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

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.

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

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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.

The Partnership records unearned revenues when cash payments are received in advance of performance. Unearned revenue related to contracts with customers was $~~5.9~~3.0 million and $~~5.7~~3.4 million at December 31, ~~2018~~2019, and ~~September~~June 30, ~~2019~~2020, respectively. ~~The change in~~For the ~~unearned revenue balance for the~~ ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020, ~~is driven by~~the Partnership recognized $~~3.2~~ ~~million in cash payments received in advance of satisfying performance obligations, partially offset by~~ ~~$3.4~~2.1 million of revenues ~~recognized~~ that were previously included in the unearned revenue ~~balance at the beginning of the period.~~balance.

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.

6.5.

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~~July 31, 2020, approximately $~~250.6~~261.6 million of revolver borrowings and $~~1.0~~1.8 million of letters of credit were outstanding under the credit agreement, leaving the Partnership with approximately $~~148.4~~136.6 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~~is limited by the financial covenants in the credit agreement. The proceeds of loans made under the credit agreement may be used for working capital and other general corporate purposes of the Partnership.

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

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

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

Borrowings under the credit agreement bear interest, at the Partnership’s option, at either the reserve-adjusted eurodollar rate (as defined in the credit agreement) plus an applicable margin that ranges from 2.0% to 3.25% 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;~~1.00; 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”).

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At ~~September~~June 30, ~~2019~~2020, the Partnership’s consolidated total leverage ratio was ~~4.24~~4.19 to 1.00 and the consolidated interest coverage ratio was ~~3.96~~5.07 to 1.00. The Partnership was in compliance with all covenants of its credit agreement as of ~~September~~June 30, ~~2019~~2020.

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~~the continued ability to comply with ~~our~~the 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~~the $~~258.6~~267.6 million in outstanding debt, as of ~~September~~June 30, ~~2019~~2020, 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.~~distribution. The Partnership is currently allowed to make distributions to its unitholders in accordance with this covenant; however, the Partnership will only make distributions to the extent it has sufficient cash from operations after establishment of cash reserves as determined by the Board 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 87 for additional information regarding distributions.

In addition to other customary events of default, the credit agreement includes an event of default if:

(i)

the general partner ceases to own 100% of the Partnership’s general partner interest or ceases to control the Partnership;

(ii)

Ergon ceases to own and control 50% or more of the membership interests of the general partner; or

(iii)

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

(A)

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

(B)

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

(C)

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

If an event of default relating to bankruptcy or other insolvency events occurs with respect to the general partner or the Partnership, all indebtedness under the credit agreement will immediately become due and payable. If any other event of default exists under the credit agreement, the lenders may accelerate the maturity of the obligations outstanding under the credit agreement and exercise other rights and remedies. In addition, if any event of default exists under the credit agreement, the lenders may commence foreclosure or other actions against the collateral.

If any default occurs under the credit agreement, or if the Partnership is unable to make any of the representations and warranties in the credit agreement, the Partnership will be unable to borrow funds or to have letters of credit issued under the credit agreement.

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Upon the execution of the 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~~June 30, 2019 and ~~2018~~2020, was $0.3 million. Interest expense related to debt issuance cost amortization for both the ~~nine~~six months ended ~~September~~June 30, ~~2018~~ 2019 and ~~2019~~,2020, was $~~0.8~~0.5 million.

During the three months ended ~~September~~June 30, ~~2018~~2019 and ~~2019~~2020, the weighted average interest rate under the Partnership’s credit agreement was ~~5.65%~~6.27% and ~~5.90%~~3.86%, respectively, resulting in interest expense of approximately $4.1 million and $~~4.0~~2.7 million, respectively. During the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2019~~2020, 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%~~6.35% and ~~6.20%~~4.37%, respectively, resulting in interest expense of approximately $~~12.6~~8.4 million and $~~12.3~~6.1 million, respectively.

~~The Partnership is exposed to market risk for changes in interest rates related to its credit agreement. Interest rate swap agreements are sometimes used to manage a portion~~

Table of ~~the exposure related to changing interest rates by converting floating-rate debt to fixed-rate debt. As of~~ ~~September 30, 2019~~Contents~~, 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 )

7.6.	NET INCOME PER LIMITED PARTNER UNIT

For purposes of calculating earnings per unit, preferred units, general partner units and common units are first allocated net income to the extent they receive a distribution. Next, 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~~its respective ownership ~~interest~~interests at the time. The remainder is allocated to the common units. The following sets forth the computation of basic and diluted net income per common unit (in thousands, except per unit data):

Three Months ended 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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	Three Months ended June 30,						Six Months ended June 30,
	2019			2020			2019			2020
Net income	$	3,356		$	1,351		$	7,113		$	1,351
General partner interest in net income		53			21			158			21
Preferred interest in net income		6,279			6,279			12,558			12,558
Net loss available to limited partners	$	(2,976	)	$	(4,949	)	$	(5,603	)	$	(11,228	)

Basic and diluted weighted average number of units:
Common units		40,715			41,035			40,696			41,025
Restricted and phantom units		1,076			1,441			904			1,212
Total units		41,791			42,476			41,600			42,237

Basic and diluted net loss per common unit	$	(0.07	)	$	(0.12	)	$	(0.13	)	$	(0.27	)

8.7.	PARTNERS’ CAPITAL AND DISTRIBUTIONS

On ~~October 17, 2019~~July 16, 2020, the Board approved a cash distribution of $0.17875 per outstanding preferred unit for the three months ended ~~September~~June 30, ~~2019~~2020. The Partnership will pay this distribution on ~~November~~August 14, ~~2019~~2020, to unitholders of record as of ~~November~~August 4, ~~2019~~2020. 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~~June 30, ~~2019~~2020. The Partnership will pay this distribution on ~~November~~August 14, ~~2019~~2020, to unitholders of record on ~~November~~August 4, ~~2019~~2020. 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~~approximately $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.

9.8.	~~RELATED-PARTY~~RELATED PARTY TRANSACTIONS

The Partnership leases asphalt facilities and provides asphalt terminalling services to Ergon. On April 3, 2020, Ergon purchased another customer of the Partnership, increasing the number of asphalt facilities under contract with Ergon from 23 to 28. For the three months ended ~~September~~June 30, ~~2018~~2019 and ~~2019~~2020, the Partnership recognized related-party revenues of $~~11.1~~8.8 million and $~~9.3~~10.9 million, respectively, for services provided to Ergon. For the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2019~~2020, the Partnership recognized related-party revenues of $~~38.6~~17.9 million and $~~27.2~~19.9 million, respectively, for services provided to Ergon. As of December 31, ~~2018~~2019, and ~~September~~June 30, ~~2019~~2020, the Partnership had receivables from Ergon of $~~1.0~~1.1 million and $~~1.8~~1.3 million, respectively. As of December 31, ~~2018~~2019, and ~~September~~June 30, ~~2019~~2020, the Partnership had unearned revenues from Ergon of $~~6.5~~5.1 million and $~~4.2~~7.2 million, respectively.

~~Effective April 1, 2018, the~~The Partnership ~~entered into~~has 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~~June 30, ~~2018~~2019 and ~~2019~~2020, the Partnership made purchases of crude oil under this agreement totaling $~~44.4~~36.1 million and $~~32.8~~16.6 million, respectively. For the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2019~~2020, the Partnership made purchases of crude oil under this agreement totaling $~~74.9~~65.8 million and $~~98.6~~44.4 million, respectively. As of ~~September~~June 30, ~~2019~~2020, the Partnership had payables to Ergon related to this agreement of $~~11.4~~8.4 million ~~related to~~for the ~~September~~June crude oil settlement cycle, and this balance was paid in full on ~~October 21, 2019.~~July 20, 2020.

