UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2018
2019  
OR 

o
TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to _________
 
Commission File Number 001-33503
 
BLUEKNIGHT ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of incorporation or organization)
 
20-8536826
(IRS Employer
Identification No.)
   
201 NW 10th, Suite 200
Oklahoma City, Oklahoma 73103
(Address of principal executive offices, zip code)
 
Registrant’s telephone number, including area code: (405) 278-6400
(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes    x    No   o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes   x   No   o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o
 
Accelerated filer x 
Non-accelerated filer o   (Do not check if a smaller reporting company)
 
Smaller reporting company o
  
Emerging growth company o
 

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  o  No x 
Securities registered pursuant to Section 12(b) of the Exchange Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common UnitsBKEPThe Nasdaq Global Market
Series A Preferred UnitsBKEPPThe Nasdaq Global Market
As of May 3, 2018,6, 2019, there were 35,125,202 Series A Preferred Units and 40,321,44240,714,857 common units outstanding.   

 




Table of Contents
  Page
FINANCIAL INFORMATION
Unaudited Condensed Consolidated Financial Statements
 Condensed Consolidated Balance Sheets as of December 31, 2017,2018, and March 31, 20182019
 Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 20172018 and 20182019
 Condensed Consolidated StatementStatements of Changes in Partners’ Capital (Deficit) for the Three Months Ended March 31, 2018 and 2019
 Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 20172018 and 20182019
 Notes to the Unaudited Condensed Consolidated Financial Statements
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Quantitative and Qualitative Disclosures about Market Risk
Controls and Procedures
   
OTHER INFORMATION
Legal Proceedings
Risk Factors
Exhibits





i

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1.    Unaudited Condensed Consolidated Financial Statements

BLUEKNIGHT ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
BLUEKNIGHT ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
BLUEKNIGHT ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
As of As ofAs of As of
December 31, 2017 March 31, 2018December 31, 2018 March 31, 2019
(unaudited)(unaudited)
ASSETS      
Current assets:      
Cash and cash equivalents$2,469
 $2,081
$1,455
 $1,209
Accounts receivable, net of allowance for doubtful accounts of $28 and $36 at December 31, 2017 and March 31, 2018, respectively7,589
 10,392
Receivables from related parties, net of allowance for doubtful accounts of $0 at both dates3,070
 2,110
Prepaid insurance2,009
 1,985
Accounts receivable, net35,683
 28,561
Receivables from related parties, net1,043
 936
Other current assets8,438
 8,503
9,345
 7,127
Total current assets23,575
 25,071
47,526
 37,833
Property, plant and equipment, net of accumulated depreciation of $316,591 and $319,220 at December 31, 2017 and March 31, 2018, respectively296,069
 304,416
Assets held for sale, net of accumulated depreciation and amortization of $3,736 at March 31, 2018
 1,536
Property, plant and equipment, net of accumulated depreciation of $263,554 and $268,576 at December 31, 2018, and March 31, 2019, respectively248,261
 243,063
Goodwill3,870
 6,728
6,728
 6,728
Debt issuance costs, net4,442
 4,186
3,349
 3,098
Intangibles and other assets, net12,913
 19,654
Operating lease assets
 11,594
Intangible assets, net16,834
 16,147
Other noncurrent assets
606
 1,193
Total assets$340,869
 $361,591
$323,304
 $319,656
LIABILITIES AND PARTNERS’ CAPITAL      
Current liabilities:      
Accounts payable$4,439
 $4,699
$3,707
 $3,925
Accounts payable to related parties2,268
 3,266
2,263
 2,111
Accrued crude oil purchases13,949
 7,576
Accrued crude oil purchases to related parties10,219
 11,885
Accrued interest payable694
 718
465
 294
Accrued property taxes payable2,432
 2,352
3,089
 2,237
Unearned revenue2,393
 3,028
3,206
 3,536
Unearned revenue with related parties551
 4,312
4,835
 15,168
Accrued payroll6,119
 2,796
3,667
 2,129
Current operating lease liability
 2,768
Other current liabilities4,747
 4,335
3,465
 3,042
Total current liabilities23,643
 25,506
48,865
 54,671
Long-term unearned revenue with related parties1,052
 996
1,714
 1,612
Other long-term liabilities3,673
 3,642
4,010
 3,715
Long-term interest rate swap liabilities225
 
Noncurrent operating lease liability
 8,935
Contingent liability with related party (Note 10)10,019
 10,870
Long-term debt307,592
 334,592
265,592
 252,592
Commitments and contingencies (Note 15)
 
Commitments and contingencies (Note 16)
 
Partners’ capital:      
Common unitholders (40,158,342 and 40,321,442 units issued and outstanding at December 31, 2017 and March 31, 2018, respectively)454,358
 446,471
Common unitholders (40,424,372 and 40,714,857 units issued and outstanding at December 31, 2018, and March 31, 2019, respectively)370,972
 365,220
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)(703,597) (703,539)(631,791) (631,882)
Total partners’ capital4,684
 (3,145)(6,896) (12,739)
Total liabilities and partners’ capital$340,869

$361,591
$323,304

$319,656
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

BLUEKNIGHT ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)
BLUEKNIGHT ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)
BLUEKNIGHT ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)
 Three Months ended
March 31,
 Three Months ended
March 31,
 2017 2018 2018 2019
 (unaudited) (unaudited)
Service revenue:        
Third-party revenue $28,663
 $17,318
 $17,318
 $15,886
Related-party revenue 13,642
 6,321
 6,321
 4,219
Lease revenue:        
Third-party revenue 
 9,804
 9,804
 9,763
Related-party revenue 
 7,703
 7,703
 4,940
Product sales revenue:        
Third-party revenue 4,035
 3,514
 3,514
 58,924
Total revenue 46,340
 44,660
 44,660
 93,732
Costs and expenses:        
Operating expense 31,906
 31,135
 31,135
 27,243
Cost of product sales 3,139
 2,637
 2,637
 24,587
Cost of product sales from related party 
 30,774
General and administrative expense 4,585
 4,221
 4,221
 3,693
Asset impairment expense 28
 616
 616
 1,119
Total costs and expenses 39,658
 38,609
 38,609
 87,416
Loss on sale of assets (125) (236)
Gain (loss) on sale of assets (236) 1,724
Operating income 6,557
 5,815
 5,815
 8,040
Other income (expenses):        
Equity earnings in unconsolidated affiliate 61
 
Gain on sale of unconsolidated affiliate 
 2,225
 2,225
 
Interest expense (net of capitalized interest of $2 and $28, respectively) (3,030) (3,569)
Interest expense (3,569) (4,271)
Income before income taxes 3,588
 4,471
 4,471
 3,769
Provision for income taxes 46
 29
 29
 12
Net income $3,542
 $4,442
 $4,442
 $3,757
        
Allocation of net income for calculation of earnings per unit:        
General partner interest in net income $209
 $231
 $231
 $105
Preferred interest in net income $6,279
 $6,278
 $6,278
 $6,279
Net loss available to limited partners $(2,946) $(2,067) $(2,067) $(2,627)
        
Basic and diluted net loss per common unit $(0.08) $(0.05) $(0.05) $(0.06)
        
Weighted average common units outstanding - basic and diluted 38,146
 40,289
 40,289
 40,678

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


BLUEKNIGHT ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL (DEFICIT)
(in thousands)
BLUEKNIGHT ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL (DEFICIT)
(in thousands)
BLUEKNIGHT ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL (DEFICIT)
(in thousands)
Common Unitholders Series A Preferred Unitholders General Partner Interest Total Partners’ Capital (Deficit)Common Unitholders Series A Preferred Unitholders General Partner Interest Total Partners’ Capital (Deficit)
(unaudited)(unaudited)
Balance, December 31, 2017$454,358
 $253,923
 $(703,597) $4,684
$454,358
 $253,923
 $(703,597) $4,684
Net income (loss)(2,065) 6,279
 228
 4,442
(2,065) 6,279
 228
 4,442
Equity-based incentive compensation33
 
 8
 41
33
 
 8
 41
Distributions(5,947) (6,279) (361) (12,587)(5,947) (6,279) (361) (12,587)
Capital contributions
 
 183
 183

 
 183
 183
Proceeds from sale of 21,246 common units pursuant to the Employee Unit Purchase Plan92
 
 
 92
92
 
 
 92
Balance, March 31, 2018$446,471
 $253,923
 $(703,539) $(3,145)$446,471
 $253,923
 $(703,539) $(3,145)

 Common Unitholders Series A Preferred Unitholders General Partner Interest Total Partners’ Capital (Deficit)
 (unaudited)
Balance, December 31, 2018$370,972
 $253,923
 $(631,791) $(6,896)
Net income (loss)(2,581) 6,279
 59
 3,757
Equity-based incentive compensation64
 
 5
 69
Distributions(3,308) (6,279) (155) (9,742)
Proceeds from sale of 63,340 common units pursuant to the Employee Unit Purchase Plan73
 
 
 73
Balance, March 31, 2019$365,220
 $253,923
 $(631,882) $(12,739)

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

BLUEKNIGHT ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
BLUEKNIGHT ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
BLUEKNIGHT ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Three Months ended
March 31,
Three Months ended
March 31,
2017 20182018 2019
(unaudited)(unaudited)
Cash flows from operating activities:      
Net income$3,542
 $4,442
$4,442
 $3,757
Adjustments to reconcile net income to net cash provided by operating activities:      
Provision for uncollectible receivables from third parties(8) 8
8
 
Depreciation and amortization8,066
 7,367
7,367
 6,734
Amortization of debt issuance costs342
 256
256
 251
Unrealized gain related to interest rate swaps(752) (354)
Unrealized (gain) loss related to interest rate swaps(354) 44
Intangible asset impairment charge
 189
189
 
Fixed asset impairment charge28
 427
427
 1,119
Loss on sale of assets125
 236
Loss (gain) on sale of assets236
 (1,724)
Gain on sale of unconsolidated affiliate
 (2,225)(2,225) 
Equity-based incentive compensation(125) 41
41
 69
Equity earnings in unconsolidated affiliate(61) 
Changes in assets and liabilities:      
Increase in accounts receivable(3,806) (2,811)
Decrease (increase) in accounts receivable(2,811) 4,480
Decrease in receivables from related parties303
 960
960
 107
Decrease in prepaid insurance441
 744
Increase in other current assets(610) (345)
Decrease in other assets3
 41
Decrease (increase) in other current assets399
 2,613
Decrease in other non-current assets41
 803
Decrease in accounts payable(86) (154)(154) (297)
Increase in payables to related parties227
 625
Increase (decrease) in payables to related parties625
 (315)
Decrease in accrued crude oil purchases
 (6,373)
Increase in accrued crude oil purchases to related parties
 1,666
Increase (decrease) in accrued interest payable(117) 24
24
 (171)
Decrease in accrued property taxes(695) (80)(80) (852)
Increase in unearned revenue794
 637
637
 165
Increase in unearned revenue from related parties3,753
 3,655
3,655
 10,231
Decrease in accrued payroll(3,372) (3,323)(3,323) (1,538)
Decrease in other accrued liabilities(443) (419)(419) (1,252)
Net cash provided by operating activities7,549
 9,941
9,941
 19,517
Cash flows from investing activities:      
Acquisitions
 (21,959)(21,959) 
Capital expenditures(4,052) (4,563)(4,563) (2,801)
Proceeds from sale of assets2,850
 26
26
 6,304
Proceeds from sale of unconsolidated affiliate
 2,225
2,225
 
Net cash used in investing activities(1,202) (24,271)
Net cash provided by (used in) investing activities(24,271) 3,503
Cash flows from financing activities:      
Payment on insurance premium financing agreement(773) (746)
Debt issuance costs(7) 
Payments on other financing activities(746) (597)
Borrowings under credit agreement25,000
 54,000
54,000
 75,000
Payments under credit agreement(19,000) (27,000)(27,000) (88,000)
Proceeds from equity issuance84
 92
92
 73
Capital contributions104
 183
183
 
Distributions(12,252) (12,587)(12,587) (9,742)
Net cash provided by (used in) financing activities(6,844) 13,942
13,942
 (23,266)
Net decrease in cash and cash equivalents(497) (388)(388) (246)
Cash and cash equivalents at beginning of period3,304
 2,469
2,469
 1,455
Cash and cash equivalents at end of period$2,807
 $2,081
$2,081
 $1,209
      
Supplemental disclosure of non-cash financing and investing cash flow information:      
Non-cash changes in property, plant and equipment$1,790
 $1,251
$1,251
 $711
Increase in accrued liabilities related to insurance premium financing agreement$750
 $720
$720
 $751

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

BLUEKNIGHT ENERGY PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
1.    ORGANIZATION AND NATURE OF BUSINESS
 
Blueknight Energy Partners, L.P. and subsidiaries (collectively, the “Partnership”) is a publicly traded master limited partnership with operations in 27 states. The Partnership provides integrated terminalling, gathering, transportation and marketing services for companies engaged in the production, distribution and marketing of crude oil and asphalt products. The Partnership manages its operations through four operating segments: (i) asphalt terminalling services, (ii) crude oil terminalling services, (iii) crude oil pipeline services and (iv) crude oil trucking and producer field services. The Partnership’s common units and preferred units, which represent limited partnership interests in the Partnership, are listed on the NASDAQ Global Market under the symbols “BKEP” and “BKEPP,” respectively. The Partnership was formed in February 2007 as a Delaware master limited partnership initially to own, operate and develop a diversified portfolio of complementary midstream energy assets.

2.    BASIS OF CONSOLIDATION AND PRESENTATION
 
The financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).  The condensed consolidated balance sheet as of March 31, 2019, the condensed consolidated statements of operations for the three months ended March 31, 20172018 and 20182019, the condensed consolidated statementstatements of changes in partners’ capital (deficit) for the three months ended March 31, 2018 and 20182019, and the condensed consolidated statements of cash flows for the three months ended March 31, 20172018 and 2018, and the condensed consolidated balance sheet as of March 31, 20182019, are unaudited.  In the opinion of management, the unaudited condensed consolidated financial statements have been prepared on the same basis as the audited financial statements and include all adjustments necessary to state fairly the financial position and results of operations for the respective interim periods.  All adjustments are of a recurring nature unless otherwise disclosed herein.  The 20172018 year-end condensed consolidated balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP.  These unaudited condensed consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes thereto included in the Partnership’s annual report on Form 10-K for the year ended December 31, 2017,2018, filed with the Securities and Exchange Commission (the “SEC”) on March 8, 201812, 2019 (the “2017“2018 Form 10-K”).  Interim financial results are not necessarily indicative of the results to be expected for an annual period.  The Partnership’s significant accounting policies are consistent with those disclosed in Note 3 of the Notes to Consolidated Financial Statements in its 20172018 Form 10-K.

The Partnership’s investmentCertain reclassifications have been made in Advantage Pipeline, L.L.C. (“Advantage Pipeline”), over which the Partnership had significant influence but not control, was accounted for by the equity method. The Partnership did not consolidate any part of the assets or liabilities of its equity investee. The Partnership’s share of net income or loss is reflected as one line item on the Partnership’s unaudited condensed consolidated statements of operations entitled “Equity earnings in unconsolidated affiliate” and increased or decreased, as applicable, the carrying value of the Partnership’s “Investment in unconsolidated affiliate” on the unaudited condensed consolidated balance sheets. Distributions tosheet as of December 31, 2018, and the Partnership reduced the carrying value of its investment and, to the extent received, were reflected in the Partnership’s unaudited condensed consolidated statementsstatement of cash flows for the three months ended March 31, 2018, to conform to the 2019 financial statement presentation. These reclassifications relate to items included in “Other current assets” and “Other noncurrent assets.” Reclassifications on the line item “Distributions from unconsolidated affiliate.” Contributions increased the carrying value of the Partnership’s investment and were reflected in the Partnership’s unaudited condensed consolidated statementsstatement of cash flows in investing activities. On April 3, 2017,were limited to the Partnership sold its investment in Advantage Pipeline. See Note 5 for additional information.“Cash flows from operating activities” section. The reclassifications have no impact on net income.

