin, excluding depreciation and amortization		18,229			21,165			54,613			56,494			2,936			16	%		1,881			3	%
Depreciation and amortization		(7,166	)		(6,240	)		(21,945	)		(19,211	)		926			13	%		2,734			12	%
General and administrative expense		(4,322	)		(3,840	)		(13,029	)		(10,495	)		482			11	%		2,534			19	%
Asset impairment expense		(15	)		(83	)		(631	)		(2,316	)		(68	)		(453	)%		(1,685	)		(267	)%
Gain (loss) on sale of assets		(63	)		(40	)		300			1,765			23			37	%		1,465			488	%
Operating income		6,663			10,962			19,308			26,237			4,299			65	%		6,929			36	%
Other income (expenses):
Other income		-			-			-			268			-			0	%		268			N/A
Gain on sale of unconsolidated affiliate		-			-			2,225			-			-			0	%		(2,225	)		(100	)%
Interest expense		(4,090	)		(3,989	)		(12,683	)		(12,394	)		101			2	%		289			2	%
Provision for income taxes		(165	)		(14	)		(215	)		(39	)		151			92	%		176			82	%
Net income	$	2,408		$	6,959		$	8,635		$	14,072		$	4,551			189	%	$	5,437			63	%

For the three and nine months ended September 30, 2019, overall operating margin, excluding depreciation and amortization, increased compared to the same period in 2018. Our asphalt terminalling services segment operating margin, excluding depreciation and amortization, was impacted by both the acquisition of an asphalt facility in March 2018 and the sale of three asphalt terminals to Ergon in July 2018. The increase in our crude oil terminalling services operating margin, excluding depreciation and amortization, is primarily due to an increase in rented storage capacity. Margins in our crude oil pipeline services segment reflect the recovery of throughput volumes since the restoration of a portion of our Oklahoma system in July 2018, on which we had suspended service in April 2016 due to the discovery of a pipeline exposure on a riverbed in southern Oklahoma. In addition, an $0.8 million sale of crude oil product accumulated over time through customer loss allowance deductions for the nine months ended September 30, 2019, also contributed to the increased margin in our crude oil pipeline services segment; there were no such sales in the same period in 2018. Crude oil trucking services operating margin, excluding depreciation and amortization, improved for the three and nine months ended September 30, 2019, due to improved rates beginning in the fourth quarter of 2018 and longer length of hauls transported.

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

25

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:

	Three Months ended				Nine Months ended				Favorable/(Unfavorable)
Operating results	September 30,				September 30,				Three Months						Nine Months
(dollars in thousands)	2018		2019		2018		2019		$			%			$			%
Service revenue:
Third-party revenue	$	6,921	$	7,385	$	18,693	$	21,217	$	464			7	%	$	2,524			14	%
Related-party revenue		5,211		3,892		17,512		11,991		(1,319	)		(25	)%		(5,521	)		(32	)%
Lease revenue:
Third-party revenue		11,288		11,444		30,762		31,026		156			1	%		264			1	%
Related-party revenue		5,406		5,427		20,584		15,179		21			0	%		(5,405	)		(26	)%
Product sales revenue:
Related-party revenue		482		-		482		-		(482	)		(100	)%		(482	)		(100	)%
Total revenue		29,308		28,148		88,033		79,413		(1,160	)		(4	)%		(8,620	)		(10	)%
Operating expense, excluding depreciation and amortization		11,683		11,025		38,412		34,980		658			6	%		3,432			9	%
Operating margin, excluding depreciation and amortization	$	17,625	$	17,123	$	49,621	$	44,433	$	(502	)		(3	)%	$	(5,188	)		(10	)%

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

• Total revenue decreased for the three and nine months ended September 30, 2019, as compared to the three and nine months ended September 30, 2018. The sale of the three asphalt facilities in July 2018 resulted in a decrease of revenue of $1.2 million and $10.8 million for the three and nine month periods, respectively. The decrease for the nine month period was offset in part by an increase in revenue of $1.5 million due to the asphalt facility acquired in March 2018 and a contract change on another asphalt facility from a related-party lease to a third-party storage contract.

• Operating expenses decreased for the three and nine months ended September 30, 2019, as compared to the three and nine months ended September 30, 2018. For the three month comparative periods, the sale of three facilities in July 2018 led to a decrease in operating expenses of $0.6 million.  In addition, decreased utility costs at some facilities were offset by net flood-related expenses of $0.1 million as well as increases in other non-flood related repairs. For the nine month comparative periods, the sale of three facilities in July 2018 led to a decrease in operating expenses of $5.4 million, which was partially offset by an increase of $0.8 million related to the acquisition in March 2018, net flood-related expenses of $0.2 million, and increased compensation costs at some facilities.