~~The~~In May 2018, the Partnership, along with Kingfisher Midstream and Ergon, ~~have an agreement (the “Agreement”) that gives each party rights concerning~~announced the ~~purchase or sale~~execution of ~~Ergon’s interest in~~definitive agreements to form Cimarron ~~Express, subject to certain terms and conditions.~~Express. 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~~original anticipated in-service date in the second half of ~~2019~~.2019. Ergon formed a Delaware limited liability company, Ergon - Oklahoma Pipeline, LLC (“DEVCO”), which ~~holds~~held Ergon’s 50% membership interest in Cimarron Express. ~~Under~~The Partnership and Ergon had an agreement (the “Agreement”) that gave each party certain rights to obligate the ~~Agreement,~~counterparty to either sell or purchase the ~~Partnership has the right, at any time, to purchase 100% of the authorized and~~ outstanding ~~member~~membership interests in DEVCO ~~from Ergon~~ for ~~the Purchase Price (as defined in the Agreement), which shall be~~a purchase price computed by taking Ergon’s total investment in Cimarron Express plus interest, ~~by giving written notice~~subject to ~~Ergon (the “Call”). Ergon has the right to require the Partnership to purchase 100% of the authorized~~certain terms 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 Agreementconditions as ~~Exhibit B. Upon receipt of the Purchase Price, Ergon shall be obligated to convey 100% of the authorized and outstanding member interests~~described 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, theThe Partnership considered the SEC staff’s opinions outlined in SAB 107 Topic 5.T Accounting for Expenses or Liabilities Paid by Principal ~~Stockholders. The~~Stockholders, and, as 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,~~pipeline, 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,impairments on a push-down basis based on Ergon’s 50% interest in Cimarron Express. During 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~~six months ended June 30, 2019,~~. During~~ the ~~nine months ended September 30, 2019~~,Partnership recorded impairment expense of $1.9 million related to the Agreement, which included a change in estimate and accrued ~~interest resulted in the Partnership recording additional impairment expense of~~ ~~$2.0~~ ~~million.~~interest. The Partnership’s contingent liability as of ~~September 30,~~December 31, 2019,~~, consists~~ consisted of Ergon’s ~~$10.4~~$10.2 million investment plus accrued interest of ~~$1.7~~ ~~million, of which~~ ~~$0.4~~ ~~million relates to the three months ended~~ ~~September 30,~~$2.0 million. In November 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~~wound up the business, distributed assets, and dissolved Cimarron Express. On January 2, 2020, Ergon exercised its right under the Agreement to require the Partnership to purchase the outstanding member interest in DEVCO, and the Partnership paid the amount in full on January 3, 2020. This cash payment is reflected as an acquisition of DEVCO in the ~~process~~investing cash flows section on the Partnership’s condensed consolidated statement of ~~negotiating final agreements to windup~~cash flows for the ~~business, distribute the assets, and dissolve Cimarron Express.~~six months ended June 30, 2020.

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~~10.~~9.

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)		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		15,306	$	4.85	$	74
December 2018		23,436	$	1.20	$	28		23,436	$	1.20	$	28
December 2019								7,500	$	1.07	$	8

~~(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)		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		396,536	$	4.77	$	1,891
March 2019		524,997	$	1.14	$	598		524,997	$	1.14	$	598
June 2019		46,168	$	1.08	$	50		46,168	$	1.08	$	50
March 2020								600,396	$	0.90	$	540

(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~~June 30, ~~2019~~2020, was $~~1.1~~0.9 million, which will be expensed over the remaining vesting period.

The Partnership’s equity-based incentive compensation expense for both the three months ended ~~September~~June 30, ~~2018~~2019 and ~~2019~~2020, was $~~0.7~~ ~~million and~~ $0.3 ~~million, respectively.~~million. The ~~Partnership’s~~Partnership's equity-based incentive compensation expense for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2019~~2020, was $~~1.8~~0.6 million and $~~0.8~~0.5 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		Number of Units		Weighted Average Grant Date Fair Value
Nonvested at December 31, 2018		998,219	$	5.88
Nonvested at December 31, 2019						1,068,343	$	3.42
Granted		571,165		1.14		600,396		0.90
Vested		366,282		4.80		305,149		5.59
Forfeited		104,758		4.10		-		-
Nonvested at September 30, 2019		1,098,344	$	3.45
Nonvested at June 30, 2020						1,363,590	$	2.71

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

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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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., and (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~~2019, which was filed with the Securities and Exchange Commission (the “SEC”) on March ~~12, 2019~~26, 2020 (the “~~2018~~2019 Form 10-K”).

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~~2019 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.

We are a publicly traded master limited partnership with operations in 2726 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.

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,~~period, and other volatility in the overall energy industry, ~~and~~ specifically in ~~publicly traded~~the midstream energy ~~partnerships~~industry, 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~~July 31, 2020, the forward crude oil price curve is currently in a ~~shallow~~ contango. Potential impacts of these factors are discussed below.

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Due to the global pandemic related to the coronavirus disease, COVID-19, and the Organization of Petroleum Exporting Countries’ and Russia’s disagreements over production output, the energy market had historic drops in oil prices in March and April of 2020; however, prices rose during the second quarter of 2020 to near pre-COVID-19 levels. Despite this volatility in prices, our business is uniquely positioned and expected to benefit in certain areas, and cash flow for the full year is expected to remain stable in 2020. Our asphalt and crude oil terminalling services segments represented 104% of our operating margin for the six months ended June 30, 2020, and as of July 31, 2020, these segments are fully contracted with take-or-pay revenue that have a weighted average remaining term of 4.3 years. While our customers across all our segments could be impacted by the recent market volatility, they are primarily high-quality counterparties, with over 50% of our revenues earned from those that are investment grade quality, which minimizes our counterparty credit risk. As of July 31, 2020, we do not expect any supply chain disruptions from COVID-19 to affect our customers. Management is also actively monitoring the states and regions in which we operate, and, as of now, our operations are excluded from mandatory closings due to the essential designation of our assets. In addition, a large portion of our operating margin, approximately 84%, from the asphalt terminalling services business unit is related to infrastructure spending at the federal, state, and local levels, and the U.S. government has continued to indicate its support for infrastructure spending. At the same time, state revenue is down due to COVID-19, so we remain cautious about future spending on infrastructure and road construction absent an infrastructure bill passed by the federal government to support funding efforts. While we are unaware of any potential negative impact of COVID-19 on our business at this time, we are continuing to monitor the situation and have been preparing our employees to take precautions and planning for unexpected events, which may include disruptions to our workforce, customers, vendors, facilities and communities in which we operate. In an effort to protect the health and safety of our employees and the customers and vendors we interact with, we took proactive action to adopt social distancing policies at our locations, including working from home, limiting the number of employees attending meetings, reducing the number of people in our sites at any one time, and suspending employee travel.

Asphalt Terminalling Services - ~~Historically,~~While, 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~~oil, due to the steep decline in ~~the price of~~ crude oil ~~will necessarily~~prices earlier this year, asphalt prices also fell significantly before recovering. However, demand has held steady for road construction activity due to there being fewer vehicles on roads to interfere with construction work and the lower asphalt prices. This current environment is expected to have ~~a significant impact on~~more positive than negative implications for 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,~~As previously mentioned, the ~~level~~U.S. government continues to indicate supporting infrastructure spending in this time of economic uncertainty. Further, customers have communicated that infrastructure projects may be accelerated and increased during this time of decreased transportation volume on the roads and highways. While it is early in the asphalt season, customer throughput volumes ~~through our terminals~~ have ~~varied across~~generally been higher than 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 laterprior year. However, it is still too early in the season to ~~help make up~~determine the financial impact for ~~this. In addition, during~~ the ~~first half~~year.

At the end of ~~2019, several~~June 2020, a 40,000 barrel tank (less than 10% of facility capacity) caught fire at our Gloucester City, New Jersey, asphalt ~~facilities~~facility. The roof and top portion of the tank was damaged, but the asphalt product remained, undamaged, in the ~~Midwest were damaged by flooding. While the facilities were able~~tank. The facility remains operational, and we are making operational adjustments to ~~successfully execute flood plans~~continue to ~~minimize damages,~~fulfill our obligation to meet our customer’s needs. Initial costs ~~related to the floods~~ are ~~expected to include approximately~~ ~~$0.7~~estimated at $0.3 million ~~of expenses~~ for ~~cleanup and the removal and reinstallation of equipment and~~ ~~$1.9~~ ~~million of~~cleanup; 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~~repair the tank are still being assessed but we expect any to fit within our capital budget for the ~~assets was~~ ~~$0.3~~ ~~million. As of~~ ~~September 30, 2019, we have recognized~~ ~~$0.7~~ ~~million of~~year. We will pursue insurance ~~recoveries. While we are pursuing additional insurance claims~~recoveries for ~~these events,~~this event, but there can be no assurance of the amount or timing of any proceeds we may ~~receive under such claims.~~

Onreceive. As of 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 price31, 2020, the assessment into the cause of ~~$90.0 million, subject to customary adjustments.~~the fire is ongoing.