3.    REVENUE

Revenue from Contracts with Customers

On January 1, 2018,2019, the Partnership adopted the new accounting standard ASC 606842 - Revenue from Contracts with CustomersLeases and all related amendments (“new revenuelease standard”) using the modified retrospective method, and as a result applied the new guidance only to contracts that are not completed at the adoption date.method. Results for reporting periods beginning on January 1, 2018,2019, are presented under the new revenuelease standard, while prior period amounts are not adjusted and continue to be reported in accordance with the Partnership’s historic accounting under ASC 605840 - Revenue RecognitionLeases.

The majorityadoption of ASC 842 did not have a material effect on the Partnership’s services revenue continues to be recognized as services are performed. Under the new revenue standard, the timing of revenue recognition on variable throughput fees will change, within a single reporting year, compared to the previous recognition. The effect will be straight-line recognition of unconstrained estimated annual throughput volumes over each contract year.  See further discussion on variable throughput fees below. In addition, asprimary impact is a result of the adoption of the new revenue standard, revenue from leases is requiredchange to be presented separately from revenue from customers. As the Partnership applied the modified retrospective method, prior periods have not been reclassified.

Upon adoption of the new revenue standard, there was no cumulative adjustment to the balance sheet at January 1, 2018. Adoption of the new revenue standard resulted in recognition of an additional $0.1 million of “Service revenue - Third-party revenue” in the unaudited condensed consolidated statement of operations for the three months ended March 31, 2018, and “Accounts receivable” on the unaudited condensed consolidated balance sheet as of March 31, 2018, over what would have been recorded under ASC 605. While some revenue under storage, throughput and handling contracts in the asphalt terminalling segment will shift between quarters within a fiscal year, the impact of adoption of the new revenue standard is not expected to be material to net income on an ongoing basis because the analysis of contracts under the new revenue standard supports the recognition of revenuevariable consideration that has both a service and lease component. Previously, the variable consideration related to the service component was estimated at the beginning of the contract year and recognized on a straight-line basis over the year. Under ASC 842, the variable consideration related to the service component is treated as services are performed,a change in estimate in the period when the facts and circumstances on which the variable payment is consistent with the previous revenue recognition model.based occur.

There are two types of contracts in the asphalt terminalling segment: (i) operating lease contracts, under which customers operate the facilities, and (ii) storage, throughput and handling contracts, under which the Partnership operates the facilities. The operating lease contracts are accounted for in accordance with ASC 840842 - LeasesLeases.. The storage, throughput and handling contracts contain both lease revenue and non-lease service revenue. In accordance with ASC 840842 and 606, fixed consideration is allocated to the lease and service components based on their relative stand-alone selling price. The stand-alone selling price of the lease component is calculated using the average internal rate of return under the operating lease agreements. The stand-alone selling price of the service component is calculated by applying an appropriate margin to the expected costs to operate the facility. The service component contains a single performance obligation that consists of a stand-ready obligation to perform activities as directed by the customer. Revenuecustomer, and revenue is recognized on a straight-line basis over time as the customer receives and

consumes benefits. The lease component is recognized on a straight-line basis over the term of the initial lease. Fixed consideration, consisting of the monthly storage and handling fees, is billed a month prior to the performance of services and is due by the first day of the month of service. Payments received in advance of the month of service are recorded as unearned revenue (contract liability) until the service is performed.performed, and the service component is treated as a contract liability.

Asphalt storage, throughput and handling contracts also contain variable consideration in the form of reimbursements of utility, fuel and power expenses and throughput fees. Utility, fuel and power reimbursements are allocated entirely to the service component of the contracts. Utility, fuel and power reimbursements relate directly to the distinct monthly service that makes up the overall performance obligation and revenue is recognized in the period in which the service takes place. Variable consideration related to reimbursements of utility, fuel and power expenses is billed in the month subsequent to the period of service, and payment is due within 30 days of billing. Throughput fees are allocated to both the lease and service component of the contracts using the allocation percentages from contract inception. Total throughput fees are estimated at contract inception and updated at the beginning of each reporting period based on historical trends, current year throughput activities at the facilities, and analysis with customers regarding expectations for the current year. This consideration can be constrained when there is a lack of historical data or other uncertainties exist regarding expected throughput volumes. The service component of throughput fees is recognized on a straight-line basis over time as the customer receives and consumes benefits. In accordance with ASC 840,842, the lease component of variable throughput fees is recognized in the period when the changes in facts and circumstances on which the variable payment is based occur. Fees related to actualAdditionally, under ASC 842, when variable consideration contains both a lease and non-lease service component, the service component cannot be recognized until the period in which the changes in facts and circumstances on which the variable payment is based occur. At that time, it can be recognized in accordance with ASC 606. The service component of variable throughput are billedfees is treated as a change in estimate in the month subsequent toperiod in when the period of movement,changes in facts and circumstances on which can result in the recognition of un-billed accounts receivable (contract assets) when therevariable payment is based occur and is then recognized on a variance instraight-line basis over time as the straight-line revenue recognitioncustomer receives and actual throughput fees billed.consumes benefits. Payment on variable throughput consideration is due within 30 days of billing. Changes in estimated throughput fees affect the total transaction price and will be recorded as an adjustment to revenue in the period in which the change is identified. There was no adjustment related to changes in estimated throughput fees for the three months ended March 31, 2018.

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

As of March 31, 2018,2019, the Partnership has service revenue performance obligations satisfied over time under asphalt storage, throughput and handling contracts that are wholly or partially unsatisfied. The service revenue related to these performance obligations will be recognized as follows (in thousands):


Revenue Related to Future Performance Obligations Due by Period(1)
  
Less than 1 year $35,270
1-3 years 63,229
4-5 years 48,079
More than 5 years 17,181
Total revenue related to future performance obligations $163,759
Revenue Related to Future Performance Obligations Due by Period(1)
  
Twelve months ending March 31, 2020 $30,705
Twelve months ending March 31, 2021 29,704
Twelve months ending March 31, 2022 25,487
Twelve months ending March 31, 2023 18,903
Twelve months ending March 31, 2024 11,711
Thereafter 7,841
Total revenue related to future performance obligations $124,351
____________________
(1)Excluded from the table is revenue that is either constrained or related to performance obligations that are wholly unsatisfied as of March 31, 2018.2019.

In addition, as of March 31, 2019, the Partnership has minimum future annual lease rentals contracted to be received under asphalt operating lease contracts and asphalt storage, throughput and handling contracts. The lease revenue related to these minimum rentals will be recognized as follows (in thousands):
Revenue Related to Minimum Future Annual Lease Rentals Due by Period  
Twelve months ending March 31, 2020 $55,176
Twelve months ending March 31, 2021 52,360
Twelve months ending March 31, 2022 46,637
Twelve months ending March 31, 2023 36,655
Twelve months ending March 31, 2024 24,798
Thereafter 19,220
Total revenue related to minimum future annual lease rentals $234,846

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 ourits published tariffs. Crude oil pipeline services contracts have a single performance obligation to perform the transportation service. The transportation service is provided to the customer in the same month in which the customer makes the related nomination. Revenue is recorded in the month of service and invoiced in the following month. Payment is due within 30 days. The Partnership has elected to use the right-to-invoice expedient on crude oil pipeline services contracts as the right to consideration corresponds directly with the value to the customer of performance completed to date.

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

Services in the crude oil trucking and field services 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 and field services 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 and field services revenues as the right to consideration corresponds directly with the value to the customer of performance completed to date.

Disaggregation of Revenue

The following table represents a disaggregationDisaggregation of revenue from contracts with customers for each operating segment by revenue type is presented as follows (in thousands):

  Three Months ended March 31, 2018
  Asphalt  Terminalling Services Crude Oil Terminalling Services Crude Oil Pipeline Services Crude Oil Trucking Services Total
Third-party revenue:          
Fixed storage, throughput and other revenue $3,549
 $4,081
 $
 $
 $7,630
Variable throughput revenue 117
 504
 
 
 621
Variable reimbursement revenue 1,466
 
 
 
 1,466
Crude oil transportation revenue 
 
 2,061
 5,540
 7,601
Crude oil product sales revenue 
 
 3,508
 6
 3,514
Related-party revenue:          
Fixed storage, throughput and other revenue 4,631
 
 
 
 4,631
Variable reimbursement revenue 1,690
 
 
 
 1,690
Total revenue from contracts with customers $11,453
 $4,585
 $5,569
 $5,546
 $27,153

 Three Months ended March 31, 2018 Three Months ended March 31, 2019
 Asphalt  Terminalling Services Crude Oil Terminalling Services Crude Oil Pipeline Services Crude Oil Trucking and Producer Field Services Total Asphalt  Terminalling Services Crude Oil Terminalling Services Crude Oil Pipeline Services Crude Oil Trucking Services Total
Third-party revenue:                    
Fixed storage and throughput revenue $3,549
 $4,081
 $
 $
 $7,630
Fixed storage, throughput and other revenue $4,983
 $3,069
 $
 $
 $8,052
Variable throughput revenue 117
 504
 
 
 621
 3
 504
 
 
 507
Variable reimbursement revenue 1,466
 
 
 
 1,466
 1,996
 
 
 
 1,996
Crude oil transportation revenue 
 
 2,061
 5,540
 7,601
 
 
 2,498
 2,833
 5,331
Crude oil product sales revenue 
 
 3,508
 6
 3,514
 
 
 58,924
 
 58,924
Related-party revenue:                    
Fixed storage and throughput revenue 4,631
 
 
 
 4,631
Fixed storage, throughput and other revenue 2,848
 
 83
 
 2,931
Variable reimbursement revenue 1,690
 
 
 
 1,690
 1,270
 
 18
 
 1,288
Total revenue from contracts with customers $11,453
 $4,585
 $5,569
 $5,546
 $27,153
 $11,100
 $3,573
 $61,523
 $2,833
 $79,029

Contract Balances

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

Billed accounts receivable from contracts with customers were $8.5$34.6 million and $8.4$25.8 million at December 31, 2017,2018, and March 31, 2018,2019, respectively.

Un-billed accounts receivable from contracts with customers were $0.1 million at March 31, 2018. There were no un-billed accounts receivable at December 31, 2017.

The Partnership records unearned revenues when cash payments are received in advance of performance. Unearned revenue related to contracts with customers was $3.7$5.9 million and $5.5$10.1 million at December 31, 2017,2018, and March 31, 2018,2019, respectively. The increasechange in the unearned revenue balance for the three months ended March 31, 2018,2019, is driven by $3.3$7.3 million in cash payments received in advance of satisfying performance obligations, partially offset by $1.5$3.1 million of revenues recognized that were included in the unearned revenue balance at the beginning of the period.

Practical Expedients and Exemptions

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

4.     RESTRUCTURING CHARGES

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


Changes in the accrued amounts pertaining to the restructuring charges are summarized as follows (in thousands):
 Three Months ended
March 31,
 2017 2018
Beginning balance$474
 $286
Cash payments46
 49
Ending balance$428
 $237

The remaining accrued amounts relate to lease payments that will be paid over the remaining lease terms, which extend through July 2019.
 Three Months ended
March 31,
 2018
Beginning balance$286
Cash payments49
Ending balance$237

5.    EQUITY METHOD INVESTMENT
 
The Partnership’s investment in Advantage Pipeline, L.L.C. (“Advantage Pipeline”), over which the Partnership had significant influence but not control, was accounted for by the equity method. The Partnership did not consolidate any part of the assets or liabilities of Advantage Pipeline. On April 3, 2017, Advantage Pipeline was acquired by a joint venture formed by affiliates of Plains All American Pipeline, L.P. and Noble Midstream Partners LP. The Partnership received cash proceeds at closing from the sale of its approximate 30% equity ownership interest in Advantage Pipeline of approximately $25.3 million and recorded a gain on the sale of the investment of $4.2 million. Approximately 10% of the gross sale proceeds were held in escrow, subject to certain post-closing settlement terms and conditions. The Partnership received approximately $1.1 million of the funds held in escrow in August 2017, and approximately $2.2 million for its pro rata portion of the remaining net escrow proceeds in January 2018. The Partnership’s proceeds were used to prepay revolving debt (without a commitment reduction). The operating and administrative services agreement to whichAs of March 31, 2019, the Partnership and Advantage Pipeline were parties and under which the Partnership operated the 70-mile, 16-inch Advantage crude oil pipeline, located in the southern Delaware Basin in Texas, was terminated at closing. The Partnership and the Plains/Noble joint venture entered into a short-term transition services agreement under which the Partnership provided certain services through August 1, 2017.had no equity investments.

Summarized financial information for Advantage Pipeline is set forth in the tables below for the periods indicated in which the Partnership held the investment in Advantage Pipeline (in thousands):
 As of
 March 31, 2017
Balance Sheet 
Current assets$1,420
Noncurrent assets87,811
Total assets89,231
Current liabilities1,073
Long-term liabilities19,067
Member’s equity69,091
Total liabilities and member’s equity$89,231
 
Three Months ended
March 31, 2017
Income Statement 
Operating revenues$3,150
Operating expenses$465
Net income$187

6.    PROPERTY, PLANT AND EQUIPMENT
Estimated Useful Lives (Years) December 31, 2017 March 31,
2018
Estimated Useful Lives (Years) December 31, 2018 March 31,
2019
  
  (dollars in thousands)  (dollars in thousands)
LandN/A $24,776
 $27,079
N/A $24,705
 $24,705
Land improvements10-20 6,787
 7,794
10-20 5,758
 5,798
Pipelines and facilities5-30 166,004
 165,923
5-30 116,155
 117,188
Storage and terminal facilities10-35 370,056
 377,975
10-35 321,096
 322,476
Transportation equipment3-10 3,293
 759
3-10 2,798
 1,782
Office property and equipment and other3-20 32,011
 32,255
3-20 26,980
 27,186
Pipeline linefill and tank bottomsN/A 3,233
 3,619
N/A 10,297
 8,882
Construction-in-progressN/A 6,500
 8,232
N/A 4,026
 3,622
Property, plant and equipment, gross  612,660
 623,636
  511,815
 511,639
Accumulated depreciation  (316,591) (319,220)  (263,554) (268,576)
Property, plant and equipment, net  $296,069
 $304,416
  $248,261
 $243,063
 
Plant, property and equipment under operating leases at March 31, 2019, in which the Partnership is the lessor, had a cost basis of $282.1 million and accumulated depreciation of $173.3 million.

Depreciation expense for the three months ended March 31, 20172018 and 2018,2019, was $7.7$7.0 million and $7.0$6.0 million, respectively.