26

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:

	Three Months ended				Nine Months ended				Favorable/(Unfavorable)
Operating results	September 30,				September 30,				Three Months						Nine Months
(dollars in thousands)	2018		2019		2018		2019		$			%			$			%
Service revenue:
Third-party revenue	$	1,923	$	4,225	$	9,418	$	11,819	$	2,302			120	%	$	2,401			25	%
Intersegment revenue		222		278		392		853		56			25	%		461			118	%
Lease revenue:
Third-party revenue		9		-		35		-		(9	)		(100	)%		(35	)		(100	)%
Total revenue		2,154		4,503		9,845		12,672		2,349			109	%		2,827			29	%
Operating expense, excluding depreciation and amortization		928		1,212		3,115		3,511		(284	)		(31	)%		(396	)		(13	)%
Operating margin, excluding depreciation and amortization	$	1,226	$	3,291	$	6,730	$	9,161	$	2,065			168	%	$	2,431			36	%
Average crude oil storage contracted per month at our Cushing terminal (in thousands of barrels)		2,950		5,862		4,029		5,731		2,912			99	%		1,702			42	%
Average crude oil stored per month at our Cushing terminal (in thousands of barrels)		779		3,104		1,249		3,339		2,325			298	%		2,090			167	%
Average crude oil delivered through our Cushing terminal (in thousands of barrels per day)		32		99		50		87		67			209	%		37			74	%

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, 2019, increased as compared to the same period in 2018 due to an increase in rented storage capacity and an increase in crude oil delivered through the terminal.

• Operating expenses for the three and nine months ended September 30, 2019, increased compared to the three and nine months ended September 30, 2018 due to an increase in tank repair expenses.

• As of November 1, 2019, we had approximately 5.2 million barrels of crude oil storage under service contracts, including 2.5 million barrels of crude oil storage contracts that expire in 2019. The decrease in contracted storage barrels from prior quarter is due to the expiration of an intracompany contract for 0.5 million barrels, which has no net impact on our consolidated financial results. The remaining terms on the service contracts that extend beyond 2019 range from 3 to 26 months. Storage contracts with Vitol represent 2.9 million barrels of crude oil storage capacity under contract.

27

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:

	Three Months ended					Nine Months ended					Favorable/(Unfavorable)
Operating results	September 30,					September 30,					Three Months						Nine Months
(dollars in thousands)	2018			2019		2018			2019		$			%			$			%
Service revenue:
Third-party revenue	$	1,165		$	1,284	$	4,270		$	5,753	$	119			10	%	$	1,483			35	%
Related-party revenue		185			64		268			266		(121	)		(65	)%		(2	)		(1	)%
Lease revenue:
Third-party revenue		40			-		452			-		(40	)		(100	)%		(452	)		(100	)%
Product sales revenue:
Third-party revenue		97,763			55,213		146,882			173,773		(42,550	)		(44	)%		26,891			18	%
Total revenue		99,153			56,561		151,872			179,792		(42,592	)		(43	)%		27,920			18	%
Operating expense, excluding depreciation and amortization		3,094			2,638		8,420			8,109		456			15	%		311			4	%
Intersegment operating expense		1,644			1,642		3,243			4,971		2			0	%		(1,728	)		(53	)%
Third-party cost of product sales		50,815			18,972		73,493			64,069		31,843			63	%		9,424			13	%
Related-party cost of product sales		44,106			32,691		67,853			99,886		11,415			26	%		(32,033	)		(47	)%
Operating margin, excluding depreciation and amortization	$	(506	)	$	618	$	(1,137	)	$	2,757	$	1,124			222	%	$	3,894			342	%
Pipeline transportation services average throughput volume (in thousands of barrels per day)		23			23		22			31		-			0	%		9			41	%
Crude oil marketing volumes (in thousands of barrels per day)		15			11		8			11		(4	)		(27	)%		3			38	%

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

• In July 2018, we restored service on the portion of the pipeline system that had been out of service since April 2016 due to a pipeline exposure on a riverbed in southern Oklahoma. This restored our transportation capacity to the full 50,000 barrels per day.