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~~From March 2016 through February 2020, the crude oil curve ~~has~~had 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~~Despite the ~~storage rate at which we are able to re-contract. Alternatively, despite a~~ shallow contango curve, we ~~have seen~~saw 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. AsIn late 2019, during recontracting efforts for 2020, the demand for storage declined and a ~~result~~small percentage of ~~this change~~tanks were not contracted. However, as the forward price curve moved into a deeper contango in March and April 2020, there was a significant increase in demand ~~factors~~ for crude oil storage in Cushing ~~storage, we anticipate a more complex recontracting environment~~and globally, which ~~has the potential to affect both the~~positively impacted contracted volumes and ~~rate~~rates in the second quarter of ~~our recontracting efforts.~~2020.

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~~our pipeline system may be impacted by the market price of crude oil and producers’ decisions to increase or decrease production in the areas we serve. With the historic drop in crude oil prices earlier this year, the outlook for increased drilling activity remains challenging and the risk is higher for potential well shut-ins in this environment.

~~Over the past year, we increased the volumes of crude oil transported for~~In 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 While prices have recovered in the second quarter of 2020, due to the historic drop in oil prices in March and April ~~24, 2018,~~2020 and continued uncertainty in the market, customers could have wells shut-in or request rate decreases, which could impact our revenues and operating margin. In the second quarter of 2020, we ~~sold~~evaluated our ~~producer field services business, which has been historically reported along with the~~ crude oil trucking ~~services.~~services for impairment and, based on expected future cash flows, recorded asset impairment expense of $1.3 million, consisting of $1.1 million related to plant, property and equipment and $0.2 million related to operating right-of-use assets.

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Our revenues consist of (i) terminalling revenues, (ii) gathering and transportation revenues, (iii) product sales revenues and (iv) fuel surcharge revenues. For the ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020, the Partnership recognized revenues of $~~27.2~~ ~~million and~~ ~~$0.3~~19.9 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 and operating lease 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. On April 3, 2020, Ergon purchased another customer of the Partnership, increasing the number of asphalt facilities under contract with ~~Ergon. These~~Ergon from 23 to 28. As of July 31, 2020, these agreements have, based on a weighted average by remaining fixed revenue, approximately ~~3.8~~4.4 years remaining under their terms. ~~While~~On August 4, 2020, we entered into a new agreement with Ergon that replaces and consolidates three previous agreements ~~with one customer for four~~and extends the term to December 31, 2027. Consideration of the ~~facilities expire by~~term under the new agreement increases the weighted average remaining term to 6.2 years. One agreement, representing less than 1% of asphalt terminalling segment revenues, expires at the end of ~~2019, we have commercially agreed to all terms on a new contract with~~2020, and 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.~~through 2027. 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,~~July 31, 2020, we had approximately ~~5.2~~5.5 million barrels of crude oil storage under service contracts, including ~~2.5~~2.8 million barrels of crude oil storage contracts that expire in ~~2019~~2020. 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~~2020 range from 38 to 2617 months. Storage contracts with a subsidiary of Vitol Group (together with its subsidiaries, “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;~~2020; 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):

Volumes have decreased in both pipeline and trucking transportation due to decreased drilling activities in the areas we serve. In ~~July 2018, we restored service on an out-of-service~~addition, a significant pipeline customer, Vitol, entered into a joint venture with a pipeline in the same area and in late 2019 began moving a significant 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.~~their volumes to this competing pipeline. Vitol accounted for ~~27%~~ ~~and~~ ~~28%~~40% of volumes transported on our pipelines in both the three and six months ended ~~September~~June 30, ~~2018 and~~ 2019~~, respectively.~~. Vitol accounted for ~~37%~~ ~~and~~ ~~38%~~7% of volumes transported on our pipelines in both the three and ~~nine~~six months ended ~~September~~June 30, ~~2018 and 2019~~2020~~, 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.

Operating expenses decreased by ~~10%~~7% for the ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020, as compared to the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019~~. In addition~~, due to decreases ~~related to the sale~~in compensation expense, utility costs and maintenance repairs expense as a result of ~~the three asphalt plants~~a focus on managing costs as well as a decrease 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.~~expense. General and administrative expenses ~~decreased~~increased by ~~19%~~14% for the ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020, as compared to the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019. The ~~decrease~~increase is primarily due to ~~decreased compensation and professional fees expense,~~separation expenses related to the resignation of the former Chief Executive Officer of our General Partner incurred during the six months ended June 30, 2020, as well as the receipt during the six months ended June 30, 2019, 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~~ our 2018 Form 10-K, which ~~were offset by~~reduced expenses ~~related to the Ergon buyout offer of $0.4 million.~~for that period. Our interest expense decreased by 2%27% for the ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020, as compared to the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019. 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~~2020.

Table 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;~~

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~~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~~July 16, 2020, the Board approved a cash distribution of $0.17875 per outstanding preferred unit for the three months ended ~~September~~June 30, ~~2019~~2020. We will pay this distribution on ~~November~~August 14, ~~2019~~2020, to unitholders of record as of ~~November~~August 4, ~~2019~~2020. 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~~June 30, ~~2019~~2020. We will pay this distribution on ~~November~~August 14, ~~2019~~2020, to unitholders of record onas of ~~November~~August 4, ~~2019~~2020. 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~~approximately $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.

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Results of Operations

Non-GAAP Financial Measures

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

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

The table below summarizes our financial results for the three and ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2019~~2020, reconciled to the most directly comparable GAAP measure:

	Three Months ended						Nine Months ended						Favorable/(Unfavorable)												Three Months ended						Six Months ended						Favorable/(Unfavorable)
Operating results	September 30,						September 30,						Three Months						Nine Months						June 30,						June 30,						Three Months						Six Months
(dollars in thousands)	2018			2019			2018			2019			$			%			$			%			2019			2020			2019			2020			$			%			$			%
Operating margin, excluding depreciation and amortization:
Asphalt terminalling services	$	17,625		$	17,123		$	49,621		$	44,433		$	(502	)		(3	)%	$	(5,188	)		(10	)%	$	13,792		$	14,307		$	27,308		$	27,965		$	515			4	%	$	657			2	%
Crude oil terminalling services		1,226			3,291			6,730			9,161			2,065			168	%		2,431			36	%		3,281			4,053			5,871			6,504			772			24	%		633			11	%
Crude oil pipeline services		(506	)		618			(1,137	)		2,757			1,124			222	%		3,894			342	%		325			(2,701	)		2,139			(1,170	)		(3,026	)		(931	)%		(3,309	)		(155	)%
Crude oil trucking services		(116	)		133			(601	)		143			249			215	%		744			124	%		69			(212	)		11			(62	)		(281	)		(407	)%		(73	)		(664	)%
Total operating margin, excluding depreciation and amortization		18,229			21,165			54,613			56,494			2,936			16	%		1,881			3	%		17,467			15,447			35,329			33,237			(2,020	)		(12	)%		(2,092	)		(6	)%

Depreciation and amortization		(7,166	)		(6,240	)		(21,945	)		(19,211	)		926			13	%		2,734			12	%		(6,237	)		(6,166	)		(12,971	)		(12,260	)		71			1	%		711			5	%
General and administrative expense		(4,322	)		(3,840	)		(13,029	)		(10,495	)		482			11	%		2,534			19	%		(2,962	)		(4,068	)		(6,655	)		(7,608	)		(1,106	)		(37	)%		(953	)		(14	)%
Asset impairment expense		(15	)		(83	)		(631	)		(2,316	)		(68	)		(453	)%		(1,685	)		(267	)%		(1,114	)		(1,295	)		(2,233	)		(6,417	)		(181	)		(16	)%		(4,184	)		(187	)%
Gain (loss) on sale of assets		(63	)		(40	)		300			1,765			23			37	%		1,465			488	%
Gain(loss) on disposal of assets																										81			102			1,805			(83	)		21			26	%		(1,888	)		(105	)%
Operating income		6,663			10,962			19,308			26,237			4,299			65	%		6,929			36	%		7,235			4,020			15,275			6,869			(3,215	)		(44	)%		(8,406	)		(55	)%