During the three months ended March 31, 2019, the Partnership recognized asset impairment expense of $1.1 million. A change in estimate of the push-down impairment related to Cimarron Express Pipeline, LLC (“Cimarron Express”) resulted in additional impairment expense of $0.8 million. This impairment is recorded at the corporate level and the estimate is based on the expected amount due to Ergon if the Put (as defined in Note 10) is exercised (see Note 10 for more information). In addition, a flood at an asphalt terminal in Wolcott, Kansas, led to an impairment of $0.3 million.

During the three months ended March 31, 2019, the Partnership sold various surplus assets, including the sale of three truck stations for $1.6 million, which resulted in a gain of $1.5 million, and the sale of pipeline linefill for $1.6 million, which resulted in a gain of $0.2 million. In addition, proceeds received during the three months ended March 31, 2019, included $2.6 million related to a sale of pipeline linefill in December 2018, for which the proceeds were received in January 2019.

On July 12, 2018, the Partnership sold certain asphalt terminals, storage tanks and related real property, contracts, permits, assets and other interests located in Lubbock and Saginaw, Texas and Memphis, Tennessee (the “Divestiture”) to Ergon Asphalt & Emulsion, Inc. for a purchase price of $90.0 million, subject to customary adjustments. The Divestiture does not qualify as discontinued operations as it does not represent a strategic shift that will have a major effect on the Partnership’s operations or financial results. The Partnership used the proceeds from the sale to prepay revolving debt under its credit agreement.

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

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

On April 18, 2017, the Partnership sold its East Texas pipeline system, which was included in assets held for sale as of March 31, 2017. The Partnership received cash proceeds at closing of approximately $4.8 million and recorded a gain of less than $0.1 million. The Partnership used the proceeds received at closing to prepay revolving debt (without a commitment reduction).

7.    DEBT

On May 11, 2017, the Partnership entered into an amended and restated credit agreement. On June 28, 2018, the credit agreement that consists of awas amended to, among other things, reduce the revolving loan facility from $450.0 million to $450.0400.0 million revolving loan facility.and amend the maximum permitted consolidated total leverage ratio as discussed below.

As of May 3, 2018,6, 2019, approximately $328.6$251.6 million of revolver borrowings and $1.5$1.0 million of letters of credit were outstanding under the credit agreement, leaving the Partnership with approximately $119.9$147.4 million available capacity for additional revolver borrowings and letters of credit under the credit agreement, although the Partnership’s ability to borrow such funds may be limited by the financial covenants in the credit agreement.  The proceeds of loans made under the credit agreement may be used for working capital and other general corporate purposes of the Partnership.

The credit agreement is guaranteed by all of the Partnership’s existing subsidiaries. Obligations under the credit agreement are secured by first priority liens on substantially all of the Partnership’s assets and those of the guarantors.
 
The credit agreement includes procedures for additional financial institutions to become revolving lenders, or for any existing lender to increase its revolving commitment thereunder, subject to an aggregate maximum of $600.0 million for all revolving loan commitments under the credit agreement.
 
The credit agreement will mature on May 11, 2022, and all amounts outstanding under the credit agreement will become due and payable on such date. The credit agreement requires mandatory prepayments of amounts outstanding thereunder with the net proceeds of certain asset sales, property or casualty insurance claims and condemnation proceedings, unless the Partnership reinvests such proceeds in accordance with the credit agreement, but these mandatory prepayments will not require any reduction of the lenders’ commitments under the credit agreement.

Borrowings under the credit agreement bear interest, at the Partnership’s option, at either the reserve-adjusted eurodollar rate (as defined in the credit agreement) plus an applicable margin that ranges from 2.0% to 3.0%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 2.0%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 iswill be 5.25 to 1.00 for the fiscal quarters ending March 31, 2019, and June 30, 2019; 5.00 to 1.00 for the fiscal quarters ending September 30, 2019, and December 31, 2019; and 4.75 to 1.00;1.00 for the fiscal

quarter ending March 31, 2020, and each fiscal quarter thereafter; provided that the maximum permitted consolidated total leverage ratio willmay 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). The acquisition of the asphalt terminalling facility in March 2018 qualified as a specified acquisition.
From and after the date on which the Partnership issues qualified senior notes in an aggregate principal amount (when combined with all other qualified senior notes previously or concurrently issued) that equals or exceeds $200.0 million, the maximum permitted consolidated total leverage ratio is 5.00 to 1.00; provided that from and after the fiscal quarter ending immediately preceding the fiscal quarter in which a specified acquisition occurs to and including the last day of the second full fiscal quarter following the fiscal quarter in which such acquisition occurred, the maximum permitted consolidated total leverage ratio will be 5.50 to 1.00.

The maximum permitted consolidated senior secured leverage ratio (as defined in the credit agreement, but generally computed as the ratio of consolidated total secured debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) is 3.50 to 1.00, but this covenant is only tested from and after the date on which the Partnership issues qualified senior notes in an aggregate principal amount (when combined with all other qualified senior notes previously or concurrently issued) that equals or exceeds $200.0 million.

The minimum permitted consolidated interest coverage ratio (as defined in the credit agreement, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest expense) is 2.50 to 1.00.
In addition, the credit agreement contains various covenants that, among other restrictions, limit the Partnership’s ability to:
create, issue, incur or assume indebtedness;
create, incur or assume liens;
engage in mergers or acquisitions;
sell, transfer, assign or convey assets;
repurchase the Partnership’s equity, make distributions to unitholders and make certain other restricted payments;
make investments;
modify the terms of certain indebtedness, or prepay certain indebtedness;
engage in transactions with affiliates;
enter into certain hedging contracts;
enter into certain burdensome agreements;
change the nature of the Partnership’s business; and
make certain amendments to the Partnership’s partnership agreement.

At March 31, 20182019, the Partnership’s consolidated total leverage ratio was 4.904.64 to 1.00 and the consolidated interest coverage ratio was 4.803.42 to 1.00.  The Partnership was in compliance with all covenants of its credit agreement as of March 31, 20182019.

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 EBITDA during the assessment period, management believes that it will meet these financial covenants (as described below). However, there are certain inherent risks associated with our continued ability to comply with our consolidated total leverage ratio covenant. These risks relate, among other things, to potential future (a) decreases in storage volumes and rates as well as throughput and transportation rates realized; (b) weather phenomenon that may potentially hinder the Partnership’s asphalt business activity; and (c) other items affecting forecasted levels of expenditures and uses of cash resources. Violation of the consolidated total leverage ratio covenant would be an event of default under the credit agreement, which would cause our $252.6 million in outstanding debt, as of March 31, 2019, to become immediately due and payable. If this were to occur, the Partnership would not expect to have sufficient liquidity to repay these outstanding amounts then due, which could cause the lenders under the credit facility to pursue other remedies. Such remedies could include exercising their collateral rights to the Partnership’s assets.


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

The credit agreement permits the Partnership to make quarterly distributions of available cash (as defined in the Partnership’s partnership agreement) to unitholders so long as no default or event of default exists under the credit agreement on a pro forma basis after giving effect to such distribution.distribution, provided, however, commencing with the fiscal quarter ending September 30, 2018, in no event shall aggregate quarterly distributions in any individual fiscal quarter exceed $10.7 million through, and including, the fiscal quarter ending December 31, 2019. The Partnership is currently allowed to make distributions to its unitholders in accordance with this covenant; however, the Partnership will only make distributions to the extent it has

sufficient cash from operations after establishment of cash reserves as determined by the Board of Directors (the “Board”) of Blueknight Energy Partners G.P., L.L.CL.L.C. (the “general partner”) in accordance with the Partnership’s cash distribution policy, including the establishment of any reserves for the proper conduct of the Partnership’s business.  See Note 9 for additional information regarding distributions.

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

(i)the general partner ceases to own 100% of the Partnership’s general partner interest or ceases to control the Partnership;
(ii)Ergon Inc. (“Ergon”) ceases to own and control 50% or more of the membership interests of the general partner; or
(iii)during any period of 12 consecutive months, a majority of the members of the Board of the general partner ceases to be composed of individuals:
(A)who were members of the Board on the first day of such period;
(B)whose election or nomination to the Board was approved by individuals referred to in clause (A) above constituting at the time of such election or nomination at least a majority of the Board; or
(C)whose election or nomination to the Board was approved by individuals referred to in clauses (A) and (B) above constituting at the time of such election or nomination at least a majority of the Board, provided that any changes to the composition of individuals serving as members of the Board approved by Ergon will not cause an event of default.

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

Upon the execution of the amended and restated credit agreement, the Partnership expensed $0.7 million of debt issuance costs related to the prior revolving loan facility, leaving a remaining balance of $0.9 million ascribed to those lenders with commitments under both the prior and the amended and restated credit agreement. The Partnership capitalized less than $0.1 million of debt issuance costs during the three months ended March 31, 2017. The Partnership capitalized no debt issuance costs during the three months ended March 31, 2018. Debt issuance costs are being amortized over the term of the credit agreement. Interest expense related to debt issuance cost amortization for each of the three months ended March 31, 20172018 and 2018,2019, was $0.3 million.
  
During the three months ended March 31, 20172018 and 2018,2019, the weighted average interest rate under the Partnership’s credit agreement was 4.11%4.96% and 4.96%6.43%, respectively, resulting in interest expense of approximately $3.3$3.9 million and $3.9$4.3 million, respectively.

During each of the three months ended March 31, 2017 and 2018, the Partnership capitalized interest of less than $0.1 million.

The Partnership is exposed to market risk for changes in interest rates related to its credit agreement. Interest rate swap agreements are sometimes used to manage a portion of the exposure related to changing interest rates by converting floating-rate debt to fixed-rate debt. As of December 31, 2017, and March 31, 2018,2019, the Partnership had no interest rate swap agreements; interest rate swap agreements with notional amounts totaling $200.0$100.0 million to hedge the variability of its LIBOR-based interest payments, with half maturing on June 28, 2018, and the other half maturingmatured on January 28, 2019. During the three months ended March 31, 20172018 and 2018,2019, the Partnership recorded swap interest expense of $0.5$0.1 million and swap interest income of less than $0.1 million, respectively. The interest rate swaps do not receive hedge accounting treatment under ASC 815 - Derivatives and Hedging.

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

Derivatives Not Designated as Hedging Instruments Balance Sheet Location Fair Value of Derivatives Balance Sheet Location Fair Value of Derivatives
 December 31, 2017 March 31, 2018
Derivatives Not Designated as Hedging Instruments Balance Sheet Location December 31, 2018
 Other current assets $68
 $197
 $44
Interest rate swap liabilities - noncurrent Long-term interest rate swap liabilities $225
 $

Changes in the fair value of the interest rate swaps are reflected in the unaudited condensed consolidated statements of operations as follows (in thousands):
Derivatives Not Designated as Hedging Instruments Location of Gain (Loss) Recognized in Net Income on Derivatives Amount of Gain (Loss) Recognized in Net Income on Derivatives
    Three Months ended
March 31,
    2017 2018
Interest rate swaps Interest expense, net of capitalized interest $752
 $354

As discussed above, the Partnership has an obligation to maintain certain financial ratios in accordance with its covenants under the credit agreement. Specifically, the Partnership is required to maintain a total leverage ratio of not greater than 5.25 to 1.00 and an interest coverage ratio of not less than 2.50 to 1.00, each as of the last day of any fiscal quarter. As of March 31, 2018, the Partnership is in compliance with all terms of the credit agreement, with a total leverage ratio of 4.90 to 1.00 and an interest coverage ratio of 4.80 to 1.00. However, with the current weakness in crude oil storage rates, the Partnership’s management believes that it is possible that the Partnership may fall out of compliance with these financial covenants as early as the third quarter of 2018. Failure to remain in compliance with the financial covenants could constrain the Partnership’s operating flexibility, its ability to fund its business operations and could cause the amounts outstanding under the credit agreement, which was $334.6 million as of March 31, 2018, to become immediately due and payable.

In light of this, the Partnership is considering options to enhance its financial flexibility and fund its operations, including a potential sale of assets, a reduction in the distribution rate that would be paid to the Partnership’s common unitholders, and/or the need to amend the financial covenants under the credit agreement. Any amendment of the credit agreement may increase the cost of credit provided under the credit agreement and related expenses, which may adversely impact the Partnership’s profitability.
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
March 31,
    2018 2019
Interest rate swaps Interest expense, net of capitalized interest $354
 $(44)

8.    NET INCOME PER LIMITED PARTNER UNIT

For purposes of calculating earnings per unit, the excess of distributions over earnings or excess of earnings over distributions for each period are allocated to the Partnership’s general partner based on the general partner’s ownership interest at the time. The following sets forth the computation of basic and diluted net income per common unit (in thousands, except per unit data): 
Three Months ended
March 31,
Three Months ended
March 31,
2017 20182018 2019
Net income$3,542
 $4,442
$4,442
 $3,757
General partner interest in net income209
 231
231
 105
Preferred interest in net income6,279
 6,278
6,278
 6,279
Net loss available to limited partners$(2,946) $(2,067)$(2,067) $(2,627)
      
Basic and diluted weighted average number of units:      
Common units38,146
 40,289
40,289
 40,678
Restricted and phantom units688
 833
833
 769
Total units38,834
 41,122
41,122
 41,447
      
Basic and diluted net loss per common unit$(0.08) $(0.05)$(0.05) $(0.06)


9.    PARTNERS’ CAPITAL AND DISTRIBUTIONS

On December 1, 2017,April 22, 2019, the Partnership issued 1,898,380 common units to Ergon in a private placement valued at $10.2 million in exchange for an asphalt terminalling facility in Bainbridge, Georgia.

On April 23, 2018,announced that the Board approved a cash distribution of $0.17875 per outstanding Preferred Unit for the three months ended March 31, 2018.2019.  The Partnership will pay this distribution on May 15, 201814, 2019, to unitholders of record as of May 4, 20183, 2019. The total distribution will be approximately $6.4 million, with approximately $6.3 million and $0.1 million paid to the Partnership’s preferred unitholders and general partner, respectively.

In addition, on April 23, 2018, the Board approved a cash distribution of $0.14500.04 per outstanding common unit for the three months ended March 31, 2018.2019. The Partnership will pay this distribution on May 15, 201814, 2019, to unitholders of record on May 4, 20183, 2019. The total distribution will be approximately $6.3$1.7 million, with approximately $5.81.6 million and $0.30.1 million to be paid to the

Partnership’s common unitholders and general partner, respectively, and less than $0.20.1 million to be paid to holders of phantom and restricted units pursuant to awards granted under the Partnership’s Long-Term Incentive Plan.
  
10.    RELATED-PARTY TRANSACTIONS

Transactions with Ergon

The Partnership leases asphalt facilities to Ergon and provides asphalt terminalling services to Ergon. For the three months ended March 31, 20172018 and 2018,2019, the Partnership recognized related-party revenues of $13.3$14.0 million and $14.0$9.1 million, respectively, for services provided to Ergon. As of December 31, 2017,2018, and March 31, 2018,2019, the Partnership had receivables from Ergon of $3.1$1.0 million and $2.1$0.9 million, respectively, net of allowance for doubtful accounts. As of December 31, 2017,2018, and March 31, 2018,2019, the Partnership had unearned revenues from Ergon of $1.6$6.5 million and $5.3$16.8 million, respectively.

The Partnership provided operating and administrative services to Advantage Pipeline. OnEffective April 3, 2017,1, 2018, the Partnership soldentered into an agreement with Ergon under which the Partnership purchases crude oil in connection with its investment in Advantage Pipeline. See Note 5 for additional information.crude oil marketing operations. For the three months ended March 31, 2017,2019, the Partnership earned revenuesmade purchases of $0.3crude oil under this agreement totaling $29.7 million. As of March 31, 2019, the Partnership had payables to Ergon related to this agreement of $11.9 million for services providedrelated to Advantage Pipeline.the March crude oil settlement cycle, and this balance was paid in full on April 19, 2019.