• Total throughput volumes are consistent for the three month comparative periods, while the increase in the nine month comparative periods is due to both increased crude oil marketing activities and the restored service on the Oklahoma pipeline system. In addition to the increase in volume, operating margins were positively impacted by improved margins on the crude oil marketing activities.  Throughput volumes related to the crude oil marketing business were approximately 11,000 barrels per day, or approximately 48% and 35% of total throughput, for both the three and nine months ended September 30, 2019. The service revenue for this activity associated with pipeline tariffs is eliminated on an intrasegment basis. Our crude oil pipeline recognized $1.5 million and $4.5 million in intrasegment service revenue in the three and nine months ended September 30, 2019, respectively, that is not reflected in revenues in the table above. The intrasegment revenues for three and nine months ended September 30, 2018, were $1.7 million and $3.4 million, respectively. The changes in product sales revenues, intersegment operating expense, and related-party and third-party cost of product sales are all due to changes in our crude oil marketing business.

28

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.

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

	Three Months ended					Nine Months ended					Favorable/(Unfavorable)
Operating results	September 30,					September 30,					Three Months						Nine Months
(dollars in thousands)	2018			2019		2018			2019		$			%			$			%
Service revenue
Third-party revenue	$	2,734		$	2,822	$	11,783		$	8,540	$	88			3	%	$	(3,243	)		(28	)%
Intersegment revenue		1,422			1,364		2,851			4,118		(58	)		(4	)%		1,267			44	%
Lease revenue:
Third-party revenue		31			-		160			-		(31	)		(100	)%		(160	)		(100	)%
Product sales revenue:
Third-party revenue		-			-		10			-		-			0	%		(10	)		(100	)%
Total revenue		4,187			4,186		14,804			12,658		(1	)		(0	)%		(2,146	)		(14	)%
Operating expense, excluding depreciation and amortization		4,303			4,053		15,405			12,515		250			6	%		2,890			19	%
Operating margin, excluding depreciation and amortization	$	(116	)	$	133	$	(601	)	$	143	$	249			215	%	$	744			124	%
Average volume (in thousands of barrels per day)		29			25		26			26		(4	)		(14	)%		-			0	%

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

• Service revenues were consistent for the three months ended September 30, 2019, as compared to the three months ended September 30, 2018, despite a decrease in volumes due to rate increases instituted in October 2018.

• Service revenues decreased for the nine months ended September 30, 2019, as compared to the nine months ended September 30, 2018, by $2.7 million due to the sale of the producer field services business in April 2018. This decrease was partially offset by an increase in intersegment service revenues for services provided to our crude oil pipeline services segment’s crude oil marketing business. These volumes transported on an intersegment basis increased from 8,000 barrels per day to 11,000 barrels per day.

• Operating expense, excluding depreciation and amortization, decreased for the nine months ended September 30, 2019, as compared to the nine months ended September 30, 2018, by $2.9 million due to the sale of our producer field services business.

29

Other Income and Expenses

Depreciation and amortization expense. Depreciation and amortization expense decreased by $1.0 million to $6.2 million for the three months ended September 30, 2019, compared to $7.2 million for the three months ended September 30, 2018. Depreciation and amortization expense decreased by $2.7 million to $19.2 million for the nine months ended September 30, 2019, compared to $21.9 million for the nine months ended September 30, 2018. These decreases are primarily the result of certain assets reaching the end of their depreciable lives.

General and administrative expense.  General and administrative expense decreased for the three and nine months ended September 30, 2019, compared to the same periods in 2018 primarily due to decreases in compensation and professional fees expense as well as the impact of a payment made in 2018 to a fraudulent bank account due to a compromise of the vendor’s email system. Expense related to this payment of $0.9 million was recognized in the three months ended September 30, 2018, while a settlement payment of $0.5 million was received in the second quarter of 2019. This impact was partially offset by an increase of $0.4 million due to expenses related to the Ergon buyout offer during the third quarter of 2019.

Asset impairment expense. Asset impairment expense for the three and nine months ended September 30, 2019, included a change in estimate and accrued interest related to the push-down impairment of Cimarron Express (see Note 9 to our unaudited condensed consolidated financial statements for more information) that resulted in additional impairment expense for those periods of $0.1 million and $2.0 million, respectively.  The nine months ended September 30, 2019, also included flood-related impairment expense of $0.3 million. Asset impairment expense for 2018 included approximately $0.4 million related to the value of obsolete trucking stations and $0.2 million related to an intangible customer contract asset that was not renewed.

Gain (loss) on sale of assets. Gain on sale of assets was $1.8 million for the nine months ended September 30, 2019, compared to a loss of $0.3 million for the nine months ended September 30, 2018. Gains for 2019 primarily relate to the sale of certain truck stations in locations not served by our crude oil trucking services segment.