Other income (expenses):
Other income		-			-			-			268			-			0	%		268			N/A			268			44			268			602			(224	)		(84	)%		334			125	%
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	%		(4,134	)		(2,714	)		(8,405	)		(6,113	)		1,420			34	%		2,292			27	%
Provision for income taxes		(165	)		(14	)		(215	)		(39	)		151			92	%		176			82	%		(13	)		1			(25	)		(7	)		14			108	%		18			72	%
Net income	$	2,408		$	6,959		$	8,635		$	14,072		$	4,551			189	%	$	5,437			63	%	$	3,356		$	1,351		$	7,113		$	1,351		$	(2,005	)		(60	)%	$	(5,762	)		(81	)%

For the three and ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020, overall operating margin, excluding depreciation and amortization, ~~increased compared to~~was lower than the same period in ~~2018~~2019. ~~Our~~Margins in our asphalt terminalling ~~services~~ segment ~~operating margin, excluding depreciation and amortization, was impacted by both~~were in-line with 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~~prior year, crude oil terminalling services ~~operating margin, excluding depreciation and amortization, is primarily~~was higher due to ~~an increase in rented~~favorable spot storage ~~capacity. Margins in our~~contacts and higher throughput volumes versus the prior year. The crude oil pipeline services segment ~~reflect the recovery~~reflects an unrealized derivative charge of ~~throughput volumes since the restoration of a portion of our Oklahoma system in July 2018,~~$3.6 million 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~~.forward purchase contracts. Crude oil trucking services operating margin, excluding depreciation and amortization, ~~improved~~decreased for the three and ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020, due to ~~improved rates beginning in the fourth quarter of 2018 and longer length of hauls transported.~~decreased transportation volumes.

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

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Table of Contents

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)												Three Months ended				Six Months ended				Favorable/(Unfavorable)
Operating results	September 30,				September 30,				Three Months						Nine Months						June 30,				June 30,				Three Months						Six Months
(dollars in thousands)	2018		2019		2018		2019		$			%			$			%			2019		2020		2019		2020		$			%			$			%
Service revenue:
Third-party revenue	$	6,921	$	7,385	$	18,693	$	21,217	$	464			7	%	$	2,524			14	%	$	6,850	$	6,834	$	13,831	$	13,689	$	(16	)		(0	)%	$	(142	)		(1	)%
Related-party revenue		5,211		3,892		17,512		11,991		(1,319	)		(25	)%		(5,521	)		(32	)%		3,981		4,064		8,098		8,141		83			2	%		43			1	%
Lease revenue:
Third-party revenue		11,288		11,444		30,762		31,026		156			1	%		264			1	%		9,819		8,095		19,582		17,926		(1,724	)		(18	)%		(1,656	)		(8	)%
Related-party revenue		5,406		5,427		20,584		15,179		21			0	%		(5,405	)		(26	)%		4,812		6,828		9,752		11,749		2,016			42	%		1,997			20	%
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	)%		25,462		25,821		51,263		51,505		359			1	%		242			0	%
Operating expense, excluding depreciation and amortization		11,683		11,025		38,412		34,980		658			6	%		3,432			9	%		11,670		11,514		23,955		23,540		156			1	%		415			2	%
Operating margin, excluding depreciation and amortization	$	17,625	$	17,123	$	49,621	$	44,433	$	(502	)		(3	)%	$	(5,188	)		(10	)%	$	13,792	$	14,307	$	27,308	$	27,965	$	515			4	%	$	657			2	%

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

	•	Total revenue ~~decreased~~was consistent for the three and ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020, as compared to the three and ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019. Annual CPI index increases in our long-term contracts were offset by lower reimbursement revenue from improved fuel and power costs compared to prior year. The ~~sale~~movement of ~~the three asphalt facilities~~lease revenue from third-party to related-party was due to Ergon purchasing another customer of ours in ~~July 2018 resulted in a decrease of revenue of~~ ~~$1.2~~ ~~million and~~ ~~$10.8~~ ~~million~~April 2020.
	•	Operating expenses were also consistent 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~~six months ended ~~September~~June 30, ~~2019~~2020, as compared to the three and ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019. ~~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~~Improved fuel and power 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~~primarily related to ~~the acquisition~~increases in ~~March 2018, net flood-related expenses of~~ ~~$0.2~~ ~~million, and increased compensation costs at some facilities.~~

insurance premiums.

Table of Contents

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)												Three Months ended				Six Months ended				Favorable/(Unfavorable)
Operating results	September 30,				September 30,				Three Months						Nine Months						June 30,				June 30,				Three Months						Six Months
(dollars in thousands)	2018		2019		2018		2019		$			%			$			%			2019		2020		2019		2020		$			%			$			%
Service revenue:
Third-party revenue	$	1,923	$	4,225	$	9,418	$	11,819	$	2,302			120	%	$	2,401			25	%	$	4,020	$	5,096	$	7,594	$	8,425	$	1,076			27	%	$	831			11	%
Intersegment revenue		222		278		392		853		56			25	%		461			118	%		278		-		576		-		(278	)		(100	)%		(576	)		(100	)%
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	%		4,298		5,096		8,170		8,425		798			19	%		255			3	%
Operating expense, excluding depreciation and amortization		928		1,212		3,115		3,511		(284	)		(31	)%		(396	)		(13	)%		1,017		1,043		2,299		1,921		(26	)		(3	)%		378			16	%
Operating margin, excluding depreciation and amortization	$	1,226	$	3,291	$	6,730	$	9,161	$	2,065			168	%	$	2,431			36	%	$	3,281	$	4,053	$	5,871	$	6,504	$	772			24	%	$	633			11	%

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	%		5,895		5,799		5,665		5,355		(96	)		(2	)%		(310	)		(5	)%
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	%		91		111		81		89		20			22	%		8			10	%

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

•

Total revenues for the three and ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020, increased as compared to the same ~~period~~periods in ~~2018~~2019 despite lower contracted volumes due to ~~an increase~~increases in ~~rented storage capacity~~demand and ~~an increase in crude oil delivered through~~rates driven by the ~~terminal.~~contango market, including short-term contracts executed during the quarter that generated $0.8 million, as well as increased throughput volumes.

•

Operating expenses for the three ~~and nine~~ months ended ~~September~~June 30, 2020, were consistent with the same period in 2019, while operating expenses for the six months ended June 30, 2020, ~~increased~~decreased compared to the ~~three and nine~~six months ended ~~September~~June 30, ~~2018~~2019. Decreases due to ~~an increase~~a decrease in tank repair ~~expenses.~~

expenses were partially offset by higher compensation cost and increases in insurance premiums.

•

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Crude oil pipeline services segment

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

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

	Three Months ended					Nine Months ended					Favorable/(Unfavorable)												Three Months ended					Six Months ended					Favorable/(Unfavorable)
Operating results	September 30,					September 30,					Three Months						Nine Months						June 30,					June 30,					Three Months						Six Months
(dollars in thousands)	2018			2019		2018			2019		$			%			$			%			2019		2020			2019		2020			$			%			$			%
Service revenue:
Third-party revenue	$	1,165		$	1,284	$	4,270		$	5,753	$	119			10	%	$	1,483			35	%	$	1,972	$	375		$	4,470	$	877		$	(1,597	)		(81	)%	$	(3,593	)		(80	)%
Related-party revenue		185			64		268			266		(121	)		(65	)%		(2	)		(1	)%		101		-			203		-			(101	)		(100	)%		(203	)		(100	)%
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	%		59,636		20,626			118,560		67,678			(39,010	)		(65	)%		(50,882	)		(43	)%
Total revenue		99,153			56,561		151,872			179,792		(42,592	)		(43	)%		27,920			18	%		61,709		21,001			123,233		68,555			(40,708	)		(66	)%		(54,678	)		(44	)%
Operating expense, excluding depreciation and amortization		3,094			2,638		8,420			8,109		456			15	%		311			4	%		2,749		2,328			5,471		4,451			421			15	%		1,020			19	%
Intersegment operating expense		1,644			1,642		3,243			4,971		2			0	%		(1,728	)		(53	)%		1,704		1,505			3,331		2,930			199			12	%		401			12	%
Third-party cost of product sales		50,815			18,972		73,493			64,069		31,843			63	%		9,424			13	%		20,510		7,079			45,097		21,300			13,431			65	%		23,797			53	%
Related-party cost of product sales		44,106			32,691		67,853			99,886		11,415			26	%		(32,033	)		(47	)%		36,421		12,790			67,195		41,044			23,631			65	%		26,151			39	%
Operating margin, excluding depreciation and amortization	$	(506	)	$	618	$	(1,137	)	$	2,757	$	1,124			222	%	$	3,894			342	%	$	325	$	(2,701	)	$	2,139	$	(1,170	)	$	(3,026	)		(931	)%	$	(3,309	)		(155	)%

Pipeline transportation services average throughput volume (in thousands of barrels per day)		23			23		22			31		-			0	%		9			41	%		32		16			34		16			(16	)		(50	)%		(18	)		(53	)%

Crude oil marketing volumes (in thousands of barrels per day)		15			11		8			11		(4	)		(27	)%		3			38	%		11		13			12		12			2			18	%		0			0	%

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.