The Partnership and Ergon have an agreement (the “Agreement”) that gives each party rights concerning the purchase or sale of Ergon’s interest in Cimarron Express, subject to certain terms and conditions. Cimarron Express was planned to be a new 16-inch diameter, 65-mile crude oil pipeline running from northeastern Kingfisher County, Oklahoma to the Partnership’s Cushing, Oklahoma crude oil terminal, with an originally anticipated in-service date in the second half of 2019. Ergon formed a Delaware limited liability company, Ergon - Oklahoma Pipeline, LLC (“DEVCO”), which holds Ergon’s 50% membership interest in Cimarron Express. Under the Agreement, the Partnership has the right, at any time, to purchase 100% of the authorized and outstanding member interests in DEVCO from Ergon for the Purchase Price (as defined in the Agreement), which shall be computed by taking Ergon’s total investment in the Cimarron Express plus interest, by giving written notice to Ergon (the “Call”). Ergon has the right to require the Partnership to purchase 100% of the authorized and outstanding member interests of DEVCO for the Purchase Price (the “Put”) at any time beginning the earlier of (i) 18 months from the formation, May 9, 2018, of the joint venture company to build the pipeline, (ii) six months after completion of the pipeline, or (iii) the event of dissolution of Cimarron Express. Upon exercise of the Call or the Put, the Partnership and Ergon will execute the Member Interest Purchase Agreement, which is attached to the Agreement as Exhibit B. Upon receipt of the Purchase Price, Ergon shall be obligated to convey 100% of the authorized and outstanding member interests in DEVCO to the Partnership or its designee. As of March 31, 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 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. In addition to its capital contributions to Cimarron Express, Ergon’s interest in DEVCO includes internal Ergon labor and capitalized interest that bring its investment in DEVCO to approximately $17.8 million through March 31, 2019. Ergon recorded a $10.0 million other-than-temporary impairment on its investment in Cimarron Express as of December 31, 2018 to reduce its investment to its estimated fair value. As a result, the Partnership considered the SEC staff’s opinions outlined in SAB 107 Topic 5.T Accounting for Expenses or Liabilities Paid by Principal Stockholders. The Agreement was designed to have the Partnership, ultimately and from the onset, bear any risk of loss on the construction of the pipeline project and eventually own a 50% interest in the pipeline. As a result, the Partnership recorded on a push down basis a $10.0 million impairment of Ergon’s investment in Cimarron Express in its consolidated results of operations during the year ended December 31, 2018, and a contingent liability payable to Ergon as of December 31, 2018. In April 2019, 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. As a result, the Partnership will record in April 2019, on a push down basis, a gain on the sale based on Ergon’s 50% interest in the assets.


11.    LONG-TERM INCENTIVE PLAN

In July 2007, the general partner adopted the Long-Term Incentive Plan (the “LTIP”), which is administered by the compensation committee of the Board. Effective April 29, 2014, the Partnership’s unitholders approved an amendment to the LTIP to increase the number of common units reserved for issuance under the incentive plan to 4,100,000 common units, subject to adjustments for certain events.  Although other types of awards are contemplated under the LTIP, currently outstanding awards include “phantom” units, which convey the right to receive common units upon vesting, and “restricted” units, which are grants of common units restricted until the time of vesting. The phantom unit awards also include distribution equivalent rights (“DERs”).
 
Subject to applicable earning criteria, a DER entitles the grantee to a cash payment equal to the cash distribution paid on an outstanding common unit prior to the vesting date of the underlying award. Recipients of restricted and phantom units are entitled to receive cash distributions paid on common units during the vesting period which are reflected initially as a reduction of partners’ capital. Distributions paid on units which ultimately do not vest are reclassified as compensation expense.  Awards granted to date are equity awards and, accordingly, the fair value of the awards as of the grant date is expensed over the vesting period.  

In connection with each anniversary of joining the Board, restricted common units are granted to the independent directors. The units vest in one-third increments over three years. The following table includes information on outstanding grants made to the directors under the LTIP:
Grant DateNumber of Units 
Weighted Average Grant Date Fair Value(1)
 Grant Date Total Fair ValueNumber of Units 
Weighted Average Grant Date Fair Value(1)
 Grant Date Total Fair Value
(in thousands)
December 201610,950
 $6.85
 $75
10,950
 $6.85
 $75
December 201715,306
 $4.85
 $74
15,306
 $4.85
 $74
December 201823,436
 $1.20
 $28
_________________
(1)    Fair value is the closing market price on the grant date of the awards.


In addition, the independent directors received common unit grants that have no vesting requirement as part of their compensation. The following table includes information on grants made to the directors under the LTIP that have no vesting requirement:
Grant DateNumber of Units 
Weighted Average Grant Date Fair Value(1)
 Grant Date Total Fair ValueNumber of Units 
Weighted Average Grant Date Fair Value(1)
 Grant Date Total Fair Value
(in thousands)
December 201610,220
 $6.85
 $70
10,220
 $6.85
 $70
December 201714,286
 $4.85
 $69
14,286
 $4.85
 $69
December 201821,875
 $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 vesting period. The following table includes information on the outstanding grants:
Grant DateNumber of Units 
Weighted Average Grant Date Fair Value(1)
 Grant Date Total Fair ValueNumber of Units 
Weighted Average Grant Date Fair Value(1)
 Grant Date Total Fair Value
(in thousands)
March 2016416,131
 $4.77
 $1,985
October 20169,960
 $5.85
 $58
March 2017323,339
 $7.15
 $2,312
323,339
 $7.15
 $2,312
March 2018457,984
 $4.77
 $2,185
457,984
 $4.77
 $2,185
March 2019524,997
 $1.14
 $598
_________________
(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 March 31, 20182019, was $3.71.7 million, which will be expensed over the remaining vesting period.

The Partnership’s equity-based incentive compensation expense for each of the three months ended March 31, 20172018 and 20182019, was $0.5 million.million and $0.3 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 ValueNumber of Units Weighted Average Grant Date Fair Value
Nonvested at December 31, 2017923,551
 $6.29
Nonvested at December 31, 2018998,219
 $5.88
Granted457,984
 4.77
524,997
 1.14
Vested234,012
 7.49
366,282
 4.80
Forfeited10,865
 5.39

 
Nonvested at March 31, 20181,136,658
 $5.88
Nonvested at March 31, 20191,156,934
 $3.60

12.    EMPLOYEE BENEFIT PLANS

Under the Partnership’s 401(k) Plan, which was instituted in 2009, employees who meet specified service requirements may contribute a percentage of their total compensation, up to a specified maximum, to the 401(k) Plan. The Partnership may match each employee’s contribution, up to a specified maximum, in full or on a partial basis. The Partnership recognized expense of $0.3 million for each of the three months ended March 31, 20172018 and 2018,2019, for discretionary contributions under the 401(k) Plan.

The Partnership may also make annual lump-sum contributions to the 401(k) Plan irrespective of the employee’s contribution match. The Partnership may make a discretionary annual contribution in the form of profit sharing calculated as a percentage of an employee’s eligible compensation. This contribution is retirement income under the qualified 401(k) Plan. Annual profit sharing contributions to the 401(k) Plan are submitted to and approved by the Board. The Partnership recognized expense of $0.2$0.1 million and $0.1$0.2 million for the three months ended March 31, 20172018 and 2018,2019, respectively, for discretionary profit sharing contributions under the 401(k) Plan.

Under the Partnership’s Employee Unit Purchase Plan (the “Unit Purchase Plan”), which was instituted in January 2015, employees have the opportunity to acquire or increase their ownership of common units representing limited partner interests in the Partnership. Eligible employees who enroll in the Unit Purchase Plan may elect to have a designated whole percentage, up to a specified maximum, of their eligible compensation for each pay period withheld for the purchase of common units at a discount to the then current market value. A maximum of 1,000,000 common units may be delivered under the Unit Purchase Plan, subject to adjustment for a recapitalization, split, reorganization, or similar event pursuant to the terms of the Unit Purchase Plan. The Partnership recognized compensation expense of less than $0.1 million for the each of the three months ended March 31, 20172018 and 2018,2019, in connection with the Unit Purchase Plan.
 
13.    FAIR VALUE MEASUREMENTS
 
The Partnership uses valuation techniques, such as the market approach (comparable market prices), the income approach (present value of future income or cash flow), and the cost approach (cost to replace the service capacity of an asset or replacement cost) to value assets and liabilities required to be measured at fair value, as appropriate. The Partnership uses an exit price when determining the fair value. The exit price represents amounts that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants.
 
The Partnership utilizes a three-tier fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three broad levels. The following is a brief description of those three levels:
Level 1Observable inputs such as quoted prices (unadjusted) in active markets for identical assets or liabilities.
Level 2Inputs other than quoted prices that are observable for these assets or liabilities, either directly or indirectly.  These include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active.

Level 3Unobservable inputs in which there is little market data, which requires the reporting entity to develop its own assumptions.
 
This hierarchy requires the use of observable market data, when available, to minimize the use of unobservable inputs when determining fair value.  In periods in which they occur, the Partnership recognizes transfers into and out of Level 3 as of the end of the reporting period. There were no transfers during the three months ended March 31, 2018.2019. Transfers out of Level 3 represent existing assets and liabilities that were classified previously as Level 3 for which the observable inputs became a more significant portion of the fair value estimates. Determining the appropriate classification of the Partnership’s fair value measurements within the fair value hierarchy requires management’s judgment regarding the degree to which market data is observable or corroborated by observable market data.

The Partnership’s recurring financial assets and liabilities subject to fair value measurements and the necessary disclosures are as follows (in thousands): 
Fair Value Measurements as of December 31, 2017Fair Value Measurements as of December 31, 2018
DescriptionTotal 
Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
  (Level 3)
Total 
Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
  (Level 3)
Assets:              
Interest rate swap assets$68
 $
 $68
 $
$44
 $
 $44
 $
Total swap assets$68
 $
 $68
 $
$44
 $
 $44
 $
Liabilities:       
Interest rate swap liabilities$225
 $
 $225
 $
Total swap liabilities$225
 $
 $225
 $

 Fair Value Measurements as of March 31, 2018
DescriptionTotal 
Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
  (Level 3)
Assets:       
Interest rate swap assets$197
 $
 $197
 $
Total swap assets$197
 $
 $197
 $
As of March 31, 2019, the Partnership had no interest rate swap agreements.

Fair Value of Other Financial Instruments

The following disclosure of the estimated fair value of financial instruments is made in accordance with accounting guidance for financial instruments. The Partnership has determined the estimated fair values by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.
 
At March 31, 2018,2019, the carrying values on the unaudited condensed consolidated balance sheets for cash and cash equivalents (classified as Level 1), accounts receivable, and accounts payable approximate their fair value because of their short-term nature.
 
Based on the borrowing rates currently available to the Partnership for credit agreement debt with similar terms and maturities and consideration of the Partnership’s non-performance risk, long-term debt associated with the Partnership’s credit agreement at March 31, 2018,2019, approximates its fair value. The fair value of the Partnership’s long-term debt was calculated using observable inputs (LIBOR for the risk-free component) and unobservable company-specific credit spread information.   As such, the Partnership considers this debt to be Level 3.

14.    LEASES

The Partnership adopted ASU 2016-02, Leases (Topic 842) as of January 1, 2019, using the modified retrospective approach applied at the beginning of the period of adoption. The Partnership elected the package of practical expedients permitted under the transition guidance within the new standard, which, among other things, allowed it to carry forward the historical lease classification.

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

The Partnership leases certain office space, land and equipment. Leases with an initial term of 12 months or less are not recorded on the balance sheet; lease expense for these leases is recognized as paid over the lease term. For real property leases, the Partnership has elected the practical expedient to not separate nonlease components (e.g., common-area maintenance costs)

from lease components and to instead account for each component as a single lease component. For leases that do not contain an implicit interest rate, the Partnership uses its most recent incremental borrowing rate.

Some real property and equipment leases contain options to renew, with renewal terms that can extend indefinitely. The exercise of such lease renewal options is at the Partnership’s sole discretion. Certain equipment leases also contain purchase options and residual value guarantees. The Partnership determines the lease term at the lease commencement date as the non-cancellable period of the lease, including options to extend or terminate the lease when such an option is reasonably certain to be exercised. The Partnership uses various data to analyze these options, including historical trends, current expectations and useful lives of assets related to the lease.
   As of
 Classification March 31, 2019
   (thousands)
Assets   
Operating lease assetsOperating lease assets $11,594
Finance lease assetsOther noncurrent assets 631
Total leased assets  $12,225
Liabilities   
Current   
Operating lease liabilities
Current operating lease liability

 $2,768
Finance lease liabilitiesOther current liabilities 263
Noncurrent   
Operating lease liabilitiesNoncurrent operating lease liability 8,935
Finance lease liabilitiesOther long-term liabilities 368
Total lease liabilities  $12,334

Future commitments, including options to extend lease terms that are reasonably certain of being exercised, related to leases at March 31, 2019, are summarized below (in thousands):
 Operating Leases Financing Leases
Twelve months ending March 31, 2020$2,993
 $285
Twelve months ending March 31, 20212,447
 215
Twelve months ending March 31, 20221,843
 129
Twelve months ending March 31, 20231,413
 42
Twelve months ending March 31, 20241,199
 
Thereafter5,208
 
Total15,103
 671
Less: Interest3,400
 40
Present value of lease liabilities$11,703
 $631

Future non-cancellable commitments related to operating leases at December 31, 2018, are summarized below (in thousands):  
 Operating Leases
Year ending December 31, 2019$2,862
Year ending December 31, 20201,904
Year ending December 31, 20211,242
Year ending December 31, 2022640
Year ending December 31, 2023548
Thereafter1,259
Total future minimum lease payments$8,455


The following table summarizes the Partnership’s total lease cost by type as well as cash flow information (in thousands):
   Three Months ended
March 31,
 Classification 2019
Total Lease Cost by Type:   
Operating lease cost(1)
Operating Expenses $1,142
Finance lease cost   
Amortization of leased assetsOperating Expenses 70
Interest on lease liabilitiesInterest Expense 7
Net lease cost  $1,219
Supplemental cash flow disclosures:   
Cash paid for amounts included in the measurement of lease liabilities:

   
Operating cash flows from operating leases

  $(750)
Operating cash flows from finance leases

  $(12)
Financing cash flows from finance leases

  $(66)
Leased assets obtained in exchange for new operating lease liabilities
  $569
Leased assets obtained in exchange for new finance lease liabilities

  $112
____________________
(1)    Includes short-term leases and variable lease costs, which are immaterial.
As of
March 31, 2019
Lease Term and Discount Rate
Weighted-average remaining lease term (years)
Operating leases9.0
Finance leases2.8
Weighted-average discount rate
Operating leases5.65%
Finance leases4.20%

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.

15.    OPERATING SEGMENTS

The Partnership’s operations consist of four operatingreportable segments: (i) asphalt terminalling services, (ii) crude oil terminalling services, (iii) crude oil pipeline services and (iv) crude oil trucking and producer field services.  
 