Other income. Other income for the nine months ended September 30, 2019, relates to insurance recoveries related to flood damages at certain asphalt facilities.

Gain on sale of unconsolidated affiliate. On April 3, 2017, we sold our investment in Advantage Pipeline, L.L.C. 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 30, 2018.

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

	Three Months ended					Nine Months ended						Favorable/(Unfavorable)
	September 30,					September 30,						Three Months						Nine Months
	2018			2019		2018			2019			$			%			$			%
Credit agreement interest	$	3,815		$	3,714	$	11,856		$	11,585		$	101			3	%	$	271			2	%
Amortization of debt issuance costs		251			251		764			753			-			0	%		11			1	%
Write-off of debt issuance costs		-			-		437			-			-			0	%		437			100	%
Interest rate swaps interest income		(25	)		-		(49	)		(40	)		(25	)		(100	)%		(9	)		(18	)%
Loss (gain) on interest rate swaps mark-to-market		36			-		(276	)		44			36			100	%		(320	)		(116	)%
Other		13			24		(49	)		52			(11	)		(85	)%		(101	)		(206	)%
Total interest expense	$	4,090		$	3,989	$	12,683		$	12,394		$	101			2	%	$	289			2	%

Effects of Inflation

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

Off-Balance Sheet Arrangements

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

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Liquidity and Capital Resources

Cash Flows and Capital Expenditures

The following table summarizes our sources and uses of cash for the nine months ended September 30, 2018 and 2019: 

	Nine Months ended September 30,
	2018			2019
	(in millions)
Net cash provided by operating activities	$	28.2		$	38.3
Net cash provided by (used in) investing activities	$	44.0		$	(2.3	)
Net cash provided by (used in) financing activities	$	(72.7	)	$	(34.6	)

Operating Activities.  Net cash provided by operating activities increased to $38.3 million for the nine months ended September 30, 2019, as compared to $28.2 million for the nine months ended September 30, 2018, due to increased net income as discussed in Results of Operations above as well as changes in working capital.

Investing Activities.  Net cash used in investing activities was $2.3 million for the nine months ended September 30, 2019, compared to net cash provided by investing activities of $44.0 million for the nine months ended September 30, 2018.  The nine months ended September 30, 2019, included proceeds from the sale of certain assets of $7.1 million. Of such proceeds, $2.6 million related to the December 2018 sale of linefill for which the cash consideration was not received until January 2019. The nine months ended September 30, 2018, included proceeds from the sale of three asphalt terminals of $88.5 million and proceeds from the sale of an unconsolidated affiliate of $2.2 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 2019, included maintenance capital expenditures of $6.0 million and $7.4 million, respectively, and expansion capital expenditures of $23.6 million and $2.0 million, respectively.

Financing Activities.  Net cash used in financing activities was $34.6 million for the nine months ended September 30, 2019, and $72.7 million for the nine months ended September 30, 2018.  Cash used in financing activities for the nine months ended September 30, 2019, consisted primarily of net payments on long-term debt of $7.0 million and $25.9 million in distributions to our unitholders. Net 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.

Our Liquidity and Capital Resources

Cash flows from operations and from our credit agreement are our primary sources of liquidity. At September 30, 2019, we had a working capital deficit of $8.7 million. This is primarily a function of our approach to cash management. At September 30, 2019, we had approximately $140.4 million of availability under our credit agreement subject to covenant restrictions, which limited our availability to $46.4 million. As of November 1, 2019, we have aggregate unused commitments under our revolving credit facility of approximately $148.4 million and cash on hand of approximately $1.1 million.  Based on our current outlook and liquidity, we expect to be in a position to settle the Put (see Note 9 for further information), which has a current value of $12.1 million, in cash when it is exercised. The credit agreement is scheduled to mature on May 11, 2022.

Our credit agreement contains certain financial covenants which include a maximum permitted consolidated total leverage ratio, which may limit our availability to borrow funds thereunder.  The consolidated total leverage ratio is assessed quarterly based on the trailing twelve months of EBITDA, as defined in the credit agreement. The maximum permitted consolidated total leverage ratio as of September 30, 2019, was 5.00 to 1.00 and decreases to 4.75 to 1.00 as of March 31, 2020, and for each fiscal quarter thereafter. Our consolidated total leverage ratio was 4.24 to 1.00 as of September 30, 2019. 