	•	Included in third-party cost of product sales for the three and six months ended June 30, 2020, is the unrealized loss on our commodity derivative contracts of $3.6 million, which is contributing to the negative operating margin, excluding depreciation and amortization for those periods as revenue associated with the contracts has not been recognized as of June 30, 2020. These contracts will settle with our final purchase in August 2020. The subsequent sale of this inventory is expected to result in gains that exceed our cumulative unrealized losses on our derivative contracts, which will have a positive impact on operating margin, excluding depreciation and amortization in the third quarter.
	•	~~Total throughput~~Throughput volumes ~~are consistent~~and related service revenue have decreased for the three ~~month comparative~~and six months ended June 30, 2020, as compared to the same periods ~~while the increase~~in 2019 due to decreased drilling activities in the ~~nine month comparative periods is due~~areas we serve. In addition, a significant pipeline customer, Vitol, entered into a joint venture with a pipeline in the same area and moved a significant portion of their volumes to this competing pipeline beginning in late 2019. Vitol accounted for 40% of volumes transported on our pipelines in both ~~increased~~the three and six months ended June 30, 2019. Vitol accounted for 7% of volumes transported on our pipelines in both the three and six months ended June 30, 2020.
	•	Product sales revenue for the six months ended June 30, 2019 and 2020, included $0.8 million and $1.5 million, respectively, in sales of crude oil ~~marketing activities and the restored service on the Oklahoma pipeline system. In addition to the increase~~product accumulated over time through customer loss allowance deductions. The remaining change in ~~volume, operating margins were positively impacted by improved margins on the crude oil marketing activities. Throughput volumes~~product sales revenue is related to ~~the~~our crude oil marketing business ~~were approximately~~ ~~11,000~~ ~~barrels per day, or approximately~~ ~~48%~~and ~~35%~~ ~~of total throughput, for both~~reflects 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~~decrease in the ~~three and nine months ended September 30, 2019, respectively, that is not reflected in revenues in~~market price of crude oil.
	•	With consideration of 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~~impact of the unrealized loss on our commodity derivative contracts noted above, overall cost of product sales ~~are all due to changes in our~~has decreased consistently with crude oil marketing ~~business.~~ revenue and reflect the decrease in the market price of crude oil.

Table of Contents

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)												Three Months ended					Six Months ended					Favorable/(Unfavorable)
Operating results	September 30,					September 30,					Three Months						Nine Months						June 30,					June 30,					Three Months						Six Months
(dollars in thousands)	2018			2019		2018			2019		$			%			$			%			2019		2020			2019		2020			$			%			$			%
Service revenue
Third-party revenue	$	2,734		$	2,822	$	11,783		$	8,540	$	88			3	%	$	(3,243	)		(28	)%	$	2,885	$	1,523		$	5,718	$	4,066		$	(1,362	)		(47	)%	$	(1,652	)		(29	)%
Intersegment revenue		1,422			1,364		2,851			4,118		(58	)		(4	)%		1,267			44	%		1,426		1,505			2,755		2,930			79			6	%		175			6	%
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	)%		4,311		3,028			8,473		6,996			(1,283	)		(30	)%		(1,477	)		(17	)%
Operating expense, excluding depreciation and amortization		4,303			4,053		15,405			12,515		250			6	%		2,890			19	%		4,242		3,240			8,462		7,058			1,002			24	%		1,404			17	%
Operating margin, excluding depreciation and amortization	$	(116	)	$	133	$	(601	)	$	143	$	249			215	%	$	744			124	%	$	69	$	(212	)	$	11	$	(62	)	$	(281	)		(407	)%	$	(73	)		(664	)%

Average volume (in thousands of barrels per day)		29			25		26			26		(4	)		(14	)%		-			0	%		27		19			27		21			(8	)		(30	)%		(6	)		(22	)%

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~~three and six months ended ~~September~~June 30, ~~2019~~2020, as compared to the ~~nine~~three and six months ended ~~September~~June 30, ~~2018~~2019, by ~~$2.7~~ ~~million~~ due to decreased drilling activities in 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.~~areas we serve.

•

Operating expense, excluding depreciation and amortization, decreased for the three and ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020, as compared to the three and ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019, by ~~$2.9~~ ~~million~~ due to decreases in compensation and fleet expense related to lower volumes. The decrease in volumes led to severance costs of $0.2 million in the ~~sale~~second quarter of ~~our producer field services business.~~

2020 to better manage costs.

~~Table of Contents~~

Other Income and Expenses

Depreciation and amortization expense. Depreciation and amortization expense ~~decreased~~ by ~~$1.0~~ ~~million to~~was consistent at $6.2 million for the three months ended ~~September~~June 30, ~~2019, compared to~~ ~~$7.2~~2020 ~~million for the three months ended~~and ~~September 30, 2018~~2019. Depreciation and amortization expense decreased by ~~$2.7~~ ~~million~~ to $~~19.2~~12.3 million for the ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020, compared to $~~21.9~~13.0 million for the same period in ~~nine months ended September 30, 2018~~2019. ~~These decreases are~~This decrease is primarily the result of certain assets reaching the end of their depreciable ~~lives.~~lives at the end of the first quarter of 2019.

General and administrative expense. General and administrative expense increased to ~~decreased~~$4.1 million for ~~the~~ three ~~and nine~~ months ended ~~September~~June 30, ~~2019~~2020, compared to $3.0 million for the same ~~periods~~period in ~~2018~~2019, and to $7.6 ~~primarily~~million for the six months ended June 30, 2020, compared to $6.7 million for the same period in 2019. These increases were due to ~~decreases in compensation~~transaction-related legal costs and ~~professional fees expense~~separation expenses related to the resignation of the former Chief Executive Officer of our General Partner incurred during the six months ended June 30, 2020, as well as the ~~impact~~receipt during the six months ended June 30, 2019, 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. Expense related to this payment of $0.9 million was recognized~~system as disclosed in ~~the three months ended September 30,~~our 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.Form 10-K, which reduced expense for that period.

Asset impairment expense. Asset impairment expense for the three ~~and~~ ~~nine~~ months ended ~~September~~June 30, 2020, of $1.3 million related to adjustments to our crude oil trucking services segment assets based on the expected future cash flows of the segment. This impairment consisted of $1.1 million related to plant, property and equipment and $0.2 million related to operating right-of-use assets. In addition, asset impairment expense for the six months ended June 30, 2020, included $5.1 million primarily consisting of a write-down of crude oil linefill due to the decrease in the market price of crude oil that occurred in the first quarter. Asset impairment expense for the six months ended June 30, 2019, ~~included~~was $2.2 million, and consisted of a change in estimate ~~and accrued interest related to~~of the push-down impairment ofrelated to Cimarron Express Pipeline, LLC (“Cimarron Express”) of $1.9 million (see Note ~~9 to~~8 of 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~~$0.3 million related to ~~the value of obsolete trucking stations and $0.2 million related to~~a flood at an ~~intangible customer contract asset that was not renewed.~~asphalt terminal in Wolcott, Kansas.

~~Gain (loss)~~Gain(loss) on ~~sale~~disposal of ~~assets.~~ assets~~Gain~~. Gains and losses for the three and six months ended June 30, 2020, are immaterial and relate to the disposal of assets no longer used for operations. Gains on the sale of assets ~~was~~ ~~$1.8~~ ~~million~~ for the ~~nine~~six months ended ~~September~~June 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,~~all periods relates to insurance recoveries related to flood damages incurred in 2019 at certain asphalt facilities.

~~Gain on sale~~

Table 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.