ASPHALT TERMINALLING SERVICES —The Partnership provides asphalt product and residual fuel terminalling services, including storage, blending, processing and blending services at its 56throughput services. On July 12, 2018, the Partnership sold three asphalt facilities. See Note 6 for additional information. The Partnership has 53 terminalling and storage facilities located in 26 states.

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

CRUDE OIL PIPELINE SERVICES —The Partnership owns and operates pipeline systems that gather crude oil purchased by its customers and transports it to refiners, to common carrier pipelines for ultimate delivery to refiners or to terminalling facilities owned by the Partnership and others. The Partnership refers to its pipeline system located in Oklahoma and the Texas Panhandle as the Mid-Continent pipeline system. The Partnership previously owed and operated the East Texas pipeline system, which was located in Texas. On April 17, 2017, the Partnership sold the East Texas pipeline system. See Note 6 for additional information. Crude oil product sales revenues consist of sales proceeds recognized for the sale of crude oil to third-party customers.
 

CRUDE OIL TRUCKING AND PRODUCER FIELD SERVICES — The Partnership uses its owned and leased tanker trucks to gather crude oil for its customers at remote wellhead locations generally not covered by pipeline and gathering systems and to transport the crude oil to aggregation points and storage facilities located along pipeline gathering and transportation systems.  Crude oil producer field services consist of a number of producer field services, ranging from gathering condensates from natural gas companies to hauling produced water to disposal wells. On April 24, 2018, the Partnership sold the producer field services business. See Note 18 for additional information.
 
The Partnership’s management evaluates segment performance based upon operating margin, excluding amortization and depreciation, which includes revenues from related parties and external customers and operating expense, excluding depreciation and amortization. The non-GAAP measure of operatingOperating margin, excluding depreciation and amortization (in the aggregate and by segment) is presented in the following table. The Partnership computes the components of operating margin,

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

The following table reflects certain financial data for each segment for the periods indicated (in thousands):
 Three Months ended
March 31,
 Three Months ended
March 31,
 2017 2018 2018 2019
Asphalt Terminalling Services        
Service revenue:        
Third-party revenue $13,223
 $5,132
 $5,132
 $6,982
Related-party revenue 13,332
 6,321
 6,321
 4,118
Lease revenue:        
Third-party revenue 
 9,458
 9,458
 9,763
Related-party revenue 
 7,702
 7,702
 4,940
Total revenue for reportable segment 26,555
 28,613
 28,613
 25,803
Operating expense, excluding depreciation and amortization 12,319
 13,333
 13,333
 12,285
Operating margin, excluding depreciation and amortization $14,236
 $15,280
 $15,280
 $13,518
Total assets (end of period) $145,815
 $170,473
 $170,473
 $147,844
        
Crude Oil Terminalling Services        
Service revenue:        
Third-party revenue $6,125
 $4,585
 $4,585
 $3,573
Intersegment revenue 
 298
Lease revenue:        
Third-party revenue 
 15
 15
 
Total revenue for reportable segment 6,125
 4,600
 4,600
 3,871
Operating expense, excluding depreciation and amortization 1,011
 1,275
 1,275
 1,282
Operating margin, excluding depreciation and amortization $5,114
 $3,325
 $3,325
 $2,589
Total assets (end of period) $70,518
 $68,160
 $68,160
 $67,934
        

 Three Months ended
March 31,
 Three Months ended
March 31,
 2017 2018 2018 2019
Crude Oil Pipeline Services        
Service revenue:        
Third-party revenue $2,605
 $2,061
 $2,061
 $2,498
Related-party revenue 310
 
 
 101
Lease revenue:        
Third-party revenue 
 235
 235
 
Product sales revenue:        
Third-party revenue 3,650
 3,508
 3,508
 58,924
Total revenue for reportable segment 6,565
 5,804
 5,804
 61,523
Operating expense, excluding depreciation and amortization 3,242
 2,785
 2,785
 2,722
Operating expense (intersegment) 170
 442
Cost of product sales 3,139
 2,637
Intersegment operating expense 442
 1,627
Third-party cost of product sales 2,637
 24,587
Related-party cost of product sales 
 30,774
Operating margin, excluding depreciation and amortization $14
 $(60) $(60) $1,813
Total assets (end of period) $145,351
 $116,845
 $116,845
 $98,722
        
Crude Oil Trucking and Producer Field Services    
Service revenue:    
Crude Oil Trucking Services    
Service revenue    
Third-party revenue $6,710
 $5,540
 $5,540
 $2,833
Intersegment revenue 170
 442
 442
 1,329
Lease revenue:        
Third-party revenue 
 97
 97
 
Product sales revenue:        
Third-party revenue 385
 6
 6
 
Total revenue for reportable segment 7,265
 6,085
 6,085
 4,162
Operating expense, excluding depreciation and amortization 7,268
 6,375
 6,375
 4,220
Operating margin, excluding depreciation and amortization $(3) $(290) $(290) $(58)
Total assets (end of period) $12,383
 $6,113
 $6,113
 $5,156
        
Total operating margin, excluding depreciation and amortization(1)
 $19,361
 $18,255
 $18,255
 $17,862
        
Total segment revenues $46,510
 $45,102
Elimination of intersegment revenues (170) (442)
Consolidated revenues $46,340
 $44,660
Total Segment Revenues $45,102
 $95,359
Elimination of Intersegment Revenues (442) (1,627)
Consolidated Revenues $44,660
 $93,732
____________________
(1)The following table reconciles segment operating margin (excluding depreciation and amortization) to income before income taxes (in thousands):
 Three Months ended
March 31,
Three Months ended
March 31,
 2017 20182018 2019
Operating margin, excluding depreciation and amortization $19,361
 $18,255
$18,255
 $17,862
Depreciation and amortization (8,066) (7,367)(7,367) (6,734)
General and administrative expense (4,585) (4,221)(4,221) (3,693)
Asset impairment expense (28) (616)(616) (1,119)
Loss on sale of assets (125) (236)
Gain (loss) on sale of assets(236) 1,724
Interest expense (3,030) (3,569)(3,569) (4,271)
Gain on sale of unconsolidated affiliate 
 2,225
2,225
 
Equity earnings in unconsolidated affiliate 61
 
Income before income taxes $3,588
 $4,471
$4,471
 $3,769

15.16.    COMMITMENTS AND CONTINGENCIES

The Partnership is from time to time subject to various legal actions and claims incidental to its business. Management believes that these legal proceedings will not have a material adverse effect on the financial position, results of operations or cash flows of the Partnership. Once management determines that information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred and the amount of such liability can be reasonably estimated, an accrual is established equal to its estimate of the likely exposure.
  
The Partnership has contractual obligations to perform dismantlement and removal activities in the event that some of its asphalt product and residual fuel oil terminalling and storage assets are abandoned. These obligations include varying levels of activity including completely removing the assets and returning the land to its original state. The Partnership has determined that the settlement dates related to the retirement obligations are indeterminate. The assets with indeterminate settlement dates have been in existence for many years and with regular maintenance will continue to be in service for many years to come. Also, it is not possible to predict when demands for the Partnership’s terminalling and storage services will cease, and the Partnership does not believe that such demand will cease for the foreseeable future.  Accordingly, the Partnership believes the date when these assets will be abandoned is indeterminate. With no reasonably determinable abandonment date, the Partnership cannot reasonably estimate the fair value of the associated asset retirement obligations.  Management believes that if the Partnership’s asset retirement obligations were settled in the foreseeable future the present value of potential cash flows that
would be required to settle the obligations based on current costs are not material.  The Partnership will record asset retirement obligations for these assets in the period in which sufficient information becomes available for it to reasonably determine the settlement dates.

16.17.    INCOME TAXES

In relation to the Partnership’s taxable subsidiary, the tax effects of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts at March 31, 2018,2019, are presented below (dollars in thousands):
 
Deferred Tax Asset  
Difference in bases of property, plant and equipment$464
$260
Net operating loss carryforwards5
7
Deferred tax asset469
267
Less: valuation allowance464
267
Net deferred tax asset$5
$
 
The Partnership has considered the taxable income projections in future years, whether the carryforward period is so brief that it would limit realization of tax benefits, whether future revenue and operating cost projections will produce enough taxable income to realize the deferred tax asset based on existing service rates and cost structures and the Partnership’s earnings history exclusive of the loss that created the future deductible amount for the Partnership’s subsidiary that is taxed as a corporation for purposes of determining the likelihood of realizing the benefits of the

deferred tax assets. As a result of the Partnership’s consideration of these factors, the Partnership has provided a valuation allowance against its deferred tax asset related to the difference in bases of property, plant and equipment as of March 31, 2018.2019.

17.18.    RECENTLY ISSUED ACCOUNTING STANDARDS

Except as discussed below and in the 20172018 Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the three months ended March 31, 2018,2019, that are of significance or potential significance to the Partnership.

In May 2014,February 2016, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers.2016-02, “Leases (Topic 842) The amendments in this update create Topic 606, Revenue from Contracts with Customers, and supersede the revenue recognition requirements in Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the Industry Topics of the Codification. In addition, the amendments supersede the cost guidance in Subtopic 605-35, Revenue Recognition-Construction-Type and Production-Type Contracts, and create new Subtopic 340-40, Other Assets and Deferred Costs-Contracts with Customers. In summary, the core principle of Topic 606. This is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Throughout 2015 and 2016, the FASB has issued a series of subsequent updatescomprehensive update to the revenue recognition guidancelease accounting topic in Topic 606, including ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” ASU No. 2016-08, “Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net),” ASU No. 2016-10, “Revenue from Contracts with Customers (Topic 606): Identifying Performance ObligationsCodification intended to increase transparency and Licensing,” ASU No. 2016-12, “Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvementscomparability among organizations by recognizing lease assets and Practical Expedients”lease liabilities on the balance sheet and ASU No. 2016-20, “Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers.”

disclosing key information about leasing arrangements. The amendments in ASU 2014-09, ASU 2016-08, ASU 2016-10, ASU 2016-12 and ASU 2016-20 are effective for public entities for annual reporting periods beginning after December 15, 2017, and for interim periods within that reporting period.2016-02 include a revised definition of a lease as well as certain scope exceptions. The changes primarily impact lessee accounting, while lessor accounting is largely unchanged from previous GAAP. The Partnership adopted this update instandard as of January 1, 2019, using the three-month period ending March 31, 2018.modified retrospective approach. See Note 3 and Note 14 for disclosures related to the adoption of this standard and the impact on the Partnership’s financial position, results of operations and cash flows.

In January 2016, the FASB issued ASU 2016-01, “Financial Instruments - Overall (Subtopic 825-10).” This update is intended to enhance the reporting model for financial instruments in order to provide users of financial statements with more decision-useful information. The amendments in the update address certain aspects of recognition, measurement, presentation and disclosure of financial instruments. This update is effective for financial statements issued for annual periods beginning after December 15, 2017, and interim periods within those fiscal years. The Partnership adopted this update in the three-month period ending March 31, 2018, and there was no impact on the Partnership’s financial position, results of operations or cash flows.

In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.” This update addresses the following eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies (including bank-owned life insurance policies); distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle.

This update is effective for financial statements issued for annual periods beginning after December 15, 2017, and interim periods within those fiscal years. The Partnership adopted this update in the three-month period ending March 31, 2018, and there was no impact on the Partnership’s financial position, results of operations or cash flows.

In October 2016, the FASB issued ASU 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory.” This update is intended to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. The amendments in the update eliminate the prohibition of recognizing current and deferred income taxes for an intra-entity asset transfer other than inventory until the asset has been sold to an outside party. This update is effective for financial statements issued for annual periods beginning after December 15, 2017, and interim periods within those fiscal years. The Partnership adopted this update in the three-month period ending March 31, 2018, and there was no impact on the Partnership’s financial position, results of operations or cash flows.

In November 2016, the FASB issued ASU 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash (a Consensus of the FASB Emerging Issues Task Force).” This update requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. This update is effective for financial statements issued for annual periods beginning after December 15, 2017, and interim periods within those fiscal years. The Partnership adopted this update in the three-month period ending March 31, 2018, and there was no impact on the Partnership’s financial position, results of operations or cash flows.

In January 2017, the FASB issued ASU 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business.” This update clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This update is effective for financial statements issued for annual periods beginning after December 15, 2017, and interim periods within those fiscal years. The Partnership adopted this update in the three-month period ending March 31, 2018, and there was no impact on the Partnership’s financial position, results of operations or cash flows.

In February 2017, the FASB issued ASU 2017-05, “Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20).” This update clarifies the scope of Subtopic 610-20 and adds guidance for partial sales of nonfinancial assets. Subtopic 610-20, which was issued in May 2014 as a part of ASU 2014-09, “Revenue from Contracts with Customers (Topic 606),” provides guidance for recognizing gains and losses from the transfer of nonfinancial assets in contracts with noncustomers. The amendments in ASU 2017-05 are effective for public entities for annual reporting periods beginning after December 15, 2017, and for interim periods within that reporting period. Early application is permitted for annual reporting periods beginning after December 15, 2016. The Partnership adopted this update in the three-month period ending March 31, 2018, and there was no impact on the Partnership’s financial position, results of operations or cash flows.

In May 2017, the FASB issued ASU 2017-09, “Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting.” This update provides clarity and reduces both diversity in practice and cost and complexity when applying the guidance of Topic 718, Compensation - Stock Compensation, to a change in the terms or conditions of a share-based payment award. This update is effective for financial statements issued for annual periods beginning after December 15, 2017, and interim periods within those fiscal years. The Partnership adopted this update in the three-month period ending March 31, 2018, and there was no impact on the Partnership’s financial position, results of operations or cash flows.

18.    SUBSEQUENT EVENTS

Sale of Producer Field Services
On April 24, 2018, the Partnership sold its producer field services business for approximately $3.0 million. Included in assets held for sale as of March 31, 2018, were property, plant and equipment of $1.3 million and finite-lived intangible assets of $0.2 million. The Partnership recognized a $0.4 million gain on the sale.

Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations.
  
As used in this quarterly report, unless we indicate otherwise: (1) “Blueknight Energy Partners,” “our,” “we,” “us” and similar terms refer to Blueknight Energy Partners, L.P., together with its subsidiaries, (2) our “General Partner” refers to Blueknight Energy Partners G.P., L.L.C., (3) “Ergon” refers to Ergon, Inc., its affiliates and subsidiaries (other than our General Partner and us) and (4) “Vitol” refers to Vitol Holding B.V., its affiliates and subsidiaries.  The following discussion analyzes the historical financial condition and results of operations of the Partnership and should be read in conjunction with our financial statements and notes thereto, and Management’s Discussion and Analysis of Financial Condition and Results of Operations presented in our Annual Report on Form 10-K for the year ended December 31, 2017,2018, which was filed with the Securities and Exchange Commission (the “SEC”) on March 8, 201812, 2019 (the “2017“2018 Form 10-K”). 

Forward-Looking Statements
 
This report contains forward-looking statements.  Statements included in this quarterly report that are not historical facts (including any statements regarding plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), including, without limitation, the information set forth in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “will,” “should,” “believe,” “expect,” “intend,” “anticipate,

“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 20172018 Form 10-K.
 
All forward-looking statements included in this report are based on information available to us on the date of this report. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements contained throughout this report.

Overview
 
We are a publicly traded master limited partnership with operations in 27 states. We provide integrated terminalling, gathering and transportation services for companies engaged in the production, distribution and marketing of liquid asphalt and crude oil.  We manage our operations through four operating segments: (i) asphalt terminalling services, (ii) crude oil terminalling services, (iii) crude oil pipeline services and (iv) crude oil trucking and producer field services.