Management evaluates whether conditions and/or events raise substantial doubt about our ability to continue as a going concern within one year after the date that the consolidated financial statements are issued (the “assessment period”). In performing this assessment, management considered the risk associated with its ongoing ability to meet the financial covenants.

Based on forecasted EBITDA during the assessment period, management believes that it will meet the financial covenants. However, there are certain inherent risks associated with our continued ability to comply with our consolidated total leverage ratio covenant.  These risks relate, among other things, to potential future (a) decreases in storage volumes and rates as well as throughput and transportation rates realized; (b) weather phenomenon that may potentially hinder the asphalt business activity; and (c) other items affecting forecasted levels of expenditures and uses of cash resources. Violation of the consolidated total leverage ratio covenant would be an event of default under the credit agreement, which would cause our $258.6 million in outstanding debt, as of September 30, 2019, to become immediately due and payable.  If this were to occur, we would not expect to have sufficient liquidity to repay these outstanding amounts then due, which could cause the lenders under the credit facility to pursue other remedies. Such remedies could include exercising their collateral rights to our assets. Based on our current forecasts, we believe we will be able to comply with the consolidated total leverage ratio during the assessment period.  However, we cannot make any assurances that we will be able to achieve our forecasts. If we are unable to achieve our forecasts, further actions may be necessary to remain in compliance with our consolidated total leverage ratio covenant including, but not limited to, cost reductions, common and preferred unitholder distribution curtailments, and/or asset sales.  We can make no assurances that we would be successful in undertaking these actions, or that we will remain in compliance with the consolidated total leverage ratio during the assessment period.

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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.

The following table breaks out capital expenditures for the nine months ended September 30, 2018 and 2019 (in thousands):

	Nine Months ended September 30,
	2018			2019
Acquisitions		21,959			-
Gross expansion capital expenditures		23,617			1,969
Reimbursable expenditures		(338	)		(61	)
Net expansion capital expenditures		23,279			1,908
Gross maintenance capital expenditures		5,943			7,459
Reimbursable expenditures		(572	)		(202	)
Net maintenance capital expenditures		5,371			7,257

We currently expect our expansion capital expenditures for organic growth projects to be approximately $3.5 million to $4.5 million for all of 2019.  We currently expect maintenance capital expenditures to be approximately $9.0 million to $10.0 million, net of reimbursable expenditures, for all of 2019.

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.

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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 November 1, 2019, we had $250.6 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 sometimes 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 matured on January 28, 2019. Under the terms of the second interest rate swap agreement, we paid a fixed rate of 1.97% and received one-month LIBOR with monthly settlement. The interest rate swaps did 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, 2019, the weighted average interest rate under our credit agreement was 6.20%.

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, 2019, the terms of our credit agreement, current interest rates and the effect of our interest rate swaps, an increase or decrease of 100 basis points in the interest rate would result in increased or decreased annual interest expense of approximately $2.6 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, 2019, 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, 2019, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1.    Legal Proceedings.

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

Item 1A.    Risk Factors.

See the risk factors set forth in Part I, Item 1A, of our Annual Report on Form 10-K for the year ended December 31, 2018.

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.

INDEX TO EXHIBITS

Exhibit Number	Description
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	First Amendment to the Amended and Restated Certificate of Limited Partnership of Blueknight Energy Partners L.P., dated July 18, 2019 (filed as Exhibit 3.2 to the Partnership’s Current Report on Form 8-K, filed on July 22, 2019, and incorporated herein by reference).
3.3	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).
3.4	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).
3.5	First Amendment to the Amended and Restated Certificate of Formation of Blueknight Energy Partners G.P., L.L.C., dated July 18, 2019 (filed as Exhibit 3.1 to the Partnership’s Current Report on Form 8-K, filed on July 22, 2019, and incorporated herein by reference).
3.6	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).
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, 2019, formatted in XBRL (eXtensible Business Reporting Language): (i) Document and Entity Information; (ii) Unaudited Condensed Consolidated Balance Sheets as of December 31, 2018 and September 30, 2019; (iii) Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2018 and 2019; (iv) Unaudited Condensed Consolidated Statement of Changes in Partners’ Capital (Deficit) for the three and nine months ended September 30, 2018 and 2019; (v) Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2018 and 2019; and (vi) Notes to Unaudited Condensed Consolidated Financial Statements.

____________________

*    Filed herewith.

#     Furnished herewith

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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 7, 2019	By:	/s/ D. Andrew Woodward
			D. Andrew Woodward
			Chief Financial Officer
Date:	November 7, 2019	By:	/s/ Michael McLanahan
			Michael McLanahan
			Chief Accounting Officer

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