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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.~~costs. The following table presents the significant components of interest expense:

	Three Months ended					Nine Months ended						Favorable/(Unfavorable)												Three Months ended				Six Months ended				Favorable/(Unfavorable)
	September 30,					September 30,						Three Months						Nine Months						June 30,				June 30,				Three Months						Six Months
	2018			2019		2018			2019			$			%			$			%			2019		2020		2019		2020		$			%			$			%
Credit agreement interest	$	3,815		$	3,714	$	11,856		$	11,585		$	101			3	%	$	271			2	%	$	3,861	$	2,440	$	7,871	$	5,572	$	1,421			37	%	$	2,299			29	%
Amortization of debt issuance costs		251			251		764			753			-			0	%		11			1	%		251		251		503		502		-			0	%		1			0	%
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	)%		22		23		31		39		(1	)		(5	)%		(8	)		(26	)%
Total interest expense	$	4,090		$	3,989	$	12,683		$	12,394		$	101			2	%	$	289			2	%	$	4,134	$	2,714	$	8,405	$	6,113	$	1,420			34	%	$	2,292			27	%

The decrease in credit agreement interest is due to a decrease in floating interest rates.

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~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2019~~2020:

	Nine Months ended September 30,						Six Months ended June 30,
	2018			2019			2019			2020
	(in millions)						(in millions)
Net cash provided by operating activities	$	28.2		$	38.3		$	22.9		$	23.2
Net cash provided by (used in) investing activities	$	44.0		$	(2.3	)	$	0.1		$	(17.3	)
Net cash provided by (used in) financing activities	$	(72.7	)	$	(34.6	)	$	(23.0	)	$	(5.5	)

Operating Activities. Net cash provided by operating activities increased to $~~38.3~~23.2 million for the ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020, as compared to $~~28.2~~22.9 million for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019, 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~~17.3 million for the ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020, compared to net cash provided by investing activities of $~~44.0~~0.1 million for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019. The ~~nine~~six months ended ~~September~~June 30, 2020, included a $12.2 million payment to Ergon related to our purchase of Ergon’s DEVCO entity related to Cimarron Express. The six months ended June 30, 2019, included net proceeds from the ~~sale~~disposal of certain assets of $~~7.1~~6.4 million. Of such proceeds, ~~$2.6~~$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~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2019~~2020, included maintenance capital expenditures of $~~6.0~~5.2 million and $~~7.4~~5.3 million, respectively, and expansion capital expenditures of $~~23.6~~1.1 million and $~~2.0~~1.4 million, respectively.

Financing Activities. Net cash used in financing activities was $~~34.6~~5.5 million for the ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020, ~~and~~compared to $~~72.7~~23.0 million for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019. Cash used in financing activities for the ~~nine~~six months ended ~~September~~June 30, 2020, consisted primarily of $16.2 million in distributions to our unitholders, partially offset by net borrowings on long-term debt of $12.0 million. Cash used in financing activities for the six months ended June 30, 2019, consisted primarily of net payments on long-term debt of $~~7.0~~4.0 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~~17.8 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~~June 30, ~~2019~~2020, we had a working capital deficit of $~~8.7~~11.1 million. This is primarily a function of our approach to cash management. At ~~September~~June 30, ~~2019~~2020, we had approximately $~~140.4~~267.6 million of revolver borrowings and approximately $1.8 million of letters of credit outstanding under the credit agreement, leaving us with approximately $130.6 million of availability under our credit agreement subject to covenant restrictions, which limited our availability to $~~46.4~~36.0 million. As of ~~November 1, 2019~~July 31, 2020, we have approximately $261.6 million of revolver borrowings and approximately $1.8 million of letters of credit outstanding under the credit agreement, leaving us with aggregate unused commitments under our revolving credit facility of approximately $~~148.4~~136.6 million and cash on hand of approximately $~~1.1~~0.6 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.

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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~~June 30, ~~2019~~2020, ~~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.~~thereafter, is 4.75. Our consolidated total leverage ratio was ~~4.24~~4.19 to 1.00 as of ~~September~~June 30, ~~2019~~2020.

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 itwe 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~~267.6 million in outstanding debt, as of ~~September~~June 30, ~~2019~~2020, 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~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2019~~2020 (in thousands):

	Nine Months ended September 30,						Six Months ended June 30,
	2018			2019			2019			2020
Acquisitions		21,959			-		$	-		$	12,221

Gross expansion capital expenditures		23,617			1,969		$	1,081		$	1,404
Reimbursable expenditures		(338	)		(61	)		(21	)		(130	)
Net expansion capital expenditures		23,279			1,908		$	1,060		$	1,274

Gross maintenance capital expenditures		5,943			7,459		$	5,159		$	5,282
Reimbursable expenditures		(572	)		(202	)		(30	)		(990	)
Net maintenance capital expenditures		5,371			7,257		$	5,129		$	4,292

We currently expect our expansion capital expenditures for organic growth projects to be approximately $~~3.5~~2.2 million to $~~4.5~~2.6 million for all of ~~2019~~2020. We currently expect maintenance capital expenditures to be approximately $~~9.0~~7.8 million to $~~10.0~~8.2 million, net of reimbursable expenditures, for all of ~~2019~~2020.

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.

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Recent Accounting Pronouncements

For information regarding recent accounting developments that may affect our future financial statements, see Note 1713 to our unaudited condensed consolidated financial statements.

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Other Items

Commodity Derivative Agreements

During the second quarter of 2020, our internal crude oil marketing department entered into crude oil forward purchase contracts through sell/buy arrangements with a counterparty to facilitate spot storage deals in our Cushing terminal with such counterparty during a time of favorable contango spreads. Our crude oil marketing department only holds working inventory and linefill and does not hold excess inventory for speculative purposes. Typically, each month's purchase and sale volumes, including those under the sell/buy arrangements, are similar and at the current month market price; thus, the Partnership is not exposed to additional commodity price risk beyond its normal marketing activity. These contracts are structured such that final purchase settlement will occur during the third quarter of 2020 at then market prices. That product will then be sold to a separate counterparty at then market prices; thus, effectively removing the commodity price risk. These contracts are carried at fair value on our consolidated balance sheets and are valued based on quoted prices in active markets.

I~~tem~~Item 3. Quantitative and Qualitative Disclosures about Market ~~Risk.~~Risk

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

AsItem 305(e) 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%Regulation S-K (§ 229.305(e)) 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%~~Partnership is not required to provide the information required by this Item as it is a “smaller reporting company,” as defined by Rule 229.10(f)(1).

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~~June 30, ~~2019~~2020, were effective. The Chief Executive Officer of our General Partner was also acting Chief Financial Officer of our General Partner at June 30, 2020.

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~~June 30, ~~2019~~2020, 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 1513 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~~2019.

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).
10.1		Separation Agreement and General Release of Claims, dates as of June 22, 2020, between Mark Hurley and the Partnership (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, filed on June 22, 2020, 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~~and acting Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1#		Certification of Chief Executive Officer and acting 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~~June 30, ~~2019~~2020, formatted in XBRL (eXtensible Business Reporting Language): (i) Document and Entity Information; (ii) Unaudited Condensed Consolidated Balance Sheets as of December 31, ~~2018~~2019 and ~~September~~June 30, ~~2019~~2020; (iii) Unaudited Condensed Consolidated Statements of Operations for the three and ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2019~~2020; (iv) Unaudited Condensed Consolidated Statement of Changes in Partners’ Capital (Deficit) for the three and ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2019~~2020; (v) Unaudited Condensed Consolidated Statements of Cash Flows for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2019~~2020; 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~~August 6, 2020	By:	/s/ D. Andrew Woodward
			D. Andrew Woodward
			Chief Executive Officer and acting Chief Financial Officer

Date:	~~November 7, 2019~~August 6, 2020	By:	/s/ Michael McLanahan
			Michael McLanahan
			Chief Accounting Officer