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

Since June 2014, theThe crude oil market price of West Texas Intermediate crude oil has fluctuatedand the corresponding forward market pricing curve may fluctuate significantly from a peak
of approximately $108 per barrelperiod to a low of approximately $30 per barrel (as of May 3, 2018, the price per barrel was approximately $68).period. In addition, to changes in the price of crude oil and the forward pricing curve, there has been significant volatility in the overall energy industry and specifically in publicly traded midstream energy partnerships. As a result there are a number of trends thatpartnerships may impact our partnership in the near term. TheseFactors 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 March 31, 2018,May 6, 2019, the forward price curve is slightly backwardated. We expectin a shallow contango. Potential impacts of these changes to have near-term impacts asfactors are discussed below.

Asphalt Terminalling Services - Although there is no direct correlation between the price of crude oil and the price of asphalt, the asphalt industry tends to benefit from a lower crude oil price environment, a strong economy and an increase in infrastructure spending. As a result, we do not expect recentthe changes in the price of crude oil to significantly impact our asphalt terminalling services operating segment. We have received positive feedback from customers that they are generally expecting improved throughput volumes through our terminals in 2019; however, since it is early in the asphalt season, we cannot be certain of the level of those throughput volumes or the impact that weather may have on customers’ construction or paving projects throughout the year.

In March 2019, our Wolcott, Kansas, asphalt facility was damaged by flooding of the Missouri River. While the facility was able to successfully execute its flood plan to minimize damages, costs related to the flood are expected to include $0.2 million of maintenance operating expenses for removal and reinstallation of equipment and $0.3 million of maintenance capital expenses for repairs to land improvements and tank insulation. Impairment expense related to the assets was approximately $0.3 million. In addition, we expect a loss of revenue of approximately $0.2 million for the period of time in which the facility was shut down. While we are pursuing insurance claims for this event, there can be no assurance of the amount or timing of any proceeds we may receive under such claims.

On July 12, 2018, we sold certain asphalt terminals, storage tanks and related real property, contracts, permits, assets and other interests located in Lubbock and Saginaw, Texas and Memphis, Tennessee (the “Divestiture”) to Ergon for a purchase price of $90.0 million, subject to customary adjustments.

Crude Oil Terminalling Services - A contango crude oil curve tends to favor the crude oil storage business as crude oil marketers are incentivized to store crude oil during the current month and sell into the future month. As a result of the decrease in the price of crude oil and the change in the crude oil futures pricing curve, our weighted average storage rates increased from September 2014 to March 2016. Since March of 2016, the crude oil curve has generally been in a shallow contango or backwardation. In these shallow contango or backwardationbackwardated markets there is no clear incentive for marketers to store barrels. As of March 31, 2018, the forward price curve is slightly backwardated.crude oil. A shallow contango or a backwardated market may impact

our ability to re-contract expiring contracts and/or decrease the storage rate at which we are able to re-contract. Total Cushing inventories peaked at just under 70 million barrels stored in March of 2017 and bottomed at approximately 30 million barrels stored in January of 2018. Furthermore, current storage levels are significantly below the 5-year average for storage volumes. As a result of the current shape of the curveshallow contango and lessened overall demand for Cushing storage, we anticipate that we will continue to experience a weakchallenging recontracting environment which may impact both the volume of storage we are able to successfully recontract and the rate at which we recontract. These periods are typically fairly short-lived but there can be no assurance as to the timing of a rebound in the Cushing storage market.

Crude Oil Pipeline Services - In lateA backwardated crude oil curve tends to favor the crude oil pipeline transportation business as crude oil marketers are incentivized to transport crude oil to market for sale as soon as possible. However, our crude oil pipeline services business has been impacted recently by an out-of-service pipeline. Between April 2016 as a precautionary measure,and July 2018, we suspended service on a segment of our Mid-Continent pipeline system due to discovery of a pipeline exposure caused by heavy rains and the erosion of a riverbed in southern Oklahoma. There was no damage to the pipeline and no loss of product. In the second quarter of 2016, we took action to mitigate the service suspension and worked with customers to divert volumes and, in certain circumstances, transported volumes to a third-party pipeline system via truck. In addition, the term of the throughput and deficiency agreement on our Eagle North pipeline system expired on June 30, 2016, and in July 2016, we completed a connection of the southeastern most portion of our Mid-Continent pipeline system to our Eagle North pipeline system and concurrently reversed the Eagle North pipeline system.

We are currentlyhad been operating one Oklahoma mainlinepipeline system, which is a combination of both the Mid-Continent and Eagle North pipeline systems, instead of two separate systems, providing us with a current capacity of approximately 20,000 to 25,000 barrels per day (Bpd). We are workingIn July 2018, we were able to restore service of theto a second Oklahoma pipeline system and expect to put the line back in service by the end of the second quarter of 2018, increasingwhich has increased the transportation capacity of our pipeline systems by approximately 20,000 Bpd. The ability to fully utilize the capacity of these systems may be impacted by the market price of crude oil and producers’ decisions to increase or decrease production in the areas we serve.

Over the past year, we increased the volumes of crude oil transported for our internal crude oil marketing operations with the objective of increasing the overall utilization of our Oklahoma crude oil pipeline systems.  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. We may also be exposed to price risk with respect to the differing qualities of crude oil we transport and our ability to effectively blend them to market specifications.

On April 3, 2017, AdvantageMay 10, 2018, we, together with affiliates of Ergon and Kingfisher Midstream, LLC (“Kingfisher Midstream”), a subsidiary of Alta Mesa Resources, Inc., announced the execution of definitive agreements to form Cimarron Express Pipeline, L.L.C.LLC (“Cimarron Express”). We have an agreement (the “Agreement”) with Ergon that gives each party rights concerning the purchase or sale of Ergon’s interest in Cimarron Express, subject to certain terms and conditions. Cimarron Express was formed to build a new 16-inch diameter, 65-mile crude oil pipeline running from northeastern Kingfisher County, Oklahoma to the Partnership’s Cushing, Oklahoma crude oil terminal, with an originally anticipated in-service date in the second half of 2019. Ergon formed a Delaware limited liability company, Ergon - Oklahoma Pipeline, LLC (“DEVCO”), which holds Ergon’s 50% membership interest in Cimarron Express. Under the Agreement, we have the right, at any time, to purchase 100% of the authorized and outstanding member interests in DEVCO from Ergon for the Purchase Price (as defined in the Agreement), which we owned an approximate 30% equity ownershipshall be computed by taking Ergon’s total investment in the Cimarron Express plus interest, was acquired by agiving written notice to Ergon (the “Call”). Ergon has the right to require us to purchase 100% of the authorized and outstanding member interests of DEVCO for the Purchase Price (the “Put”) at any time beginning the earlier of (i) 18 months from the formation, May 9, 2018, of the joint venture formed by affiliatescompany to build the pipeline, (ii) six months after completion of Plains All American Pipeline, L.P.the pipeline, or (iii) the event of dissolution of Cimarron Express. Upon exercise of the Call or the Put, we and NobleErgon will execute the Member Interest Purchase Agreement, which is attached to the Agreement as Exhibit B. Upon receipt of the Purchase Price, Ergon shall be obligated to convey 100% of the authorized and outstanding member interests in DEVCO to us or our designee. As of March 31, 2019, neither Ergon nor the Partnership has exercised their options under the Agreement.

In December 2018, we and Ergon were informed that Kingfisher Midstream Partners LP. We received cash proceeds at closingmade the decision to suspend future investments in Cimarron Express as Kingfisher Midstream determined that the anticipated volumes from the salecurrently dedicated acreage, and the resultant project economics, did not support additional investment from Kingfisher Midstream. As of our approximate 30% equity ownershipDecember 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. In addition to its capital contributions to Cimarron Express, Ergon’s interest in Advantage PipelineDEVCO includes internal Ergon labor and capitalized interest that bring its investment in DEVCO to approximately $17.8 million through March 31, 2019. 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, we considered the SEC staff’s opinions outlined in SAB 107 Topic 5.T Accounting for Expenses or Liabilities Paid by Principal Stockholders. The Agreement was designed to have us, 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, we recorded on a push down basis a $10.0 million impairment of Ergon’s investment in Cimarron Express in our consolidated results of operations during the year ended December 31, 2018, and a contingent liability payable to Ergon as of December 31, 2018. During the three months ended March 31, 2019, a change in estimate resulted in an additional impairment expense of $0.8 million. In April 2019, certain assets from the project were sold to a third-party for approximately $25.3$1.4 million and recordedover the fair market value that was estimated at December 31, 2018. As a result, we will record in April 2019, on a push down basis, a gain on the sale ofbased on Ergon’s 50% interest in the investment of $4.2 million. Approximately 10% of the gross sales proceeds were held in escrow, subject to certain post-closing settlement terms and conditions. We received approximately $1.1 million of the funds held in escrow in August 2017 and our remaining balance of $2.2 million in January 2018.assets.


Crude Oil Trucking and Producer Field Services - We continueCrude 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 experience increased competition in this segment, which has resulted in further pressures onhave the rates we are ableappropriate level of assets located properly to charge our customersefficiently move the barrels to delivery points for services provided. In December 2017, we evaluated our producer field services business for impairment and recognized an impairment expense of $2.4 million to record our assets at their estimated fair value. customers.

On April 24, 2018, we sold our producer field services business, which was included in assets held for sale at March 31, 2018.has been historically reported along with the crude oil trucking services.

Our Revenues 

Our revenues consist of (i) terminalling revenues, (ii) gathering transportation and producer field servicestransportation revenues, (iii) product sales revenues and (iv) fuel surcharge revenues. For the three months ended March 31, 2018,2019, the Partnership recognized revenues of $14.0$9.1 million and $0.1 million for services provided to Ergon and Cimarron Express, respectively, with the remainder of our services being provided to third parties.

Terminalling revenues consist of (i) storage service fees resulting from short-term and long-term contracts for committed space that may or may not be utilized by the customer in a given monthmonth; and (ii) terminal throughput feesservice charges to pump crude oil to connecting carriers or to deliver asphalt product out of our terminals. Terminal throughput service charges are recognized as the crude oil or asphalt product is delivered out of our terminal. Storage service revenues are recognized as the services are provided on a monthly basis. We earn terminalling revenues in two of our segments: (i) asphalt terminalling services and (ii) crude oil terminalling services. Storage service revenues are recognized as the services are provided on a monthly basis. Throughput fees in our asphalt terminalling services segment are recognized straight-line over time. Throughput fees in our crude oil terminalling services segments are recognized as the crude oil is delivered out of our terminal.

We have leases and terminalling agreements with customers for all of our 5653 asphalt facilities, including 2623 facilities under contract with Ergon.  Lease and terminallingThese agreements related to 16 of these facilities have terms that expire at the end of 2018, while the agreements relating to our additional 40 facilities have, on average, approximately five years remaining under their terms. FifteenAgreements for four of the contractsfacilities expire by the end of 2019, and the remaining agreements expire at varying times thereafter, including agreements for 23 facilities that expire in 2018 are with Ergon.2023. We may not be able to extend, renegotiate or replace these contracts when they expire and the terms of any renegotiated contracts may not be as favorable as the contracts they replace. We operate the asphalt facilities pursuant to the terminalling agreements, while our contract counterparties operate the asphalt facilities that are subject to lease agreements.

Through April 30, 2018,As of May 6, 2019, we had approximately 4.95.8 million barrels of crude oil storage under service contracts.contracts, including 3.1 million barrels of crude oil storage contracts that expire in 2019. The remaining terms on the service contracts range from 5 to 32 months. Storage contracts with Vitol represented 2.2represent 2.9 million barrels of crude oil storage capacity under a contract that expired on April 30, 2018. We were notified by Vitol of its intent to exit our terminal at the expiration of the contract, and we are in the process of that transition. Service contracts relating to an additional 1.90.5 million barrels also expire in 2018.are under an intercompany contract.

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

Gathering and transportation services revenues consist of service fees recognized for the gathering of crude oil for our customers and the transportation of crude oil to refiners, to common carrier pipelines for ultimate delivery to refiners or to terminalling facilities owned by us and others. We earn gathering and transportation revenues in two of our segments: (i) crude oil pipeline services and (ii) crude oil trucking and producer field services (as noted above we sold the producer field services business in April 2018).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.  Producer field services revenue consists

The following is a summary of a numberour average gathering and transportation volumes for the periods indicated (in thousands of services ranging from gathering condensates from natural gas producers to hauling produced water to disposal wells.  Revenue for producer field services is recognized when the service is performed.barrels per day):
 Three Months ended
March 31,
 Favorable/(Unfavorable)
 
 2018 2019 Three Months
Average pipeline throughput volume23
 37
 14
 61%
Average trucking transportation volume23
 27
 4
 17%
  
DuringWe completed work on the three months ended March 31, 2018, we transported approximately 23,000 Bpd on our Mid-Continent pipeline system, which is an increase of 5% compared to the three months ended March 31, 2017. We are working to restore service of the second OklahomaEagle pipeline system and expect to put the line backrestored service in service by the end of the second quarter ofJuly 2018, increasing the transportation capacity of our pipeline systems by approximately 20,000 Bpd. See Crude oil pipeline services segment within our results of operations discussion for additional detail. Vitol accounted for 56%57% and 57%41% of volumes transported in our pipelines in the three months ended March 31, 20172018 and 2018,2019, respectively.

For the three months ended March 31, 2018, we transported approximately 23,000 Bpd on our crude oil transport trucks, an increase of 5% as compared to the three months ended March 31, 2017. Vitol accounted for approximately 45% and 30% of volumes transported by our crude oil transport trucks in the three months ended March 31, 2017 and 2018, respectively. When our second Oklahoma pipeline system resumes service, we anticipate additional increases in volumes transported by our crude oil transport trucks as we gather barrels to be transported on this pipeline.

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

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


Our Expenses

Operating expenses decreased slightly by 2%13% for the three months ended March 31, 2018,2019, as compared to the three months ended March 31, 2017. This is primarily a result2018. In addition to decreases related to the sale of a decreasethe three asphalt plants in July 2018, depreciation expense decreased due to certain assets reaching the end of their depreciable lives as well as a decrease inand vehicle expenses decreased due to operating a smallerreduction in the size of our fleet. General and administrative expenses remained relatively consistentdecreased 13% for the three months ended March 31, 2018,2019, as compared to the three months ended March 31, 2017.2018. The decrease is primarily due to decreased compensation expense. Our interest expense increased by $0.5$0.7 million for the three months ended March 31, 2018,2019, as compared to the three months ended March 31, 2017.2018. See Interest expense within our results of operations discussion for additional detail regarding the factors that contributed to the increase in interest expense in 2018.2019.

Income Taxes

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

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

taxable income projections in future years;
whether the carryforward period is so brief that it would limit realization of tax benefits;
future revenue and operating cost projections that will produce more than enough taxable income to realize the deferred tax asset based on existing service rates and cost structures; and
our earnings history exclusive of the loss that created the future deductible amount coupled with evidence indicating that the loss is an aberration rather than a continuing condition.

Based on the consideration of the above factors for our subsidiary that is taxed as a corporation for purposes of determining the likelihood of realizing the benefits of the deferred tax assets, we have provided a full valuation allowance against our deferred tax asset related to the difference in bases of property, plant and equipment as of March 31, 20182019.

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 April 23, 2018,22, 2019, we announced that the Board approved a cash distribution of $0.17875 per outstanding Preferred Unit for the three months ended March 31, 2018.2019. We will pay this distribution on May 15, 2018,14, 2019, to unitholders of record as of May 4, 2018.3, 2019. The total distribution will be approximately $6.4 million, with approximately $6.3 million and $0.1 million paid to our preferred unitholders and General Partner, respectively.

In addition, on April 23, 2018, the Board approved a cash distribution of $0.1450$0.04 per outstanding common unit for the three months ended March 31, 2018.2019. We will pay this distribution May 15, 2018,14, 2019, to unitholders of record on May 4, 2018.3, 2019. The total distribution will be approximately $6.3$1.7 million, with approximately $5.8$1.6 million and $0.3$0.1 million paid to our common unitholders and General Partner, respectively, and $0.2less than $0.1 million paid to holders of phantom and restricted units pursuant to awards granted under our Long-Term Incentive Plan.


Results of Operations

Non-GAAP Financial Measures
 
To supplement our financial information presented in accordance with GAAP, management uses additional measures that are known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future.  The primary measure used by management is operating margin, excluding depreciation and amortization.
 
Management believes that the presentation of such additional financial measures provides useful information to investors regarding our performance and results of operations because these measures, when used in conjunction with related GAAP financial measures, (i) provide additional information about our core operating performance and ability to generate and distribute cash flow; (ii) provide investors with the financial analytical framework upon which management bases financial, operational, compensation and planning decisions and (iii) present measurements that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. These additional financial measures are reconciled to the most directly comparable measures as reported in accordance with GAAP, and should be viewed in addition to, and not in lieu of, our unaudited condensed consolidated financial statements and footnotes. 

The table below summarizes our financial results for the three months ended March 31, 20172018 and 20182019, reconciled to the most directly comparable GAAP measure:
Operating ResultsThree Months ended March 31, Favorable/(Unfavorable)
 Three Months ended
March 31,
 Favorable/(Unfavorable) Three Months
(dollars in thousands) 2017 2018 $ %2018 2019 $ %
Operating margin, excluding depreciation and amortization:               
Asphalt terminalling services $14,236
 $15,280
 $1,044
 7 %$15,280
 $13,518
 $(1,762) (12)%
Crude oil terminalling services 5,114
 3,325
 (1,789) (35)%3,325
 2,589
 (736) (22)%
Crude oil pipeline services 14
 (60) (74) (529)%(60) 1,813
 1,873
 3,122 %
Crude oil trucking and producer field services (3) (290) (287) (9,567)%
Crude oil trucking services(290) (58) 232
 80 %
Total operating margin, excluding depreciation and amortization 19,361
 18,255
 (1,106) (6)%18,255
 17,862
 (393) (2)%
               
Depreciation and amortization (8,066) (7,367) 699
 9 %(7,367) (6,734) 633
 9 %
General and administrative expense (4,585) (4,221) 364
 8 %(4,221) (3,693) 528
 13 %
Asset impairment expense (28) (616) (588) (2,100)%(616) (1,119) (503) (82)%
Loss on sale of assets (125) (236) (111) (89)%
Gain (loss) on sale of assets(236) 1,724
 1,960
 831 %
Operating income 6,557
 5,815
 (742) (11)%5,815
 8,040
 2,225
 38 %
               
Other income (expenses):               
Equity earnings in unconsolidated affiliate 61
 
 (61) (100)%
Gain on sale of unconsolidated affiliate 
 2,225
 2,225
 N/A
2,225
 
 (2,225) (100)%
Interest expense (3,030) (3,569) (539) (18)%(3,569) (4,271) (702) (20)%
Provision for income taxes (46) (29) 17
 37 %(29) (12) 17
 59 %
Net income $3,542
 $4,442
 $900
 25 %$4,442
 $3,757
 $(685) (15)%
 
For the three months ended March 31, 2018,2019, overall operating margin, excluding depreciation and amortization, increased in our asphalt terminalling services segmentdecreased slightly as compared to the same period in 2017 primarily due to2018. Our asphalt terminalling services segment operating margin, excluding

depreciation and amortization, was impacted by both the acquisition of twoan asphalt facilities, one from Ergon in December 2017 and one from a third partyfacility in March 2018 as well asand the conversionsale of another facility from a lease agreementthree asphalt terminals to a storage, handling and throughput agreement. These increases were partially offset by lower operating marginsErgon in our other segments.July 2018. The decrease in our crude oil terminalling services operating margin, excluding depreciation and amortization,was is primarily due to lower storage rates. The crude oil pipeline services margin, excluding depreciation and amortization, continues to be affected by the suspended service on ourOur Mid-Continent pipeline systemwas placed back in service in July 2018, after suspending service in April 2016 due to the discovery of a pipeline exposure, and margins in April 2016.our crude oil pipeline services segment reflect the recovery of throughput volumes since then. A sale of crude oil product accumulated over time through customer loss allowance deductions for the three months ended March 31, 2019, also contributed to the increased margin in our crude oil pipeline services segment; there were no such sales in the same period in 2018. Crude oil trucking and producer field services operating margin, excluding depreciation and amortization, decreasedimproved for the three months ended March 31, 2019, due to decreasesan increase in the average miles hauled per transaction, which results in lower revenues per barrelvolumes transported.

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

Analysis of Operating Segments

Asphalt terminalling services segment

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

The following table sets forth our operating results from our asphalt terminalling services segment for the periods indicated:
Operating resultsThree Months
ended
March 31,
 Favorable/(Unfavorable)
 Three Months ended
March 31,
 Favorable/(Unfavorable) Three Months
(dollars in thousands) 2017 2018 $ %2018 2019 $ %
Service revenue:               
Third-party revenue $13,223
 $5,132
 $(8,091) (61)%$5,132
 $6,982
 $1,850
 36 %
Related-party revenue 13,332
 6,321
 (7,011) (53)%6,321
 4,118
 (2,203) (35)%
Lease revenue:               
Third-party revenue 
 9,458
 9,458
 N/A
9,458
 9,763
 305
 3 %
Related-party revenue 
 7,702
 7,702
 N/A
7,702
 4,940
 (2,762) (36)%
Total revenue 26,555
 28,613
 2,058
 8 %28,613
 25,803
 (2,810) (10)%
Operating expense, excluding depreciation and amortization 12,319
 13,333
 (1,014) (8)%13,333
 12,285
 1,048
 8 %
Operating margin, excluding depreciation and amortization $14,236
 $15,280
 $1,044
 7 %$15,280
 $13,518
 $(1,762) (12)%

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

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

Overall revenues have increaseddecreased for the three months ended March 31, 2018,2019, as compared to the three months ended March 31, 2017, primarily2018. 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 resulted in an increase of $1.2 million and $0.3 million, respectively, in revenue and was offset by a decrease in revenue of $5.0 million due to the acquisitionsale of twothree asphalt facilities one from Ergon in December 2017 and one from a third party in MarchJuly 2018. In addition, a third facility converted from a lease contract to a storage, throughput and handling contract, which generates higher gross revenue. Third-party revenues also increased overall due to increases in reimbursement revenues.

Operating expenses increaseddecreased for the three months ended March 31, 2018,2019, as compared to the three months ended March 31, 2017,2018, primarily as a result of the acquisitions noted above. In addition, ad valorem taxesthree facilities sold in July 2018 and partially offset by the acquisition in March 2018, as well as, increased due to revised tax assessments.utility costs at some facilities.


Crude oil terminalling services segment

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

The following table sets forth our operating results from our crude oil terminalling services segment for the periods indicated:
Operating resultsThree Months
ended
March 31,
 Favorable/(Unfavorable)
 Three Months ended
March 31,
 Favorable/(Unfavorable) Three Months
(dollars in thousands) 2017 2018 $ %2018 2019 $ %
Service revenue:               
Third-party revenue $6,125
 $4,585
 $(1,540) (25)%$4,585
 $3,573
 $(1,012) (22)%
Intersegment revenue
 298
 298
 N/A
Lease revenue:               
Third-party revenue 
 15
 15
 N/A
15
 
 (15) (100)%
Total revenue 6,125
 4,600
 (1,525) (25)%4,600
 3,871
 (729) (16)%
Operating expense, excluding depreciation and amortization 1,011
 1,275
 (264) (26)%1,275
 1,282
 (7) (1)%
Operating margin, excluding depreciation and amortization $5,114
 $3,325
 $(1,789) (35)%$3,325
 $2,589
 $(736) (22)%
               
Average crude oil stored per month at our Cushing terminal (in thousands of barrels) 5,954
 1,843
 (4,111) (69)%1,843
 3,157
 1,314
 71 %
Average crude oil delivered to our Cushing terminal (in thousands of barrels per day) 43
 82
 39
 91 %82
 70
 (12) (15)%

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

Total revenues for three months ended March 31, 20182019, have decreased as compared to the same period in 20172018 due to a decrease in market rates for storage contracts.

Operating expenses for the three months ended March 31, 2018, increased as compared to2019, were generally consistent with the three months ended March 31, 2017, primarily due to the timing of routine tank maintenance expense.2018.

As of May 3, 2018,6, 2019, we had approximately 2.75.8 million barrels of crude oil storage under service contracts, with remaining terms ranging from two months to 44 months, including 1.93.1 million barrels of crude oil storage contracts that expire in 2018.2019. The remaining terms on the service contracts range from 5 to 32 months. Storage contracts with Vitol represent 2.9 million barrels of crude oil storage capacity under contract, and an additional 0.5 million barrels are under an intercompany contract.







Crude oil pipeline services segment

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

The following table sets forth our operating results from our crude oil pipeline services segment for the periods indicated:
Operating resultsThree Months ended
March 31,
 Favorable/(Unfavorable)
 Three Months ended
March 31,
 Favorable/(Unfavorable) Three Months
(dollars in thousands) 2017 2018 $ %2018 2019 $ %
Service revenue:               
Third-party revenue $2,605
 $2,061
 $(544) (21)%$2,061
 $2,498
 $437
 21 %
Related-party revenue 310
 
 (310) (100)%
 101
 101
 N/A
Lease revenue:       
Third-party revenue235
 
 (235) (100)%
Product sales revenue:               
Third-party revenue 3,650
 3,508
 (142) (4)%
Lease revenue:        
Third-party revenue 
 235
 235
 N/A
3,508
 58,924
 55,416
 1,580 %
Total revenue 6,565
 5,804
 (761) (12)%5,804
 61,523
 55,719
 960 %
Operating expense, excluding depreciation and amortization 3,242
 2,785
 457
 14 %2,785
 2,722
 63
 2 %
Operating expense (intersegment) 170
 442
 (272) (160)%
Cost of product sales 3,139
 2,637
 502
 16 %
Intersegment operating expense442
 1,627
 (1,185) (268)%
Third-party cost of product sales2,637
 24,587
 (21,950) (832)%
Related-party cost of product sales
 30,774
 (30,774) N/A
Operating margin, excluding depreciation and amortization $14
 $(60) $(74) (529)%$(60) $1,813
 $1,873
 3,122 %
               
Average throughput volume (in thousands of barrels per day)        
Mid-Continent 22
 23
 1
 5 %
East Texas 3
 
 (3) (100)%
Pipeline transportation services average throughput volume (in thousands of barrels per day)23
 37
 14
 61 %
       
Crude oil marketing volumes (in thousands of barrels per day)       
Sales1
 12
 11
 1,100 %
Purchases1
 12
 11
 1,100 %

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

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

Revenuesvolume for the three months ended March 31, 2019, compared to the three months ended March 31, 2018, is attributed to the crude oil marketing activities conducted in our crude oil pipeline services segment. Throughput volumes related to the crude oil marketing business were approximately 12,000 barrels per day, or 32% of total throughput, for the three months ended March 31, 2019, compared to approximately 1,000 barrels per day in the previous year. The service revenue for this activity associated with pipeline tariffs is eliminated on an intrasegment basis. Our crude oil pipeline recognized $1.4 million in intrasegment service revenue in the three months ended March 31, 2019, that is not reflected in revenues in the table above. The intrasegment revenues for three months ended March 31, 2018, were $0.4 million. The increases in product sales revenues, intersegment operating expense, and related-party and third-party cost of product sales is also due to the increase in our crude oil marketing business.

In July 2018, we restored service on the second Oklahoma pipeline 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. Average throughput for the first quarter of 2019 on the Oklahoma portion of our pipeline system was 35,000 barrels per day, an increase of 71% compared to the same period in 2018.


Operating expenses decreased slightly for the three months ended March 31, 2019, as compared to the three months ended March 31, 2017,2018, due to more volumes being moved under contracts with lower rates, which more than offset the increase in throughput.

On April 18, 2017, we sold the East Texas pipeline system. We received cash proceeds at closing of approximately $4.8 million and recorded a gain of less than $0.1 million. The sale of the East Texas pipeline system resulted in

decreased service revenues of $0.3 million for the three months ended March 31, 2018, as compared to the three months ended March 31, 2017.

Operating expenses decreased for the three months ended March 31, 2018, as compared to the three months ended March 31, 2017, by $0.4 million as a result of the sale of the East Texas pipeline system and by $0.2 million as a result of the sale of our investment in Advantage Pipeline, for which we provided operational and administrative services through August 1, 2017.property tax expense.

Crude oil trucking and producer field services segment

Our crude oil trucking and producer field 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 and producer field services segment for the periods indicated:
Operating results Three Months ended
March 31,
 Favorable/(Unfavorable)Three Months ended
March 31,
 Favorable/(Unfavorable)
Operating results Three Months
 2017 2018 $ %2018 2019 $ %
Service revenue:        
Service revenue       
Third-party revenue $6,710
 $5,540
 $(1,170) (17)%$5,540
 $2,833
 $(2,707) (49)%
Intersegment revenue 170
 442
 272
 160 %442
 1,329
 887
 201 %
Lease revenue:       
Third-party revenue97
 
 (97) (100)%
Product sales revenue:     
      
  
Third-party revenue 385
 6
 (379) (98)%
Lease revenue:        
Third-party revenue 
 97
 97
 N/A
6
 
 (6) (100)%
Total revenue 7,265
 6,085
 (1,180) (16)%6,085
 4,162
 (1,923) (32)%
Operating expense, excluding depreciation and amortization 7,268
 6,375
 893
 12 %6,375
 4,220
 2,155
 34 %
Operating margin, excluding depreciation and amortization $(3) $(290) $(287) (9,567)%$(290) $(58) $232
 80 %
               
Average volume (in thousands of barrels per day) 22
 23
 1
 5 %23
 27
 4
 17 %

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

Service revenues have decreased despite an increase in volumes as the volumes hauled in 2018 were, on average, over a shorter distance than in 2017, which results in lower revenue per barrel transported.

Employment costs and vehicle-related expenses decreased for the three months ended March 31, 2018,2019, as compared to the three months ended March 31, 2017, as we reduced2018, by $2.2 million due to the sale of the producer field services business in April 2018. This decrease was partially offset by an increase in intersegment service revenues for services provided to our headcount and fleet sizecrude oil pipeline services segment’s crude oil marketing business. These volumes transported on an intersegment basis increased from less than 1,000 barrels per day to better match demand.10,000 barrels per day.

Product sales revenuesOperating expense, excluding depreciation and amortization, decreased for the three months ended March 31, 2017, were the result of crude oil sales in our field services business, and there were minimal such sales in2019, as compared to the three months ended March 31, 2018.2018, by $2.3 million due to the sale of our producer field services business.