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

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			As of			As of			As of
	December 31, 2018			September 30, 2019			December 31, 2019			June 30, 2020
	(unaudited)						(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	1,455		$	2,777		$	558		$	1,042
Accounts receivable, net		35,683			25,913			23,716			21,273
Receivables from related parties, net		1,043			1,873			1,110			1,257
Other current assets		9,345			7,774			8,692			8,405
Total current assets		47,526			38,337			34,076			31,977
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
Property, plant and equipment, net of accumulated depreciation of $274,404 and $283,565 at December 31, 2019, and June 30, 2020, respectively								232,777			222,947
Goodwill		6,728			6,728			6,728			6,728
Debt issuance costs, net		3,349			2,595			2,344			1,842
Operating lease assets		-			11,374			10,758			9,634
Intangible assets, net		16,834			14,775			14,088			12,715
Other noncurrent assets		606			1,348			1,169			1,194
Total assets	$	323,304		$	313,975		$	301,940		$	287,037
LIABILITIES AND PARTNERS’ CAPITAL
LIABILITIES AND PARTNERS’ CAPITAL(DEFICIT)
Current liabilities:
Accounts payable	$	3,707		$	4,036		$	3,125		$	3,303
Accounts payable to related parties		2,263			3,306			2,460			2,728
Accrued crude oil purchases		13,949			6,465			6,706			3,831
Accrued crude oil purchases to related parties		10,219			11,438			11,807			8,369
Contingent liability with related party (Note 8)								12,221			-
Accrued interest payable		465			289			293			226
Accrued property taxes payable		3,089			3,701			3,247			2,657
Unearned revenue		3,206			5,476			1,942			2,675
Unearned revenue with related parties		4,835			2,624			2,934			4,193
Accrued payroll		3,667			3,836			4,823			4,186
Current operating lease liability		-			2,479			2,391			2,153
Commodity derivative liability								-			3,589
Other current liabilities		3,465			3,352			2,627			5,172
Total current liabilities		48,865			47,002			54,576			43,082
Long-term unearned revenue with related parties		1,714			1,545			2,149			2,964
Other long-term liabilities		4,010			3,708			2,417			1,343
Noncurrent operating lease liability		-			8,968			8,529			7,734
Contingent liability with related party (Note 9)		10,019			12,061
Long-term debt		265,592			258,592			255,592			267,592
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
Commitments and contingencies (Note 12)
Partners’ capital(deficit):
Common unitholders (40,830,051 and 41,036,094 units issued and outstanding at December 31, 2019, and June 30, 2020, respectively)								356,777			342,651
Preferred Units (35,125,202 units issued and outstanding at both dates)		253,923			253,923			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	)		(632,023	)		(632,252	)
Total partners’ deficit		(6,896	)		(17,901	)		(21,323	)		(35,678	)
Total liabilities and partners’ deficit	$	323,304		$	313,975		$	301,940		$	287,037

	Common Unitholders			Series A Preferred Unitholders			General Partner Interest			Total Partners’ Capital (Deficit)			Common Unitholders			Series A Preferred Unitholders			General Partner Interest			Total Partners’ Capital (Deficit)
	(unaudited)												(unaudited)
Balance, June 30, 2018	$	436,416		$	253,923		$	(703,704	)	$	(13,365	)
Balance, March 31, 2019													$	365,220		$	253,923		$	(631,882	)	$	(12,739	)
Net income (loss)		(3,910	)		6,279			39			2,408			(2,976	)		6,279			53			3,356
Equity-based incentive compensation		656			-			9			665			289			-			5			294
Distributions		(3,319	)		(6,279	)		(156	)		(9,754	)		(1,672	)		(6,279	)		(128	)		(8,079	)
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	)	$	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	)	$	370,972		$	253,923		$	(631,791	)	$	(6,896	)
Net income (loss)		(4,983	)		18,836			219			14,072			(5,557	)		12,558			112			7,113
Equity-based incentive compensation		637			-			15			652			353			-			10			363
Distributions		(6,658	)		(18,836	)		(411	)		(25,905	)		(4,980	)		(12,558	)		(283	)		(17,821	)
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	)
Proceeds from sale of 63,340 common units pursuant to the Employee Unit Purchase Plan														73			-			-			73
Balance, June 30, 2019													$	360,861		$	253,923		$	(631,952	)	$	(17,168	)

Balance, March 31, 2020													$	348,983		$	253,923		$	(632,148	)	$	(29,242	)
Net income (loss)														(4,949	)		6,279			21			1,351
Equity-based incentive compensation														315			-			4			319
Distributions														(1,698	)		(6,279	)		(129	)		(8,106	)
Balance, June 30, 2020													$	342,651		$	253,923		$	(632,252	)	$	(35,678	)

Balance, December 31, 2019													$	356,777		$	253,923		$	(632,023	)	$	(21,323	)
Net income (loss)														(11,228	)		12,558			21			1,351
Equity-based incentive compensation														420			-			7			427
Distributions														(3,373	)		(12,558	)		(257	)		(16,188	)
Proceeds from sale of 53,372 common units pursuant to the Employee Unit Purchase Plan														55			-			-			55
Balance, June 30, 2020													$	342,651		$	253,923		$	(632,252	)	$	(35,678	)

	Nine Months ended September 30,						Six Months ended June 30,
	2018			2019			2019			2020
	(unaudited)						(unaudited)
Cash flows from operating activities:
Net income	$	8,635		$	14,072		$	7,113		$	1,351
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		21,945			19,211			12,971			12,260
Amortization of debt issuance costs		1,200			754			503			502
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	)		-
Unrealized loss recognized on commodity derivative								-			3,589
Tangible asset impairment charge								2,233			6,417
(Gain)loss on disposal of assets								(1,805	)		83
Equity-based incentive compensation		1,352			652			363			427
Changes in assets and liabilities:
Decrease (increase) in accounts receivable		(39,328	)		7,128
Decrease in accounts receivable								7,116			2,453
Decrease (increase) in receivables from related parties		1,423			(830	)		(78	)		(147	)
Decrease in other current assets		868			3,571			3,469			2,410
Decrease in other non-current assets		424			2,255			1,551			1,063
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
Increase (decrease) in accounts payable								(440	)		209
Increase (decrease) in payables to related parties								(20	)		134
Decrease in accrued crude oil purchases								(8,431	)		(4,311	)
Decrease in accrued crude oil purchases to related parties								(39	)		(3,438	)
Decrease in accrued interest payable		(232	)		(176	)		(71	)		(67	)
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	)
Increase (decrease) in accrued property taxes								9			(590	)
Decrease in unearned revenue								(1,334	)		(570	)
Increase in unearned revenue from related parties								2,797			2,074
Decrease in accrued payroll								(584	)		(638	)
Increase (decrease) in other accrued liabilities								(2,385	)		30
Net cash provided by operating activities		28,187			38,284			22,938			23,241
Cash flows from investing activities:
Acquisitions		(21,959	)		-
Acquisition of DEVCO from Ergon (Note 8)								-			(12,221	)
Capital expenditures		(29,560	)		(9,428	)		(6,240	)		(6,686	)
Proceeds from sale of assets		4,707			7,089			6,351			1,633
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	)		111			(17,274	)
Cash flows from financing activities:
Payments on other financing activities		(1,722	)		(1,894	)		(1,214	)		(1,350	)
Debt issuance costs		(358	)		-
Borrowings under credit agreement		216,000			218,000			158,000			115,000
Payments under credit agreement		(252,000	)		(225,000	)		(162,000	)		(103,000	)
Proceeds from equity issuance		208			176			73			55
Capital contributions		183			-
Distributions		(34,992	)		(25,905	)		(17,821	)		(16,188	)
Net cash used in financing activities		(72,681	)		(34,623	)		(22,962	)		(5,483	)
Net increase (decrease) in cash and cash equivalents		(543	)		1,322
Net increase in cash and cash equivalents								87			484
Cash and cash equivalents at beginning of period		2,469			1,455			1,455			558
Cash and cash equivalents at end of period	$	1,926		$	2,777		$	1,542		$	1,042

Supplemental disclosure of non-cash financing and investing cash flow information:
Non-cash changes in property, plant and equipment	$	(908	)	$	1,528		$	1,515		$	1,879
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		$	1,912		$	2,324

		Page
PART I	FINANCIAL INFORMATION	1
Item 1.	Unaudited Condensed Consolidated Financial Statements	1
	Condensed Consolidated Balance Sheets as of December 31, ~~2018~~2019, and ~~September~~June 30, ~~2019~~2020	1
	Condensed Consolidated Statements of Operations for the Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2018~~2019 and ~~2019~~2020	2
	Condensed Consolidated Statements of Changes in Partners’ Capital (Deficit) for the Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2018~~2019 and ~~2019~~2020	3
	Condensed Consolidated Statements of Cash Flows for the ~~Nine~~Six Months Ended ~~September~~June 30, ~~2018~~2019 and ~~2019~~2020	4
	Notes to the Unaudited Condensed Consolidated Financial Statements	5
	1. Organization and Nature of Business	5
	2. Basis of Consolidation and Presentation	5
	3. Revenue	5
	4. Property, Plant and Equipment	8
	5. Debt	8
	6. Net Income Per Limited Partner Unit	11
	7. Partners’ Capital and Distributions	11
	8. Related Party Transactions	11
	9. Long-term Incentive Plan	12
	10. Derivative Financial Instruments	13
	11. Fair Value Measurements	13
	12. Operating Segments	15
	13. Commitments and Contingencies	17
	14. Recently Issued Accounting Standards	17
	15. Subsequent Events	17
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2118
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	3328
Item 4.	Controls and Procedures	3328