Other Income and Expenses

Depreciation and amortization expense. Depreciation and amortization expense decreased by $0.7 million to $6.7 million for the three months ended March 31, 2019, compared to $7.4 million for the three months ended March 31, 2018, compared to $8.1 million for the three months ended March 31, 2017. This decrease is2018. These decreases are primarily the result of certain assets reaching the end of their depreciable lives.
 
General and administrative expensesexpense.  General and administrative expenses were relatively consistent at $4.2expense decreased by $0.5 million to $3.7 million for the three months ended March 31, 2018,2019 compared to $4.6 million for the three months ended March 31, 2017, with the changesame period in 2018 primarily consisting ofdue to decreases in legal, audit, and compensation expenses.expense.


Asset impairment expense. Asset impairment expense was $0.6for 2019 included a change in estimate of the push-down impairment related to Cimarron Express (see Note 10 to our unaudited condensed consolidated financial statements for more information) that resulted in additional impairment expense of $0.8 million and less than $0.1$0.3 million for the three months ended March 31, 2018 and 2017, respectively.related to a flood at an asphalt terminal in Wolcott, KS. Asset impairment expense for 2018 included approximately $0.4 million related to the value of obsolete trucking stations, as well as $0.2 million related to an intangible customer contract asset that was not renewed.
 

LossGain (loss) on sale of assets. LossGain on sale of assets was $0.2 million and $0.1$1.7 million for the three months ended March 31, 2018 and 2017, respectively. Losses2019, compared to a loss of $0.2 million for the three months ended March 31, 2018. Gains for 2019 primarily relate to the sale of certain truck stations in both periods were primarily comprised of sales of surplus, used property and equipment.locations not served by our crude oil trucking services segment.

Equity earnings in unconsolidated affiliate/Gain on sale of unconsolidated affiliate. The equity earnings are attributable to our former investment in Advantage Pipeline. On April 3, 2017, we sold our investment in Advantage Pipeline and received cash proceeds at closing from the sale of approximately $25.3 million, recognizing a gain on sale of unconsolidated affiliate of $4.2 million. Approximately 10% of the gross sale proceeds were held in escrow, subject to certain post-closing settlement terms and conditions. We received approximately $1.1 million of the funds held in escrow in August 2017, for which we recognized an additional gain on sale of unconsolidated affiliate during the three months ended September 30, 2017. We received approximately $2.2 million for the pro rata portion of the remaining net escrow proceeds in January 2018, for which we recognized an additional gain on sale of unconsolidated affiliate during the three months ended March 31, 2018.

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

Total interest expense for the three months ended March 31, 2018,2019, increased by $0.5$0.7 million compared to the three months ended March 31, 2017.2018. The increase was driven by additional interest on our credit agreement of $0.6 million due to increases in our average debt outstanding andfollowing table presents the weighted average interest rate under our credit agreement. In addition, during the three months ended March 31, 2018, we recorded unrealized gains of $0.4 million due to the change in fair valuesignificant components of interest rate swaps compared to unrealized gains of $0.8 million during the three months ended March 31, 2017. These increases in interest expense were partially offset by a decrease in monthly net interest payments on the interest rate swaps of $0.4 million for the three months ended March 31, 2018, as compared to the three months ended March 31, 2017. Also included in interest expense is the amortization of debt issuance costs of $0.3 million for both periods.expense:
 Three Months ended
March 31,
 Favorable/(Unfavorable)
  Three Months
 2018 2019 $ %
Credit agreement interest$3,626
 $4,009
 $(383) (11)%
Amortization of debt issuance costs256
 251
 5
 2 %
Interest rate swaps interest expense (income)66
 (40) 106
 161 %
Loss (gain) on interest rate swaps mark-to-market(353) 44
 (397) (112)%
Other(26) 7
 (33) (127)%
Total interest expense$3,569
 $4,271
 $(702) (20)%

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.
 

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

The following table summarizes our sources and uses of cash for the three months ended March 31, 20172018 and 20182019
Three Months ended
March 31,
Three Months ended March 31,
2017 20182018 2019
(in millions)(in millions)
Net cash provided by operating activities$7.5
 $9.9
$9.9
 $19.5
Net cash used in investing activities$(1.2) $(24.3)
Net cash provided by (used in) investing activities$(24.3) $3.5
Net cash provided by (used in) financing activities$(6.8) $13.9
$13.9
 $(23.3)
 
Operating Activities.  Net cash provided by operating activities increased to $19.5 million for the three months ended March 31, 2019, as compared to $9.9 million for the three months ended March 31, 2018, as compared to $7.5 million for the three months ended March 31, 2017, due to increased net income.income as discussed in Results of Operations above as well as changes in working capital.

Investing Activities.  Net cash used inprovided by investing activities was $3.5 million for the three months ended March 31, 2019, compared to net cash used by investing activities of $24.3 million for the three months ended March 31, 2018, as compared to $1.2 million for the2018.  The three months ended March 31, 2017.2019, included proceeds from the sale of certain assets of $6.3 million. Of such proceeds, $2.6 million related to the December 2018 sale of linefill for which the cash consideration was not received until January 2019. The three months ended March 31, 2018, included 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 three months ended March 31, 2018 and 2017,2019, included gross maintenance capital expenditures of $1.8 million and $1.6$2.1 million, respectively, and expansion capital expenditures of $2.8 million and $2.4 million, respectively.$0.7 million.

Financing Activities.  Net cash used in financing activities was $23.3 million for the three months ended March 31, 2019, as compared to net cash provided by financing activities wasof $13.9 million for the three months ended March 31, 2018, as compared to net cash2018.  Cash used in financing activities of $6.8 million for the three months ended March 31, 2017.  Cash2019, consisted primarily of net payments on long-term debt of $13.0 million and $9.7 million in distributions to our unitholders. Net cash provided by financing activities for the three months ended March 31, 2018, consisted primarily of net borrowings on long-term debt of $27.0 million partially offset by $12.6 million in distributions to our unitholders. Net cash used in financing activities for the three months ended March 31, 2017, consisted primarily of $12.3 million in distributions to our unitholders partially offset by net borrowings on long-term debt of $6.0 million.

Our Liquidity and Capital Resources
 
Cash flows from operations and from our credit agreement are our primary sources of liquidity. At March 31, 2018,2019, we had a working capital deficit of $0.4$16.8 million. This is primarily a function of our approach to cash management.

At March 31, 2018,2019, we had approximately $113.9$146.4 million of availability under our credit agreement and we could borrow an additional $23.7 million and still remain withinsubject to covenant restrictions, which limited our covenant restrictionsavailability to $32.9 million. As of May 3, 2018,6, 2019, we have aggregate unused commitments under our revolving credit facility of approximately $119.9$147.4 million and cash on hand of approximately $1.8$1.2 million.  The credit agreement is scheduled to mature on May 11, 2022.  As previously indicated, because the current forward price curve for crude oil is slightly backwardated and

Our credit agreement contains certain financial covenants which include a maximum permitted consolidated total Cushing storage volumes are below the 5-year average, we are anticipating a relatively weak recontracting environmentleverage ratio, which may impact bothlimit our availability to borrow funds thereunder.  The consolidated total leverage ratio is assessed quarterly based on the volumetrailing twelve months of storage and the storage rate we are able to successfully recontract in 2018. These periods are typically fairly short-lived, but there can be no assuranceEBITDA, as to the timing of a rebounddefined in the Cushing storage market. Ascredit agreement. The maximum permitted consolidated total leverage ratio as of May 3, 2018, we had approximately 2.7 million barrelsMarch 31, 2019, was 5.25 to 1.00, decreases to 5.00 to 1.00 as of crude oil storage under service contractsSeptember 30, 2019, and decreases to 4.75 to 1.00 as of ourMarch 31, 2020, and thereafter. Our consolidated total capacityleverage ratio was 4.64 to 1.00 as of 6.6 million barrels, including 1.9 million barrels of crude oil storage contracts that expire in 2018.March 31, 2019. 

As discussed in Note 7
Management evaluates whether conditions and/or events raise substantial doubt about our ability to our unaudited condensedcontinue as a going concern within one year after the date that the consolidated financial statements our credit agreement includesare issued (the “assessment period”). In performing this assessment, management considered the risk associated with its ongoing ability to meet the financial covenantscovenants.

Based on forecasted EBITDA during the assessment period, management believes that are tested on a quarterly basis, based onit will meet the rolling four-quarter period that ends on the last day of each fiscal quarter. As of the end of the first quarter of 2018, we were in full compliance with all 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 $252.6 million in outstanding debt, as of March 31, 2019, to become immediately due and payable.  If this were to occur, we would not expect to have sufficient liquidity to repay these outstanding amounts then due, which could cause the lenders under the credit facility to pursue other remedies. Such remedies could include exercising their collateral rights to our assets. Based on our current forecasts, we believe we will be able to comply with the current weakness in crude oil storage rates,consolidated total leverage ratio during the assessment period.  However, we believe that it is possiblecannot make any assurances that we will be able to achieve our forecasts. If we are unable to achieve our forecasts, further actions may fall out ofbe 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 financial covenants as early asactions, or that we will remain in compliance with the third quarter of 2018. Failureconsolidated total leverage ratio during the assessment period.

Based on management’s current forecasts, management believes 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 the financial covenants could constrain our operating flexibility, our abilityconsolidated total leverage ratio covenant including, but not limited to, fund our business operationscost reductions, common and could cause the amounts outstanding under the credit agreement, which was $334.6 million as of March 31, 2018, to become immediately due and payable.
In light of this,preferred unitholder distribution curtailments, and/or asset sales. We can make no assurances that we are considering options to enhance our financial flexibility and fund our operations, including a potential sale of assets, a reduction in the distribution rate that would be paid tosuccessful in undertaking these actions, or that we will remain in compliance with the Partnership’s common unitholders, and/orconsolidated total leverage ratio during the need to amend the financial covenants under the credit agreement. Any amendment of the credit agreement may increase the cost of credit provided under the credit agreement and related expenses, which may adversely impact our profitability.assessment period.

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.

ExpansionThe following table breaks out capital expenditures for organic growth projects, net of reimbursable expenditures of $0.1 million, totaled $2.7 million in the three months ended March 31, 2018 compared to $2.3 million in the three months ended March 31, 2017.  and 2019 (in thousands):
  Three Months ended March 31,
  2018 2019
Acquisitions 21,959
 
     
Expansion capital expenditures 2,800
 700
Reimbursable expenditures (100) 
Net expansion capital expenditures 2,700
 700
     
Gross Maintenance capital expenditures 1,800
 2,100
Reimbursable expenditures (200) (100)
Net maintenance capital expenditures 1,600
 2,000

We currently expect our expansion capital expenditures for organic growth projects to be approximately $17.0$3.5 million to $22.0$4.5 million inclusive of anticipated crude oil purchases for pipeline linefill and the Cushing terminal operational needs and net of reimbursable expenditures, for all of 2018.  Maintenance capital expenditures totaled $1.6 million, net of reimbursable expenditures of $0.2 million, in the three months ended March 31, 2018, compared to $1.3 million in the three months ended March 31, 2017.2019.  We currently expect maintenance capital expenditures to be approximately $8.0$9.5 million to $10.0$11.0 million, net of reimbursable expenditures, for all of 2018.2019.

Our Ability to Grow Depends on Our Ability to Access External Expansion Capital. Our partnership agreement requires that we distribute all of our available cash to our unitholders. Available cash is reduced by cash reserves established by our General Partner to provide for the proper conduct of our business (including for future capital expenditures) and to comply with

the provisions of our credit agreement.  We may not grow as quickly as businesses that reinvest their available cash to expand ongoing operations because we distribute all of our available cash. 

Recent Accounting Pronouncements
 
For information regarding recent accounting developments that may affect our future financial statements, see Note 1718 to our unaudited condensed consolidated financial statements.

Item 3.    Quantitative and Qualitative Disclosures about Market Risk.

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

As of May 3, 2018,6, 2019, we had $328.6$251.6 million outstanding under our credit agreement that was subject to a variable interest rate.  Borrowings under our credit agreement bear interest, at our option, at either the reserve adjusted eurodollar rate (as defined in the credit agreement) plus an applicable margin or the alternate base rate (the highest of the agent bank’s prime rate, the federal funds effective rate plus 0.5%, and the 30-day eurodollar rate plus 1%) plus an applicable margin. Interest rate swap agreements are sometimes used to manage a portion of the exposure related to changing interest rates by converting floating-rate debt to fixed-rate debt. In March 2014, we entered into two interest rate swap agreements with an aggregate notional value of $200.0 million. The first $100.0 million agreement became effective June 28, 2014, and maturesmatured on June 28, 2018. Under the terms of the first interest rate swap agreement, we paypaid a fixed rate of 1.45% and receivereceived one-month LIBOR with monthly settlement. The second agreement became effective January 28, 2015, and maturesmatured on January 28, 2019. Under the terms of the second interest rate swap agreement, we paypaid a fixed rate of 1.97% and receivereceived one-month LIBOR with monthly settlement. The fair market value of the interest rate swaps at March 31, 2018, consists of a current asset of $0.2 million and is recorded in other current assets on our unaudited condensed consolidated balance sheets. The interest rate swaps dodid 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 three months ended March 31, 20182019, the weighted average interest rate under our credit agreement was 4.96%6.43%.

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 March 31, 2018,2019, 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 $1.3$2.5 million. 
 

Item 4.    Controls and Procedures.

Evaluation of disclosure controls and procedures.  Our General Partner’s management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, evaluated, as of the end of the period covered by this report, the effectiveness of our disclosure controls and procedures as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of our General Partner concluded that our disclosure controls and procedures, as of March 31, 2018,2019, were not effective because of the material weakness in our internal control over financial reporting described in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A of Part II of our Annual Report on Form 10-K for the year ended December 31, 2017.effective. 

Remediation Plan for the Material Weakness. Our management is actively engaged in remediation efforts to address the material weakness identified. Specifically, our management is in the process of providing additional training of financial reporting personnel with respect to the preparation and review of the consolidated statements of cash flows with specific focus on the control that identifies non-cash components of transactions on the statement of cash flows. Our management believes that these actions will remediate the material weakness in internal control over financial reporting.
Changes in internal control over financial reporting.  Except for the remediation efforts noted above, thereThere were no changes into our internal control over financial reporting that occurred during the quarterthree months ended March 31, 2018, which2019, that have materially affected, or wereare reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION
 
Item 1.    Legal Proceedings.

The information required by this item is included under the caption “Commitments and Contingencies” in Note 1516 to our unaudited condensed consolidated financial statements and is incorporated herein by reference thereto.

Item 1A.    Risk Factors.
 
See the risk factors set forth in Part I, Item 1A, of our Annual Report on Form 10-K for the year ended December 31, 2017.2018.

Item 6.    Exhibits.

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


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.CL.L.C.
   its General Partner
    
Date:May 10, 20189, 2019By:/s/ Alex G. StallingsD. Andrew Woodward
   Alex G. StallingsD. Andrew Woodward
   Chief Financial Officer and Secretary
    
Date:May 10, 20189, 2019By:/s/ James R. GriffinMichael McLanahan
   James R. GriffinMichael McLanahan
   Chief Accounting Officer



INDEX TO EXHIBITS
Exhibit Number Description
3.1 
3.2 
3.3 
3.4 
4.1 
10.1
10.2
10.3
10.4
31.1# 
31.2# 
32.1# 
101# 
____________________
#     Furnished herewith






3637