PART II	OTHER INFORMATION	3429
Item 1.	Legal Proceedings	3429
Item 1A.	Risk Factors	3429
Item 6.	Exhibits	3429

	Three Months ended September 30,						Nine Months ended September 30,						Three Months ended June 30,						Six Months ended June 30,
	2018			2019			2018			2019			2019			2020			2019			2020
	(unaudited)												(unaudited)
Service revenue:
Third-party revenue	$	12,743		$	15,716		$	44,164		$	47,329		$	15,727		$	13,828		$	31,613		$	27,057
Related-party revenue		5,396			3,956			17,780			12,257			4,082			4,064			8,301			8,141
Lease revenue:
Third-party revenue		11,368			11,444			31,409			31,026			9,819			8,095			19,582			17,926
Related-party revenue		5,406			5,427			20,584			15,179			4,812			6,828			9,752			11,749
Product sales revenue:
Third-party revenue		97,763			55,213			146,892			173,773			59,636			20,626			118,560			67,678
Related-party revenue		482			-			482			-
Total revenue		133,158			91,756			261,311			279,564			94,076			53,441			187,808			132,551
Costs and expenses:
Operating expense		27,174			25,168			87,297			78,326			25,915			24,291			53,158			49,230
Cost of product sales		50,815			18,972			73,493			64,069			20,510			7,079			45,097			21,300
Cost of product sales from related party		44,106			32,691			67,853			99,886			36,421			12,790			67,195			41,044
General and administrative expense		4,322			3,840			13,029			10,495			2,962			4,068			6,655			7,608
Asset impairment expense		15			83			631			2,316			1,114			1,295			2,233			6,417
Total costs and expenses		126,432			80,754			242,303			255,092			86,922			49,523			174,338			125,599
Gain (loss) on sale of assets		(63	)		(40	)		300			1,765
Gain(loss) on disposal of assets														81			102			1,805			(83	)
Operating income		6,663			10,962			19,308			26,237			7,235			4,020			15,275			6,869
Other income (expenses):
Other income		-			-			-			268			268			44			268			602
Gain on sale of unconsolidated affiliate		-			-			2,225			-
Interest expense		(4,090	)		(3,989	)		(12,683	)		(12,394	)		(4,134	)		(2,714	)		(8,405	)		(6,113	)
Income before income taxes		2,573			6,973			8,850			14,111			3,369			1,350			7,138			1,358
Provision for income taxes		165			14			215			39			13			(1	)		25			7
Net income	$	2,408		$	6,959		$	8,635		$	14,072		$	3,356		$	1,351		$	7,113		$	1,351

Allocation of net income for calculation of earnings per unit:
Allocation of net income(loss) for calculation of earnings per unit:
General partner interest in net income	$	39		$	110		$	298		$	268		$	53		$	21		$	158		$	21
Preferred interest in net income	$	6,279		$	6,278		$	18,836		$	18,836		$	6,279		$	6,279		$	12,558		$	12,558
Net income (loss) available to limited partners	$	(3,910	)	$	571		$	(10,499	)	$	(5,032	)
Net loss available to limited partners													$	(2,976	)	$	(4,949	)	$	(5,603	)	$	(11,228	)

Basic and diluted net income (loss) per common unit	$	(0.09	)	$	0.01		$	(0.25	)	$	(0.12	)
Basic and diluted net loss per common unit													$	(0.07	)	$	(0.12	)	$	(0.13	)	$	(0.27	)

Weighted average common units outstanding - basic and diluted		40,380			40,811			40,331			40,735			40,715			41,035			40,696			41,025

	Revenue from Contracts with Customers(1)		Revenue from Leases		Revenue from Contracts with Customers(1)		Revenue from Leases
Remainder of 2019	$	7,756	$	14,012
2020		30,602		53,487
Remainder of 2020					$	15,966	$	28,084
2021		27,253		49,244		30,828		55,019
2022		19,937		38,545		23,198		44,262
2023		14,533		29,609		17,605		35,289
2024						11,250		28,675
Thereafter		9,142		22,342		9,930		27,930
Total revenue related to future performance obligations	$	109,223	$	207,239	$	108,777	$	219,259

	Nine Months ended September 30, 2018										Three Months ended June 30, 2020
Revenue from contracts with customers
Third-party revenue:
Fixed storage, throughput and other revenue	$	13,038	$	8,679	$	-	$	-	$	21,717	$	5,109	$	3,919	$	-	$	-	$	9,028
Variable throughput revenue		471		739		-		-		1,210
Variable throughput and other revenue												243		1,177		-		-		1,420
Variable reimbursement revenue		5,184		-		-		-		5,184		1,482		-		-		-		1,482
Crude oil transportation revenue		-		-		4,270		11,783		16,053		-		-		375		1,523		1,898
Crude oil product sales revenue		-		-		146,882		10		146,892		-		-		20,626		-		20,626
Related-party revenue:
Fixed storage, throughput and other revenue		12,272		-		132		-		12,404		2,891		-		-		-		2,891
Variable throughput and other revenue												210		-		-		-		210
Variable reimbursement revenue												963		-		-		-		963
Total revenue from contracts with customers											$	10,898	$	5,096	$	21,001	$	1,523	$	38,518
Lease revenue
Third-party revenue:
Fixed lease revenue											$	7,590	$	-	$	-	$	-	$	7,590
Variable throughput revenue		762				-		-		762		33		-		-		-		33
Variable reimbursement revenue		4,478		-		136		-		4,614		472		-		-		-		472
Total revenue from contracts with customers	$	36,205	$	9,418	$	151,420	$	11,793	$	208,836
Related-party revenue:
Fixed lease revenue												6,561		-		-		-		6,561
Variable reimbursement revenue												267		-		-		-		267
Total lease revenue											$	14,923	$	-	$	-	$	-	$	14,923
Total revenue											$	25,821	$	5,096	$	21,001	$	1,523	$	53,441

	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

	Six Months ended June 30, 2020
Revenue from contracts with customers
Third-party revenue:
Fixed storage, throughput and other revenue	$	10,223	$	6,533	$	-	$	-	$	16,756
Variable throughput and other revenue		377		1,892		-		-		2,269
Variable reimbursement revenue		3,089		-		-		-		3,089
Crude oil transportation revenue		-		-		877		4,066		4,943
Crude oil product sales revenue		-		-		67,678		-		67,678
Related-party revenue:
Fixed storage, throughput and other revenue		5,782		-		-		-		5,782
Variable throughput and other revenue		425		-		-		-		425
Variable reimbursement revenue		1,934		-		-		-		1,934
Total revenue from contracts with customers	$	21,830	$	8,425	$	68,555	$	4,066	$	102,876
Lease revenue
Third-party revenue:
Fixed lease revenue	$	16,816	$	-	$	-	$	-	$	16,816
Variable throughput and other revenue		33		-		-		-		33
Variable reimbursement revenue		1,077		-		-		-		1,077
Related-party revenue:
Fixed lease revenue		11,362		-		-		-		11,362
Variable reimbursement revenue		387		-		-		-		387
Total lease revenue	$	29,675	$	-	$	-	$	-	$	29,675
Total revenue	$	51,505	$	8,425	$	68,555	$	4,066	$	132,551

	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

		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

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	)

		Fair Value of
Derivatives Not Designated as Hedging Instruments	Balance Sheet Location	Derivatives
		June 30, 2020
Commodity derivative	Commodity derivative liability	$	3,589

Derivatives Not Designated as	Location of Gain(Loss) Recognized in Net	Amount of Gain(Loss) Recognized
Hedging Instruments	Income on Derivatives	in Net Income on Derivatives
		Three Months ended June 30,			Six Months ended June 30,
		2020			2020
Commodity derivative	Cost of product sales	$	(3,589	)	$	(3,589	)

	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	$	-

	Fair Value Measurements as of June 30, 2020
Description	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Liability:
Commodity derivative	$	3,589	$	3,589	$	-	$	-
Total derivative liabilities	$	3,589	$	3,589	$	-	$	-

		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

	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

	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

	~~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~~	%

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	$	-